UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 20-F

ANNUAL REPORT PURSUANT TO SECTION 13
OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2003

Commission file number 333-11130

PETROBRAS ENERGÍA PARTICIPACIONES S.A.

Maipú 1, 22nd Floor
(C1084ABA) Buenos Aires
Argentina
(Address of principal executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

The number of outstanding shares of each of the issuer’s classes of capital or common stock as of December 31, 2003 was:

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:

Indicate by check mark which financial statement item the Registrant has elected to follow:

The following disclosure item is omitted from Item 18 in this annual report: the financial statements for Compañia de Inversiones de Energía S.A., a company of which we held 50% of the share capital as of December 31, 2003 and over which we exercised joint control.

TABLE OF CONTENTS

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INTRODUCTION

     All references in this annual report to:

     “Petrobras Energía Participaciones,” “we,” “us,” “our,” and similar terms refer to Petrobras Energía Participaciones S.A. and its subsidiaries, but excludes affiliates and companies under joint control. Prior to July 2003, our corporate name was Perez Companc S.A.

     “Petrobras Energía” refers to Petrobras Energía S.A., a 98.21% owned subsidiary of Petrobras Energía Participaciones together with its controlled subsidiaries, but excludes affiliates and companies under joint control. Prior to July 2003, the corporate name of Petrobras Energía was Pecom Energía S.A.

     “Argentine pesos”, “pesos” or “P$” refer to the currency of the Republic of Argentina.

     “U.S. dollars” or “U.S.$” refer to the currency of the United States of America.

FORWARD-LOOKING STATEMENTS

     Some of the information included in this annual report contains information that is forward looking, including statements regarding, among other items, future earnings and operating results, capital expenditures, competition and sales, oil and gas reserves and prospects and trends in the oil and gas, refining and petrochemicals and electricity industries.

     Certain statements contained in this annual report are forward-looking statements and are not based on historical fact, such as statements containing the words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “expect” and similar words. These forward-looking statements are subject to risks, uncertainties and assumptions, including those discussed in “Item 4. Information About Us,” “Item 5. Operating and Financial Review and Prospects” and elsewhere in this annual report. Factors that could cause actual results to differ materially and adversely include, but are not limited to:

     We believe that our estimates are reasonable, but you should not unduly rely on these estimates, which are based on our current expectations. We undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of these factors. Further, we cannot assess the impact of each factor on our business or the extent to which any factor, or combination of factors, may cause actual results to be materially different from those contained in any forward-looking statements.

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Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

     Not applicable.

Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE

     Not applicable.

Item 3. KEY INFORMATION

SELECTED FINANCIAL DATA

     The financial information set forth below may not contain all of the financial information that you should consider when making an investment decision. This information should be read in conjunction with, and is qualified in its entirety by reference to, the “Risk Factors” included in this annual report. See “—Risk Factors.” You should also carefully read our financial statements and “Item 5. Operating and Financial Review and Prospects” included in this annual report for additional financial information about us.

     Our financial statements are prepared in accordance with Argentine GAAP which differs in certain significant respects from U.S. GAAP. Note 22 to our financial statements provides a description of the principal differences between Argentine GAAP and U.S. GAAP as they relate to us, and note 23 provides a reconciliation to U.S. GAAP of net income, shareholders’ equity and certain other selected financial data. Neither the effects of inflation accounting nor the proportional consolidation of Distrilec Inversora S.A., a company under joint control which we refer to as Distrilec, under Argentine GAAP have been reversed in the reconciliation to U.S. GAAP. The proporational consolidation of Compañía de Inversiones de Energía S.A., another company under joint control which we refer to as CIESA, in 2001 and 2003 under Argentine GAAP has been reversed in the reconciliation to U.S. GAAP.

     We are a holding company whose only asset is our 98.21% equity interest in Petrobras Energía. We were organized as a result of a spinoff of Petrobras Energía shares by Sudacia S.A., effective July 1, 1998. We acquired control of Petrobras Energía on January 25, 2000 as a result of the completion of an exchange offer of our Class B shares for 69.29% of Petrobras Energía’s outstanding common stock. Prior to January 25, 2000, our only asset was a minority interest in Petrobras Energía.

     Our financial data relating to the fiscal years ended December 31, 2003, 2002 and 2001 set forth below have been derived from our financial statements included in this annual report. Our financial statements as of and for the years ended December 31, 2002 and December 31, 2001 have been restated to reflect changes in generally accepted accounting principles in Argentina, which we refer to as Argentine GAAP. See “Item 5. Operating and Financial Review and Prospects—Critical Accounting Policies.” Our balance sheet as of December 31, 2003 and 2002 and the related consolidated statements of income, changes in shareholders’ equity and cash flows for each of the three fiscal years ended December 31, 2003, 2002, 2001 included in this annual report have been audited by Pistrelli, Henry Martin y Asociados S.R.L., a member firm of Ernst & Young Global. Selected financial data for the fiscal years ended December 31, 2000 and 1999 has not been restated to reflect the changes in Argentine GAAP, and accordingly are not comparable to the financial data for the fiscal years ended December 31, 2003, 2002 and 2001. Argentine law does not require that we restate these financial statements and any such restatement cannot be prepared without unreasonable effort or expense.

     Due to the inflationary environment in Argentina in 2002, and the conditions created by the Public Emergency Law, the Professional Council of Economic Sciences of the City of Buenos Aires, or CPCECABA, approved on March 6, 2002 Resolution MD No. 3/02 applicable to financial statements for fiscal years or interim periods ending on or after March 31, 2002. Resolution MD No. 3/02 required the reinstatement of the adjustment-for-inflation method of accounting in financial statements, which provides that all recorded amounts arising between August 31, 1995 and December 31, 2001 be stated in constant currency as of December 31, 2001.

     On July 16, 2002, the Argentine government issued Decree No. 1,269/02, instructing the National Securities Commission (Comisión Nacional de Valores), which we refer to as CNV, and other regulatory authorities

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to issue the necessary regulations for the delivery to such authorities of balance sheets or financial statements prepared in constant currency. On July 25, 2002, under Resolution No. 415/02, the CNV reinstated the requirement to submit financial statements in constant currency. As the inflation rate stabilized, on March 25, 2003, Decree No. 664/03 rescinded the requirement that financial statements be prepared in constant currency. On April 8, 2003, the CNV issued Resolution No. 441/03 discontinuing inflation accounting as of March 1, 2003.

     In accordance with the above, for comparative purposes, our financial statements for the fiscal years ended December 31, 2001 and 2002, were restated in constant pesos as of February 28, 2003, based on changes in the Argentine wholesale price index published by the National Institute of Statistics and Census (Instituto Nacional de Estadísticas y Censas), which we refer to as the INDEC. This price index does not reflect any specific variation in the price of products and services sold by us, and, therefore, variations in gains (losses) for both periods include positive or negative price variations that may be higher or lower than the price variations for the products or services sold by us. The selected financial data for the fiscal years ended December 31, 2000 and 1999 has also been restated in constant pesos as of February 28, 2003.

     In accordance with the procedure set forth in Technical Resolutions Nos. 4 and 19 of the Argentine Federation of Professional Councils in Economic Science, or FACPCE, we have consolidated line by line on a proportional basis our financial statements with the companies in which we exercise joint control. See “Item 5. Operating and Financial Review and Prospects—Overview.” In the consolidation of companies over which we exercise joint control, the amount of the investment in the subsidiaries under joint control and the interest in their income (loss) and cash flows are replaced by our proportional interest in the subsidiary’s assets, liabilities and income (loss) and cash flows.

     Petrobras Energía Participaciones’s net income per share under Argentine and U.S. GAAP was calculated as follows:

     Our basic net income per share for the fiscal years 2001 and 2000 was calculated in the manner described above because Class B shares were entitled to dividends equal to 150% of dividends that were paid with respect to Class A shares.

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Income Statement Data

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Balance Sheet Data

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EXCHANGE RATES

     Prior to December 1989, the Argentine foreign exchange market was subject to exchange controls. Between April 1, 1991, when Law No. 23,928 and Decree No. 529/91 (together referred to as the Convertibility Law) became effective, and January 5, 2002, the peso was freely convertible into U.S. dollars at a fixed one-to-one exchange rate. Pursuant to the Convertibility Law, the Central Bank of Argentina, which we refer to as the Central Bank, had to (i) maintain a reserve in foreign currencies, gold and certain public bonds denominated in foreign currency equal to the amount of outstanding Argentine currency and (ii) sell U.S. dollars to any requesting person at a fixed U.S.$1.00 to P$1.00 exchange rate. In addition, on January 12, 1995, the Central Bank issued Communication “A” 2298 which provided that all exchange transactions made with the Central Bank also had to be made at a fixed U.S.$1.00 to P$1.00 exchange rate.

     On January 6, 2002, the Argentine Congress passed the Public Emergency and Foreign Exchange System Reform Law No. 25,561, which superseded certain provisions of the Convertibility Law, including the fixed one-to-one exchange rate. This law granted the federal executive branch the power to set the exchange rate between the peso and foreign currencies and to issue regulations related to the foreign exchange market. On January 6, 2002, the executive branch established a temporary dual exchange rate system. As of February 11, 2002, a single and free exchange market has been established for all exchange transactions. Within this new exchange regime and for the purpose of supporting the peso exchange rate, the Central Bank has intervened several times in the exchange market by selling U.S. dollars.

     In light of a growing demand for U.S. dollars during the six months ended June 30, 2002 and the shortage of U.S. dollars available to satisfy this demand, the Argentine government adopted a series of measures to mitigate the demand for U.S. dollars and increase its U.S. dollar reserve base. As a result, (i) the export sector has had to exchange on a daily basis its non-Argentine currency into Argentine pesos through the Central Bank, (ii) new restrictions on the transfer of funds abroad were implemented, (iii) the purchase of foreign exchange was limited and (iv) requirements relating to the purchase of foreign currency from banks and exchange agencies became more stringent. Under these guidelines, the demand from private parties for U.S. dollars significantly declined and the Central Bank gradually started to accumulate U.S. dollar reserves.

     In 2003, the balance of trade yielded a strong surplus, which, together with the continuing default in partial foreign debt payments by the government, caused an excess supply of foreign currency. As a result, the peso appreciated significantly against the U.S. dollar during 2003, notwithstanding the Central Bank’s efforts to curtail these effects on the exchange rate through numerous currency purchases.

     The following table sets forth, for the periods indicated, the high, low, average and period end exchange rates for the purchase of U.S. dollars, expressed in nominal pesos per U.S. dollar. The Federal Reserve Bank of New York does not report a noon buying rate for pesos.

     On June 11, 2004, the exchange rate for the purchase of U.S. dollars published by Banco de la Nación Argentina was P$2.97 per U.S. dollar.

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RISK FACTORS

Factors Relating to Argentina

Overview

     We are an Argentine corporation. As of December 31, 2003, approximately 64% of our total assets, 69% of our net sales, 58% of our combined crude oil and gas production and 40% of our proved oil and gas reserves were located in Argentina. Fluctuations in the Argentine economy and government actions adopted by the Argentine government have had and will continue to have a significant effect on Argentine private sector entities, including us. Specifically, we have been affected and might be affected by inflation, interest rates, the value of the peso against foreign currencies, price controls, regulatory policies, business regulations, tax regulations and in general by the political, social and economic scenario in and affecting Argentina.

The Argentine economy has experienced significant volatility.

     The Argentine economy has experienced significant volatility in recent decades, characterized by periods of low or negative growth and high and variable levels of inflation and currency devaluation. In 1988, 1989 and 1990, the annual inflation rates were approximately 388%, 4,924% and 1,344%, respectively, based on the Argentine consumer price index and approximately 422%, 5,386% and 798%, respectively, based on the Argentine wholesale price index. As a result of inflationary pressures, the Argentine currency was devalued repeatedly during the 1960s, 1970s and 1980s, and macroeconomic instability led to broad fluctuations in the real exchange rate of the Argentine currency relative to the U.S. dollar. To address these pressures, the Argentine government during this period implemented various plans and utilized a number of exchange rate systems and controls.

     In April 1991, the Argentine government launched a plan aimed at controlling inflation and restructuring the economy, enacting the Convertibility Law. The Convertibility Law fixed the exchange rate at one peso per U.S. dollar and required that the Central Bank maintain reserves in gold and foreign currency at least equivalent to the monetary base. Following the enactment of the Convertibility Law, inflation declined steadily and the economy experienced growth through most of the period from 1991 to 1997. In the fourth quarter of 1998, however, the Argentine economy entered into a recession that caused the gross domestic product to decrease by 3.4% in 1999, 0.8% in 2000, 4.4% in 2001 and 10.9% in 2002. As discussed below, in 2003, the Argentine economy began to recover with GDP growing 8.7%.

Argentina experienced a severe recession and significant political and social instability during 2001 and 2002, and economic turmoil and recession may occur again in the future.

     Beginning in the second half of 2001, Argentina’s recession worsened significantly. As the public sector’s creditworthiness deteriorated, interest rates reached record highs, bringing the economy to a virtual standstill. The lack of confidence in the country’s economic future and its ability to sustain the peso’s parity with the U.S. dollar led to a massive withdrawal of deposits from banks and capital outflows.

     To prevent further capital outflows, on December 1, 2001, the Argentine government implemented a number of monetary and exchange control measures that mainly included restrictions on the free disposition of funds deposited with banks and the practical impossibility of making transfers of foreign currency abroad, with the exception of certain transactions subject, in some cases, to the previous authorization of the Central Bank. Foreign currency resulting from export sales was required to be deposited with Argentine Banks, to the extent no prior exemption mechanisms were in place.

     The measures were perceived as further paralyzing the economy for the benefit of the financial system, 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, after declaring a state of emergency and suspending civil liberties, President Fernando de la Rúa tendered his resignation to Congress. After a series of interim presidents, on January 1, 2002, Eduardo Duhalde was appointed by Congress at a joint session to complete the remaining term of former President de la Rúa.

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     The new President, among other measures, ratified the suspension of payment of a portion of Argentina’s sovereign debt declared by Interim President Rodríguez Saá.

     On January 6, 2002, the Argentine Congress enacted the Public Emergency Law, which introduced dramatic changes to Argentina’s economic model and put an end to the U.S. dollar-peso parity established since the enactment of the Convertibility Law in 1991, leading to a significant devaluation of the Argentine peso.

     The Public Emergency Law also empowered the federal executive branch of Argentina to implement, among other things, additional monetary, financial and exchange measures to overcome the economic crisis in the short term, such as determining the rate at which the peso was to be exchanged into foreign currencies.

     The federal executive branch implemented a number of far-reaching initiatives, which included:

     Commercial and financial activities were virtually paralyzed in 2002, further aggravating the economic recession, which included a 10.9% decline in GDP in 2002.

     The crisis and the government’s reactions to the crisis severely weakened the Argentine banking system. A few small banks went into liquidation, and credit became scarce for the public and private sectors.

     Towards the end of 2002, the Argentine government implemented different measures aimed at unblocking the economy and abrogating certain restrictions to gradually normalize the foreign exchange market and the commercial and financial flow of foreign currency.

     On April 27, 2003, presidential elections took place. Since none of the presidential candidates captured either 45% of the votes or a 10% margin of victory, the former-President Carlos Menem and Néstor Kirchner, the two candidates with the most votes in the first round, entered a run-off election that was scheduled to have taken place on May 18, 2003. However, Carlos Menem dropped out of the Argentine presidential election, and, thus, Nestor Kirchner automatically became the country’s newly elected president. On May 25, 2003, Mr. Kirchner took office as Argentina’s president.

     In September 2003, Argentina and the International Monetary Fund, or IMF, reached a three-year stand-by credit agreement, which set specific fiscal targets for 2004. This new agreement guaranteed the refinancing of all principal maturities of credit facilities granted by multilateral agencies.

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     In 2003, the Argentine economy began to recover with GDP growing 8.7%. This recovery, at first based almost exclusively on import substitution, broadened as the level of consumption and investment increased. Reflecting the economic recovery, Argentine stock exchange indices displayed great dynamism in 2003, and both labor indicators and salary purchasing power registered consistent improvements during this year. The balance of trade exhibited a strong surplus, favored by an increase in commodity prices, which, together with the continuity of the partial foreign debt payment default, caused an excess supply of foreign currency. The peso appreciated significantly against the U.S. dollar during 2003, even as the Central Bank made numerous currency purchases to attempt to maintain a high rate of exchange. Inflation was below 4% during 2003.

     Although the social and economic situation has improved, important issues remain unresolved, such as renegotiating the external public debt and public utility contracts, restructuring the financial system and redesigning the federal fiscal regime. Argentine government actions concerning the economy, including with respect to inflation, interest rates, price controls, foreign exchange controls and taxes, have had, and may continue to have, a material adverse effect on private sector entities, including us. We cannot provide any assurance that future economic, social and political developments in Argentina, over which we have no control, will not further impair our business, financial condition, or results of operations or impair our ability to make payments of principal and/or interest on our outstanding indebtedness.

Argentina’s insolvency and default on its public debt could limit or impair Argentina’s economic recovery.

     Because Argentina failed to meet fiscal targets, including those for the fourth quarter of 2001, on December 5, 2001, the IMF suspended further disbursements. This decision deepened the economic and financial crisis.

     On December 23, 2001, interim President Rodríguez Saá declared the suspension of debt payments on approximately U.S.$63 billion of Argentina’s sovereign debt, which amounted to approximately U.S.$144.5 billion as of December 31, 2001. On January 2, 2002, President Duhalde ratified this decision.

     On September 22, 2003, the Argentine government presented bondholders with a proposal for restructuring the country’s defaulted bonds at the IMF/World Bank annual meeting in Dubai, United Arab Emirates. Under the proposal, sovereign bonds issued before December 31, 2001 would be eligible for the proposed bond exchange, which we refer to as Eligible Debt, maintaining a strict equitable principle among all kinds and classes of creditors. The Eligible Debt would comprise approximately U.S.$100 billion, issued under 152 different series of bonds, seven different currencies and eight different governing laws. Past due interest payments since the early 2002 default would not be paid, and principal would be reduced by 75%. The stated main objective of the government’s proposal is to restore solvency through improvements in the Debt/GDP and Debt Service/Fiscal Revenues ratios, reaching a new debt profile that would be consistent with Argentina’s payment capacity. The proposal was not well received by bondholders.

     In March 2004, within the framework of a second review of the three-year agreement subscribed with the IMF, the government committed itself to taking decisive steps towards the restructuring of the public debt. In this regard, the federal executive branch issued a decree appointing the syndicate of banks that will assist the government in the restructuring.

     On June 1, 2004, the Argentine government announced a new proposal to restructure the country’s defaulted debt. This new proposal includes a plan to pay accrued interest on the defaulted bonds for the period commencing on the date the country defaulted on its sovereign debt until either December 31, 2003 or June 30, 2004 depending on the level of acceptance of the proposal, and an option for existing bondholders to exchange their bonds for one of three types of bonds, namely par, quasi-par and discount bonds, which have coupons pegged to the country’s growth in GDP and with terms ranging from 20 to 32 years. This offer has not been launched, and we cannot predict whether bondholders will adhere to the offer, when and if launched. The government expects to complete the exchange process before the end of the year.

     The Argentine government’s current insolvency, its inability to obtain financing and the uncertainties surrounding the restructuring process, which is described as one of the most complex in history and has led and may continue to lead to a growing number of lawsuits by creditors until a final agreement is reached, may affect significantly the government’s ability to implement reforms and restore sustainable economic growth. This could further undermine the maintenance of the economic recovery experienced during 2003 and may result in recession,

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higher inflation, greater unemployment and social unrest. If this happens, our financial condition and results of operations would be adversely affected.

The devaluation of the peso creates greater uncertainty as to Argentina’s economic future.

     The peso has been subject to large devaluations in the past and may be subject to significant fluctuations in the future.

     The Public Emergency Law put an end to ten years of U.S. dollar-peso parity and authorized the Argentine government to set the exchange rate between the peso and foreign currencies, and issue regulations related to foreign exchange markets. After devaluing the peso, the Argentine government initially established a dual exchange rate of P$1.40 per U.S. dollar for certain transactions and a free-floating rate for all other transactions. This dual system was later eliminated in favor of a single free-floating exchange rate for all transactions.

     Since the end of the U.S. dollar-peso parity, the peso has fluctuated significantly. As a result, the Central Bank has taken several measures to stabilize the exchange rate and preserve its reserves. See “—Exchange Rates.”

     The marked peso devaluation during 2002 adversely affected our results and financial position. All of our financial debt and a significant portion of our affiliates’ debt are denominated in U.S. dollars. Before the enactment of the Public Emergency Law, our cash flow, usually denominated in U.S. dollars or dollar-adjusted, provided a natural hedge against exchange rate risks. The new Argentine regulatory framework, however, limited our ability to mitigate the impact of the peso devaluation. Pesification of utility rates, regulatory issues related to the renegotiation of pesified utility rates, new taxes on hydrocarbon exports and the implementation of regulations to prevent an increase in prices to final users in the domestic market had a significant impact in such respect.

     As from the second half of 2002, domestic prices of the main commodities have significantly recovered in line with export prices. In addition, we aggressively pursued a trade policy of opening and consolidation of export markets to capitalize on domestic and export price asymmetries. In light of the above strategies and the strength of our foreign operations with a cash flow primarily denominated in U.S. dollars, our exposure to peso fluctuations has dropped, and we have substantially recovered our ability to naturally hedge our cash exposure to U.S. dollar liabilities.

     We cannot assure you, however, that the Argentine government will not adopt new regulations or make regulatory changes that prevent or limit us from offsetting the risk derived from our exposure to the U.S. dollar.

Inflation may escalate and undermine any hope for continued economic growth in Argentina.

     On January 24, 2002, the Argentine government amended the charter of the Central Bank to allow the Central Bank to print currency without having to maintain a fixed and direct relationship to foreign currency and gold reserves. This change allows the Central Bank to make short-term advances to the federal government to cover its anticipated budget deficits and to provide assistance to financial institutions with liquidity or solvency problems.

     There is considerable concern that, if the Central Bank prints currency to finance public sector spending, to assist financial institutions in distress or to prevent a further appreciation of the peso, significant inflation could result. During 2002, the Argentine consumer price index increased 40.98%, and the wholesale price index increased 118.2%. During 2003, within a substantially different economic scenario, such indices increased only 3.7% and 2.0%, respectively.

     In the past, inflation has materially undermined the Argentine economy and the government’s ability to stimulate economic growth. The variability of inflation in Argentina makes it impossible to estimate how our activities and results of operations will be affected in the future. Sustained inflation in Argentina, without a corresponding increase in the price of our products in the local market, would have a negative effect on our results of operations and financial position.

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Exchange controls may further impair our ability to service our foreign currency-denominated debt obligations.

     After December 2001, the Argentine authorities implemented a number of monetary and currency exchange control measures that included restrictions on the withdrawal of funds deposited with banks and tight restrictions on foreign transfers, including restrictions relating to the servicing of foreign debt, with the exception of those related to foreign trade and other authorized transactions. Although these control measures have been relaxed and, during 2003, the Central Bank issued a number of regulations aimed at gradually normalizing the domestic exchange market, we cannot assure you as to how long these more flexible regulations will be in effect or whether they will become more restrictive again in the future.

     Pursuant to Decree No. 1589/89 relating to the deregulation of the upstream oil industry, companies engaged in oil and gas production in Argentina are free to sell and dispose of the hydrocarbons they produce, and are entitled to maintain outside Argentina up to 70% of the foreign currency proceeds from crude oil and gas exports. These companies are required to repatriate the remaining 30% through the Argentine exchange markets. During 2002, controversies arose among producers and the authorities regarding the enforceability of the right to freely dispose of up to 70% of the proceeds from foreign currency export sales. These controversies were the subject of legal challenges, and many federal judges have pronounced on and recognized the prima facie validity of producers’ rights. In December 2002, we filed with a federal court of the Province of Santa Cruz, a temporary injunction against the federal executive branch, requesting the maintenance of the status quo that allows us to freely dispose of up to 70% of our export proceeds. This right was prima facie admitted by the court. On December 31, 2002, Decree No. 2703/02, effective as of January 1, 2003, was enacted. This decree recognized the right of oil and gas producers to dispose of 70% of the proceeds from foreign currency export sales, but had no provisions related to such right during 2002. In order to avoid any uncertainty regarding the application of this right in 2002, in February 2003, we filed a civil action of certainty, requesting that the court recognize our right to freely dispose up to 70% of our export proceeds in 2002, based on the effectiveness of Decree No. 1589/89. This was admitted prima facie by the court.

     If the Argentine government decides further to tighten its transfer restrictions by, among other things, eliminating Decree No. 1589/89 or otherwise, we may be unable to make principal or interest payments when they become due.

Limits on exports of hydrocarbons could lower our anticipated dollar-denominated cash receipts.

     On May 23, 2002, the Argentine government enacted Decree No. 867/02 declaring a state of emergency in the supply of hydrocarbons in Argentina until September 30, 2002 and empowering the Secretary of Energy to determine the volume of crude oil and liquefied petroleum gas, which we refer to as LPG, produced in Argentina that should be sold in the local market. In addition, by Resolution No. 140/02, temporary limits were established for hydrocarbon exports during the months of June, July, August and September of 2002. Resolution No. 140/02 was repealed on July 26, 2002 by Resolution No. 341/02.

     Argentina is suffering an energy crisis. In light of this situation, the Secretary of Energy issued Resolution No. 265/2004 on March 26, 2004, pursuant to which limits on natural gas exports may be imposed and, in fact, some limits have already been imposed. This resolution instructs the Undersecretary of Fuels to create a program for the rationing of gas exports and for the regulation of the use of transportation capacity. In compliance with this instruction, the Undersecretary of Fuels issued Disposition No. 27/04 implementing this program. Both regulations were issued as temporary measures in order to avoid a crisis in the local supply of natural gas and, consequently, in the supply of electricity to the wholesale electricity market. We do not believe that these measures will have a material adverse effect on our results or financial condition, but we cannot assure you that this will be the case.

     Additionally, in April of 2004, in order to facilitate the recovery of gas prices, the Secretary of Energy entered into an agreement with natural gas producers requiring them to sell a specified amount of gas in the local regulated market for prices determined in accordance with a roadmap that culminates with the expected complete deregulation of wellhead prices for natural gas by January of 2007. See “Item 4. Information About Us—Regulation of Our Businesses—The Argentine Gas Industry and Regulatory Framework—Adjustment of the Price of National Gas in Wellhead.”

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     We cannot assure you that the Argentine government will not impose additional export restrictions on hydrocarbons. If it were to do so, we would receive lower dollar-denominated cash receipts, which might limit our ability to service our U.S. dollar-denominated debt.

Export taxes on our products have negatively affected, and may continue to negatively affect, the profitability of our operations.

     Effective as of March 2002, the Argentine government adopted a 20% export tax on crude oil exports and a 5% tax on exports of certain oil by products. Diesel oil’s effective export tax from June until July 31, 2002 was 20%. In May 2004, the Argentine government increased to 25% the export tax on crude oil exports, increased the export tax on LPG oil exports to 20% and imposed a 20% tax on all gas exports.

     We cannot assure you that the Argentine government will reduce the current export tax rates or will not increase them further. We do not know the government’s future intentions in regard to export taxes.

Price controls have affected, and may continue to affect, our results of operations and capital expenditures.

     For the purposes of reducing inflationary pressures generated by the sharp Argentine peso devaluation, the Argentine government issued a set of regulations aimed at controlling the increase in prices to end users. These regulations were particularly focused on the energy sector.

     Under the Public Emergency Law, our ability to increase the price of energy and gas sold in the domestic market is limited, especially in connection with sales agreements entered into with utility companies and energy sales in the spot market. This limitation, within the context of the peso devaluation and subsequent inflation, resulted in a substantial change in the economic and financial balance of our energy and gas related businesses, significantly affecting our operating results and prospects. As a result, gas investments, especially at the Neuquén basin, were postponed.

     With respect to crude oil prices, in January 2003, at the federal executive branch’s request, hydrocarbon producers and refineries executed a temporary agreement in connection with crude oil, gasoline and diesel oil price stability in the domestic market. After successive renewals, the term of this agreement was extended until May 2004. This agreement provided for crude oil deliveries to be invoiced and paid based on the West Texas Intermediate Crude reference price, or WTI, of U.S.$28.5 per barrel instead of the actual relevant WTI. Any positive or negative difference between the actual relevant WTI, not exceeding U.S.$36 per barrel, and the reference price would be paid out of any balance generated in periods where the actual WTI is below U.S.$28.5 per barrel. Refineries, in turn, would reflect the crude oil reference price in domestic market prices. In February 2004, a new agreement corresponding to the period beginning on March 1, 2004 and ending on April 30, 2004 was reached between producers and refineries, but the Secretary of Energy has not yet approved this agreement because it contains a difference concerning the interest rate to be used to calculate the debt between producers and refiners. If the situation continues in the future, producers shall be forced to reinvoice refiners in order to adjust prices. Notwithstanding this situation, beginning in May 2004, hydrocarbon producers and refineries have informally agreed that while the WTI per barrel ranges between U.S.$32 and U.S.$42, crude oil deliveries will be invoiced and paid based on a reference price equal to (i) 86% of the WTI as long as this price does not exceed U.S.$ 36 per barrel, or (ii) 80% of the WTI, in cases where this price exceeds U.S.$36 per barrel.

     With respect to electricity generation, the Argentine government implemented the pesification of dollar-denominated prices in the wholesale electricity market, and through Resolution No. 08/02 of the Secretary of Energy, set a price cap for the energy sold in the spot market of P$120/MWh. This is the maximum price for an efficient generation company, regardless of the actual marginal cost of electricity generation. Resolution No. 240/03 effective since August 15, 2003, established that the cost of liquid fuels in thermal power plants and water in hydroelectric plants was excluded from the determination of electricity prices. This resolution was temporarily suspended on October 9, 2003, and then put into effect again by the Secretary of Energy on January 30, 2004. These measures represent deviations from the marginal cost system implemented in 1992 and from the provisions in Electricity Law No. 24,065, which allow for an adequate return on investment in a competitive environment based on a marginal price system. Thermal power generating companies, however, may cover variable operating costs through certain mechanisms. See “Item 4. Information About Us—Regulation of Our Businesses—The Argentine Electricity Industry and Regulatory Framework—Dispatch.”

     In addition, due to the government’s decision to suspend the seasonal increases in electricity prices, electricity prices have not reflected production costs. As a result, the Stabilization Fund (Fondo de Estabilización) was exhausted and Compañia Administradora del Mercado Eléctrico S.A., or CAMMESA, which we refer to as the

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Wholesale Market Manager, could not settle accounts with market agents. As a palliative measure, in December 2003 the Argentine government made a P$150 million contribution to the Stabilization Fund under Decree No. 1181/03 and on March 2004, under Decree No. 365/04, made a further contribution of P$200 million. In February 2004, in an effort to restore the Stabilization Fund, the government reinstated the seasonal adjustment in electricity prices for the February-April 2004 period, but on May 2004, the government suspended seasonal adjustments again. As of May 2004, the Stabilization Fund has a deficit of P$650 million.

     In light of the uncertainties prevailing in Argentina, we have made progress in renegotiating the terms and conditions of gas and electricity sale agreements entered into with industrial clients in order to adjust prices to reflect the new economic conditions. In this regard, we have reached commercial agreements that gradually increase sale prices to reflect the effects of the peso devaluation. We, as well as others, have attempted to maximize export opportunities in an effort to capitalize on variations between domestic and export prices, by effectively encouraging the opening and consolidation of new markets. During 2003, we started to export gas to Chile from the Austral basin.

     The Argentine government is expected to gradually restore the economic and financial balance in the natural gas and electricity sectors, in compliance with the respective regulatory frameworks. However, our results and capital expenditure plans may be negatively affected if the Argentine government continues issuing additional decrees or exerting political pressure to curb price increases or control exports or if it applies its regulatory emergency authority to fix prices or adopts other laws to stabilize prices or supply.

The pesification of utility rates has affected and may continue to affect the operations of our affiliated utility companies.

     The Public Emergency Law pesified tariffs for public utility services and prohibited the increase of such tariffs based on indexation factors. Tariffs were converted into pesos at a P$1=U.S.$1 parity. Pursuant to this law, the Argentine federal executive branch is authorized to renegotiate the terms of contracts relating to the provision of public utility services. The criteria for such renegotiation must take into account: (i) the impact of tariffs on economic competitiveness and on income distribution, (ii) the quality of the service and capital expenditure programs, in cases where they were required in the contracts, (iii) the interest of the customers and accessibility to the services, (iv) the safety of the systems and (v) the companies’ profitability.

     On February 12, 2002, the federal executive branch issued Decree No. 293/02 under which the Ministry of Economy was empowered to renegotiate utility contracts and a Public Works and Services Contract Renegotiation Committee, which we refer to as the Renegotiation Committee, was created, the members of which, among them a representative of customers, were appointed through Decree No. 370/02. The Renegotiation Committee’s mission is to provide advice to and assist the Ministry of Economy, which must submit a renegotiation proposal to the federal executive branch or otherwise recommend the termination of concession contracts. Such proposal or recommendation is subsequently submitted to the relevant congressional commissions for analysis. The Renegotiation Committee, however, failed to achieve its intended goal due to successive actions to protect constitutional rights (acciones de amparo) brought by the Argentine National Ombudsman (Defensor del Pueblo de la Nación).

     In order to secure the supply of utilities, and in line with the renegotiation process, the federal executive branch authorized an increase in gas and electricity rates under Decree No. 146/03. Such increase was 10% for Transportadora Gas del Sur S.A., or TGS, 9% for Edesur S.A., or Edesur, and 22% for Compañía de Transporte de Energía Eléctra en Alta Tensión Transener S.A., or Transener and 18% for Empresa de Transporte de Energía Eléctrica por Distribución Troncal Sociedad Anónima Transba S.A. or Transba The Argentine National Ombudsman and consumer organizations challenged the increase. On February 25, 2003, a Court of First Instance issued a provisional remedy and suspended the rate increase authorized under Decree No. 146/03.

     In July 2003, the Utilities Contract Renegotiation and Analysis Committee, or UNIREN, was created within the scope of the Ministries of Economy and Production and Federal Planning, Public Investment and Services. UNIREN, as successor of the Renegotiation Committee, was created to, among other things, assist in the contract renegotiation process for public works and services, subscribe comprehensive or partial agreements and submit regulatory projects concerning temporary price and rate adjustments. To date, no substantial progress has been made in the renegotiation process.

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     On October 1, 2003, the Argentine Congress enacted a law whereby the term granted to the federal executive branch under the Public Emergency Law to renegotiate contracts with privatized utility companies was extended until December 2004. In addition, under such law the federal executive branch may fix temporary utility rates until completion of the renegotiation process.

     We cannot anticipate the outcome of the current renegotiation process. If utility companies’ contracts are renegotiated, the new terms could be less favorable than the current terms. If so, the results of operations and financial position of utility companies could be severely affected. Even if these contracts are renegotiated with more favorable terms, such terms could be insufficient to prevent a material adverse effect on the results of operations and financial position of utility companies. The problems faced by our affiliated utilities have adversely impacted our net income and our ability to receive dividends from these companies. Whereas we received dividends from these companies in 2000 and 2001, we did not receive dividends from them in 2002 or 2003. See “Item 5. Operations and Financial Review and Prospects—Overview.”

The devaluation and pesification of utility rates have resulted in payment defaults by some of our affiliates.

     The new macroeconomic scenario after enactment of the Public Emergency Law deeply changed the economic and financial balance of utility companies. The tremendous effect of devaluation, within a context where revenues remained unchanged as a consequence of the pesification of rates and financial debts with foreign creditors were primarily denominated in foreign currency, affected the financial position, results of operations and cash generation ability of utility companies.

     CIESA and Transener have defaulted on their debt and are attempting to restructure it. On February 24, 2003, TGS started an overall restructuring process for substantially all its financial debt. This process mainly aims at extending short-term maturities, modifying certain financial restrictions contemplated in financial agreements and adjusting interest rate and repayment terms to align cash flows required to repay the debt with its expected cash flows, with no principal reductions.

     TGS first attempted to reach an agreement with creditors through a pre-packaged out-of-court reorganization agreement (Acuerdo Preventivo Extrajudicial), or APE, which is a new structure permitted by Argentine law. An APE essentially permits a company to restructure its debt pursuant to an agreement approved by two-thirds of its creditors, which we refer to as the Requisite Majority, and which is then endorsed by an Argentine Court. Since TGS could not achieve this Requisite Majority, on May 14, 2003, it withdrew the restructuring proposal and simultaneously announced the postponement of the payment of interest on its financial debt. TGS is currently conducting negotiations with its main creditors.

     Transener has been notified of a request by one of its creditors for the commencement of involuntary bankruptcy proceedings against it and of requests for attachment of approximately U.S.$11.5 million in accounts receivable from CAMMESA. Transener is pursuing all reasonable defenses to protect its rights.

     The management of our different affiliated utility companies have formulated and implemented an action plan aimed at offsetting the negative impact of the current conditions. We cannot assure you that these plans will prove to be successful or that these plans will help meet the companies’ established goals.

     We could lose some or all of our ownership in these companies if any necessary debt restructuring is unsuccessful and creditors proceed against the assets of the defaulting affiliates, although the outcome of such procedure is uncertain due to the procedural difficulties of Argentine bankruptcy courts and laws relating to the ownership of Argentine utilities. In addition, as part of a debt restructuring, creditors may require an equity stake in these companies, thereby reducing our equity interest. If our equity interest were reduced, our share of any future cash dividends and equity in earnings from affiliates from these companies would decrease in line with the decrease in our ownership interest.

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Factors Relating to Venezuela

Political and social events in Venezuela may negatively affect our Venezuelan operations.

     Operations in Venezuela have become an important part of our businesses. In 2003, production in Venezuela accounted for 27.3% of the total average production in barrels of oil equivalent. As of December 31, 2003, a significant share of our total combined proved reserves was located in Venezuela. Accordingly, our operations are affected by political developments in Venezuela.

     Effective January 2002, the Venezuelan government adopted a new law whereby royalty payments increased from 16.67% to 30%. This had a significant adverse impact on the results of certain of our fields.

     In February 2002, as a result of the capital drain that had started a few years before and the fall in economic activity caused by production cuts mandated by the Organization of Petroleum Exporting Countries, or OPEC, Venezuela was forced to abandon the exchange rate system that it had maintained for some time. Venezuela’s currency, the Bolivar, was allowed to float against the U.S. dollar, leading to a significant devaluation.

     In April 2002, the President of Venezuela, Hugo Chávez, was removed from power but subsequently returned to the presidency after a few days. He was removed by the military after heavy political backlash over the implementation of his social programs and decision to change management at Petróleos de Venezuela S.A., or PDVSA, the state-owned oil company.

     The political crisis deepened in the last months of 2002, with less support for President Chávez and increased violence. In December 2002, in the face of Chávez’s refusal to permit a referendum that would determine whether to accelerate elections, a general strike organized by the “Coordinadora Democrática” was initiated. A number of sectors, including PDVSA workers, joined the strike; as a result, oil production plummeted. The strike was accompanied by increased capital drains, loss of bank deposits and a material deterioration of the country’s tax situation as a result of reduced tax revenues. Credit rating agencies downgraded Venezuela’s debt ratings. Taking into account the economic deterioration brought by the strike, opposition forces decided to lift the strike in February 2003. The government, in turn, was able to resume control over PDVSA and to partially reinstate production, after dismissing a large number of PDVSA employees.

     After discussions between the government and the opposition resumed, an agreement was reached to hold a referendum on President Chávez’s future tenure. In June 2004, the Venezuelan Justicia Electoral determined that the opposition to Hugo Chávez had gathered the necessary support to force a referendum on Chávez’s mandate, which is scheduled to occur in August of 2004. New riots and social protests are expected.

     Amid this continuing struggle, the economy has suffered. A significant loss in reserves and capital flight was recorded. In addition, the country was plunged into in an unprecedented recession, which significantly increased inflation, unemployment and violence rates.

     For the reasons mentioned above, the government adopted emergency measures including:

     While these measures enabled a gradual recovery of reserves as oil production returned to normal levels, with high crude oil prices, the restrictions resulted in a sharp decline in overall imports and affected the general level of activity, particularly in the non-oil sector. Venezuela experienced both shortage problems and the emergence of a black market. The unemployment rate rose as poverty indices soared.

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     By the end of 2003, Venezuela experienced:

     We are required to deliver all of our oil equivalent production in Venezuela to PDVSA, and accordingly PDVSA has become one of our most important customers.

     Since oil production activities in Venezuela are closely monitored by the government through PDVSA, our operations in Venezuela could be affected by political and social riots, including strikes and other forms of political protest, similar to those experienced during the first quarter of 2003. Due in part to the oil strike at PDVSA in 2002, our daily sales volume of oil equivalent decreased 12.5% during 2003. In addition to these effects, Venezuela’s complex crisis could have other unforeseen effects, which may have an adverse impact on our results of operations.

     The Venezuelan government may, at its own discretion, decide to enact additional laws to modify the terms and conditions of our operating agreements that could negatively impact our operations. Such changes may include increased royalty payments or production cuts. In addition, since Venezuela is an OPEC member country, we are subject to any decision related to production cuts that OPEC may adopt.

Factors Relating to Us

Decline in oil prices affect our operating results and capital expenditures.

     Oil prices in Argentina and other Latin American countries reflect world market prices. World oil prices are determined by global supply and demand factors over which we have no control. Oil prices have fluctuated widely over the last ten years. During 2003, 2002 and 2001, the average WTI was U.S.$31, U.S.$26 and U.S.$26 per barrel, respectively.

     Because a substantial amount of our revenue is derived from sales of oil, any decline in the price of oil may affect our operating results and the amount and timing of our projected capital expenditures. Although we regularly evaluate the opportunity to enter into derivative transactions to mitigate our exposure to changes in the price of crude oil and crude oil by-products, if oil prices decline significantly, we may have to dramatically cut capital expenditures, and this could adversely affect our production forecasts in the medium term and our hydrocarbon reserve estimates.

The lack of financing alternatives may impact the execution of our strategic business plan.

     After the default on the Argentine sovereign debt, Argentine companies have had significantly fewer opportunities to access international credit markets. Non-Argentine financial markets and institutions are reluctant to lend additional capital and grant loans to Argentine entities and companies. In addition, as a result of the default in payment of loans and other financial liabilities in Argentina on the part of the government and private entities and the massive withdrawal of money from accounts opened with financial institutions in Argentina and from the Argentine financial market in general, the opportunities to obtain financing at attractive rates in Argentina continue to be very limited.

     Although we have thus far been able to fulfill our financings needs throughout the Argentine crisis (we were the first Argentine company to place a new issuance of debt which was not associated or part of a debt restructuring in the international capital markets since the Argentine governement defaulted on its debt), the prospects for all Argentine companies, including us, of accessing financial markets in the near or medium-term

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continue to be challenging. If we are unable to access the financial markets, we may have to reduce our projected capital expenditures in order to meet our contractual obligations. This may in turn affect the implementation of our business plan for 2004 and our long-term prospects.

Production of oil in Block 31 in Ecuador is significantly delayed, and this delay has and will continue to affect our results. Further delays could result in an increase in our operating losses related to our group of assets in Ecuador.

     Our oil fields in an area referred to as Block 31 in Ecuador are located in the Amazon jungle in the northeastern part of the country where no significant infrastructure currently exists for the production of hydrocarbons.

     Investments of approximately U.S.$800 million are estimated to be required for Block 31’s development in full. Initial investments in the amount of approximately U.S.$150 million must be effectively made before the start of the production phase, which is currently scheduled for 2006. The decline in our capital expenditures following the Argentine crisis resulted in significant delays with respect to our original plan for Block 31’s development. Our investments are dependent upon our ability to increase capital expenditures in future periods and to access the financial markets.

     Future oil production in Block 31 will be shipped through a heavy crude oil pipeline known as Oleoducto de Crudos Pesados. We entered into a contract with Oleoducto de Crudos Pesados Ltd., or OCP, whereby 80,000 barrels per day of oil transportation capacity was committed on a “ship or pay” basis for a 15-year term as from the date OCP starts operations. Our annual cost associated with this oil transportation capacity is approximately P$220 million. Transportation capacity costs are billed by OCP on a monthly basis and charged to expensed by us as incurred.

     OCP started commercial operations on November 10, 2003. As of that date, we have had to comply with our contractual obligations with respect to our committed acquired capacity by paying a fee which as of December 31, 2003 was estimated to be P$7.53 per barrel.

     We currently estimate that, during the contract’s term, oil production will be lower than our committed transportation capacity. We have reached this belief based on, among other reasons, the delays involved in the development of Block 31, the new schedule of investments required for the joint development of Blocks 18 and 31 and a revised outlook on the potential of Block 31. As of December 31, 2003, we have recorded an impairment allowance of P$321 million to adjust the book value of a group of assets in Ecuador to its recoverable value.

     If we cannot increase capital expenditures in future periods, production from Block 31 will be delayed further. In addition, once development projects are commenced, unforeseen delays in our drilling activities may occur, which could result in significant additional delays in production. See “—Our drilling activities may be adversely affected by events beyond our control.” Furthermore, we cannot assure you that, if required investments were made, future production levels would reach estimated production levels. As a result of these scenarios, we may have future operating losses to the extent that our revenues do not compensate our operating expenses and such losses shall be recognized when incurred.

Our oil and gas proved reserve estimates are not 100% accurate and may be subject to revision.

     We estimate our proved developed crude oil and natural gas reserves by using geological and engineering data to demonstrate with reasonable certainty whether they are recoverable in future years from known reservoirs under existing economic and operating conditions. These estimates are audited by Gaffney, Cline & Associates, an international technical consulting firm for the oil and gas industry. Nonetheless, reserve estimates are based, in part, on subjective judgments and as a consequence are not 100% accurate, and, thus, may be subject to revision. Crude oil and natural gas reserves are reviewed annually to take into account production levels, field reviews, the addition of new reserves from discoveries, new economic conditions and other factors. Although we believe our proved reserve estimates fairly present the amount of reserves available to us, proved reserve estimates could be materially different from the quantities of crude oil and natural gas that are ultimately recovered.

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We may not be able to replace our oil and gas reserves.

     The rate of production from oil and gas properties generally declines, and the cost of such production generally increases, as reserves are depleted. Without successful exploration and development activities or reserve acquisitions, our proved reserves will decline as oil and gas are produced from our existing proved developed reserves. We cannot guarantee that our exploration, development and acquisition activities will result in significant additional reserves or that we will continue to be able to drill productive wells at acceptable costs. Our ability to replace our reserves is also dependent upon our capital expenditures. In 2002, we reformulated our investment plan and adopted a restrictive expense and investment policy. This has significantly limited our reserve replacement ratio.

     Looking towards the future, we have limited capital resources to implement an ambitious capital expenditure program. In addition, as long as the financial debt remains unpaid, we must comply with a series of restrictions and covenants, including restrictions on capital expenditure levels.

Our drilling activities may be adversely affected by events beyond our control.

     Oil and gas drilling activities are subject to numerous risks, many of which are beyond our control. Our operations may be curtailed, delayed or canceled as a result of weather conditions, mechanical difficulties, shortages or delays in the delivery of equipment and compliance with governmental requirements. Drilling may involve unprofitable efforts, not only with respect to dry wells, but also with respect to wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a return on the investment or a recovery of drilling, completion and operating costs.

Our oil and gas operations may be affected by standard industry operating risks.

     Our operations are subject to all of the risks normally incident to the operation and development of oil and gas properties and the drilling of oil and gas wells, including the risk of fire, explosions, blow outs, pipe failure, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures or discharges of toxic gases. The occurrence of these industry operating risks could cause us to suffer substantial losses, including losses due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damages and clean up responsibilities, and penalties and suspension of operations.

Our activities may be adversely affected by events in other countries in which we do business.

     As we expand our operations in other countries, we may be increasingly affected by the following factors and developments: political and economic uncertainties; expropriation of property and cancellation or modification of contract rights; regulatory changes; currency exchange fluctuations and other risks arising out of the imposition of foreign investment or capital controls, and risks of loss in countries due to civil strife, acts of war, guerilla activities and insurrection.

Our operations run the risk of causing environmental damage, and any changes in environmental laws may increase our operational costs.

     The nature of some of our operations forces us to undertake risks that may cause environmental as well as other types of damage.

     In 2003, we hired an international consulting firm to perform an environmental and safety audit on our operations. The report ratified the high environmental standards under which our operations are performed and also identified a series of actions necessary for our operations to be in full compliance with current laws and regulations, to satisfy future requirements and, in the absence of local laws, to comply with applicable international standards. We have decided to implement the actions recommended by the audit. Consequently, over the next several years we will make investments to improve prevention systems and production facilities, among other things, in the amount of approximately U.S.$23 million, and we will implement several corrective and remediation actions, some of which are already underway.

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     Notwithstanding our decision to implement actions recommended by the environmental audit and our commitment to our environmental, health and safety efforts, we cannot assure you that our operations will not cause environmental or other damages or that any such damages will not result in legal liabilities to us.

     We are subject to extensive environmental regulation both in Argentina and in the other countries in which we operate. Additionally, local, provincial and national authorities in Argentina are moving toward more stringent enforcement of applicable environmental laws, which may require us to incur higher compliance costs. We cannot predict what additional environmental legislation or regulations will be enacted in the future or the potential effects on our financial position and results of operations.

We operate some of our businesses pursuant to concessions and licenses that are subject to termination.

     The terms of the concessions under which some of our businesses operate typically require the operator to meet specified requirements and to maintain minimum quality and service standards. Failure to comply with these criteria could result in the imposition of fines or other government actions. In addition, in extreme cases our license or concession may be terminated or revoked. Although we have materially complied with the terms and conditions of our licenses and concessions in the past and expect to do so in the future, we cannot assure you that our businesses will be able to comply fully with the terms and conditions of their licenses.

     Regarding utility companies, the freezing of rates, in addition to increased operating and financing costs, had a significant adverse impact on the utilities’ cash flow and capital expenditure plans. Although these companies have continued to maintain acceptable service quality levels, their ability to continue meeting these levels will be seriously affected if the Argentine government does not adopt structural measures allowing for a recovery of these companies’ economic-financial balance.

Our activities may be adversely affected by competition.

     Activities in the energy business are highly competitive and are expected to remain competitive in the future.

     We compete with other companies, including leading international oil and gas companies in Argentina and the rest of Latin America. Some of these companies may have greater financial and other resources than us and, as a result, may be in a better position to compete for future business opportunities. In addition, other alternative sources of energy are expected to come into operation in the future.

     We cannot assure you that we will maintain our current competitive position in the regional energy markets. In addition, we cannot predict with reasonable certainty the magnitude and speed of evolution of such potential competitive threats or their effect on our operations.

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Item 4. INFORMATION ABOUT US

OUR HISTORY AND DEVELOPMENT

Our History

     We are an Argentine based holding company and operate exclusively through our subsidiary Petrobras Energia and its subsidiaries which are engaged in oil and gas exploration and production, refining, petrochemicals, electricity generation, transmission and distribution and hydrocarbons marketing and transportation. We conduct operations in Argentina, Bolivia, Brazil, Ecuador, Peru and Venezuela. We are a corporation organized and existing under the laws of the Republic of Argentina with a duration of 99 years from the date of our incorporation, September 25, 1998. Our legal name is Petrobras Energía Participaciones S.A. and we are known commercially as Petrobras Energía Participaciones. Our principal executive offices are located at Maipú 1, 22nd Floor, C1084ABA Buenos Aires, Argentina, Telephone: 54 11 4344-6000.

     Our original name was PC Holdings S.A. We were formed in 1998 as a result of a spinoff by Sudacia S.A. of its equity interest in Petrobras Energía. At the time of the spinoff, we and Sudacia S.A. were wholly owned by members of the Perez Companc family. In addition, Petrobras Energía was also controlled at the time by members of the Perez Companc family. We were formed for the sole purpose of owning shares of Petrobras Energía. As of December 31, 1998 and 1999, we owned 16.15% and 28.92%, respectively, of Petrobras Energía’s common stock.

     We acquired control of Petrobras Energía on January 25, 2000 as a result of the consummation of an exchange offer pursuant to which we issued 1,504,197,988 Class B shares, with one vote per share, in exchange for 69.29% of Petrobras Energía’s outstanding capital stock, thereby increasing our ownership interest in Petrobras Energía to 98.21%. Since January 26, 2000, our Class B shares have been listed on the Buenos Aires Stock Exchange and our American Depositary Shares, each representing ten Class B shares, have been listed on the New York Stock Exchange. At the time, we were controlled by members of the Perez Companc family, who owned all of our Class A shares. Those Class A shares had five votes per share until October 17, 2002, when all Class A shares converted into Class B shares upon their purchase by Petrobras.

     In July 2000, we completed the change in our corporate name from PC Holdings S.A. to Perez Companc S.A.

     On October 17, 2002, Petrobras Participacões, S.L., a wholly owned subsidiary of Petróleo Brasileiro S.A. — PETROBRAS, or Petrobras, acquired from the Perez Companc family and Fundación Perez Companc their entire ownership interest, or 58.6%, of Petrobras Energía Participaciones’s capital stock. Petrobras is the largest integrated oil, gas and energy company in Brazil. It is engaged in a broad range of oil and gas activities, including crude oil and natural gas exploration and production, refining, transportation, marketing and distribution of oil products, petrochemicals, natural gas and power. Petrobas is a mixed-capital company with a majority of its voting capital owned by the Brazilian federal government. Prior to that date, the Perez Companc family, together with Fundación Perez Companc, had owned at least half of the share capital issued by Petrobras Energía Participaciones.

     On April 4, 2003, at a regular and special shareholders’ meeting, shareholders approved the change of our corporate name to Petrobras Energía Participaciones S.A. from Perez Companc S.A. On the same date, shareholders of Pecom Energía S.A., or Pecom, approved the change of its name to Petrobras Energía S.A. Both changes were registered with the National Corporate Registrant (Inspección General de Justicia) on July 17, 2003.

     On May 13, 2003, the CNDC approved the purchase of 58.62% of Petrobras Energía Participaciones S.A’s capital stock.

History of Petrobras Energía

     Petrobras Energía was founded in 1946 as a shipping company by the Perez Companc family. In the mid-1950’s Petrobras Energía began its forestry operations when it acquired an important forestry area in northeastern Argentina. In 1960, Petrobras Energía began servicing oil wells, and, over time, its maritime operations were gradually discontinued and replaced by oil-related activities. The development of Petrobras Energía’s oil and gas business is marked by two significant events. The first occurred in the early 1990s, when Petrobras Energía was

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awarded concessions to operate Puesto Hernandez, the second most important oilfield in Argentina, and the Faro Virgenes and Santa Cruz II areas in the Austral basin, Argentina’s most important area of oil and gas production. As a result of this and other concessions, Petrobras Energía has become one of the largest oil and gas producers in Argentina.

     The second milestone in Petrobras Energía’s oil and gas operations occurred in 1994 when Petrobras Energía bid on and was awarded an exploration and production service contract for the Oritupano Leona area in Venezuela. Over the last few years Petrobras Energía has expanded its operations rapidly in Venezuela, Peru, Ecuador, Brazil and Bolivia as part of its strategy to become a leading integrated energy company in Latin America.

     Petrobras Energía developed its other energy businesses primarily through the acquisition of interests in state-owned companies that were privatized by the Argentine government between 1990 and 1994. Petrobras Energía acquired interests in companies operating in refining and petrochemicals, hydrocarbon transportation and distribution and power generation, transmission and distribution. These companies have formed the core of Petrobras Energía’s energy businesses.

     In addition to the energy sector, Petrobras Energía has in the past conducted operations in other industries, including construction, telecommunications and mining. Petrobras Energía entered the construction business in the 1970s when it acquired Sade S.A. Petrobras Energía entered the telecommunications business when it acquired an interest in Nortel Inversora S.A., the controlling shareholder of Telecom Argentina, an Argentine telephone services provider, in the early 1990s when the Argentine government privatized the telecommunications industry. These businesses were sold by Petrobras Energía during the late 1990s as part of Petrobras Energía’s strategy to focus its operations on the energy sector. As a result of these divestitures and the development of Petrobras Energía’s energy businesses over the last decade, Petrobras Energía has become a vertically integrated energy company.

Capital Expenditures and Divestitures

     For a description of our most significant divestitures see “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations” and “—Business Overview—Divestments of non-core assets.” For a description of our capital expenditures see “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.”

BUSINESS OVERVIEW

Our Strategy

     Our long-term strategy is to grow as an integrated energy company with a leading presence in Latin America as part of the Petrobras group, while focusing on profitability as well as social responsibility.

     We will continue to integrate our business in order to take full advantage of our significant hydrocarbon reserves.

     We consider the following objectives essential in our efforts to meet these goals:

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     We currently manage our activities, with the support of the corporate staff, in five business segments: Oil and Gas Exploration and Production, Hydrocarbon Marketing and Transportation, Refining, Petrochemicals, and Electricity.

OIL AND GAS EXPLORATION AND PRODUCTION

Overview

     The core of our operations is the oil and gas exploration and production business segment. In line with our profitability and cash generation goals, this business segment’s strategy is based on the following: (1) sustained growth of operations by capitalizing on our experience and presence in almost all Latin American oil producing countries, (2) aggressive field exploration as a significant vehicle for growth, (3) monetization of our oil and gas reserves, (4) low lifting costs, and (5) investment portfolio optimization.

     We currently conduct oil and gas exploration and production operations in Argentina, Venezuela, Peru, Bolivia and Ecuador.

     As of December 31, 2003, our combined crude oil and natural gas proved reserves, including our shares of the reserves of our unconsolidated investees, were estimated at 758.1 million barrels of oil equivalent, approximately 53% of which were proved developed reserves and approximately 47% of which were proved undeveloped reserves. Crude oil accounted for approximately 75.1% of our combined proved reserves, while natural gas accounted for about 24.9%. As of December 31, 2003, 40.1% of our total combined proved reserves were located in Argentina and 59.9% were located abroad. Over the last few years, total reserves located abroad have become an increasing component of our assets portfolio, consistent with our strategy aimed at growing as an integrated energy company throughout Latin America. Pursuant to this strategy, between 2001 and 2003, total investments outside of Argentina accounted for 65% of our total investments.

     For the year ended December 31, 2003, our combined crude oil and natural gas production, including our share of the production of our unconsolidated investees, averaged 158.6 thousand barrels of oil equivalent per day (114.6 thousand oil barrels and 264 million cubic feet of natural gas per day). Approximately 49.6% of our oil production and 23.4% of our gas production were outside of Argentina. In particular, in 2003, Venezuelan production became a main component of our total production, accounting for 27.3% of our total average production in barrels of oil equivalent.

     Deliveries of oil equivalent, including those relating to unconsolidated investees, totaled 161.3 thousand barrels of oil equivalent per day.

     As of December 2003, we had total proved reserves equal to 13.1 years of production at 2003 oil and gas production levels.

     Our integrated business vision places our refining, petrochemicals and electricity businesses as primary links in our business value chain, through which the potential of our significant hydrocarbon reserves may be maximized. Integration with our refining business segment enables us to process a large part of our crude oil production in Argentina. The Genelba Power Plant allows us to use approximately 2.8 millions cubic meters of natural gas per day of our own reserves. In addition, we supply gas to our petrochemical operations in Argentina.

Investments

     Significant investments made by us in the past have laid a foundation for the expansion and growth of our oil and gas exploration and production segment. During 1999-2001, investments totaled P$3,165 million.

     The 2002 fiscal year marked a change in our investment history. The magnitude and complexity of the crisis that broke out in Argentina late in 2001 and the limited opportunities to access the capital markets forced us to reformulate our growth strategy. Given this new environment, we developed a new strategy that prioritizes cash

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generation and the maintenance of adequate liquidity levels. This has resulted in more restrictive expense and investment policies. As a result, capital expenditures in 2002 totaled only P$596 million, a relatively low amount compared to our historical average investment levels.

     The reduced pace of investments influenced our growth objectives in the short term, mainly affecting our future production volumes of oil and gas. In addition, reduced investments delayed the development of new exploitation areas and related production.

     In 2003, as the Argentine economy began to improve, our operating cash flow recovered and our liquidity approached our target levels, which allowed our investment levels to partially recover. In 2003, capital expenditures totaled P$696 million, accounting for a 17% increase compared to 2002. Capital expenditures in 2003 focused on maintaining production and increasing cash flow generation, while prioritizing investments in countries and in products with higher profit margins.

Our Oil and Gas Exploration and Production Interests

     We generally participate in exploration and production activities in conjunction with joint venture partners, as is commonplace in the oil and gas exploration and production business. Contractual arrangements among participants in a joint venture are usually governed by an operating agreement, which provides that costs, entitlements to production, and liabilities are to be shared according to each party’s percentage interest in the joint venture. One party to the joint venture is usually appointed as operator and is responsible for conducting the operations under the overall supervision and control of an operating committee that consists of representatives of each party to the joint venture. While operating agreements generally provide for liabilities to be borne by the participants according to their respective percentage interest, licenses issued by the relevant governmental authority generally provide that participants in joint ventures are jointly and severally liable for their obligations to that governmental authority pursuant to the applicable license. In addition to their interest in field production, contractual operators are generally paid their production costs on a monthly basis by their partners in proportion to their participation in the relevant field. Our joint venture partners are oil companies that are active in Argentina and subsidiaries of overseas oil companies.

     As of December 31, 2003, we had interests in 24 oil fields, 17 of which are oil and gas producing fields and seven of which are located in exploration areas, four in Argentina and three outside of Argentina. We are, directly or indirectly, the contractual operator of 21 of the 24 fields in which we have an interest.

     As of December 31, 2003, our total gross and net productive wells were as follows:

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     As of December 31, 2003, our total producing and exploration acreage, both gross and net, is shown in the following table:

Production

Argentine Production

     Argentina is currently the fourth largest oil producer in Latin America after Mexico, Venezuela and Brazil. In 2003, Argentina’s daily production was approximately 720 thousand barrels, accounting for approximately 8.1% of the region’s total production. Production from Mexico, Venezuela and Brazil accounts for about 37.7%, 22.6% and 17.2%, respectively, of total oil production in Latin America.

     According to statistical data for 2002, Argentina has the second largest amount of natural gas proved reserves in Latin America. Reserve volumes in Argentina coupled with its highly developed gas infrastructure, both for the domestic and export markets, has enabled the country to position itself as an energy leader in the region. Considering its significant gas reserves, as well as the tremendous growth in electric power generation supplied by natural gas in the southern part of South America, Argentina is expected to consolidate its position as a large gas exporter to Chile, Brazil and Uruguay.

     Since the privatization of natural gas utilities in 1992, the natural gas industry in Argentina has grown significantly as a result of a number of factors, including: (i) an increase in gas availability, (ii) increased and improved transportation and distribution, (iii) environmental efficiency, (iv) low prices as compared to international levels and (v) alternative fuels in the domestic market. As a result of natural gas’s competitiveness, demand for gas significantly increased from 17,800 million cubic meters in 1990 to 43,466 million cubic meters in 2003, and natural gas became the preferred fuel for both residential and industrial users as well as electricity generation companies.

     In response to this increased demand for natural gas, we made significant investments in each step of the natural gas chain during the last decade. Transportation and distribution licensees, in turn, also made sizable investments. As a result, our gas transportation capacity doubled from 67 million cubic meters per day to 115 million cubic meters per day and distribution networks increased in size by 53%. These investments allowed for exports to bordering countries and led to a suspension of imports. The higher gas availability resulting from the expansion of gas pipelines and distribution networks caused the tripling of the number of compressed natural gas, or CNG, stations. CNG is the least expensive and least polluting motor fuel. As a result, Argentina currently has the largest CNG-fueled vehicle fleet in the world.

     Notwithstanding this segment’s potential, the Public Emergency Law has significantly changed the applicable regulatory framework and has adversely affected the economic attractiveness of the gas business. Following enactment of this law, there has been an abrupt reduction of investment in exploration activities in Argentina. This reduction, combined with the increase in demand, has significantly reduced Argentina’s horizon of reserves, which decreased from approximately 25 years of production in the beginning of the 1990s to a 14-year

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reserve by the end of 2002. Without a clear path to price recovery, there may be structural uncertainties as to the future potential of the gas industry and the consequent integral use of reserves.

     In the fiscal year ended December 31, 2003, our oil and gas production accounted for 4.6% and 3.9% of total oil and gas production in Argentina, respectively. As of December 31, 2003, we had interests in ten Argentine oil and gas production fields, with production rights in 3,211 thousand net acres.

     Our production is concentrated in two basins, the Neuquén and the Austral basins. This positioning helps to optimize our operating efficiency and capitalize on the operating synergies of our own assets. The Neuquén basin is the most important area in Argentina in terms of oil and gas production. We own 579 thousand net acres under production concessions. Our most important fields in the Neuquén basin are 25 de Mayo-Medanito S.E., Puesto Hernández and Río Neuquén. In the Austral basin we own 2,632 thousand net acres under production concessions, with Santa Cruz I and Santa Cruz II being our most important fields in that basin.

     In line with our current strategy, we have implemented the following initiatives during the last three years:

     Rights to develop oil and gas fields in Argentina are granted through concessions and exploration permits. Concessions are generally granted for periods of 25 years and are typically renewable for a maximum term of ten years, and permits are generally granted for initial periods of three years. The concessions for all production areas in Argentina typically provide for the free availability of oil. All permanent fixtures, materials and equipment are under the control of the concessionaire, although they revert to the Argentine government at the end of the concession. Royalties are paid to the respective Argentine provinces for the production of crude oil and the volumes of natural gas produced for sale. These royalties are 12% of the wellhead price for oil and gas. The wellhead price used to determine the royalty cost is similar to the final sales price less treatment, storage and transportation costs.

Production outside of Argentina

     As a result of the substantial investments we have made in the rest of Latin America in recent years, as of December 31, 2003, 59.9% of our combined proved reserves were located outside of Argentina. In addition, approximately 49.6% of our oil production and 23.4% of our gas production came from outside Argentina in 2003. We have interest in seven oil and gas production fields outside of Argentina: Oritupano-Leona, Acema, La Concepción and Mata in Venezuela, Lote X in Peru, Block 18 in Ecuador and Colpa Caranda in Bolivia.

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Venezuela

     Venezuela is an important country in the international oil market. With proven reserves of approximately 77.8 billion barrels of crude oil in 2003, Venezuela possesses the largest proven reserves in the Western Hemisphere and has 7% of the total reserves on earth. Its commercial production is concentrated in the basins of Zulia and Barinas-Apure in the western part of the country and in the basins of the Estados Monagas and Anzoátegui in the eastern part of the country. Venezuela also has billions of barrels of heavy duty crude and bitumenes, the great majority of which is situated in the Faja Petrolífera of Orinoco.

     In 2002, Venezuela produced approximately 2.6 million barrels of crude oil a day, of which close to 407,000 barrels were consumed in the local market and the rest were exported. It is worth noting that production levels were affected by a general strike that took place in the beginning of December of 2002 and lasted until February of 2003. See “Item 3. Key Information—Risk Factors—Factors Related to Venezuela.”

     Production from Venezuela has become an important part of our total production, accounting for 27.3% of the total average production in barrels of oil equivalent in 2003.

     In Venezuela, our rights are held under operating service contracts.

     In 1994, during the second round of operating agreements, we were awarded the first service contract by PDVSA at the Oritupano-Leona field to provide production services for a 20-year period, which may be extended for an additional ten-year period. Oritupano-Leona is a 215 thousand net acre block located in the Oriental basin that includes 263 producing wells.

     The Oritupano Leona joint venture’s sole customer for the sale of oil production is PDVSA. Per our operating service agreement, PDVSA is the sole owner of the facilities, assets and/or operating equipment used by the joint venture to conduct the activities provided for in this agreement. For the provision of production services, we receive a variable fee based on production volumes plus an additional fee for reimbursement of capital expenditures, on a quarterly basis during the first ten-year term of the agreement. Expenses related to investments made thereafter will be recovered over the rest of the term. Any of these unpaid expenses will bear interest of up to 1% over the London Interbank Offered Rate, or LIBOR, annual rate. The contract has a cap (maximum total fee) on the amount which we can collect, which is reset quarterly based on the market price of oil. As of December 2003, this cap was approximately U.S.$28.72 per barrel.

     In 1997, PDVSA awarded us three 20-year service contracts for the exploration and production of Acema, La Concepción and Mata blocks in the so-called Third Round bids. The bids were initially made through joint ventures. Currently, we have a 90% interest in the La Concepción block and a 86.23% interest in the Acema and Mata oil blocks, which, together with the La Concepción, block we refer to as the Third Round Blocks. La Concepción is a 55 thousand net acre block located in the Maracaibo basin, with 92 producing wells. Acema and Mata, located in the Oriental basin, are 64 thousand and 45 thousand acre blocks with 22 and 53 producing wells, respectively. According to the concession contracts, PDVSA will be the sole owner of the facilities, assets, and operating equipment. We receive a fee for each barrel delivered which has a fixed component related to contractual baseline production and a variable component related to the incremental production that covers investments and production costs, plus a gross profit up to a maximum that is tied to a basket of international oil prices.

     Effective January 2002, the Venezuelan government adopted a new law whereby royalty payments increased from 16.67% to 30%. This law had a significant adverse impact on the operating results of our Third Round Blocks. We are taking every necessary step to partially reverse this increase, since under a new hydrocarbons law the federal executive may reduce such royalties by up to 20%.

     The government of Venezuela may set a limit on our oil production under the terms of the service agreements. Venezuela is a member of OPEC and has set forth a policy of strict compliance with the production quotas decided within OPEC. According to the Venezuelan Hydrocarbon Law, any decisions made by the federal administration in connection with agreements or international treaties involving hydrocarbons are applicable to any party that carries out the activities governed by the law. As a result of this, if there are production cuts approved by OPEC, these cuts affect private producers as well as PDVSA. See “—Regulation of Our Businesses—The

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Venezuela Petroleum and Gas Industry and Regulatory Framework.” Production cuts were only contemplated by the third round operating agreements, which we refer to as the Third Round Agreements, but not by the second round operating agreements, which we refer to as the Second Round Agreements, which apply to the Oritupano-Leona field. Although no production cuts have been ordered under the Second Round Agreements to date, it is not completely clear whether the constitutional principle that prohibits retroactive application of the law will protect Second Round Agreements against future production cuts.

Peru

     In 1996, we acquired 30-year oil and 40-year natural gas production rights in Lote X, a 116 thousand acre block in Peru’s Talara basin, through a public bidding process. The purchase included all of the then existing assets on the site. The concession agreement provides for the free availability of hydrocarbons. As of December 31, 2003, Lote X had 2,366 productive wells. We have entered into a long-term sales contract under which Perupetro S.A., the Peruvian state-owned company which we refer to as Perupetro, is obligated to purchase all of our production at market prices. Hydrocarbon sales are subject to royalty payments of 24% of the sales price. The sales contract is set to expire in July 2006.

     In June 2003, the Peruvian government approved the National Law for the Promotion of Investment in the Exploitation of Resources and Marginal Reserves of Hydrocarbons (Ley para la Promoción de la Inversión en la Explotación de Recursos y Reservas Marginales de Hidrocarburos a Nivel Nacional) through which Perupetro is authorized to reduce the level of royalty payments. This reduction would be contingent on the concessionairés agreeing to minimum production levels and work programs. Under this scheme, we entered into an agreement with Perupetro, modifying the original terms of our concession, in which we promised to invest U.S.$65 million during the first five years and U.S.$33 million in the following two years, in exchange for a reduction in royalty payments, which, under current conditions, we estimate would decline to 16.5%. This agreement becomes valid simultaneously with the promulgation of the Supreme Decree (Decreto Supremo) approving the modification of our concession.

     Peru production accounted for 8.1% of our total average production in barrels of oil equivalent in 2003.

Bolivia

     Petrobras Energía has a 100% interest in the oil and gas fields of Colpa Caranda and has operated them since 1989. Colpa Caranda is a 56 thousand net acre block located in the Sub Andina Central basin that has 55 producing wells. Approximately 88.6% of our proved developed reserves in Bolivia are gas. These fields, which originally supplied Bolivian gas exports to Argentina, currently have priority in the dispatch of gas to the Santa Cruz-São Paulo pipeline that transports gas to Brazil. Bolivia production accounted for 3.8% of our total average production in barrels of oil equivalent in 2003.

Ecuador

     In 2001, we acquired a 70% interest in Block 18, located in the Oriente basin of Ecuador. Block 18 is a field covering 197 thousand acres and having a significant potential of 28º to 33° API light crude oil reserves. The concession for production activities in Block 18 will be for an initial 20-year term as from October 2002. Once this term expires, the Ecuadorian hydrocarbons law provides for the possibility of an additional five-year extension period.

     In October 2002, the Hydrocarbons National Directorate approved the development plan for the Pata field in Block 18, thereby initiating its production phase until October 2022. The Government has the right to take 35% of production, in kind. Exploratory activities will continue for an additional three-year period ending October 2005.

     In August 2002, Petroecuador, the Ecuadorian state-owned oil company, subscribed to a joint exploitation agreement for the Palo Azul field in Block 18. In December of 2002, the Palo Azul development plan was approved and has been extended until December 2022. The general terms of the agreement include differential production sharing percentages according to a formula that takes into account the final selling price of Palo Azul’s crude oil and the level of total proved reserves. Specifically, if Palo Azul’s crude oil sells at a price less than U.S.$15 per barrel, the State’s share of crude oil equals 30%. If crude oil sells at a price greater or equal to U.S.$24 per barrel, the

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State’s share of crude oil equals about 50%. For all other price ranges, a scale was agreed with Petroecuador. Palo Azul’s selling price is computed by considering the WTI crude oil benchmark minus the market discount for the Oriente crude oil. The agreement provides for the free availability of crude oil.

     Block 18 has eight productive wells, two of which are 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.

Mexico

     In 2003, as part of the bidding launched by Petróleos Mexicanos, or 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 Petrobras, Teikoku and Diavaz. Under an operating agreement, we will act as contractor and provide the joint venture with the technical and operating support required for the operation of the Cuervito and Fronterizo blocks.

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Statistical Information Relating to Oil and Gas Production

     The following table sets forth our oil and gas fields’ production as of December 31, 2003. In addition, the table includes our percentage interest in the oil and gas production of each field, the number of producing wells and the expiration date of the concessions. Although some of these concessions may be extended at their expiration, the expiration dates set forth below do not include any such extensions.

     In 2003, our annual production from producing oil fields, including our oil fields in Bolivia, Venezuela, Peru and Ecuador, was 41.8 million barrels of oil, 21.1 million of which were produced in Argentina. Our annual production of gas amounted to 96.3 million cubic feet, 73.8 million cubic feet of which were produced in Argentina.

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     The following table sets forth our average daily production of oil, including other liquid hydrocarbons, for the three fiscal years ended December 31, 2003, 2002 and 2001. This table includes our proportionate share of the production of both our consolidated subsidiaries and our unconsolidated investees.

     The following table sets forth our average daily gas production for the three fiscal years ended December 31, 2003, 2002 and 2001. This table includes our proportionate share of the production of both our consolidated subsidiaries and our unconsolidated investees.

     The following table sets forth the average sales price per barrel of oil and per thousand cubic feet of gas for each geographic area for the three fiscal years ended December 31, 2003, 2002 and 2001, of our consolidated subsidiaries.

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     The following table sets forth our average lifting cost, royalties and depreciation cost of oil and gas fields in each geographic area for the three fiscal years ended December 31, 2003, 2002 and 2001. This table includes our proportionate share of the production of our consolidated subsidiaries.

     The following table sets forth the average reserve replacement cost and the finding and development costs of oil and gas from all fields for the three fiscal years ended December 31, 2003, 2002 and 2001. This table includes our proportionate share of the production of both our consolidated subsidiaries and our unconsolidated investees.

Exploration

Overview

     We believe that an increase in exploration is essential to maintain and grow our reserve base. Exploration is a key activity to sustain a high reserve replacement ratio.

     We use 3-D seismic technology to ensure a technologically sound prospect portfolio and a high success rate. The integration of well and 3-D seismic data into subsurface models is critical for exploration drilling, field delineation and optimization of the appraisal of well locations.

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     The following table lists our oil and gas fields in exploration areas as of December 31, 2003, the location of the basin in each area, our ownership interest and the expiration date of the exploration permits for each field.

Exploration in Argentina

     As of December 31, 2003, we hold interest in 911 thousand gross acres (887 thousand net acres) of basin area in Argentina available for exploration. Under exploration licenses we hold interests in Glencross, Santa Cruz I — Oeste and CAM-2A exploratory areas. We may continue to acquire acreage positions in the future as the Argentine government offers additional exploration permits through license bidding rounds.

     We compete with other oil and gas producers in Argentina for the acquisition of new properties.

     The following table sets forth the number of wells we drilled in Argentina, and the results thereof, for the periods indicated. A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil and gas. A well is deemed to be a dry hole if it is determined to be incapable of commercial production. “Gross wells drilled” in the tables below refers to the number of wells completed during each fiscal year, regardless of the spud date, and “net wells drilled” relates to the fractional ownership working interest in wells drilled. This table includes wells drilled by both our consolidated subsidiaries and unconsolidated investees.

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     During 2002, we farmed out a 50% interest in Santa Cruz I exploratory block. The buyer committed to make all the investments necessary to acquire and process 500 km2 of 3-D seismic lines and to drill five wells. However, we remain responsible for conducting operations in this block.

Exploration Outside of Argentina

     As of December 31, 2003, we hold interests in 857 thousand gross acres (675 thousand net acres) outside of Argentina available for exploration. We hold interests in three oil and gas exploration fields outside of Argentina: San Carlos and Tinaco in Venezuela and Block 31 in Ecuador. We continue to seek new business opportunities in Peru, Bolivia, Ecuador and Venezuela.

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     The following table sets forth our drilling activities outside of Argentina for the three years ended December 31, 2003, 2002 and 2001. A well is considered productive for purposes of the following table if it justifies the installation of permanent equipment for the production of oil and gas. A well is considered to be a dry hole if it is determined to be incapable of commercial production. This table includes both our consolidated subsidiaries and unconsolidated investees.

     Venezuela

     We began exploration activities in the San Carlos region of western Venezuela under a contract entered into with PDVSA through its subsidiary, Corporación Venezolana de Petróleo S.A., in July 1996. The block is located in the areas of Cojedes and Portuguesa and extends across 125 thousand acres. We are required to pay all exploration costs in the block. The exploration activities in this block started late in 1996 and the work commitments for the first stage of the exploration process were fulfilled with the acquisition of 2-D seismic data and the drilling of 2 exploratory wells. Total expenditures required for initial exploration in the block were U.S.$32 million. Our exploration activities in this block yielded gas findings.

     In June 2001, upon the opening of free gas exploration areas, we were awarded a license for the exploration and production of gas in the Tinaco area, a field adjacent to the San Carlos field, with an area of 238 thousand acres. This event is an important step in the development of the San Carlos block, since it would enable us to confirm related natural gas reserves. The contractual work commitments included the acquisition of 200 km of 2-D seismic data.

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     During 2003, the conditions prevailing in the political, economic and social arena in Venezuela prevented the performance of the 2-D seismic works in the Tinaco area. These works will be completed throughout the first half of 2004. Depending on the seismic results obtained, an exploratory well may be drilled in 2005.

     If gas reserves are commercialized in the future, we will be required to pay 23.21% in royalties.

     In connection with the joint future gas production of both blocks, we negotiated the conversion of the San Carlos contract into a contract with similar conditions as those appearing in the Tinaco contract.

     In October 2002, we subscribed to an association agreement, which we refer to as the Transfer of Interest Agreements, with Teikoku Oil Co. Ltd., or Teikoku, whereby we transferred 50% of our rights and obligations in and to gas production in San Carlos and Tinaco exploratory areas.

     The Transfer of Interest Agreement, which is subject to approval by the Venezuelan Ministry of Energy and Mines, provides for an initial cash payment of U.S.$1 million and a subsequent payment of U.S.$2 million for the financing of the exploratory investment program in the Tinaco area in relation to geological studies, 2-D seismic shooting and 2-D seismic evaluation and interpretation. Furthermore, in the event a joint commercial development in this area is agreed upon, we will receive a supplementary payment in the amount of U.S.$3 million.

     Ecuador

     In Ecuador, we hold a 100% interest in Block 31. In 1996, Petroecuador called the Eighth Round of International Bids for the performance of exploration and production activities in the Amazon Region, and we were awarded 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 full development of the block, we estimate that approximately U.S.$800 million in investments will be required. Initial investments in the amount of approximately U.S.$150 million are necessary prior to the production phase. Changes in our investment scenario following the Argentine crisis have resulted in significant delays to our original investment plan for the area’s development.

     Under the concession contract, the exploration program is divided into two phases, with the first phase having expired in July 2001 and the second in June 2003. To fulfill the committed work program, 1,200 km of 2-D seismic lines were acquired and three exploratory wells were drilled.

     We have conducted the following works in Block 31: 1,382 km of 2-D seismic, 167 km ² of 3-D seismic, and the drilling of four exploratory wells in Apaika, Nenke, Obe and Minta. All the wells were successful and led to the discovery of the Apaika/Nenke, Obe, and Minta fields. Interpretation of 600 km of 2-D seismic acquired in the eastern and northeastern areas of the block was also performed. The 3-D seismic cube (167 km2) was reprocessed to ensure better adjustment to 2-D seismic. In March 2004, the Minister of Energy of Ecuador approved an environmental impact study, completing all of the required steps for the approval of the development plan. Following approval of the environmental study, a twenty-year exploitation period has begun, during which, in the initial three-year period, the plan contemplates investments of U.S.$75 million. We are obligated to give Petroecuador a guaranty of 20% of this amount.

     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 and crude oil gravity. The Block 31 concession provides for the free availability of crude oil.

     Future oil production in Block 31 will be shipped through a heavy crude oil pipeline known as Oleoducto de Crudo Pesados in which we currently have an 11.42% interest. We have entered into a 15-year “ship or pay” transportation contract under which OCP has committed to provide us with a shipping capacity of 80,000 barrels per day. OCP started commercial operations on November 10, 2003 and since that date, we have had to comply with our contractual obligations with respect to our committed acquired capacity by paying a transportation capacity fee. We currently estimate that during the contract’s term, oil production will be lower than our committed transportation capacity. Accordingly, as of December 31, 2003, we have recorded an impairment allowance of P$321 to adjust the book value of our group of assets in Ecuador to its recoverable value. See “Item 3. Key Information—Risk Factors—Factor Relating to Us—Production of oil in Block 31 in

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Ecuador is significantly delayed, and this delay has and will continue to affect our results. Further delays could result in an increase in our operating losses related to our group of assets in Ecuador.”

     As a way of maximizing the value of this asset and enhancing its potential, we are considering a number of alternatives, including the addition of a new partner who could speed up the development of the block or a potential sale of all or a portion of our interest in Block 31. A transaction involving a sale of all or part of our interest in Block 31 may likely involve a sale or other disposition of all or a portion of our interests in Block 18 and in OCP.

     Peru

     In 1998, Petrobras Energía entered into exploration agreements for Lote XVI, in which it has a 100% interest. Exploratory investments were first made in this block in 1999, with the shooting of 50 km2 of 3-D seismic lines. During 2002, interpretation of the block geology was concluded and a location was selected for the drilling of an exploration well in 2003. Due to the disappointing results of the exploration, in May 2003, we decided not to proceed to the next phase.

     In the Ucayali basin, two blocks were awarded to a consortium formed by Petrobras Energía and Repsol-YPF S.A., the latter being the operator of both blocks. Seven-year exploration contracts were signed in September 1998 for Lote 34 and in November 1998 for Lote 35. We had a 40% interest in Lote 34 and a 35.15% interest in Lote 35. Both contracts provide for an initial two-year exploration phase, each with a commitment of 500 km 2-D seismic line acquisition and the reprocessing of 1,000 km of existing 2-D seismic data. The subsequent five one-year exploration periods are optional, and each period requires the drilling of an exploration well or compensatory exploratory seismic. The wildcat Mashansha 35-13-IX in the Lote 35 was drilled in 2002. The well resulted in a dry hole with sparse oil shows. In 2003, after a thorough evaluation of the well results and the impact on the additional exploration objectives, it was decided not to continue in both blocks due to the limited remaining exploration potential.

     In 2001, we executed a concession contract for hydrocarbon exploration and production in Lote 99, a block located in the Ucayali basin. We hold a 100% interest in Lote 99. The concession program requires a minimum exploration program of seven years divided into five periods. Exploration during the first 18-month period included geological surveys and the reprocessing and reinterpretation of 900 km2 of seismic data. In 2003, after evaluating the exploration results, we decided not to proceed to the next stage.

     In May 2004, we entered into a contract with Repsol Exploración Perú S.A. to perform certain exploration activities jointly in Lot 57. Petrobras Energía has an option to participate in Lot 57 by acquiring a 35.15% interest from Repsol, which currently holds a 76.15% interest in Lot 57. Burlington Resources Perú Ltd. is Repsol’s partner in the shared risk agreement with Perupetro for the exploration and exploitation of hydrocarbons in Lot 57.

     In the Lote 63 area, the survey period has concluded and an exploration contract will be negotiated with Perupetro.

Reserves

     We believe our estimates of remaining proved recoverable oil and gas reserve volumes to be reasonable. These estimates have been prepared in accordance with Rule 4-10 of Regulation S-X under the U.S. Securities Act. Gaffney, Cline & Associates, Inc., an international technical and management advisory firm for the oil and gas industry, audited our oil and gas reserves as of December 31, 2003, 2002 and 2001.

     The estimated reserves were subjected to economic tests to determine economic limits. These estimated reserves in Argentina, Peru and Bolivia are stated prior to the payment of any royalties, as they have the same attributes as taxes on production and, therefore, are treated as operating costs. In Ecuador, due to the type of contract in which the government has the right to a percentage of production and takes it in kind, reserves are stated after such percentage. In Venezuela, the government maintains full ownership of all hydrocarbons in such areas. Reserve volumes in Venezuela are computed by multiplying our percentage interest by the gross proved recoverable volumes for the contract area. In Venezuela, for the Acema, Mata and La Concepción areas, 30% royalties are paid, calculated based on the crude wellhead estimated price. Under contractual terms the Third Round Block’s royalties

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are deducted from the sales price. Pursuant to operating agreements in force, we are exempt from production royalty payments in the Oritupano Leona field.

     As of December 31, 2003, liquid hydrocarbon and natural gas proved reserves, audited by Gaffney, Cline & Associates, Inc., amounted to 758.1 million barrels of oil equivalent (569.1 million barrels of oil and 1,134.8 billion cubic feet of natural gas, representing a 6.7% decline compared to the reserves certified as of December 31, 2002 (a decline of 4.2% for liquid hydrocarbons and 13.6% for natural gas)).

     As of December 2003, total proved reserves represented, at 2003 oil and gas production levels, a 13.1-year production.

     During the 2002-2003 period, after the change in the investment scenario for our businesses following the Argentine crisis, we focused on maintaining adequate liquidity levels and cash generation, and this focus affected our reserve replacement strategy. Production of proved undeveloped reserves was prioritized relative to prior years, with a reduced emphasis on exploration and acquisition activities, which had historically been a major source of reserve replacement. This had a negative impact on the addition of reserves.

     Therefore, during 2003 the reserve replacement ratio was 33%, reflecting production of 57.9 million barrels of oil equivalent which was partially offset by a net addition of 19.3 million barrels of oil equivalent, as reflected below:

     In addition, in 2003, the sale of the Catriel Oeste and Faro Vírgenes areas in Argentina reduced our reserves by 15.9 million barrels of oil equivalent.

     Liquid hydrocarbons and natural gas account for 75.1% and 24.9%, respectively, of total proved reserves, and 59.9% are located outside of Argentina. Proved reserves outside Argentina increased as a percentage of proved reserves. This increase reflects principally lower investments in gas projects in Argentina, which were scaled back in light of low domestic prices, with a consequent reduction in additions from recoveries, extensions and discoveries.

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     The table below sets forth, by geographic area, total proved reserves and proved developed reserves of crude oil, condensate and natural gas liquids and natural gas reserves at the indicated dates.