Edgar Filing: PETROBRAS ENERGIA PARTICIPACIONES SA

Year ended December 31,

Production (thousands of tons)

Sales (in millions of pesos)

Form 20-F

As filed with the Securities and Exchange Commission on June 30, 2005

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 20-F

ANNUAL REPORT PURSUANT TO SECTION 13

OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2004

Commission file number 333-11130

PETROBRAS ENERGÍA PARTICIPACIONES S.A.

(Exact name of Registrant as specified in its charter)


N/A		REPUBLIC OF ARGENTINA
(Translation of Registrant’s name into English)		(Jurisdiction of incorporation of organization)

Maipú 1, 22^nd Floor

(C1084ABA) Buenos Aires

Argentina

(Address of principal executive offices)

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

Title of each Class

Name of Each Exchange

On Which Registered

American Depositary Shares, each representing 10 Class B shares

New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

The number of outstanding shares of each of the issuer’s classes of capital or common stock as of December 31, 2004 was:


Class B ordinary shares, par value P$1.00 per share		2,132,043,387

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days:

Yes x No ¨

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

Item 17 ¨ Item 18 x

TABLE OF CONTENTS


		Page
Item 1-2.	Not Applicable	2

Item 3.	Key Information	2

Selected Financial Data		2

Exchange Rates		6

Risk Factors		8

Item 4.	Information About the Company	18

Oil and Gas Exploration and Production		23

Hydrocarbon Marketing and Transportation		40

Refining		45

Petrochemicals		49

Electricity		53

Regulation of Our Businesses		64

Organization Structure		88

Item 5.	Operating and Financial Review and Prospects	92

Factors Affecting our Consolidated Results of Operations		95

Discussion of Results		106

Critical Accounting Policies		134

Liquidity and Capital Resources		137

Item 6.	Directors, Senior Management and Employees	150

Item 7.	Major Shareholders and Related Party Transactions	161

Item 8.	Financial Information	165

Item 9.	Offer and Listing	167

Item 10.	Additional Information	169

Item 11.	Quantitative and Qualitative Disclosures About Market Risk	185

Item 12-14.	Not Applicable	188

Item 15.	Controls and Procedures	188

Item 16A.	Audit Committee Financial Expert	189

Item 16B.	Code of Ethics	189

Item 16C.	Principal Accountant Fees and Services	189

Item 16D.	Not Applicable	190

Item 16E.	Purchases Of Equity Securities By The Issuer And Affiliated Purchasers	190

Item 17.	Not Applicable	190

Item 18.	Financial Statements	190

Item 19.	Exhibits	191

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 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. See “Item 4. Information About the Company—Our History and Development.”

“Petrobras” refers to Petróleo Brasileiro S.A. — PETROBRAS.

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

“US dollars” or “US$” 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 capital expenditures, competition and sales, oil and gas reserves and prospects and trends in the oil and gas, refining, 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 3. Key Information—Risk Factors” and elsewhere in this annual report. Factors that could cause actual results to differ materially and adversely include, but are not limited to:

•

Changes in general economic, business, political or other conditions in Argentina or changes in general economic or business conditions in other Latin America countries;

•

The availability of financing at reasonable terms to Argentine companies, such as us;

•

The failure of governmental authorities to approve proposed measures or transactions described in this annual report;

•

Changes in the price of hydrocarbons;

•

Changes to our capital expenditure plans;

•

Changes in laws or regulations affecting our operations;

•

Increased costs; and

•

Other factors discussed under “Risk Factors” in Item 3 of this annual report.

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.

Item 1-2.

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 consolidated financial statements are prepared in accordance with regulations of the National Securities Commission (Comisión Nacional de Valores), which we refer to as the CNV, and, except for the matters described in note 3 to our consolidated financial statements, with generally accepted accounting principles in Argentina (as approved by the Professional Council of Economic Sciences of the City of Buenos Aires, or CPCECABA), which we refer to as Argentine GAAP. Argentine GAAP differs in certain significant respects from generally accepted accounting principles in the United States, which we refer to as 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.

We are a holding company whose only asset as of December 31, 2004 is our 98.21% equity interest in Petrobras Energía. Our interest in Petrobras Energía is expected to decrease to 75.82% as a result of the merger of certain companies controlled by Petrobras into Petrobras Energía, which is further described in “Item 4. Information About the Company—Our History and Development—The Petrobras Energía Merger.” We were initially 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 selected financial data relating to the fiscal years ended December 31, 2004, 2003 and 2002 set forth below have been derived from our financial statements included in this annual report. Selected financial data for the fiscal years ended December 31, 2000 has not been restated to reflect the changes in Argentine GAAP, and accordingly is not comparable to the financial data for the fiscal years ended December 31, 2004, 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.

Presentation of figures in constant Argentine pesos

Due to the inflationary environment in Argentina in 2002, there was a 118.2% increase in the applicable wholesale price index used in the restatement of our financial statement from the period of January 1, through December 31, 2002, the 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.

On July 16, 2002, the Argentine government issued Decree No. 1,269/02 instructing the CNV and other regulatory authorities to issue the necessary regulations for the delivery to such authorities of 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. This method was not in accordance with professional accounting standads effective in the city of Buenos Aires. The CPCECABA, through Resolution No. 287/03 discontinued the application of the restatement method as from October 1, 2003.

In accordance with the above, for comparative purposes, our financial statements for the fiscal years ended December 31, 2002 were restated in constant pesos as of February 28, 2003, based on changes in the Argentine wholesale price index or the 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, 2001 and 2000 has also been restated in constant pesos as of February 28, 2003.

Proportional consolidation of companies under which we exercise joint control

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 (other than Compañía Inversora en Transmisión Eléctrica Citelec S.A., or Citelec) in our financial statements. See “Item 5. Operating and Financial Review and Prospects—Proportional Consolidation and Presentation of Discussion.” In the consolidation of companies over which we exercise joint control, the amount of the investment in the companies under joint control and the interest in their income (loss) and cash flows are replaced by our proportional interest in the subsidiaries’ assets, liabilities and income (loss) and cash flows. In addition, related party receivables, payables and transactions within the consolidated group and companies under joint control are eliminated on a pro rata basis pursuant to our ownership share in that company.

Presentation of information related to income (loss) per share

Our net income per share under Argentine and U.S. GAAP was calculated as follows:

•

diluted net income per share was calculated by dividing net income by the average number of shares outstanding during each year (assuming all Class A shares are converted into Class B shares);

•

for 2004, 2003 and 2002, net income per share was calculated by dividing net income by the average number of shares outstanding during each year (as of October 2002, all outstanding Class A shares were converted into Class B shares);

•

for 2001 and 2000, basic net income per Class A share was calculated by dividing net income by the sum of (1) the average number of Class A shares outstanding during 2001 and 2000, respectively, and (2) the average number of Class B shares outstanding during 2001 and 2000, respectively, multiplied by 1.5; and

•

for 2001 and 2000, basic net income per Class B share was calculated by multiplying (a) the quotient attained by dividing net income by the sum of (1) the average number of Class A shares outstanding during 2001 and 2000, respectively, and (2) the average number of Class B shares outstanding during 2001 and 2000, respectively, multiplied by 1.5 (b) by 1.5.

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.

U.S. GAAP Reconciliation

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 proportional consolidation of Compañía de Inversiones de Energía S.A., which we refer to as CIESA, another company under joint control, in 2003 and 2004 under Argentine GAAP has been reversed in the reconciliation to U.S. GAAP. This reversal was a result of (1) CIESA having negative shareholders equity for the years-ended 2003 and 2004 for purposes of U.S. GAAP, and (2) our not having assumed commitments to make capital contribution or to provide financial assistance to CIESA, which caused our interests in CIESA to be valued at zero.

Income Statement Data


	Year Ended December 31,
	2004		2003		2002⁽¹⁾		2001⁽¹⁾		2000⁽¹⁾⁽²⁾
	(in millions of pesos, except for per share amounts and share capital or as otherwise indicated)
Income Statement Data
Argentine GAAP:
Net sales	6,974		5,494		5,106		5,170		3,185
Cost of sales	(4,210	)	(3,386	)	(3,284	)	(3,347	)	(2,161	)

Gross profit	2,764		2,108		1,822		1,823		1,024
Administrative and selling expenses	(640	)	(559	)	(609	)	(665	)	(385	)
Exploration expenses	(89	)	(196	)	(58	)	(41	)	(13	)
Other operating (expense) income, net	(304	)	(121	)	(28	)	23		22

Operating income	1,731		1,232		1,127		1,140		648
Equity in earnings of affiliates	76		163		(638	)	119		189
Financial income (expense) and holding gains (losses)	(1,261	)	(417	)	(1,827	)	(573	)	(325	)
Other (expense) income, net	(27	)	(421	)	(187	)	(88	)	132

Income (loss) before income tax and minority interest in subsidiaries	519		557		(1,525	)	598		644
Income tax provision	198		(18	)	(82	)	(385	)	(41	)
Minority interest in subsidiaries	(39	)	(158	)	28		(112	)	(15	)

Net income (loss)	678		381		(1,579	)	101		588
Basic net (loss) income per share:
Class A⁽³⁾	—		—		—		0.035		0.215
Class B	0.319		0.179		(0.744	)	0.053		0.322
Diluted net (loss) income per share	0.319		0.179		(0.744	)	0.047		0.288
Number of shares outstanding (in millions):
Class A⁽³⁾	—		—		—		628		628
Class B	2,132		2,132		2,132		1,504		1,504

U.S. GAAP:
Net sales	6,562		5,078		5,182		4,630		3,343
Operating income	1,408		622		830		853		864
Income (loss) from continuing operations⁽⁴⁾	760		109		(1,868	)	(2,254	)	286
Income (loss) from discontinued operations	—		(39	)	135		12		38
Cumulative effect of changes in accounting principles	—		30		179		—		—
Net income (loss)⁽⁵⁾	760		100		(1,554	)	(2,266	)	324
Basic net (loss) income per share:
Class A⁽³⁾	—		—		—		(0.786	)	0.119
Class B	0.356		0.047		(0.729	)	(1.179	)	0.178
Diluted net (loss) income per share	0.356		0.047		(0.729	)	(1.063	)	0.157
Basic net (loss) income per share:
Class A⁽³⁾
Continuing operations	—		—		—		(0.782	)	0.105
Discontinued operations	—		—		—		(0.004	)	0.014
Class B
Continuing operations	0.356		0.051		(0.876	)	(1.172	)	0.157
Discontinued operations	—		(0.018	)	0.063		(0.006	)	0.021
Cumulative effect of changes in accounting principles	—		0.014		0.084		—		—

⁽¹⁾	Expressed in constant pesos as of February 28, 2003, except share capital.

⁽²⁾	Selected financial data for the fiscal year ended December 31, 2000 has not been restated to reflect changes in Argentine GAAP, which have been effective since January 2003, and accordingly are not comparable to the financial data for the fiscal years ended December 31, 2004, 2003, 2002 and 2001.

⁽³⁾	As of October 2002, there are no Class A shares outstanding.

⁽⁴⁾	After minority interest in subsidiaries and income tax (expense) benefit.

⁽⁵⁾

We have applied SFAS No. 142, “Goodwill and Other Intangible Assets,” effective as of January 1, 2002, and SFAS No. 143, “Accounting for Asset Retirement Obligations,” effective as of January 1, 2003. If the new standards had been effective and applied before January 1, 2001, net income (loss) for the years ended December 31, 2003, 2002 and 2001, would have been P$70 million, P$(1,723) million and P$(2,265) million, respectively.

Balance Sheet Data


	Year Ended December 31,
	2004		2003		2002⁽¹⁾	2001⁽¹⁾	2000⁽¹⁾⁽²⁾
	(in millions of pesos, except for per share amounts and share capital or as otherwise indicated)
Argentine GAAP:
Consolidated Balance Sheet
Assets
Current assets
Cash	128		153		93	98	59
Investments	790		802		664	1,254	543
Trade receivables	1,210		886		784	1,108	908
Other receivables	629		861		734	397	470
Inventories	487		319		356	346	374
Other assets	1		3		178	—	—

Total current assets	3,245		3,024		2,809	3,203	2,354
Non-current assets
Trade receivables	39		36		21	21	7
Other receivables	648		131		220	370	162
Inventories	56		61		39	240	205
Investments	1,323		1,284		1,103	1,341	2,750
Property, plant and equipment	11,280		11,559		10,433	11,633	6,572
Other assets	19		43		24	63	11

Total non-current assets	13,365		13,114		11,840	13,668	9,707

Total assets	16,610		16,138		14,649	16,871	12,061

Liabilities
Current liabilities
Accounts payable	893		860		651	852	547
Short-term debt	1,652		3,204		1,543	3,501	1,625
Payroll and social security taxes	90		93		76	99	75
Taxes payable	163		172		133	145	138
Other current liabilities	686		423		372	563	97

Total current liabilities	3,484		4,752		2,775	5,160	2,482
Non-current liabilities
Accounts payable	26		7		9	4	20
Long-term debt	6,248		5,098		6,130	4,114	3,100
Other liabilities	313		279		641	368	303
Reserves	71		277		86	61	55

Total non-current liabilities	6,658		5,661		6,866	4,547	3,478

Total liabilities	10,142		10,413		9,641	9,707	5,960

Transitory differences
Measurement of derivative financial instruments designated as effective hedge	(2	)	(18	)	—	—	—
Foreign currency translation	(47	)	(56	)	—	—	—
Total transitory differences	(49	)	(74	)	—	—	—
Minority interest in subsidiaries	1,006		966		556	1,133	149
Total Shareholders’ Equity	5,511		4,833		4,452	6,031	5,953
Total liabilities and shareholders’ equity	16,610		16,138		14,649	16,871	12,062

Capital Stock	2,132		2,132		2,132	2,132	2,132

Dividends⁽³⁾
Per Class A share	—		—		—	—	0.0208
Per Class B share	—		—		—	—	0.0317
U.S. GAAP:
Total assets	15,015		14,508		16,108	20,264	15,794
Shareholders’ equity	5,286		4,523		4,499	6,403	8,406

⁽¹⁾	Expressed in constant pesos as of February 28, 2003, except share capital.

⁽²⁾	Selected financial data for the fiscal year ended December 31, 2000 has not been restated to reflect changes in Argentine GAAP, which have been effective since January 2003, and accordingly are not comparable to the financial data for the fiscal years ended December 31, 2004, 2003, 2002 and 2001.

⁽³⁾	Dividends declared in 2000 as expressed in U.S. dollars would equal amounts in historical pesos since the exchange rate between the peso and the US dollar was fixed at a one to one ratio during those years in accordance with the Convertibility Law. See “—Exchange Rates.”

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, pesos were freely convertible into US 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 (1) maintain a reserve in foreign currencies, gold and certain public bonds denominated in foreign currency equal to the amount of outstanding Argentine currency and (2) sell US dollars to any requesting person at a fixed US$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 US$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, and which we refer to as the Public Emergency Law. 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 intervened several times in the exchange market by selling US dollars.

In light of a growing demand for US dollars during the six months ended June 30, 2002 and the shortage of US dollars available to satisfy this demand, the Argentine government adopted a series of measures to mitigate the demand for US dollars and increase its US dollar reserve base. As a result, (1) the export sector has had to exchange on a daily basis its non-Argentine currency into Argentine pesos through the Central Bank, (2) new restrictions on the transfer of funds abroad were implemented, (3) the purchase of foreign exchange was limited and (4) 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 US dollars significantly declined and the Central Bank gradually started to accumulate US dollar reserves. Towards the end of 2002, the Argentine government implemented different measures aimed at stimulating the economy and abrogating certain restrictions in order to gradually normalize the foreign exchange market and the commercial and financial flow of foreign currency.

In 2003, the balance of trade yielded a strong surplus, which, together with the continuing default in partial foreign debt payments by the government declared at the end of 2001, caused an excess supply of foreign currency. As a result, the peso appreciated significantly against the US dollar during 2003. Only numerous currency purchases by the Central Bank, supported by the explicit intention of the Argentine government to maintain a high rate of exchange, prevented greater appreciation of the Argentine peso against the US dollar. In addition, on June 26, 2003, through Decree No. 285, the government fixed the minimum period that currencies may enter the country with speculative purposes at 180 days in order to avoid volatility in the exchange rate.

In 2004, the peso was relatively stable, again supported by the government’s explicit position in favor of a high exchange rate. To such respect, the Central Bank’s intervention in the exchange market steadily increased due to an ongoing excess supply of foreign currency, again determined both by a still wide but contracting trade balance surplus and the continuation of the partial default on the sovereign external debt, and, to a lesser extent, due to foreign capital inflows. The trade balance evidenced a new surplus, although not as sizable as the previous year due to the increase in imports. In an effort to maintain the rate of exchange at about P$3 to US$1 by the end of 2004 purchases by the Central Bank achieved record levels of approximately US$100 million per day, totaling approximately US$1,400 million during December 2004. During the course of 2005, purchases by the Central Bank have remained at similar levels, totaling US$1,500 million during May 2005. In addition, on May 24, 2005, through Resolution No. 292/05, the government extended the minimum period for which currencies may enter the country with speculative purposes from 180 to 365 days, as an additional measure to mitigate the volatility of the exchange rate.

in connection with other credit transactions. Export and import financing operations, as well as, primary public offerings of debt securities listed on self-regulated markets are exempt from the foregoing provisions. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Changes to Exchange Market Regulations.”

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


	Exchange Rate
	High	Low	Average⁽¹⁾	Period End
	(in pesos)
Year Ended December 31,
2000	1.00	1.00	1.00	1.00
2001	1.00	1.00	1.00	1.00
2002	3.90	1.60	3.14	3.38
2003	3.37	2.73	2.95	2.94
2004	2.99	2.94	2.97	2.98
Most Recent Six Months:
December, 2004⁽²⁾	2.99	2.94	2.97	2.98
January, 2005⁽²⁾	2.97	2.92	2.95	2.92
February, 2005⁽²⁾	2.94	2.89	2.92	2.94
March, 2005⁽²⁾	2.96	2.91	2.93	2.92
April, 2005⁽²⁾	2.92	2.88	2.90	2.91
May, 2005⁽²⁾	2.91	2.88	2.89	2.88
June, 2005⁽²⁾⁽³⁾	2.90	2.87	2.88	2.87

⁽¹⁾	Based on monthly average exchange rates.

⁽²⁾	Source: Banco de la Nación Argentina.

⁽³⁾	Through June 21, 2005.

On June 21, 2005, the exchange rate for the purchase of US dollars published by Banco de la Nación Argentina was P$2.87 per US dollar.

RISK FACTORS

Factors Relating to Argentina

Recent political and economic instability in Argentina has and may continue to adversely affect our financial condition and results of operations.

We are an Argentine corporation (sociedad anónima). As of December 31, 2004, approximately 55% of our total assets, 61% of our net sales, 53% of our combined crude oil and gas production and 36% 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 in recent decades, characterized by periods of low or negative growth and high and variable levels of inflation and currency devaluation. Following a seven-year period (1991-1997) of economic growth and monetary stability, starting in the fourth quarter of 1998, the Argentine economy entered into a severe recession, with gross domestic product declining by 3.4% in 1999, 0.8% in 2000 and 4.4% in 2001. Beginning in the second half of 2001, Argentina’s recession significantly worsened. 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 inability to sustain the peso’s parity with the US dollar led to massive withdrawals of deposits from banks and capital outflows and Argentina experienced significant social and political instability. As a response, the government adopted a series of measures, including monetary and exchange control measures.

In January 2002, the government enacted the most important of these measures, the Public Emergency Law, which granted broad economic, financial and monetary powers to the executive branch and ended the US dollar-peso parity established in 1991. In accordance with this law, the federal executive branch implemented a number of far-reaching initiatives, including, but not limited to the following:

•

The pesification of certain assets and liabilities denominated in foreign currency and held in the country;

•

An amendment to the charter of the Central Bank authorizing it to (1) issue money in excess of the foreign currency reserves, (2) grant short-term loans to the federal government and (3) provide financial assistance to financial institutions with liquidity or solvency problems;

•

The pesification and elimination of indexing clauses on utility rates, fixing those rates in pesos at a P$1=US$1 exchange rate; and

•

The implementation of taxes on hydrocarbon exports and certain oil by-products.

As a result of these measures, commercial and financial activities were virtually paralyzed in 2002, further aggravating the economic recession, which included a 10.9% decline in GDP in 2002. In addition, there was a significant devaluation of the peso and increased inflation.

The crisis had significant and adverse consequences on our company, including (1) losses derived from the effects of peso devaluation on our and our affiliate’s net borrowing position, which was primarily denominated in US dollars, (2) the impairment of the book value of certain gas areas and tax credits due to material changes in the prospects of our operations, (3) a decrease in US dollar cash flows due the imposition of export taxes, (4) limits on our ability to renew our short-term lines of credit and the current portion of our medium and long-term financings at maturity and (5) restrictions on our ability to pass through the effects of inflation to the prices of products sold by us in the domestic market. In 2002, we reported a net loss of P$1,579 million compared to income of P$101 million in 2001, which was a significant departure from the historical evolution of our results. In order to secure compliance

with our financial commitments, we implemented a plan, which focused on refinancing a substantial portion of our debt and significantly reduced our investments plan. As a result, capital expenditures in 2002, net of divestments, totaled only P$139 million, a relatively low amount compared to our historical average investment. The Argentine economy and social and political environments have experienced improvements since 2002 and the Argentine government has eased certain regulations and taken measures to effectively stimulate the economy. There are, however, important unresolved issues (such as the treatment and position of holdout bondholders that declined to participate in Argentina’s voluntary debt exchange, the renegotiation of utility contracts, arrangements between the Argentine government and the International Monetary Fund, or IMF) that if not addressed satisfactorily could derail the recovery, which, in turn, could affect our business. See “Item 4. Information About the Company—Business Overview—Our Principal Market.”

Further, Argentine government actions concerning the economy in response to the crisis, 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 adversely affect our business, financial condition, or results of operations.

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 the international credit markets. Non-Argentine financial markets and institutions are reluctant to lend additional capital and grant loans to Argentine entities and companies.

The prospects for all Argentine companies, including us, of accessing financial markets in the near or medium-term continue to be challenging. If we are unable to have access to the international financial markets to refinance our indebtedness at reasonable cost, we may have to reduce our projected capital expenditures, which, in turn, may affect the implementation of our strategic business plan.

Fluctuations in the value of the peso create greater uncertainty as to Argentina’s economic future and may adversely affect our financial condition and result of operations.

The peso has been subject to large devaluations in the past and may be subject to significant fluctuations in the future. Since the end of the US 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. At December 31, 2002, the exchange rate was P$3.38 per US dollar, at December 31, 2003, the exchange rate was P$2.94 per US dollar and, at December 31, 2004, the exchange rate was P$2.98 per US dollar. As of June 21, 2005, the peso/US dollar exchange rate was P$2.87 per US dollar, as published by Banco de la Nación Argentina. See “—Exchange Rates.” Devaluation of the peso could create additional inflationary pressures. On the other hand, appreciation of the peso against the US dollar may lead to a deterioration of the country’s current account and the balance of payments.

The marked peso devaluation during 2002 adversely affected our results and financial position. Substantially all of our financial debt and a significant portion of our affiliates’ debt were denominated in US dollars. Before the enactment of the Public Emergency Law, our cash flow, usually denominated in US dollars or dollar-adjusted, provided a natural hedge against exchange rate risks. The Argentine regulatory framework after the enactment of the Public Emergency Law (which included the 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), however, limited our ability to mitigate the impact of the peso devaluation.

Given the continuing uncertainty regarding Argentina’s medium and long-term economic prospects, it is impossible to predict whether, and to what extent, the value of the peso may further depreciate or appreciate against the US Dollar and how those uncertainties will affect the demand of our products and services. Moreover, we cannot assure you 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 US dollar and, if so, what impact these changes will have on our financial condition and results of operation.

Inflation may escalate and undermine economic growth in Argentina and adversely affect our financial condition and results of operations.

In the past, inflation has materially undermined the Argentine economy and the government’s ability to stimulate economic growth. During 2002, the Argentine consumer price index increased by 41%, and the wholesale price index increased by 118.2%.

In 2003, inflation decelerated sharply, and the consumer and wholesale price indices for 2003 were 3.7% and 2.0%, respectively. The strong recovery of domestic demand caused an acceleration of retail inflation in 2004, with the consumer price index increasing by 6.1%. Wholesale inflation in 2004 also showed clear signs of acceleration driven by the pace of economic growth. The wholesale price index increased by 7.9% during 2004, with a significant rise in prices for manufactured products, energy and mineral products and, to a lesser extent, imported products. Increases in these items are in contrast with the slight rise in the price of the remaining primary products. The variability of inflation in Argentina makes it impossible to estimate with a reasonable degree of certainty how our activities and results of operations will be affected in the future.

In 2003 and 2004 there was a slowdown in the inflation indexes as compared to 2002. We, however, cannot assure you that this situation will remain the same. There is considerable concern that significant inflation will result if the Central Bank prints currency to finance public-sector spending, assist financial institutions in distress or attempt to limit the future appreciation of the peso. 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.

Argentina has imposed exchange controls in recent periods and exchange controls may impair our ability to service our foreign currency-denominated debt obligations and to pay dividends.

After December 2001, Argentine authorities implemented a number of monetary and currency exchange control measures that included restrictions on the withdrawal of funds deposited with banks and on foreign transfers, including restrictions relating to the servicing of foreign debt. The Central Bank has since issued a number of regulations aimed at gradually normalizing the domestic exchange market and, as a result, most restrictions in connection with the repayment of foreign creditors and the payment of dividends to foreign shareholders have been lifted.

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. If the Argentine government decides further to tighten its transfer restrictions, we may be unable to make principal or interest payments when they become due and/or we may be unable to pay dividends.

Limits on exports of hydrocarbons have and may continue to lower our anticipated US dollar-denominated cash receipts.

In recent periods, Argentina has faced difficulties in satisfying its domestic energy needs. As a result, the government has enacted a series of measures limiting the export of hydrocarbons. 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 produced in Argentina that should be sold in the local market.

In March 2004, the Secretary of Energy issued Resolution No. 265/04, which authorizes the imposition of limits on natural gas exports. 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. Temporary limits on certain natural gas exports have been imposed under the program to avoid a crisis in the local supply of natural gas. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Gas” for further details. As of the date of this annual report, these measures have not had a material adverse effect on our results or financial condition, but we cannot assure you that this will be the case in the future.

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 schedule of gradual increases in gas prices that culminates with the expected complete deregulation of wellhead prices for natural gas by January of 2007.

In addition, pursuant to Resolution 1679/04, which was passed in December 2004, producers must obtain the approval of the Argentine government prior to exporting crude oil or diesel oil. In order to obtain this approval, exporters must demonstrate that they have either satisfied local demand requirements or have granted the domestic market the opportunity to acquire oil or diesel oil on terms similar to current domestic market prices and, in the case of diesel oil, they must also demonstrate, if applicable, that commercial terms offered to the domestic market are at least equal to those provided to their own gas station network. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Gas—Modifications to the Regulatory Framework.”

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 US dollar-denominated cash receipts, which might affect our results of operations and financial position.

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

The Argentine government has levied a series of tax increases on crude oil, its by-products and gas. On March 1, 2002, the Argentine government imposed a 20% tax on exports of crude oil and a 5% tax on exports of certain oil by-products, which are due to expire in five years. In May 2004, the tax on exports of crude oil and liquified petroleum gas increased to 25% and 20%, respectively, and a 20% tax was levied on exports of natural gas. Effective August 4, 2004, the Argentine government further increased taxes on exports of crude oil by an additional 3% to 20% more than the current rates, with a cap set at 45%. The determination of the additional rate depends on the price per barrel of crude oil, increasing gradually from 3% when crude oil price is US$32.01 per barrel to 20% when the price is US$45 or more per barrel. See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Economic and Political Developments in Argentina—Price Stabilization and Supply—Hydrocarbons.”

This tax regime has adversely affected the profitability of our upstream operations and has prevented us from fully benefiting from the significant increases in international oil prices.

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. As a consequence, we cannot predict the impact that any changes may have on our results of operations.

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.

Hydrocarbons

In an effort to mitigate the impact of the significant increase of West Texas Intermediate Crude reference price, or WTI, on local prices and ensure price stability for crude oil, gasoline and diesel oil, since January 2003, at the request of the Argentine Federal Executive Branch, hydrocarbon producers and refineries entered into a series of temporary agreements, which contained price limits with respect to crude oil deliveries. The most recent agreement expired in June 2004. In August 2004, in light of the WTI having exceeded US$42, the Argentine government established a cap on the domestic price of crude oil equal to the international market price net of the taxes imposed on exports. As from October 2004, hydrocarbon producers and refiners negotiate crude price based on the export

parity reference price. See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Economic and Political Developments in Argentina—Price Stabilization and Supply—Hydrocarbons.” These measures had an impact and may continue to have an impact on our upstream operations’ profitability and have prevented and may continue to prevent us from capitalizing fully on the benefits derived from the significant increases in international oil prices. We cannot be certain whether further price control measures with respect to hydrocarbons will be taken in the future nor can we be certain of the impact such measures may have on our results.

Gas and electricity

Pursuant to the Public Emergency Law, we were precluded from increasing the price of the gas and electricity sold in the domestic 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, we postponed infrastructure, development and exploration investments, especially at the Neuquén basin in Argentina.

In April 2004, we along with the remaining gas producers entered into an agreement with the Argentine government, which provides for a schedule of gradual increases in gas prices in the domestic market that culminates in complete deregulation of the wellhead price of natural gas by January 2007.

In December 2004, the Secretary of Energy committed to approve successive seasonal electricity price increases to reach values covering at least total monomic costs by November 2006. In addition, as soon as the market returns to normal and once new generation capacity derived from the government maintained fund called FONINVEMEM becomes available to dispatch energy to the market, the Secretary of Energy has committed (1) to pay for energy at the marginal price obtained in the spot market and (2) to pay for power at the US dollar values that were in effect prior to the enactment of the Public Emergency Law. See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Economic and Political Developments in Argentina—Price Stabilization and Supply.”

Through these combined measures, the Argentine government is expected to gradually restore the economic and financial balance in the natural gas and electricity sectors. Our results and capital expenditure plans, however, may be adversely affected if (1) the agreed schedule of increases in gas prices or commitments with respect to electricity prices fail to be implemented by the Argentine government, (2) the government continues issuing additional decrees or exerting political pressure to curb price increases or (3) the government applies its regulatory emergency authority or adopts other laws to control prices or supply.

Downstream margins

Downstream margins have significantly declined since the enactment of the Public Emergency Law. As part of the effort to avoid inflationary escalation, the Argentine government exerted pressure to limit the increase in prices of gasoline and diesel oil at the retail level that would have resulted from (1) higher costs due to increases in WTI prices, (2) the peso devaluation and (3) domestic inflation. These measures affected the sector’s profitability. Since the enactment of the Public Emergency Law, crude oil cost for Argentine operations have increased 67% while gasoline and diesel oil average sales prices have increased only by 21% and 46%, respectively.

Notwithstanding the absence of a formal price control policy, many initiatives taken by other downstream companies in an attempt to recover the profitability of the sector, have been thwarted by governmental pressure, including a communication campaign aimed at generating social opposition to these initiatives.

The downstream business in Argentina has been and may continue to be subject to extensive governmental intervention that affect prices and profitability, and these interventions may have an adverse affect on the results of our operations.

The pesification of utility rates has affected and may continue to affect utility companies’ financial position, results of operations and their ability to generate cash.

The new macroeconomic scenario after enactment of the Public Emergency Law impacted the economic and financial balance of utility companies in Argentina. The combined effect of (1) the devaluation of the peso, (2) the pesification of rates on a one to one basis and (3) financial debts primarily denominated in foreign currency, adversely affected the utility companies’ financial position, results of operations and ability to satisfy financial obligations.

In light of the adverse conditions faced by utility companies, during 2002, CIESA, Transportadora de Gas del Sur S.A., or TGS, and Compañía de Transporte de Energía Eléctrica en Alta Tensión Transener S.A., or Transener, defaulted on their debt. TGS has recently concluded a debt restructuring process with creditors. Transener proposed an exchange offer to its creditors, which in April 2005 was accepted by 98.8% of them. Pursuant to a restructuring agreement entered into on May 19, 2005, Transener has 45 business days to comply with the terms of the exchange offer, otherwise the restructuring agreement may be terminated at their creditors’ option. As a result of Transener’s restructuring, our indirect interest in Transener would be reduced from 32.5% to 26.326%. CIESA is currently negotiating with creditors to refinance its defaulted obligations. See “Item 4. Information About the Company–Electricity–Electricity Transmission: Transener, Yacylec and Enecor—Transener” and “Item 4. Information About the Company–Hydrocarbon Marketing and Transportation—Gas Transportation-TGS—Our interests in TGS and Corporate Developments.” Until a successful restructuring of this debt, there will remain substantial doubt about the ability of CIESA, Citelec and Transener to continue operating as a going concern.

The problems faced by our affiliated utilities have adversely impacted our net income and our ability to receive dividends from these companies. We did not receive dividends from them in 2002, 2003 or 2004. In addition, we could lose some or all of our ownership in CIESA, Citelec and Transener if any necessary debt restructuring is unsuccessful and creditors proceed against the assets of the defaulting affiliates. The outcome of any such proceedings is uncertain due to the procedural difficulties of Argentine bankruptcy courts and laws relating to the ownership of Argentine utilities companies.

The Argentine government and our affiliated utility companies are in the process of renegotiating utility contracts, and the recovery of these affiliates depends on the successful completion of these negotiations.

The Public Emergency Law granted the Argentine government broad authority to renegotiate utility contracts, which authority has been extended to December 2005. On October 1, 2003, the Argentine Congress passed a bill allowing the executive branch of the government to set public utility rates until the completion of the renegotiation process. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Electricity—UNIREN.” UNIREN (the agency created to, among other things, provide assistance in the utility renegotiation process, execute comprehensive or partial agreements with utility companies and submit regulatory projects related to transitory rate adjustments) is currently in the process of renegotiating contracts with our affiliates Edesur S.A., or Edesur, TGS, Transener and Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires S.A., or Transba. These discussions are in different stages, and some of our affiliates have rejected UNIREN’s latest proposals. See “Item 4. Hydrocarbon Marketing and Transportation—Gas Transportation - TGS—Regulated Energy Segment” and “Item 4. Information About and Company—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener.” We cannot guarantee that these discussions will ultimately result in a level of tariff increases sufficient to restore the economic and financial position of utility companies.

Factors Relating to Venezuela

Adverse economic, political and social conditions in Venezuela have and may in the future adversely affect our financial position and results of operations.

The government through Petróleos de Venezuela, S.A., or PDVSA, strictly controls oil production in Venezuela. Accordingly, our operations are affected by the economic and political conditions of Venezuela. Additionally, as Venezuela is a member of the Organization of Petroleum Exporting Countries, or OPEC, we are subject to the production cut decisions that OPEC may adopt, as was the case in 2002.

Since the end of 2002 and throughout 2003, Venezuela faced one of its worst political and economic crisis in the last 40 years. On December 2, 2002, a nationwide strike was organized, which included PDVSA and involved the country’s main production areas. This situation affected our operations of the three fields located in the east of the country (Oritupano-Leona, Mata and Acema), significantly reducing their production. Throughout the first quarter of 2003, oil production average volume dropped by 40.2% to approximately 30,400 barrels per day compared to the same quarter of 2002. After the conclusion of the nationwide strike, the situation gradually reversed. The year 2004 was marked by economic recovery, triggered by high prices of hydrocarbons in the international market and recovery of the national oil production. See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Political and Economic Situation in Venezuela.”

Given the importance of Venezuela to our business, we are unable to assure you that political, economic and social events in Venezuela will not adversely affect our results of operations and financial position.

Changes in the regulatory and contractual framework applicable to our operating agreements have and may in the future adversely affect our financial position and results of operations.

The Venezuelan government increased royalties in 2001 from 1-16.66% to 20-30% thereby affecting our results of operations. This increase in royalties resulted in lower revenues of P$84 million, P$57 million and P$60 million for 2004, 2003 and 2002, respectively.

In April 2005, the Venezuelan Energy and Oil Ministry instructed PDVSA to review the thirty-two operating agreements signed by PDVSA with oil companies from 1992 through 1997, including agreements with our affiliates in connection with the areas of Oritupano Leona, La Concepción, Acema and Mata. The Venezuelan government has instructed PDVSA to take measures within a six-month term to convert all currently effective operating agreements into mixed-ownership contracts in order to grant the Venezuelan government, through PDVSA, more than 50% ownership of each field. The government has further instructed PDVSA to limit the total accumulated payments to contractors during a calendar year to 66.67% of the value of oil and gas produced under the related agreement. On April 15, 2005, PDVSA notified our subsidiary Petrobras Energía Venezuela, S.A. about this and advised that the Venezuelan Energy and Oil Ministry will, as soon as possible, contact our subsidiary to fix a date to begin the related discussions. Without opining on the proposed changes or the legitimacy of the operating agreements, we have expressed our willingness to engage in discussions with PDVSA and the Venezuelan government. See “Item 4. Information About the Company—Oil and Gas Exploration and Production—Production—Production Outside of Argentina—Venezuela.”

On June 23, 2005, we received notice from PDVSA that it would start paying in local currency the amounts due to us under the operating agreements that correspond to national services and materials, instead of US dollars as provided in the relevant agreements. Under the current agreements, all payments from PDVSA are due in dollars outside Venezuela. During an interim period and until PDVSA performs an audit that finally determines the portion of services under the operating agreements that correspond to national services, PDVSA would start paying 50% of the amounts due to us under the operating agreements in local currency, and the remaining 50% would continue to be payable in dollars.

Given the early stage and uncertainty of the overall process, we are unable to predict its outcome or the impact that it may have on our operations, financial results, liquidity or investment plans. Accordingly, we cannot assure you that the changes resulting from this process will not adversely affect our financial position or results of operations.

under-reported their taxable income in Venezuela. As of the date of this annual report, none of the oil companies operating in Venezuela, including us, have received a claim from the National Integrated Service of Tax Administración ( Servicio Nacional Integrado de Administración Tributaria), or SENIAT, in connection with this alleged investigation.

Factors Relating to the Company

Decline in oil prices affect the profitability of our operations and capital expenditures.

International oil prices, which are out of our control, can vary as a result of changes in supply and demand and may be influenced by factors such as economic conditions, weather conditions or actions taken by major oil exporting countries. Political developments, including war, embargos and political strife in oil producing regions can also affect oil supply, and thus affect international oil prices. Changes in oil prices typically result in changes in the price of oil products. International oil prices have fluctuated widely over the last ten years. During 2004 and 2003, the average WTI was US$41.5 and US$31 per barrel, respectively, compared to an average of US$22.56 per barrel for the period 1994-2003.

Because a substantial amount of our revenues are derived from sales of oil and oil-related products, any declines in the price of oil may affect the profitability of our operations, our ability to generate cash, the value of our assets and the amount and timing of our projected capital expenditures. If oil prices decline significantly, we may have to dramatically cut capital expenditures, and this could adversely affect our ability to replace reserves and our production forecasts in the medium term.

Even during periods of high crude oil prices it may not be possible to pass through higher prices to end consumers, due to, among other factors, governmental regulations or changes in consumer demand. This may have an impact on our results of operations, particularly with respect to our downstream operations.

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. Reserve estimates are based, in part, on subjective judgments and, therefore, are not 100% accurate and may be subject to revision. See “Item 4. Information About the Company—Oil and Gas Exploration and Production—Reserves” and “Item 5. Operating and Financial Review and Prospects—Critical Accounting Policies—Estimation of Oil and Gas Reserves.” Crude oil and natural gas reserves are reviewed annually to take into consideration many factors, including:

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new production or drilling activities;

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field reviews;

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the addition of new reserves from discoveries, and extensions of existing fields;

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changes in the international prices of oil and gas;

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the application of improved recovery techniques; and

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new economic conditions.

Proved reserve estimates could be materially different from the quantities of crude oil and natural gas that are ultimately recovered, and downward revisions of our estimates in the future could impact our results of operations and business plan, including our levels of capital expenditures.

We may not be able to replace our oil and gas reserves, which may have an adverse impact on our future results of operations and financial position.

The rate of production from oil and gas properties generally declines, and the cost of production generally increases, as reserves are depleted. Our future oil and gas production is significantly dependent on the successful implementation of our development projects. Our development projects, in turn, are dependent on and affected by the interpretation of geological and engineering data, scheduling commitments, cost estimates, as well as, other factors. In addition to current development projects, our future oil and gas production depends on our ability to access new reserves, including through exploration and acquisitions funded by increases in capital expenditures. Failures in exploration and/or our inability to acquire suitable potential reserves could adversely impact our oil and gas production and reserve replacement, which, in turn, could have an adverse impact on our future results of operations and financial position. We have limited capital resources to implement an ambitious capital expenditure program. Moreover, we face strong competition in bidding for new production blocks, especially those blocks with the most attractive crude oil and natural gas reserves. This competition may result in our future failure to obtain desirable production blocks, undermining our ability to replace reserves.

Without successful development and exploration activities or reserve acquisitions, our proved reserves will decline as our oil and gas production will be forced to rely on our existing proved developed reserves. This was the case in 2002-2004 when our liquid hydrocarbon and natural gas proved reserves decreased by 10%. This was partly the result of the reduction in our capital expenditures during 2002 in response to the Argentine economic crisis, and the limited possibilities to negotiate gas price increases as a result of the Public Emergency Law. The reduction in our capital expenditures particularly affected our Argentine assets, which are mature assets, with low exploratory prospects, and are under production through secondary recovery methods. Therefore, we have experienced considerable natural declines with respect to our Argentine reserves. In Argentina, alone, our liquid hydrocarbon and natural gas proved reserves decreased approximately 30% during 2004-2002. During that period, Argentina’s combined oil and gas production volume decreased by 13%. See “Item 4. Information About the Company—Oil and Gas Exploration and Production—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. If we are not able to successfully find, develop or acquire additional reserves or drill cost-efficient productive wells, our reserves may continue to decline and, therefore, may adversely affect our future results of operations and financial position.

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

Our operations are concentrated in Latin America, a region that has experienced significant economic, social, political and regulatory volatility in recent periods. For example, recent political unrest in Bolivia has targeted foreign companies’ participation in Bolivia’s natural gas industry, which in May 2005 resulted in a significant increase in royalties and taxes and calls by some groups for nationalization of the energy industry. The Bolivian political, economic and social situation, generally, and the country’s energy policy, in particular, remain extremely volatile and unpredictable. As we expand our operations in other countries throughout Latin America, we may be increasingly affected from time to time by economic, political and regulatory developments in such countries, such as forced divesture of assets, restrictions on production, expropriation of property and cancellation or modification of contract rights, price controls, tax increases, 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.

The likelihood of these occurrences and their overall effect may vary greatly from country to country and are not predictable and, if they occur, they may have an adverse impact on our results of operations and financial position.

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 are subject to certain environmental risks that are inherent in the oil and gas industry and which may arise unexpectedly and result in material adverse effects on our results of operations

and financial position. We recorded a P$58 million loss in 2003 and a P$51 million loss in 2004 for environmental remediation efforts. We may have to incur additional environmental related costs in the future, which may negatively impact our results of operations. See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Environmental Matters.”

In addition, we are subject to extensive environmental regulation both in Argentina and in the other countries in which we operate. 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.

Item 4.

INFORMATION ABOUT THE COMPANY

OUR HISTORY AND DEVELOPMENT

Our History

We are a holding company that operates exclusively through our subsidiary Petrobras Energía 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, Mexico, 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, 22^nd Floor, C1084ABA Buenos Aires, Argentina, Telephone: 54 11 4344-6000. Our process agent in the U.S. is CT Corporation System, located at 111 Eighth Avenue, New York, New York 10011.

Our original name was PC Holdings S.A. We were formed in 1998 for the sole purpose of owning shares of Petrobras Energía, and both we and Petrobras Energía were controlled at the time by members of the Perez Companc family. As of December 31, 1999, we owned 28.92% 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. 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 Participaciones, S.L.U., or PPSL, a wholly owned subsidiary of Petrobras, acquired from the Perez Companc family and Fundación Perez Companc their entire ownership interest, or 58.6%, in our 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 and is a mixed-capital company with a majority of its voting capital owned by the Brazilian federal government.

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.

Our interest in Petrobras Energía is expected to decrease to 75.82% from 98.21% as a result of the merger of certain companies controlled by Petrobras into Petrobras Energía. Pursuant to the merger, Petrobras indirectly will receive 230,194,137 newly issued Class B shares of Petrobras Energía, representing 22.8% of its capital stock. See “—Petrobras Energía Merger.”

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 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 was awarded an exploration and production service contract for the Oritupano Leona area in Venezuela. Since this milestone, Petrobras Energía has expanded its operations in Venezuela, as well as in 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. 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.

Petrobras Energía Merger

On January 21, 2005, the special shareholders’ meetings of Petrobras Energía, EG3 S.A., or EG3, Petrobras Argentina S.A., or PAR, and Petrolera Santa Fe SRL, or PSF, approved the merger of EG3, PAR and PSF into Petrobras Energía. Prior to the merger, Petrobras, through its subsidiary PPSL, held a 99.6% interest in EG3 and a 100% interest in each of PAR and PSF. Pursuant to the merger, PPSL is expected to receive 230,194,137 newly issued Class B shares of Petrobras Energía, representing 22.8% of Petrobras Energia’s capital stock. As a result, our interest in Petrobras Energía is expected to decline to 75.8%. On March 3, 2005, the final merger agreement was signed providing that, once implemented, following receipt of necessary governmental approvals and registration with the public registry, the merger would be given retroactive effect to January 1, 2005. On June 28, 2005, the CNV approved the merger. The merger is in the process of being registered with the Argentine Public Registry of Commerce. After the merger, Petrobras Energía will be the surviving entity.

EG3 is mainly engaged in the refining and processing of oil and oil by-products and the distribution and marketing of liquid and gaseous fuels and lubricants through gas stations and fuel retail outlets. EG3 has a refinery located at Bahía Blanca, Buenos Aires, a strategic location for the delivery of crude oil coming from the Neuquén Basin or by sea from the south of Argentina or international markets. With a crude processing capacity of approximately 31,000 barrels per day, EG3 manufactures a wide variety of products: high-grade gasoline, regular gasoline, super 97 SP gasoline, raw materials for the production of solvents and petrochemical products—including kerosene, diesel oil, fuel oil, asphalts base, propane, propylene and butanes. EG3 has a wide network of gas stations (approximately 621) throughout the country that operate under the Petrobras and EG3 brands.

PAR is mainly engaged in oil and gas production. PAR owns a concession for a production area at the Noroeste basin, with a production volume of approximately 7,000 barrels of oil equivalent per day and proved reserves of 17 million barrels of oil equivalent as of December 31, 2004.

PSF is engaged in oil and gas production. PSF has concessions for five oil fields, which were located in the Neuquén, San Jorge and Cuyana basins. These fields had an aggregate production volume of approximately 12,000 barrels of oil equivalent per day and proved reserves of 78 million barrels of oil equivalent as of December 31, 2004.

Capital Expenditures and Divestitures

For a description of our capital expenditures see “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources.” For a description of our most significant divestitures see “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Divestment of Assets” and “—Divestments of Non-Core Assets.”

BUSINESS OVERVIEW

Our Strategy

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

The main points of this strategy are:

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Increasing oil and gas reserves and production to secure sustainable growth;

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Growing downstream in Argentina, while balancing the crude production – refining – logistics – commercialization chain and differentiating ourselves through the quality of our products and services;

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Developing businesses in the gas and energy areas that will allow for the best overall use of our gas reserves;

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Consolidating our leading position in our petrochemical markets, by maximizing the use of our raw materials; and

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Using capital in a disciplined manner, with a view to optimizing our debt to capital ratio and maintaining our financial solvency.

In order to adhere to this strategy, we consider the following to be essential:

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A commitment to protect the quality of our goods and services, the environment and the health and safety of our employees, contractors and neighboring communities;

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Adoption of, and compliance with, corporate governance practices in line with international best practices;

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Maintenance of a style of management that favors communication and teamwork, fostered by the value of the people that work in our organization; and

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Developing new business opportunities, by maximizing potential synergies and capitalizing on complementary business opportunities with Petrobras.

We currently manage our activities, with the support of corporate staff, in five business segments: (1) Oil and Gas Exploration and Production, (2) Hydrocarbon Marketing and Transportation, (3) Refining, (4) Petrochemicals and (5) Electricity.

Our Principal Market

We are an Argentine corporation and, as of December 31, 2004, 55% of our total assets, 61% of our net sales, 53% of our combined crude oil and gas production and 36% of our proved oil and gas reserves are located in Argentina. Fluctuations in the Argentine economy and 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 environment in and affecting Argentina. See “Item 3. Key Information—Risk Factors—Factors Related to Argentina.”

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 US 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 US 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 and 4.4% in 2001.

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 US 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 which 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. 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 US 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:

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Pesification of certain assets and liabilities denominated in foreign currency and held in the country;

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Rescheduling of bank deposits, with the subsequent ability for owners of such deposits to receive certain US dollar-denominated government bonds maturing in ten years or peso-denominated government bonds maturing in three or five years or bills with specific terms in lieu of payment of such deposits;

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Amendment of the charter of the Central Bank authorizing it to issue money in excess of the foreign currency reserves, to grant short-term loans to the federal government and to provide financial assistance to financial institutions with liquidity or solvency problems;

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Issuance by the federal government of bonds to compensate banks for losses resulting from the different pesification rates applicable to deposits and US dollar obligations assumed in Argentina;

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Pesification of all private agreements entered into as of January 6, 2002 at the P$1=US$1 exchange rate and subsequent adjustment thereof by the Benchmark Stabilization Coefficient, published by the Central Bank;

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Pesification and elimination of indexing clauses on utility rates, fixing those rates in pesos at the P$1=US$1 exchange rate; and

•

Implementation of taxes on hydrocarbon exports and certain oil by-products, among others.

In 2002, our financial results were negatively impacted by drastic political and economic changes that resulted from the severe crisis that broke out in Argentina late in 2001. Due to high level of institutional instability, which included social conflicts, the default on most of Argentina sovereign debt, the abandonment of convertibility, the freeze on and rescheduling of banking deposits, the pesification and the elimination of indexation on utility rates and, in general, active intervention by the government in the development of the economy, commercial and financial activities were virtually paralyzed in 2002, further aggravating the economic recession, which included a 10.9% decline in GDP. Within this context, the peso devalued 238%, the wholesale price index rose 118.2% and the consumer price index increased 41%. Towards the end of 2002, the Argentine government implemented different measures aimed at stimulating the economy and abrogating certain restrictions to gradually normalize the foreign exchange market and the commercial and financial flow of foreign currency.

On May 25, 2003, Mr. Kirchner took office as Argentina’s president. Argentina had numerous rounds of negotiations with the IMF in 2002-2003 regarding Argentina’s economic program and the medium-term refinancing of its debt with the IMF. In September 2003, Argentina and the IMF entered into a three-year standby credit agreement. This new agreement guaranteed the refinancing of all principal maturities of credit facilities granted by multilateral agencies. The agreement specified a series of quantitative and qualitative conditions to be met by the Argentine government during the 2003-2004 period.

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. The domestic demand for energy and gas grew in line with GDP growth. Oil production, however, declined 2%, despite crude oil processing having increased by 4%. 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 US 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.

During 2004, the Argentine economy continued to exhibit signs of stability. Real GDP growth was 9.0% for the year. Both inflation and the peso nominal exchange rate were stable during 2004, with an increase of 6.1% in the consumer price index and 7.9% in the wholesale price index, while the peso devaluated 1.3%. Furthermore, the employment situation improved, unemployment reaching a 12.1% rate during the fourth quarter of 2004, which was a decrease of 26% from the levels it had reached during the 2002-2003 period. Notwithstanding the improvement in the economy, oil production in Argentina continued to fall in 2004 (6.1%), while crude oil processing increased 1.5% during the year, with a decline in crude oil exports. Gas production increased 3% during the year. The domestic demand for gas increased approximately 8%, mainly driven by compressed natural gas and power plants, while exports reflected similar growth and gas imports from Bolivia resumed at approximately four million cubic meters per day. Energy generation increased 8.5%, which was in line with GDP growth.

Negotiations with the IMF stalled in 2004 and the IMF and Argentina ultimately deferred negotiation of certain undetermined aspects of the IMF program until after Argentina completed the restructuring of its defaulted debt with private creditors. During that period, Argentina met its payment obligations to the IMF.

In March 2005, the government’s debt exchange offer received a significant level of acceptance (approximately 76%). The agreement with the IMF, however, is still on hold. In May 2005, the IMF agreed to roll over US$2.5 billion in loans owed by Argentina over the next 12 months.

In 2005, it is expected that the Argentine economy will continue to grow as long as it manages to overcome the remaining effects of the default on its sovereign debt and investments are made to expand production capacity.

Nonetheless, the long-term evolution of the Argentine economy remains highly uncertain. The country still faces significant challenges, including the solution of the problem with holdout creditors, who did not accept the exchange offer with respect to Argentina’s public debt, and the renegotiation of utility contracts.

OIL AND GAS EXPLORATION AND PRODUCTION

Overview

The core of our operations is the oil and gas exploration and production business segment. The business segment’s strategy is to increase reserves and oil and gas production in Argentina and other parts of Latin America, in order to secure our sustainable growth. In line with this strategy, our business goals are:

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Increasing oil and gas production by capitalizing on our experience and presence in nearly all Latin American oil producing countries;

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Optimizing our investment portfolio by balancing high risk exploration projects with development projects; and

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Being recognized as an efficient operator and excellent manager, with competitive lifting costs and a good environmental record.

We currently conduct oil and gas exploration and production operations in Argentina, Venezuela, Peru, Ecuador and Bolivia. In addition, we act as contractor and provide technical and operating support in Mexico.

As of December 31, 2004, our combined crude oil and natural gas proved reserves, including our shares of the reserves of our unconsolidated investees, were estimated at 732 million barrels of oil equivalent, approximately 51.2% of which were proved developed reserves and approximately 48.8% of which were proved undeveloped reserves. Crude oil accounted for approximately 75.5% of our combined proved reserves, while natural gas accounted for about 24.5%. As of December 31, 2004, 36% of our total combined proved reserves were located in Argentina and 64% 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 2003 and 2004, total investments outside of Argentina accounted for approximately 60% of our total investments in the oil and gas exploration and production business segment.

For the year ended December 31, 2004, our combined crude oil and natural gas production, including our share of the production of our unconsolidated investees, averaged 163,600 barrels of oil equivalent per day, an increase of 3.1% compared to 158,600 barrels of oil equivalent per day in 2003. Crude oil production volume increased 4.5% to 119,800 barrels per day and gas volumes decreased 0.4% to 262.9 million cubic feet. Approximately 55.9% of our oil production and 24.6% of our gas production were outside of Argentina. Venezuelan production has become a main component of our production outside of Argentina, accounting for 31.5% of our total average production in barrels of oil equivalent.

As of December 2004, we had total proved reserves equal to 12.2 years of production at 2004 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 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 Thermal Power Plant, which we refer to as Genelba, allows us to use approximately 2.9 million cubic meters of natural gas per day of our own reserves. In addition, we supply gas to our petrochemical operations in Argentina.

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. The 2002 fiscal year, however, 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 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$499 million (or P$596 million on a cash flow basis), a relatively low amount compared to our historical average investment. See “Item 5. Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Capital Investments.” 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 operating areas and related production.

In 2003 and 2004, buoyed by the recovery of our operating cash flow and liquidity, capital expenditures amounted to P$776 million and P$954 million, respectively. The levels of expenditures in the last two years, we believe, are indicative of the new dynamics of our investment plan, and the expected recovery following the significant decline resulting from the Argentine crisis. In the years ahead, we plan to make significant investments in oil and gas exploration and production to achieve our production growth and reserve replacement targets, especially in Argentina, Venezuela and Ecuador. In accordance with this strategy and in order to grow from a financially solvent platform, investments will principally be made in our existing operations and in exploration, including new off-shore opportunities.

Our Oil and Gas Exploration and Production Interests

As is commonplace in the oil and gas exploration and production business, we generally participate in exploration and production activities in conjunction with joint venture partners. 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.

As of December 31, 2004, we had interests in 23 oil fields, 17 of which are oil and gas producing fields and six of which are located in exploration areas, three in Argentina and three outside of Argentina. We are directly or indirectly the contractual operator of 22 of the 23 fields in which we have an interest.

As of December 31, 2004, our total gross and net productive wells were as follows:


	Oil	Gas	Total
Gross productive wells⁽¹⁾	4,548	254	4,802
Net productive wells⁽²⁾	3,726	221	3,947

(1)	Refers to number of wells completed.

(2)	Refers to fractional ownership working interest in gross wells.

As of December 31, 2004, our total producing and exploration acreage, both gross and net, is shown in the following table:


	Average
	Producing⁽¹⁾		Exploration⁽²⁾
	Gross⁽³⁾	Net⁽⁴⁾	Gross⁽³⁾	Net⁽⁴⁾
	(in thousands of acres)
Argentina	4,027	3,211	882	876
Peru	116	116	—	—
Venezuela	585	379	363	181
Ecuador	775	691	—	—
Bolivia	56	56	—	—

Total	5,559	4,453	1,245	1,057

(1)	Includes all areas in which we produce commercial quantities of oil and gas or areas in the stage of development.

(2)	Includes all areas in which we are allowed to perform exploration activities but where commercial quantities of oil and gas are not produced.

(3)	Represents number of wells completed.

(4)	Represents our fractional ownership working interest in the gross acreage.

The following table sets forth the number of total wells we drilled in Argentina and outside 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 well if it is determined to be incapable of commercial production. “Gross wells drilled” in the table 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.


	Year ended December 31,
	2004		2003		2002
	Argentina	Outside Argentina	Argentina	Outside Argentina	Argentina	Outside Argentina
Gross wells drilled:
Production:
Productive wells:
Oil	194	45	169	20	109	2
Gas	4	—	8	1	7	—
Dry wells	2	1	8	—	4	—

Total	200	46	185	21	120	2

Exploration:
Discovery wells:
Oil	2	1	—	2	—	—
Gas	—	—	—	—	—	—
Dry wells	—	1	—	1	1	2

Total	2	2	—	3	1	2

Net wells drilled:
Production:
Discovery wells:
Oil	109.0	35.2	105.2	17.7	78.7	1.1
Gas	2.8	—	6.6	0.6	5.8	—
Dry wells	1.7	0.9	6.2	—	2.8	—

Total	113.5	36.1	118.0	18.3	87.3	1.1

Exploration:
Discovery wells:
Oil	1	2	—	1.4	—	—
Gas	—	—	—	—	—	—
Dry wells	—	0.7	—	1.0	1	1.1

Total	1	2.7	—	2.4	1	1.1

Production

Argentine Production

Argentina is currently the fourth largest oil producer in Latin America after Mexico, Venezuela and Brazil. In 2004, Argentina’s daily production was approximately 695,000 barrels, accounting for approximately 7.5% of the region’s total production. Production from Mexico, Venezuela and Brazil accounts for about 37.5%, 24.3% and 16.4%, respectively, of total oil production in Latin America.

Oil production activities in Argentina are mainly developed in mature fields undergoing secondary recovery operations, which are capital-intensive projects. As a result of regulatory changes and the resulting influx of private capital in exploration and production, oil reserves in Argentina significantly grew in the 1990s, reaching 3.071 million barrels in 1999. Since that time period, a sustainable drop in reserves has been recorded, with a 13% reduction in 2003 compared to 1999. This drop was mainly due to price controls set by the government on oil and gas prices, including implementation of an export tax regime and a freeze on the price of gas, as well as, the lack of specific economic and tax incentives—all of which have strongly discouraged investments in research for new reserves. In 2004, for the seventh year in a row, oil production in Argentina decreased, to 695,000 barrels per day, which represents a 6.1% reduction compared to 2003.

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: (1) an increase in gas availability, (2) increased and improved transportation and distribution, (3) environmental efficiency and (4) low prices as compared to international levels.

As a result of natural gas’ 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 residential and industrial users as well as electricity generation companies. Compressed natural gas also became an important fuel source for vehicles during the last ten years because compressed natural gas is the least expensive and least polluting motor fuel. Argentina currently has the largest compressed natural gas-fueled vehicle fleet in the world.

In response to the increased demand for natural gas, significant investments in the natural gas chain were made following the privatization of the services of natural gas transportation and distribution which occurred in 1992 until 2001.

The Public Emergency Law, however, significantly changed the applicable regulatory framework. Measures such as the freezing of natural gas prices as well as the pesification and freezing of transportation and distribution tariffs have adversely affected the economic attractiveness of the gas business and have led to a significant reduction in exploration activities. This reduction juxtaposed with an increase in demand has significantly reduced Argentina’s horizon of reserves, which decreased from approximately 25 years in the beginning of the 1990s to little more than a 12-year reserve by the end of 2004.

In 2004, natural gas volumes for the year reached 142.9 million cubic meters per day, a 3% increase compared to the same period of 2003 (139.5 million cubic meters per day). Demand for natural gas, however, outpaced this increase and grew by 8% during the same period, mainly boosted by the sale of compressed natural gas and consumption by power plants. In light of the foregoing imbalance between production and demand, the Argentine government intensified its intervention in the energy market through a series of measures, including: (1) increasing natural gas prices at well-heads; (2) increasing imports of natural gas from Bolivia; (3) reducing natural gas exports to Chile to between 2 and 5 million cubic meters a day; (4) creating the “Program for the Rationalization of Energy,” which attempts to stimulate savings of gas and electricity from domestic consumption in order to generate surpluses that can then be applied to industrial activities; (5) outlining the framework for the creation of trust funds in order to finance the expansion of gas pipelines; (6) creating the Gas Electronic Market, with the aim of improving the transparency and efficiency of daily operations through the free interaction of supply and demand of natural gas; and (7) creating the company Energía Argentina S.A., or ENARSA, a new state-owned energy company that attempts to, as one of its major goals, find new oil and gas reserves in unexplored areas in association with private companies.

In the fiscal year ended December 31, 2004, our oil and gas production accounted for 8% and 4% of total oil and gas production in Argentina, respectively. As of December 31, 2004, we had interests in ten Argentine oil and gas production fields, with production rights in approximately 3,211,000 net acres.

Our production is concentrated in two basins, the Neuquén and 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 basin in Argentina in terms of oil and gas production. We own approximately 578,000 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 approximately 2,633,000 net acres under production concessions, with Santa Cruz I and Santa Cruz II being our most important fields in that basin.

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 four years. The concessions for all areas in Argentina typically provide for the free availability of oil. All permanent fixture, materials and equipment are under the control of the concessionaire, although they revert to the Argentine government at the end of the concession. Royalties based on production are paid to the respective Argentine provinces where the production of crude oil occurs and the volumes of natural gas are located. Throughout the country, these royalties are fixed at 12% of the wellhead price for oil and gas.

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, 2004, 63.9% of our combined proved reserves were located outside of Argentina. In addition, approximately 56% of our oil production and 25% of our gas production came from outside Argentina in 2004. We have interest in eight oil and gas production fields outside of Argentina: Oritupano-Leona, Acema, La Concepción and Mata in Venezuela, Lote X in Peru, Block 18 and Block 31 in Ecuador and Colpa Caranda in Bolivia.

•

Venezuela

Venezuela is an important country in the international oil market. With proven reserves of approximately 78 billion barrels of crude oil in 2004, Venezuela possesses the largest proven reserves in the Western Hemisphere and has 6.8% 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 2004, 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 remainder was exported.

Production from Venezuela is an important part of our total production, accounting for 31.5% of the total average production in barrels of oil equivalent in 2004. In Venezuela, our rights are held under operating service contracts.

In 1994, during what is referred to as the second round bids, 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. (We refer to the contracts awarded pursuant to the second round bids as the second round operating agreements.) Oritupano-Leona is an approximately 215,000 net acre block located in the Oriental basin that includes 272 producing wells.

The Oritupano Leona joint venture’s sole customer for the sale of oil production 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 (1) a variable fee based on production volumes plus (2) an additional fee for reimbursement of capital expenditures. The additional payments in item (2) that commence during the first ten-year period of the agreement are paid in quarterly installments for a term of ten years, and the additional payments that commence during the second ten-year period of the agreement are paid in quarterly installments for a term equivalent to the remainder of the twenty-year period. The contract has a cap on the amount, which we can collect, which is reset quarterly based on the market price of oil. As of December 2004, this cap was approximately US$37.9 per barrel. The contract also establishes an incentive, which is not subject to the cap, for any production over 155 million barrels of oil, calculated using a rate per barrel that is based on variations of certain crude oil prices. During the first quarter of 2005, cumulative field production exceeded the 155 million barrel production level and, since then, any additional production has been subject to the incentive.

In 1997, during what is referred to as the third round bids, PDVSA awarded us three 20-year service contracts for the exploration and production of Acema, La Concepción and Mata blocks. (We refer to the contracts awarded pursuant to the third round bids as the third round operating agreements and the three blocks awarded to us during those bids, namely the Acema, La Concepción and Mata blocks, as the third-round blocks.) The bids were initially made through joint ventures. Currently, we have a 90% interest in the La Concepción block and an 86.23% interest in the Acema and Mata oil blocks. La Concepción is an approximately 55,000 net acre block located in the Maracaibo basin with 116 producing wells. Acema and Mata, located in the Oriental basin, are approximately 64,000 and 45,000 net acre blocks with 18 and 57 producing wells, respectively. According to the concession contracts, PDVSA 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. Under contractual terms, royalties are deducted from the sales price.

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—Venezuelan Regulatory Framework—Petroleum and Gas—Additional Matters—OPEC.” Production cuts were only contemplated by the third round operating agreements, but not by the second round operating agreements, , which apply to the Oritupano-Leona field. Although no production cuts have been ordered under the second round operating agreements to date, it is not completely clear whether the constitutional principle that prohibits retroactive application of the law will protect those agreements against future production cuts.

The Venezuelan government has instructed PDVSA to take measures within a six-month term to convert all currently effective operating agreements into mixed-ownership contracts in order to grant the Venezuelan government, through PDVSA, more than 50% ownership of each field. The government has further instructed PDVSA to limit the total accumulated payments to contractors during a calendar year to 66.67% of the value of oil and gas produced under the related agreement. On April 15, 2005, PDVSA notified our subsidiary Petrobras Energía Venezuela, S.A. about this and advised that the Venezuelan Energy and Oil Ministry will, as soon as possible, contact our subsidiary to fix a date to begin the related discussions. Without opining on the proposed changes or the legitimacy of the operating agreements, we have expressed our willingness to engage in discussions with PDVSA and the Venezuelan government.

In addition, the Venezuelan tax authorities have recently publicly stated that they are looking into the taxes paid by private oil companies in recent years. The authorities have stated that private oil companies may have under-reported their taxable income in Venezuela. As of the date of this annual report, none of the oil companies operating in Venezuela, including us, have received a claim from the SENIAT in connection with this alleged investigation.

•

Peru

In 1996, we acquired 30-year oil and 40-year natural gas production rights in Lote X, an approximately 116,000-acre block in Peru’s Talara basin, through a public bidding process. The purchase included all of the then existing assets on the site. As of December 31, 2004, Lote X had 2,388 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. 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), which authorizes Perupetro to reduce the level of royalty payments, which are equal to 24% of the sales price. In accordance with the new law, we entered into an agreement with the Peruvian government whereby we undertake to make investments of approximately US$97 million in Lote X during the 2004-2011 period. Works covered by this agreement include the drilling of 51 wells, the workover of 526 wells, the reactivation of 177 temporarily abandoned wells and the implementation and expansion of a water injection project. The Peruvian government, in turn, reduced the percentage of royalties. Royalties paid for the production of crude oil are based on the price of a basket of crude oil prices, starting at a rate of 13% for prices up to US$23.9 per barrel. The royalty rate applicable as of December 31, 2004 was 17.6%. Production of natural gas is subject to a fixed royalty rate of 24.5%.

Due to the decrease in royalties as a result of this agreement, our economic projections in connection with operations in Peru have improved. Peru production accounted for 8% of our total average production in barrels of oil equivalent in 2004.

•

Ecuador

In Ecuador we operate Blocks 18 and 31, in which as of December 31, 2004, we hold a 70% and 100% interest, respectively. Ecuador production accounted for 4% of our total average production in barrels of oil equivalent in 2004.

— Block 18

In 2001, we acquired a 70% interest in Block 18, located in the Oriente basin of Ecuador. Block 18 is a field covering approximately 197,000 net acres and having a significant potential of 28º to 33° API light crude oil reserves. The concession for production activities in Block 18 is for an initial 20-year term, which commenced in October 2002. Once this term expires, Ecuadorian hydrocarbon laws 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. Exploratory activities were to continue for an additional three-year period and are scheduled to end in October 2005. With respect to this field, the government receives a production share ranging from 25.8%, if daily production is lower than 35,000 barrels per day, to 29%, if production exceeds 45,000 barrels per day. For the middle production range, the average share is about 26.1%.

In August 2002, Petroecuador, the Ecuadorian state owned company, subscribed to a joint exploitation agreement for the Palo Azul field in Block 18. In December 2002, the Palo Azul development plan was approved and the duration of the exploitation concession 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. Namely, if the crude from Palo Azul is sold at less than US$15 per barrel, the government receives about 30% of the crude produced, while, if the price of the crude is US$24 or higher, the government receives about 50% of production. The selling price of the Palo Azul crude is calculated considering as reference the WTI after taking into account the standard market discount for the Oriente crude.

As of December 31, 2004, the government’s shares of the oil produced at the Pata and Palo Azul fields was 25.8% and 50%, respectively.

As of the date of this annual report, 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 approximately 20,000 barrels per day. In 2004, we started works to expand production facilities in order to increase capacity to approximately 30,000 barrels per day by mid 2005.

— Block 31

Block 31 is located in a highly sensitive ecological area of the Amazon jungle in the central part of the eastern border of the upper Amazon basin and covers an area of approximately 494,000 net acres. Pursuant to the block’s production sharing agreement between Petroecuador and us, Petroecuador is entitled to a crude oil production share ranging between 12.5% and 18.5% depending on the field’s daily crude oil production and crude oil gravity.

We have conducted extensive exploratory work in the block, including the drilling of four exploratory wells in Apaika, Nenke, Obe and Minta. Each of these wells was successful and led to the discovery of the Apaika/Nenke, Obe, and Minta fields. In order to further develop the block, significant investments are required prior to the production phase.

In August 2004, the Minister of Energy of Ecuador approved an environmental impact study, completing all of the required steps for the approval of the development plan for the block. Following approval of the environmental study, a 20-year exploitation period began. During an initial three-year period, the plan contemplates investments of US$75 million by us, and we are obliged to provide Petroecuador a guarantee of 20% of this amount. In December 2004, as part of these contemplated investments, we commenced construction of a pier on the Napo River.

We have already started the development of the Apaika Nenke Field in Block 31. Initial investments of approximately US$50 million are necessary prior to the commencement of the production phase.

In January 2005, we entered into a crude oil transportation agreement with Occidental Exploration and Production Company, or Oxy. Under this agreement, we will be able to use a pipeline owned by Oxy to transport oil produced by Block 31 to the head of the OCP pipeline. The agreement becomes effective thirty days after the earlier of (1) the date that Block 31’s first volumes of crude oil are ready for transportation or (2) January 1, 2007, and runs through July 2019. A ship or pay clause is included in the agreement for an amount of approximately US$10 million, which is spread over 13 years and equals 25% of the production related to the Apaika Nenke field’s proved reserves. To comply with the agreement, Oxy’s facilities must be expanded, which will require an investment of approximately US$14 million. This investment will be financed by us and will be reimbursed by reducing the transportation rate charged to us. This agreement remains subject to approval by the Ecuadorian government.

— Ship or Pay Contract with Oleoducto de Crudos Pesados (OCP)

We entered into a ship or pay contract with OCP, whereby OCP has committed to provide us with a shipping capacity of 80,000 barrels per day for a 15-year term. OCP started commercial operations on November 10, 2003 and, as of that date, pursuant to our contractual obligations, we are required to pay OCP a transportation capacity fee regardless of whether we use the committed capacity. As of December 31, 2004, the fee was US$2.2 per barrel. We have assigned approximately 8,000 barrels a day of the 80,000 barrels per day commitment to a third party from July 2004 until January 2012. These arrangements will defray some of our shipping costs. Nonetheless, we currently estimate based on (1) the forecasted pace of development of Block 31 and (2) the revised outlook of the potential of Block 31’s reserves, that during the ship or pay contract’s term, oil production will be lower than our remaining portion of committed transportation capacity. We refer to this potential amount of unfulfilled commitment as an oil production deficit. After taking into consideration the significant economic effects due to this oil production deficit, as of December 31, 2003, we recorded a P$324 million impairment allowance in connection with our assets in Ecuador.

— Agreement with Teikoku

In January 2005, we entered into an agreement with Teikoku Oil Co., Ltd., or Teikoku, whereby, following approval by the Ministry of Energy of Ecuador, we will transfer 40% of our rights and interest in Blocks 18 and 31. In addition, once production in Block 31 reaches an average of 10,000 barrels of oil per day for a period of 30 consecutive days, Teikoku has agreed to assume 40% of our rights and obligations resulting from the crude oil transportation agreement with OCP. (Allocation of the transportation capacity to Teikoku will enable us to reduce the oil production deficit.) Teikoku, in turn, will pay us US$15 million. In addition, Teikoku has agreed to make investments in Block 31 in excess of its interest in the joint venture, causing accelerated development of the block. Once the agreement is approved by the Ministry of Energy of Ecuador, our interests in Blocks 18 would be reduced from our current level of 70% to 30% and our interest in Block 31 would be reduced from 100% to 60%, but we will continue acting as operator for both blocks. We expect that our partnership with Teikoku will accelerate the development of our Ecuadorian assets, making our operations in Ecuador a more relevant component in our business portfolio.

•

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 an approximately 56,000 net acre block located in the Sub Andina Central basin that has 48 producing wells with approximately 7,200 barrels of oil equivalent of production per day. Approximately 86% of our proved developed reserves in Bolivia are gas. These fields, which originally exported gas 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 approximately 4% of our total average production in barrels of oil equivalent in 2004.

In January 2005, we entered into a sales agreement with Petrobras Bolivia, whereby, we will transfer, subject to the approval of Yacimientos Petroliferos Fiscales Bolivianos, or YPFB, a 5% interest in Colpa Caranda to Petrobras.

•

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 act as contractor and provide the joint venture with the technical and operating support required for the operation of these blocks.

Statistical Information Relating to Oil and Gas Production

The following table sets forth our oil and gas fields’ production as of December 31, 2004. 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 extensions.


Production Areas	Location	Basin	2004 Production		Oil and Gas Wells	Interest		Expiration
Production Areas	Location	Basin	Oil⁽¹⁾	Gas⁽²⁾	Oil and Gas Wells	Interest		Expiration
Argentina:

25 de Mayo – Medanito S.E.	La Pampa and Río Negro	Neuquén	5,051	1,847	512	100.00	%	2016
Jagüel de los Machos	Río Negro and La Pampa	Neuquén	1,025	2,589	75	100.00	%	2015
Puesto Hernández	Mendoza and Neuquén	Neuquén	5,121	—	642	38.45	%	2016
Bajada del Palo – La Amarga Chica	Neuquén	Neuquén	82	—	4	80.00	%	2015
Santa Cruz II	Santa Cruz	Austral	3,711	18,385	83	100.00	%	2017
Río Neuquén	Neuquén and Río Negro	Neuquén	811	10,414	131	100.00	%	2017
Entre Lomas	Neuquén and Río Negro	Neuquén	742	1,278	345	17.90	%	2016
Veta Escondida and Rincón de Aranda U.T.E.	Neuquén	Neuquén	—	—	—	55.00	%	2016
Aguada de la Arena	Neuquén	Neuquén	88	6,862	10	80.00	%	2022
Santa Cruz I U.T.E.	Santa Cruz	Austral	2,686	31,194	94	71.00	%	2016

Total in Argentina			19,317	72,569	1,896


Outside of Argentina:

Colpa Caranda	Bolivia	—	497	12,914	48	100.00	%	2029
Oritupano Leona	Venezuela	Oriental Maturin	10,453	—	272	55.00	%	2014
Acema	Venezuela	Oriental Maturin	887	—	18	86.23	%	2017
La Concepción	Venezuela	Lago Maracaibo	4,749	7,589	116	90.00	%	2017
Mata	Venezuela	Oriental Maturín	1,491	—	57	86.23	%	2017
Lote X	Peru	Talara	4,145	3,140	2,388	100.00	%	2024
Block 31	Ecuador	Oriente	—	—	—	100.00	%	2024
Block 18	Ecuador	Oriente	2,290	—	8	70.00	%	2022

Total outside Argentina			24,512	23,643	2,907

Total			43,829	96,212	4,803

(1)	in thousands of barrels

(2)	in billions of cubic feet

The following table sets forth our average daily production of oil, including other liquid hydrocarbons, for the three fiscal years ended December 31, 2004, 2003 and 2002. This table includes our proportionate share of the production of both our consolidated subsidiaries and our unconsolidated investees.


	Year ended December 31,
	2004	2003	2002
	(average barrels per day)
Argentina	52,778	57,803	56,746
Outside of Argentina	66,973	56,827	58,917

Total	119,751	114,630	115,663

The following table sets forth our average daily gas production for the three fiscal years ended December 31, 2004, 2003 and 2002. This table includes our proportionate share of the production of both our consolidated subsidiaries and our unconsolidated investees.


	Year ended December 31,
	2004	2003	2002
	(average millions of cubic feet per day)
Argentina	198,217	202,272	252,559
Outside of Argentina	64,657	61,679	61,238

Total	262,874	263,951	313,797

The following table sets forth the average sales price per barrel of oil and per million cubic feet of gas for each geographic area for the three fiscal years ended December 31, 2004, 2003 and 2002, of our consolidated subsidiaries.


	Year ended December 31,
	2004	2003	2002
Argentina:
Oil (in pesos per barrel of oil equivalent)	88.11	69.80	65.88
Gas (in pesos per million cubic feet)	1.93	1.76	1.98
Outside of Argentina:
Oil (in pesos per barrel of oil equivalent)	61.91	52.70	50.70
Gas (in pesos per million cubic feet)	3.79	4.37	4.52

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, 2004, 2003 and 2002. This table includes our proportionate share of the production of our consolidated subsidiaries.


	Year ended December 31,
	2004	2003	2002
	(in pesos per barrel of oil equivalent)
Argentina:
Lifting Cost	7.74	6.45	5.77
Royalties	6.27	5.37	5.28
Depreciation	11.35	10.02	9.61

Total	25.36	21.84	20.66

Outside of Argentina:
Lifting Cost	8.92	9.42	10.41
Royalties	5.08	5.52	5.45
Depreciation	11.67	12.78	15.41

Total	25.67	27.72	31.27

Exploration

We believe exploration is an important vehicle for our future growth and for reserve replacement. We have, therefore, developed a strategy designed to constantly search for new exploration opportunities that are aligned with our growth targets. In accordance with this view, we plan on increasing investments in exploration, including new off-shore opportunities.

We use state of the art technology to minimize geological risk and to build a sound prospect portfolio.

In exploring off-shore areas, we will apply the technology and know-how of Petrobras, a world leader in offshore exploration and a pioneer in deep and ultra deep water activities. Petrobras has previously been awarded (on two occasions) with the “Offshore Technology Conference Distinguished Achievement Award” for its deep-water technology, the most important award in the international off-shore oil industry.

The following table lists our oil and gas fields in exploration areas as of December 31, 2004, the location of the basin in each area, our ownership interest and the expiration date of the exploration permits for each field.


	Location	Basin	Interest		Expiration
Argentina:
Glencross	Santa Cruz	Austral	96.68	%	1999	⁽¹⁾
Estancia El Chiripá	Santa Cruz	Austral	100.00	%	2001	⁽¹⁾
Santa Cruz I – Oeste	Santa Cruz	Austral	50.00	%	2006
Outside of Argentina:
San Carlos	Venezuela	Guarico	50.00	%	2005
Tinaco	Venezuela	Guarico	50.00	%	2005
Block 57	Peru	Ucayali	35.50	%	2010

⁽¹⁾	We have requested that the lot be declared operational and are awaiting a response from the relevant authorities.

Exploration in Argentina

As of December 31, 2004, we hold interest in approximately 882,000 gross acres (876,000 net acres) of exploration acreage in Argentina. 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.

In 2004, two successful wells were drilled in El Campamento - El Martillo exploratory field, in the Santa Cruz I Oeste Block, which resulted in discoveries. The first well yielded 190 barrels of oil per day and approximately 60,000 cubic meters of gas during the production test. The second well yielded 314 barrels of oil per day at a depth of approximately 1,400 meters. Further, exploratory drilling is scheduled for 2005.

In 2004, we decided to perform offshore activities in the Argentine marine basin and were awarded the seismic survey and exploration of two blocks: CAA 01, located 220 km to the east of Mar del Plata, in Buenos Aires Province and CAA 08, located 420 km to the south of this city. Water depth in these blocks ranges between 400 and 3,000 meters. No exploration activities have been previously performed in these areas.

During 2002, we farmed out a 50% interest in Santa Cruz I-Oeste 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. During 2004, two successful wells were drilled in accordance with this arrangement.

Exploration Outside of Argentina

As of December 31, 2004, we hold interests in approximately 363,000 gross acres (181,000 net acres) outside of Argentina available for exploration. We hold interests in three exploration blocks outside of Argentina: San Carlos and Tinaco in Venezuela and Block 57 in Peru. We also continue our exploration activities in Blocks 18 and 31 in Ecuador, and are seeking new business opportunities in Peru, Bolivia, Ecuador and Venezuela.

•

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 approximately 125,000 acres. 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 two exploratory wells. Total expenditures required for initial exploration in the block were US$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 approximately 238,000 acres. This event was an important step in the future development of the San Carlos block permitting us to confirm related natural gas reserves.

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

In October 2002, we entered into an association agreement with Teikoku, whereby we transferred 50% of our rights and obligations in and to gas production in San Carlos and Tinaco exploratory areas. This agreement is subject to approval by the Venezuelan Ministry of Energy and provides for an initial cash payment of US$1 million and a subsequent payment of US$2 million for the financing of certain exploratory investments in the Tinaco area. Furthermore, in the event both parties agree on a joint commercial development for the area, we will receive a supplementary payment of US$3 million.

•

Ecuador

The concession contract for Block 31 permits us to perform additional exploratory works for a period of three years following commencement of the development stage. We, therefore, may perform exploratory activities

until August 2007. We are currently performing new exploratory activities to determine the existence of other oil accumulations within Block 31, as well as, along the Apaika-Nenke trend. We plan to drill an appraisal well to test a step-out structure located immediately to the south of the Apaika block, which may have an impact on the field’s development. In addition, a 3D seismic survey is planned for later this year to appraise the Obe field discovery and potential structures immediately to the north of this field.

•

Peru

In May 2004, we entered into a contract with Repsol Exploración Perú S.A. to perform certain exploration activities jointly in Block 57, which is located in the Ucayali basin. Pursuant to this contract, we participate in Block 57 with a 35.15% interest. The work commitment for the initial exploration period consists of the reprocessing of existing 2D seismic data and geological studies.

Reserves

We believe our estimates of remaining proved recoverable oil and gas reserve volumes to be reasonable. Proved oil and natural gas reserves are those estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from reservoirs under existing economic, operating and regulatory conditions, i.e. prices and cost at the date of estimation. 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, 2004, 2003 and 2002.

As of December 31, 2004, liquid hydrocarbon and natural gas proved developed and undeveloped reserves, audited by Gaffney, Cline & Associates, Inc., amounted to 732 million barrels of oil equivalent (552.5 million barrels of oil and 1,077.0 billion cubic feet of natural gas), representing a 3.5% decline compared to the reserves certified as of December 31, 2003 (a decline of 2.9% for liquid hydrocarbons and 5.1% for natural gas).

Liquid hydrocarbons and natural gas accounted for 75% and 25%, respectively, of our total proved reserves as of December 31, 2004. Approximately 64% of our total proved reserves as of December 31, 2004 were located outside of Argentina as compared to 60% as of December 31, 2003. This increase is attributable to increased proved reserves in Ecuador. As of December 31, 2004, our proved developed reserves of crude oil equivalent represented 51.2% of our total proved reserves of crude oil equivalent.

During 2004, production totaled 59.9 million barrels of oil equivalent. Net additions of proved reserve totaled 34 million barrels of oil equivalent. Net additions during 2004 resulted from:

•

14.1 million barrels of oil equivalent added from improved recovery in production areas, particularly in Peru, where as a result of the increased profitability expectations resulting from the reduction of royalties brought about by new Law 28,109 “For the Promotion of Investment in the Exploitation of Hydrocarbon, Resources and Marginal Reserves,” we have added development projects;

•

44.6 million barrels of oil equivalent added from extensions and discoveries, principally as a result of the classification as proved reserves of discoveries and extensions of proved areas in Ecuador. In addition, reserves were added in the Argentine Austral basin and in Venezuela from extensions on producing fields; and

•

technical reviews based on the performance of the different fields and the projects implemented during 2004, resulting in reductions of previous estimates by 25 million barrels of oil equivalent mainly at fields in Argentina and Venezuela that are under secondary production.

As of December 2004, we had total oil and gas proved reserves equal to 12.2 years of production at 2004 oil and gas production levels.

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. This table includes our proportionate share of the proved reserves of our consolidated subsidiaries and unconsolidated investees. Our proportionate share of the proved reserves of our unconsolidated investees represented only 2.4% of our total proved reserves as of December 31, 2004.


	Crude oil, condensate and natural gas liquids						Natural gas
	Argentina		Outside of Argentina		Total		Argentina		Outside of Argentina		Total		Combined
	(in thousands of barrels)						(in millions of cubic feet)						(in millions of barrels of oil equivalent)
Total proved developed and undeveloped reserves as of December 31, 2002	213,342		380,536		593,878		943,788		369,456		1,313,244		812.7
Proved developed reserves as of December 31, 2002	146,319		177,876		324,195		554,104		209,854		763,958		451.5
Increase (decrease) originated in:
Revisions of previous estimates	(19,026	)	(3,278	)	(22,304	)	(131,964	)	23,110		(108,854	)	(40.4	)
Improved recovery	10,082		15,392		25,474		—		7,261		7,261		26.7
Extensions and discoveries	3,258		18,303		21,561		61,370		7,571		68,941		33.0
Purchase of proved reserves in place	—		—				—		—		—		—
Sale of proved reserves in place	(7,707	)	—		(7,707	)	(49,450	)	—		(49,450	)	(15.9	)
Year’s production	(21,097	)	(20,743	)	(41,840	)	(73,825	)	(22,517	)	(96,342	)	(57.9	)
Total proved developed and undeveloped reserves as of December 31, 2003	178,852		390,210		569,062		749,919		384,881		1,134,800		758.2
Proved developed reserves as of December 31, 2003	122,085		169,925		292,010		455,465		207,144		662,609		402.4
Increase (decrease) originated in:
Revisions of previous estimates	(21,351	)	(5,753	)	(27,104	)	14,276		(1,749	)	12,527		(25.0	)
Improved recovery	2,553		9,555		12,108		12,181				12,181		14.1
Extensions and discoveries	5,309		36,966		42,275		7,165		6,498		13,663		44.6
Purchase of proved reserves in place	—		—				—		—		—		—
Sale of proved reserves in place	—		—		—		—		—		—		—
Year’s production	(19,317	)	(24,512	)	(43,829	)	(72,568	)	(23,643	)	(96,211	)	(59.9	)
Total proved developed and undeveloped reserves as of December 31, 2004	146,046		406,466		552,512		710,973		365,987		1,076,960		732.0
Proved developed reserves as of December 31, 2004	97,696		168,119		265,815		444,404		208,440		652,844		374.6

The following table sets forth the breakdown of our total proved reserves of liquid hydrocarbons and natural gas into proved developed and proved undeveloped reserves as of December 31, 2004, 2003 and 2002.


	2004			2003			2002
	Millions of barrels of oil equivalent	% of total proved reserves		Millions of barrels of oil equivalent	% of total proved reserves		Millions of barrels of oil equivalent	% of total proved reserves
Proved developed reserves	374.6	51.2	%	402.4	53.1	%	451.5	55.6	%
Proved undeveloped reserves	357.4	48.8	%	355.8	46.9	%	361.2	44.4	%

Total Proved Reserves	732.0	100	%	758.2	100	%	812.7	100	%

Approximately 9% of our proved developed reserves as of December 31, 2004 are non-producing reserves.

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

There are many uncertainties in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including certain factors that are beyond our control. The reserve data set forth in this annual report solely represents estimates of our proved oil and gas reserves. Reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of a reserve estimate stems from available data, engineering and geological interpretation and judgment of reserves and reservoir engineering. As a result, different engineers often obtain different estimates. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate, so the reserve estimates at a specific time are often different from the quantities of oil and gas that are ultimately recovered. Furthermore, estimates of future net revenues from our proved reserves and the present value thereof are based upon assumptions about future production levels, prices and costs that may not prove to be correct over time. Forecasts of future prices, costs and production levels are subject to great uncertainty and may not prove to be correct over time. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Accordingly, we cannot assure that any specified production levels will be reached or that any cash flow arising therefrom will be produced. The actual quantity of our reserves and future net cash flows therefrom may be materially different from the estimates set forth in this annual report. See “Item 3. Key Information—Risk Factors—Factors Relating to the Company—Our oil and gas reserves are not 100% accurate and may be subject to revision.”

We replace our reserves through the acquisition of new producing fields, new exploration of our existing fields, the exploration of new fields and by “proving up” reserves in existing fields. “Proving up” is the process by which additional reserves classified as “probable and possible reserves” in a producing field are accessed and reclassified as “proved reserves.” We prove up reserves with reservoir management techniques by implementing waterflood and enhanced oil recovery projects. Reservoir management techniques currently used include water injection and drilling of horizontal wells, including producing and injection wells. In addition, technologies such as 3-D seismic process, horizontal and step out wells, underbalance drilling and reservoir numerical stimulation are also used.

As further discussed under “—Our History and Development—Petrobras Energía Merger,” as a result of the merger agreement, which will have retroactive effect as from January 1, 2005, EG3, PAR and PSF are expected to be merged into Petrobras Energía. If the merger had been consummated as of December 31, 2004, our volume of proved reserves as of December 31, 2004 of crude oil, condensate and liquids from natural gas and natural gas in Argentina would have increased by 20.7% and 54.7%, respectively.

Transportation and Sales

In Argentina, we transport our oil and gas production in several ways depending on the infrastructure availability and the cost efficiency of the transportation system in a given location. We use the Argentine oil pipeline system and oil tankers to transport oil to customers. Oil is customarily sold through FOB contracts, and therefore, producers are responsible for transporting oil produced from the field to a port for shipping, with all costs and risks associated with transportation borne by the producer. Gas, however, is sold at the delivery point of the gas pipeline system near the field and, therefore, the customer bears most of the transportation costs and risks associated therewith. Oil and gas transportation in Argentina operates in an “open access” non-discriminatory environment under which producers have equal and open access to the transportation pipelines. The privatization of the pipeline system led to capital investments in the systems. We maintain limited storage capacity at each oil site and at the terminals from which oil is shipped. In the past, these capacities have been sufficient to store oil without reducing current production during temporary unavailability of the pipeline systems, due, for example, to maintenance requirements or temporary emergencies.

With respect to production from Block 18 in Ecuador, oil is transported by a system that has a current transportation capacity of approximately 25,000 barrels per day. This capacity is expected to be increased to 40,000 barrels per day during 2006. Once the Palo Azul field has been completely developed, a 12-inch diameter and 35 km long oil pipeline is expected to be constructed from the oil treatment plant to Lago Agrio to transport production through the OCP or the Sistema de Oleoducto Transportation in accordance with the commercial circumstances prevailing at that time.

Future oil production from Block 31 will be transported through the OCP. With respect to future oil production from Blocks 18 and 31, we have entered into an agreement with OCP to ensure 80,000 barrels per day of oil transportation capacity (of which 8,000 has been assigned to a third party). See “—Hydrocarbon Marketing and Transportation—Oleoducto de Crudo Pesados (OCP).” We have also entered into a crude oil transport agreement with Oxy, pursuant to which, we will be able to use a pipeline owned by Oxy to transport oil produced by Block 31 to the head of the OCP. See “—Production—Production Outside Argentina—Ecuador—Block 31.”

Sales of crude oil and gas for the year ended December 31, 2004 were made mainly to PDVSA, Petroperú, EG3 and Glencore AG and sales to those entities represented about 12%, 7%, 6% and 3%, respectively, of total crude oil and gas sales, before deducting export duties, for that year. During 2004, oil and gas exports totaled approximately P$237 million or 7% of total consolidated crude oil and gas sales (calculated before deducting export duties). In 2004, exports sales were made principally to Chile.

Competition

Our oil and gas related businesses are subject to oil price fluctuations determined by international market conditions. In executing our strategy to expand our oil and gas operations both in and outside of Argentina, we face competition from oil and gas producers throughout the world.

HYDROCARBON MARKETING AND TRANSPORTATION

The hydrocarbon marketing and transportation segment serves to link our energy businesses. In the hydrocarbon marketing business, we provide oil, gas and liquified petroleum gas brokerage services to producing companies who prefer outsourcing oil, gas and liquified petroleum gas sales. This business enables us to position ourselves as a major commercial service provider since it assists clients not only in sales but also in logistics, foreign trade and market knowledge. We are engaged in the hydrocarbon transportation business through our interests in TGS, Oleoductos del Valle S.A., or Oldelval, and OCP.

Gas Transportation – TGS

•

Our interests in TGS and Corporate Developments

We hold, directly or indirectly, a 35% interest in TGS. TGS is controlled by CIESA, which, together with other companies of the Petrobras Energía group and the Enron group, own 70% of TGS’ capital stock. The remaining 30% of TGS’s capital stock is listed on the Buenos Aires Stock Exchange and New York Stock Exchange. CIESA, in turn, is owned on a 50/50 basis by subsidiaries of Enron Corporation, or Enron, and us. Both Enron and we have a right of first refusal on the transfer of CIESA’s shares and preferential rights to any shares issued by CIESA. An ownership committee composed of an equal number of our representatives and those of Enron manages the activities of TGS and CIESA. We appoint the chairman of the board of directors of both TGS and CIESA and the chief executive officer of TGS.

Due to the abrupt changes subsequent to the enactment of the Public Emergency Law in Argentina, CIESA and TGS both defaulted on their debt. CIESA failed to repay corporate notes having a principal amount of US$220 million and derivative instruments of approximately US$2 million in value. CIESA’s shareholders, including us, have not assumed any financial obligations to assist CIESA. Currently, CIESA is negotiating with its creditors to

refinance the terms of its debt. No pledges have been made by CIESA’s shareholders to provide financial aid. In April 2004, in order to provide the flexibility necessary to facilitate the restructuring of CIESA’s indebtedness, CIESA’s shareholders executed a Master Settlement Agreement, which provides for the following share transfers: During the first phase, (a) Enron will transfer 40% of the shares issued by CIESA to a newly created trust or an alternate entity and (b) we will transfer common class “B” shares issued by TGS (representing 7.35% of the capital stock of TGS) to Enron. If CIESA successfully renegotiates its indebtedness, during the second phase, Enron would transfer its remaining interest in CIESA to the abovementioned newly created trust or an alternate entity while CIESA would simultaneously transfer common class “B” shares issued by TGS (representing about 4.3% of the capital stock of TGS) to Enron. In no case, will we hold, directly or indirectly, more than 50% of the capital stock currently held in CIESA or a controlling interest in CIESA. In addition, Petrobras Energía and Enron agreed to release each other from all claims related to their investments in CIESA and TGS. The bankruptcy court handling the Enron bankruptcy approved the Master Settlement Agreement in May 2004. The proposed share transfers were submitted to the CNDC for approval, which has been confirmed. They have also been submitted to ENARGAS, which has conditioned its approval on the receipt of a favorable opinion from the Treasury Attorney General (Procuración General del Tesoro) and, as of the date of this annual report, we do not know whether this opinion has already been rendered.

TGS failed to comply with certain financial restrictions contemplated in its debt obligations. As a result, in February 2003, TGS started an overall restructuring process involving US$1,027 million of its indebtedness, which accounted for almost all of its debt. In 2004, TGS successfully emerged from default through a restructuring proposal presented to creditors in October 2004. The restructuring proposal was accepted by close to 100% of its creditors. The creditors that accepted the proposal received (1) a cash payment equivalent to 11% of the outstanding principal amount, (2) new debt securities for the remaining 89% of the outstanding principal amount, structured into two tranches, A and B, with amortization terms of six and nine years, respectively, accruing interest rates ranging from 5.3% to 10%, and (3) a cash payment in respect of the accrued and outstanding interest on the previous debt, calculated at the interest rate stipulated by contract for each instrument up to December 31, 2003, and at an annual rate of 6.18% from January 1 to December 15, 2004. The interest payment described in item (3) above was considered full settlement of any claim for interest owed, including any punitive interest.

In late 1992, TGS entered into the Technical Assistance Agreement with Enron Pipeline Company Argentina S.A., which has a term of eight years from December 28, 1992 and is automatically renewable upon expiration for additional eight-year periods. In accordance with the Master Settlement Agreement, this agreement was assigned to us on July 15, 2004, following receipt of approval from ENARGAS in June 2004. Since then, we have been in charge of providing services related to the operation and maintenance of the gas transportation system and related facilities and equipment, to ensure that the performance of the system is in conformity with international standards and in compliance with certain environmental standards. For these services, TGS pays us an annual fee equal to the greater of (1) P$3 million or (2) 7% of the amount obtained after subtracting P$3 million from TGS’ net income before financial income (expense) and income taxes. Before this assignment, we shared in these management fees through an agreement with Enron, in which we were reimbursed for any costs associated with any service provided by TGS on behalf of Enron and received a percentage of the operating income.

•

Business

TGS began operations in late 1992 as a part of the privatization of the Argentine energy sector. Currently, TGS is the leading gas transportation company in Argentina, delivering about 61% of the gas consumed. TGS is also one of the leading natural gas liquids producers and traders, both in the domestic and international market, and an important provider of midstream services, including business and financial structuring, turnkey construction and the operation and maintenance of facilities (used for gas gathering, conditioning and transportation).

The following chart shows statistical information relating to TGS’s business segments for fiscal years ended December 31, 2004, 2003 and 2002.


	2004		2003		2002
Regulated Segment:
Average firm committed capacity⁽¹⁾	63.6		61.7		61.4
Average daily deliveries⁽¹⁾	61.5		52.6		49.4
Annual load factor⁽²⁾	97	%	85	%	80	%
Unregulated Segment:
Liquids total production⁽³⁾	969.0		929.1		908.5
Processing capacity at year end⁽¹⁾	43.0		43.0		43.0

(1)	In millions of cubic meters per day.

(2)	Corresponds to the quotient of the average daily deliveries and the average firm contracted capacity.

(3)	In thousands of tons.

Regulated Energy Segment

Within the regulated energy segment, TGS is the gas transportation licensee in the south of Argentina and is the largest transporter of natural gas in Argentina and all of Latin America. TGS has an exclusive license for the utilization of the southern gas transport system, which is due to expire in 2027 with an option to extend for ten additional years if certain conditions are fulfilled.

TGS transports gas through more than 7,400 km of pipelines with a capacity of approximately 65 million cubic meters per day, substantially all of which is committed under firm transportation contracts. Pursuant to these contracts, the capacity is reserved and paid for irrespective of the actual use by the customer. Almost all capacity of the gas transportation pipelines in Argentina is currently apportioned among gas distribution companies, large industrial customers and gas-fired power plants under firm long-term contracts. In 2004, TGS entered into a new firm transportation agreements covering approximately 3.6 million cubic meters per day. The total average life of its firm transportation contracts is approximately eight years. In addition, TGS provides interruptible transportation services under which gas transportation is dependent on the availability of capacity. TGS’ pipeline system connects Argentina’s southern and western gas reserves with the main consumption centers in those regions, including Greater Buenos Aires.

Transportation services begin with the receipt of gas owned by a shipper (e.g., distribution companies, producers, marketers or major users) at one or more reception points. It is then transported and delivered to delivery points along the system. The total service area includes approximately 4.8 million end users, approximately 3.3 million of which are in Greater Buenos Aires. Direct services to residential, commercial, industrial users and electrical power plants is mainly rendered by four gas distribution companies, which are connected to the TGS system: MetroGas S.A., Gas Natural Ban S.A., Camuzzi Gas Pampeana S.A, and Camuzzi Gas del Sur S.A. Certain significant industries and electrical power plants are also located within TGS’s operational area, to whom TGS renders direct transportation services and represent approximately 19% of TGS’ total capacity.

TGS has made significant investments in its business. As a result, approximately 821 km of gas pipelines were laid in addition to the existing pipelines, totaling 7,400 km of gas pipelines, compression power was increased from 339,000 horsepower in 1992 to 550,230 horsepower in 2004 and transportation capacity increased from 42.9 million cubic meters per day to 63.4 million cubic meters per day by the end of 2004.

As a consequence of the enactment of the Public Emergency Law, which pesified and froze tariffs, revenues from the regulated segment significantly decreased. In 2004, the gas transportation segment accounted for 44% of TGS’s total revenues compared to 47% and 57% in 2003 and 2002, respectively, and to approximately 80% since the start of the service until 2001. TGS continues seeking new alternatives aimed at growing its business and mitigating the effects derived from this law. Along these lines, in 2003, TGS entered into an agreement with a gas producing consortium at the Austral basin, comprised of Total Austral S.A., Panamerican Sur S.R.L. and Wintershall Energía S.A., for the purpose of providing Argentine natural gas to Methanex—a leading company in the production of methanol located in Chile. Pursuant to this agreement, TGS constructed a compressor plant of

12,700 horsepower along the General San Martín pipeline and built a pipeline approximately 6 km long with 1 million cubic meters per day of initial capacity, which links TGS’s main pipeline system to the Chilean border. This project was developed in 2004 and was completed in February 2005.

In July 2004, UNIREN made a proposal to TGS to adjust the contractual terms of its license, by effecting a 10% rate increase for 2005 and providing for a comprehensive rate review effective as of 2007. Because UNIREN’s proposal did not reflect the outcome of previous meetings held with UNIREN, TGS requested to continue the negotiation process in order to come to a comprehensive agreement during 2005. On April 27, 2005, at a public hearing called by UNIREN to analyze the proposal made on July 2004, UNIREN repeated its 10% increase proposal and proposed to accelerate effectiveness of the comprehensive rate review process to 2006, and TGS has decided to continue negotiating in order to seek to improve these terms.

In June 2004, in accordance with Argentine regulatory requirements with respect to the creation of trust funds to finance system expansions, TGS submitted to the Energy Bureau an expansion project for the San Martín pipeline that involved a capacity increase of approximately 2.9 million cubic meters per day. The project requires the construction of approximately 500 km of pipelines and the construction of a compressor plant and revamping of certain compressor units to increase compression capacity to 30,000 horsepower by the third quarter of 2005. Works for the project have begun. On November 3, 2004, TGS, the Argentine government, Petrobras, Nación Fideicomisos S.A. and certain other parties executed an agreement for the construction and financing of the project. This agreement provides that Petrobras will lead and coordinate the financing of the project, which includes financing for exports from Brazilian suppliers, to be provided by Banco Nacional de Desenvolvimento Económico e Social de Brasil, or BNDES, (or any other financial institution appointed by Petrobras) amounting to at least US$142 million and will obtain the financing, and/or, otherwise, contribute the funds to the project, until such financing is disbursed. TGS will be in charge of managing the project and operating and maintaining the new facilities.

Petrobras Energía has agreed to act on account and behalf of Petrobras by providing up to US$142 million of the funds to finance the project until the financing is made available by BNDES. In turn, a financial trust created for the project’s financing will deliver debt securities in equivalent value to Petrobras Energía. Petrobras Energía has contributed US$53 million to the trust on account and behalf of Petrobras. On May 25, 2005, BNDES made an initial disbursement of US$14 million and, since then, the financing facility with BNDES became effective.

Petrobras Energía’s US$142 million contribution to this project is being funded by a loan from Petrobras Internacional Braspetro BV, a subsidiary of Petrobras.

Businesses

In addition to the regulated segment of natural gas transportation, TGS is also one of the leading processors of natural gas and one of the largest marketers of natural gas liquids. Natural gas liquids production and commercialization involves the extraction of ethane, propane, butane, and natural gasoline from the gas flow that arrives to the General Cerri Complex, located near Bahía Blanca, in the Province of Buenos Aires, which is connected to TGS’s main pipelines. TGS has two gas processing plants at the General Cerri Complex: (1) an ethane, propane, butane and natural gasoline turbo expander separating plant and (2) an absorption plant which extracts propane, butane and gasoline from the gas transported through the TGS pipeline system, with a gas processing capacity of 43 million cubic meters per day and a storage capacity of 60,450 tons. After extraction, TGS commercializes these products in the domestic and international market. TGS also stores and ships the products at facilities located in Puerto Galván. These activities are not regulated by ENARGAS.

As a result of agreements entered into with natural gas producers in the Neuquén basin, TGS became the owner of a portion of the General Cerri Complex production. TGS was also able to increase the richness of the gas reaching the complex for processing purposes and, thus, minimized the impact of competitive developments.

Natural gas liquid’s revenues, as a part of total revenues of TGS, increased from a share of 48% in 2003 to 51% in 2004. Three factors contributed to the growing strength of natural gas liquids: (1) the material increases in the international prices of liquids derived from gas—which gained momentum with the sharp increase of oil prices during 2004, (2) the increase in demand for gas at the General Cerri Complex that generated record liquid volumes and (3) the effects of the Public Emergency Law on the revenues from the regulated segment.

Through the provision of midstream services, TGS provides integral solutions for natural gas treatment at the wellhead, including conditioning, gathering and gas compression services. These services also include those related to the construction, operation and maintenance of gas pipelines and treatment plants provided by TGS or its related companies, Gas Link S.A. and Transporte y Servicios de Gas en Uruguay S.A. TGS is developing a strategy geared towards becoming one of the main service providers in Argentina.

TGS has a 49% interest in Gas Link S.A., a company engaged in the construction, operation and maintenance of the gas pipeline connecting the TGS system and the Cruz del Sur gas pipeline, which links Argentina to Uruguay and is likely to be extended to Brazil. This pipeline is approximately 40 km long, has a current transportation capacity of 1 million cubic meters per day and started operations in October 2002.

Oldelval

Oldelval, a company in which we have a 23.1% interest, holds the concession for the transportation of crude oil through 888 km-long oil pipelines with 1,706 km of installed piping between the Neuquén basin and Puerto Rosales (located in the Province of Buenos Aires). The concession has a 35-year period starting in 1993 with an option to renew for ten years. Oldelval’s other shareholders are Repsol-YPF, Petrolera San Jorge, Pluspetrol, Pan American and Tecpetrol.

The Allen/Puerto Rosales section transportation capacity is approximately 265,000 barrels per day, with a 173,000 cubic meters of storage capacity. In 2004 and 2003, Oldelval transported approximately 66.5 million and 65 million of oil barrels, respectively, from the Neuquén basin to the Atlantic coast.

The applicable laws governing the transportation of hydrocarbons through oil pipelines, which are based on the free access notion, assign loading preference quotas to pipeline owners based on their shareholdings. Oil transportation rates are set by the Argentine Secretary of Energy.

Oleoducto de Crudos Pesados (OCP)

The government of Ecuador awarded OCP with the construction and operation for a 20-year term of the 503 km long pipeline that runs from the northeastern region of Ecuador to the Balao distribution terminal on the Pacific Ocean coast. As of December 31, 2004, we held an 11.42% interest in OCP. OCP’s other shareholders are Encana, Perenco, Occidental, Repsol-YPF and AGIP.

The oil pipeline has an approximately 450,000 barrels per day transportation capacity, of which at least 350,000 barrels per day have been committed under a ship or pay contract for transportation of their production. Since the oil pipeline runs across ecologically sensitive areas, the pipeline was constructed under stringent environmental protection and technical standards.

The construction of the oil pipeline was performed by Techint International Construction Corporation, or Tenco, and was completed in 2003. After testing the system at its maximum capacity and obtaining approval by the Ministry of Energy and Mines of Ecuador, the oil pipeline officially started operations on November 10, 2003. During 2004, the first year of operation, it transported over 75 million barrels of heavy crude oil, which were shipped on more than 138 vessels from its offshore facilities on the Ecuadorian coast.

In 2004, OCP’s marine terminal obtained the certificate for compliance with the Code of Protection of Vessels and Port Facilities required by the International Marine Organization, becoming one of the first ports in Latin America to obtain this certification.

OCP’s original budget amounted to US$1,210 million, US$900 million of which was funded by banking institutions, US$250 million of which was funded by subordinated loans from shareholders and US$60 million through capital contributions. We made contributions in the amount of US$9 million and were granted a 15% shareholding interest. The total construction cost of the oil pipeline amounted to US$1.4 billion, which was US$190 million in excess of the original budget. The need for additional financing was satisfied through loans and capital contributions by shareholders in the amount of US$150 million and US$40 million, respectively. We did not make any such contributions and our equity interest was diluted from 15% to 8.96%.

In May 2004, Tenco exercised an option to sell to us its shares and subordinated debt in OCP, comprising a 2.46% ownership interest for US$14 million. Consequently, our interest in OCP increased to 11.42%.

In connection with production from Blocks 18 and 31 in Ecuador (Block 31 has no production yet as it is in the early stages of development), we, through Petrobras Energía Ecuador, entered into a ship or pay contract with OCP, whereby OCP has committed to transport 80,000 barrels per day for a 15-year term, as from November 2003. For a more detailed discussion see “—Oil and Gas Exploration and Production—Production—Production Outside of Argentina—Ecuador—Ship or Pay Contract with Oleoducto de Crudos Pesados (OCP).”

In June 2004, Petrobras Energía Ecuador entered into a transportation agreement with Murphy/Canam Oil whereby we committed to transport, using our committed capacity in the OCP, 8,000 barrels per day until January 2012. Under this agreement, we transported approximately 1.6 million barrels of crude oil in 2004, thereby mitigating the impact of the economic commitment under the ship or pay agreement by US$3.6 million.

Competition

TGS’s gas transportation business, which provides an essential service in Argentina, faces only limited direct competition. In view of the characteristics of the markets in which TGS operates, it would be very difficult for a new entrant in the transportation market to pose a significant competitive threat to TGS, at least in the short to medium term. In the longer term, the ability of new entrants to successfully penetrate TGS’s market would depend upon a favorable regulatory environment, an increasing and unsatisfied demand for gas by end users, and sufficient investment in gas transportation to accommodate increased delivery capacity from the transportation systems.

On a day-to-day basis, TGS competes, to a limited extent, with Transportadora de Gas del Norte S.A. for interruptible transportation services and for new firm transportation services made available as a result of expansion projects from the Neuquén basin to the greater Buenos Aires area. Interruptible transportation services accounted for only 5.4% of TGS’s regulated net revenues for 2004. The relative volumes of such services will depend principally upon the specific arrangements between buyers and sellers of gas in such areas, the perceived quality of services offered by the competing companies, and the applicable rate for each company.

With respect to natural gas liquids processing activities, TGS competes with MEGA S.A., which owns a gas processing plant at the Neuquén basin and has a processing capacity of approximately 36 million cubic meters per day. Our controlling company, Petrobras, has a 34% interest in MEGA S.A.

REFINING

Our presence in the refining business is a further step towards the vertical integration of our operations. The refining business enables us to capitalize on our significant hydrocarbon reserves. Refining operations are a necessary link in the business value chain, which starts with crude oil exploration and ends with customer service.

Our refining operations are located in Argentina and Bolivia. In Argentina, we operate our own refinery in San Lorenzo and have a 28.5% interest in Refinería del Norte S.A., or Refinor. In Bolivia, as of December 31, 2004, we had a 49% interest in Empresa Boliviana de Refinación, or EBR.

The Refining Business in Argentina

During recent years, the Argentine liquid fuel market was adversely affected by the growth of compressed natural gas as substitute fuel. The high taxes imposed on gasoline and, to a lesser extent, on diesel consumption, affected the market, encouraging the use of compressed natural gas to the detriment of liquid fuels. The gasoline domestic market shrank approximately 48% in the 1995-2003 period. In 2004, this downward trend was interrupted, achieving an increase of 2%. Demand for diesel grew by approximately 4% and 9% in 2003 and 2004, respectively, partly as a result of growth in the agricultural sector. This recovery halted a prolonged downward trend in the market, which had resulted in a 14% drop from 1999-2002.

The Argentine government has imposed taxes on exports of crude oil, certain oil by-products and gas, in an effort to maximize volumes refined domestically, to shelter the domestic economy from foreign fluctuations and to stabilize domestic levels of industrial activity, employment and prices. During 2004, the Argentine government repeatedly increased export taxes in line with the increase of international crude oil prices. We have been able to minimize the impact of these increases through the integration of our upstream and downstream activities and the synergies derived from our relationship with Petrobras, as described below. During 2004 and 2003, sales volumes of crude oil among our business segments increased 7.2% and 21.6%, respectively, to approximately 34,000 barrels per day and approximately 31,700 barrels per day, while exports of crude oil in the 2002/2004 period declined approximately 75%.

Business synergy with Petrobras

Our Refining segment, being a part of the Petrobras group, offers the most immediate prospects of further developing and exploiting business opportunities. During 2003 and 2004, the sale of diesel oil to and the purchase of gasoline from EG3, the change of flags of former Pecom gas stations and the development of high value added products such as Podium, were all examples of the benefits we have enjoyed from this relationship. The complementary nature of our business with EG3, a company previously controlled by Petrobras that merged into Petrobras Energía in 2005, provided us with the opportunity to further the vertical integration of our operations. Since the volume of diesel oil produced by us at our refinery in San Lorenzo exceeds the demand of our gas station network, during 2004 and 2003, we sold 466,000 and 248,000 cubic meters, respectively, of refined products to EG3, and as a consequence of these sales, there was an increase in crude oil volumes processed at our refinery in San Lorenzo.

Refining Division

We operate a refinery in San Lorenzo, Province of Santa Fé, strategically located along the central product distribution system. The refinery capacity is approximately 37,700 barrels of oil per day, enabling us to process a large part of our crude oil production in Argentina. The refinery has three atmospheric distillation units, two vacuum distillation units, a heavy diesel oil thermal cracking unit and an aircraft fuel production unit, which produce the following products: premium and regular gasoline, jet fuel, diesel oil, fuel oil, kerosene, solvents, aromatics and asphalts.

The refinery has two fuel storage and dispatch plants located in the Provinces of Santa Fe and Buenos Aires, respectively. At our Dock Sud facilities, in the Province of Buenos Aires, crude oil is received, stored and dispatched. The Dock Sud facility has a total storage capacity of approximately 377,000 barrels. Crude oil is received from the oil pipeline connecting Bahía Blanca with Dock Sud and is dispatched to tankers transporting the oil to the San Lorenzo refinery. In addition, the San Lorenzo refinery, located on the right bank of the Paraná River, with access from the so-called hydroway forming part of the Océano-Santa Fé trunk navigation route, has three docks for 250 meter-long vessels having 70,000 ton displacement.

As of December 31, 2004, we had a commercial network of 122 retail outlets, including 86 gas stations (eight directly operated by us), 20 diesel centers, including six mobile diesel centers and ten agro-service centers, located in the Provinces of Santa Fé, Buenos Aires, Entre Ríos, Corrientes, Santiago del Estero, Tucumán, San Juan, San Luis, Catamarca, Chaco, Formosa, Salta, Mendoza and Córdoba. We continued the development of new Petrobras-branded gas stations and rebranding of gas stations from Pecom to Petrobras, aimed at capitalizing on the positive attributes associated with the Petrobras brand. As of December 31, 2004, 48 retail outlets were using the Petrobras brand, 39 of which changed names in 2004. Petrobras has built an excellent image for its brands, products and services in Argentina, currently competing with the image of the leading companies in the country.

As part of our marketing strategy, in order to increase market share and profitability, we offer higher value-added products and services. In mid 2004, we launched Podium, a gasoline with the highest octane rating in the Argentine market. Created jointly by Petrobras’ and our technicians, Podium is produced at the San Lorenzo refinery in Santa Fe and is distributed on an exclusive basis by Petrobras’ retail network throughout Argentina.

Podium is not only the first Argentine premium gasoline of its kind to offer a 100 octane rating but also contains multifunctional additives to help keep the engine clean. Podium meets the highest quality and environmental safety standards, having been awarded quality certifications by the Petrobras Research Center (CENPES) in Brazil and the South West Research Institute in Houston, United States. Podium was well received by the Argentine market and, by the end of the year, Podium’s sales surpassed the premium gasoline it replaced, Magnum, by 54%.

Through our extensive gas station network, we also market Lubrax lubricants. These lubricants, which are manufactured by Petrobras, enjoy 9.2% of the domestic market share and have experienced the highest growth rate in Argentina among lubricants in 2004. Petrobras’ technical, commercial and advertising efforts for the development of the Lubrax brand give considerable support to our sales growth in this business.

In addition, as part of our marketing strategy, we began offering in 2004 the Tarjeta Flota card, which is a brand loyalty program aimed at increasing sales volumes and establishing a more stable and lasting relationship with customers.

The following table shows production and sales figures for the Refining business segment for the fiscal years ended December 31, 2004, 2003 and 2002:


	Year Ended December 31,
	2004	2003	2002
Production (thousands of tons):
Virgin naphtha	398	417	325
Diesel oil	647	613	499
Other products	622	619	507
Sales:
Aromatics (thousands of tons)	39	56	67
Benzene (thousands of tons)	54	50	44
Gasoline (thousands of m3)	207	119	123
Diesel oil (thousands of m3)	913	883	622
Other medium distillates (thousands of m3)	5	11	13
Asphalts (thousands of tons)	115	86	43
Reformer plant products (thousands of tons)	74	79	65
Other heavy products (thousands of tons)	445	418	374
Paraffins (thousands of tons)	138	151	138
Sales (in millions of pesos):
Argentina	1,275	956	636
Outside of Argentina	470	346	372

Total	1,745	1,302	1,008

During 2004, our refinery processed an average of 33,100 barrels per day. Crude oil volumes processed accounted for about 88% of the refining capacity. The integration of our operations with EG3 has allowed us to significantly increase the crude oil volumes processed and to further link our upstream and downstream businesses in Argentina. In 2003 and 2002, crude oil volumes processed amounted to on average 32,600 barrels per day and 27,100 barrels per day, respectively. As of December 31, 2004, we estimate that we had a market share of approximately 3.4% in the gasoline market, 3.5% in the diesel oil market, 25.3% in the asphalt market and 13.1% in the fuel oil market.

Refinor

We have a 28.5% interest in Refinor. Refinor’s other two shareholders are Repsol-YPF (50%) and Pluspetrol Exploración y Producción S.A. (21.5%).

Refinor owns the only refinery in the northern region of Argentina, which is located in Campo Duran, Province of Salta. Refinor’s refining capacity is 26,103 barrels of oil per day and its natural gas processing capacity

is 19.5 million cubic meters per day. Refinor receives crude oil and natural gas from the oil and gas fields located at the northwestern region of Argentina and Bolivia. It has an atmospheric distillation unit, a vacuum distillation unit, a catalytic reformer plant, two turboexpander plants and a compressor plant. Refinor produces gasoline, diesel oil, fuel oil, virgin naphtha, propane, butane, natural gasoline and liquified petroleum gas. It is the leading liquified petroleum gas producer based on production volumes in the northern region of Argentina and the third largest producer in the country.

As of December 31, 2004, Refinor had a commercial network comprising 73 gas stations (14 owned by Refinor) located in the Provinces of Salta, Tucumán, Jujuy, Córdoba, Santiago del Estero, Catamarca and Chaco and had started developing a commercial network in Bolivia, where it has 12 gas stations under its brand. For logistics and distribution purposes, Refinor operates a 1,112 km poliduct that extends from the compression station in Campo Durán (Salta) to Montecristo (Córdoba). Along the pipeline, layout product recompression stations are located at Urundel (Salta), Lavallén (Jujuy), Cobos and Piedras (Salta) and Quilino (Córdoba). The pipeline supplies the following dispatch plants:

•

General Güemes (Salta), with a 1,800 cubic meter storage capacity (liquefied gas);

•

Banda del Río Salí (Tucumán), with a 57,508 cubic meter storage capacity (fuels); and

•

Leales (Tucumán), with a 5,054 cubic meter storage capacity (liquefied gas).

In addition, the poliduct discharges a large volume of products, such as petrochemical naphta and liquefied gas, at the Terminal Station located at Montecristo (Córdoba), and these products are then dispatched in the area or sent to San Lorenzo, Province of Santa Fé.

The following table sets forth Refinor’s sales and production for the fiscal years ended December 31, 2004, 2003 and 2002:


	Year ended December 31,
	2004	2003	2002
Production:
Gasoline (thousands of m3)	101	122	121
Virgin naphtha (thousands of m3)	387	420	473
Diesel oil (thousands of m3)	354	330	335
Natural gasoline (thousands of m3)	132	129	134
Propane/butane (thousands of tons)	363	313	287
Other products (thousands of m3)	158	138	100
Sales:
Gasoline (thousands of m3)	109	121	122
Virgin naphtha (thousands of m3)	529	550	611
Diesel oil (thousands of m3)	406	378	374
Propane/butane (thousands of tons)	354	297	274
Other products (thousands of m3)	81	97	103
Sales (in millions of pesos):
Argentina	582	490	428
Outside of Argentina	534	373	412
Total	1,116	863	840

In 2004, Refinor’s sales through its service centers had a share in the gasoline and diesel oil markets in the northwest of Argentina of 25% and 18.2%, respectively. In addition, Refinor reached a 55% share in the diesel oil import market in Bolivia.

Empresa Boliviana de Refinación (EBR)

We have a 49% interest in EBR. Petrobras is our strategic partner, with a 51% interest.

EBR owns two Bolivian refineries located in Cochabamba and Santa Cruz de la Sierra, with an estimated maximum production capacity of 47,500 barrels of oil per day, accounting for 95% of Bolivia’s total refining capacity. In 2004, an average of 37,460 barrels per day were processed.

EBR wholly owns Petrobras Bolivia Distribución a company having a commercial network of 92 gas stations, 11 of which were added during the last fiscal year. In 2004, Petrobras Bolivia Distribución continued implementing the Integrated Gas Stations concept in Bolivia by offering supplemental products.

Competition

We compete in Argentina principally with Repsol-YPF S.A., Shell CAPSA and Esso S.A., which hold approximately 49.7%, 16.3% and 14.1% of the domestic market share. Together with EG3, which, upon registration with the Argentine Public Registry of Commerce, is expected to merge into Petrobras Energía, we would have had a combined market share of 14.7% as of December 31, 2004.

PETROCHEMICALS

The Petrochemicals business is a key component in our strategy of vertically integrating our operations. Our goal in the petrochemical business is to consolidate our regional leadership by:

•

Maximizing the use of our own petrochemical raw materials;

•

Taking advantage of current conditions in the styrenics market by increasing the supply; and

•

Consolidating the fertilizer business which uses and, therefore, adds value to our natural gas business.

Our petrochemical operations are performed in Argentina and Brazil, through the production of a wide array of products, such as styrene, polystyrene, synthetic rubber, fertilizers and polypropylene, both for the domestic and export markets.

Through Innova, our wholly owned subsidiary in Brazil, we have the region’s largest installed capacity to produce styrene and polystyrene, and can provide services to clients in both Brazil and Argentina. We also have a 40% interest in Petroquímica Cuyo S.A, which we refer to as Cuyo, a producer and marketer of polypropylene

Argentine Operations

Argentine styrenics division

In Argentina, we are the only producer of styrene monomer, polystyrene and elastomers and the only integrated producer of products from oil and natural gas to plastics. As part of our efforts to integrate our operations, we use a large amount of styrene for the production of polystyrene and synthetic rubber.

The styrenics division has a plant at Puerto General San Martín, Province of Santa Fé, with a production capacity of 110,000 tons of styrene per year and 57,000 tons of synthetic rubber per year, and a plant at Zárate, Province of Buenos Aires, with a production capacity of 66,000 tons of polystyrene per year and 14,000 tons of bioriented polystyrene, or Bops, per year. This state-of-the-art plant of Bops in Zárate is the only one of its type in Latin America.

In March 2004, we acquired from Imperial Chemical Industries an ethylene plant located in San Lorenzo. The plant has a production capacity of 20,000 tons per year, and became operational in October 2004. It is located along the Paraná river coast, adjacent to the San Lorenzo refinery, which provides the oil feedstock necessary for its operation, and the Puerto General San Martín petrochemical complex, which uses ethylene as raw material for the production of ethylbenzene and ultimately styrene. The acquisition of this ethylene plant has expanded our business value chain and our product offering, resulting in an increase in our share of the plastic raw material market. In addition, it allowed us to increase production capacity at the Puerto General San Martín ethylbenzene plant from

116,000 tons to 180,000 tons per year. With this additional ethylbenzene production, we expect to be able to make full use of the installed production capacity of our Innova plants, thereby broadening our regional leadership in this market.

During 2004, production volumes from the Puerto General San Martín complex totaled 110,500 tons of styrene, a 4% increase from the previous year. Volumes from the Zarate plant, in turn, increased 8% compared to 2003, with a production of 62,000 tons of polystyrene. In 2004, Petrobras Energía achieved a new production record of 12,000 tons of Bops (11% higher than the previous year). Rubber production, in turn, totaled 58,400 tons (4% higher than volumes recorded in 2003), setting a historical record that was caused in part by increased domestic demand.

As of December 31, 2004, our estimated share in the Argentine market was:

•

Styrene - 100%; and

•

Styrene butadiene rubber, or SBR, combined with the market for nitrite butadiene rubber, or NBR - 95%.

In addition, we are market leaders in Argentina for polystyrene.

Exports are a significant part of our business. In 2004, we exported 30%, 57% and 42% of our total sales volumes of styrene, rubber and polystyrene, respectively. Exports were primarily to Mercosur member countries and Chile. As of November 2004, we started exporting ethylbenzene, produced from the ethylene from our new plant in San Lorenzo, to Innova in Brazil. In addition, we exported 9,600 tons of bioriented polystyrene, primarily to Europe and the United States.

Fertilizers division

We are pioneers in the production and distribution of fertilizers in Argentina. We supply approximately one-third of the Argentine fertilizer market with a wide array of specific solutions and are the only liquid fertilizer producer in Latin America.

The fertilizers division has a plant located at Campana, Province of Buenos Aires, with a production capacity of 200,000 tons per year of urea. We are the only producer of liquid fertilizer (a composition of urea and ammonium nitrate) in Latin America. In 2004, we increased the installed production capacity of liquid fertilizer to 677,000 tons per year from 475,000 tons per year. In October 2004, we finished the construction of a thiosulfate fertilizer plant, with a production capacity of 140,000 tons per year. Construction of the plant required investments of approximately US$15 million. The plant, which has state of the art equipment, was designed in accordance with environmental standards and in line with Petrobras’ stringent standards of Quality, Safety, Environment and Occupational Health.

Liquid storage capacity totaled 40,000 tons, which, together with an automatic and computerized loading facility, has allowed us to manage the growth in the production of liquids.

We have 700 customers throughout Argentina. Of these, 130 are distributors with their own storage facility centers, complementing our warehouses and assistance centers in Buenos Aires, Santa Fé, Mendoza and Tucumán provinces.

The following table sets forth production and sales by major product for both the styrenics and fertilizers divisions for the fiscal years ended December 31, 2004, 2003 and 2002:


	Year ended December 31,
	2004	2003	2002
Production (thousands of tons):
Styrene ⁽¹⁾	111	106	98
Synthetic rubber ⁽²⁾	58	56	51
Urea	188	193	190
UAN	248	184	145
Polystyrene	62	57	61
Bops	12	11	6
Sales (in millions of pesos):
Styrene ⁽¹⁾	202	124	100
Synthetic rubber ⁽²⁾	195	161	138
Fertilizers	477	304	259
Polystyrene and Bops ⁽³⁾	257	180	170
Other products and services	12	23	26

Total	1,143	792	693

Export Sales (in millions of pesos)	270	260	223

(1)	Including styrene monomer and by-products.

(2)	Including SBR, NBR and butadiene.

(3)	Net of P$5 million, P$25 million and P$9 million in intercompany eliminations for 2004, 2003 and 2002, respectively.

Peroquímica Cuyo (Cuyo)

Cuyo is primarily involved in the production and marketing of polypropylene. Admire Trading Company and we are Cuyo’s main shareholders, with a 50.5% and a 40% interest, respectively. Cuyo’s industrial plant, located at Luján de Cuyo, Province of Mendoza, has a production capacity of approximately 100,000 tons per year. The quality and specialization of its products have enabled Cuyo to enter international markets and export to several countries, especially to Mercosur member countries and Chile.

Approximately 87% of the propylene feedstock required for Cuyo’s operations is supplied by Repsol-YPF from its Luján de Cuyo refinery under a long-term contract set to expire in 2014.

Cuyo is a licensee of the Novolen Technology Holding company, a member of the ABB Lumus Group, engaged in the production and marketing of polypropylene. In addition, Cuyo maintains transfer, assistance and technology upgrade agreements, allowing it to be a leading company in product applications and to serve the market with world-class processes and products.

The following table sets forth Cuyo’s production and sales for the fiscal years ended December 31, 2004, 2003 and 2002.

Brazilian Operations

Our petrochemical operations in Brazil are conducted through Innova, our wholly owned subsidiary. Innova has the first integrated complex in Latin America for the production of ethylbenzene, styrene and polystyrene in one site. It is located at Triunfo Petrochemical Pole, Rio Grande do Sul, in the south of Brazil. The styrene plant has a production capacity of 250,000 tons per year and the polystyrene plant has a production capacity of 120,000 tons per year. Copesul, a Brazilian company, supplies the benzene and ethylene feedstock necessary for the production of styrene pursuant to a long-term contract.

The polystyrene plant uses approximately 113,000 tons of styrene monomer as feedstock to produce two grades of polystyrene (Crystal and High Impact). The remaining styrene is sold mainly in the Brazilian market for the production of synthetic rubber, expanded polystyrene, polyester and acrylic resins.

In 2004, Innova plants produced a company record of 208,000 tons of ethylbenzene and 202,000 tons of styrene under ordinary operating conditions. Increased styrene production (from 179,000 tons in 2003) enabled us to partially satisfy the supply deficit in the regional market and to increase polystyrene production, with volumes reaching a company record of 105,000 tons per year. In November 2004, Innova started to import ethylbencene from our Puerto General San Martín complex, which will enable Innova to use its estyerene plant at full capacity.

As of December 31, 2004, Innova was Brazil’s largest styrene producer and merchant (not including styrene used in the production of polystyrene) and one of Brazil’s largest polystyrene producers and merchants, with an estimated 47% and 30% market share, respectively.

As a key component of its business, Innova implements a customer-oriented strategy directed at developing new products and solutions jointly with customers. One of these customers, Sony, authorized the use of polystyrene compounds manufactured by Innova in its electronic products. Innova is currently performing final tests of high resistance products together with customers from the household appliances and packaging industries.

We, through Innova’s operations in Brazil, enjoy a tax benefit, pursuant to an incentive program granted by the Rio Grande do Sul State, Brazil, for companies located in that state. The benefit consists of a 60% reduction of the interstate goods transport tax, or ICMS, until December 31, 2007. As of the fiscal year ended December 31, 2004, Innova started to pay ICMS and thereby began to accrue the related tax benefit. During 2004, we recognized a P$27 million gain from this benefit.

The following table sets forth Innova’s production and sales of styrene and polystyrene for the fiscal years ended December 31, 2004, 2003 and 2002.


	2004	2003	2002
Production (in thousands of tons):
Styrene	202	175	179
Polystyrene	105	86	96
Sales (in millions of pesos):
Styrene	339	216	234
Polystyrene	394	255	298
Other	40	31	29

Total sales	773	502	561

Competition

The petrochemical markets in which we compete are highly cyclical, and our results in these businesses are heavily influenced by world market conditions. We are the only producer of styrene monomer, polystyrene and elastomers in Argentina, but compete with other foreign producers, especially those in Brazil. In the fertilizers market, we compete with Profertil S.A., a local urea and ammonia producer with a production capacity of one million tons per year and other players who import and mix fertilizers such as Cargill, Nidera and Yara. Profertil is owned by Repsol-YPF and Agrium S.A. In the polypropylene business, Petroken S.A is Cuyo’s main competitor with a production capacity of 180,000 tons per year.

In Brazil, we mainly compete with Dow Chemical and BASF, which have a polystyrene production capacity of 190,000 tons per year each and a styrene production capacity of 160,000 and 120,000 tons a year, respectively. In addition, Videolar, a Brazilian producer of polystirene, operates a 120,000-ton capacity plant in Manaos.

ELECTRICITY

In the electricity business, we are involved in all three industry segments: generation, transmission and distribution. Thus, we are positioned as a major player in the Argentine electricity market.

We believe that electricity generation allows us to accelerate the monetization of our significant gas reserves. Electricity transmission and distribution provides us with new growth opportunities, adding value through the sale of power and energy services to end users, as well as, through the development of cutting edge technology.

We conduct electricity generation activities through Genelba in the Province of Buenos Aires and the Pichi Picún Leufú Hydroelectric Complex, or HPPL, in the Comahue region, on the Limay River, Province of Neuquén. In addition, we have a 9.19% interest in Hidroneuquén S.A., a company controlling 59% of Hidroeléctrica Piedra del Aguila S.A., a hydroelectric complex located on the Limay River, in the Comahue region at the dividing line between the Provinces of Neuquén and Río Negro. We are engaged in the transmission business through our interests in Transener (through Citelec), Enecor S.A. and Yacylec S.A, and in the electricity distribution business through our interest in Edesur (through Distrilec).

The changes resulting from the enactment of the Public Emergency Law in Argentina adversely impacted the financial equation of the electricity business. In particular, the devaluation of the peso and the subsequent inflation, within a context of fixed revenues from utilities companies as a consequence of the pesification of rates, affected the financial position and results of operations of the electricity utility companies and extremely hindered their ability to comply with their financial obligations.

The Argentine Electricity Market

In Argentina, in the early 1990s, within the state-reform general framework, the Argentine government carried out a deep restructuring of the electricity sector transforming it into a more decentralized model with greater private sector participation. Up to then, the electricity system was characterized by the inability to meet the requirements of short- and long-term demand and a low service quality standard, all within a framework of a limited financing capacity on the part of the state to make necessary investments. Over the last ten years, electricity demand in Argentina has strongly increased at an average rate of 4.8%, exceeding the growth in gross domestic product for the same period. In 2004, electricity demand grew approximately 6.7% to 82,967 GWH from 77,738 GWH in 2003. Total electricity generation including exports increased 8.5%. As of December 2004, installed generation capacity reached 22,500 MW, representing a growth of approximately 70% from the time of the privatization of electricity services.

Within this context, there has been growth in the installed capacity of non-nuclear thermal power plants and hydroelectric plants. As of December 31, 2004, thermal and hydroelectric power accounted for 54.1% and 35.9%, respectively, of total supply. In the case of non-nuclear thermal units, the new plants have substantially increased their operating efficiency by incorporating cutting-edge technology, such as combined cycles, which decreased the average unavailability of thermal units from 50% to approximately 20%. Serving as an integrating link, the system’s transportation capacity increased by 20% between 1994 and 2004. These improvements in the installed capacity enabled plants to meet the growth in demand in Argentina.

As a consequence of the Public Emergency Law, the Argentine government implemented the pesification of US dollar-denominated prices in the wholesale electricity market and set a price cap for the energy sold in the spot market. This regulatory change caused a deviation from the marginal cost system, which had been implemented in 1992. As a result of the distorted effects on the profitability of the electricity sector caused by the regulatory changes immediately following the enactment of the Public Emergency Law in Argentina, infrastructure investments in the electricity sector declined significantly. In addition, there was a halt in the growth in electricity generation and transport, breaking the growth trend that existed up until 2001. This decline coupled with a growing demand led to an energy crisis.

During 2004, the government took successive measures to restabilize the electricity business. Seasonal tariff adjustments were reinstated for the February-April and August-October 2004 periods, recognizing the greater

costs resulting from the recovery of natural gas prices. In order to increase the available supply of electric power generation in Argentina and in addition adjust the Stabilization Fund deficit, the Secretary of Energy created a fund called FONINVEMEM. The Secretary of Energy invited wholesale electricity market’s creditors to participate in investments in electric power generation, in order to expand thermal generation capacity that is expected to be available towards the end of 2007. We participate with 65% our credit balances recorded in the 2004-2006 period resulting from the spread between the sale price of the energy and the variable cost. Our estimated total contribution for the entire period is expected to equal US$35 million and account for approximately 8% of the fund’s capital. The final amount will depend on water conditions, the dispatch of our generation units determined by Compañia Administradora del Mercado Eléctrico S.A., or CAMMESA, and the resulting prices of energy. See “—Regulation of Our Businesses—Argentine Regulatory Framework— Electricity.”

Electricity Generation

Genelba and HPPL

Our Genelba Thermal Power Plant is a 660MW combined cycle gas-fired generating unit located at the central node in the Argentine electricity network, at Marcos Paz, about 50 km from the city of Buenos Aires. As part of our strategy to increase vertical integration, Genelba allows us to use approximately 2.9 million cubic meters per day of our own gas reserves.

Genelba, which commenced commercial operations in February 1999, has two gas-fired turbines that receive gas through an 8 km duct connected to the transportation system operated by TGS. The electricity produced at Genelba is distributed via the national grid through a connection to the Ezeiza transformer station (owned by Transener) and is located only 1 km away from Genelba.

The allocation of electricity dispatch to the wholesale electricity market, whether the electricity is produced for firm contracts or for the spot market, is subject to market rules based on the lowest variable cost of electricity generation. See “—Regulation of Our Businesses—Argentine Regulatory Framework—Electricity.” Since Genelba uses combined cycle technology for a natural gas-fired power plant, our short-run variable cost is expected to be lower than the cost of other thermoelectric power plants, granting significant competitive advantages for Genelba. Therefore, CAMMESA is expected to dispatch Genelba’s generating capacity before that of most other thermoelectric plants, and Genelba is estimated to operate at an approximately 89% capacity on a month-to-month basis.

The development and implementation of the Primary Frequency Response system, or PFR System, operation mode along with the full combined cycle represents a milestone in Genelba operation. Plant engineers designed the associated system, and Genelba was the first of its type worldwide to provide this service to the interconnected system. In 2003, the U.S. Patent Office granted us patent rights on this system, and currently steps are being taken to obtain patents in Europe and Argentina.

In May 2004, Genelba was authorized by CAMMESA to start commercial operations of the PFR System under “joint control” modality. As a result of this project, the power plant obtains significant economic benefits.

In 2004, the power plant entered into an agreement with Termorio S.A, an independent producer of electricity in Brazil, whereby the power plant will provide management and technical assistance services in connection with the operation and maintenance of the Termorio combined cycle power plant.

During 2004, Genelba reached historical monthly and daily generation records having generated 480 Gwh of electricity in July and 16,445 Mwh on July 16, 2004.

We were awarded a 30-year concession beginning in August 1999 for hydroelectric power generation at HPPL. Our total investment in the construction of the complex was P$291 million. The complex has three generating units with an installed capacity of 285MW. Units 1 and 2 began commercial operations during the third quarter of 1999, and Unit 3 started commercial operations in December 1999.

Pursuant to our concession contract and applicable law, since August 2003, we have paid 1% in hydroelectric royalties, which will be increased by 1% annually until reaching a 12% maximum tax rate, on the amount resulting from applying to the energy sold the tariff corresponding to block sales. In addition, we pay the Argentine government a monthly fee for the use of the water source amounting to 0.5% of the amount used in the calculation of these hydroelectric royalties.

In order to secure completion of the works within the term of the concession and to ensure certain minimum profitability levels needed to make the investment viable, the Secretary of Energy granted us P$25 million from a government fund. For purposes of determining whether this amount should be reimbursed, a price support system was created. The price support system guarantees our project by providing a minimum return on investment. Given HPPL’s energy sales prices for the period ended December 2004 and taking into consideration the guarantees provided by the price support system, we recognized P$20 million in income from this fund as of December 31, 2004 and P$15 million as of December 31, 2003.

Genelba and HPPL, together, account for approximately 6.7% of the power used by, and approximately 6.4% of the power generated for, the Argentine electricity system. The joint operation of the generating units minimizes income volatility, capitalizing on the natural barriers existing among the different energy resources used for power generation.

The following chart details energy generation and sales figures for Genelba and HPPL for the fiscal years ended December 31, 2004, 2003 and 2002.


	For the year ended December 31,
	2004	2003	2002
Generation (Gwh)	5,689	5,400	5,278
Sales (Gwh):
Contracted sales	1,437	1,588	1,569
Spot market	4,719	4,450	4,402
Total sales	6,156	6,038	5,971
Sales (in millions of pesos)	280	235	196

Piedra del Aguila

We, through our 9.19% interest in Hidroneuquén S.A., have an indirect 5.4% interest in Hidroeléctrica Piedra del Aguila S.A., or HPDA.

The Piedra del Aguila hydroelectric complex has 1,400 MW of installed capacity and four vertical axis turbosets. During 2004, HPDA sold 5,758 GWh in the wholesale electricity market, 5,523 GWh of which were supplied by its own generation (close to its historical average) and 235 GWh were purchased in the spot market.

On June 30, 2002, Piedra del Aguila announced the suspension of principal and interest payments on its financial debt. During 2004, pursuant to an exchange offer, HPDA restructured its senior debt. Approximately US$102 million of its subordinated debt owed to Total Finance S.A. is still in the process of being restructured.

Electricity Transmission: Transener, Yacylec and Enecor

Transener

We currently own an indirect participation of 32.5% in Transener. Transener is the leading power transmission company in Argentina. We are committed to divesting our aggregate equity interest in Transener as required in connection with the Argentine Antitrust Commission’s resolution approving the purchase of our majority stock by Petrobras. This divestiture would be subject to supervision by the Argentine regulatory entity for electricity, Ente Nacional Regulador de la Electricidad, or ENRE, and must be approved by the Argentine Secretary of Energy. No time limits had been set to effect this divestiture. On May 26, 2005, we received a notice addressed to Petrobras, with a copy of Resolution 757 of the Argentine Secretary of Energy attached thereto. Under this resolution, March 31, 2006 is fixed as the deadline for Petrobras to divest our equity interest in Transener. The resolution also requires that a divestment plan be submitted within 15 days after receipt of notice. On June 17, 2005, the Secretary of Energy suspended Resolution 757.

Transener is controlled by Citelec, who owns 65% of the capital of Transener. Citelec, in turn, is owned on a 50/50 basis by Dolphin Fund Management, or Dolphin, and Petrobras Energía. On July 28, 2004, the Argentine Antitrust Commission authorized Petrobras Energía to exercise a right of first refusal on 17,406 shares of Citelec’s common stock, representing 0.007% of Citelec’s capital stock, thereby giving Petrobras Energía a 50% equity interest in Citelec. Petrobras Energía exercised this option within the framework of the purchase by Dolphin of the entire equity interest that National Grid Finance B.V. had in Citelec.

Under a 95-year concession, which is due to expire in 2088, Transener operates approximately 7,500 km of extra high and high voltage power lines (most of them 500 Kv lines) and 32 transformer stations. This network is the core of the power transmission system in Argentina.

Transener was awarded an exclusive license for the rest of the term of the original concession to construct, maintain and operate the fourth line of the Comahue-Buenos Aires electricity transmission system, which began operations late in 1999 and consists of 1,292 km of 500 Kv electricity lines.

In July 1997, Transener was awarded the exclusive 95-year concession to operate Transba, which expires in 2091. Transba operates approximately 5,991 km of electricity transmission lines (most of them 132 KV lines) and 81 transformer stations.

Transener operates approximately 90% of the Argentine extra high voltage power transmission system. Transener and Transba jointly operate approximately 75% of the Argentine high-voltage power transmission system.

We have agreed with Dolphin Fund Management to jointly manage Transener and Transba and to share equally in the management fees received under a management agreement with Transener. In addition, shareholders have a right of first refusal in any transfer of Transener’s shares. Under the concession agreement with the government, certain shares of Transener are pledged as guarantee for the execution of obligations under such agreement.

Transener generates additional income related from the supervision of the construction and operation of certain assets connected with the networks and other power transmission services provided to third parties. In this respect, efforts are being made by Transener to expand its activities abroad, supported by its quality engineering and experienced technical personnel.

In order to meet the commitments arising from two contracts with foreign joint ventures in Brazil, Transener organized Transener Internacional Limitada, with offices in Brasilia. During 2004, Transener Internacional Limitada performed operation and maintenance activities in Brazil, reaching a high operating efficiency level. In Brazil, Transener executed a five-year-term agreement with the ETIM Consortium (Expansión Itumbiara-Marimbondo Ltda.) to operate and maintain the 500 Kv Itumbiara-Marimbondo high voltage line and two transformer stations located in the Goias and Minas Gerais states.

In addition, in Paraguay, Transener completed the first works relating to the 500 Kv line in the transmission system, which was financed by the International Development Bank and awarded to the company on the basis of a public international bidding. The project encompasses 15 km of lines, a 500 Kv yard and a 200 Kv extension of the transformer station. On August 3, 2004, first works were provisionally accepted, with no significant works pending completion.

The following chart details the evolution of Transener’s failure rate for the fiscal years ended December 31, 2004, 2003 and 2002. The failure rate represents the service quality provided by the company to users. The maximum admissible failure rate under the concession contract is 2.50 failures per year per every 100 km.

Maintenance of this low failure rate resulted from operating improvements, acquisition of special equipment and agreements with public safety agencies.

The provisions of the Public Emergency Law have severely affected the economic and financial balance of Transener’s business. In April 2002, as a result of the changes caused by the Public Emergency Law, Transener publicly announced the suspension of principal and interest payments on all its financial debt. On February 22, 2005, Transener proposed an exchange offer to its creditors, which in April 2005 was accepted by 98.8% of them. Pursuant to a restructuring agreement entered into on May 19, 2005, Transener has 45 business days to comply with the terms of the exchange offer, otherwise the restructuring agreement may be terminated at creditors’ option. This exchange offer restructured Transener’s indebtedness, which as of March 31, 2005 amounted to P$1,353 million in principal. In the offer, Transener will issue to its creditors an aggregate of: (1) US$80 million in par notes due 2016, with interest accruing at an increasing rate from 3% to 7% per annum, (2) US$199.8 million in discount notes due 2015 with interest accruing at an increasing rate from 9% to 10% per annum and (3) 84,475,000 shares (or cash in lieu of shares). (As a result of the issuance of the shares described in (3) above, Citelec’s interest in Transener will be reduced from 65% to 52.652% and our indirect interest will be reduced from 32.5% to 26.326%.) In addition, Transener will redeem indebtedness with a nominal value of US$110 million, by paying US$550 in cash for every US$1,000 of outstanding debt. The issuance of the new debt and the new shares has been approved by the CNV.

In addition to the renegotiation process described above, on February 2, 2005, Transener and Transba entered into letters of understanding with UNIREN, which contain principal terms (including a new tariff scheme) and conditions for a comprehensive renegotiation of both companies’ concession contracts. These renegotiated agreements are expected to become effective before May 2006. In the meantime, temporary tariff increases of 31% to Transener and 25% to Transba are pending congressional approval and ratification and, if approved, will be in force with retroactive effect as of June 1, 2005.

Yacylec

Yacylec S.A., which we refer to as Yacylec, is an independent transmission company formed by a consortium of construction and engineering companies of Argentina and Europe, including Empresa Nacional de Electricidad S.A. of Spain, or ENDESA, Impregilo International Infrastructures N.V. of The Netherlands and Dumez S.A. of France, which currently hold 22.2%, 18.67% and 1.78% of Yacylec, respectively. We have a 22.22% direct interest in this consortium. The consortium operates and maintains the 500 Kv and 280 km-long electric power transmission line from the Yacyretá hydroelectric complex to the Argentine national grid under a 95-year concession that expires in 2091. Under the concession agreement, ENRE’s approval is necessary to transfer or sell shares representing up to 49% of the capital stock of Yacylec. The transfer of a higher percentage requires a public tender.

Under the shareholders’ agreement, shareholders have a right of first refusal in any transfer of shares.

Enecor

Enecor is an independent electricity transmission company. We own 69.99% of Enecor and Impregilo International Infrastructures N.V. of The Netherlands owns the remaining interest in the company. Enecor has a 95-year concession, expiring in 2088, to construct, operate and maintain approximately 22 km of electricity lines and a 500 Kv/132 Kv transformer station in the Province of Corrientes. Enecor has entered into a maintenance agreement with Transener until 2008. Under the concession contract, certain shares of Enecor are pledged in favor of the Province of Corrientes.

As collateral for the amounts owed by the Dirección Provincial de Energía de Corrientes, or DPEC, to Enecor, the Province of Corrientes has assigned to Enecor (1) all royalty credits it has against the Comisión Técnica Mixta de Salto Grande for the sales of electricity generated by the Salto Grande Hydroelectric Power Complex and (2) the funds that belong to the province under the Fondo de Desarrollo Eléctrico del Interior, or FEDEI. Enecor has been collecting from these guarantees because the DPEC has failed to pay tariffs to Enecor since September 1999. However, as a result of lower hydropower generation and the issuance of Resolution 406/03 of the Secretary of Energy, which affected all generators by establishing a priority for canceling existing debts subject to the Stabilization Fund having sufficient funds (coming from either the adjustment of the seasonal price or the federal government), Enecor’s ability to collect fees has been affected and, therefore, Enecor has been accumulating receivables from DPEC since November 2003. Enecor is taking appropriate administrative and legal actions with respect to these matters, but it’s not certain that these actions will result in a favorable outcome to Enecor.

Electricity Distribution: Edesur

In 1992, Edesur was awarded an exclusive license by the Argentine government to distribute electricity in the southern area of the federal capital and 12 districts of the Province of Buenos Aires, serving a residential population of approximately 6 million inhabitants and a client portfolio of approximately 2.1 million. The license will expire in 2087 and is extendable for an additional 10-year period. Edesur was created as part of the privatization of the Buenos Aires electricity distribution network. We own 48.5% of Distrilec which, in turn, owns 56.35% of Edesur.

We and the Enersis/Chilectra group, owned by ENDESA, are the only shareholders of Distrilec and, pursuant to a shareholders’ agreement, we each have the right to elect an equal number of directors.

The unanimous approval of the board of directors is necessary for the grant of any lien on Edesur’s shares or any merger, reorganization, dissolution or spin-off of Distrilec. Shareholders also have a right of first refusal on any transfer of shares and preferential rights on any new issue of shares.

In compliance with the terms and conditions of the privatization, Edesur entered into an operating agreement with Chilectra S.A. for the provision of technical advisory services. This agreement is effective through August 2007, and we are reimbursed for costs incurred by us in connection with the management agreement

Under the terms of the agreement, Chilectra was entitled to receive management fees of US$1 million plus 10% of operating income per year. In November 2004, Edesur and Chilectra renegotiated the terms of the agreement and, as of 2005, Chilectra will receive an annual fee with a fixed component equal to US$600,000, plus a variable component, based on the kind of service rendered.

Under the concession contract, Edesur is subject to a fixed cap on what it may charge each customer for the distribution of electricity to that customer. However, Edesur may pass through to the customer the cost of the electricity purchased, limited only by the pre-adjusted seasonal wholesale electricity market price. Customers are divided into tariff categories based on the type of consumption required. Under the current regulations, large users may purchase energy and power directly from the wholesale electricity market. Edesur charges these large users a wheeling fee for the provision of distribution services. Residential consumers purchase power only from distributors. These customers are generally daylight and weather sensitive and their consumption of electricity is different in summer and winter. Peak demand occurs in July, when there is the least amount of sunlight, and in January, which is usually the hottest summer month in Argentina.

The enactment of the Public Emergency Law significantly affected Edesur’s economic and financial balance and its ability to comply with its contractual commitments. For this reason, Edesur’s efforts were focused on refinancing financial liabilities, reducing risks and optimizing working capital. Based on these guidelines, Edesur managed to refinance all of its financial debt, achieving a better maturity profile and lower average costs.

In addition, Edesur has regained access to the local financial market, becoming one of the first Argentine companies to place, after the crisis, an issuance in the domestic market of peso-denominated notes with favorable terms and rates. The proceeds of this issuance were used to repay financial debt with financial institutions, achieving a reduction to its exposure to devaluation.

On June 16, 2004, Edesur entered into a memorandum of understanding with UNIREN in connection with the renegotiation of Edesur’s concession contract. The memorandum of understanding establishes terms and conditions which will be the basis for the comprehensive agreement for renegotiation of the concession contract between the federal executive branch and Edesur. The memorandum of understanding provides for the implementation of a transitional tariff scheme as from November 1, 2005, that increases the utility’s average tariff by up to 15% and requires prior regulatory approval for the payment of dividends during that transitionary period. In addition, the memorandum provides for a comprehensive tariff revision process to take place between June 16, 2004 and September 30, 2006 in order to establish a new tariff scheme with a 5-year term that would commence on November 1, 2006.

The chart below sets forth Edesur’s annual power sales for each type of customer for the fiscal years ended December 31, 2004, 2003 and 2002.


	Annual sales in Gwh
	2004	2003	2002
Type of customer:
Residential	4,796	4,304	4,597
General	2,798	2,785	2,439
Large users	5,729	5,569	5,123

Total	13,323	12,658	12,159

Since its privatization, Edesur has made investments of approximately P$3,000 million, of which P$150 million were invested in 2004. As a result of these investments, Edesur was able to provide for more than a 35% increase in demand – reaching its highest levels of output while maintaining a high quality of service.

In addition, investments enabled Edesur to reduce total energy loss through the system. This loss had accounted for 26% of total electricity received in 1992 but currently accounts only for 11.75%. Since 2004, an underground loss control campaign has been implemented where new technologies, such as radio detectors and georadars, are used to identify irregularities in underground networks that are likely to have unidentifiable connections.

By the end of 2004, Edesur’s clients numbered 2,138,753, accounting for a 1.02% net increase compared to 2003. This indicator maintains the upward trend resumed in 2003 after two years of decline. Edesur has added more than 200,000 customers since its privatization. Some of these customers were added as a result of new electricity lines and others, who had been receiving electricity outside the system, are now fully connected and accurately billed. Edesur has also substantially reduced overdue payments from customers and is implementing more efficient billing and collection practices.

Competition

We compete with other generators in the wholesale electricity market, both in the spot market and for contracts (mainly short-term contracts). The price received by us for energy generation is determined by the wholesale electricity market rules and by rules and regulations enacted following the Argentine crisis and the adoption of the Public Emergency Law. See “—Regulation of Our Businesses—Argentine Regulatory Framework—Electricity.”

DIVESTMENTS OF NON-CORE ASSETS

The sale of 58.6% of our capital stock to Petrobras represented a major milestone in the development of our strategy to focus on our core businesses.

The agreements executed in connection with the transfer of our control granted Petrobras an option whereby, if within 30 days after closing of the stock purchase transaction we did not consummate the sale of assets related to the farming, forestry and mining businesses, Petrobras had the right to compel our former controlling shareholders (the Perez Companc Family and Fundación Perez Companc) to acquire such assets for US$190 million.

In line with the provisions of the agreements mentioned above, during 2002 we sold the asset portfolio associated with our mining, farming and forestry businesses.

In addition, in April 2002, pursuant to an asset swap, we transferred our 50% interest in Pecom Agra S.A., a company involved in the agricultural business. We, in turn, received (1) a 0.75% interest in the Puesto Hernandez oil field, (2) a 7.5% interest in Citelec and (3) a 9.19% interest in Hidroneuquen S.A.

These divestitures helped to enhance our asset portfolio and moved us forward with our strategy to focus on energy operations and to become an integrated energy company.

INSURANCE

We carry insurance covering “all operating risk” damages, with assets valued at current market replacement cost. The coverage limit for each and every loss in our oil and gas exploration and production businesses is the total value at risk for each location:

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US$420 million for each and every loss in our Argentine styrenics petrochemical business;

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US$350 million for each and every loss in our Brazilian styrenics petrochemical business;

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US$190 million for each and every loss in our fertilizers business;

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US$130 million for each and every loss in our San Lorenzo refining business;

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US$181 million for each and every loss in our Bahía Blanca’s refining business;

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US$180 million with respect to our thermoelectric generation businesses; and

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US$228 million for each and every loss in the hydroelectric generation power plant.

The rest of the assets have been insured in full value for each and every loss.

In addition, we carry insurance of up to:

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US$100 million for ocean marine and non-ocean marine third-party liability;

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US$7.5 million for well control costs in Argentine fields;

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US$40 million for wells in Bolivia;

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US$40 million for wells in Ecuador;

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US$25 million for fields in Venezuela; and

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US$10.5 million for cargo transportation by sea or river.

We also carry insurance for workmen’s compensation and automobile liabilities.

Our coverage includes the following different types of deductibles:

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US$10,000,000 for combined claims for property damage and business interruption for all our businesses, except for the oil and gas exploration and production businesses;

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US$10,000,000 for claims for each property of our oil and gas exploration and production businesses;

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US$5,000,000 for in well control costs;

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US$5,000,000 in non-ocean marine third-party liability; and

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US$5,000,000 in ocean-marine third-party liability.

Our insurance decisions are based on our requirements and available commercial and market opportunities.

PATENTS AND TRADEMARKS

Minor portions of our commercial activities are conducted under licenses granted by third parties, including Petrobras. Royalties related to sales associated with such commercial activities are paid under the relevant licenses. We use the name “Petrobras” with the permission of Petrobras.

QUALITY, SAFETY, ENVIRONMENT AND HEALTH

We are a socially and environmentally responsible corporation in continued search for excellence in management. This commitment lies in the core of our corporate identity and is part of our corporate mission. We believe that caring for the environment in which we operate and for the safety and health of individuals is an essential condition for the activities we develop. Along these lines, our strategic and business plans include goals involving excellence in management and performance in Quality, Safety, Environment and Health (QSEH).

Within the scope of this philosophy, in April 2004, we launched a new QSEH policy. The quality policy provides a more comprehensive, executable and applicable approach. The Safety, Environment and Health (SEH) Policy incorporates state-of-the-art concepts, including: coefficiency, life cycle, continuous improvement and leadership. This is implemented through the use of 15 guidelines for practical and customary action, each aimed at behavior-based responsible development. The foregoing policies and actions have been enhanced through our relationship with Petrobras.

While implementing these changes, we complied with international audits and certifications with respect to environmental management, quality, safety and occupational health. We have 23 assets certified, including ISO 14001, ISO 9001 or OHSAS 18001/IRAM 3800, which are maintained through regular third-party audits.

Excellence in Management

In order to achieve high standards of excellence in management, we implemented a cycle of evaluations aimed at measuring the global quality of corporate performance. This cycle was started at key units – Genelba, Innova, E&P-Venezuela and E&P-Argentina – and involved the participation of over 1,000 employees in evaluator training courses, sensitivity lectures, training courses and management report writing courses. Currently, each of these units is developing its respective Plan for Management Improvement.

New policy and guidelines, new management tools – Process Safety Program

To guarantee the effective implementation of the new SEH policy and guidelines, we have developed a set of corporate management tools in the Process Safety Program (PSP). This program was launched in April 2004 with a diagnosis of management that encompassed 23 production units and centralized functions and included interviews with over 300 members of management, our employees and contractors.

During a second stage, PSP sought to review business production unit action plans, production and centralized functions through the progress and enhancement of several projects.

Safety

To minimize the occurrence of operation-related casualties and contingencies, we developed a series of preventive measures, including technical audits, behavioral audits with their respective deviation analyses, corrective actions to address the deviations detected in both technical and behavioral audits, training and implementation of a learning process based on the analysis of individual accidents and accidents occurred within the entire Petrobras system.

Road safety management was identified as an area with great potential for improvement. To minimize and control the risks involved in this operation, we designed and implemented a new plan, the 2004 Road Safety Plan, which is one of the main prevention tools in terms of resource mobilization.

Quick and correct decisions-making is crucial to minimize eventual damages and rapidly restore previous conditions in the event of an accident. It is essential to have reliable, qualified and updated information available for this purpose. Geographical data platforms are among the newest technological tools used internationally to obtain this type of data.

We have developed a support system for contingencies named Geodatabase, which includes all relevant facilities and the information available at each operating unit. Geodatabase provides detailed geographical information and also interrelates spatial references with a powerful database. In this manner, each spatial reference is accompanied by additional information: satellite images, plans, digital photographs, process sketches and other documents. In addition, the database is supplemented with information on resources, either human or material, available in over two thousand population centers.

Another technological tool used by us to solve contingencies is INFOPAE. INFOPAE was created to specifically respond to each scenario where an accident occurs, by providing key information for the initial decision-making process and the guidance of response groups prior to (through emergency simulation), during (on-time assistance to response personnel) and after (during the preparation of reports and the evaluation of actions taken) the accident.

In 2004, we signed a Mutual Assistance Agreement with Petrobras to help each other in coping with possible spill situations in our road and maritime operations.

Environment

We implemented several actions to minimize the environmental impact of operations and reduce associated risks. Among them, we implemented a maintenance and replacement pipeline program, waste treatment plans and projects for the improved performance of effluent treatment plants.

Since July 2003, we have put into operation a project called “Inventory System of Atmospheric Emissions,” which was initiated in September 2002 by Petrobras. The main goal of this project is the creation of a tool for the management of atmospheric emissions. The work consists of the creation of a collection, utilization and communication data system that permits the systematic environmental evaluation of our emissions, the identification of critical issues and the technological analysis of improvements that can be put into place to reduce these emissions.

Through the application of this system, we have obtained consolidated numbers with respect to our Green House Gases Inventory (GHG) and other regulated pollutants for the year 2004.

Environmental audit

Following the change of our controlling shareholder and pursuant to our goal of continuously improving our environmental, health and safety management, in 2003, we hired an international consulting firm to conduct an environmental and safety audit of all our operations.

The final audit report issued by this consulting firm confirmed the high environmental standards of our operations and 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. Consequently, we have implemented a plan aimed to improve, among other things, our prevention systems and production facilities at a cost of approximately US$23 million. In addition, we will implement several corrective and remediation actions, for which a P$45 million loss provisions was recorded in fiscal year ended December 31, 2003. During the year 2004, a general remediation plan was implemented scoping several units of the company, and 44 environmental projects were initiated at a cost of approximately US$7 million.

Pursuant to the objectives of the SHE policy launched in 2004, an environmental study was produced for the fiscal year ended December 31, 2004, as a supplement to the audit performed in 2003. Under the standards of the new policy, the study enabled us to identify the need for additional remediation measures, in relation to which we recorded loss provisions amounting to P$33 million in 2004.

Health

We have implemented a Health Promotion and Protection Program (HPPP), which prioritizes the quality of life of our employees. The principal components of the program are health promotion, stress management, physical activity, healthy diet and accident prevention actions. Program activities include workshops on stress, sedentary life-style, healthy diet and a smoking reduction plan. In order to encourage physical activity, we opened health promotion centers – gyms and aerobics tracks – in several plants and executed agreements with fifteen private gyms in Buenos Aires.

REGULATION OF OUR BUSINESSES

ARGENTINE REGULATORY FRAMEWORK

Petroleum

The Argentine oil and gas industry operates under Law No. 17,319, which we refer to as the Hydrocarbons Law, enacted in 1967, and the Natural Gas Act No. 24,076, enacted in 1992. The Hydrocarbons Law allows the federal executive branch of the Argentine government to establish a national policy for the development of Argentina’s hydrocarbon reserves, with the principal purpose of satisfying domestic demand.

A new regulatory framework was required in order to respond to several changes in the Argentine oil and gas industry after the privatization of Yacimientos Petrolíferos Fiscales Sociedad del Estado, or YPF, and Gas del Estado, or GdE. Pursuant to Law No. 24,145, which is referred to as the Privatization Law, the Argentine government transferred to the provinces ownership of oil and gas reserves located within their territories. The transfers will be implemented once (1) the Hydrocarbons Law is modified for the purpose stated in Law No. 24,145 and (2) the rights of holders of existing exploration permits and production concessions, as applicable, have expired. In connection with this legislation, certain issues remain unresolved with respect to the relevant regulatory authority of the federal executive branch and the provinces, regarding oil and gas exploration, production, and transportation activities.

Exploration and Production

The Hydrocarbons Law sets forth the basic legal framework for the current regulation of oil and gas exploration and production in Argentina. The Hydrocarbons Law permits surface reconnaissance of territory not covered by exploration permits or production concessions upon authorization of the Secretary of Energy and with permission of the property owner. Information gained as a result of surface reconnaissance must be provided to the Secretary of Energy, who is prohibited from disclosing such information for a period of two years, without the permission of the party that conducted the reconnaissance, except in connection with the grant of exploration permits or production concessions.

The Hydrocarbons Law provides for the grant of exploration permits by the federal executive branch following submissions of competitive bids. Permits granted to third parties in connection with the deregulation and demonopolization process were granted in accordance with procedures specified in certain decrees, known as the Oil Deregulation Decrees, issued by the federal executive branch. In 1991, the federal executive branch established a program under the Hydrocarbons Law, known as the Argentina Exploration Plan, pursuant to which exploration permits may be auctioned. The holder of an exploration permit has the exclusive right to perform the operations necessary or appropriate for the exploration of oil and gas within the area specified by the permit. Each exploration permit may cover only unexplored areas up to 10,000 km2 (15,000 km2 offshore), and may have a term of up to 14 years (17 years for offshore exploration).

In the event that the holder of an exploration permit discovers commercially exploitable quantities of oil or gas, the holder may apply for, and is entitled to receive, an exclusive concession for the production and development of such oil and gas. A production concession vests in the holder the exclusive right to produce oil and gas from the area covered by the concession for a term of 25 years (plus, in certain cases, a part of the unexpired portion of the underlying exploration permit), which may be extended for an additional ten-year term by application to the federal executive branch. A production concession also entitles the holder to obtain a transportation concession for the transport of the oil and gas produced.

Holders of exploration permits and production concessions are required to carry out all necessary works to find or extract hydrocarbons, using appropriate techniques, and to make the investments specified in such holders’ permits or concessions. In addition, these holders are required to avoid damage to oil fields and waste of hydrocarbons, to adopt adequate measures to avoid accidents and damage to agricultural activities, the fishing industry, communications networks and the water table, and to comply with all applicable federal, provincial and municipal laws and regulations.

Holders of production concessions are also required to pay a 12% royalty to the government of the province in which production occurs, calculated on the wellhead price (equal to the FOB price less transportation costs and certain other reductions) of crude oil and natural gas produced. The Hydrocarbons Law authorizes the government to reduce royalties up to 5% based on the productivity and location of a well and other special conditions. Any oil and gas produced by the holder of an exploration permit prior to the grant of a production concession is subject to the payment of a 15% royalty.

Resolution No. 435/04 issued by the Secretary of Energy, which updates Resolution No. 155 dated December 23, 1992, (1) imposes additional reporting requirements with respect to royalties, (2) introduces certain changes, which affect provincial empowerment, (3) amends certain parts of the royalty determination system, including applicable deductions and exchange rates and (4) establishes penalties upon default of a reporting duty. This resolution has been applicable to permit and concession holders since June 2004.

Concession holders are required to file sworn statements with the Secretary of Energy and the relevant provincial authorities, informing them of:

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The quantity and the quality of extracted hydrocarbons, including (1) the computable production levels of liquid hydrocarbons and (2) a break down of the crude oil (specifying the type), condensate and total natural gas recovered (with a 0.1% maximum error tolerance);

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The sales to domestic and foreign markets;

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Reference values for transfers made at no cost for purposes of further industrialization;

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Freight costs from location where marketable condition is acquired to location where commercial transfer takes place; and

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Description of sales executed during the month.

In addition to the sworn statement, concession holders shall file receipts evidencing payment of royalties. Upon breach of any reporting duty, provincial authorities are entitled to make their own assessment of royalties.

Resolution No. 435/04 also provides that if a concession holder allots crude oil production for further industrialization processes at its or affiliated plants, the concession holder is required to agree with provincial authorities and the Secretary of Energy, as applicable, to the reference price to be used for purposes of calculating royalties and payments. Upon default by the concession holder, provincial authorities may fix this reference price. The concession holder is eligible for certain deductions including (1) inter-jurisdictional freight costs, which can be deducted from the selling price, as long as transportation is made by means other than pipeline and monthly invoices and any relevant agreements are provided and (2) internal treatment costs (not exceeding 1% of the payment) incurred by authorized permit or concession holders.

Exploration permits and production or transportation concessions are subject to termination in the event of certain breaches or defaults of laws or regulations or upon the bankruptcy of the concessionaire. Upon the expiration or termination of a production concession, all oil and gas wells, operating and maintenance equipment and facilities ancillary thereto automatically revert to the Argentine government, without payment to the concessionaire.

Net Worth Requirements

Resolution No. 193/03 of the Secretary of Energy implements mandatory minimum net worth requirements for companies that wish to acquire or maintain exploration permits, exploration concessions, and hydrocarbon transportation concessions in Argentina.

The Secretary of Energy has historically required companies that wish to obtain these permits or concessions to comply with certain minimum net worth and economic and financial solvency requirements. Along

these lines, the Hydrocarbons Law and subsequent regulations provide for certain economic and financial solvency requirements for carrying out these activities. Prior to the issuance of Resolution No. 193/03, there were no resolutions that established specific required amounts, but rather, the Secretary of Energy determined the amount that would be required to comply with the solvency requirement on a case by case basis. Resolution No. 193/03 sets forth minimum net worth requirements, as well as, alternative economic and financial guarantees that can be complied with to obtain permits or concessions.

This resolution also provides that, in order to be a holder of a permit or concession, the company or group of companies (for example, companies associated through a joint operating or joint venture agreement) shall have a minimum net worth of P$2,000,000 for land-based areas and US$20,000,000 for off-shore areas. This minimum net worth amount must be maintained during the whole term of the permit or concession. The breach of this obligation may result in sanctions, including fines, or even the revocation of a company’s registry with the Secretary of Energy as a petroleum company. To comply with these requirements other local Argentine companies or foreign companies may grant financial support or guarantees of up to 70% of the minimum net worth requirements in favor of the entity requesting a permit or concession.

Transportation

The Hydrocarbons Law grants hydrocarbon producers the right to obtain from the federal executive branch a 35-year transportation concession for the transportation of oil, gas and their by-products through public tenders. Producers granted a transportation concession remain subject to the provisions of the Natural Gas Act, and in order to transport their hydrocarbons do not need to participate in public tenders. The term of a transportation concession may be extended for an additional ten years upon application to the federal executive branch.

Transporters of hydrocarbons must comply with the provisions established by Decree No. 44/91, which implements and regulates the Hydrocarbons Law as it relates to the transportation of hydrocarbons through oil pipelines, gas pipelines, multiple purpose pipelines and/or any other services provided by means of permanent and fixed installations for transportation, loading, dispatching, tapping, compression, conditioning infrastructure and hydrocarbon processing. This decree is applicable currently and primarily to oil pipelines and not to gas pipelines. (Gas pipelines are subject to ENARGAS regulations, see “—Gas—ENARGAS.”)

The transportation concessionaire has the right to transport oil, gas, and petroleum products and to construct and operate oil pipelines and gas pipelines, storage facilities, pumping stations, compressor plants, roads, railways and other facilities and equipment necessary for the efficient operation of an oil, gas and petroleum product pipeline system. While the transportation concessionaire is obligated to transport hydrocarbons on a non-discriminatory basis on behalf of third parties for a fee, this obligation applies only if such producer has surplus capacity available, and after such producer’s own transportation requirements are satisfied.

Depending on whether it is gas or crude oil that is transported, transportation tariffs are subject, respectively, to approval by ENARGAS or the Secretary of Energy. Resolution No. 5/04 of the Secretary of Energy sets forth:

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Maximum amounts for tariffs on hydrocarbon transportation through oil pipelines, and multiple purpose pipelines, as well as the tariffs on storage, use of buoys, and the handling of liquid hydrocarbons; and

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Maximum deduction amounts that may be applied in connection with crude oil transportation by producers that, as of the date of the regulation, transport their production through their own unregulated pipelines, for the purpose of assessing royalties.

Upon expiration of a transportation concession, ownership of the pipelines and related facilities is granted to the Argentine government at no cost.

Refining

Hydrocarbon refining activities by oil producers and other third parties are regulated, ever since the enforcement of National Decree No. 1212/89, by the regulations under the Hydrocarbons Law. Together with several other norms that were dictated by the Secretary of Energy, this legal framework essentially regulates the commercial, environmental and security matters with respect to refineries and gas stations. This law made possible free imports, abolishing oil assignments by the Secretary of Energy, and deregulated the installation of refineries and gas stations. The Secretary of Energy’s regulatory authority has also been delegated to provincial and municipal authorities and, therefore, refining and the sale of refined products must also comply with provincial and municipal technical, health and safety and environmental regulations.

The refining of hydrocarbons is subject to requirements established by the Secretary of Energy, including registration by oil companies. Approval of registration is granted on the basis of financial, technical and other standards. As further described below, liquid fuel retail outlets, points of sale locations for fuel fractioning, the resale to large users and supply contracts between gas stations and oil companies are all also subject to registration requirements set by the Secretary of Energy.

Refiners are authorized to freely commercialize their products in the domestic market as they would otherwise in the international market (except for, diesel and liquified petroleum gas exports, are subject to prior approval by the Secretary of Energy) and to freely install gas stations identified by their own or third-party flags, provided that their own gas stations or those directly operated by oil companies do not exceed 40% of their distribution network.

As from November 2004, norms have been put into effect that have impacted the refinery segment, including:

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Secretary of Energy Resolution No. 1104/04. This resolution created price information modules for oil wholesalers and retailers, obligating refinery and gas station owners to submit monthly sales information. In cases where gas station owners fail to supply the required information, they, as well as, brand owners may face financial penalties.

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Secretary of Energy Resolution No. 1679/04. This resolution restored the Diesel Oil Exportation Operations Registry, which had been created by National Decree No. 645/02. Pursuant to this resolution, producing, trading and refining companies or any other person with intentions of carrying out diesel oil export operations are required to register for prior approval from the Refining and Marketing National Directive, an organization operating under the Undersecretary of Fuels of the Secretary of Energy, and guarantee sufficient product supply for oil suppliers who are commercially connected with exporters. Additionally, oil suppliers are required to apply for approval prior to undertaking export operations, in order to ascertain that the demand of all refineries authorized to operate in the country has been satisfied and/or those refineries have been given the opportunity to acquire the oil which is earmarked for exportation.

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Secretary of Energy Resolution No. 1102/04. This resolution abolished Resolution No. 79/99 of the Secretary of Energy, and created a regulatory framework for new gas stations, other fuel-sale outlets and distribution channels. Application to the Registry is a prerequisite to participation in the liquid fuel market. There are stiff sanctions for the execution of commercial transactions with un-authorized parties and repetitive violations may result in suspension and withdrawal from the registry. The resolution also establishes several requirements for all fuel market participants and makes brand owner companies jointly responsible for breaches by companies operating under their flags.

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Secretary of Energy Resolution No. 1103/04. This resolution establishes an economic sanction structure applicable to owners of facilities that are registered in the Registry of Liquid Fuel Gas Stations, as well as other distributors, resellers, traders of refined products and owners of bulk oil and liquid fuel stores and compressed natural gas stores, who breach certain fuel quality

specifications (regulated under, or in connection with, Resolution No. 54/96 of the former Works and Public Services Minister). Pursuant to Article 17 of National Decree No. 1212/89, brand owner companies are liable for failure to comply with commercialized products specifications, including quality and quantity requirements, in those gas stations belonging to the commercialization chain of a company registered in the Registry of Oil Companies created by Resolution No. 419/98 of the Secretary of Energy.

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National Law No. 26.022. Under this law, because of the economic emergency, many import operations are temporarily exempt from the Fuel Liquids and Gas Natural Tax, as well as, the Diesel Oil Tax on volumes up to 500,000 cubic meters. This law also establishes sanctions applicable to the solid, liquid and gaseous oil sector, that imposes stiff penalties for any breaches related to health, security, environmental, product quality and information provision issues.

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Resolution No. 398/03. The Secretary of Energy, pursuant to this resolution, set forth new maximum standards as to the contents of sulphur and/or benzene and/or total fragrant hydrocarbons. These standards are applicable to (1) regular and special gasolines as from January 1, 2006, (2) gas oil as from January 1, 2008 and (3) fuel oil as from January 1, 2009.

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Resolution No. 824/03. This resolution defines those urban areas that are under the jurisdiction of the Secretary of Energy. The secretary’s jurisdiction classifies the city of Rosario, in the Province of Santa Fe, as a new urban area, which is under the Secretary of Energy’s jurisdiction with respect to the control of certain sulphur contents of gasolines, gas oil and fuel oil.

Market Regulation

Under the Hydrocarbons Law and the Oil Deregulation Decrees, the holders of exploitation concessions have the right to freely dispose of their production either through sales in the domestic market or abroad.

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 keep out of Argentina up to 70% of the foreign currency proceeds they receive from crude oil and gas sales, while being required to repatriate the remaining 30% through Argentine exchange markets. During 2002, as a result of the reestablishment of a system that requires exporters of domestic products to repatriate foreign currency amounts generated by their exports, many controversies arose among producers and the authorities regarding the enforceability of the right to freely dispose of up to 70% of their foreign currency. These controversies were even subject to legal suit, and many federal judges have pronounced on and recognized the prima facie validity of producers’ rights. In December 2002, we filed before a federal court of the Province of Santa Cruz, a temporary injunction against the federal executive branch, requesting the maintenance of the status quo which 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 declared the right to dispose of 70% of foreign currency but had no provisions related to this right during 2002. Therefore, in order to avoid any uncertainty regarding the application of this right during 2002, in February 2003, we filed a civil action of certainty, requesting that the court recognize our right to freely dispose of up to 70% of our foreign proceeds in 2002, based on the effectiveness of Decree No. 1589/89.

The Hydrocarbons Law authorizes the federal executive branch to regulate the Argentine oil and gas markets and prohibits the export of crude oil during any period in which the federal executive branch finds domestic production to be insufficient to satisfy domestic demand. In the event the federal executive branch restricts the export of oil and petroleum products or the free disposal of natural gas, the Oil Deregulation Decrees provide that producers, refiners and exporters shall receive a price, in the case of crude oil and petroleum products, not lower than that of similar imported crude oil and petroleum products and, in the case of natural gas, not less than 35% of the international price per cubic meter of Arabian light oil, at 34 degrees.

On May 23, 2002, the Argentine government issued Decree No. 867/02 declaring an emergency in the supply of hydrocarbons in Argentina through October 1, 2002. This decree authorized the Secretary of Energy to

determine quotas on the minimum volumes of petroleum and liquified petroleum gas produced in Argentina that must be sold on the domestic market. By means of Resolution No. 140/02, the Secretary of Energy established that in June, July, August and September of 2002, only 36% of the oil produced in each preceding month could be exported. In addition, during this emergency period, no producer or exporter of oil was permitted to export a volume of oil higher than the volume it exported during the equivalent months of 2001. The emergency resolution was amended and finally repealed on July 26, 2002.

Argentina is currently suffering an energy crisis, and there is an agreement in principle, subject to the approval of the federal executive branch, for gas producers to sell a minimum specified amount in the local market in exchange for price increases. This proposal may change during the approval process. See “Item 3. Key Information—Risk Factors—Factors Relating to Argentina—Limits on exports of hydrocarbons have and may continue to lower our anticipated US dollar-denominated cash receipts.”

Taxation

Holders of exploration permits and production concessions are subject to federal, provincial, and municipal taxes and regular customs duties on imports. The Hydrocarbons Law grants such holders a legal guarantee against new taxes and certain tax increases at the provincial and municipal levels. Permit holders and concessionaires must pay an annual surface tax based on the area held.

On January 6, 2002, the Argentine Congress enacted the Public Emergency Law. Pursuant to the Public Emergency Law, all foreign-denominated bank deposits were converted into peso-denominated bank deposits at a rate of P$1.4 per US dollar, and all US dollar-denominated debts with Argentine financial institutions were converted into peso-denominated debts at a rate of one-to-one. Under the Public Emergency Law, the Argentine Congress delegated the right to issue secured government bonds to the federal executive branch in order to compensate it for the effect of pesification and to ameliorate the situation of financial institutions.

The Public Emergency Law established a five-year export tax on hydrocarbon exports as security for these bonds and empowered the federal executive branch to establish the applicable tax rate. By virtue of Decree No. 310/02, the federal executive branch determined that the applicable tax rate would be 20% on crude oil and 5% on petrochemical and oil by-products. On May 13, 2002, by Decree No. 809/02, the federal executive branch temporarily extended the 20% export tax to other hydrocarbon exports, such as petrochemical and oil by-products, stating that the 20% export tax applicable to hydrocarbon exports would be reduced to 5% on October 1, 2002.

Through Resolution No. 77, the Secretary of Energy regulates the payment of tolls by persons and companies that are subject to audit and control under technical and security regulations for the fractionation and sale of liquid gas and the transportation of liquid hydrocarbons and its derivatives through pipelines. It provides the methods and terms and conditions for payment of the tolls.

Stability of Diesel Prices – Supply to the Domestic Market

Decrees No. 645/02 and 652/02 and Resolution No. 38/02 of the Secretary of Energy were published in the Official Gazette on April 22, 2002 and were aimed at overcoming the diesel fuel supply shortage.

Decree No. 645/02 provides that diesel exports must be registered and empowers the Secretary of Energy to expand the list of hydrocarbons subject to registration, depending on the condition of the domestic market. The Secretary of Energy has also been authorized to discontinue the registration system if the situation in the domestic market so warrants.

Resolution No. 202/02 of the Secretary of Energy, dated December 19, 2002, modified Decree No. 645/02 by canceling the registration system established by that decree for crude oil export transactions. This resolution also provides for the automatic registration and approval of diesel oil and liquefied petroleum gas exports such that simple evidence of a receipt of the form signed by an attorney of the export company is considered sufficient evidence of the registration and approval of the transaction.

By means of Decree No. 652/02, the federal executive branch ratified the diesel supply stability agreement for public transportation services, dated April 19, 2002, among the national government and hydrocarbon producing and refining companies. Under the agreement:

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Refining companies agreed to supply the domestic market with diesel for the public transportation service at a set maximum price until July 31, 2002;

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Hydrocarbon manufacturers agreed to supply local refineries with the same amount of crude oil that they had supplied in the first quarter of 2002, plus an additional amount (with a fixed price and exchange rate), until July 31, 2002; and, in turn,

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The national government agreed to allow manufacturing companies to offset against export duties:

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The amount of any costs, penalties and indemnities incurred due to the total or partial cancellation of supply to third parties, which were incurred for purposes of complying with the stability agreement; and

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Any differences between the fixed price and exchange rate set by the agreement and market prices and rates.

The parties also agreed that, if the fixed price and exchange rate at which manufacturers have agreed to sell their products exceeds a certain limit, either party may request that the agreement be renegotiated. If no agreement is reached in this respect, then the agreement may be terminated.

Decree No. 652/02 has been extended by means of Decree Nos. 1,912/02, 704/03, 447/03 and 301/04 until December 31, 2003.

Subsequently, Decree No. 1,912/02 ratified the agreement on extension of the stability agreement and the first quarterly agreement. Under the extension to the stability agreement, the national government agreed to issue a resolution that would provide for the reduction of export duties imposed on diesel, from a 20% rate to a 5% rate, retroactive as of August 1, 2002.

The first quarterly agreement aimed at limiting diesel volumes that must be provided to public transportation companies at contractually discounted prices, by establishing an information and verification system. The refining companies were entitled to compensation for any differences between the net income that refining companies obtained from the sale of diesel at the market price compared to that obtained from sales at agreed upon prices. The amount of that economic compensation is verified by the Secretary of Energy, who issues a certificate permitting the refining companies to obtain from producers a rebate on the unit price of crude oil equal to the value of the compensation. Producers, in turn, may discount the amount of such rebate from export duties.

Since ratification of the first quarterly agreement, a series of extension agreements has been executed and ratified through Decrees No. 704/03 and No. 447/03. In turn, Decree No. 576/03 empowered the Cabinet of Ministers until December 31, 2003 to execute new agreements with the companies, as well as to enter into amendments to these agreements, in order to secure a continued supply of diesel at a discounted price.

Stability of Fuel Prices

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 WTI of US$28.5 per barrel instead of the actual relevant WTI. Any positive or negative difference between the actual relevant WTI, not exceeding US$36 per barrel, and the reference price would be paid out of any balance generated in periods where the actual WTI is below US$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 US$32 and US$42, crude oil deliveries will be invoiced and paid based on a reference price equal to (1) 86% of the WTI as long as this price does not exceed US$36 per barrel, or (2) 80% of the WTI, in cases where this price exceeds US$36 per barrel.

Royalties

The national government has provided that the Central Bank will be responsible for issuing the regulations that may be required to apply the provisions of Section 5 of Decree No. 1,589/89, which will permit producing companies to dispose of their proceeds from sales in the domestic market, and the national government has described the manner in which these regulations shall apply during the course of the Argentine economic crisis.

Under Resolution No. 76/02 of the Ministry of Economy, royalties on oil exports must be fixed taking into account the seller exchange rate of Banco de la Nación Argentina on the day before the royalty is paid.

However, from December 2001 until May 2002, producers and refiners agreed to negotiate a reduced exchange rate in order to moderate the impact of the devaluation in product price. Producers calculated and paid royalties according to this reduced exchange rate. These calculations have been rejected by Argentine Provinces, which have presented claims for any shortfall arising from this agreement.

Gas

In 1992, the Natural Gas Act and related decrees of the federal executive branch were passed providing for the privatization of GdE. The Natural Gas Act and the related decrees provided for, among other things, the transfer of substantially all the assets of GdE to two transportation companies and eight distribution companies. The transportation assets were divided into two systems on a geographical basis, the northern and southern area pipeline systems, designed to give both systems access to gas sources and to main centers of demand, including the greater Buenos Aires region. The distribution assets were also divided on a geographical basis.

A majority stake in each of the ten companies was sold to private bidders through a public tender process. Each consortium of bidders was required to be qualified on the basis of technical merit, including having a consortium participant with previous experience as an operator of gas transportation or distribution facilities. Accordingly, each consortium included one or more significant international operators.

The Natural Gas Act and related decrees granted each privatized company a license to operate the transferred assets, established a regulatory framework for the privatized industry based on open, non-discriminatory access, and created ENARGAS to regulate the transportation, distribution, marketing and storage of natural gas. The Natural Gas Act also provided for the regulation of wellhead gas prices in Argentina for a period of between one and two years beginning in June 1992 with prices to be deregulated no later than June 1994. Pursuant to a subsequent decree, gas prices were deregulated as of January 1, 1994. Since the deregulation, prices have risen with variances based on the basin and the season of the year.

As part of the privatizations, the concessionaires assumed a series of obligations aimed at correcting the previous situation. In particular, concessionaires agreed to incorporate modern technology and make greater investments in equipment, thereby improving quality and safety levels to comply more closely with international standards and ensuring a supply necessary to meet a growing demand. In addition, operating efficiencies were sought, with a view to sharing these benefits with the consumers through tariff rebates.

In exchange, the companies were entitled to tariff levels that ensured a reasonable and fair profit, comparable with profits at the domestic and international levels. In line with that objective, tariffs were to be denominated in US dollars, in order to permit companies to better match their income with their expenses and investments, which in large part were tied to foreign markets, both through the import of specialized equipment and foreign financing.

Regulatory framework

Natural gas transportation and distribution companies operate in an “open access,” non-discriminatory environment under which producers, large users and certain third parties, including distributors, are entitled to equal and open access to the transportation pipelines and distribution system in accordance with the Natural Gas Act, applicable regulations and the licenses for privatized companies. In addition, a regime of concessions under the Hydrocarbons Law is available to exploitation concessionaires to transport their own gas production.

The Natural Gas Act prohibits gas transportation companies from buying and selling natural gas. Additionally, gas producers, storage companies, distributors and consumers who contract directly with producers may not own a controlling interest (as defined in the Natural Gas Act) in a transportation company. Furthermore, gas producers, storage companies and transporters may not own a controlling interest in a distribution company, and no seller of natural gas may own a controlling interest in a transportation or distribution company (unless such seller neither receives nor supplies more than 20% of the gas received or transported, on a monthly basis, by the relevant distribution or transportation company).

Contracts between affiliated companies engaged in different stages in the natural gas industry must be reported to ENARGAS. ENARGAS may disapprove such contracts only if it determines that they were not entered into on an arm’s-length basis.

ENARGAS

ENARGAS is an autonomous entity which functions under the Ministry of Economy and Public Works and Services of Argentina and is responsible for a wide variety of regulatory matters, including the approval of rates and rate adjustments and transfers of controlling interests in the distribution and transportation companies. ENARGAS is governed by a board of directors composed of five full-time directors who are appointed by the federal executive branch subject to confirmation by the Argentine Congress.

ENARGAS has its own budget which must be included in the Argentine national budget and submitted to congress for approval. ENARGAS is funded principally by annual control and inspection fees that are levied on regulated entities in an amount equal to the approved budget, net of collected penalties, and allocated proportionately to each regulated entity.

Conflicts between two regulated entities or between a regulated entity and a third-party arising from the distribution, storage, transportation or marketing of natural gas must first be submitted to ENARGAS for its decision. ENARGAS’s decisions may be appealed through an administrative proceeding to the Ministry of Economy or directly to the federal courts.

Rate Regulation

Since the adoption of the Public Emergency Law and the other emergency measures taken by the Argentine government in early 2002, the regulation of public utility tariffs including those for gas transportation and distribution has changed dramatically. The rapid implementation of these rate changes has resulted in a complex and often conflicting legal framework. Although the rate regulations described below are still in effect, in practice, they have for the most part been superseded by new regulations which we summarize below. See “—Public Emergency Law.” We cannot provide assurance on which regulatory scheme will ultimately be implemented by the Argentine government once it acts to conform the conflicting regulations.

The Natural Gas Act regulates the rates for gas transportation and distribution services, including those of TGS. Under the TGS license, TGS is permitted to adjust rates (1) semi-annually to reflect changes in the US producer price index, and (2) every five years in accordance with efficiency and investment factors to be determined by ENARGAS. In addition, subject to ENARGAS’s approval, rates may be adjusted from time to time to reflect cost variations resulting from changes in the tax regulations (other than income tax) applicable to TGS, and for objective, justifiable and non-recurring circumstances.

The Natural Gas Act provides that the tariffs for natural gas charged to end users by distribution companies shall consist of the sum of three components: (1) the price of gas purchased; (2) the transportation tariff for transporting gas from the production area through the distribution system; and (3) the distribution tariff. The rates of TGS are expressed in US dollars and are adjusted every five years in accordance with efficiency and investment factors determined by ENARGAS. The ratemaking methodology contemplated by the Natural Gas Act and the TGS license is the “price-cap with periodic review” methodology, a type of incentive regulation which allows regulated companies to retain a portion of the economic benefits arising from efficiency gains.

Under the terms of the TGS gas transportation license, TGS could increase rates semi-annually based on the U.S. producer price index. In January 2000, ENARGAS, TGS and the other gas transportation and distribution companies agreed to postpone the Producers Price Index adjustment scheduled for January 2000. In August 2000, Decree No. 669/00 was issued which (1) allowed TGS to bill its customers retroactively for the January 2000 producer price index rate adjustment over a 12-month period, and (2) postponed any further producer price index rate adjustments until July 2002. Decree No. 669/00 allows TGS to bill its customers retroactively for these postponed producer price index rate adjustments beginning in July 2002. Decree No. 669/00 also allows TGS to add an interest charge to its bills in order to compensate it for the delay in billing these producer price index rate adjustments.

In late August 2000, a court proceeding was commenced, which challenged the legality of Decree No. 669/00, claiming that the producer price index rate adjustments contradict the Convertibility Law. The court suspended the application of Decree No. 669/00 and, subsequently, ENARGAS notified TGS that it should not apply any producer price index rate adjustments until the court proceeding is resolved. As a result of the enactment of the Public Emergency Law, ENARGAS notified TGS of the suspension of the second five-year review of its tariffs. This review had begun in 2000. Because of certain provisions of the Public Emergency Law and our contract renegotiation efforts, we do not expect that Decree No. 669/00 will be upheld nor do we expect that TGS will ultimately be able to retroactively bill its clients for producer price index rate adjustments.

Notwithstanding the foregoing, through Decree No. 689/02, the federal executive branch exempted the following from the pesification required by the Public Emergency Law and Decree No. 214/02: (1) tariffs for the regulated transportation of natural gas destined for export; (2) agreements for the transportation of natural gas destined for export; and (3) purchase and sale contracts for natural gas destined for export whose terms had been originally fixed in a currency other than the Argentine peso (these contracts are to be invoiced and paid in US dollars at an exchange rate of P$1/US$1).

Decrees No. 689/02 and 704/02 excluded from pesification the obligations to pay in foreign currency incurred by individuals or companies residing or located outside Argentina, payable with funds coming from abroad, to individuals or companies residing or located in the country. Under Resolution No. 2,774/02, which was based on these decrees, ENARGAS reinstated the producer price index as an adjustment coefficient for transportation tariffs in respect of gas destined for exportation, and consequently, with respect to natural gas destined for exportation, approved the tariff schedules presented by TGS effective as of July 1, 2002, and permitted the denomination of the charges related to each type of service to be in US dollars.

Public Emergency Law

The Public Emergency Law established that in contracts related to public works and services, clauses setting forth the price of such works and services in foreign currencies and indexation clauses based on foreign price indices or any other indexation mechanisms are no longer valid. Prices and tariffs resulting from those clauses had to be converted into pesos at a conversion rate of P$1=US$1. Pursuant to this law, the Argentine federal executive branch is authorized to renegotiate the terms of these contracts. See “—Electricity—UNIREN.”

On December 4, 2003, Law 25,820 was promulgated, which extended up to December 31, 2004 the public emergency declared by Law 25,561 on social, economic, administrative, financial and foreign exchange matters, and the delegation of powers provided to the federal executive branch to renegotiate the tariffs of the public services and

license contracts. This law empowers the federal executive branch to negotiate tariffs without being constrained by the applicable regulatory frameworks. Any legally permitted revisions of any current tariff must be authorized by the applicable regulatory agency to the extent these revisions fall within the scope of the renegotiation process led by the executive branch. Also, any agreed transitory changes to the utility service agreements and/or licenses must be considered in the definitive agreements.

Modifications to the regulatory framework

On February 16, 2004, Decree No. 180/04 was published in the Official Gazette providing for:

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Creation of a trust fund (the trust will be funded by tariffs payable by users of the service, special credit programs and contributions from direct beneficiaries);

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Creation of an electronic market to coordinate “spot” transactions of the sale of natural gas and secondary market transactions for transportation and distribution of natural gas;

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Expansion of section 34 of Decree No. 1738 that regulates Gas Law 24,076 to prohibit distributors or their shareholders from having a controlling participation in more than one dealing company; and

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Authorization by the Secretary of Energy to take all necessary measures to maintain an adequate level of services in the event that it verifies that the system could face a supply crisis.

On February 16, 2004, Decree No. 181/04 was published in the Official Gazette that instructed the Secretary of Energy to design a framework for the normalization of prices of natural gas at the wellhead. This framework is to be applicable to both distributors and major consumers. The decree authorizes the Secretary of Energy to negotiate with gas producers on a price framework for the adjustment of prices in sale contracts to distributors. It also authorizes the Secretary of Energy to determine a category of users who will not be able to buy gas from distributors but, rather, must buy directly from producers. A new mechanism for protection of this new category of consumers must be established to guaranty supply and price, and must be extended to July 31, 2005.

The decree further states that prices resulting from sales pursuant to the agreement with producers shall be the prices used as a reference for calculating and paying royalties. These prices will also be used by ENARGAS in calculating any necessary adjustments in tariffs that result from variations in the price of purchased gas. The decree also states that the framework shall adjust tariffs corresponding to form “R” for Residential Services and “P” for General Services. In addition, the decree states that all agreements for the sale of natural gas shall be filed with the gas electronic market, and the Secretary of Energy has the authority to regulate the sale of gas (1) between producers and (2) between producers and the dealers who they either control or are affiliated with.

On April 2, 2004, the Secretary of Energy entered into an agreement with natural gas producers, in which the following was agreed to:

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Minimum volumes that natural gas producers must supply to the local market, including specified amounts for: (1) distributors who supply industrial users, (2) clients of distributors, or new direct consumers, who are prohibited from buying directly from distributors and must buy directly from producers and (3) power stations that generate electricity for the local market;

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Authorization of the producers to increase the prices of natural gas according to a price roadmap which differs for each basin and that culminates in complete deregulation of the wellhead price of natural gas by January 1, 2007;

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Obligation of the distribution and generation companies to renegotiate the price and volumes of their supply contracts with producers who are also a party to the agreement. If an agreement is not reached after a 45-day period, producers are released from their obligation to supply natural gas to these distribution and generation companies;

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New direct customers have regulated prices through June 31, 2005; and

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Notice of all new supply agreements must be given to the Secretary of Energy and will be published in the electronic gas market once this market starts functioning.

This agreement was further approved by Resolution No. 208 of the Ministry of Federal Planning, Public Investments and Utilities. The public hearings at ENARGAS took place on May 6, 2004.

In addition, on March 24, 2004, under Resolution No. 265/04 the Secretary of Energy imposed certain restrictions in order to avoid a crisis in the supply of gas to the domestic market. Specifically, export authorizations and exports of natural gas surplus volumes were suspended and the Undersecretary of Fuels was instructed to create a program for the rationalization of gas exports and the use of the country’s transportation capacity.

Under Resolution No. 27/04, which was issued by the Undersecretary of Fuels, a Program for the Rationalization of Natural Gas Exports was approved and is in effect as long as natural gas volumes in the Argentine system fail to satisfy the domestic demand. In addition, an order of priority for the selection of companies that will be subject to export suspension restrictions was established taking into account the following factors: (1) the degree of compliance with the producers’ commitment of gas supply to the domestic market (these commitments were established by each producer at the time the corresponding gas export authorization was granted), (2) the history of sales to the domestic market, and as divided between sales to distributors and sales to direct consumers and (3) the impact that this suspension would have on the domestic market supply.

Except as expressly authorized by the Undersecretary of Fuels, no export authorizations will be granted if such authorizations would result in export volumes (not including surplus volumes) higher than those exported in 2003. For calculation purposes, volumes for each month will be compared with figures from the corresponding month of the previous year. In addition, excess volumes, if any, already exported by a producer will be offset until the end of the third quarter of 2004.

Producers that have not maintained the level of sales to the domestic market committed at the time of requesting their export authorizations will receive the average basin price for the domestic market as published by ENARGAS. On the other hand, producers who have complied with their obligations with respect to the supply of the domestic market will receive a value for their natural gas equal only to the value actually received under their respective export agreement.

On June 18, 2004, the Secretary of Energy passed Resolution No. 659/04 by which the Complementary Program to Supply the Domestic Market of Natural Gas, which we refer to as the Complementary Program, was approved. The Complementary Program replaces the Program of Natural Gas Exportations and Transportation Capacity Rationing, which had been approved by Disposition 27/2004 issued by the Undersecretary of Fuels. The Complementary Program commenced on June 24, 2004 and partially eliminates the monthly and quarterly limits on the export of natural gas which was applicable under Disposition 27/2004.

On April 21, 2004, the Argentine government reached a six-month agreement with the Bolivian government. This agreement allowed Argentina to import up to 4 million cubic meters of natural gas from Bolivia per day. Also in April 2004, Resolution No. 185/04 of the Ministry of Federal Planning, Public Investment and Utilities was issued creating trust funds with the objective of financing infrastructure works in gas transportation.

On May 26, 2004, under Resolution No. 503/04 the Secretary of Energy approved a method for priority use of transportation for the supply by distributors of uninterruptible natural gas. This resolution is effective through August 31, 2004.

Also in May 2004, under Executive Order 645/04, the government imposed a 20% export tax on all natural gas exports.

On May 23 2005, pursuant to Resolution No. 752/05 the Secretary of Energy established a mechanism by which new direct consumers will be able to buy natural gas directly from producers. If no agreement is reached, new

direct consumers will be able to buy natural gas by posting an irrevocable offer in the electronic gas market, which was originally created for “spot” transactions and is now open for long-term operations. The irrevocable offer, which will require on December 31, 2006, is required to contain the following minimum terms:

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Term: 36 months;

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Price: export parity; and

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Volume: 1,000 cubic meters per day.

If the irrevocable offer is not accepted, new direct consumers may require the Secretary of Energy to provide natural gas for a period of six months pursuant to the prices approved by Resolution No. 208 of the Ministry of Federal Planning, Public Investments and Utilities. The Secretary of Energy will order the export producers to provide this natural gas.

Transportation companies are prohibited from transporting natural gas for exportation purposes as long as local demand is not satisfied.

Liquefied Petroleum Gas

Prior to the enactment of Law No. 26,020 on April 8, 2005, the Argentine liquified petroleum gas market was regulated by the Hydrocarbons Law, as supplemented by several technical and commercial rules, and regulations issued by the Undersecretary of Fuels, which covered all activities related to liquefied petroleum gas, including production, transportation, fractionation, domestic and international marketing and relationship management between consumers and the national government. Under Resolutions No. 49/01 and No. 52/01, the Secretary of Energy became the enforcement authority for the liquified petroleum gas industry and a liquified petroleum gas board, which reports to the National Refining and Marketing Board, which, in turn, reports to the Undersecretary of Fuels, became the controlling authority.

The Argentine Congress established, pursuant to Law 26020, a new regulatory framework for the liquified petroleum gas industry that is intended to guarantee regular, reliable and economical provision of liquified petroleum gas to low-income residential sectors who currently are without natural gas network services. This new regime regulates production, fractionation, transportation, storage and distribution of liquified petroleum gas, as well as, port services and trading of liquified petroleum gas. These activities, pursuant to Section 5 of Law 26020, are considered of public interest. The enforcement authority in charge of complying with the purposes of Law 26020 is the Secretary of Energy, which may delegate supervision and control tasks to ENARGAS. The relevant portions of this law are summarized below:

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Prices. The Secretary of Energy determines reference prices (below export parity prices) with the goal of guaranteeing regular supply in the domestic market and may establish price stabilization mechanisms in order to avoid price fluctuation in the domestic market. The Secretary of Energy will determine and disseminate a reference price for liquified petroleum gas, which is sold in containers of up to 45 kg in size, in each region every six months for domestic use. Market participants found selling liquified petroleum gas at significantly different prices will be sanctioned.

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Market limitations. The Secretary of Energy together with the Antitrust Commission, or CNDC, will perform an analysis of the sector, including behavioral patterns of its agents, for the purpose of fixing limits at certain levels at each stage of vertical integration of the industry.

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Open Access. An open access regime is established in connection with liquified petroleum gas storage, with the Secretary of Energy providing conditions and regulations in order to determine the maximum tariffs to be paid for this service.

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Imports/Exports. Free import of liquified petroleum gas without authorization is allowed and, as long as the necessary volumes for provision of domestic supply are guaranteed, the Secretary of Energy authorizes restriction-free exports of liquified petroleum gas.

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Trust Fund. A trust fund for subsidizing the liquified petroleum gas residential consumption, funded mainly with the resources obtained from the sanctions set forth in Law 26020 and from amounts allotted by the National Budget Law, is created for the purpose of attending to liquified petroleum gas needs of the low-income sector and to expand natural gas distribution networks to areas without service.

Resolution No. 168/05 of the Undersecretary of Fuels makes liquified petroleum gas subject to Resolution No. 1679/04. See “—Petroleum—Refining.” Pursuant to the framework of Resolution No. 168/2005, Petrobras Energía and the remaining liquified petroleum gas producing companies entered into an agreement with the Undersecretary of Fuels to continue supplying liquified petroleum gas to the domestic market without complying with the procedures established in Resolution No. 168/05 because no actual domestic supply difficulties exist.

Electricity

Prior to 1991, virtually all of the electricity supply industry in Argentina was controlled by the public sector. Inefficient management and inadequate capital expenditures under that regime resulted in the deterioration of quality in service and physical equipment, poor financial condition and high rates for poor service.

Accordingly, the Argentine government enacted Decree No. 634/02 in March 1991, and the Argentine Congress enacted Law 24,065, known as the Regulatory Framework Law, in January 1992, establishing guidelines for the restructuring and privatization of the electricity sector within the framework of Law 23,696. The new regulatory framework of the sector established, as separate areas, the generation, transportation and distribution of electricity, and adopted separate regulatory regimes for each, thereby moving to a decentralized model with an increased participation in the private sector.

The privatization process began in February 1992 with the sale of several large thermal generation facilities, previously operated by Servicios Eléctricos del Gran Buenos Aires, and has continued with the sale to the private sector of transmission and distribution facilities, as well as additional thermoelectric and hydroelectric generation facilities. The companies that have received concessions have also assumed a series of commitments to improve the quality and safety of the industry. They also plan to ensure supply by incorporating modern technologies and by making large investments in equipment and works.

Due to privatization, a higher level of quality has been achieved, with fewer losses of grid capacity during peak times. Wholesale prices have also been reduced as a direct result of new generation equipment in place of less cost-efficient power plants.

In order for the flow of revenues to be more closely associated with expenses and investments, the operations of the sector were denominated in US dollars. This was because private operators often funded their large works through foreign lending institutions due to difficulty in obtaining significant amounts of financing at adequate rates in the domestic market.

Regulatory Framework

The Secretary of Energy regulates electric power supply and grants and controls electricity sector concessions at the national level through the National Directorates for Coordination and Regulation of Prices and Rates and for Electricity Planning. The Federal Board of Electric Power, made up of representatives from each province, is an advisory body to the Secretary of Energy, which coordinates policies for the electricity sector. The Federal Entity of Electricity Regulation, or ENRE, is an autonomous body which reports to the Secretary of Energy and has overall supervisory power in the electricity industry. It is managed by a board of five members selected by the federal executive branch, two of whom are individuals from a list proposed by the Federal Board of Electric Power. The members of the board of directors of ENRE are not allowed to have any economic interest in the areas under their jurisdiction.

ENRE’s purpose is to pursue the objectives set out in the Regulatory Framework Law and provide regulations regarding security, the standard quality of service, and procedures for technical areas such as metering and interpretation. Accordingly, ENRE’s specific duties, among others, include: (1) establishing a tariff collection mechanism; (2) establishing the criteria and conditions for awarding concessions; and (3) safeguarding public safety, environmental protection and property rights relating to the construction and operation of generation, transmission, and distribution facilities.

ENRE has mandatory jurisdiction over all disputes between generators, transmitters and distributors in matters relating to the public supply, distribution and transportation of electricity. If ENRE becomes aware of practices that are inconsistent with the Regulatory Framework Law and other regulations, it is empowered to notify the interested parties, hold hearings and take the appropriate authorized action. In particular, ENRE can apply penalties for noncompliance with the Regulatory Framework Law and initiate and pursue legal actions to ensure compliance therewith. Appeals to ENRE’s decisions may be filed directly before the Secretary of Energy and the courts.

ENRE is required to prepare an annual budget and to submit it to the regulated entities for approval. These regulated entities are required to pay a fee to ENRE on the basis of the approved budget and their respective share in the total gross profit of all regulated entities. In addition to revenues from regulated entities from this fee, ENRE is entitled to retain cash from fines and seizures.

Structure

Under the current regulatory structure, generation of electricity in Argentina is organized as a competitive market, the wholesale electricity market in which independent generators sell the power they produce to other generators, distribution companies, large scale users and into the spot market. The generation of electricity is characterized under the law as a public utility and as such is not highly regulated. In contrast, the transmission and distribution of electricity are considered public services and as such are licensed by the national and/or the provincial government. Transporters are obliged to permit third parties to have access to any available transmission capacity, but are not themselves authorized to buy or sell electricity, and are entitled to charge a toll for the provision of transmission services. Distributors are also regulated through the establishment of rates and specifications for quality of service. They are required to satisfy demand in their markets and, as long as they have any distribution capacity available, they have to permit large scale users, who have purchased electricity from a different source, to transmit such electricity through their network. Large scale users include (1) major large users, meaning consumers with a demand of at least 1.0 MW of electricity who are willing to execute contracts with a duration of at least one year and who purchase electricity through contracts that require that the suppliers meet at least 50% of their demand and (2) minor large users, meaning consumers with a demand between 0.1 MW and 2.0 MW of electricity who are willing to execute contracts with a duration of at least two years and who purchase electricity through contracts that require that the suppliers meet 100% of their demand.

Management and operations of the wholesale electricity market

The activities of participants in the wholesale electricity market are governed by the terms of the Regulatory Framework Law. Additionally, CAMMESA was specifically created by the federal government to perform the necessary administrative functions of the wholesale electricity market. CAMMESA’s capital stock is distributed equally among the entities representing generation companies, transmission companies, distribution companies, large scale users and the Secretary of Energy, each of which has the right to nominate two of CAMMESA’s directors. The Secretary of Energy has a veto right over the decisions taken by CAMMESA. CAMMESA’s operating costs are covered by mandatory contributions made by all the members of the wholesale electricity market. CAMMESA does not itself buy or sell electricity, but it manages the physical transactions of the system and commercial transactions on the spot market.

In addition to the national structure of the wholesale electricity market, medium-voltage transmission and distribution of electricity (except in the city of Buenos Aires, the greater Buenos Aires area and the city of La Plata)

are also subject to provincial regulation. In particular, provincial governments may, in certain cases, forbid the direct sale of electricity to large scale users within their own jurisdiction. Large scale users connected to the national interconnected system (described below), however, cannot be prevented from purchasing electricity directly from generators.

Dispatch

The dispatch of generating units into the wholesale electricity market is managed by CAMMESA based on the short-run marginal cost of each unit on the system. CAMMESA defines the marginal cost of thermoelectric generating units for dispatching purposes as the cost of fuel delivered (natural gas, fuel oil, diesel oil or coal) for such unit to produce 1kWh. The marginal cost of hydroelectric plants with reservoirs that are overflowing is determined by a model that takes into account existing reservoir levels and projected hydroelectrical conditions for the subsequent six months. The marginal cost associated with flow-through hydroelectric generating units is zero, meaning that such units are the first to be dispatched.

Generation companies advise CAMMESA on a weekly basis of their anticipated available energy and other relevant information such as fuel type, price and anticipated consumption. CAMMESA then ranks each generating unit according to that unit’s marginal costs, taking into consideration the minimum operating load needed to keep generating units on line and expenses incurred in shutting down and restarting generating units. Based on this ranking, and in order for CAMMESA to obtain the lowest overall system cost, generating units are dispatched to the network successively from the lowest cost generating unit to the highest cost generating unit until the demand for electricity is met. CAMMESA is responsible for administering all transactions through the wholesale electricity market, but is not involved in the actual settlement of transactions between generators, distributors and large users that have entered into either long-term or medium-term contracts.

CAMMESA makes optimum dispatch arrangements without taking into account the existence of long-term and medium-term agreements between generators, distributors and large scale users. CAMMESA also administers an option market in which generators may enter into option contracts known as cold reserve contracts. Finally, CAMMESA coordinates the dispatching of generators in the spot market.

As a consequence of the crisis in Argentina, the Secretary of Energy issued Resolution 2/02, which pesified the prices of power and the reference prices of fuels at an exchange rate of P$1=US$1. This placed a limit on the generators’ stated prices. Resolution No. 8/02 established market prices that accounted for part of the variable costs in production declared by the generators, and it also established a maximum price of $120/MWh. Resolution No. 82/03 suspended the last seasonal increase of prices. Under Resolution No. 240/03, in connection with the spot market, generators are able to set a market price without considering potential restrictions in the supply of gas, and those generators, with costs higher than the established price, are individually paid their variable costs of production. By means of Resolution No. 406/03 the Secretary of Energy established that all credits pending of payment by CAMMESA as a consequence of the deficit of the Stabilization Fund (due to the suspension of the seasonal increase of prices) should be consolidated and paid once this fund has sufficient monies.

Resolution No. 984/03 of the Secretary of Energy authorized the wholesale electricity market to call for bids for reserve of available capacity fuel for the Argentine winter period from May through October 2004. We participated with a bid of 550 MW from Genelba and were awarded an advance of US$29,072,736.

During 2004, the Secretary of Energy started to increase seasonal prices for certain tariff segments without increasing residential tariffs. (Taking into consideration the seasonal price demand, the residential tariff is 44%.) Changes in seasonal prices were insufficient, however, and the deficit between the funds and accounts administered by CAMMESA continued to grow.

Given the foregoing situation, during 2004 the electricity market scenario was characterized by energy-producing companies having limited financing ability and uncertainty as to gas availability for thermal power plants. For this reason, the Secretary of Energy implemented short and long-term measures to secure electric power supply, the main measures of which are summarized below:

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Pre-financing of diesel oil was provided in order to allow generation companies to pay in advance liquid fuel estimated to be used at each power plant.

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Additional income was provided to negotiate gas and liquid fuel supply with suppliers.

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The Secretary of Energy instructed CAMMESA to import energy from Brazil through an International Public Bidding process at Garabí 1 and 2 Converter Stations for the June-November period.

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A comprehensive cooperation agreement was entered into between Argentina and the Bolivarian Republic of Venezuela.

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A redistribution of export gas for the electricity market was undergone to avoid supply shortages due to the inability to generate electricity from alternative fuels.

Given that, due to financial and regulatory adjustments made in the electricity market, capital is expected to be limited for investments and that, according to annual CAMMESA studies, there is high risk of not meeting medium-term demand for electric power, the Secretary of Energy issued successive resolutions throughout the year under which an investment fund, called FONINVEMEN, was created to administer economic resources and increase the electric power supply by 2007. Under Resolution No. 826/04, wholesale electricity market generators were invited to voluntarily contribute a percentage of their marginal profit for the 2004 – 2006 period to increase generation supply by one or two combined cycles (between 800 and 1,600 MW).

In December 2004, 72.5% of private generators, including Petrobras Energía, agreed to contribute with 65% of their credits with the wholesale electricity market to FONINVEMEM, or an amount equivalent to P$923.9 million as estimated by CAMMESA. Petrobras Energía’s contributions account for approximately 11% of the total funds provided to FONINVEMEM.

UNIREN

The Public Emergency Law pesified tariffs for public utility services and prohibited the increase of these tariffs based on indexation factors. Tariffs were converted into pesos at a P$1=US$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 the following factors, among others:

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Impact of tariffs on economic competitiveness and on income distribution;

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Quality of services to be provided and/or the capital expenditure programs provided for in the contracts;

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Interest of customers and accessibility to the services;

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The safety of the systems; and

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The company’s 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. In July 2003, UNIREN was created with the purposes, among others, to provide assistance in the public works and services renegotiation process, to execute comprehensive or partial agreements, and to submit regulatory projects related to transitory rate adjustments.

In 2004, the following resolutions were entered into:

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Resolution No. 712/04 of the Secretary of Energy. This resolution created FONINVEMEM, through which the economic resources necessary to increase the supply of electric power by 2007 are to be managed.

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Resolution No. 826/04 of the Secretary of Energy. This resolution provided an invitation to generation companies to contribute to FONINVEMEM a percentage of their marginal profit for the 2004- 2006 period. Generation companies voluntarily contributing to this fund will become shareholders of the new installations and will participate in its operations.

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Resolution No. 1427/04 of the Secretary of Energy. This resolution provided an invitation to generation companies to formally state their decision to participate in FONINVEMEM. It also included a Memorandum of Agreement for adjustment of the wholesale electricity market, pursuant to which private generation companies committed themselves to contribute between 65% to 100% of their marginal profit for the 2004- 2006 period as security and agreed to take all necessary measures to complete the projects.

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Resolutions No. 93/04, 842/04, 1434/04 of the Secretary of Energy. Under these resolutions, the Secretary of Energy sets forth, as from February 2004, seasonal prices for energy with increases to non-residential users (66% of seasonal demand). The value resulting from this increase is estimated at 220% on values pesified and was frozen in November 2002.

Generation

Power plants in Argentina are classified by the type of energy source used—hydroelectric, nuclear and thermoelectric (gas, fuel oil, diesel oil or coal). Power plants are also classified by capacity, defined as the net output the station is capable of sustaining for an indefinite period without causing damage to the station, which is referred to as declared net capacity.

Transmission

In Argentina, bulk transfer of electricity is achieved by means of a national interconnected system, or NIS, which consists mainly of overhead lines and substations and covers approximately 90% of the territory of Argentina. Practically all of the NIS’ 500 kV transmission lines have been privatized and are owned by Transener. Apart from Transener, there are five other regional subtransmission companies in charge of transmitting energy at 132 kV and 330 kV voltages, and almost all large power plants use the NIS. Supply points connect the NIS to distribution systems and large users. In addition, there are two international connections: one between the Argentine transmission system and the Uruguayan transmission system, and the other between Argentina and Brazil, which permit the import or export of electricity between these systems. The cost of transmission is charged to generators, distributors and large users. The transportation cost is made up of a variable charge corresponding to the energy transmitted across the system, and a fixed charge for (1) connection to the system, (2) transformation and (3) transmission capacity. Transmission companies operate as common carriers and must provide open access to all generation companies. Transener’s rates are set by the concession contract and are to be subject to revision by ENRE. The law provides that services provided by transmission companies must be offered at fair and reasonable rates which yield sufficient income to meet reasonable operating costs applicable to service, taxes, depreciation and a reasonable rate of return. The rate of return should bear a relationship to (1) the energy costs, (2) the use of transmission lines and (3) the degree of operating efficiency of the business, and should be similar, as an industry average, to that of other domestic or international activities of similar or comparable risk. The rates that Transener may charge have been modified by the Public Emergency Law. See “—Petroleum.”

Pursuant to Resolution No. 1650/98, ENRE approved an 8% overall reduction of Transener’s tariffs for the second tariff period, July 1998 – July 2003, retroactive to July 17, 1998. In addition, a bonus subject to compliance with certain quality parameters was approved, and currently, Transener’s quality levels entitle it to a bonus of approximately P$2.5 million.

Since the beginning of the second tariff period, Transener’s income from transportation capacity and connection has been reduced annually through the application of an efficiency ratio established by ENRE. Pursuant to Resolution No. 1319/98, the efficiency ratio applicable to the second tariff period is approximately 0.5% per annum.

Distribution

Electricity is transferred from the NIS supply points to consumers by means of distribution systems consisting of a widespread network of overhead lines, underground cables and substations having successively lower voltages (220 kV and below). In general, electricity users in Argentina are the users of the distributor within whose area of distribution the premises of such consumer are located. Each user is charged in accordance with the applicable tariff. Distributors’ charges seek to recover the various costs associated with supply, including the electricity purchase costs and transmission and distribution charges, in addition to, the added value of distribution. In accordance with Law 24,065, and in the case of transmission companies, services provided by electricity distributors must be offered at fair and reasonable rates which yield sufficient income to meet reasonable operating costs applicable to service, taxes, depreciation and a reasonable rate of return. The rate of return should bear a relationship to the degree of operating efficiency of the business, and should be similar, as an industry average, to that of other domestic or international activities of similar or comparable risk. Similarly, distributors are required to include a representative figure for the acquisition cost of electricity from the wholesale electricity market in the electricity sales price to end-users.

Each distributor operates in accordance with a concession agreement executed between itself and the Argentine government or provincial government, depending on whether the distributor is under federal or provincial jurisdiction, which provides for, among other things, the area of its concession, the quality of service that it is required to provide, the tariffs it is permitted to charge and its obligation to satisfy demand. ENRE, in the case of distributors under the federal jurisdiction (Edenor, Edesur and Edelap), and the provincial regulatory agencies in each of the provinces, monitor compliance by the distributor with the provisions of the concession agreement and the regulatory framework and provide a mechanism for public hearings at which complaints against the distributor can be heard and resolved.

Rate adjustment method

Under the terms of the concession contract, the rate adjustment structure applicable by Edesur is calculated in US dollars but stated in Argentine pesos, taking into account the exchange rates in “Item 3. Key Information—Exchange Rates” and Decree No. 2128/91, which contains the regulations under Law 23,928. Distribution costs are adjusted on an annual basis and, among other things, are subject to the application of the U.S. wholesale price index for industrial products.

Since the adoption of the Public Emergency Law and other emergency measures taken by the Argentine government in early 2002, the regulation of public utility tariffs, including those related to transportation and distribution of electricity, has changed dramatically. The rapid implementation of these rate changes has resulted in a complex and oftentimes conflicting legal framework. Although the rate regulations described below are still in effect, in practice they have been superseded by the new regulations described under “—Petroleum—Taxation.” We cannot assure which regulatory scheme will ultimately be implemented by the Argentine government once it acts to conform the conflicting regulations.

On December 2, 2003, Law 25,820 was promulgated, which extended until December 31, 2004 the public emergency declared by Law 25,561 on social, economic, administrative, financial and foreign exchange matters, and the delegation of powers therein provided to the federal executive branch to renegotiate the tariffs of the public services and license contracts. This authorization empowers the national executive branch to negotiate such tariffs without being constrained by the applicable regulatory frameworks. The legally permitted revisions of any current tariff should be decided by the applicable regulatory agency to the extent that these revisions fall within the scope of the renegotiation process led by the federal executive branch. In addition, the transitory changes made to the utility service agreements and/or licenses should be considered in the definitive agreements that may be reached with respect thereto.

During 2004, Transener and Transba negotiated with the government – appointed renegotiation unit, UNIREN, the terms and conditions for the comprehensive renegotiation of its concession contract (the amendments

to which will be effective between January 6, 2002 and the end of the concession contract), and the application of a transitional tariff regime to be applied until a general tariff review is conducted with, and approved by, ENRE. This general review, which will be finished by November 2005, will establish a five-year tariff regime for the following five-year period. The agreement reached was implemented under a letter of intent signed on February 2, 2005 and was subject to a public hearing held on March 18, 2005. Once the federal executive branch sends the definitive proposal to the congress’ bicameral commission in charge of monitoring the renegotiation process, congress will have 60 days to approve or reject it. If rejected, the federal executive branch shall reopen the renegotiation process with Transener and Transba. See “—UNIREN.”

VENEZUELAN REGULATORY FRAMEWORK

Petroleum and Gas

The Venezuelan state is owner of all hydrocarbon fields and as such has established methods different from Argentina for the regulation of the exploitation of hydrocarbon located in Venezuelan fields.

The Gas Hydrocarbons Organic Law published on September 23, 1999 in Official Gazette No. 36,793, was issued to regulate the exploitation of free gas and the transportation, distribution, collection, storage, industrialization, handling and internal and external commerce of associated gas and free gas, permitting the private sector’s participation in these activities. This was later regulated by Decree No. 840 of May 31, 2000.

In December 1999, the new Venezuelan Constitution became effective, which contains provisions related to petroleum activity. Article 12 of the Constitution states that oil fields are the property of the Venezuelan state. Article 302 of the Constitution reserves petroleum activity to the Venezuelan state. Article 303 of the Constitution states that, PDVSA or the entity created for the management of petroleum activity (except for affiliates, strategic associations, companies or any other company set up to develop PDVSA’s business) is owned by Venezuelan state.

The new Hydrocarbons Organic Law published on November 13, 2001 in Official Gazette No. 37,323 was issued, effectively reversing most prior related legislation, except for the Gas Hydrocarbons Organic Law, and granted ample opportunity for the private sector to participate in the industry, limiting the activities reserved by the Venezuelan state to primary activities and to the sale of crude oil and specific products.

The purpose of the Hydrocarbons Organic Law is to regulate everything related to the exploration, exploitation, refinery, industrialization, transportation, storage, commercialization and conservation of hydrocarbons, and everything related to refined products and works that the performance of these activities require. The law sets forth the following principles: (1) hydrocarbon fields are public property, (2) hydrocarbon activities are activities of public utility and of social interest and (3) activities described in the law are subject to decisions of the Venezuelan state adopted in connection with international treaties and agreements on hydrocarbons.

The Performance of Hydrocarbon Related Activities

The primary activities expressly reserved by law to the Venezuelan state can only be performed by: (1) the executive branch, (2) wholly owned state entities or (3) companies in which the Venezuelan state owns at least 50% of the capital stock. Activities related to the internal and external sale of natural hydrocarbons and the derivatives, specifically mentioned by the executive branch, can only be performed by wholly owned state entities. Installations and existing facilities dedicated to the refining of natural hydrocarbons in the country and to the transportation of products and gas are reserved to the Venezuelan state.

Hydrocarbon refining activities may be carried out by the Venezuelan state and private entities, in a joint effort or separately. Those activities relating to the internal and external sale of derivative products, which have not been reserved by the executive branch to be carried out by wholly owned state entities, may be carried out directly by (1) the Venezuelan state, (2) by wholly owned state entities, (3) by entities with public and private capital in any proportion or (4) by private entities. Pursuant to Decree No. 1,648 dated January 15, 2002, activities related to the exportation and importation of products derived from hydrocarbons that have been carried out in the past by wholly owned state entities shall continue to be carried out in such manner until those products are specifically excluded in

order to create an international market for them. Internal commercial activities regarding services deemed as public may be performed by anyone who obtains a permit. The sale of refined hydrocarbons may be performed by (1) the Venezuelan state, (2) its wholly owned state entities, (3) entities with public and private capital in any proportion, and (4) private entities.

In order for the Venezuelan state to carry out its activities, the executive branch is authorized to create, through a Council of Ministers, wholly owned state entities of any kind, including corporations. These entities may also create other entities, with the approval of their shareholders, or modify their corporate purpose, merge, enter into joint ventures, liquidate, and create affiliates. These wholly owned state entities are regulated by (1) Decree No. 1,648 and its regulations, (2) their by-laws, (3) dispositions of the executive branch and certain entities connected with the Ministry of Energy and Mines and (4) applicable law. They are also subject to local and international inspection and audit and must comply with guidelines and policies of the executive branch administered through the Ministry of Energy and Mines.

The private sector may participate in primary hydrocarbon related activities only through entities in which the Venezuelan state holds the majority of the capital. The creation of these entities and the conditions under which they will carry out their activities must be previously approved by the National Assembly, which may modify the conditions proposed or set forth conditions that it, itself, considers suitable. These entities must meet the following minimum conditions: (1) must have a maximum duration of 25 years (which may be extended for 15 years), (2) must provide information regarding location, orientation and extension of the area, (3) all of their assets must be reserved and turned over to the Venezuelan state once the activity ends and (4) any dispute among its shareholders must be resolved through private negotiations or arbitration and shall be subject to the Venezuelan legal system.

Licenses and permits

Entities that wish to carry out activities related to the refining of natural hydrocarbons must obtain a license from the Ministry of Energy and Mines. This license is subject to certain conditions. Entities that wish to carry out activities related to the processing of refined hydrocarbons must obtain a permit from the Ministry of Energy and Mines. This permit is also subject to certain conditions. Entities that wish to carry out activities related to the domestic sale of refined hydrocarbons must obtain a permit from the Ministry of Energy and Mines.

Relevant Tax Features

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Income tax

Venezuelan income tax law imposes a tax at a rate of 50% on the net taxable income of persons involved in hydrocarbon related activities, or activities related to the purchase or acquisition of hydrocarbons and derivatives for exportation. These persons may be authorized to deduct from their income tax 8% of the value of new investments in fixed assets up to a maximum amount equal to 2% of their annual income for the relevant fiscal year. Any excess may be used in the following three fiscal years. Four percent of certain investments in high waters may also be deducted. Accelerated amortization and depreciation of fixed assets and direct or indirect expenses necessary for the drilling of oil wells is permitted.

Activities related to the exportation of extra-heavy hydrocarbons through vertically integrated projects or the exploration or exportation of natural non-associated gas are subject to a 34% rate.

Contractors dedicated to exploration and production activities under operative agreements with state companies are subject to a 34% rate.

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Value Added Tax

Subject to certain exceptions, in particular for exporting companies, imports and local purchases of goods and services are subject to a value added tax, or VAT, at a rate of 15%, with a limited number of goods and services subject to a VAT at a rate of 8%.

In operative contracts for the rehabilitation of marginal fields, the VAT on goods and services acquired by the contractor in the name of the state company shall be considered directly charged, under the Third Round Agreements, to that entity and, therefore, will have no economic effect on the contractor.

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Municipal taxes

Hydrocarbon activity is not subject to municipal taxes, as taxes on this activity are exclusively reserved for the national executive branch.

Income from contractors that have entered into operative contracts with state companies for the rehabilitation of marginal fields is subject to a tax on gross income. The municipality in which the contractors perform their activities sets this rate. Under the second round operating agreements, municipal taxes paid by a contractor can be recovered from the state. However, under the third round operating agreements, only municipal taxes in excess of 41% of gross income may be recovered from the state, subject to certain conditions.

Additional Matters

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OPEC

Venezuela is a founding member of OPEC. In the past, PDVSA, under instructions from the Ministry of Energy and Mines, has adjusted its own production to assure that Venezuela as a whole complies with the production ceilings set forth by OPEC.

The Venezuelan government has created a policy of strict compliance with the production quotas decided within OPEC. Article 6 of the new Hydrocarbons Law extends reductions such as those that may be set forth by OPEC to all persons that perform activities regulated by the Hydrocarbons law. As a result of this, if there are productions cuts, these cuts may directly affect private producers and contractors as well as PDVSA.

Under agreements that specifically contemplate production costs (e.g., the third round operating agreements), the reductions that may be imposed on the contractor may not exceed the percentage of reduction in production requested from petroleum companies that operate in Venezuela as a whole, including PDVSA. and its affiliates. These reductions must be determined in each case with respect to available production capacity. If the contractor cannot recuperate losses resulting from these production cuts by increasing production to an adequate level, it has the right to extend the original 20 year term of its operating agreement in order to produce the same quantity that it would have produced without the production cut.

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Exchange control system

On February 5, 2003, the Venezuelan government set forth an exchange control system. These regulations state that companies set up for the purpose of developing any of the activities described in the Hydrocarbons Organic Law may maintain outside of Venezuela accounts in currency other than the currency of Venezuela in banking or similar institutions only for purposes of meeting their obligations outside Venezuela, which obligations must be verified by the Central Bank of Venezuela. Any other foreign currency generated by such companies must be sold to the Central Bank of Venezuela. These companies do not have the right to acquire foreign currency from the Central Bank of Venezuela to make foreign currency payments. These limitations do not apply to contractors who have entered into operative agreements, and, thus, act on account of the PDVSA. These companies are only obligated to sell to the Central Bank of Venezuela any foreign currency that they voluntarily bring into Venezuela.

ECUADORIAN REGULATORY FRAMEWORK

Petroleum and Gas

Petroleum activity in Ecuador is regulated by (1) the Hydrocarbons Law (of Ecuador) and its regulations, (2) certain Ministry of Energy and Mines regulations and (3) the specific terms of a tender for public auction.

The executive branch, led by the President of the Republic, regulates hydrocarbon policies. The Ministry of Energy and Mines sends hydrocarbon policies to the President for his consideration.

The National Directorate of Hydrocarbons, who is under the authority of the Ministry of Energy and Mines, is the technical and administrative entity in charge of controlling and auditing hydrocarbon operations. The National Directorate for Environmental Protection, who is also under the authority of the Ministry of Energy and Mines, is in charge of approving environmental impact studies and environmental management plans.

Exploration and Exploitation of Hydrocarbons

Hydrocarbons and related products are the property of the Ecuadorian state. Hydrocarbon activities are performed by the Empresa Estatal de Petroleos Ecuador, which we refer to as Petroecuador, by and through third parties.

The award of exploration and exploitation agreements is performed through a special tender mechanism implemented by relevant authorities. In order to reach the exploitation phase, the contractor may only retain those areas with commercially exploitable hydrocarbons. If the contractor fails to comply with this requirement, it will be forced to return those areas to the state. The exploration and exploitation agreements for crude oil in Ecuador are generally divided into two stages. The first stage, or the exploration period, lasts four years and is renewable for another two years. The second stage, or the exploitation period, may be up to 20 years in duration and is renewable. Both exploration and exploitation agreements require an exploratory program agreeable to all parties. A minimum average investment of US$120 to US$180 per hectare, either on land and/or in seawater, shall be made during each of the first three years of the exploration period. Royalties are paid as follows: (1) 12.5% for daily gross production levels less than 30,000 barrels, (2) 14% when these daily levels are between 30,000 and 60,000 barrels, and (3) 18.5% when gross production exceeds 60,000 barrels per day. With respect to contracts for specified services or for marginal or participation fields, the contractor is not obliged to pay royalties. The contractor may not sell any of the assets related to the agreement without authorization from the Ministry of Energy and Mines. At the end of the term of the agreement, the contractor shall deliver to Petroecuador, at no cost, all these assets.

The contractor assumes at its own risk and expense all investments, costs and expenses required to perform these hydrocarbon related activities, and, in turn, it has the right to receive a portion of the production of the area covered by the agreement, with Petroecuador having the right to the other portion. Petroecuador may enter into joint venture agreements by contributing rights over areas, fields, hydrocarbons or other rights. Petroecuador’s joint venture party, in turn, acquires these rights and is obligated to make the investments agreed to by the parties. In services agreements, the contractor shall provide exploration and exploitation services in the agreed area at its own risk and expense. If the contractor finds commercially exploitable fields, it shall have the right to be reimbursed for its investments, costs and expenses and will also have the right to be paid for its services.

Prior to initiating any work, an environmental impact study and an environmental management plan must be prepared. Consultation and participation procedures, referred to in the National Constitution, must be complied with while taking into consideration local rules of the citizens in the affected area, as well as the rules applicable to all other citizens.

OTHER COUNTRIES’ REGULATORY FRAMEWORK

In addition to Argentina, Venezuela and Ecuador, our businesses must comply with regulations in the other countries where we are located, including Peru, Bolivia and Brazil.

In Peru, the petroleum, transportation, gas and liquefied petroleum gas industry are each regulated under Peru’s regulatory framework, which includes taxation, environmental codes and payments of royalties. In 1993, Perupetro, a state owned company functioning under private law, was created under the Organic Hydrocarbon Law No. 26221 and has assumed significant powers within the Peruvian energy industry. It represents the Peruvian State as contracting party and is given authority to grant areas for hydrocarbon exploration and exploitation activities and supervise the activities carried out in those areas. Perupetro was also given the authority to negotiate contracts, including the payment of royalties, which payment is further governed by a series of national decrees.

In Bolivia, the petroleum and gas industry is regulated by the System of Regulation by Sectors, which has the responsibility to regulate, control and supervise telecommunications, electricity, hydrocarbons, transportation and water activities, to assure that they operate efficiently, protecting the interest of users, service providers and the Bolivian state by contributing to the development of the country. Pursuant to Hydrocarbons Law 1689 of April 30, 1996, the right to explore and exploit hydrocarbon fields and to commercialize their products is exercised by the Bolivian state through YPFB, which enters into shared risk agreements that may not exceed 40 years for the exploration, exploitation and commercialization of hydrocarbons. YPFB also administers and audits the shared risk agreements. All controversies arising between YPFB and the contractors under shared risk agreements must be resolved through arbitration with application of Bolivian law. There has been recent political instability in Bolivia that may impact the Bolivian regulatory framework. See “Item 3. Key Information—Risk Factors—Factors Relating to Us—Our activities may be adversely affected by events in other countries in which we do business.”

In Brazil, the petrochemical industry is regulated by laws affecting petrochemicals, as well as, certain environmental, health and safety regulations, which affect our subsidiary Innova.

ORGANIZATION STRUCTURE

As of the date of this annual report:

LOGO

After the consumation of the expected merger of EG3, PAR and PSF into Petrobras Energía, which still needs to be registered with the Argentine Public Registry of Commerce:

LOGO

The following is a summary diagram of our material subsidiaries and affiliates as of the date of this annual report, including information about ownership, business segment and location:

LOGO

*	Following the expected merger of EG3, PAR and PSF into Petrobras Energía, PEPSA’s stake in Petrobras Energía is expected to decline to 75.82%. (See “–Our History and Development–Petrobras Energía Merger.”)

**	In addition to the companies diagrammed in this chart, we have holding companies in Spain, Austria, Bolivia, Cayman, the Bermudas and Argentina, which are not reflected in the chart.

PROPERTY, PLANTS AND EQUIPMENT

We have freehold and leasehold interests in various countries in South America, but there is no specific interest that is individually material to our company. The majority of our property, consisting of oil and gas reserves, service stations, refineries, petrochemical plants, power plants, manufacturing facilities, power distribution systems, stock storage facilities, gas pipelines, oil and gas wells, pipelines and corporate office buildings, is located in Argentina. We also have significant interests in crude oil and natural gas operations outside Argentina in Venezuela, Ecuador, Bolivia and Peru, a petrochemical plant in Brazil and interest in two refineries and a gas station network in Bolivia. For a more detailed description of our property, plants and equipment, including information on our oil and gas reserves and production see “—Oil and Gas Exploration and Production.”

Item 5. OPERATING

AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read in conjunction with, and is entirely qualified by reference to, our consolidated financial statements and the notes to those financial statements. Our consolidated financial statements were prepared in accordance with Argentine GAAP, which differs in certain significant respects from U.S. GAAP. Note 22 to our consolidated 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.

PROPORTIONAL CONSOLIDATION AND PRESENTATION OF DISCUSSION

In accordance with the procedures set forth in Argentine GAAP, beginning in 2003, we were required to consolidate on a proportional basis the financial statements of companies over which we exercise joint control. Joint control exists where all shareholders, or shareholders representing a voting majority, have resolved on the basis of written agreements to share control over defining and establishing operating and financial policies. When consolidating companies over which we exercise joint control, the amount of our investment in the companies under our joint control and the interest in their income (loss) and cash flows are replaced by our proportional interest in that company’s assets, liabilities and income (loss) and cash flows. In addition, related party receivables, payables, and transactions within the consolidated group and companies under joint control are eliminated on a pro rata basis pursuant to our ownership share in that company.

There are three companies over which we exercise joint control:

•

Citelec, which is engaged in the electricity transmission business in Argentina through its subsidiary, Transener. Citelec is considered part of our electricity business segment.

•

CIESA, which is principally engaged in the gas transportation business in the south of Argentina through its subsidiary, TGS. CIESA is considered part of our hydrocarbon marketing and transportation business segment.

•

Distrilec, which is engaged in the electricity distribution business in the southern area of the Federal Capital and the 12 districts of the province of Buenos Aires through its subsidiary, Edesur. Distrilec is considered part of our electricity business segment.

Despite being a company under our joint control, we did not consolidate proportionally the financial statements of Citelec because we have committed to sell our interest in Transener as required in connection with the Argentine Antitrust Commission’s Resolution approving the transfer of our control to Petrobras. See “Item 4. Information About the Company—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener.”

We consolidated proportionally line-by-line the assets, liabilities, income (loss) and cash flow of CIESA and Distrilec for all periods covered by the financial statements included in this annual report, except, in the case of CIESA, for the year ended December 31, 2002. CIESA was not consolidated that year because our equity interest as of December 31, 2002 had a P$33 million negative value and, since we had not assumed any commitments to make capital contributions or provide financial assistance to CIESA, we valued our shareholding of CIESA at zero.

Even though we consolidate the results of CIESA and Distrilec proportionally in our financial statements, our management analyzes our results and financial condition separately from the results and financial condition of these companies. Accordingly, we believe financial information without proportional consolidation is useful to investors in evaluating our financial condition and results of operations.

Unless otherwise provided, the discussion below is presented on the basis of our consolidated financial data without proportionally consolidating CIESA or Distrilec, and, therefore, is not directly comparable to the corresponding financial data set forth in our financial statements. For the results of CIESA and Distrilec (both of which are presented under proportional consolidation in our consolidated financial statements) and Citelec (which is

presented under the equity method of accounting in our consolidated financial statements) please refer to our discussion under “—Discussion of Results—Equity in Earnings of Affiliates and Companies under Joint Control.” See also “—Reconciliation Tables.”

The table below presents selected consolidated financial data of us and our subsidiaries, including the proportional consolidation of CIESA and Distrilec, as compared to such data excluding the proportional consolidation of such companies under joint control, in each case for the fiscal years indicated.


	With Proportional Consolidation For the Year Ended December 31,						Without Proportional Consolidation For the Year Ended December 31,
	2004		2003		2002		2004⁽¹⁾		2003⁽¹⁾		2002⁽¹⁾
Net sales	6,974		5,494		5,106		5,967		4,615		4,587
Costs of sales	(4,210	)	(3,386	)	(3,284	)	(3,542	)	(2,817	)	(2,878	)

Gross profit	2,764		2,108		1,822		2,425		1,798		1,709
Administrative and selling expenses	(640	)	(559	)	(609	)	(558	)	(464	)	(532	)
Exploration expenses	(89	)	(196	)	(58	)	(89	)	(196	)	(58	)
Other operating expenses, net	(304	)	(121	)	(28	)	(265	)	(104	)	(28	)

Operating income	1,731		1,232		1,127		1,513		1,034		1,091
Equity in earnings of affiliates	76		163		(638	)	79		371		(647	)
Financial income (expense) and holding gains (losses)	(1,261	)	(417	)	(1,827	)	(1,097	)	(568	)	(1,659	)
Other expenses, net⁽²⁾	(27	)	(421	)	(187	)	(31	)	(408	)	(178	)

Income (loss) before income tax and minority interest in subsidiaries	519		557		(1,525	)	464		429		(1,393	)
Income tax provision	198		(18	)	(82	)	224		(47	)	(209	)
Minority interest in subsidiaries	(39	)	(158	)	28		(10	)	(1	)	23

Net income (loss)	678		381		(1,579	)	678		381		(1,579	)

(1)	For a reconciliation of our results to our results as adjusted to reflect the elimination of proportional consolidation see “—Reconciliation Tables.”

(2)	Includes impairment charges for some of our assets, including our assets in Ecuador.

OVERVIEW

We are an integrated energy company engaged in:

•

The exploration and production of oil and gas;

•

Refining;

•

Petrochemicals;

•

Electricity generation, transmission and distribution; and

•

Hydrocarbon marketing and transportation.

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

Our principal place of business has historically been Argentina, but we also conduct operations in Bolivia, Brazil, Ecuador, Peru, Venezuela and Mexico. Approximately 55% of our total assets, 61% of our net sales, 53% of our combined crude oil and gas production and 36% of our proved oil and gas reserves were located in Argentina as of December 31, 2004. Fluctuations in the Argentine economy and actions adopted by the Argentine government have had and will continue to have a significant effect on Argentine private sector entities, including us. See “Item

3. Key Information—Risk Factors—Factors Related to Argentina.” In recent years, our international operations have grown in importance. As of December 31, 2004, 64% of our proved oil and gas reserves were located outside of Argentina, as compared to 60% in December 31, 2003.

Year to year fluctuations in our income are a result of a combination of factors, including principally:

•

The volume of crude oil, oil products and natural gas we produce and sell;

•

Changes in international prices of crude oil and oil products, which are denominated in US dollars;

•

Fluctuations in the Argentine peso/US dollar exchange rate;

•

Inflation;

•

Interest rates;

•

Changes to our capital expenditures plan;

•

Price controls; and

•

Changes in laws or regulations affecting our operations, including tax and environmental matters.

The Petrobras Energía Merger

On January 21, 2005, the special shareholders’ meetings of Petrobras Energía, EG3, PAR, and PSF, approved the merger of EG3, PAR and PSF into Petrobras Energía. On March 3, 2005, the final merger agreement was signed providing that, once implemented, following receipt of necessary governmental approvals and registration with the public registry, the merger would be given retroactive effect to January 1, 2005. On June 28, 2005, the CNV approved the merger. The merger is in the process of being registered with the Argentine Public Registry of Commerce. After the merger, Petrobras Energía will be the surviving entity. See “Item 4. Information About the Company—Our History and Development—Petrobras Energía Merger.” As of December 31, 2004, EG3, PAR and PSF had combined revenues of P$2,511 million, of which P$621 million would have been eliminated in consolidation with our financial statements, and combined operating losses of P$64 million.

The merger is a merger of companies under common control, and Argentine GAAP does not provide specific guidance with respect to these kinds of mergers. Nonetheless, Argentine GAAP contemplates that matters not specifically covered by its principles should be resolved pursuant to generally applicable international standards, particularly those applicable in the markets regulating the issuer of the financial statements. Because we also list our shares on the New York Stock Exchange, we look to U.S. GAAP, or in this case SFAS No. 141, which requires the use of the pooling of interest consolidation method for mergers of companies under common control. Accordingly, in 2005, we plan to account for the effects of the merger using the pooling of interest consolidation method. Under that method, the assets, liabilities and shareholders’ equity items of the entities under reorganization are booked in the combined entity based on their carrying amounts, without recognizing any new positive or negative goodwill. In addition, for comparative purposes, we will be required to show the financial statements of all periods presented, including those with respect to periods prior to the merger, as if the merger had occurred at the beginning of the first period presented.

FACTORS AFFECTING OUR CONSOLIDATED RESULTS OF OPERATIONS

Economic and Political Developments in Argentina

The most important factors arising from Argentina’s economic crisis that have affected and may affect our future results of operations are the following:

Argentine Peso Devaluation

Pursuant to the Convertibility Law, between April 1, 1991 and January 5, 2002, the peso was freely convertible into US dollars at a fixed one-to-one exchange rate and, as a result, Argentine currency experienced a period of stability. In 2002, however, following the government’s termination of the peso’s one-to-one exchange rate parity, the peso significantly depreciated against foreign currencies, losing 238% of its value against the US dollar and, as of December 31, 2002, the exchange rate was P$3.38 to US$1. Since all of our financial debt and a significant portion of our affiliates’ debt are denominated in US dollars, the marked devaluation of the peso in 2002 adversely affected our results and financial position. We recorded significant foreign exchange loses in 2002, as a result of the devaluation.

Prior to the enactment of this law, our cash flows were usually denominated in US dollars or US dollar-adjusted, which provided hedging against exchange rate risks. The new Argentine regulatory framework, including the pesification of utility rates, however, limited our ability to mitigate the impact of peso devaluation and prevented us from increasing the prices of our products in the domestic market to offset the devaluation of the peso. Our foreign operations, which have cash flows primarily denominated in US dollars, provided us with limited hedge against our US dollar-exposure.

In 2003, the peso began to recover its value. The balance of trade yielded a strong surplus, which, together with the continuing default in partial foreign debt payments, caused an excess supply of foreign currency. Only numerous currency purchases by the Central Bank, supported by the explicit intention of the Argentine government to maintain a high rate of exchange, prevented greater appreciation of the Argentine peso against the US dollar. As of December 31, 2003 and 2004, the peso exchange rate stood at P$2.94 to US$1 and P$2.98 to US$1, respectively. For more information on the impact of peso fluctuations on our results of operations, see “—Discussion of Results—Year ended December 31, 2004 compared to year ended December 31, 2003—Financial income (expense) and holding gains (losses)” and “—Discussion of Results—Year-ended December 31, 2003 compared to year ended December 31, 2002—Financial income (expense) and holding gains (losses).”

We have aggressively pursued a trade policy of opening and consolidating export markets to capitalize on domestic and export price asymmetries. As a result of this, the solid positioning of our foreign operations with cash flows primarily denominated in US dollars and the increase in some domestic prices in line with their respective export reference prices, our exposure to fluctuations in the peso has decreased as we have substantially recovered our ability to naturally hedge our cash exposure to US dollar liabilities.

On January 1, 2003, Technical Resolutions Nos. 16, 17, 18, 19 and 20 of the FACPCE became effective and introduced material changes in the guidelines regarding the recognition and disclosure of exchange differences. Formerly, exchange differences were charged to income, as gains and losses on foreign currency translation. The new regulations provide that exchange differences arising from liabilities in foreign currency assumed to hedge the net investment in foreign entities are not charged to income but rather are recorded as “Transitory differences – foreign currency translation” where the effect from the translation of financial statements into Argentine pesos is also recorded. As required by these new standards, the change is to be applied prospectively and, therefore, affects the comparability of the financial statements.

Inflation

Historically, the Argentine economy has experienced significant volatility, characterized by periods with high levels of inflation. During the 1990s, however, the Argentine economy experienced a period of low inflation levels and, in accordance with professional accounting standards, we suspended the use of the adjustment-for-inflation method from September 1995 to December 2001.

In 2002, in light of the peso devaluation and the economic instability that the country suffered during this year, Argentina experienced a significant increase in inflation (41% and 118.2% measured in terms of the consumer price index and the wholesale price index, respectively).

As a result of the high inflation in 2002, Argentine GAAP reintroduced inflation accounting, which is applicable to financial statements for fiscal years or interim periods ending on or after March 31, 2002. The most important impacts of inflation on results were the effect of exposure of our monetary assets and liabilities to inflation and the restatement in constant currency of our income statement accounts.

Since the second semester of 2002, the economy started to recover and the peso began to appreciate at an accelerated pace, which helped maintain monthly inflation at very low levels. In March 2003, in response to the stabilization of the economy, the CNV, under Resolution No. 441, provided that starting on March 1, 2003, financial statements must be stated in nominal currency. Accordingly, we discontinued inflation accounting and the corresponding restatement of our financial statements. Our financial results as of and for the year ended December 31, 2002 are stated in constant pesos as of March 1, 2003. This method was not in accordance with professional accounting standads effective in the city of Buenos Aires. The CPCECABA, through Resolution No. 287/03 discontinued the application of the restatement method as from October 1, 2003.

In 2004, the consumer price index increased 6.1%. The strong recovery of domestic demand caused an acceleration of retail inflation, due to, in large part, the fluctuations in utility prices. Wholesale inflation in 2004 also showed clear signs of acceleration driven by the high growth pace. The wholesale price index recorded a 7.9% increase during the year, with a significant rise in prices for manufactured product, electric power and mineral products and, to a lesser extent, imported products. Increases in these items contrast with the slight rise in the price of the remaining primary products.

In the past, inflation has materially undermined the Argentine economy and the government’s ability to stimulate economic growth. See “Item 3. Key Information—Risk Factors—Factors Related to Argentina—Inflation may escalate and undermine economic growth in Argentina and adversely affect our financial condition and results of operations.”

Investments in Utility Companies

The new macroeconomic scenario after enactment of the Public Emergency Law impacted the economic and financial balance of utility companies in Argentina. The combined effect of (1) the devaluation of the peso, (2) the unchanged level of revenues due to the pesification of rates and (3) financial debts primarily denominated in foreign currency, adversely affected the utility companies’ financial position, results of operations and ability to fulfill financial obligations.

The Public Emergency Law ordered the pesification of utility rates payable in US dollars, fixing them at the exchange rate of P$1= US$1 and the elimination of certain indexation clauses in utility contracts. In addition, the Public Emergency Law granted the Argentine government broad authority to renegotiate utility contracts, which authority has been extended to December 2005. See “Item 3. Key Information—Risk Factors—Factors Relating to Argentina—The pesification of utility rates has negatively affected and may continue to affect utility companies’ financial position, result of operations and their ability to generate cash.” and “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework.” UNIREN is currently in the process of renegotiating contracts with our affiliates Edesur, TGS, Transener and Transba. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework— Electricity—UNIREN.” Congress has authorized the government to fix utility rates until completion of the renegotiation process. We cannot assure you that these renegotiations will be concluded to the satisfaction of our utility companies.

In light of the adverse conditions faced by utility companies, during 2002, CIESA, TGS and Transener declared default on their debt. TGS has recently concluded a debt restructuring process with its creditors. Transener proposed an exchange offer to its creditors, which in April 2005 was accepted by 98.8% of them. Pursuant to a restructuring agreement entered into on May 19, 2005, Transener has 45 business days to comply with the terms of the exchange offer, otherwise the restructuring agreement may be terminated at creditors’ option. CIESA is currently negotiating with creditors to agree on an extension for its defaulted obligations. See “Item 4. Information About the Company—Hydrocarbon Marketing and Transportation—Gas Transportation-TGS—Our interests in TGS and Corporate Developments” and “Item 4. Information About the Company—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener.”

The impact of the measures taken by the Argentine government on the financial statements of these companies was recognized according to the assessments and estimates conducted by their respective managements. Actual future results might differ from the assessments and estimates so conducted and these differences may be significant.

As of December 31, 2004, the value of our investments in CIESA, TGS and Citelec were P$206 million, P$151 million and P$116 million, respectively. As of December 31, 2003, the value of our investments in CIESA, TGS and Citelec were P$190 million, P$140 million and P$158 million, respectively. As of December 31, 2002, the value of our net investments in CIESA, TGS and Citelec were P$0, P$88 million and P$71 million, respectively.

Our equity interest in CIESA for December 31, 2002 would have accounted for a P$33 million negative shareholders’ equity. However, since we did not assume commitments to making capital contributions or provide financial assistance to CIESA, our shareholding in CIESA was valued at zero, limiting the recognition of related losses to such book value. The book value of such shareholdings was below their recoverable value as of such date.

For further detail in connection with our equity interests and the earnings of our affiliated utility companies see “Discussion of Results—Year ended December 31, 2004 compared to year ended December 31, 2003—Equity in Earnings of Affiliates and Companies under Joint Control” and “Discussion of Results—Year ended December 31, 2003 compared to year ended December 31, 2002—Equity in Earnings of Affiliates and Companies under Joint Control.”

Price Stabilization and Supply

For the purpose of lessening inflationary pressures caused by the sharp devaluation of the peso in 2002, the Argentine government issued a set of regulations aimed at controlling the increase in prices payable by the final customer. These regulations have focused particularly on the energy sector.

•

Gas

Pursuant to the Public Emergency Law, we were precluded from increasing the price of gas sold in the domestic market. As a result of this and the lack of price adjustments since then, we postponed infrastructure, development and exploration investments to add new gas reserves. With respect to existing gas sales agreements entered into with industrial clients, we have gradually and partially renegotiated the terms and conditions of these agreements in order to adjust them to the new economic scenario and have gradually increased sales prices to reflect the effects of peso devaluation. We have also attempted to maximize export opportunities in an effort to capitalize on higher prices offered by foreign markets. As part of these efforts, during the first quarter of 2003, we started exporting gas to Chile from the Austral basin, which accounted for approximately 15% of the total gas produced by us in Argentina during 2004. In order to secure the supply of gas for domestic consumption and thermal generation, in light of the local energy crisis, during 2004, the Argentine government on several occasions imposed restrictions on gas exports. While these measures had a limited effect on the total volume of our exports to Chile during 2004, we cannot be certain of their future impacts with respect to our gas exports to Chile or other foreign markets.

In February 2004, the Argentine government, through Decree No. 181/04, mandated the creation of a plan to increase natural gas prices. In April 2004, we along with the remaining gas producers entered into an agreement with the Argentine government applicable to industrial clients and electricity generation clients that provided for a schedule of gradual increases in gas prices until July 2005, with differential rates per basin. The schedule would increase gas wellhead prices to approximately US$1.07/MMBTU and US$0.90/MMBTU in the Neuquén and Austral basins, respectively, representing a price recovery ranging between 100% and 150%. This recovery is applicable to all sales of gas made to generation companies, and applicable on a pro rata basis to distributors based on each distributor’s percentage of sales made to industrial clients. With respect to lower consumption users, such as residential consumers, the plan calls for the Secretary of Energy to furnish a normalization schedule in order for lower consumption users to be able to pay the final values as determined in the agreement by January, 2007. As of December 31, 2004, average prices were US$0.74/MMBTU and US$0.55/MMBTU for PEPSA’s generation company clients and distributor clients, respectively. The agreement provides for a guarantee of supply until 2006, and each producer has committed to make the necessary investments to reach agreed upon volumes.

•

Hydrocarbons

Aiming to mitigate the impact of the significant increase of WTI on local prices and ensure price stability for crude oil, gasoline and diesel oil, in January 2003, at the request of the Argentine Federal Executive Branch, hydrocarbon producers and refineries entered into a temporary agreement, which required crude oil deliveries to be invoiced and paid based on a WTI reference price of US$28.5 per barrel. Any positive or negative difference between the actual WTI price and the reference price, not exceeding US$36 per barrel, would be paid out of any balances generated in the periods in which the actual WTI price fell below US$28.5 per barrel. Refineries, in turn, reflected the crude oil reference price in domestic market prices, a criterion that was equally applied to determine intercompany transfer prices. After successive renewals, this agreement expired in May 2004. Thereafter, hydrocarbon producers and refineries executed a new agreement that was effective until June 2004, which provided that, while the WTI per barrel ranged between US$32 and US$42, crude oil deliveries would be invoiced and paid considering a reference price equal to: (1) 86% of the WTI as long as such price did not exceed US$36 per barrel, or (2) 80% of the WTI if this price exceeded US$36 per barrel. In August 2004, in light of the WTI having exceeded US$42, the Argentine government established a cap on the domestic price of crude oil equal to the international market price net of the taxes imposed on exports. As from October 2004, hydrocarbon producers and refiners negotiate crude price based on the export parity reference price.

Within this same framework, as part of the effort to prevent inflationary pressure and to discourage exports to ensure local feedstock, on March 1, 2002, the Argentine government imposed a 20% tax on exports of crude oil and a 5% tax on exports of certain oil by-products, which are due to expire in five years. In May 2004, the tax on exports of crude oil and liquified petroleum gas increased to 25% and 20%, respectively, and a 20% tax was levied on exports of natural gas. Effective August 4, 2004, the Argentine government established increases in crude oil export taxes, starting at a rate of 25% if the price per barrel is less than or equal to US$32 with additional increased withholdings ranging from 3% to 20%, depending on whether the price per barrel of crude oil varies from US$32.01 to US$45, with a maximum tax of 45% if the price exceeds US$45.

These measures had an impact on the upstream operations’ profitability and prevented us from capitalizing fully on the benefits derived from a very favorable international price context. The export parity reference price, however, helped our refining business mitigate the effects of increased crude oil prices.

In light of the current scenario, we have redesigned our business strategies to minimize the impact of such measures, giving priority to products with higher margins. With this in mind, we have prioritized crude oil refining and the subsequent sale of refined products in both domestic and foreign markets. Our positioning as an integrated energy company, with growing integration of our upstream and downstream activities and the competitive advantages we have realized through our relationship with Petrobras, are key components of this approach.

As a result, during 2004 and 2003, intersegment sales volumes of crude oil increased 7.2% and 21.6%, respectively, to 34,000 barrels per day and to 31,700 barrels per day, while exports of crude oil in the 2004 to 2002 period declined approximately 75%. In addition, in 2004 and 2003, 466,000 cubic meters and 248,000 cubic meters of refined products were sold to EG3, respectively. As a further result, the sales to EG3 increased the crude oil volumes processed at a profit at the San Lorenzo refinery to levels significantly higher than those recorded over the last few years.

•

Downstream Margins

Downstream margins have significantly declined since the enactment of the Public Emergency Law. As part of their effort to avoid inflationary escalation, the Argentine government exerted strong pressures to limit the passing to the retail level of gasoline and diesel oil, the higher costs derived from higher WTI prices, the peso devaluation and domestic inflation. The application of these measures has resulted in an overall reduction in the sector’s profitability. Since the enactment of the Public Emergency Law, crude oil costs for Argentine operations increased 67.4%, while gasoline and diesel oil average sales prices increased 21% and 46%, respectively.

Notwithstanding the absence of a formal price control policy, many initiatives on the part of other companies within the refining sector aimed at recovering downstream operation profitability, were thwarted by explicit governmental pressures, including efforts aimed at generating strong public opposition to the companies’ initiatives.

Electricity Generation

With respect to electricity generation, following the Public Emergency Law, the Argentine government implemented the pesification of US dollar-denominated prices in the wholesale electricity market and set a price cap for the energy sold in the spot market, which as of 2004 equaled approximately P$40/MWh. This price is determined by the cost of thermal generation regardless of the use of liquid fuels. This change in regulations was a deviation from the marginal cost system that was previously in effect. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Electricity.”

As a result of the Argentine government’s decision to suspend seasonal increases in electricity prices, these prices have failed to reflect total generation costs adequately. This lag led to the gradual depletion of the Stabilization Fund (Fondo de Estabilización), causing an increasing deficit thereof, which in turn prevented CAMMESA from settling accounts with market agents. To address this situation, the Secretary of Energy established a methodology to manage the lack of funds. This consisted in the establishment of an order of cancellation of credits with generation companies. In an effort to restore the Stabilization Fund, between December 2003 and August 2004, the Argentine government made a P$650 million contribution to the fund. In December 2004, the government authorized the National Treasury to grant an additional P$300 million loan. In addition, seasonal adjustments were reinstated for the February-April and August-October 2004 periods, recognizing the greater costs resulting from the recovery of natural gas prices in the determination of wholesale spot prices. Also in December 2004, the Argentine government approved a new increase of approximately 19% in seasonal prices, which became effective in January of 2005.

In order to definitively adjust the Stabilization Fund deficit, the Secretary of Energy created an investment fund called FONINVEMEM. This fund encourages wholesale electricity market creditors to participate in investments in electric power generation in order to increase the available supply of electric power generation in Argentina and achieve sustainability. FONINVEMEM’s funds will be used to expand thermal generation capacity, approximately 1,600 MW, which is estimated to start commercial operations in late 2007. The Secretary of Energy has invited wholesale electricity market’s agents to participate and has determined that credit balances resulting from the spread between the sales price of energy and the generation variable cost for agents who choose not to participate in the creation thereof will be paid subject to the positive cash flows generated by the works constructed with FONINVEMEM’s resources. We have accepted the invitation and will, therefore, participate with 65% of the credit balances recorded for the 2004-2006 period with respect to this spread. Total credit balances contributed by us in the 2004 fiscal year amounted to US$5 million in nominal value. Our estimated total contribution for the 2004-2006 period is projected to be US$35 million, or approximately 8%, of the fund’s capital. The final amount will depend on, among other factors, water conditions, the dispatch of our generation units determined by CAMMESA and the resulting prices of energy.

In order to restore the regular operation of the wholesale electricity market as a competitive market that provides sufficient supply, in December 2004, the Secretary of Energy committed to approve successive seasonal price increases to reach values covering at least total monomic costs by November 2006. In addition, it committed to compensate energy with the marginal price obtained in the spot market and power with the U.S. dollar values that were in effect prior to the enactment of the Public Emergency Law when the market returns to normal conditions after the additional capacity contributed by FONINVEMEM commences commercial operations.

During 2004, for the second consecutive year, the Secretary of Energy decided to make a call for bids for fuel reserve aimed at guaranteeing the supply of electricity. Generation companies are paid an additional amount to the market price for electricity in exchange for guaranteed availability. We participated in the bid receiving an additional price of $12/MWh, which generated total additional income of P$30 million in 2004 and P$17 million in 2003.

Recoverability of Assets

The peso devaluation and the enactment of the Public Emergency Law, in addition to all subsequent events, resulted in a dramatic change in our expectations regarding the future cash flow of certain of our businesses and assets. Considering the prevailing uncertainty regarding Argentina’s economic recovery and the recoverability of certain assets and businesses, we adjusted the book value of certain investments and assets.

Gas areas in Argentina: Due to (1) the strong deterioration of the domestic price of gas in real terms, (2) the limited possibilities of negotiating price increases within the context of the Public Emergency Law and (3) the decline in gas reserve volumes as a result of reduced expenditures, we recorded impairment charges in the amount of P$37 million in 2003 and P$44 million in 2002.

Argentine government bonds: Following the default by Argentina on its sovereign debt, the Argentine government did not allow us to apply the nominal value of “Patriotic” bonds toward the payment of our Argentine federal tax liabilities until a debt exchange was concluded and, therefore, as of December 31, 2002, we created a provision for the decrease in value of our investment in these government bonds in the amount of P$30 million. As of December 31, 2004 this provision amounted to P$23 million.

Tax loss carry forwards: As of December 31, 2003, we maintained a P$1,189 million allowance for tax loss carry forwards. Despite a partial recovery in economic activity, the future course of the economy as of December 31, 2003 was still uncertain, and considering the recent actions taken by the Argentine government, the recoverability of such tax loss carry forwards remained uncertain as of December 31, 2003.

As of December 31, 2004, after taking into consideration profitability expectations in connection with our business plan, we partially reversed this allowance and recorded a P$268 million gain. This reversal was due to, among other factors, expectations of high and sustained prices for commodities, the relative stability of the main macroeconomic variables in Argentina, including positive developments with respect to the recovery of energy prices. As of December 31, 2004, Petrobras Energía maintained a P$855 million allowance for tax loss carry forwards. In the future, our management will continue to evaluate the reversal of some or all of the allowance. This analysis will focus on positive changes in macroeconomic variables, the recovery of the Argentine economy and the progress attained in the resolution of key issues, including the restructuring of Argentina’s sovereign debt and the renegotiation of utility contracts. The tax loss carry forwards can be used until the fiscal year ending December 31, 2007.

Minimum presumed income tax credit: Taking into account the prospects of our results of operations and the uncertainty regarding our ability to use amounts paid under minimum presumed income tax credits for the reduction of our future income taxes, we recorded an allowance which, as of December 31, 2004, amounted to P$72 million, which corresponds to the allowance for the amounts paid as minimum taxes from 1998 to 2002. In 2002, we recorded a P$19 million loss in connection with the amount paid as minimum taxes.

Commodity Prices and Management of Crude Oil Price Risk

Our results of operations and cash flow are exposed to risks related to the volatility of international prices, mainly crude oil and by-product prices. See “Item 3. Key Information—Risk factors—Factors Related to the Company—Decline in oil prices affect the profitability of our operations and capital expenditures.” In addition, while our reporting currency is the Argentine peso, a significant portion of our revenues are denominated in or indexed to the US dollar, reflecting in part the important contribution of exports and foreign operations to our business. Accordingly, changes in the peso exchange rate may have a considerable impact on the prices of the commodities we sell as reported in pesos, thereby affecting our revenues.

In 2004, crude oil prices hit record levels. The WTI closed at US$43.3 per barrel, with an average of US$41.5 per barrel during the year (US$32.4 per barrel and US$31 per barrel, respectively, in 2003 and US$31.2 per barrel and US$26 per barrel, respectively, in 2002). High prices were sustained by both demand and supply factors. Acceleration in world growth, the tension in the Middle East and low inventory levels in the United States, among other factors, led to an escalation of price increases, which does not show signs of a rapid decline. In 2004,

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our average sales prices for crude oil, gasoline, diesel oil, styrene and polystyrene grew 19.4%, 12%, 18%, 41% and 31%, respectively, compared to 2003. In 2003, as compared with 2002, our average prices for crude oil, gasoline, diesel oil and polystyrene rose 4.8%, 16.5%, 7.3% and 2%, respectively, with styrene exhibiting a 9% decline.

In line with the business integration strategy, our risk management policy focuses on measuring our net risk exposure and monitoring the risks that affect our overall portfolio of assets. We use hedging derivative instruments, such as futures, swaps, options and other instruments, to mitigate risks related to results and cash flow volatility as a result of fluctuations in the price of crude oil. In Argentina, as we grow as an integrated energy company, we expect to process more of our crude oil production in our refineries and, therefore, we expect that oil product prices, rather than crude oil prices, will most directly affect our financial results.

On January 1, 2003, Technical Resolutions Nos. 16, 17, 18, 19 and 20 of the FACPCE became effective and introduced material changes in the guidelines regarding the recognition, measurement and disclosure of derivatives and hedging transactions. These new regulations, whose principles are consistent with the international accounting standards issued by the International Accounting Standards Committee, or IASC, provide that derivative financial instruments are recorded at their fair value and allow, on a very restrictive basis, for the implementation of hedge accounting. Under hedge accounting changes in the fair value of derivatives are recognized under “Transitory differences—Measurement of derivative financial instruments designated as effective hedge” and subsequently reclassified to income (loss) for the year or years in which the hedged item affects results. If the financial derivative instrument is not designated as an effective hedge, changes in the accounting measurement of such derivatives are recognized in the income statement under “financial income (expense) and holding gains (losses).” The new regulations permit hedge accounting on a very restrictive basis, since a hedge is deemed effective if at its inception and during its life its changes offset between 80% and 125% of the changes in the hedged item. Notwithstanding our objectives, some of our derivative instruments do not qualify for hedge accounting. Therefore, in connection with instruments not designated as efficient hedges, a significant asymmetry is shown between recognition of gain or losses for the instruments and gains or losses for the items originally hedged. As of December 31, 2004 and 2003, our derivative portfolio consisted solely of instruments that did not qualify for hedge accounting.

In view of the high crude oil prices recorded during 2004, 2003 and 2002, we recognized (1) for instruments that qualify for hedge accounting, reduced sales in the amount of P$81 million in 2003 and P$373 million in 2002, and (2) for instruments that do not qualify for hedge accounting, financial losses of P$687 million in 2004, P$298 million in 2003 and P$470 million in 2002.

As of December 31, 2004, for 2005 we have swaps that do not qualify for hedge accounting in place for 20,000 barrels per day, at an average settlement price of US$19 per barrel. As of December 31, 2004, the fair value of the instruments amounted to US$(170) million. See “Item 11. Quantitative and Qualitative Disclosures About Market Risk.”

Political and Economic Situation in Venezuela

Operations in Venezuela are an important component of our business. In 2004, Venezuela’s oil and gas sales volumes accounted for 31.5% of our total volumes of barrels of oil equivalent, and as of December 31, 2004, a significant percentage of our total combined proved reserves were located in Venezuela. Oil production in Venezuela is strictly controlled by the government through PDVSA. Our operations, therefore, are particularly affected by the political and economic events in Venezuela. See “Item 3. Key Information—Risk Factors—Factors Related to Venezuela.” Additionally, as Venezuela is a member of OPEC, we are subject to the OPEC-mandated production cut decisions, as was the case in 2002.

Since the end of 2002 and throughout 2003, Venezuela faced one of its worst political and economic crises in the last 40 years. On December 2, 2002, a nationwide strike was organized, which included PDVSA. This situation affected the operations of our three fields located in the east of the country (Oritupano-Leona, Mata and Acema), significantly reducing their production. Throughout the first quarter of 2003, oil production average volume dropped by 40.2% to 30,400 barrels per day compared to the same quarter of 2002. After the conclusion of the nationwide strike, the situation gradually recuperated.

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The year 2004 was marked by economic recovery, triggered by high prices of hydrocarbons in the international market and recovery of the national oil production, as well as changes within the political environment after a referendum and regional elections, which provided more political stability to the country. Venezuela’s economy recorded growth of approximately 17% in 2004, and the country’s activity level returned to levels similar to those existing prior to the crisis. The high prices of hydrocarbons and the economic stability experienced in Venezuela throughout 2004 allowed us to carry out our operations smoothly.

Despite the economic improvement in 2004, changes in the Venezuelan legal framework continue to affect our results. The 2001 Hydrocarbons law replaced the Hydrocarbons Law of 1943 and the Nationalization Law of 1975. The new Hydrocarbons Law raised royalties payable by private companies to 20%-30% from the previous 1%-16.66%. Such increase resulted in lower revenues of P$84 million, P$57 million and P$ 60 million in the years 2004, 2003 and 2002, respectively.

In April 2005, the Venezuelan Energy and Oil Ministry instructed PDVSA to review the thirty-two operating agreements signed by PDVSA with oil companies from 1992 through 1997, including agreements with our affiliates in connection with the areas of Oritupano Leona, La Concepción, Acema and Mata. See “Item 4. Information About the Company—Oil and Gas Exploration and Production—Production—Production Outside of Argentina—Venezuela.” The Venezuelan government has instructed PDVSA to take measures within a six-month term to convert all currently effective operating agreements into mixed-ownership contracts in order to grant the Venezuelan government, through PDVSA, more than 50% ownership of each field. The government has further instructed PDVSA to limit the total accumulated payments to contractors during a calendar year to 66.67% of the value of oil and gas produced under the related agreement. We have begun discussions with PDVSA but cannot predict the outcome of these discussions nor their impact on our Venezuelan operations. See “Item 3. Key Information—Risk Factors—Factors Relating to Venezuela— Changes in the regulatory and contractual framework applicable to our operating agreements have and may in the future adversely affect our financial position and results of operations.”

In 2004, 2003 and 2002, we registered a P$15 million, P$27 million and a P$42 million allowance, respectively, for the book value of loans granted to our joint venture partners in Venezuela. As of December 31, 2004, the total allowance amounts to US$35 million. Through these loan agreements, we often provide our joint venture partners with the cash required to comply with their joint venture obligations. These allowances were recorded to reflect our estimate of the recoverable value of these loans, which takes into account that these loans are secured by pledges.

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Agreements in San Carlos and Tinaco

In October of 2002, we entered into an association agreement with Teikoku under which we transferred 50% of our rights and obligations in non-associated gas production in the San Carlos and Tinaco Blocks. As a result of this transaction, we recorded a P$37 million loss. The political and economic crisis that broke out in Venezuela late in 2002 caused the delay of exploratory works in the San Carlos and Tinaco areas. Since as of December 31, 2003, we did not anticipate drilling an additional exploratory well to confirm additional reserves with respect to the San Carlos Block that would have justified performance of infrastructure works for field development, such as gas pipelines and treatment facilities, we charged to income P$29 million attributable to the remaining capitalized investment in the San Carlos Block.

Operations in Ecuador

We operate two fields in Ecuador—Block 18 and Block 31. As of December 31, 2004, we had a 70% and 100% interest, respectively, in these fields. In addition, we had an 11.42% interest in OCP.

In 2000, as a result of the successful drilling of two exploratory wells, heavy crude oil reserves were discovered in Block 31. The significant volume of reserves would have allowed us to complete the wells and turn them into producing wells as long as significant infrastructure investments were made, such as oil pipelines and facilities. Accordingly, in 2001, OCP began to build an oil pipeline to transport production, and the oil pipeline started operations in late 2003. The reductions made to our investment plan as a consequence of the Argentine crisis in 2002 delayed the development of Block 31. In 2003, two additional wells were drilled, which confirmed the potential of this area. Because as of December 31, 2003 drilling of new exploratory wells was not planned for the near future and as of such date no reserves had been proved in Block 31, in accordance with SFAS 19, we (1) charged to income P$106 million of previously capitalized exploratory costs in connection with the drilling of the first two wells and (2) capitalized exploratory costs for wells where less than one year had elapsed since the completion of drilling. During 2004, we charged to income P$80 million of these exploratory costs, as one year had elapsed from completion of drilling.

In August 2004, with the approval by the Ecuadorian Ministry of Energy of the Environmental Impact Studies, all requirements necessary for the approval of Block 31’s development plan were met. Following this approval, a 20-year production period started. As of December 31, 2004, we have proved crude oil reserves in connection in Block 31.

With respect to the exploitation of Blocks 18 and 31, we have an agreement with OCP, whereby we secured an oil transportation capacity of 80,000 barrels per day for a 15-year term, starting on November 10, 2003. Under the ship or pay transportation agreement, we must fulfill our ship or pay contractual obligations in full for the 80,000 barrels per day oil volume commitment and pay, even if no crude oil is transported, a fee covering OCP operating costs and financial services. As of December 31, 2004, this fee amounted to US$2.2 per barrel. Costs in connection with the transportation capacity are invoiced by OCP and charged to expenses on a monthly basis. We have assigned part of our allotted transportation capacity, or approximately 8,000 of our 80,000 barrels per day commitment, for the period starting in July 2004 until January 2012.

We estimate that during the term of our contract with OCP, oil production will be lower than the transportation capacity committed, even after taking into consideration assigned transportation capacity, creating an oil production deficit. Our estimate is based mainly on the forecasted pace of development and revised estimated potential for Block 31. In light of the significant economic effects of this oil production deficit, as of December 31, 2004, we maintained a P$324 million impairment allowance in connection with our group of assets in Ecuador. In 2003 and 2002, we recorded a loss of P$309 million and P$63 million, respectively.

Agreement with Teikoku

In January 2005, we entered into an agreement with Teikoku, whereby, following approval by the Ministry of Energy of Ecuador, we will transfer 40% of our rights and interest in Blocks 18 and 31. In addition, once production in Block 31 reaches an average of 10,000 barrels of oil per day for a period of 30 consecutive days,

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Teikoku has agreed to assume 40% of our rights and obligations resulting from the crude oil transportation agreement entered into with OCP. Allocation of the transportation capacity to Teikoku will enable us to reduce the effects of the oil production deficit under the ship or pay contract. Teikoku, in turn, will pay us US$15 million. In addition, Teikoku has agreed to make investments in Block 31 in excess of its interest in the joint venture, causing accelerated development of the block. Once approval by the Ministry of Energy of Ecuador occurs, our interests in Block 18 would be reduced from our current level of 70% to 30% and our interest in Block 31 would be reduced from 100% to 60%, but we will continue acting as operator for both blocks.

Operations in Peru

In 2004, we, through Petrobras Energía Perú S.A., entered into an agreement with the Peruvian government, whereby we agreed to make investments of about US$97 million in Lote X during the 2004-2011 period. The Peruvian government, in turn, reduced the royalties it receives for hydrocarbon production from a fixed rate of 24% to a variable scheme, starting at rate of 13% applicable when oil prices are up to US$23.9 per barrel and increasing 1.8% every US$5 of increase in the price per barrel. (The royalty rate applicable as of December 31, 2004 was 17.6%.) Investments covered by this agreement include drilling of 51 wells, workover on 526 wells, reactivation of 177 temporarily abandoned wells, and the implementation and expansion of a water injection project.

In light of the significance of this agreement, economic projections in connection with operations in Peru have changed. As a result, in 2004, we recorded a P$31 million gain from the partial reversal of allowances previously recorded in respect of tax loss carry forwards. In addition, proved reserves were added, since as a result of the new royalties regime certain development projects became profitable.

Capital Investments

As a result of the size and complex nature of the crisis that broke out in Argentina and the limited opportunities to access the capital markets, in 2002, we had to take a new approach to our growth strategy, which resulted in great changes to our short and medium-term outlook and has caused us to prioritize cash generation and the maintenance of adequate liquidity levels. Consequently, in that year, our capital investments totaled P$641 million, an amount that was significantly lower than our capital investments in 2001, which were approximately P$1,700 million. During 2002, we also made important divestments of non-core assets amounting to P$593 million, which helped us to finance our capital investments during that year. The reduced pace of investments during 2002 mainly affected oil and gas production volumes and delayed development of new exploitation areas and related production, including the development of Block 31.

In 2003 and 2004, with the recovery of operating cash flow and liquidity at target levels, we readjusted our investment plan. In 2003, we increased capital investments by P$252 million to P$893 million and, in 2004, capital investments increased P$211 million to P$1,104 million. In addition, in line with our long-term strategy to grow as an integrated energy company in Latin America, we have increased our levels of capital investments outside of Argentina, which accounted for about 55% of total investments in 2004.

Our level of capital investments overall is expected to gradually increase in the future.

Divestment of Assets

The following divestments, some of which were consummated as result of the transfer of our control to Petrobras, have helped us to move forward with our strategy of becoming an integrated energy company:

•

In June 2003, we sold to Geodyne Energy Inc., Argentina Branch, a 50% interest in the Faro Vírgenes area concession, accounting for a P$11 million loss. Payments in connection with this transaction will be made during a ten year term, in quarterly installments, with a value in US dollars calculated based on 8.8% of the total quarterly gas production from the Faro Vírgenes area. We have the option of receiving directly this gas production.

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•

In August 2003, we sold to Central International Corporation, Argentine Branch, an 85% interest in the Catriel Oeste area concession. Considering the transfer price (US$7 million), we recorded a P$28 million loss.

•

In July 2002, we sold to Anglogold our 46.25% indirect equity interest in Cerro Vanguardia S.A. and certain related assets. The transaction price amounted to US$90 million, and the operation accounted for a P$123 million gain.

•

In September 2002, we sold to Argentina Farmland Investors LLC our 100% equity interest in Pecom Agropecuaria S.A.’s capital stock. The transaction amounted to US$53 million, accounting for a P$27 million gain.

•

In December 2002, we sold our forestry business assets, including a total area of about 169,000 hectares of forestry land located in the provinces of Misiones, Corrientes and Buenos Aires and a sawmill with 90,000 cubic meters per year capacity. Considering the sale price (US$53 million), we recorded a P$153 million loss.

•

In October 2002, we sold to Sudacia S.A., a company controlled by the Perez Companc Family, a 66.67% equity interest in Conuar, including a 68% interest in Fabricación de Aleaciones Especiales S.A., for US$8 million. No gain or loss was recorded for the sale.

•

In April 2002, under an asset swap, we sold to IRHE (Argentine Branch) and GENTISUR S.A. (a company wholly owned by IRHE) our 50% interest in Pecom Agra with a value of US$30 million, accounting for a P$81 million gain. In return, the parties transferred to us a 0.75% interest in Puesto Hernández UTE, with a value of US$4.5 million, a 7.5% interest in Citelec, with a value of US$15 million, and a 9.187% interest in Hidroneuquén S.A, with a value of US$5.5 million.

Environmental Matters

Quality control, health and safety and environmental protection are integral components of our business. See “Item 4. Information About the Company—Quality, Safety, Environment and Health.”

In 2002, our environmental remediation expenses totaled P$15 million.

In 2003, we retained an international consulting company to conduct an environmental audit of our operations. The final audit report set forth an action plan to enforce our Safety, Environmental and Occupational Health Policy. To execute this action plan, we will make investments of approximately US$23 million to improve, among other things, our prevention systems and production facilities. In addition, we will implement several corrective and remediation actions, for which a P$45 million loss was recorded for the year ended December 31, 2003. Including this figure, in 2003, we recorded expenses of P$58 million for environmental remediation.

In April of 2004, we launched new Quality and Safety, Environmental and Occupational Health policies, each of which represents a change from those principles previously in force. The new Safety, Environmental and Occupational Health policies incorporate cutting-edge concepts, such as eco-efficiency, life cycle and sustainability of the operations. Pursuant to the objectives of these policies, an environmental study was conducted during 2004 as a supplement to the audit performed in 2003. Under the standards of the new Safety, Environmental and Occupational Health policies, the study enabled us to identify the need to apply remediation measures, in relation to which we recorded a loss of P$33 million. Including this figure, in 2004, we recorded expenses of P$51 million for environmental remediation activities.

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DISCUSSION OF RESULTS

The following tables set out net sales, gross profit and operating income for each of our business segments for the years ended December 31, 2004, 2003 and 2002, both including proportional consolidation, which is required by Argentine general accounting standards, and excluding the proportional consolidation of the companies under common control. Our management analyzes our results and financial condition separately from the results and financial conditions of these companies and we believe financial information without proportional consolidation is useful to investors in evaluating our financial condition and results of operations. See “—Proportional Consolidation and Presentation of Discussion” and “—Reconciliation Tables.” Net sales eliminations relate to intersegment sales. Gross profit eliminations relate to adjustments related to intersegment sales and costs associated with such sales.

Substantially all of our intersegment sales are related to sales of oil and gas to our Refining, Petrochemicals and Electricity businesses. The business segment year-to-year comparisons that follow the table do not exclude intersegment sales.

With Proportional Consolidation


	For the year ended, December 31,
	2004		2003		2002
	(in millions of pesos)
Net Sales:⁽¹⁾
Oil and Gas Exploration and Production	3,359		2,729		2,806
Hydrocarbon Marketing and Transportation	861		521		16
Refining	1,745		1,302		1,008
Petrochemicals	1,877		1,294		1,254
Electricity	825		691		766
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(1,693	)	(1,043	)	(744	)

Total	6,974		5,494		5,106

Gross Profit:⁽³⁾
Oil and Gas Exploration and Production	1,765		1,281		1,206
Hydrocarbon Marketing and Transportation	270		240		5
Refining	182		123		64
Petrochemicals	374		312		362
Electricity	197		168		158
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(24	)	(16	)	27

Total	2,764		2,108		1,822

Operating Income:
Oil and Gas Exploration and Production	1,182		861		902
Hydrocarbon Marketing and Transportation	247		205		16
Refining	120		54		—
Petrochemicals	278		185		251
Electricity	122		112		89
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(218	)	(185	)	(131	)

Total	1,731		1,232		1,127

(1)	Royalties with respect to the oil and gas business in Argentina, Peru and Bolivia are accounted for as a cost or production and are not deducted in determining net sales.

(2)	Eliminations correspond to sales between our business units and their associated costs.

(3)	Net sales less cost of sales.

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Without Proportional Consolidation


	For the year ended, December 31,
	2004		2003		2002
	(in millions of pesos)
Net Sales:⁽¹⁾
Oil and Gas Exploration and Production	3,359		2,729		2,806
Hydrocarbon Marketing and Transportation	376		75		16
Refining	1,745		1,302		1,008
Petrochemicals	1,877		1,294		1,254
Electricity	290		244		248
Other Investments and Eliminations⁽²⁾	(1,680	)	(1,029	)	(745	)

Total	5,967		4,615		4,587

Gross Profit:⁽³⁾
Oil and Gas Exploration and Production	1,765		1,281		1,206
Hydrocarbon Marketing and Transportation	20		4		5
Refining	182		123		64
Petrochemicals	374		312		362
Electricity	111		94		50
Other Investments and Eliminations⁽²⁾	(27	)	(16	)	22

Total	2,425		1,798		1,709

Operating Income:
Oil and Gas Exploration and Production	1,182		861		902
Hydrocarbon Marketing and Transportation	32		11		16
Refining	120		54		—
Petrochemicals	278		185		251
Electricity	119		108		57
Other Investments	—		—		—
Corporate and Other Discontinued Investments	(218	)	(185	)	(135	)

Total	1,513		1,034		1,091

(1)	Royalties with respect to the oil and gas business in Argentina, Peru and Bolivia are accounted for as a cost or production and are not deducted in determining net sales.

(2)	Eliminations correspond to sales between our business units and their associated costs.

(3)	Net sales less cost of sales.

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Year ended December 31, 2004 compared to year ended December 31, 2003

Net income: Net income increased P$297 million, or 78%, to P$678 million in 2004 from P$381 million in 2003. Operations for the year were favorably affected by the increase in international crude oil prices, which we were generally able to pass through to prices for the main refined and petrochemical products. As a result, operating income increased significantly. In addition, gains derived from the reversal of certain tax loss carry forward allowances recorded in prior years and a significant decline in other expenses, net had a significant favorable impact on the results for the year. These improvements were partially offset by higher fair value losses derived from derivative instruments that do not qualify for hedge accounting and a decline in equity in earnings of affiliates.

Net sales: Net sales increased P$1,480 million, or 26.9%, to P$6,974 million in 2004 from P$5,494 million in 2003. Sales for 2004 reflect P$485 million and P$535 million, attributable to our share in CIESA and Distrilec’s net sales (net of intercompany sales of P$13 million), respectively. Net sales for 2003 reflect P$446 million and P$447 million, attributable to our share in CIESA and Distrilec’s net sales (net of intercompany sales of P$14 million).

Without proportional consolidation, net sales increased P$1,352 million, or 29.3%, to P$5,967 million in 2004 from P$4,615 million in 2003. The significant increase in the WTI and the related price increases for the main petrochemical and refined products and, to a lesser extent, growth in sales volumes resulted in sales increases in the Oil and Gas Exploration and Production, Petrochemicals and Refining business segments, equal to P$630 million (23%), P$583 million (45%) and P$443 million (34%), respectively (including intercompany sales). The Electricity business segment also experienced sales increases (P$46 million, or 19%, in 2004), predominantly due to improved generation prices. In addition, and due to changes implemented in the way we allocate certain product sales among different business segments, Hydrocarbon Marketing and Transportation sales increased P$301 million. As the business operations continue to integrate, intersegment sales increased to P$1,680 million in 2004 from P$1,029 million in 2003. The majority of these sales are between our Exploration and Production segment and our Refining segment.

Gross profit: Gross profit increased P$656 million, or 31.1%, to P$2,764 million in 2004 from P$2,108 million in 2003. This increase reflects gains of P$250 million and P$86 million, attributable to our share of the gross profit of CIESA and Distrilec, respectively, and P$3 million in eliminations. Gross profit for 2003 reflects gains of P$236 million and P$74 million, attributable to our share of the gross profit of CIESA and Distrilec, respectively.

Without proportional consolidation, gross profit for 2004 grew P$627 million, or 34.9%, to P$2,425 million from P$1,798 million in 2003. This increase in gross profit was due to an increase in the gross profit at each of our business segments, particularly in the Oil and Gas Exploration and Production and Refining segments. Gross profit for the Oil and Gas Exploration and Production segment increased P$484 million, or 37.8%, predominately due to an increase in sales and margins resulting from a 19.4% increase in average sales prices of oil equivalent. Gross profit for our Refining segment increased P$59 million, or 48%, due in large part to the combined effect of increased sales volumes and improved margins. Gross profits for our Petrochemical, Electricity and Hydrocarbon Marketing and Transportation segments also increased 19.9%, 17% and 13% respectively. For more information as to our gross profit for each of our business segments see “—Analysis of Operating Results by Business Segment.”

Administrative and selling expenses: Administrative and selling expenses increased P$81 million, or 14.4%, to P$640 million in 2004 from P$559 million in 2003. The expenses for 2004 reflect P$16 million and P$66 million, attributable to our share of the administrative and selling expenses of CIESA and Distrilec, respectively. The expenses for 2003 reflect P$30 million and P$65 million, attributable to our share of the administrative and selling expenses of CIESA and Distrilec, respectively.

Without proportional consolidation, administrative and selling expenses increased P$94 million, or 20.2%, to P$558 million in 2004 from P$464 million in 2003. This increase is primarily due to the increased scale of operations in Ecuador, higher sales volumes and increased corporate advertising expenses.

Exploration expenses: Exploration expenses decreased P$107 million to P$89 million in 2004 from P$196 million in 2003. During 2004 and 2003, we expensed certain exploratory drilling costs that had been capitalized in prior years. For an explanation of why these expenses decreased in 2004 see “—Analysis of Operating Results by Business Segment—Oil and Gas Exploration and Production.”

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Other operating income (expense), net: Other operating income (expense), net accounted for P$304 million in losses in 2004 compared to P$121 million in losses in 2003. Other operating income (expense), net for 2004 reflects losses of P$19 million and P$17 million, attributable to our share of CIESA and Distrilec, respectively, and P$3 million in eliminations. Other operating income (expense), net for 2003 reflects losses of P$12 million and P$5 million, attributable to our share of other operating income (expense), net of CIESA and Distrilec, respectively.

Without proportional consolidation, other operating income (expense), net accounted for losses of P$265 million for 2004 and P$104 million for 2003. This increase in losses is mainly attributable to expenses for unused transportation capacity in connection with the ship or pay contract with OCP in the amount of P$184 million. Since November 2003, we have become obligated to pay for transportation capacity to OCP. See “—Factors Affecting Our Consolidated Results of Operations—Operations in Ecuador.”

Operating income: Operating income grew P$499 million, or 40.5%, to P$1,731 million in 2004 from P$1,232 million in 2003. Operating income for 2004 reflects P$215 million and P$3 million, attributable to the share of operating income of CIESA and Distrilec, respectively. Operating income for 2003 reflects P$194 million and P$4 million, attributable to the share of operating income of CIESA and Distrilec, respectively.

Without proportional consolidation, operating income increased P$479 million, or 46.3%, to P$1,513 million in 2004 from P$1,034 million in 2003. The increase in operating income principally was a result of increased gross profit in the Oil and Gas Exploration and Production segment. For a detailed discussion of our operating income at each of our segments see “-Analysis of Operating Results by Business Segment.”

Equity in earnings of affiliates: Equity in earnings of affiliates decreased P$87 million, or 53.4%, to P$76 million in 2004 from P$163 million in 2003. Without proportional consolidation, equity in earnings of affiliates decreased P$292 million, or 78.7%, to P$79 million in 2004 from P$371 million in 2003. This decline was primarily due to the effects of peso appreciation in 2003 (compared to dramatic peso depreciation in 2002) on the net borrowing position of our affiliates utility companies, which is predominately denominated in US dollars. This was partially offset by increased equity earnings from EBR and Refinor in the amount of P$23 million and P$12 million, respectively. See “—Equity in Earnings of Affiliates and Companies under Joint Control.”

Financial income (expense) and holding gains (losses): In 2004, our financial expenses and holding losses increased P$844 million, or 202%, to P$1,261 million in 2004 from P$417 million in 2003. Financial expenses and holding losses for 2004 reflects financial expenses of P$144 million and P$20 million, attributable to the share of the financial income (expense) and holding gains (losses) of CIESA and Distrilec, respectively. Financial expenses and holding losses for 2003 reflects financial income in the amount of P$123 million and P$28 million, attributable to the share of the financial income (expense) and holding gains (losses) of CIESA and Distrilec, respectively.

Without proportional consolidation, financial income (expense) and holding gains (losses) reflected losses of P$1,097 million in 2004 and P$568 million in 2003. The increase in 2004 is principally attributable to the following:

•

An increase in losses resulting from the valuation at fair value of derivative instruments that do not qualify for hedge accounting, to P$687 in 2004 from P$294 million in 2003 (This increase reflects principally a 53.9% increase in the futures curve of crude oil prices during 2004, as compared to a 1.8% increase in 2003);

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The impact of the evolution of the exchange rate between the peso and US dollar (1.3% and 11.8% appreciation in 2004 and 2003, respectively) and the inflation rate on our net borrowing position, which together resulted in a P$19 million loss in 2004 compared to a P$136 million gain in 2003; and

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•

An offsetting decrease in interest expense in the amount of P$420 million in 2004, or 1.6%, from P$427 million in 2003, reflecting a decline in our US dollar-denominated average indebtedness.

Other expenses, net: Other expenses, net equaled losses of P$27 million in 2004 and P$421 million in 2003. In 2004, other expenses, net reflect a P$14 million loss, attributable to our share of the other expenses, net of CIESA and a gain of P$18 million, attributable to the share of the other expenses, net of Distrilec. In 2003, other expenses, net reflect losses of P$1 million and P$12 million, attributable to our share of the other expenses, net of CIESA and Distrilec, respectively.

Without proportional consolidation, other expenses, net accounted for losses of P$31 million in 2004 and P$408 million in 2003.

The other expenses, net for 2004 primarily reflect the following:

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P$12 million impairment charge for the Acema area, in Venezuela; and

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P$15 million allowance on the book value of loans granted to joint venture partners in Venezuela (see “—Factors Affecting Our Consolidated Results of Operations—Political and Economic Situation in Venezuela.”

The other expenses, net for 2003 primarily reflect the following:

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P$309 million impairment charge for the operations in Ecuador (see “—Factors Affecting Our Consolidated Results of Operations—Operations in Ecuador”);

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P$39 million loss attributable to the sale of oil and gas areas (see “—Factors Affecting Our Consolidated Results of Operations—Divestment of Assets”);

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P$37 million impairment charge for oil production areas (see “—Factors Affecting Our Consolidated Results of Operations—Economic and Political Developments in Argentina—Recoverability of Assets”); and

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P$27 million allowance for the book value of loans granted to joint venture partners in Venezuela (see “—Factors Affecting Our Consolidated Results of Operations—Political and Economic Situation in Venezuela”).

Income Tax: Income tax accounted for a gain of P$198 million in 2004 compared to a loss of P$18 million in 2003. Income tax in 2004 reflects losses of P$6 million and P$20 million, attributable to our share of the income tax of CIESA and Distrilec, respectively. The income tax charge for 2003 reflects a gain of P$58 million, attributable to our share of the income tax of CIESA, and a P$29 million loss, attributable to our share of the income tax of Distrilec.

Without proportional consolidation, income tax accounted for a gain of P$224 million in 2004 compared to a loss of P$47 million in 2003. As of December 31, 2004, after taking into consideration the profitability expectations arising from our business plan, we partially reversed an allowance for tax loss carry forwards and recognized a gain of P$268 million. See “—Factors Affecting Our Consolidated Results of Operations—Recoverability of Assets.” In addition, Petrobras Energía Perú S.A. recorded a gain of P$31 million from the reversal of tax allowances, derived from improved economic expectations for Lote X. See “—Factors Affecting Our Consolidated Results of Operations—Operations in Peru.”

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Analysis of Operating Results by Business Segment

Oil and Gas Exploration and Production

In 2004, international prices were highly favorable for our Oil and Gas Exploration and Production business segment. The WTI averaged US$41.4 per barrel, which was 33% higher than the average price in 2003. In Argentina, however, large increases in taxes on crude oil exports during 2004 partially offset increases in both domestic and export oil prices. In Argentina, the market price applied to crude transfers to the refining industry is based on the export parity reference price.

Operating income: Operating income for the Oil and Gas Exploration and Production business segment increased P$321 million, or 37.3%, to P$1,182 million in 2004 from P$861 million in 2003. This increase was predominately due to the 19.4% rise in average sales prices of oil equivalent resulting from (1) the 33.1% increase in the WTI, and (2) the absence of derivative financial instruments qualifying for hedge accounting in 2004. This increase, however, was partially offset by charges derived from the ship or pay crude oil transportation agreement with OCP that accounted for a loss of P$184 million in 2004.

Net sales: Net sales for the Oil and Gas Exploration and Production business segment increased P$630 million, or 23.1%, to P$3,359 million in 2004 from P$2,729 million in 2003. This increase was predominately due to 19.4% increase in the average sales price of oil equivalent and, to a lesser extent, to a 2.7% increase in volume sales of oil equivalent.

In 2004, daily oil and gas sales volumes increased to 162,200 barrels of oil equivalent from 157,900 barrels of oil equivalent in 2003. Oil sales volumes increased to 115,500 barrels per day, or 3.9%, in 2004 from 111,200 barrels per day in 2003, while gas daily volumes remained substantially unchanged, totaling 280.4 million cubic feet in 2004 and 280.0 million cubic feet in 2003. As discussed below, volume sale increases arose from sales outside Argentina. In 2004, the average sales price per barrel of oil, including the effects of hedging transactions and taxes on exports, increased 19.7% to P$73.2 from P$61.2, due to the increase in the WTI.

During 2004, none of our derivative instruments qualified for hedge accounting, and as a result we did not record any decreases in sales from these instruments. The crude oil hedging policy accounted for an opportunity cost of P$85 million in 2003.

Net sales in Argentina: In 2004, overall sales in Argentina increased by P$217 million, or 14.1%, to P$1,755 million from P$1,538 million in 2003. Combined oil and gas daily sales volumes decreased 6.6% to 84,500 barrels of oil equivalent in 2004 from 90,400 barrels of oil equivalent in 2003.

Crude oil sales increased by P$207 million, or 14.8%, to P$1,608 million in 2004 from P$1,401 million in 2003. This increase was due to a 26% increase in the average sales price to P$88.1 per barrel in 2004 from P$69.8 per barrel in 2003, which, in turn, was predominately caused by (1) the increase of the WTI and (2) the absence of derivative instruments qualifying for hedge accounting in 2004. Our ability to benefit from the WTI increase was limited by the export tax regime in Argentina and the transfer price agreements with refiners in Argentina.

During 2004, we were able to mitigate the impact of the increase in export taxes by transferring more crude oil to our downstream operations in Argentina. As a result, we experienced a 75% decline in export volumes in 2004 as compared to 2003 and taxes on exports decreased to P$26 million from P$60 million in 2003.

Daily oil sales volumes declined 9.3% to 49,900 barrels in 2004 from 55,000 barrels in 2003, predominately because our Argentine assets are mature assets, which are under production through secondary recovery methods and, therefore, experience considerable natural declines. In order to address this, we made significant investments in 2004, mainly in projects aimed at improving the fields’ production, which allowed us to mitigate this decline.

Total gas sales increased 7.3% to P$147 million in 2004 from P$137 million in 2003, mainly as a result of a 9.6% increase in the average sales price, which was partially offset by a 2.5% decline in sales volumes. The

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average sales price for gas increased to P$1.93 per million cubic feet in 2004 from P$1.76 per million cubic feet in 2003, mainly as a consequence of the April 2004 agreement between gas producers and the Secretary of Energy of Argentina, which allowed for natural gas price increases and the renegotiation of contracts. The effect of these domestic price increases was mitigated by an 11% decrease in exports volumes, resulting from export limitations imposed by the Argentine government in response to the energy crisis. Domestic gas sales are made at lower prices than export sales.

Daily gas sales volumes declined 2.3% to 207.9 million cubic feet in 2004 as compared to 2003, primarily due to the decline in demand associated with the shutdown of Genelba for maintenance works during November 2004, and repair works to the gas treatment equipment at the Austral basin fields.

Net Sales Outside of Argentina: In 2004, combined oil and gas sales outside of Argentina increased P$413 million, or 34.7%, to P$1,604 million from P$1,191 million in 2003. Total oil and gas sales volumes increased 15.3% to 77,700 barrels of oil equivalent per day in 2004 from 67,400 barrels of oil equivalent per day in 2003. The average sales price of oil equivalent per barrel increased 15.5% to P$55.8 in 2004 from P$48.3 in 2003, mainly due to the increase in the WTI and the absence of derivative instruments qualifying for hedge accounting in 2004.

The following is an overview of 2004 sales figures for each country in which we have oil and gas operations:

Venezuela: In Venezuela, oil and gas sales increased P$217 million, or 36.6%, to P$811 million in 2004 from P$594 million in 2003. In 2004, the average price per barrel of oil was P$46.5, which was a 15.1% increase from P$40.4 in 2003. This change was predominately attributable to the increase in the WTI. The impact of the WTI increase was limited by the compensation formula contained in the third round operating agreements, which sets the price of crude as a function of the operating income of oil producing companies. The average price for gas decreased 35.5% to P$1.20 in 2004 from P$1.86 per million cubic feet in 2003 as a consequence of a decrease in the reference price in Venezuela, which is regulated by the government.

Daily sales volumes of oil equivalent increased 19.9% to 51,300 barrels of oil equivalent in 2004 from 42,800 barrels of oil equivalent in 2003, due to the magnitude of our investments in Venezuela and the adverse impact on our 2003 production of the oil strike in the beginning of 2003. In 2004, 23 wells were drilled, 63 repair works were performed and 5 conversions were made in Venezuela, mainly in the Oritupano-Leona and La Concepción oil fields. Our maintenance works included 22 extraction improvements as well as investments made to overhaul our surface and sub-surface equipment.

Ecuador: In Ecuador, oil sales increased 81.7% to P$209 million in 2004 from P$115 million in 2003. Investments made in Block 18, which include drilling of four wells and construction of surface facilities, contributed to a 47.9% increase in daily oil sales volumes to 5,800 barrels per day. The average sales price increased 25.1% to P$99.1 per barrel from P$79.2 per barrel mainly due to the rise in the international reference price (Oriente crude oil). The increase in the Oriente crude oil reference price during 2004 was lower than that of the WTI due to an increased discount for this type of crude oil.

Peru: In Peru, oil and gas sales increased P$84 million, or 22.5%, to P$458 million in 2004 from P$374 million in 2003, mainly as a result of a 24% increase in the sales price of oil equivalent.

The average crude oil price increased 27.1% to P$105.4 per barrel from P$82.9 per barrel, as a result of changes in the international reference price (Oriente crude oil). The average gas price decreased 24.4% to P$5.12 from P$6.77 per million cubic feet as a consequence of the increase in gas supply resulting from the entry in the gas market of sales from the Camisea field, which is the most important gas reserve in Peru and one of the most important gas reserves in Latin America.

Daily sales volumes of oil equivalent decreased by 0.8% to 12,900 barrels per day in 2004 from 13,000 barrels per day in 2003.

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Bolivia: In Bolivia, oil and gas sales did not suffer significant changes between 2004 and 2003, amounting to approximately P$108 million in both periods. Combined oil and gas daily sales volumes increased by 1.0% to 7,800 barrels of oil equivalent in 2004 compared to 2003. The average sales price for gas remained at P$5.23 per million cubic feet from year to year.

Gross profit: Gross profit for this business segment increased by P$484 million, or 37.8%, to P$1,765 million in 2004 from P$1,281 million in 2003. The margin on sales increased to 52.5% from 46.9% in 2003. This increase in margin was mainly attributable to the 19.4% increase in average sales prices of oil equivalent. Average lifting costs increased 9.9% to P$8.46 per barrel of oil equivalent in 2004 from P$7.70 per barrel of oil in 2003, mainly due to an increase in fees for oil services and electric power rates and to incremental costs associated with new safety and environmental standards. The price increase was mitigated by increased royalties paid in Argentina, which are determined on the basis of pre-tax sales and consequently are not affected by the increases in export taxes.

Administrative and selling expenses: Administrative and selling expenses increased P$34 million, or 19.1%, to P$212 million in 2004 from P$178 million in 2003. This increase was mainly attributable to the impact of the rise in sales volumes in Ecuador and, to a lesser extent, an increase in labor costs.

Exploration expenses: Exploration expenses totaled P$89 million in 2004 and P$196 million in 2003. Expenses for 2004 were mainly attributable to the expensing of exploratory drilling costs in Block 31 for P$80 million. In addition, exploration expenses during 2004 reflect expenses in connection with seismic works in the Santa Cruz I Oeste area in Argentina for P$6 million.

In 2003, we expensed previously capitalized exploratory investments in Block 31 in Ecuador and the San Carlos area in Venezuela in the amount of P$141 million (including P$35 million for costs of feasibility studies) and P$29 million, respectively, and we also expensed costs of non-producing exploratory wells drilled in Santa Cruz II and Lote XVI in Peru and the seismic works related to such wells.

Other operating income (expense), net: Other operating income (expense), net accounted for losses of P$282 million in 2004 and P$46 million in 2003. Losses for 2004 are mainly attributable to costs associated with the unused transportation capacity under the ship or pay contract with OCP in Ecuador (P$184 million), environmental remediation expenses (P$51 million), project discontinuance (P$5 million) and losses derived from contract renegotiation (P$10 million). Losses in 2003 include P$26 million for environmental remediation expenses and P$32 million for other allowances. Losses in 2003 were partially offset by the favorable resolution of commercial claims in Venezuela.

Hydrocarbon Marketing and Transportation

Our results for this segment in 2004 and 2003 reflect the proportional consolidation of CIESA. See “—Proportional Consolidation and Presentation of Discussion.”

In 2004, we implemented changes in the way we allocate certain product sales among different business segments. As a result, the Hydrocarbon Marketing and Transportation business segment now sells the gas produced in Argentina and the liquids obtained from gas processing, which are transferred to it at market prices from the Oil and Gas Exploration and Production segment. In addition, the Hydrocarbon Marketing and Transportation business segment’s operations include gas and liquified petroleum and gas brokerage activities, which were previously provided by our Exploration and Production business segment. Also, as of 2004, oil brokerage services are now provided through our Refining business segment. As a result of these changes, we have been able to expand our commercial opportunities to strengthen the profitability of our operations.

Operating income: Operating income for the Hydrocarbon Marketing and Transportation business segment increased P$42 million, or 20.5%, in 2004 to P$247 million from P$205 million in 2003. The 2004 operating income reflects gains of P$215 million in 2004 and P$194 million in 2003, attributable to the proportional consolidation of CIESA. Without proportional consolidation, the operating income for this business segment increased by P$21 million, or 190.9%, in 2004 to P$32 million from P$11 million in 2003, reflecting principally increased net sales.

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Net sales: Sales revenues without proportional consolidation increased P$301 million to P$376 million in 2004 from P$75 million in 2003, due to the reallocation of certain activities among business segments discussed above. In 2004, revenues from the sale of gas and liquids produced by us totaled P$158 million and P$193 million, respectively. Sales volumes of gas produced by us in Argentina totaled 205.5 million cubic feet per day, and sales volumes of liquids amounted to 232,000 tons. Gas and liquified petroleum and gas brokerage services accounted for P$25 million and P$75 million in sales revenues during 2004 and 2003, respectively.

Gross profit: As a consequence of the segment reallocation changes implemented in 2004, gross profit without proportional consolidation increased P$16 million to P$20 million in 2004 from P$4 million in 2003.

Other operating income (expense), net: Other operating income (expense), net derived from technical assistance rendered to TGS without proportional consolidation accounted for gains of P$18 million in 2004 and P$11 million in 2003. Prior to July 2004, Enron was TGS’s technical operator, and we were reimbursed by costs incurred by us in connection with these services. As from July 2004, pursuant to an assignment entered into with Enron (See “Item 4. Information About the Company—Hydorcarbon Marketing and Transportation—Gas Transportation-TGS—Our Interests in TGS and Corporate Developments”), we are providing technical assistance to TGS for, among other things, the operation and maintenance of TGS’s gas transportation system and facilities and related equipment. These services are provided with a view to ensuring that TGS’s operations comply with international standards. TGS, in return, pays monthly fees, which are based on its results and must annually exceed a minimum amount.

Refining

As previously mentioned, in 2004, we implemented changes in the way we allocate certain of the product sales among different business segments. As a result, as of 2004, the Refining business segment provides oil brokerage-related services, which were previously provided by the Hydrocarbon Marketing and Transportation business segment. These operations accounted for P$46 million in sales revenues during 2004.

Operating income: Operating income for the Refining business segment increased P$66 million, or 122.2%, to P$120 million in 2004 from P$54 million in 2003. This increase was primarily due to the significant increase in prices of refined products, following the dramatic increase in crude oil international prices. The impact of the WTI increase on the costs of this segment’s sales was mitigated predominately by the set of regulations and taxes issued by the Argentine government aimed at controlling the increase in prices payable by the final customer. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Petroleum.”

Net sales: Net sales of refinery products increased P$443 million, or 34%, to P$1,745 million in 2004 from P$1,302 million in 2003. This increase was primarily a result of significant price increases and, to a lesser extent, an 8% average rise in sales volumes and the reallocation of the oil brokerage activities to this segment.

Average sales prices of benzene, heavy distillates, paraffins, aromatics, diesel oil, medium distillates, gasolines, reformer plant by-products and asphalts increased 83%, 24%, 21%, 20%, 18%, 16%, 12%, 4% and 4%, respectively, mainly as a result of the significant increase in crude oil international prices.

Benefiting from the competitive advantages derived from the integration of our upstream and downstream operations, as well as, those resulting from the complementary nature of our businesses with Petrobras’ companies, especially EG3, during 2004, we were able to refine increased volumes of crude oil. This assisted us in mitigating the effects of the export tax regime on crude oil production activities and in enhancing the chain value of our businesses. In 2004, crude oil volumes processed at the refinery increased 5.9% to 33,129 barrels per day.

Domestic sales volumes increased 12% in 2004 compared to 2003, primarily due to diesel oil and premium gasoline sales to EG3. Export sales volumes increased 3%, primarily as a result of an increase in gasoline sales.

Total diesel oil sales volumes increased 3.4% to 913,000 cubic meters in 2004. This increase was due to a 7% increase in sales to the domestic market, which was partially offset by a decline in exports. Sales increased in

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Argentina, predominately due to increased sales to EG3 and, to a lesser extent, increased demand from the agricultural sector. We have been increasingly taking advantage of the synergies from the integration of our operations with EG3. Because the volume of diesel oil produced by us at our San Lorenzo refinery exceeds the demand of our gas station network, we have continued selling diesel oil to EG3. In 2004, diesel oil sales volumes reached 382,000 cubic meters, significantly more than the 210,000 cubic meters in 2003. EG3, in turn, has continued to sell us its surplus of gasoline.

Growth in the diesel oil domestic market combined with the decision to sell diesel oil to EG3, resulted in a decrease in our diesel oil domestic market share to 3.5% in 2004 compared to our market share of 4.7% in 2003.

Total gasoline sales volumes increased 74% to 207,000 cubic meters in 2004, due to increased sales to the domestic market including sales of our premium gasoline “Podium” to EG3. Our market share was 3.4% in 2004 and 3.1% in 2003. During the middle of 2004, we launched Podium, the gasoline with the highest octane rating in the Argentine market. Podium has been well received by the market and by the end of 2004, had surpassed sales of the premium gasoline it replaced (Magnum) by 54%. This figure exceeded our expectations, and Podium has improved our overall performance in the premium gasoline segment.

Asphalt sales volumes grew 33.8% in 2004 and the market share in the road asphalt segment increased to 24.6% in 2004 from 23.6% in 2003. Domestic market sales increased 59.2%, as a result of an increase in road construction in Argentina, where we have served as provider of asphalt products in various projects, such as, National Road 43, the Buenos Aires–Córdoba highway, the Rosario–Buenos Aires highway and the Rosario–Victoria Bridge. Increased sales to the domestic market resulted in a reduction in export levels, predominately to Paraguay and Bolivia.

Sales volumes of heavy distillates increased 4.5% in 2004, primarily due to a 24.1% growth in the domestic sales market, particularly in fuel oil sales to thermal power plants. Exports declined 3.6%, as a result of reduced fuel oil and Ifos sales (“Ifos” are a mixture of several refined products), partially offset by increased cracking feedstock sales.

Sales volumes for reformer plant by-products declined 3.6% in 2004, generally due to reduced liquified petroleum gas exports. Aromatics sales volumes declined 22.5% in 2004, while paraffins sales volumes increased 8.6%, mainly due to export opportunities.

Gross profit: Gross profit increased P$59 million, or 48%, to P$182 million in 2004 from P$123 million in 2003, due in large part to the combined effect of increased sales volumes and improved margins. Gross margin on sales increased to 10.4% in 2004 from 9.4% in 2003.

In order to optimize the marketing margins, we focused on products and distribution channels with higher profit margins. In addition, the agreements entered into between producers and refineries for price stability allowed us to mitigate the 33% average increase of the WTI. As a result, sales prices increased an average of 21% in 2004, compared to an 18.2% increase in the average cost of crude oil processed to P$95.4 per barrel from P$80.7 per barrel.

Administrative and selling expenses: Administrative and selling expenses increased 5.3% to P$60 million in 2004 from P$57 million in 2003, primarily due to an increase in variable expenses for marketing activities.

Other operating income (expense), net: Other operating income (expense), net recorded losses of P$2 million in 2004 and P$12 million in 2003. When we do not operate at full capacity, we do not expense all of our fixed costs to production. Instead the portion that is not absorbed by our products is expensed as other operating expenses, net. In 2003, the under-absorption of fixed costs resulted in a P$6 million loss. This reflects our policy of monitoring and controlling the volume of processed crude oil with a view to maximizing the margins of our refined products. In addition, a P$8 million loss was recorded in connection with required environmental remediation activities.

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Petrochemicals

Industry Overview: With respect to the styrenics business, and in line with the upward trend in oil prices, 2004 was characterized by high international prices for both finished products and major raw materials. Styrene, polystyrene and benzene (main feedstock) international prices showed increases of 50%, 46% and 87%, respectively. The international spreads for styrene and polystyrene grew 16% and 18%, respectively.

In Brazil, in 2004, the demand for styrene and polystyrene increased 14% and 15% respectively, boosted by the economic recovery.

The demand for styrenics in the domestic market increased significantly in Argentina during 2004 — 30% for styrene, 14% for polystyrene and Bops and 20% for synthetic rubber. This increase was predominately due to economic growth, which fueled demand for these products.

The Mercosur region and Chile continued to show a deficit status in terms of styrene supply, while, in contrast, polystyrene recorded a significant supply surplus, due to installed production capacity increases in Brazil.

In the fertilizers business, international prices for urea increased to US$175 per ton, or 25.9%, in 2004 from an average of US$139 per ton in 2003, due to an increase in demand in the southeast of Asia and a decrease in global supply as a result of the high costs of natural gas in the major manufacturing centers of urea around the world.

Total demand for fertilizers in Argentina recorded a significant increase of 31% in 2004, due to an increase in international prices of grains during the first semester of 2004, which fostered agricultural production in the country, a greater use of nutrients and improved yields.

Operating income: Operating income for the Petrochemical business segment increased P$93 million, or 50.3%, to P$278 million in 2004 from P$185 million in 2003, predominately due to gross profit increases and the recognition of tax benefits derived from Innova’s operations.

Net sales: Net sales (net of eliminations in the amount of P$39 million and P$5 million) increased P$583 million, or 45.1%, to P$1,877 million in 2004 from P$1,294 million in 2003, primarily due to increased sales prices and, to a lesser extent, increased sales volumes.

Styrenics - Argentina: Sales of styrenics in Argentina increased P$181 million, or 37.3%, to P$666 million in 2004 from P$485 million in 2003, primarily due to price increases. These sales amounts include exports to Innova in the amount of P$39 million in 2004 and P$5 million in 2003.

In 2004, in line with increases with international reference prices, average sales prices for the business segment increased 31% compared to 2003, with increases of 50%, 30% and 16% for the styrene, polystyrene and synthetic rubber lines, respectively.

Styrenics sales volumes increased 5.4% to 195,000 tons in 2004 compared to 2003, predominately due to higher ethylbenzene export volumes (approximately 10,000 tons) to Innova, as a result of the start up of the San Lorenzo ethylene plant.

As the Argentine market recovered, we made changes in sales channels in order to prioritize higher-margin domestic market sales over exports. As a result, styrene sales volumes in the domestic market increased 30%, but we experienced a 38% decline in exports, particularly to Chile, Uruguay and Peru.

Along these lines, polystyrene sales volumes increased an average of 7%, with a 14% increase in the domestic market and a 2% decline in exports. Exports were made mainly to Chile and Uruguay (polystyrene) and the United States and Europe (Bops).

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Synthetic rubber sales volumes increased 5.8%, with 20% average growth in the domestic market, in 2004, due to an increased demand for products derived from import substitution. This resulted in a 5% increase in our share of the Argentine styrene butadiene rubber market. (“Import substitution” refers to the production of domestically produced products that become substitutes for products that were previously available predominantly through imports.) Exports decreased 4% in 2004 compared to 2003. Export sales were made mainly to Brazil, Chile and Peru.

Styrenics-Brazil - Innova: Innova sales increased P$271 million, or 54%, to P$773 million in 2004 from P$502 million in 2003, mainly due to the effect of higher prices and, to a lesser extent, to increased sales volumes. In 2004, styrene and polystyrene prices increased 41% and 33%, respectively. The increase in sales volumes (up 13.5% in 2004) was due to an increase in demand as a result of the economic recovery in Brazil and problems experienced at our competitor’s production plants in 2004. The sales strategy implemented in 2004 focused on the domestic market, which offered higher margins as compared to exports and, partially as a result of these efforts, styrene and polystyrene sales volumes increased 11% and 16%, respectively. Export sales of polystyrene increased 10% compared to 2003, mainly due to increased sales to the United States and Africa.

Fertilizers: Fertilizer sales increased P$165 million, or 52.9%, to P$477 million in 2004 from P$312 million, due to the combined effect of (1) a 31% increase in sales volumes, resulting from higher fertilizer consumption attributable to the strong growth in the agricultural industry and commercial restructuring which extended sales areas, and (2) a 18% price increase, in line with changes in the WTI.

Gross profit: Gross profit increased P$62 million, or 19.9%, to P$374 million in 2004 from P$312 million in 2003. Gross margin on sales decreased to 19.9% from 24.1% in 2004, reflecting the impact of the increase in the international prices for the segment’s raw materials and, to a lesser extent, an increase in production costs.

Styrenics - Argentina: Gross profit increased P$3 million, or 2.3%, to P$132 million in 2004 from P$129 million in 2003. Gross margin on sales decreased to 19.8% from 26.6%, primarily due to the increase in benzene prices and higher fixed production costs associated with the start up costs of the new San Lorenzo ethylene plant.

Styrenics - Brazil: Gross profit increased P$40 million, or 44.9%, to P$129 million in 2004 from P$89 million in 2003. Increased gross profit was predominately due to significant price improvement. Gross margin on sales declined to 16.7% from 17.7% as a consequence of increases on the price of raw materials, mainly benzene.

Fertilizers: Gross profit increased P$19 million, or 20.2%, to P$113 million in 2004 from P$94 million in 2003, while gross margin decreased to 23.7% from 30.1%. The increase in gross profit was attributable to increased sales volumes and improved prices, while the decrease in gross margin reflects higher costs of imported products for resale and the increase in the rate of gas.

Administrative and selling expenses: Administrative and selling expenses increased P$13 million, or 11.8%, to P$123 million in 2004 from P$110 million in 2003, primarily due to higher expenses derived from increased sales volumes and the start up of the San Lorenzo ethylene plant.

Other operating income (expense), net: Other operating income (expense), net recorded a gain of P$27 million in 2004 compared to a loss of P$17 million in 2003. The gain in 2004 is attributable to the collection of tax benefits granted by the Rio Grande do Sul State, Brazil, to companies operating in that state. The loss in 2003 is predominately due to the impact of environmental remediation expenses.

Electricity

Our results for this segment in 2004 and 2003 reflect the proportional consolidation of Distrilec. See “—Proportional Consolidation and Presentation of Discussion.”

Operating income: Operating income for the Electricity business segment increased P$10 million, or 8.9%, to P$122 million in 2004 from P$112 million in 2003. Operating results reflect gains of P$3 million in 2004 and P$4 million in 2003, due to our share of the operating income of Distrilec. Excluding proportional consolidation, operating income increased to P$119 million in 2004 from P$108 million in 2003, reflecting increased sales margins in generation activity.

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Electricity generation

Net sales: Net sales of electricity generation increased P$45 million, or 19.1%, to P$280 million in 2004 from P$235 million in 2003, primarily due to a 17% improvement in generation prices. Our competitive advantages resulting from being an integrated energy company and operating both thermal and hydroelectric generation plants allowed us to capitalize on market opportunities and keep operation levels similar to those of 2003, in spite of shutdowns to Genelba during major maintenance works in 2004.

The increase in energy prices was primarily attributable to (1) higher demand for energy within a context of lower water flows at the different basins and gas supply restrictions, which resulted in energy deliveries by less efficient plants, (2) the passing through of increased gas costs to sales prices as a result of a price plan implemented during the fourth quarter of 2004, and (3) higher compensation for guaranteed supply to the electricity market, because the Secretary of Energy guarantees a price in excess of market price for guaranteed availability by generation companies.

Net sales attributable to Genelba increased P$28 million, or 14.3%, to P$224 million in 2004 from P$196 million in 2003, primarily due to improved generation prices. The average sales price increased 13.8% to P$45.4 per MWh in 2004 from P$39.9 per MWh in 2003. Payment of additional compensation for guaranteed supply to the electricity market reflected increased sales of P$30 million in 2004 and P$17 million in 2003. Energy delivered remained almost unchanged in both years, 4,931 GWh in 2004 and 4,918 GWh in 2003. A significant generation increase was recorded during the first three quarters of 2004. During that period, the integration of operations with the Oil and Gas Exploration and Production business segment was a key factor in overcoming gas supply restrictions faced by thermal plants in 2004. This increase was offset by reduced volumes recorded in the fourth quarter of 2004 derived from the scheduled shutdown of Genelba. Genelba’s factory increased its capacity to 82.7% in 2004 from 79.1% in 2003 and the availability factor decreased to 85% from 96.5% as a consequence of the scheduled plant shutdown.

Net sales attributable to HPPL increased P$16 million, or 44.4%, in 2004 to P$52 million from P$36 million in 2003, due to the combined effect of an improvement in sales prices and higher generation volumes. The average sales price increased 32.1% to P$42.4 per MWh in 2004 from P$32.1 per MWh in 2003, due to the above-mentioned market reasons and the implementation of a dynamic and flexible policy in terms of the mix of spot and futures sales. During 2004, energy delivered increased to 1,226 GWh, or 9.5%, from 1,120 GWh in 2003. This increase was caused by fuel supply problems, which led to an increase in demand for energy from alternative sources and, as a result, we tapped into the upper reservoirs of the Comahue basin power plants in order to substitute thermal energy supply.

Gross profit: Gross profit for the generation business increased P$19 million, or 20.9%, to P$110 in 2004 from P$91 million, predominately due to improved sales prices.

Administrative and selling expenses: Administrative and selling expenses for generation activity increased P$2 million, or 25%, to P$10 million in 2004 from P$8 million in 2003.

Equity in Earnings of Affiliates and Companies under Joint Control

In the following discussion, unless we specifically mention that a figure represents our share of the affiliates’ results, the amounts attributed to each affiliate or company represents the total amount recorded by that affiliate or company.

CIESA/TGS: Our equity in earnings of CIESA and TGS decreased P$212 million, or 89.1%, to P$26 million in 2004 from P$238 million in 2003. The earnings for 2004 were impacted by relatively minor peso depreciation. The earnings for 2003, on the other hand, were impacted by a relatively large level of peso appreciation. This swing was a main factor in the 89.1% decrease. Because of the significant US dollar-denominated financial indebtedness of both companies, CIESA recorded a loss of P$37 million exchange difference in 2004 and a gain of P$527 million in 2003.

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In 2004, TGS restructured its debt, which resulted in a gain of P$33 million.

As of December 31, 2002, CIESA’s shareholders’ equity amounted to negative P$66 million, after reconciling CIESA’s valuation methods with ours. Given our 50% equity interest in CIESA, our equity interest as of December 31, 2002 in CIESA would have been valued at negative P$33 million. However, because we had not assumed commitments to make capital contributions or to provide financial assistance to CIESA, under Argentine GAAP, our shareholder equity interest in CIESA for 2002 was valued at zero. As of December 31, 2003, CIESA reported positive shareholders’ equity. In accordance with Argentine GAAP, we adjusted downwards our equity in earnings of affiliates for 2003 by P$33 million, representing our share of CIESA’s negative shareholders’ equity as of December 31, 2002.

Total sales revenues for CIESA increased P$78 million, or 8.7%, to P$970 million in 2004 from P$892 million in 2003. Sales revenues for CIESA from the gas transportation segment increased P$12 million, or 2.9%, to P$434 million in 2004. This increase was primarily attributable to the execution of new firm transportation agreements, effective May 2004, in the amount of P$5 million and to increased interruptible transportation services in the amount of P$5 million. The increased transportation capacity committed (3.6 MMm³ per day) is a result of competitive biddings for transportation capacity conducted by TGS in March 2004.

CIESA’s income from the natural gas liquids production and marketing segment increased P$64 million, or 15.2%, to P$483 million in 2004, primarily due to the 21% increase the average sale price of natural gas liquids and, to a lesser extent, an increase of approximately 5% in sales volumes. These effects, however, were partially offset by the increase from 5% to 20% in taxes on exports of natural gas liquids, which have been in effect since May 2004.

In 2004, operating income increased P$42 million, or l0.8%, to P$430 million, primarily due to an increase in the prices of natural gas liquids.

CIESA is presented under the proportional consolidation method in our financial statements included in this annual report. See “—Proportional Consolidation and Presentation of Discussion.” As a result, the financial data discussed above is not directly comparable to the corresponding data appearing in our financial statements.

Distrilec/Edesur: Our equity in earnings of Distrilec accounted for losses of P$13 million in 2004 and P$11 million in 2003.

Distrilec’s sales from services in 2004 increased 19.7% or P$182 million, to P$1,104 million. This increase was due to a 13% increase in sales prices and a 5.2% increase in the demand for energy.

Distrilec’s operating income slightly increased to P$10 million in 2004 from P$8 million in 2003, principally due to increase in demand. Increased sales prices did not benefit Distrilec’s margins since they reflect the pass through of higher electricity costs.

Distrilec’s financial income (expense) accounted for a loss of P$44 million in 2004 compared to a gain of P$58 million in 2003. This significant variation was primarily due to the fluctuations in the exchange rate and their corresponding effect on Distrilec’s US dollar-denominated net borrowing position.

Distrilec’s other operating income (expense), net accounted for a gain of P$37 million in 2004 compared to a loss of P$27 million in 2003. The gain in 2004 was primarily due to a gain of P$36 million, as a result of a final settlement reached with Alstom Argentina in connection with a dispute regarding events that took place on January 15, 1999.

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Distrilec is presented under the proportional consolidation method in our financial statements included in this annual report. See “—Proportional Consolidation and Presentation of Discussion.” As a result, the financial data discussed above is not directly comparable to the corresponding data appearing in our financial statements.

Citelec/Transener: Our equity in earnings of Citelec accounted for a loss of P$42 million in 2004 compared to a gain of P$87 million in 2003. Our equity in earnings for 2003 includes the reversal of a P$66 million allowance recorded in 2002. The variation is primarily due to the fluctuations in the exchange rate and their corresponding effect on Citielec’s financial indebtedness, which is predominately denominated in US dollars. As a result of peso appreciation in 2003, Citelec recorded a significant gain in 2003.

Citelec’s sales revenues increased 10.7% to P$305 million, primarily due to increased revenues from unregulated services outside of Argentina derived from the regional expansion of Transener’s activities in Latin America, mainly in Paraguay and Brazil. Regulated rates were not subject to adjustments during 2004 and 2003.

Citelec’s operating income declined P$10 million, or 23.8%, to P$32 million in 2004 compared to P$42 million in 2003, primarily due to increased labor costs, which resulted from new labor regulations imposed by the Argentine government in 2004. This was partially offset by the increased contribution from unregulated activities.

Cuyo: Our equity in earnings of Cuyo accounted for P$16 million gains in both years.

Cuyo sales increased 31.6% to P$283 million in 2004 from P$215 million in 2003, primarily due to a significant increase in sales prices, which was partially offset by a 2% decline in sales volumes. Average sales prices increased 34% in 2004 compared to 2003 as a result of the increase in oil prices, which, in turn, caused significant increases in international reference prices of the petrochemical industry. Cuyo’s operating income increased 46% to P$63 million, mainly due to the above-mentioned increase in prices. This effect, however, was principally offset by higher income taxes.

EBR: Our equity in earnings of EBR accounted for a gain of P$18 million in 2004 compared to a loss of P$5 million loss in 2003, due to the combined effect of improved margins and higher volumes.

In 2004, EBR contribution margins significantly recovered as a result of agreements signed with producers aiming to mitigate the effects of the new regulatory framework in force in 2003, which had sharply reduced the refining margins of EBR. In 2003, as a result of this regulatory framework, EBR had no refining margins.

In addition, EBR recorded a 15% increase in crude processing and an 11% increase in sales volumes (mainly of gasoline and diesel oil). These increased volumes were sold through EBR’s extended commercial network, which in 2004 added 11 new sale points through its subsidiary Empresa Boliviana de Distribución.

Refinor: Our equity in earnings of Refinor increased P$12 million, or 42.9%, to P$40 million in 2004 from P$28 million in 2003. This significant increase is generally due to increased fuel marketing margins and, to a lesser extent, increased gas sales volumes and the revaluation of inventories due to the increase in WTI.

Refinor’s sales increased P$214 million, or 23.7%, to P$1,116 million in 2004 from P$902 million in 2003. In 2004, in line with the increase in WTI, Refinor’s average sales prices were 22% higher compared to 2003. The volume of gas processed averaged 18.9 million cubic meters per day in 2004, 14% higher than in 2003, due to the incorporation of the gathering and compression system of the gas-rich Chango Norte Field, which commenced operations in May 2003. Oil volumes processed totaled an average of 17,400 barrels per day, which was a 1% decrease compared to 2003, due to lower crude oil availability.

Oldelval: Our equity in earnings of Oldelval increased to P$7 million in 2004 from P$2 million in 2003, primarily due to the recognition of a gain from the extraordinary sale of crude oil surplus.

Oldelval’s sales revenues increased 10% to P$112 million in 2004, due to the combined effect of increased transported volumes and improved average prices. Crude oil transported volumes increased 1.97% to 66.5 million barrels in 2004. This increase was generally due to declines in exports to Chile (transported through the Trasandino Oil Pipeline) and in pumping activities to the Luján de Cuyo distillery. These declines caused more volume to be routed through Oldelval’s pipelines and, thus, increased Oldelval’s revenue.

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Year ended December 31, 2003 compared to year ended December 31, 2002

Net income: In 2003, we reported net income of P$381 million, compared to a net loss of P$1,579 million in 2002. This shift principally reflects improvements in Argentina’s economic conditions during 2003, including an 8.7% increase in GDP, as compared to the 11% contraction in 2002, the impact of the appreciation of the peso against the US dollar on the income from our utility affiliates and a reduction in interest expense. Notwithstanding this improvement in the Argentine economy, significant obstacles to a sustained recovery remain, including the refinancing of Argentina’s sovereign debt and the renegotiation of utility contracts. These ongoing obstacles could undermine the recovery of our operations.

Net sales: In 2003, our net sales increased by P$388 million, or 7.6%, to P$5,494 million, from P$5,106 million in 2002. Our net sales for 2003 reflect P$446 million and P$447 million corresponding to our share of the net sales of CIESA and Distrilec, respectively, for that year (net of P$14 million in intercompany sales). Our net sales for 2002 reflect P$519 million corresponding to our share of Distrilec’s net sales for that year.

In 2003, without proportional consolidation, our net sales increased P$28 million, or 0.6%, to P$4,615 million from P$4,587 million in 2002, due to an increase in sales from each of our Refining, Hydrocarbon Marketing and Transportation, and Petrochemicals business segments. Refining registered the highest increase in net sales to P$1,302 million from P$1,008 million, boosted by a 24.4% increase in sales volumes and, to a lesser extent, higher prices. Sales from our Hydrocarbon Marketing and Transportation segment grew by P$59 million, while sales from our Petrochemicals segment grew by P$40 million. These increases were partly offset by a 2.7% reduction in sales from our Oil and Gas Exploration and Production business, to P$2,729 million (including intercompany sales in the amount of P$944 million) from P$2,806 million in 2002 (including intercompany sales in the amount of P$773 million). This reduction resulted from a 7.7% drop in sales volumes of oil equivalent, which was partly offset by a 5.8% increase in sales prices.

Gross Profit: In 2003, our gross profit increased by P$286 million, or 15.7%, to P$2,108 million, from P$1,822 million in 2002. Our gross profit for 2003 reflects P$236 million and P$74 million corresponding to our share of the gross profits of CIESA and Distrilec, respectively, for that year. Our gross profit for 2002 reflects P$113 million corresponding to our share of Distrilec’s gross profit for that year.

In 2003, without proportional consolidation, our gross profit increased by P$89 million, or 5.2%, to P$1,798 million, from P$1,709 million in 2002, primarily due to higher margins for crude oil, refined products and generation activity. Reflecting these higher margins, our gross profit from Oil and Gas Exploration and Production increased by P$75 million, our gross profit from Refining activity increased by P$59 million and our gross profit from our Electricity business increased by P$44 million. In contrast, the gross profit from our Petrochemicals business declined by P$50 million, commensurate with the decline experienced in the industry internationally.

Administrative and selling expenses: In 2003, our administrative and selling expenses decreased by P$50 million, or 8.2%, to P$559 million, from P$609 million in 2002. Our administrative and selling expenses for 2003 reflect P$30 million and P$65 million corresponding to our share of the administrative and selling expenses of CIESA and Distrilec, respectively, for that year. Our administrative and selling expenses for 2002 reflect P$77 million corresponding to our share of Distrilec’s administrative and selling expenses for that year.

In 2003, without proportional consolidation, our administrative and selling expenses declined by P$68 million or 12.8% to P$464 million, from P$532 million in 2002. This drop is primarily due to the impact of the peso appreciation on expenses incurred outside Argentina.

Exploration expenses: In 2003, exploration expenses increased P$138 million, or 237.9%, to P$196 million, from P$58 million in 2002, mainly as a result of the charge to income of P$141 million in capitalized exploratory wells investments in Block 31. See “—Analysis of Operating Results by Business Segment—Oil and Gas Exploration and Production.”

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Other operating (expense), net: In 2003, our other operating expenses increased on a net basis by P$93 million, or 332.1%, to P$121 million from P$28 million in 2002. Our net other operating expenses for 2003 reflect P$12 million and P$5 million corresponding to our share of the net other operating expenses of CIESA and Distrilec, respectively, for that year. Distrilec (which was subject to proportional consolidation in 2002) did not register, on a net basis, any other operating expenses in 2002.

In 2003, without proportional consolidation, our other operating expenses increased on a net basis by P$76, or 271.4%, to P$104 million from P$28 million in 2002. This increase is mainly attributable to environmental remediation expenses (P$58 million in 2003) and other allowances (P$32 million in 2003).

Operating income: In 2003, our operating income increased by P$105 million, or 9.31%, to P$1,232 million, from P$1,127 million in 2002. Our operating income for 2003 reflects P$194 million and P$4 million, corresponding to our share of the operating income of CIESA and Distrilec, respectively, for that year (net of P$4 million in intercompany operations). Our operating income for 2002 reflects P$36 million corresponding to our share of Distrilec’s operating income for that year (net of intercompany operations).

In 2003, without proportional consolidation, our operating income declined P$57 million, or 5.2%, to P$1,034 million, from P$1,091 million in 2002. This decline resulted primarily from the significant increase in exploration expenses and environmental remediation expenses and contingencies.

Equity in earnings of affiliates: In 2003, our equity interest in the earnings of affiliates accounted for a P$163 million gain, compared to a P$638 million loss in 2002, mainly as a result of improved earnings from Citelec and our affiliate utility companies. In 2003, but not in 2002, CIESA’s results were consolidated into our financial statements pursuant to the proportional consolidation method. See “—Proportional Consolidation and Presentation of Discussion.” In 2002, CIESA reported a significant loss.

Without applying proportional consolidation, our equity in earnings of affiliates would have been a P$371 million gain in 2003, compared to a P$647 million loss in 2002, which includes a P$59 million gain from Cerro Vanguardia, which was sold in 2002. As a result of the appreciation of the peso and reduction of the inflation rate in 2003, our equity share in the earnings of our affiliate utility companies (CIESA, TGS, Distrilec and Citelec) accounted for a P$312 million gain in 2003, compared to a P$732 million loss in 2002. The increased equity gains also resulted from increased earnings of P$19 million, P$26 million and P$13 million at Refinor, Cuyo and Inversora Mata S.A., respectively. These increased earnings were partly offset by P$17 million and P$9 million reductions in the earnings of EBR and Oldelval, respectively.

For a discussion of our equity in the earnings of companies over which we exercise joint control in 2003 and the factors that affected these companies’ results during that year, see “—Equity in Earnings of Affiliates and Companies under Joint Control.”

Financial income (expense) and holding gains (losses): In 2003, our financial expenses and holding losses decreased by P$1,410 million, or 77.2%, to P$417 million, from P$1,827 million in 2002. Our financial expenses and holding losses for 2003 reflect P$123 million corresponding to our share of CIESA’s financial and holding gains for 2003, and P$28 million corresponding to our share of Distrilec’s financial and holding gains for 2003. Our financial expenses and holding losses for 2002 reflect P$168 million corresponding to our share of Distrilec’s financial expenses and holding losses for that year.

In 2003, without proportional consolidation, our financial expenses and holding losses declined to P$568 million from P$1,659 in 2002. This reduction is mainly attributable to the following factors:

•

Gains from foreign exchange and exposure to inflation of P$136 million in 2003 on our net borrowing position, as compared to a loss of P$370 million in 2002, principally reflect the effects of peso appreciation and inflation on our net borrowing position.

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•

A P$349 million drop in net interest expense, to P$423 million in 2003 from P$772 million in 2002, resulting from the appreciation of the peso and an 8% reduction in the average amount of our US dollar-denominated indebtedness.

•

A 37.4% reduction in losses attributable to derivative instruments that do not qualify for hedge accounting, to P$294 million in 2003 from P$470 million in 2002. In nominal terms, the loss for 2003 was actually higher than the loss in 2002, mainly due to the increase in the future curve of reference crude oil prices. In constant currency, however, the loss for 2002 is higher than for 2003 due to the effects of the adjustment for inflation. This increase was partially offset by the peso appreciation during 2003.

Other expenses, net: In 2003, our other expenses increased on a net basis by P$234 million, or 125%, to P$421 million, from P$187 million in 2002. Our net other expenses for 2003 reflect P$1 million and P$12 million corresponding to our share of the net other expenses of CIESA and Distrilec, respectively, for that year. Our net other expenses for 2002 reflect P$9 million corresponding to our share of Distrilec’s net other expenses for that year.

In 2003, without proportional consolidation, our other expenses, net increased by P$230 million, or 129.2%, to P$408 million, from P$178 million in 2002. These increased expenses reflected:

•

Impairment allowance for our operations in Ecuador of P$309 million (see “—Factors Affecting Our Consolidated Results of Operations—Operations in Ecuador”);

•

P$39 million loss attributable to the sale of oil and gas areas;

•

P$37 million impairment charge for oil production areas (see “—Factors Affecting Our Consolidated Results of Operations—Political and Economic Situation in Venezuela—Agreements in San Carlos and Tinaco”); and

•

P$27 million allowance for the book value of loans granted to joint-venture partners in Venezuela.

These expenses for 2003 compare to the following other expenses for 2002:

•

P$63 million allowance for operations in Ecuador;

•

P$44 million impairment charge for gas production areas;

•

P$37 million loss attributable to the assignment of a 50% interest in San Carlos area;

•

P$42 million allowance for the book value of loans granted to joint venture partners in Venezuela;

•

P$17 million charge for the accelerated amortization of financial debt issuance costs;

•

P$10 million impairment charge for an interest in Hidroneuquén; and

•

P$78 million income from divestment of non-core assets.

Income tax: In 2003, our income tax charge decreased by P$64 million, or 78.1%, to P$18 million, from P$82 million in 2002. Our income tax charge for 2003 reflects a P$58 million gain corresponding to our share of CIESA’s income tax for that year, and a P$29 million loss corresponding to our share of Distrilec’s income tax for that year. Our income tax provision for 2002 reflects a P$127 million gain corresponding to our share of Distrilec’s income tax for that year.

In 2003, without proportional consolidation, our income tax provision declined P$162 million, or 77.5%, to P$47 million, from P$209 million in 2002. This decline reflects the inclusion of the following items in 2002: (1) an

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allowance for tax losses and a minimum presumed income tax of P$134 million and P$19 million, respectively, in line with the uncertain economic context prevailing in Argentina, and (2) a P$19 million provision attributable to Conuar, an asset we sold in 2002.

Analysis of Operating Results by Business Segment

Oil and Gas Exploration and Production

Operating income: Operating income for this segment decreased 4.5% in 2003, to P$861 million from P$902 million in 2002. This drop was due primarily to a significant increase in exploration expenses and a decline in sales volumes, which were partially offset by a rise in sales prices resulting from changes in our price hedging strategies and a 19% increase in the WTI.

Net sales: Net sales for 2003 declined P$77 million, or 2.7%, to P$2,729 million (including intercompany sales in the amount of P$944 million), from P$2,806 million in 2002 (including intercompany sales in the amount of P$773 million). This drop is attributable to a 7.7% decline in sales volumes of oil equivalent, which was partially offset by a 5.8% increase in sales prices.

Combined oil and gas sales volumes declined 7.7% in 2003 to 157,900 barrels of oil equivalent per day, from 171,100 barrels of oil equivalent per day in 2002. Oil sales volumes decreased 5% in 2003 to 111,200 barrels per day, from 117,100 barrels per day in 2002, while gas sales volumes declined 13.5% to 280.0 million cubic feet per day, from 323.6 million cubic feet per day in 2002. This significant drop in sales volumes is primarily attributable to the decline in the level of activity of our operations in Venezuela, which was affected by the oil strike that took place at the beginning of 2003, and to the restrictive investment policy implemented by us in 2002 in light of the Argentine crisis. While this policy protected our operating cash flow in 2002, it delayed the development of hydrocarbon projects. The decline of our operation in Venezuela, however, was offset by the start of commercial operations in Ecuador, with production reaching a total of 3,900 barrels per day. In addition, gas sales volumes declined due to price restrictions in the Argentine market, which discouraged production.

During 2003, the average crude oil sales price per barrel, including the effects of hedging transactions and taxes on exports (as discussed below), increased 4.8% to P$61.2, from P$58.4 in 2002. This increase reflected a 19% increase in the average WTI to US$31.1 per barrel and changes in our hedging policy. This increase was partially offset by the effect of the peso appreciation against the US dollar during 2003, which had a negative impact on US dollar-denominated flows from foreign operations and exports.

In 2003, our crude oil price hedging policy accounted for P$85 million in reduced net sales, compared with P$373 million in 2002. These reduced losses mainly reflect a change in our hedging strategy. During 2003, we relied on option contracts that allowed us more flexibility to benefit from price increases. Conversely, in 2002 hedging instruments consisted primarily of swap agreements, with fixed sales prices.

In 2003, Argentine taxes on exports resulted in a reduction in net sales of P$60 million, compared to P$84 million in 2002, reflecting a 50% drop in export volumes.

Net Sales in Argentina: In 2003, overall sales in Argentina decreased by P$69 million, or 4.3%, to P$1,538 million, from P$1,607 million in 2002, due to a 10.9% decrease in combined oil and gas daily sales volumes, to 90,400 barrels of oil equivalent from 101,500 barrels of oil equivalent in 2002.

Crude oil sales in Argentine declined P$22 million, or 1.5%, to P$1,401 million, from P$1,423 million in 2002. This reduction in crude oil sales is mainly attributable to a 7.1% decline in sales volumes to 55,000 barrels per day, which was partially offset by a 6.1% increase in average sales prices. Gas sales in Argentina dropped by P$46 million, or 25.1%, to P$137 million, from P$183 million in 2002. This drop in gas sales resulted from the combined effect of reduced sales volumes and reduced prices. Daily gas sales volumes declined 16.2% to 212.8 million cubic feet, from 253.9 million cubic feet in 2002, while gas sales price dropped 11.1% to P$1.76 per million cubic feet, from P$1.98 per million cubic feet in 2002. The Public Emergency Law has prevented nominal sales prices from changing significantly.

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In 2003, the volume of intercompany sales in Argentina, particularly to the Refining business, increased 21.6% to 31,700 barrels per day.

Net Sales Outside of Argentina: In 2003, combined oil and gas sales outside of Argentina decreased 0.7% to P$1,191 million, from P$1,199 million in 2002. Oil and gas total sales volumes declined to 67,400 barrels of oil equivalent per day, or 3.0%, with respect to 2002. The average sales price for oil per barrel rose to P$52.7, or 3.9%, from P$50.7 in 2002, mainly due to the rise in the international reference price and the change in our hedging policy (as discussed above).

The following is an overview of 2003 sales figures for each country in which we have oil and gas operations:

Venezuela: Oil and gas sales decreased P$106 million, or 15.1%, to P$594 million, from P$700 million in 2002, due to the following factors:

•

The average price of oil per barrel decreased 3.6% to P$40.4, from P$41.9 in 2002. This decline was attributable to the effect of the appreciation of the peso, which was partially offset by the change in the hedging policy (as discussed above) and the increase in the WTI; and

•

Daily sales volume of oil equivalent decreased 12.5% to 42,800 barrels of oil equivalent, from 48,900 barrels of oil equivalent in 2002, primarily as a result of the oil strike that took place at the beginning of 2003, and the natural field decline resulting from our restrictive investment policy in 2002.

Bolivia: Oil and gas sales decreased P$4 million, or 3.6%, to P$108 million, from P$112 million in 2002, due primarily to a 7.4% reduction in the sale price of gas to P$5.24 per million cubic feet, from P$5.66 per million cubic feet in 2002. This decline in the gas sales price was partially offset by the combined oil and gas daily sales volumes, which increased 5.5% to 7,700 barrels of oil equivalent, from 7,300 barrels of oil equivalent in 2002.

Peru: Oil and gas sales increased 4.2% to P$374 million, from P$359 million in 2002, due to the following factors:

•

Sales price increased 1.3% to P$78.5 per barrel, from P$77.5 per barrel in 2002, as a result of the change in our hedging policy (as discussed above) and the increase in international prices, which were partially offset by peso appreciation; and

•

Oil and gas daily deliveries increased 2.4% to 13,000 barrels of oil equivalent per day, from 12,700 barrels of oil equivalent per day in 2002, as a consequence of improved well productivity resulting from workover tasks.

Ecuador: Oil sales increased 310.7% to P$115 million, from P$28 million in 2002, due to the approval of the development plan for Block 18, which was obtained in the fourth quarter of 2002. After obtaining this approval, we were able to start drilling activities, particularly at the Palo Azul field, where we currently operate five wells, which yielded a production of 17,000 barrels per day in December (before deduction on account of the Ecuadorian government’s interest and before deducting royalties). Daily crude oil sales volumes (net of the Ecuadorian government’s interest) increased to 3,900 barrels per day at a price of P$79.2 per barrel.

Gross profit: In 2003, gross profit for the Oil and Gas Exploration and Production segment increased 6.2% to P$1,281 million, from P$1,206 million in 2002. The gross margin on sales rose to 46.9% from 43% in 2002. This increase in margins is primarily attributable to the rise in sale prices.

Administrative and selling expenses: In 2003, administrative and selling expenses for this segment totaled P$178 million, compared to P$224 million in 2002. This drop is attributable to the appreciation of the peso in 2003, which reduced the peso equivalent of expenses incurred abroad.

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Exploration expenses: In 2003, exploration expenses increased by P$138 million, or 237.9%, to P$196 million, from P$58 million in 2002. Exploration expenses during 2003 reflected the charge to income of P$141 million exploration investments in Block 31 (in Ecuador), and P$30 million exploration investments in the San Carlos area (in Venezuela). In addition, expenses were recorded for non-producing exploration wells in the Santa Cruz II Oeste area in Argentina and Lote XVI in Peru and the investment in seismic testing related to such wells.

In 2002, the Chontayacu well in Block 18 (Ecuador) was drilled and did not prove to be successful. In addition, 238 km of 2-D seismic were shot in Block 31. In Argentina and Peru, expenses in connection with the Chiripá well in the Santa Cruz II Oeste area and the Mashansha well in Lote 35, respectively, were charged to income.

Other operating income (loss), net: In 2003, other operating expenses for this segment increased on a net basis by P$24 million, or 109.1%, to P$46 million, from P$22 million in 2002. This increase was primarily a result of environmental remediation expenses in the amount of P$26 million and other allowances in the amount of P$32 million. These effects were offset by the favorable settlement of certain commercial claims in Venezuela.

Hydrocarbon Marketing and Transportation

Our results for this segment in 2003 reflect the proportional consolidation of CIESA. In 2002, CIESA’s results were not proportionally consolidated. See “—Proportional Consolidation and Presentation of Discussion.”

Operating income: In 2003, our operating income for this segment increased by P$189 million, or 1181.3%, to P$205 million, from P$16 million in 2002. Our operating income for this segment in 2003 reflects P$194 million corresponding to our share of CIESA’s operating income for that year.

In 2003, without proportional consolidation, our operating income for this segment decreased 31.3% to P$11 million, from P$16 million in 2002.

Net Sales: Our operations in this segment include oil, gas and liquified petroleum gas brokerage services, with significantly different margins subject to the specific characteristics of each operation.

In 2003, our net sales for this segment increased by P$505 million, or 3.156%, to P$521 million, from P$16 million in 2002. Our net sales for this segment in 2003 reflect P$446 million corresponding to our share of CIESA’s net sales for that year.

In 2003, without proportional consolidation, our aggregate net sales significantly increased to P$75 million from P$16 million in 2002, principally as a result of increased volume in our oil brokerage operations.

Gross profit: In 2003, our gross profit for this segment increased by P$235 million to P$240 million, from P$5 million in 2002. Our gross profit for this segment in 2003 reflects P$236 million corresponding to our share of CIESA’s gross profit for that year.

In 2003, without proportional consolidation, our gross profit decreased to P$4 million from P$5 million in 2002, as a result of a reduction in margins in the brokerage business.

Other operating income, net: In 2003, we registered other net operating expenses for this segment in the amount of P$1 million, compared to other net operating income in the amount of P$13 million in 2002. The other net operating expenses for this segment in 2003 reflect P$12 million corresponding to our share of the other net operating expense of CIESA for that year.

In 2003, excluding proportional consolidation, we registered other net operating income in the amount of P$11 million, a 15.4% decrease from the P$13 million in other net operating income than we registered in 2002.

In 2003, the income from the advisory services we provided to TGS’s technical operator was P$12 million, as compared to P$13 million in 2002.

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Refining

Operating income: In 2003, operating income for this segment totaled P$54 million, while no significant results were recorded in this segment in 2002. The improvement resulted from a significant increase in sales volumes and margins.

Net sales: In 2003, net sales of refined products increased P$294 million, or 29.2%, to P$1,302 million, from P$1,008 million, due to a 24.4% increase in sales volumes and higher prices, particularly in the domestic market. Below we highlight certain significant trends in sale prices and volumes for refined products in 2003:

•

In an effort to optimize our margins in this segment, we adopted changes in the mix of the refined products we sell and of our distribution channels. Domestic sales of refined products increased 41%, mainly due to increased diesel oil sales to EG3. Exports of refined products, on the other hand, dropped 2%.

•

In 2003, average sales prices of diesel oil, gasoline, aromatics and reformer plant by-products increased 7%, 16%, 14% and 9%, respectively. Taxes on exports of refined products imposed by the Argentine government starting on April 2002 totaled P$9 million in 2003 and P$14 million in 2002, decreasing revenues.

•

Crude oil volumes processed in 2003 averaged 32,600 barrels per day, a 19.9% increase from 2002. During 2003, in order to maximize our overall results in light of the applicable tax regime, integration of our refining and exploration and production operations increased. Given the 20% export tax on crude oil imposed in Argentina in March 2002, we prioritized the refining of crude oil over crude oil exports.

•

Sales volumes of diesel oil grew 41.9% in 2003, to 882,600 cubic meters, reflecting a 62.3% increase in sales volumes for diesel oil in the domestic market. This increase resulted primarily from increased sales to EG3 and, to a lesser extent, a 4.2% recovery of the domestic demand for this product, which was driven by demand from the farming sector. The increase in domestic sales of diesel oil in 2003 was partly offset by an 18.3% drop in exports to bordering countries, particularly to Paraguay.

•

Total gasoline sales volumes declined 2.9% in 2003, to 119,200 cubic meters, reflecting a 4.6% drop in our sales volumes in Argentina. This decline in domestic gasoline sales resulted primarily from a 10% reduction in total domestic demand for gasoline, due to increased use of compressed natural gas as a substitute fuel.

•

Sales volumes of reformer plant by-products grew 21.8% in 2003, to 79,000 tons, as a result of a 14% increase in domestic sales and a 54% rise in exports.

•

Sales volumes for heavy distillates grew 12% in 2003, to 438,000 tons, due primarily to a 63% increase in domestic sales as a result of increased demand for fuel oil and the increase in crude oil volumes processed. The increase in domestic sales was partially offset by a 1% drop in export volumes.

•

Asphalt sales volumes grew 102.4% in 2003, to 86,000 tons, as a result of our active trade policy, and a 110% increase in domestic sales, due to a rise in road construction and specific public works (such as the construction of the Rosario-Victoria Bridge). In addition, 2003 was a record year for asphalt exports, with exports to Bolivia and Paraguay increased 90% compared to 2002, reflecting increased demand in these countries.

•

Sales volumes of paraffins increased 9.4% in 2003, to 151,000 tons, due to a 32% increase in domestic sales, resulting from increased demand. This increase was offset by a 4% drop in exports, particularly to the United States and countries bordering Argentina.

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•

Sales volumes of aromatic products decreased 16.1%, to 56,000 tons, as a result of a 27.5% drop in domestic sales, which was offset by a 41.6% increase in exports, particularly to countries bordering Argentina.

Gross profit: In 2003, gross profit for this segment increased P$59 million, or 92.2%, to P$123 million, from P$64 million in 2002, due to higher sales volumes and improved gross margins. The gross margin on sales of refined products increased to 9.5% from 6.3%. This increase is attributable to a 4.5% rise in average sales prices, that was only partially offset by a 2.3% increase in the cost of crude (from P$78.9 per barrel in 2002 to P$80.7 per barrel in 2003). While the average WTI increased by 19% in 2003, the appreciation of the peso during this year helped to contain the increase in our crude acquisition costs (which are dollar-based).

Administrative and selling expenses: In 2003, administrative and selling expenses for the Refining segment increased P$9 million, or 18.8%, to P$57 million, from P$48 million. This increase resulted primarily from increased commercial expenses associated with the expansion of our gas station network.

Other operating expenses, net: In 2003, other operating expenses for the Refining segment decreased on a net basis to P$12 million, from P$16 million in 2002. Idle-facility costs accounted for a P$6 million loss in 2003, compared to a P$10 million loss in 2002. In addition, P$8 million environmental remediation expenses were recorded for this segment in 2003.

Petrochemicals

International and Regional Overview: In 2003, the styrenics business was marked by a strong increase in international prices for its primary raw materials. In line with the upward trend of oil prices, prices for benzene and ethylene increased approximately 27% and 25%, respectively, in 2003. International prices of styrene and polystyrene increased approximately 15%. As a result of the increase in the costs of raw materials, spreads (i.e., the difference between the sales price and the cost of raw materials) for styrenics decreased in 2003, particularly the spread for styrene, which decreased 21% and, to a lesser extent, the spread for polystyrene, which decreased 4%.

The demand for styrenics in Argentina increased considerably in 2003, due to the strong recovery in the country’s economic activity. The demand for styrene, polystyrene and rubber increased 38%, 14% and 19%, respectively. In Brazil, the demand for styrene rose 8% in 2003, while the demand for polystyrene dropped 10%.

The Mercosur region and Chile continued to record a shortage of styrene. The excess supply of polystyrene, on the other hand, continued to increase, due to increased production and lower demand for this product in the Brazilian market.

In the fertilizers business, international prices for urea significantly increased in 2003 to an average of US$139 per ton, from an average of US$94 per ton in 2002. This increase resulted primarily from increased demand in the southeastern region of Asia, as well as a lower global supply resulting from the high cost of natural gas in the major manufacturing centers of urea around the world.

Our fertilizers business also benefited from improved conditions in the Argentine farming sector, resulting from favorable international prices for grains, significant growth in sown areas, record soybean harvest and an increased use of nutrient mixes. Droughts in the Provinces of Córdoba, La Pampa and Buenos Aires did not affect this general positive trend. Total demand for fertilizers in Argentina recorded a 31% increase in 2003.

Operating income: In 2003, operating income for the Petrochemicals segment decreased P$66 million, or 26.3%, to P$185 million, from P$251 million in 2002, mainly as a result of the decrease in the spreads.

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Net sales: In 2003, net sales for the Petrochemical segment increased P$40 million, or 3.2%, to P$1,294 million, from P$1,254 million in 2002, mainly as a result of increased sales volumes in Argentina. We highlight below certain sales figures and trends for this segment:

Styrenics—Argentina: In 2003, total sales of styrenics from our Argentine operations increased P$34 million, or 7.5%, to P$485 million (including exports to Innova in the amount of P$5 million), from P$451 million in 2002 (including exports to Innova in the amount of P$26 million). In 2003, total sales volumes for styrenics increased to 104,000 tons from 84,000 tons in 2002. Average sales prices for styrenics did not register significant changes compared to 2002, as the alignment with international reference prices was offset by peso appreciation.

•

Sales volumes for styrene increased approximately 38% in 2003, due to increased domestic demand for this products and export growth. The greater level of exports is attributable to increased shipments to Chile reflecting the consolidation of our presence in this country’s styrene market.

•

Sales volumes for polystyrene decreased approximately 11.7% in 2003, due to a 43% drop in exports resulting from lower shipments to Brazil and Europe. These lower shipments in part reflect our efforts to increase exports of styrene to certain regional markets from which we can extract greater profit margins. A 6% increase in sales volume of polystyrene to the domestic Argentine market, resulting from the country’s economic recovery, partly offset the decline in the volume of exports of this product.

•

Sales volumes for Bops increased approximately 56% in 2003, due primarily to a 74% increase in exports, which resulted from increased shipments to the United States and Europe. In addition, Bops sales volumes to the domestic Argentine market increased 11% due to the country’s economic recovery.

•

Sales volumes for rubber increased approximately 11%, as a result of the recovery of the Argentine economy and an increase in our market share.

Styrenics—Brazil: In 2003, sales of styrenics from Innova decreased P$59 million, or 11%, to P$502 million, from P$561 million in 2002, as a result of the decline in sales volumes and prices. Total sales volumes of styrenics from Innova declined 7% in 2003, reflecting a 3.9% reduction in sales volumes to the Brazilian domestic market (from 176,000 tons in 2002 to 169,000 tons in 2003). This reduction in domestic sales volumes was mainly the result of a 13% decline in local sales of polystyrene, mainly due to the start-up of a new competitive plant in Manaus. Local sales of styrene, on the other hand, did not reflect significant changes from the levels recorded in 2002. Export volumes of styrenics from our Brazilian operation declined 17% in 2003, as the decline in international margins for polystyrene limited the opportunities to export polystyrene to markets outside of the region. The average sales price of styrenics from our Brazilian operations dropped 4%, as the appreciation of the peso offset the increase in the international prices of polymers.

Fertilizers: In 2003, sales of fertilizer increased 16.4% to P$312 million, from P$268 million in 2002, due primarily to a 32% increase in sales volumes that was caused by increased demand for nutrient mixes in Argentina. A 38% increase in sales of liquid fertilizers in 2003 also improved overall fertilizer sales. This improvement in sales of liquid fertilizers reflected the consolidation of our leading position in the Argentine fertilizer market, particularly in the liquid fertilizers segment. Average sales prices for fertilizers dropped 11% in 2003, due to the effects of the peso appreciation that offset the increase in US dollar-denominated prices, and the strong growth in sales of liquid fertilizer, which have lower unit prices than solid fertilizers.

Gross profit: In 2003, gross profit for the Petrochemicals segment decreased P$50 million, or 13.8%, to P$312 million, from P$362 million in 2002. Gross margin for this segment decreased to 24.1% in 2003 from 28.9% in 2002, due to an increase in the international prices for raw materials. We highlight below certain significant trends in this segment:

Styrenics—Argentina: In 2003, gross profit for styrenics from our Argentine operations increased 2.4% to P$129 million, from $126 million in 2002, reflecting increased volumes. Gross margin on sales in these products, on the other hand, declined to 26.6% in 2003 from 27.8% in 2002, mainly as a result of the increased cost of raw materials.

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Styrenics—Brazil: In 2003, gross profit for styrenics from our Brazilian operations declined 13.6% to P$89 million, from P$103 million in 2002. Gross margin for these products declined to 17.7% in 2003 from 18.4% in 2002, mainly as a result of the increased cost of raw materials.

Fertilizers: In 2003, gross profit for our fertilizers business declined 29.3% to P$94 million, from P$133 million in 2002. Gross margins for fertilizers declined to 30.1% in 2003 from 49.6% in 2002, mainly due to a reduction in the average sales price of fertilizer products as explained above and a change in the product mix. Our margins in this segment were adversely affected by the increase in resales by us of fertilizer volumes with a unit cost higher than that of our own fertilizer products.

Administrative and selling expenses: In 2003, administrative and selling expenses for the Petrochemical segment declined P$12 million, or 10%, to P$110 million, from P$122 million in 2002, mainly as a result of the impact of the significant appreciation of the peso on our costs incurred in Brazil.

Other operating expenses, net: In 2003, other operating expenses for this segment, accounted on a net basis for a P$17 million loss, attributable to future environmental remediation expenses. This compared to a P$11 million gain in 2002, attributable to the collection of insurance compensation for a loss occurred at Innova’s ethylbenzene plant and certain tax credits from our operations in Brazil.

Electricity

Our results for this segment in 2003 and 2002 reflect the proportional consolidation of Distrilec. See “—Proportional Consolidation and Presentation of Discussion.”

Operating income: In 2003, our operating income for this segment increased by P$23 million, or 25.9%, to P$112 million, from P$89 million in 2002. Our operating income for this segment in 2003 and 2002 reflects P$4 million and P$32 million, respectively, corresponding to our share of Distrilec’s operating income for these years.

In 2003, without proportional consolidation, our operating income for this segment increased P$51 million, or 89.5%, to P$108 million, from P$57 million in 2002 (which includes P$10 million from the operating income of Conuar Fae, a company that was divested in the fourth quarter of 2002), due primarily to an increase in the price of electricity and lower production costs.

Net sales: In 2003, our net sales for this segment decreased by P$75 million, or 9.8%, to P$691 million, from P$766 million in 2002. Our net sales for this segment in 2003 and 2002 reflect P$447 million and P$518 million, respectively, corresponding to our share of Distrilec’s net sales for these years.

In 2003, without proportional consolidation, our net sales for this segment increased P$38 million, or 18.4%, to P$244 million, from P$206 million in 2002 (excluding P$42 million in net sales of Conuar/Fae in 2002, which we sold in that year).

Net sales from generation: In 2003, net sales for our electricity generation business increased P$39 million, or 19.9%, to P$235 million, from P$196 million in 2002. This increase resulted from a 20.4% increase in average sales prices, which is attributable primarily to the following factors:

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As a result of changes in the regulatory framework, payments of additional compensation from the Argentine Stabilization Fund were received between March and October of 2003 for guaranteed supply to the electricity market during the winter season. These additional payments accounted for a P$17 million increase in sales;

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An increase of approximately 7% in the demand for electricity, which, as a result of the limited availability of natural gas during the winter season (due to lower temperatures and increased consumption by industries), required energy dispatch from less efficient machines, which resulted in higher market prices. The reduction in the availability of gas did not affect the activity of Genelba due to the gas supply contract it had in effect during 2003); and

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•

Reduced flows from incoming rivers during the second half of the year, which shifted generation away from low-cost hydroelectric plants. This reduction in river flows was caused by a mild summer, which resulted in less snow water supplying the river basins.

In 2003, net sales from Genelba increased P$34 million, or 21%, to P$196 million, from P$162 million in 2002, due to increased prices and sales volume. The average monomic price of energy and power delivered increased 16.7% in 2003, to P$39.9 per MWh from P$34.2 per MWh in 2002. Energy deliveries from this plant increased 4% to 4,918 GWh, from 4,731 GWh in 2002, with a plant factor of 79.1% in 2003 and 73.6% in 2002. The increased sales volume in 2003 was primarily attributable to higher dispatch to the network, due to changes in 2002 to the regulations regarding cost declaration, that benefit the plant’s relative competitiveness and permit a more timely and flexible operation. In 2003, the availability factor of Genelba was 96.5%, 1.1% higher than in 2002, as a result of the optimization of starting processes, inspections, maintenance works and the plant’s general performance.

In 2003, net sales attributable to HPPL increased P$7 million, or 24%, to P$36 million, from P$29 million in 2002. The average monomic sale price of energy and power increased 37.4% to P$32.1 per MWh, from P$23.5 per MWh in 2002, reflecting the overall increase in energy prices discussed above. Energy delivered by HPPL dropped 9.7% to 1,120 GWh, from 1,240 GWh in 2002, due to a lower contribution from incoming river flows, as compared to historic average values. As a result of the application of the Energy Support Price Method and by virtue of the prices recorded in 2003 and 2002, and their future estimates, we recorded P$3 million and P$5 million gains in 2003 and 2002, respectively.

Gross profit: In 2003, our gross profit for this segment increased by P$10 million, or 6.3%, to P$168 million, from P$158 million in 2002. Our gross profit for this segment in 2003 and 2002 reflects P$74 million and P$108 million, respectively, corresponding to our share of Distrilec’s gross profit for these years.

In 2003, without proportional consolidation, our gross profits increased P$59 million, or 168.6%, to P$94 million, from P$35 million in 2002 (excluding P$15 million corresponding to the gross profits of Conuar/Fae, which we sold in 2002).

Gross profit from generation: In 2003, gross profit for the electricity-generation business increased P$60 million or 193.5% to P$91 million, from P$31 million in 2002. This significant increase is mainly attributable to higher sales prices and lower sales costs as measured in constant pesos given that the nominal cost of gas remained unchanged.

Administrative and selling expenses: In 2003, our administrative and selling expenses for this segment decreased by P$19 million, or 20.7%, to P$73 million, from P$92 million in 2002. Our administrative and selling expenses for this segment in 2003 and 2002 reflects P$65 million and P$76 million, respectively, corresponding to our share of Distrilec’s administrative and selling expenses for these years.

In 2003, without proportional consolidation, our administrative and selling expenses for the generation business dropped P$4 million, or 33.3%, to P$8 million, from P$12 million in 2002 (excluding P$4 million corresponding to administrative and selling expenses of Conuar/Fae, which we sold in 2002). In nominal terms, these expenses remained unchanged.

Other operating income (expense), net: In 2003, our other operating income for this segment decreased on a net basis P$6 million, or 26%, to P$17 million, from P$23 million in 2002. Our net other operating income for this segment in 2003 reflects P$5 million corresponding to our share of Distrilec’s operating income for that year. In 2002, Distrilec did not register significant net other operating income.

In 2003, excluding proportional consolidation, our other operating income decreased on a net basis by P$1 million, or 4.3%, to P$22 million, from P$23 million in 2002.

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Equity in Earnings of Affiliates and Companies under Joint Control

CIESA/TGS: In 2003, our equity share in the earnings of CIESA (which owns 55.3% of TGS), together with our 7.35% direct interest in TGS, accounted for a P$240 million gain, compared to a P$482 million loss in 2002. Given the significant financial indebtedness of both TGS and CIESA that is denominated in US dollars, the appreciation of the peso in 2003, compared to the depreciation it registered in 2002, had a significant impact on their net results. Additionally, CIESA’s operating income declined 6.7% in 2003, to P$407 million, as a result of lower revenues for the regulated gas transportation market as a consequence of the pesification of rates. Our results in 2003 include a P$33 million gain in respect of our investment in CIESA, representing the reversal of the P$33 million negative value of our equity in this company as of December 31, 2002.

Sales revenues for CIESA from the gas transportation segment dropped 20.7% in 2003 to P$422 million. While the committed transportation capacity for CIESA slightly increased from 61.3 to 61.4 millions of cubic meters per day, the drop in revenues results from failure to adjust gas transportation rates due to the delayed start of the tariff negotiation process with the Argentine government and the restatement of income for 2002. Both effects were partially offset by increased revenues from interruptible transportation services, as a result of a rise in the demand for natural gas.

CIESA’s income from the natural gas liquids production and marketing segment increased 23.3% in 2003 to P$428.4 million, as a result of: (1) an increase in domestic sale prices caused by a significant increase in international sale prices, (2) the renegotiation of certain natural gas liquids processing and marketing agreements, which had been pesified and were re-indexed to the dollar, and (3) a 6% increase in sales volumes. These positive factors were partially offset by the effect of the restatement of income for 2002, reflecting the fact that the increase in prices and margins exceeded domestic inflation.

CIESA is presented under the proportional consolidation method in our financial statements as of and for the year ended December 31, 2003 included in this annual report, but not in the financial statements as of and for the year ended December 31, 2002. See “—Proportional Consolidation and Presentation of Discussion.” As a result, the financial data discussed above is not directly comparable to the corresponding data appearing in our financial statements.

Distrilec/Edesur: In 2003, our equity interest in the earnings of Distrilec (through which we hold our interest in Edesur) accounted for a P$11 million loss, compared to an P$8 million loss in 2002. In 2003, Distrilec registered a P$17 million operating loss, compared to a P$47 million operating gain in 2002. In 2002, despite having a positive operating income, the depreciation of the peso caused Distrilec to record a significant financial and holding loss as a result of its US dollar-denominated debt. In contrast, in 2003, the appreciation of the peso against the US Dollar permitted Distrilec to partially mitigate its operation loss.

Distrilec’s net sales declined 13.9% in 2003 to P$920.2 million. This decline was mainly attributable to a decrease of approximately 17% (in constant currency) in the average sale price for energy, which was partially offset by a 4.4% increase in the demand for energy. Distrilec’s operating loss in 2003 was positively affected by the appreciation of the peso during this year on this company’s financial debt.

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Citelec/Transener: In 2003, our equity interest in the earnings of Citelec (through which we hold our interest in Transener) accounted for a P$87 million gain, compared to a P$241 million loss in 2002. This shift resulted primarily from the appreciation of the peso and its effects on Transener’s financial indebtedness in 2003 (as opposed to the effects of the depreciation of the peso in 2002) and the reversal of the P$66 million allowance recorded in 2002. The reversal of the allowance occurred because the book value in Citelec, as of December 31, 2002, exceeded its recoverable value. Our calculation of the recoverable value was based on the listed value of Transener’s shares, which is the only operating subsidiary of Citelec. As of December 31, 2003, the recoverable value of or our equity in Citelec exceeded its book value and, we, therefore, reversed the P$66 million allowance.

In 2003, Citelec’s operating income declined 39.1% to P$42 million, from P$69 million in 2002, primarily as a result of the pesification of regulated rates. Sales revenues for Citelec declined 3.7% in 2003, to P$276 million, mainly as a result of the Argentine government’s failure to adjust regulated rates in 2002 and 2003. This effect was offset by the increase in unregulated revenues, primarily attributable to revenues derived from construction of the Yacyretá – Ayolas 500 kV High Voltage Transmission Line and other projects in Paraguay.

Cuyo: In 2003, our equity interest in the earnings of Cuyo accounted for a P$16 million gain, compared to a P$10 million loss in 2002 (which reflects the impact of the peso devaluation in 2002 on Cuyo’s US dollar-denominated debt). Cuyo’s sales in 2003 totaled P$225 million, compared to P$200 million in 2002, as a result of a 5.9% increase in average sale prices of its products, mainly reflecting the 25% rise in the international prices of polypropylene.

EBR: In 2003, our equity interest in the earnings of EBR accounted for a P$5 million loss, compared to a P$12 million gain in 2002. This drop is mainly attributable to changes introduced in this company’s regulatory framework, which resulted in a significant drop in refining margins.

Refinor: In 2003, our equity interest in the earnings of Refinor accounted for a gain of P$28 million, compared to a gain of P$9 million in 2002. This increase resulted primarily from a 19% rise in fuel marketing margins and, to a lesser extent, the losses attributable to the devaluation of the peso, which had reduced Refinor’s earnings for 2002. Refinor’s sales increased to P$858 million in 2003, from P$836 million in 2002, reflecting a 10% increase in the volume of gas it processed (to an average of 16.7 million cubic meters per day). This increase in gas volume processed resulted from the launch of operations of the Chango Norte field, which supplied gas to Refinor’s gathering and compression system. This increase in gas production was offset by a 6% decrease in the level of oil processed (to 17,600 barrels per day), resulting from reduced availability of crude oil.

Oldelval: In 2003, our equity interest in the earnings of Oldelval accounted for a P$2 million gain, compared to a P$11 million gain in 2002, mainly due to a 16% decline in Oldelval’s sales revenues (to P$102 million) resulting from an increase in the US dollar-denominated rate that Oldelval charges to its customers. Oldelval’s operating costs increased due to maintenance work performed to secure reliability of the pumping system. During 2003, oil volumes transported by Oldelval from Allen to Puerto Rosales registered a slight 1.2% drop to 60 million barrels, reflecting the natural decline of the oil field at the Neuquén basin, and sustained growth of exports to Chile through the Trans-andino Oil Pipeline, Oldelval’s competitor’s pipeline, which cause less volume to be routed through Oldelval’s pipeline.

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CRITICAL ACCOUNTING POLICIES

This operating financial review and prospects is based upon our financial statements, which have been prepared in accordance with accounting principles generally accepted in Argentina. The preparation of financial statements in accordance with GAAP requires our management to make estimates that affect the reported amounts of our assets and liabilities. Our actual results could differ from those estimated if our estimates or assumptions prove to be incorrect.

We believe the following represents our critical accounting policies. Our accounting policies are more fully described in notes 2 and 4 to our financial statements.

Estimation of oil and gas reserves.

Evaluations of oil and gas reserves are important to the effective management of upstream assets. They are used to help make investment decisions about oil and gas properties. Oil and gas reserve quantities are also used as the basis of calculating the unit-of-production rates for depreciation and evaluating for impairment. Oil and gas reserves are divided between proved and unproved reserves. Proved reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from reservoirs under existing economic, operating and regulatory conditions, i.e., prices and costs at the date of estimation. Unproved reserves are those with less then reasonable certainty of recoverability and are classified as either probable or possible. Probable reserves are reserves that are more likely to be recovered than not and possible reserves are less likely to be recovered than not.

Estimates of oil and gas reserves have been prepared in accordance with Rule 4-10 of Regulation S-X. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history.

Our management must make reasonable and supportable assumptions and estimates with respect to (1) the market value of reserves, (2) oil fields’ production profiles, (3) future investments and their amortization, taxes and costs of extraction and (4) appropriate risk factors for unproved reserves and other factors. Such assumptions and estimates have a significant impact on our calculations. As such, any change in variables used to prepare such assumptions and estimates may have, as a consequence, a significant effect on both the depreciation of, and the impairment tests relating to, investments in areas with oil and gas reserves. Therefore, the reserves estimations, as well as future production profiles, are often different from the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.

Downward revision in our reserves estimates may result in: (a) higher depreciation and depletion charges in future periods; (b) an immediate write-down of an asset’s book value; or (c) changes in our accrual of the asset retirement obligation. If, on the other hand, the oil and gas reserve quantities were revised upward, our per barrel depreciation and depletion expense and our accrual of the asset retirement obligation would be lower. Changes in proved oil and gas reserves will also affect the standardized measure of discounted cash flows presented in note 25 to our financial statements.

Significant changes in market conditions, such as the change in gas prices during 2002, may cause us to revise our reserve estimates downward due to our determination that reserves are no longer recoverable in light of new market conditions.

Impact of Oil and Gas Reserves on Depreciation and Depletion.

The calculation of unit-of-production depreciation and depletion is a critical accounting estimate that measures the depreciation and depletion of upstream assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those proved reserves recoverable through existing wells with existing equipment and operating methods) applied to (3) asset cost. Proved undeveloped reserves are considered in the amortization of leasehold acquisition costs. The volumes produced and asset cost are known and while proved developed reserves have a high probability of recoverability they are based on estimates that are subject to some variability. This

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variability may result in net upward or downward revisions of proved reserves in existing fields, as more information becomes available through research and production. We revised our proved reserves in the last three years, decreasing our proved reserves by 25 million barrels of oil equivalent in 2004, decreasing our proved reserves by 40.4 million barrels of oil equivalent in 2003 and decreasing our proved reserves by 191.9 million barrels of oil equivalent in 2002. While the revisions we have made in the past are an indicator of variability, they have had a small impact on the unit-of-production rates because they have been small compared to our large reserves base.

Impairment of oil and gas assets.

A substantial part of our assets—P$6.5 billion, net of accumulated depletion, at December 31, 2004—consists of oil and gas producing properties. These properties are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. We estimate the future and discounted cash flows of the affected properties to judge the recoverability of carrying amounts.

We perform asset valuation analyses on an ongoing basis as a part of our management program. These analyses monitor the performance of assets against corporate objectives. They also assist us in reviewing whether the carrying amounts of any of our assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices.

In general, we do not view temporarily low oil prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, industry prices over the long term will continue to be driven by market supply and demand fundamentals. Accordingly, any impairment tests that we perform make use of our long-term price assumptions for the crude oil and natural gas markets. These are the same price assumptions that are used in our planning and budgeting processes and our capital investment decisions, and they are considered to be reasonable, conservative estimates given market indicators and past experience. Significantly lower future oil and gas prices could lead to impairments in the future, if such decreases were considered to be indicative of long-term trends. Additionally, significant changes in production curve expectation, discount and/or required production and lifting costs, could affect impairment analysis. While such uncertainties are inherent to this estimation process, the amount of impairment charges in past years has been: P$12 million in 2004, P$346 million in 2003 and P$107 million in 2002.

Successful efforts method of accounting.

We follow the successful effort method of accounting for our oil and gas activities. Occasionally, an exploratory well may determine the existence of oil and gas reserves which, upon completion of drilling, cannot be classified as proved reserves. In those cases, in accordance with the successful effort method of accounting, one of the following would be applicable:

(1)

If the well finds reserves in an area, which requires major capital expenditures before production may start, classification of that well’s reserves as proved would depend on whether any additional reserves are found that would justify such capital expenditures. The cost of the exploratory well will continue to be capitalized so long as (a) reserves found are sufficient to justify completion of the well to a productive well, if the relevant capital investments are made, and (b) the drilling of additional exploratory wells is in progress or firmly planned for the near future. If either of these two conditions is not fulfilled, drilling costs are charged to expenses.

(2)	If the reserves are not classified as proved for any other reason, drilling costs of exploratory wells will not remain capitalized for a period exceeding one year after the completion of the drilling.

In making decisions about whether to continue capitalizing exploratory drilling costs for a period longer than 12 months, it is necessary to make judgments about the satisfaction of each of these conditions. In making judgments about commercially producible quantities of reserves we take into consideration the expected cash flow to be generated by the development and production of the volumes of hydrocarbons. If we change our views, as a result of changed circumstances or otherwise, during a later period, we would expense the relevant exploratory drilling cost during such later period, such as occurred in 2002 with the Chontayacu well in Block 18 (Ecuador). See “—Discussion of Results—Year ended December 31, 2003 compared to year ended December 31, 2002—Analysis of Operating Results by Business Segment—Oil and Gas Exploration and Production.”

The application of the successful efforts method can cause material fluctuations between periods in exploration expenses if drilling results are different than expected or if we change our exploration and development plans.

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FASB has recently issued FASB Staff Position 19-1 “Accounting for Suspended Well Costs” (FSP 19-1) in March 2005, which applies to enterprises that use the successful efforts method of accounting. Application of this position would result in the continued capitalization, on a prospective basis, of the cost of certain exploratory wells beyond 12 months that do not satisfy the criteria described above if both (1) sufficient reserves have been found to justify completion as a producing well and (2) sufficient progress is being made towards assessing the reserves and the economic and operating viability of the project. This would result in lower write-offs if proved reserves are ultimately determined, with a consequential increase in depreciation, depletion and amortization in future periods.

Impairment of long-lived assets.

We record impairment losses on long-lived assets used in operations when events and circumstances indicate that the undiscounted cash flows estimated to be generated by those assets are less than the carrying amount of those items. Our cash flow estimates are based on historical results adjusted to reflect our best estimate of future market and operating conditions. Our estimates of fair values used to determine the resulting impairment loss, if any, represent our best estimate based on forecasted cash flows, industry trends and reference to market rates and transactions. Impairments can also occur when we decide to dispose of assets.

While we believe our estimates of future cash flows to be reasonable, different assumptions with respect to project commodity sales prices, production and overhead costs and foreign currency exchange rates and inflation could materially affect the anticipated cash flows to be generated by the long-lived assets, thereby, affecting our evaluation of their carrying values. Other factors that can lead to changes in estimates include variations in regulatory environments, restructuring plans, as well as the discount rate used for impairment testing. Changes in the discout rate can result from inflation rates, individual country risks and currency risks.

For example, in 2002 and 2003 as a result of the Argentine economic crisis, we adjusted the book value of certain long-lived assets, including certain of our investments in gas areas in Argentina. See note 10 to our consolidated financial statements.

Contingencies.

Certain conditions may exist as of the date of the financial statements, which may result in a loss to us, but which will only be resolved when one or more future events occur or fail to occur. We assess contingent liabilities based on the opinion of our legal counsel and available evidence. If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount can be estimated, a liability is accrued. If the assessment indicates that a potential loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the possibility of occurrence, is disclosed in a note to the financial statements. Loss contingencies considered remote are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

Changes in the facts or circumstances related to these types of contingencies, as well as the future outcome of these disputes, can have a significant effect on the amount of provisions for contingencies recorded. For example, in 2003, we recorded a provision of P$45 million in respect of environmental remediation work identified during the course of an environmental audit of our operations in light of applicable law. A change in applicable laws or a more stringent interpretation of such laws, or in our understanding thereof, may cause us to increase our expected costs in respect of this environmental remediation work.

Income tax.

We estimate income tax on an individual basis under the deferred tax method. The deferred tax balance as of the end of each period has been determined on the basis of the temporary differences generated in certain items that have a different accounting and tax treatment.

To book such differences, we use the liability method, which establishes the determination of net deferred tax assets and liabilities on the basis of temporary differences determined between the accounting measurement of assets and liabilities and the related tax measurement. Temporary differences determine the balance of tax assets

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and liabilities where its future reversal decreases or increases the taxes determined. In the event there are unused tax loss carry-forwards that may be offset against future taxable income, we will evaluate the recoverability of a deferred tax asset, only to the extent that it is “more likely than not” (under U.S. GAAP) or “probable” (under Argentine GAAP) that some portion or all of the deferred tax asset will be realized.

Deferred tax assets and liabilities have been valued at their nominal value, as established by CNV’s General Resolution No. 434. The professional accounting standards effective in the city of Buenos Aires require that such nominal value be discounted at a current rate estimated as of each year-end.

Judgment is required in determining the amounts of future income tax assets and liabilities and the related valuation allowance recorded against the net future income tax assets. In assessing the potential realization of future income tax assets, management considers whether it is “more likely than not” (under U.S. GAAP) or “probable” (under Argentine GAAP) that some portion or all of the future income tax assets will be realized. The ultimate realization of future income tax assets is dependent upon us generating sufficient future taxable income from operations during the period in which the future income tax assets are recoverable. Management expects to realize all the future income tax assets. However, some uncertainty exists surrounding our ability to generate sufficient taxable income from operations before the expiration of the loss carry forwards. To reflect this uncertainty, we have provided a valuation allowance of million P$1,336 million against tax loss carry forwards as at December 31, 2004. In future periods, we, after evaluating more recent data about our future performance and prospects, may reverse a part of this allowance. In 2004, for example, after taking into consideration the profitability expectations arising from Petrobras Energía’s business plan, we partially reversed an allowance for tax loss carry forwards in Argentina and recognized a gain of P$268 million.

LIQUIDITY AND CAPITAL RESOURCES

We prioritize liquidity maintaining adequate levels to secure compliance with our financial obligations, supporting our growth strategy. Financial solvency is the foundation – and the guiding principle – on which sustainable development of our businesses is built.

Pursuant to these strategic guidelines, we seek to:

•

Gradually reduce our level of indebtedness, by creating and maintaining a capital structure in line with industry standards and adaptable to those financial markets in which we operate, and by establishing a debt maturity profile that is consistent with our cash generation;

•

Gradually reduce our indebtedness costs;

•

Have adequate flexibility to overcome the high volatility inherent in emerging capital markets, by adhering to a conservative cash management policy that minimizes the risks of financial distress; and

•

Gradually increase our capital investments in the future.

From 2002 through 2004, by adhering to these guidelines, we have achieved the following:

•

138% growth in our operating cash flow.

•

Strict compliance with all of our financial obligations, with a 12% decline in annual average indebtedness.

•

With the issuance in October 2003 of US$100 million aggregate principal amount of our Series R notes due 2013, we became the first Argentine company to place an issuance of new debt in the international market following the Argentine government’s default. In addition, in April of 2004 we successfully reopened this series of notes and obtained an additional US$100 million in financing.

•

Significant increase in investments, supporting the growth strategy. See “—Analysis of Liquidity and Capital Resources—Investing Activities.”

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We have traditionally funded our capital expenditures with a combination of cash from operations and debt financings.

In the short term, the most significant factors generally affecting our cash flow from our operating activities are (1) fluctuations in prices for crude oil, (2) production levels and demand for our products, (3) margins in refining and petrochemicals, (4) changes in regulations or conditions in the countries where we operate (such as taxes on exports, changes in royalties payments and price controls) and (5) fluctuations in exchange and inflation rates. See generally “Item 3. Key Information—Risk Factors.” The Argentine crisis had a significant negative impact on our ability to refinance our indebtedness and to finance our investment projects.

In connection with our derivative financial instruments, we have to meet collaterals requirements to reduce the related counterparty credit risk. As of December 31, 2004, we had posted cash collateral amounting to US$57 million in connection with derivative contracts outstanding as of such date covering transactions that are scheduled to occur during 2005. Total amount of cash collateral is dependant on the future WTI. Significant increases in WTI would require us to provide additional cash collateral, which in the short-term would affect our liquidity.

In the longer term, our ability to replace reserves will affect our capacity to maintain or increase production levels in Exploration and Production, which, in turn, will affect our cash flow provided by operating activities. Nonetheless, we do not believe that the risks associated with failure or delay of any single project would have a significant impact on our overall liquidity or ability to generate sufficient cash flows for operations and fixed commitments, since we have a diverse portfolio of development projects and exploration opportunities, which helps to mitigate the overall political and technical risks of Exploration and Production and the associated cash flow provided by operating activities. For example, we have recently had a delay in our projects in Ecuador in connection with the development of Blocks 31 and 18, but have been able to meet our financial obligations there and elsewhere in part due to our diverse portfolio throughout Latin America. See “Item 4. Information About the Company—Oil and Gas Exploration and Production.”

Analysis of Liquidity and Capital Resources

Our management analyzes its results and financial condition separately from the results and financial condition of affiliates under joint control. The discussion below, therefore, relates to the liquidity and capital resources of us and our controlled subsidiaries, excluding proportional consolidation of companies over which we exercise joint control, and as a result may not be directly comparable to amounts reflected in our financial statements. See “—Proportional Consolidation and Presentation of Discussion.”

The table below reflects our statements of cash flow for the fiscal years ended December 31, 2004, 2003 and 2002 under Argentine GAAP and, for comparative purposes, the pro forma statements of cash flow excluding the effect of proportional consolidation of companies over which we exercise joint control.


	With Proportional Consolidation						Without Proportional Consolidation
	2004		2003		2002		2004		2003		2002
	(in millions of pesos)
Cash and cash equivalents at beginning of year⁽¹⁾	927		725		1,333		545		693		1,256
Additions (deductions) of cash and cash equivalents from proportional interest in CIESA at beginning of period	—		103		(64	)	—		—		—
Net cash provided by operations	1,463		1,353		710		1,269		1,003		532
Net cash used in investing activities	(1,039	)	(915	)	(182	)	(912	)	(857	)	(114	)
Net cash provided by (used in) financing activities	(432	)	(251	)	(1,827	)	(203	)	(206	)	(1,754	)
Devaluation and inflation effects on cash	(6	)	(88	)	755		(7	)	(88	)	773

Cash and cash equivalents at end of year	913		927		725		692		545		693

(1)	For 2003, this amount does not include cash and cash equivalents from our proportional interest in CIESA.

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Cash

As of December 31, 2004, 2003 and 2002, cash and cash equivalents totaled P$692 million, P$545 million and P$693 million, respectively. The increase in operating cash flow in 2004 caused an increase in liquidity levels. Our goal is to maintain excess cash, primarily in US dollars, in short-term investments, such as money market funds and overnight deposits, in order to ensure adequate liquidity levels.

Pursuant to Decree No. 1589/89 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 and repatriate the remaining 30% through the Argentine exchange markets.

Operating activities

Net cash from operations, excluding the proportional consolidation of companies under joint control, was P$1,269 million in 2004, P$1,003 million in 2003 and P$532 million in 2002.

In 2004, net cash from operations increased P$266 million, primarily due to the increase in the WTI, an increase in our refining margins and increased sales volumes of petrochemical and refined products.

In 2003, net cash from operations increased P$471 million, mainly due to the increase in the WTI and refining margins, a decrease in interest expense and a reduction in losses attributable to derivatives instruments use to hedge the price of crude oil.

Investing activities

Cash used in investing activities, excluding the proportional consolidation of companies under joint control, was P$912 million in 2004, P$857 million in 2003 and P$114 million in 2002.

Capital expenditures, excluding the proportional consolidation of companies under joint control, increased by P$131 million to P$909 million in 2004 from P$778 million in 2003, triggered by the recovery in our operating cashflow and improved liquidity.

The table below reflects total capital expenditures, net, on a cash flow basis:


	Fiscal years ended December 31,
	2004	2003		2002
	(in millions of pesos)
Oil and Gas Exploration and Production	766	696		596
Petrochemicals	96	32		22
Refining	29	25		64
Hydrocarbon Marketing and Transportation	6	11		39
Electricity	1	—		2
Corporate Structure and Other Investments	11	14		9

Total capital expenditures	909	778		732
Divestments	—	(20	)	(593	)

Total net capital expenditures	909	758		139

As part of our long-term strategy to grow as an integrated energy company in Latin America, we have increased our investments outside of Argentina to diversify our business portfolio and have attempted to increase our US dollar cash flow. Capital expenditures made outside Argentina accounted for approximately 55% for the 2004-2002 period, totaling P$1,340 million.

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Oil and Gas Exploration and Production.

Capital investment made in the oil and gas exploration and production business segment totaled P$766 million, P$696 million and P$596 millions in 2004, 2003 and 2002, respectively. In 2004, capital expenditures in the Oil and Gas Exploration and Production business segment were primarily directed towards maintaining production levels and prioritizing investments in countries and products with higher expected profit margins. In 2004, 246 wells were drilled, of which 202 are located in Argentina and 394 units were repaired, of which 203 are located in Argentina. In Argentina, development of reserves continued through well drilling and expansion of corresponding surface facilities. Work relating to the La Porfiada Field Interconnection Project started and led to the development of gas reserves. In Venezuela, capital expenditures were primarily directed towards the construction of development wells, and, to a lesser extent, investments were made in lifting improvements and additional surface equipment. Our capital expenditure efforts led to a 20% increase in oil sales volumes in Venezuela. In Ecuador, at Block 18, four wells were drilled and we began expansion works in our early production facilities, resulting in a gross production of 25,000 barrels per day.

Refining and Petrochemicals.

Capital expenditures in the Refining and Petrochemical business segment totaled P$125 million, P$57 million and P$86 million in 2004, 2003 and 2002, respectively. Capital expenditures in these segments were primarily directed towards maintaining efficient operating conditions. In addition, US$9 million were invested in the new ammonium thiosulphate plant, which started operations in 2004 with a capacity of 140,000 tons per year of fertilizers. We also invested approximately US$6 million in the acquisition and commissioning of an ethylene plant with a capacity of 20,000 ton per year.

Hydrocarbon Marketing and Transportation.

In the Hydrocarbon Marketing and Transportation business segment, in May 2004, we increased our interest in OCP by 2.46%, when Techint Internacional Construction Corp. exercised an irrevocable option to sell its shares to us for P$6 million. In 2003, we made contributions to OCP in the amount of P$11 million, while in 2002 we were required to disburse P$39 million to maintain letters of credit that secure our investment commitments in connections with OCP.

Financing activities

Most of our financial debt and a significant portion of the debt of our main affiliates are denominated in US dollars. As of December 31, 2004, our total indebtedness, excluding proportional consolidation of companies under joint control, was P$5,949 million, of which P$4,802 million was long-term indebtedness. This compares to P$6,063 million as of December 31, 2003, of which P$5,009 was long-term indebtedness. As of December 31, 2004, our short-term indebtedness totaled P$1,147 million, of which P$859 million represents the current portion of long-term obligations and P$278 million represents short-term indebtedness with financial institutions under loan agreements and foreign trade financing.

Our long-term debt primarily consists of corporate notes. We maintain a global corporate note program with a maximum principal amount at any time outstanding of US$2.5 billion or its equivalent in any currency, which we refer to as our Global Note Program. As of December 31, 2004, notes in an aggregate principal amount of US$1,569 million were outstanding under this program. The Global Note Program is rated at “A+(arg)” and “raA+” by Fitch Argentina Calificadora de Riesgo S.A. and Standard & Poor’s International Ratings, LLC, Argentina, respectively. On an international basis, Fitch Rating Ltd and Standard & Poor’s Rating Services have assigned the program a credit rating of “B”. Notes under the program are not subject to acceleration in the event our credit ratings are downgraded.

As of April 30, 2005, notes outstanding under the Global Note Program were:

•

Class B notes, in an aggregate principal amount of US$5 million, payable in a single installment in May 2006, accruing interest at a 9% annual rate;

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•

Class F notes, in an aggregate principal amount of US$64.4 million maturing in August 2005, accruing interest at a 7.875% annual rate;

•

Class G notes, in an aggregate principal amount of US$250 million maturing in January 2007, accruing interest at a 9% annual rate;

•

Class H notes, in an aggregate principal amount of US$181.5 million maturing in May 2009, accruing interest at a 9% annual rate;

•

Class I notes, in an aggregate principal amount of US$349.2 million maturing in July 2010, accruing interest at an 8.125% annual rate;

•

Class N notes, in an aggregate principal amount of US$87 million maturing in June 2011, accruing interest at six-month LIBOR plus 1%;

•

Class Q notes, in an aggregate principal amount of US$3.6 million maturing in April 2008, accruing interest at a 5.625% annual rate; and

•

Class R notes, in an aggregate principal amount of US$200 million, with final maturity in October 2013, accruing interest at a 9.375% annual rate (issued in US$100 million tranches in October 2003 and in April 2004).

Class F, G, H, I, N, Q and R notes include cross default covenants, whereby the trustee under those notes, if instructed by the noteholders representing at least 25% of the outstanding principal amounts of a series of notes, shall declare all the amounts owed due and payable, if any debt of ours or our significant subsidiaries is not paid when due, provided that (1) those due and unpaid amounts exceed the higher of US$25 million, or 1%, of Petrobras Energía’s shareholders’ equity at the time such debt is due, and (2) the default has not been cured within 30 days after we have been served notice of the default.

Certain other loan agreements, include cross default covenants, whereby the Trustee or the lender, as appropriate, may declare all the amounts owed as due and payable, if any debt of ours exceeding US$10 million, or 1%, of our shareholders’ equity is not paid when due.

In addition to the Global Note Program, Petrobras Energía had a US$1.2 billion global medium-term note program, which we refer to as the US$1.2 Billion MTN Program. In June 1998, the right to issue new notes under this program expired. As of the date of this annual report, one series of notes remained outstanding under this program, with an aggregate principal amount of US$32.6 million, maturity of July 2007, and interest at 8.125%.

A small portion of our long-term debt consists of (1) loans granted by the International Finance Corporation in order to finance capital expenditures in Venezuela and the construction of Innova plants in Brazil, (2) foreign trade financing operations and (3) bank loans obtained by other foreign subsidiaries.

The following is our debt maturity profile as of December 31, 2004:


1 year	2 years	3 years	4 years	5 years	6 or more years
(in millions of pesos)
1,147	618	1,345	230	603	2,006

Net cash used in financing activities, excluding the proportional consolidation of companies under joint control, totaled P$203 million, P$206 million and P$1754 million in 2004, 2003 and 2002, respectively. We paid long-term indebtedness in the amount of P$988 million, P$629 million and P$1,724 in 2004, 2003 and 2002, respectively. Cash provided by long-term financing totaled P$669 million, P$591 million and P$124 million in 2004, 2003 and 2002, respectively. Cash provided by short-term financing totaled P$116 million in 2004, primarily from foreign trade financing, compared to P$168 million of cash used in short-term financing in 2003 and to P$154 million in 2002.

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Our long-term financing in 2004 consisted of the following:

•

In April 2004, we issued Tranche 2 of our Class R notes under our Global Notes Program for an aggregate principal amount of P$289 million (US$100 million), which represents a single class with our Class R notes issued in October 2003. The Class R notes are due October 2013 and accrue interest at a rate of 9.375% per annum.

•

In September 2004, Petrobras Internacional Braspetro BV, a subsidiary of Petrobras, granted us a P$150 million loan (US$50 million), which accrues interest at a rate of 7.5% per annum. The principal loan is repayable in one installment in 42 months and may be prepaid without penalties.

•

The International Finance Corporation made the last disbursement of P$85 million (US$29 million) under the loan granted in 2003 to our subsidiary Petrobras Energía Venezuela S.A.

•

Cash provided by foreign trade financing totaled P$60 million (US$20 million).

•

Petrobras Energía del Perú S.A. received a P$84 million (US$30 million) disbursement, under the loan granted by a syndicate of banks in 2003, which constituted the last disbursement under such loan.

Our main long-term financing in 2003 consisted of the following:

•

In October 2003, we issued Class R notes in the amount of P$286 million (US$100 million).

•

In December 2003, the first disbursement in the amount of P$206 million (US$76 million) was received under a US$105 million loan entered into between Petrobras Energía Venezuela S.A. and the Internacional Finance Corporation.

•

In August 2003, our subsidiary Petrobras Energía del Perú S.A. received a first disbursement of P$87 million (US$30 million) under a loan agreement entered into with a syndicate of banks.

•

In 2002, we issued Class E notes in the amount of P$124 million (US$35 million).

Payments, Prepayments and Refinancing

During 2005, we prepaid the total outstanding principal amount of Class K and M notes under our Global Notes Program in a total amount of US$335 million. In connection with these series of notes, we were subject to compliance with certain covenants, including restrictions on payments of dividends and capital expenditures. As a result of the prepayment, our obligations under these covenants are no longer in effect. We also prepaid the outstanding amount of Class C medium term notes for US$63 million. A significant portion of the repayments of debt that have been made during 2005 was financed with loans provided by Petrobras.

In 2004, we made partial payments of principal of Class C, M and K notes under our Global Notes Program. We fully repaid at maturity the Class O and P notes of the same program and the Fourth Series of the US$1.2 Billion MTN program. These partial payments and full payments, together, totaled P$881 million. In addition, we repaid bank loans in the amount of P$107 million.

In 2003, we paid at maturity Class E, J and L notes under our Global Notes Program in an amount of P$421 million (US$146 million). In addition, we repaid bank loans and long-term lines of credit in an amount of P$208 million.

In 2002, we made payments of long-term liabilities, including payments towards (1) our Fifth Series of notes in an aggregate amount of P$841 million (US$177 million), issued under the US$1.2 billion global program,

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which were paid in March 2002; (2) financial debt with an aggregate principal amount of approximately P$553 million (US$144 million), which was cancelled pursuant to the terms and conditions of the exchange offers launched to refinance our overall debt; and (3) outstanding notes in aggregate principal amount of P$86 million (US$22 million) issued under PASA S.A.’s global note program (later absorbed by us), which were repaid at maturity.

Changes to Exchange Market Regulations

On June 9, 2005, the federal executive branch issued Executive Order 616/2005. As a result of this executive order any cash inflow to the domestic market derived from foreign loans to the Argentine private sector shall have a maturity for repayment of at least 365 days as from the date of inflow of cash. In addition, 30% of the amount shall be deposited with domestic financial institutions. This deposit must be (1) registered, (2) non-transferable, (3) non-interest bearing, (4) made in US dollar, (5) have a term of 365 days and (6) cannot be used as security or collateral in connection with other credit transactions. Export and import financings and primary public offerings of debt securities listed on self-regulated markets are exempt from the foregoing provisions.

This Executive Order may limit our ability to finance our operations through new intercompany loans or any other kinds of financial loans.

Future Capital Requirements

In 2005, we expect to make investments for approximately US$550 million. These investments, which include approximately US$100 million for activities performed by EG3, PAR and PSF (See “Item 4. Information About the Company—Our History and Development—Petrobras Energía Merger”), are part of our strategy of sustained growth, which we have pursued in accordance with growth and expansion targets contemplated in our business plan.

We currently expect that our capital investment requirements, financial debt payment obligations and working capital will be financed by cash from operations and, to a lesser extent, by new debt financings and possible divestments. Our level of investments will depend on a variety of factors, many of which are beyond our control. These include the future price evolution of the commodities we sell, the behavior of energy demand in Argentina and in regional markets, the existence and competitive impact of alternative projects, regulatory developments, changes in applicable taxes and royalties, the economic situation prevailing in Argentina, Venezuela and the Mercosur region and changes in exchange rates.

Oil and Gas Exploration and Production

Our 2005 business investment plan will primarily focus on the Oil and Gas Exploration and Production segment, with special emphasis on operations in Argentina, Venezuela and Ecuador. Projected investments in this segment will be in line with the goal of increasing reserves and production to secure our sustainable growth.

Argentina. Our efforts are expected to continue at the Neuquen Basin to develop oil reserves through well drilling and the improvement of existing secondary recovery projects. With respect of gas production at the Neuquen basin, two main areas of development are contemplated: (1) the evaluation of gas tight reservoirs both in exploratory as well as upsides in development areas and (2) building of facilities for the Mangrullo field, formerly owned by PFS, with first gas expect by middle 2006. At the Austral basin, drilling expenditures will be mainly directed toward development and delimitation of oil reserves. Facilities expenditures at Austral Basin will have two main focuses: (1) the building of a new treatment plan to improve Santa Cruz I and II assets oil quality and (2) the building of gas facilities (pipelines, compression units and gas treatment plants) to interconnect the asset’s gas reserves and maintain the production.

Venezuela. The 2005 business plan contemplates the development of producing reservoirs, with a special focus on drilling and lifting improvement activities. In addition, efforts are expected to be made to enhance facilities to secure profitable production under applicable safety and environmental standards. Our 2005 business plan in Venezuela ultimately may be affected by the current discussion with PDVSA in connection with the renegotiation of certain of our contracts. See “Item 3. Key Information—Risk Factors—Factors Relating to Venezuela Changes in

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the regulatory and contractual framework applicable to our operating agreements have and may in the future adversely affect our financial position and results of operations.”

Ecuador. Development of Block 18 is expected to continue through drilling of producing wells and the construction of a treatment plant and infrastructure works for crude oil transportation. In Block 31, development of the Apaika Nenke field is foreseen through the construction of a pier and access area. In addition, construction works are expected to start in connection with the crude oil treatment and water injection plants and the oil pipeline to transport crude oil to OCP.

Peru. The capital expenditure program contemplates execution of drilling and secondary recovery projects aimed at developing reserves and increasing the recovery factor. In addition, the program contemplates execution of optimization projects for the recovery of production and greater efficiency in operating costs.

Refining

In the Refining segment, we will continue developing the retail commercial network. In this regard, investments are projected to increase the number of gas stations and simultaneously continue the rebranding efforts to the Petrobras brand, with a view to consolidating its image and sustained growth in customer satisfaction ratings. In addition, investments are foreseen to improve the efficiency and operating reliability of our refineries and expand logistics infrastructure.

Petrochemicals

In the Petrochemicals business segment, investments are expected to be made to consolidate our leadership in the fertilizer and styrene businesses and expand product offerings in those businesses.

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OFF-BALANCE SHEET TRANSACTIONS

Other than the transactions described below, we do not have any off-balance sheet arrangements required to be disclosed by Item 5 of Form 20-F.

OCP Investment’s Letters of Credit

We are required to procure letters of credit in order to guarantee a portion of our commercial obligations under the ship or pay contract with OCP and of OCP’s financial obligations. As of December 31, 2004, we had procured letters of credit for US$214 million, of which for US$148 million we were required to post cash collateral for the benefit of the banks issuing these letters of credit. As from April 2005, in connection with the redemption of Class K and M notes under our Global Program and other medium term debt instruments, we replaced the outstanding letters of credit with letters that do not require us to post cash collateral. As of May 31, 2005, the letters of credit totaled US$133 million. These letters of credit must remain in place until our underlying obligations expire or are terminated. We are required to renew or replace these letters of credit as they mature, otherwise, we will be required to repay the amounts due in cash at maturity, which will have a material adverse effect on our cash flows.

Derivative Financial Instruments

We have commitments under derivative financial instruments. For a discussion of these additional commitments, see “Item 11. Quantitative and Qualitative Disclosure About Market Risk.” In connection with our derivative financial instruments, we have to procure letters of credit and meet collaterals requirements to reduce the related counterparty credit risk. As of December 31, 2004, we had posted cash collateral amounting to US$57 million in connection with derivative contracts, which will be in effect during 2005. The total amount of cash collateral that must be delivered under these instruments varies depending on the future WTI. Significant increases in WTI would require us to provide additional cash collateral, which in the short-term would affect our liquidity. As of December 31, 2004, we had procured standby letters of credit in place in favor of these counterparties with total commitments of US$99 million.

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CONTRACTUAL OBLIGATIONS

The following table summarizes certain contractual obligations as of December 31, 2004. The table does not include accounts payable or pension liabilities.


	Payments due by period
	Total	Less than 1 Year	1 - 3 years	3 - 5 years	More than 5 years
	(in millions of pesos)
Debt Obligations	5,949	1,147	1,963	833	2,006
Significant Operating Lease Obligations	2	1	1	—	—
Purchase Obligations:
Ship or pay agreement with OCP⁽¹⁾.	2,413	172	345	345	1,551
Long–term service agreement	88	29	59	—	—
Gas transportation agreement with TGS⁽²⁾	402	30	60	60	252
Ethylene ⁽³⁾	714	65	130	130	389
Benzene ⁽⁴⁾	2,425	220	441	441	1,323
Investment commitments	233	72	51	68	42
Total	12,226	1,736	3,050	1,877	5,563

⁽¹⁾	Estimated price US$2.20 per barrel.⁽⁵⁾

⁽²⁾	Estimated price P$0.038 million per millions of cubic meters.⁽⁵⁾

⁽³⁾	Estimated price US$711 per ton.⁽⁵⁾ Contractual prices are in US dollars. Peso amounts translated using exchange rate as of December 31, 2004.

⁽⁴⁾	Estimated price US$875 per ton.⁽⁵⁾ Contractual prices are in US dollars. Peso amounts translated using exchange rate as of December 31, 2004.

⁽⁵⁾

Our obligations under these agreements are determined by volume, and prices are generally determined by formulas based on future market prices of the goods or services under each contract. Estimated prices used to calculate the monetary equivalent of these purchase obligations for purposes of the table are based on current market prices as of December 31, 2004 and may not reflect actual future prices of these commodities. Accordingly, the peso amounts provided in this table with respect to these obligations are provided for illustrative purposes only.

The following table sets forth volume information with regard to our commitments under commercial contracts for which a fixed price has been agreed, for the years indicated below, as of December 31, 2004.


	Obligations by period
	Total	Less than 1 Year	1 -3 years	3 -5 years	More than 5 years
Purchase Obligations
Ship or pay agreement with OCP (in millions of barrels)	389	26	53	53	257
Gas transportation agreement with TGS (in millions of cubic meters)	10,674	1,199	2,398	2,398	4,679
Ethylene (in thousands of tons)	337	31	61	61	184
Benzene (in thousands of tons)	930	85	169	169	507

Sales Obligations
Natural gas (in millions of cubic meters)	19,729	2,200	2,858	2,449	12,222
Styrene (in thousands of tons)	52	46	6	—	—
Electric power (in MWh)	587,291	512,329	74,962	—	—

Long Term Service Agreement. We have entered into a long term service agreement for the maintenance and repair of Genelba.

OCP Oil Transportation Agreement. Regarding the future exploitation of Blocks 18 and 31, we have executed an agreement with OCP whereby we acquired an oil transportation capacity of 80,000 barrels per day for a term of 15 years as from commencement of OCP operations. We, as well as the remaining producers, that have entered into capacity agreements with OCP, are required to pay a ship or pay fee that will cover, among other items, OCP’s operating costs and financial services. We have assigned part of our committed transportation capacity, or

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approximately 8,000 barrels per day to a third party. See “Item 4. Information About the Company—Oil and Gas Exploration and Production—Production—Production outside of Argentina—Ecuador—Ship or Pay Contract with Oleoducto de Crudos Pesados (OCP).”

Innova Supply Agreements. Benzene and ethylene feedstock, necessary for Innova operations, are supplied by Copesul, a Brazilian company, pursuant to a long-term contract that expires in 2014.

Gas Transportation Agreements. We have entered into various gas firm transportation agreements with TGS to provide gas transportation services to Genelba.

Investment commitments: Petrobras Energía Perú S.A. has entered into an agreement with the Peruvian Government, whereby it undertook the commitment to make investments in Lot X amounting to at least US$97 million approximately over the period 2004-2011. As of December 31,2004, US$18 million of this amount had already been invested. In addition, we have some exploratory commitments.

In respect of Block 31, we have the commitments to perform an environmental impact study, as well as 120 sq. km of 3D seismic readings, processing and interpretation, reprocessing 500 km of 2D seismic studies for integration with the new 3D seismic and the drilling of an exploratory well, representing an investment of about US$16 million. Meanwhile, in Block 18, we have commitments amounting to approximately US$47 million related to the operation of the Pata and Palo Azul fields and including production well drilling and construction of crude-oil treatment plants.

U.S. GAAP RECONCILIATION

We had net income under U.S. GAAP of P$760 million in 2004, as compared to net income of P$100 million in 2003 and to net losses of P$1,554 million in 2002. Under Argentine GAAP, we reported net income of P$678 million in 2004 and P$381 million in 2003 , as compared to a net loss of P$1,579 million in 2002.

There are several differences between Argentine GAAP and U.S. GAAP that significantly affect our net income and stockholders’ equity. The most significant differences in their effect on 2004 net income related to foreign currency translation adjustments, the depreciation of property, plant and equipment, the accounting for derivative instruments and deferred income taxes. See note 22 to our financial statements. Neither the effects of inflation accounting nor the proportional consolidation of Distrilec, a company under joint control, under Argentine GAAP have been reversed in the reconciliation to U.S. GAAP. The proportional consolidation of CIESA, another company under joint control, in 2004 and 2003 under Argentine GAAP has been reversed in the reconciliation to U.S. GAAP.

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RECONCILIATION TABLES

The following tables reconciliate our results for the years ended December 31, 2002, 2003 and 2004 with proportional consolidation as required by new changes to Argentine GAAP to our results as adjusted to reflect the elimination of proportional consolidation:


	For the Year Ended December 31, 2004
	With Proportional Consolidation		CIESA⁽¹⁾		Distrilec⁽²⁾		Without Proportional Consolidation
	(in millions of pesos)
Net sales	6,974		(472	)	(535	)	5,967
Costs of sales	(4,210	)	219		449		(3,542	)

Gross profit	2,764		(253	)	(86	)	2,425
Administrative and selling expenses	(640	)	16		66		(558	)
Exploration expenses	(89	)	—		—		(89	)
Other operating income (loss) net	(304	)	22		17		(265	)

Operating income	1,731		(215	)	(3	)	1,513
Equity in earnings of affiliates	76		16		(13	)	79
Financial income (expense) and holding gains (losses)	(1,261	)	144		20		(1,097	)
Other expenses, net	(27	)	14		(18	)	(31	)

Income (loss) before income tax and minority interest in subsidiaries	519		(41	)	(14	)	464
Income tax provision	198		6		20		224
Minority interest in subsidiaries	(39	)	35		(6	)	(10	)

Net income (loss)	678		—		—		678

(1)	The results of CIESA are proportionally consolidated in our Hydrocarbon segment.

(2)	The results of Distrilec are proportionally consolidated in our Electricity segment.


	For the Year Ended December 31, 2003
	With Proportional Consolidation		CIESA⁽¹⁾		Distrilec⁽²⁾		Without Proportional Consolidation
	(in millions of pesos)
Net sales	5,494		(432	)⁽³⁾	(447	)	4,615
Costs of sales	(3,386	)	196		373		(2,817	)

Gross profit	2,108		(236	)	(74	)	1,798
Administrative and selling expenses	(559	)	30		65		(464	)
Exploration expenses	(196	)	—		—		(196	)
Other operating income (loss) net	(121	)	12		5		(104	)

Operating income	1,232		(194	)	(4	)	1,034
Equity in earnings of affiliates	163		219		(11	)	371
Financial income (expense) and holding gains (losses)	(417	)	(123	)	(28	)	(568	)
Other expenses, net	(421	)	1		12		(408	)

Income (loss) before income tax and minority interest in subsidiaries	557		(97	)	(31	)	429
Income tax provision	(18	)	(58	)	29		(47	)
Minority interest in subsidiaries	(158	)	155		2		(1	)

Net income (loss)	381		—		—		381

(1)	The results of CIESA are proportionally consolidated in our Hydrocarbon segment.

(2)	The results of Distrilec are proportionally consolidated in our Electricity segment.

(3)	Net of P$14 million in intercompany sales.

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	For the Year Ended December 31, 2002
	With Proportional Consolidation		CIESA⁽¹⁾	Distrilec⁽²⁾		Without Proportional Consolidation
Net sales	5,106		—	(519	)	4,587
Costs of sales	(3,284	)	—	406		(2,878	)

Gross profit	1,822		—	(113	)	1,709
Administrative and selling expenses	(609	)	—	77		(532	)
Exploration expenses	(58	)	—	—		(58	)
Other operating income (loss) net	(28	)	—	—		(28	)

Operating income	1,127		—	(36	)	1,091
Equity in earnings of affiliates	(638	)	—	(9	)	(647	)
Financial income (expense) and holding gains (losses)	(1,827	)	—	168		(1,659	)
Other expenses, net	(187	)	—	9		(178	)

Income (loss) before income tax and minority interest in subsidiaries	(1,525	)	—	132		(1,393	)
Income tax provision	(82	)	—	(127	)	(209	)
Minority interest in subsidiaries	28		—	(5	)	23

Net income (loss)	(1,579	)	—	—		(1,579	)

(1)	For the 2002 fiscal year we did not proportionately consolidate on a line-by-line basis the assets, liabilities, earnings and cash flow of CIESA, since, as of December 31, 2002 our equity interest in such company had a P$33 million negative value.

(2)	The results of Distrilec are proportionally consolidated in our Electricity segment.

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Item 6. DIRECTORS,

SENIOR MANAGEMENT AND EMPLOYEES

DIRECTORS AND SENIOR MANAGEMENT

Board of Directors

In accordance with our by-laws, the Board of Directors, which formally meets at least once every three months, shall comprise a minimum of six and a maximum of nineteen members. Shareholders may appoint a number of alternate directors that may be equal to or lower than the number of regular directors in order to fill any vacancy, in the order of their appointment. Directors and alternate directors are appointed by shareholders at their annual shareholders’ meeting for the term of two fiscal years, with half of the directors up for election every year. The most recent annual shareholder’s meeting was held on March 31, 2005.

The following table sets out the members and alternate members of our Board of Directors.


Name	Year of appointment	Year first joined Petrobras Energía	Position	Term Expires
José Eduardo de Barros Dutra	2003	—	Chairman	2005
Nestor Cuñat Cerveró	2003	—	Vice Chairman	2005
Ildo Luis Sauer	2003	—	Director	2006
José Sergio Gabrielli de Azevedo	2003	—	Director	2005
Guilherme de Oliveira Estrella	2003	—	Director	2006
Renato de Souza Duque	2003	—	Director	2006
Luiz Augusto Marciano da Fonseca	2004	2003	Director	2006
Luis Miguel Sas	2003	1984	Director	2006
Alberto da Fonseca Guimarães	2003	2002	Director	2005
Oscar Anibal Vicente	1981	1970	Director	2005
Cedric Bridger	2004	—	Director	2005
Héctor Daniel Casal	2003	1991	Director	2005
Daniel Maggi	2003	1993	Director	2005
Nicolas Perkins	2004	—	Director	2006
Roberto Alejandro Fortunati	2004	—	Director	2006
Carlos Alberto Pereira de Oliveira	2004	2003	Director	2005
Alberto Javier Saggese	2005	2003	Director	2006
Decio Fabricio Oddone Da Costa	2005	—	Director	2006
Paulo Roberto Costa	2004	—	Director	2005
Pablo Cavallaro	2004	—	Alternate Director	2006
Vilson Reichemback da Silva	2005	2004	Alternate Director	2006

In compliance with Resolution No. 368 of the National Securities Commission, Nicolas Perkins, Roberto Alejandro Fortunati and Pablo Cavallaro qualify as independent directors, and the other directors are not independent in accordance with the National Securities Commission rules. Resolution No. 368 provides that a member of a corporate body shall not be considered independent if that member fits one or more of the following descriptions:

•

The member is also a member of management or an employee of shareholders who hold significant interests in the issuer, or of other entities in which these shareholders hold either directly or indirectly significant interests or over which these shareholders exercise a significant influence.

•

The member is an employee of the issuer or has been an employee in the last three years.

•

The member has professional relations or is part of a company or professional association that maintains professional relations with, or that receives remunerations or fees (other than directors’ fees)

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from, the issuer or from its shareholders that hold either directly or indirectly significant interests in or exercise a significant influence over the issuer, or from which such shareholders hold either directly or indirectly significant interests or exercise a significant influence.

•

The member is either directly or indirectly a holder of significant interests in the issuer or in an entity that has significant interests in or exercises a significant influence over the issuer.

•

The member sells or provides either directly or indirectly goods or services to the issuer or to shareholders that hold either directly or indirectly significant interests in or exercise a significant influence over the issuer and receives compensation for such services that is substantially higher than that received as a director.

•

The member is married or is a family member, up to fourth degree by blood or up to second degree by affinity, to an individual who would not qualify as independent.

“Significant interests” shall mean shareholdings that represent at least 35% of the capital stock of the relevant entity, or a smaller percentage when the person has the right to elect one or more directors by class of shares or by having entered into agreements with other shareholders relating to the governance and the management of the relevant entity or of its controlling shareholders.

The following is a brief summary of the principal business and academic experience of each of our directors listed in the table above:

José Eduardo de Barros Dutra (48) graduated in Geology from Universidade Federal Rural do Rio de Janeiro, Brazil, in 1979. He carried out a geological mapping of Rio de Janeiro from 1983 to 1990. In 1994 he was elected Senator of the Federative Republic of Brazil from the State of Sergipe for the 1995–2003 period and President of the Sindicato dos Mineiros do Estado de Sergipe (State of Sergipe Miners Union) from 1989 to 1994. He was a member of the following Federal Senate Committees of Brazil: Constitutional and Justice, Economic Affairs, Infrastructure, Education, and Supervision and Control. Mr. Dutra also served as leader of the Workers’ Party from 1996 to 1997, and as a member of the Workers’ Party National Executive Committee. In January 2003 he was appointed Chairman of Petrobras. He is Chairman of Petrobras Energía, Petrobras Gas S.A.; Petrobras Quimica S.A. and Petrobras Transporte S.A., and is also a member of the boards of directors of Petrobras, Petrobras Energía, Petrobras Distribuidora S.A.

Nestor Cuñat Cerveró (53) graduated in Chemical Engineering from Universidade Federal do Rio de Janeiro, and completed post-graduate studies in Process Engineering while at Petrobras and MBA courses for managers and executives at Getúlio Vargas School, in Brazil. He has served in the energy area in Petrobras Industrial Department since 1984. He currently serves as International Director of Petrobras, and Vice Chairman of Petrobras Energía and Chairman of Petrolera Entre Lomas S.A. He has worked at Petrobras since 1975, where he held several positions, including: Energy Manager, Programa de Termelétricas (Thermoelectrical Plants Program); Thermoelectrical Plants Manager of the Participations Superintendency; assistant to the CEO for the development of new ventures and partnerships; and Head of the Energy Sector of the industrial area. He has also represented Petrobras at the Boards of Directors of several thermoelectrical energy companies and acted as assistant to the Presidência da Comercializadora Brasileira de Energia Emergencial (Presidency of the Brazilian Supplier of Emergencial Energy—CBEE) of the Ministry of Mines and Energy.

Ildo Luis Sauer (50) graduated in Civil Engineering from Universidade Federal do Rio Grande do Sul, Brazil. He holds a Master’s degree in Nuclear Sciences and Engineering and Energy Planning from Universidade Federal do Rio de Janeiro and a Ph.D. in Nuclear Engineering from the Massachusetts Institute of Technology in the United States. He also holds a MSc degree from COPPE—Federal University of Rio de Janeiro in Energy Planning/Nuclear Power. He is Professor at the Instituto de Eletrotécnica e Energia da Universidade de São Paulo (Electrotechnical and Energy Institute of the University of São Paulo), on leave, where he has published more than 100 technical papers and supervised more than 40 doctoral and master theses in the field. Previously, he worked as a consultant at TecSauer Consultoria Ltda. and as manager of the nuclear reactor project for the Brazilian Navy. He currently serves as a Director of Petrobras, Petrobras Energia and Petrobras Gas.

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José Sérgio Gabrielli de Azevedo (55) graduated in Economics from Universidade Federal da Bahía, Brazil, where he also received a Masters Degree in Fiscal Incentives and Regional Development. He holds a PhD in Economics from Boston University. As a full-time Professor of Macroeconomics at the Universidade Federal da Bahia, he taught both graduate and undergraduate levels, and also served in administrative posts such as Vice-Chancellor for Research, Dean of the School of Economics, and Superintendent of the Fundação de Apoio a Pesquisa e Extensão (Foundation for Support of Research and Extension – Fapex). Dr. Gabrielli spent the 2000-2001 academic year as a Visiting Researcher at the London School of Economics and Political Science, devoted to studies on income distribution. He currently serves as Chief Financial Officer at Petrobras, and as a member of the board of directors of Petrobras Energía.

Guilherme de Oliveira Estrella (63) graduated in Geology from Universidade Federal do Rio de Janeiro, Brazil. He served as an Advisory Director and Vice President of the Brazilian Geology Society. He was a member of the Brazilian Paleontology Society and the American Association of Petroleum Geologists. Since January 31, 2003, Mr. Estrella has been Managing Director of Exploration and Production of Petrobras. Currently, Mr. Estrella is also a member of the boards of directors and executive boards of Petrobras Energia. He worked at Petrobras from 1965 until 1994, when he retired as a geologist of our Exploration Department. Before his retirement, he held several other positions of Petrobras, including: General Superintendent (1989-1993); Superintendent of Research and Development for exploration, drilling and production (1985-1989); Head of the Exploration Division (1981-1985); Head of the Organic Geochemistry Sector (1981); Head of the Brazilian East Coast Basin Interpretation Sector of the Petrobras Exploration Department—DEPEX/RJ (1978-1981); and Exploration Manager of Petrobras Internacional S.A.—BRASPETRO in its Iraqi branch (1976-1978). Mr. Estrella has also served as Director of the Instituto Brasileiro de Petróleo e Gás (Brazilian Oil and Gas Institute) for which he is now Chairman of the Board, and is a member of the board of directors of Petrobras Gas S.A. GASPETRO.

Renato de Souza Duque (49) graduated in Electrical Engineering by Universidade Federal Fluminense, Rio de Janeiro, Brazil, and received an MBA Executive by Universidade Federal do Rio de Janeiro. He joined PETROBRAS in 1978, where he specialized as an Oil Engineer. In his career he has been heavily involved in our Exploration and Production business segment, as the Manager of Offshore Drilling Units, Drilling Operations at Campos Basin, Oilwell Engineering and Technology, Contracts and Human Resources. In January 2003, he was elected Services Director responding for Research and Development, Engineering, Procurement, Health Safety & Environment, Information Technology and Shared Services Areas. He currently serves as Vice President of Corporate Services at Petrobras and as Director of Petrobras Energía and Petrobras Gas.

Luis Augusto M. da Fonseca (52) graduated in Electronic Engineering from Escola de Ingeniería Mauá, São Paulo, with a specialization degree in Oil Engineering, and obtained a degree in Economics from Universidad do Estado de Rio de Janeiro. At Petrobras he worked as the company representative to the Latin American Energy Organization, chief assistant to Petrobras International Executive Vice President, Manager of Operations in Houston, Officer Director & Engineering Services Manager at BRASOIL, coordinator of International Relations with international agencies, OLADE Executive Secretary and Business Development Manager. He participated in official missions together with government agencies and energy sector entities of Latin American and Caribbean countries, multilateral and international cooperation agencies. He currently is Vice President of Communications of Petrobras Energía.

Alberto da Fonseca Guimarães (55) graduated in Mechanical Engineering from UNESP, Guaratingueta, São Paulo State. He holds a MBA degree in Administration from Coppead, Rio de Janeiro. He has served for three years as Executive Manager of Commercialization and Marketing at Petrobras. He served as Executive Manager of Refining at Petrobras, and for a seven-year term, he served as Commercial Manager of Petrobras in New York and London. He was Executive Director of Business Development at Petrobras. Currently, he is a Director and Chief Executive Officer of Petrobras Energía. He is also a Director of Petrolera Entre Lomas S.A.

Oscar Anibal Vicente (66) graduated in Engineering from Universidad Nacional de La Plata and in Oil Production Engineering from Universidad de Buenos Aires. He joined Petrobras Energía in 1970 and has since held several positions, including General Manager (1978-1982) and Chief Executive Officer (1997-2001). He is the President of the Argentine Hydrocarbon Producing Companies Chamber. In addition, he is a Director of Petrobras Energía and Petrolera Entre Lomas S.A.

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Cedric Bridger (69) graduated in Public Accounting in London, where he initiated his professional activities. In Buenos Aires (1964) he was Financial Manager of FADIP S.A. (later Hughes Tool Co. S.A.). He then held the position of General Manager of the company in Brazil and was finally appointed Vice President of Operations of the company for Latin America. From 1992 until 1998, he was Vice President of Finance at YPF S.A. In April 1998, he retired from YPF S.A. and took a position as a Director of Banco Hipotecario. He is currently attorney-in-fact of the Argentine subsidiary of Técnicas Reunidas S.A. (Spain) and a Director of Petrobras Energía and IRSA and President of Patagonia Natural Products S.A.

Héctor Daniel Casal (49) graduated in Law. He serves as Vice President of Legal Affairs of Petrobras Energía. He has worked at Petrobras Energía since 1991. He also serves as Vice Chairman of Petrobras Energía Internacional S.A. He is a Director of Petrobras Energía, Citelec, Distrilec, Innova, Transener, Transba, Petrobras Financial Services Austria Gmbh and as an alternate Director of Corod Produccion S.A., Petrolera Entre Lomas S.A., Edesur, Petrobras Energía Venezuela S.A. and Petrobras Finance Bermuda Ltd. He is a Statutory Syndic of Refinor, TGS, CIESA and Telcosur S.A.

Daniel Maggi (52) graduated in Law. He attended post-graduate studies in Business Management at the Universidad del Salvador. He has worked at Petrobras Energía since 1997 and currently serves as Vice President of Human Resources. In the past, he has acted as Director of Human Resources of Edesur, and Manager of Human Resources at Sade Ingeniería y Construcciones S.A. and as Manager of Legal Affairs and Human Resources at La Plata Cereal S.A. He is also a Director of Petrobras Energía, and Edesur and alternate Director of Distrilec.

Alberto Javier Saggese (49) graduated in Law at the Buenos Aires University. He obtained a Post-Graduated degree in the Université de Paris I – Sorbonne in Energy Law (1985). He has worked at Petrobras Energía since 2003 and currently serves as Legal Manager in Up Stream and Down Stream activities. In the past, he has acted as Manager of Legal Affairs Petrobras Argentina S.A. (2001-2003), Manager Legal Affairs of Sociedad Comercial del Plata S.A. (1992-2001), Manager of the Legal Department of Total Austral S.A. (1985-1992) and Chief of the Contracts Department of YPF S.E. (1980-1983). He is also a Statutory Syndic of Petroquímica Cuyo and an alternate Statutory Syndic of Refinor.

Nicolas Perkins (32) graduated in Law from Universidad Católica Argentina in 1995. He obtained a Master of Law degree from New York University in 1998. From 1996 to 1998, he worked as an associate at the law firm Cárdenas, Cassagne & Associales, and from 1998 to 1999, he worked as a foreign associate with Linklaters & Alliance in New York. From 1999 to 2000 he worked as General Counsel and Human Resources Manager for LatinStocks.com coordinating work with local counsel in Argentina, Brazil, Mexico and the United States in commercial and intellectual property law related matters. In 2001 he worked as General Counsel for Latin America for Schlumberger-Schlumbergersema. He currently works as an associate with the law firm of Fortunati & Lucero.

Roberto Alejandro Fortunati (49) graduated in law from the Universidad de Buenos Aires in 1979. He is currently a professor in the post-graduate program of Petroleum and Gas Law and adjunct professor in Public International Law at the University of Buenos Aires, and a member of the Consulting Board of the Universidad Torcuato Di Tella Law School. In 1985 he participated in the Seminar on U.S. and International Law in the International and Comparative Law Center at the Southwestern Legal Foundation in Dallas, Texas. From 1996 to 2001, he was partner and member of the Executive Committee of the law firm Estudio Beccar Varela. From 2001 to 2002, he was Vice President and Director of legal affairs at Citibank, Argentina Branch. Since 2003, he has been a member of the law firm Estudio Fortunati & Lucero where he is a founding partner.

Carlos Alberto Pereira de Oliveira (47) graduated in Mechanical and Automotive Engineering from Instituto Militar de Ingenieria, in the city of Rio de Janeiro, with a specialization in petroleum engineering. He specialized in Financial Administration in the areas of petroleum and gas at the University of Texas, U.S.A. In Petrobras, he was Integral Manager of Production and Development, Production and Development Manager and Reserves and Reservoirs General Manager. He currently is Vice President of the Oil and Gas Exploration and Production and Hydrocarbon Transportation Business Units. He is President of Petrobras Energía Perú S.A. and a Director of Petrolera Entre Lomas S.A. and Petrobras Energía.

Luis Miguel Sas (42) has a degree in economics, is a Certified Public Accountant, a graduate of Universidad de Buenos Aires and holds an MBA from the Instituto de Altos Estudios Empresariales – Universidad

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Austral. He joined Petrobras Energía in 1984 and has since served in the area of finance. In 1990 he was appointed head of the Financial Operations Division when Petrobras Energía took over Telecom Argentina S.A., one of the first privatized companies in Argentina. He worked as head of the Petrobras Energía money desk during the 1992-1997 period. In 1997 he was appointed Corporate Finance Manager, in charge of capital market financing and project financing. In January 2000, he was appointed Chief Financial Officer of Edesur. He served as Finance Manager at Petrobras Energía between May 2001 and May 2004. On May 7, 2004 he was appointed Chief Financial Officer of Petrobras Energía. In addition, he currently serves as Chairman of Petrobras Energía Internacional S.A., and as Director of Petrobras Energía, World Energy Business, Petrobras Holdings Austria AG and Distrilec. He is also an alternate Director of TGS, and a member of Counsel of Petrobras Hispano Argentina S.A.

Pablo Cavallaro (39) graduated in Law from the Universidad de Córdoba in 1988. In 1993 he finished a course specializing in International Economics and Development from the University of Denver, in which he received the highest average. Between 1993 and 1994, he was a consultant with the World Bank. Between 1994 and 1997 he was employed as an associate with the law firm Clifford Chance in London. Afterwards, he was an associate at the law firm Bruchou, Fernandez, Madero and Lombardi. Between 1999 and 2003, he advised important business organizations while working at the law firm of O’Farrel. Currently, he is a post-graduate Professor of Capital Markets in the School of Law at the Universidad de Buenos Aires, and since May 2003, a senior lawyer at the firm Fortunati & Lucero. He is currently a member of the Statutory Auditing Committee of RJ Delta Asset Management and an alternate Statutory Auditor of RJ Delta Capital.

Decio Fabricio, Oddone Da Costa (44) graduated in Mechanical Engineering from Universidad Federal de Río Grande do Sul., Brasil. He completed post-graduated courses in oil engineering promoted by Petrobras and in “Advanced Management” at Business School of Harvard University. He is doctor Honoris Causa from Aquino’s University, Bolivia. He has occupied managerial positions at Petrobras in Brazil, Argentina, Angola, Lybia and Bolivia’s units. Currently he serves as Chairman of Petrobras Bolivia and is responsible for Petrobras’s Activities in Cono Sur, as Executive Manager for the region. He is also member of the boards of directors of Petrolera entre Lomas S.A., Petrobras Energía and Petrobras Participaciones SLU. He has been decorated with several presitigous honors awared by the Brazilian government, the Soberana Orden de Malta and other institutions.

Paulo Roberto Costa (51) graduated in Mechanical Engineering from the Federal University of Paraná in 1976 and specialized in off-shore engineering at Petrobras. From 1979 to 1994 he worked on platform installation and production development at the Campos basin in the areas of Engineering, Support Management and as Superintendent of the Southeastern Production Region. In 1995, he was promoted to General Manager of E&P Sul (Southern Brazil Exploration and Production), with responsibility for the Santos and Pelotas basins. In 1996, he became general manager for Logistics in the Exploration and Production business segment. From May 1997 to 1999 he headed up the Gas Segment, responsible for commercialization of natural gas. He was Director of Petrobras Gas S.A.-GASPETRO from May 1999 to December 2000. From January 2001 to April 2003, he was General Manager for Logistics at Petrobras of Natural Gas Segment. He has been Managing Director of TBG-Transportadora Brasileira Gasoduto Bolivia Brasil since April 2003. Currently he is Director of Petrobras, Petrobras Energía and Petrobras Química S.A.

Vilson Reichemback Da Silva (54) graduated in Law from the Universidade Federal do Ceará in 1995. He currently serves as Vice Chairman of EG3 RED S.A., EG3 Asfaltos S.A. and Petrobras Energía. He is also Alternate Director and Vice President of Downstream Operations of Petrobras Energía.

Administration and Organization

Our operations are conducted through Petrobras Energía. Petrobras Energía’s operations are divided into five business segments that are in turn supported by a corporate center. The five business segments are: Oil and Gas Exploration and Production, Hydrocarbon Marketing and Transportation, Refining, Petrochemicals and Electricity.

Petrobras Energía is managed by an executive committee made up of 11 members: the Chief Executive Officer, the Chief Financial Officer, the Vice President of each business unit and the Vice President of Legal Affairs, Human Resources, Corporate Services, Communications, Quality, Environmental, Safety and Occupational Health and the Executive Manager of Planning and Management Control.

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Operations are managed through standardized processes that facilitate and secure coordination between the different units and groups. Delegation of authority is encouraged for the purpose of promoting efficiency. In addition, the scope of the delegation of authority is clearly and expressly determined through systemized approval limits for risk minimization purposes. Our internal control system is supported by coordination among the areas responsible for managing businesses and administering them on a centralized basis, always within the framework of the policies established by the executive committee. Operating and administrative processes are jointly supported by administrative procedures, highly reliable information systems, production of periodical management control reports, performance appraisals and fluid communications.

Our Executive Officers

Because we are a holding company, we do not have any executive officers. Our operations are conducted by Petrobras Energía’s team of highly qualified executive officers. The following table sets forth the names and positions of Petrobras Energía’s executive officers.


Name		Position
Alberto Guimarães		Chief Executive Officer
Luis Miguel Sas		Chief Financial Officer
Carlos Alberto P. de Oliveira		Vice President of Oil and Gas Exploration and Production and Hydrocarbon Transportation Business Units
Carlos Alberto Fontes		Vice President of Refining and Petrochemicals Business Units
Rafael Fernández Morandé		Vice President of Electricity and Hydrocarbon Marketing Business Units
Daniel Maggi		Vice President of Human Resources
Héctor Daniel Casal		Vice President of Legal Affairs
Alberto Bethke		Vice President of Corporate Services
Luiz Augusto M. da Fonseca		Vice President of External Communications
Rui Antonio Alves da Fonseca		Vice President of Quality, Environmental and Safety and Occupational Health
Adelson da Silva		Executive Manager of Planning and Management Control

The following is a brief summary of the principal business and academic experience of Petrobras Energía’s executive officers who are not also directors of ours (for the summary regarding executive officers who are directors, see above).

Carlos Alberto Fontes (55) graduated in Chemical Engineering with executive education (MBA at the Rio de Janeiro Federal University). He joined Petrobras 30 years ago and has since served in different positions, including Assistant Director of Refining, Manager of the Technological Processes and Products of Refining, Manager of Petrochemical Projects, Chief Executive of Petrochemical Supply and President of PETROQUISA. In addition, he has been on the board of directors for companies such as Rio Polímeros S.A., Petroquímica Triumfo, among others.

Rafael Fernández Morandé (50) graduated in Civil Engineering. He has a post-graduate degree in Business Administration. He served as Director of the Electricity business segment since 1997, and additionally, since April 2001, as Vice President of the Energy and Gas Business Units. He was previously President of the Association of Electric Energy Generators in Argentina, a Director of the executive committee of CAMMESA and General Manager of Central Puerto S.A. He is President of World Energy Business S.A., Petrobras Finance Bermuda, TGS and CIESA, Edesur and Transener and a Director of Petrobras Energía. He is also Vice President of Citelec and Transba.

Alberto Bethke (39) graduated in Public Accounting. He completed a post-graduate degree in Business Administration at the Instituto de Altos Estudios Empresariales – Universidad Austral. He currently serves as Director and Vice President of Corporate Services of Petrobras Energía. He has been with Petrobras Energía since 1994, first as Corporate Information Manager and then from 2000-2001 as E-Commerce Manager. He previously served as Administrative Manager in TGS and prior to that in the audit and consulting division of Pistrelli, Díaz y Asociados.

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Rui Antonia Alves da Fonseca (48) majored in Mechanical Engineering at Universidade Federa do Rio de Janeiro and completed MBA courses for managers and executives and Fundación Getúlio Vargas, Brazil. At Petrobras he worked as head of the CENPES Industrial Project Division and as Environment, Safety and Health General Manager. He currently is Vice President of Quality, Environment, Safety and Occupational Health of Petrobras Energía.

Adelson Antonio da Silva (48) graduated as an Accountant from the University Nilton Paiva Ferreira, in the city of Belo Horizonte and as a Lawyer from University Candido Mendes in Rio de Janeiro. He specialized in Tax Law at University Estácio de Sá and MBA Executive/Marketing at COPPEAD-UFRJ in Rio de Janeiro. He worked for 25 years in Petrobras, predominately at the Accounting, Finance, Commercial, and Development of New Business areas. He participated in the biggest international acquisitions of Petrobras. He is currently Executive Manager of Planning at Petrobras Energía, and a Director of TGS, CIESA, World Energy Business S.A., Distrilec and also of Citelec, Transener, Transba and Petrolera entre Lomas.

COMPENSATION

Compensation of the members of the Board of Directors is determined at the Regular Shareholders’ Meeting in compliance with the Business Companies Law, No. 19,550. The maximum amount of compensation that the members of the Board of Directors may receive, including salaries and any other form of compensation for the performance of technical, administrative, or permanent functions, may not exceed 25% of our profits. Such amount will be 5% in the event that no dividends are distributed to the shareholders and will be increased pro rata on the basis of the dividend distribution, up to the 25% cap. In the event that one or more directors serve as members of a special committee or perform technical or administrative functions, and profits are reduced or non-existent, and, consequently, the preset limits are exceeded, compensation in excess of the limit may only be paid with the prior express approval by shareholders at the Regular Shareholders’ meeting.

In Petrobras Energía, the compensation policy for executive officers includes an annual cash compensation and a benefit program. The annual cash compensation is determined based on the characteristics and responsibilities of the relevant position and the executive officer’s qualifications and experience and benchmark information. Such compensation consists of a monthly fixed compensation and an annual variable compensation dependent upon Petrobras Energía’s results of operations and the achievement of individual goals and objectives. Benefits granted to executive officers are similar to those granted to our staff, such as life insurance, health care plan, meal allowance, and supplementary pension plan.

In addition to cash compensation, we sponsor a long term incentive plan for Petrobras Energía’s executive officers and senior managers. The plan consists of two stock option programs. The Appreciation Rights Program grants executive officers and senior managers options to purchase shares of Petrobras Energía Participaciones at a set exercise price or to receive cash equal to the difference between the average market price of Petrobras Energía Participaciones shares during the 20 days prior to exercise date and the exercise price. The Full Value Program grants executive officers and senior managers options to receive shares of Petrobras Energía Participaciones at no cost or receive cash equal to the market value of such shares. Each option grants the holder the right to purchase one share of Petrobras Energía Participaciones.

As part of this program, the Board of Directors of Petrobras Energía approved the incentive plans for 2001 and 2000. For further information see our financial statements as of December 31, 2003. In 2002, 2003 and 2004, no grants were made under these plans.

No contracts for services were entered into between the directors and our company or any of our subsidiaries that provide for benefits after termination of their office, other than as provided by law.

In 2004, we paid an aggregate of approximately P$14 million to our directors and to the executive officers of Petrobras Energía.

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BOARD PRACTICES

Audit Committee

Pursuant to the Regime concerning Transparency in Public Offerings approved by Decree No. 677/01, Argentine public companies must have an Audit Committee composed of three or more members of the Board of Directors. On May 21, 2003, our Board approved the implementation process required under General Resolution No. 400/02 of the CNV, which sets forth the rules concerning the implementation and operation of the Audit Committee that must be provided for either in our internal regulations or in our by-laws.

In compliance with the above resolutions, at the shareholders’ ordinary meeting held on March 19, 2004, we approved an amendment to our by-laws adding a provision related to the structure and operation of the Audit Committee.

Pursuant to the foregoing regime and the requirements imposed by the U.S. Securities and Exchange Commission, or SEC, and the New York Stock Exchange, or NYSE, we have created an Audit Committee.

The Audit Committee’s purpose is to assist the Board of Directors in fulfilling its responsibilities to investors, the market and others in matters relating to (1) the integrity of our financial statements, (2) compliance with applicable legal, regulatory and behavioral requirements, (3) qualification and independence of the independent external auditor that delivers an audit report on our financial statements (the “Independent Auditor”), and (4) the conduct of the internal audit and the Independent Auditor’s performance.

The Audit Committee is composed of three regular directors and an equal or lower number of alternate members that will be appointed by the Board of Directors from among its members. Directors having sufficient experience and ability in financial, accounting or business matters are eligible to become members of the Audit Committee. All members of the Audit Committee must be independent in accordance with applicable SEC standards and only a majority must be independent in accordance with the standards of the CNV. See “—Directors and Senior Management—Board of Directors.” The Audit Committee may adopt its own internal regulations. At the Board of Directors meeting held on May 7, 2004, Roberto Fortunati, Nicolás Perkins and Cedric Bridger were appointed as regular members of the Audit Committee and Pablo Cavallaro was appointed as an alternate member. At the Board of Directors meeting, which was held on April 1, 2005, our Directors reappointed the above-mentioned members of the Audit Committee for another one-year term.

Once a year, the Audit Committee prepares a working plan with respect to the Audit Committee’s goals and work schedule for the fiscal year to be submitted to the Board of Directors. The remaining directors, statutory syndics, managers and external auditors are required, at the Audit Committee’s request, to attend the Committee’s meetings, assist the Committee and provide it with any information available to them.

The Audit Committee has the following principal powers and responsibilities:

•

To supervise the performance of the internal control systems, the performance and trustworthiness of the administrative and accounting system, the trustworthiness of the financial statements and all the financial information and the disclosure of relevant events.

•

To establish and supervise the implementation of procedures for the reception, documentation and treatment of claims or reports on irregularities in connection with accounting, internal control or auditing matters, on a confidential and anonymous basis.

•

To issue founded opinions with respect to transactions with related parties as required by applicable law. To issue founded opinions whenever a conflict of interest exists or may arise for us and to communicate this opinion to self-regulated entities as required by the CNV.

•

To provide the market with complete information with respect to transactions where members of the corporate bodies and / or controlling shareholders of ours have conflicts of interests.

157

•

To opine with respect to the reasonableness of the compensation and option plans proposed by management for directors or managers.

•

To opine with respect to the compliance of legal requirements and on the reasonableness of proposals to issue shares or securities convertible into shares, in the case of capital increases that exclude or limit preemptive rights.

•

To issue at least once, at the time of submittal of the annual financial statements, a report on the treatment given during the year to the matters under its responsibility.

•

To issue an opinion to the shareholders on any proposal submitted by the Board for the appointment (or revocation) of the independent auditor to the shareholders.

•

To evaluate the qualifications and independence of the independent auditors.

•

To issue and maintain pre-approval procedures in connection with any service (whether audit-related or not) to be provided by the independent auditor. The Committee has the exclusive authority to approve any service provided by the said Auditor.

•

To evaluate the quality of our accounting standards and the main changes to such accounting standards.

These same policies were implemented by Petrobras Energía for its Audit Committee.

Statutory Syndic Committee

We have a Statutory Syndic Committee that is comprised of three members and three alternate members. The members of Petrobras Energía’s Statutory Syndic Committee are the same as those that serve on our Statutory Syndic Committee.

The table below sets out the name, year of appointment and position of each person on the Statutory Syndic Committee, approved by Petrobras Energía’s Ordinary Shareholders’ Meeting held on March 31, 2005:


Name	Year of Appointment	Position
Juan Carlos Cincotta	2004	Member
Justo Federico Norman	2003	Member
Rogelio Norberto Maciel	2003	Member
Olga M. Morrone de Quintana	2004	Alternate
Mariana P. Ardizzone	2004	Alternate
María Laura Maciel	2004	Alternate

The members and alternate members of the Statutory Syndic Committee are elected by the shareholders at the annual shareholders’ meeting to serve for a renewable term of one year. The primary responsibilities of the Statutory Syndic Committee are to monitor management’s compliance with the Business Companies Law, our by-laws and the shareholders’ resolutions. The Statutory Syndic Committee also performs other functions, including: (1) attending meetings of the Board of Directors and shareholders, (2) calling special shareholders’ meetings when deemed necessary or when required by shareholders, in accordance with the Business Companies Law, No. 19550, (3) presenting a report on the reports of the Board of Directors and the annual financial statements at regular shareholders’ meetings, and (4) investigating written complaints of shareholders representing not less than 2% of the capital stock. The Statutory Syndic Committee may not engage in any management control and, accordingly, may not evaluate business judgment and decisions on issues of administration, financing, selling and production, as these issues fall within the exclusive responsibility of the Board of Directors.

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Justo Federico Norman, Rogelio Norberto Maciel, Mariana P. Ardizzone and Maria Laura Maciel are lawyers and work at Maciel, Norman & Asociados Law Office, which has professional relations with and charges fees to us, our controlling companies and other Petrobras Energía companies.

Olga Margarita Morrone de Quintana is a public accountant and works at Estudio Morrone de Quintana, Seoane & Quintana, which has professional relations with and charges fees to us and other Petrobras Energía companies.

In compliance with Technical Resolution No. 15 of the Federación Argentina de Consejos Profesionales de Ciencias Económicas, Juan Carlos Cincotta and Olga Margarita Morrone de Quintana are independent.

The following is a brief summary of the principal business and academic experience of the members of the Statutory Syndic Committee listed in the table above:

Juan Carlos Cincotta (60) graduated in Public Accounting from Universidad de Buenos Aires. He is currently a member of Cincotta Asesores, formerly a partner at Ernst & Young, Grant Thornton & Bertora Asociados. He specializes in external audits of major public and private entities, consulting in accounting issues and auditing of companies. He is a member of the Special Commission on Accounting and Auditing Regulations (CENCyA) of the Federación Argentina de Consejos Profesionales de Ciencias Económicas. He is also a representative at the Instituto Argentino de Ejecutivos de Finanzas in the Committee on International Accounting Standards of IAFEI and Director of the Subcommittee of National and International Technical Rules. He is currently a member of the Statutory Syndic Committee of Petrobras Energía.

Justo F. Norman (60) graduated in Law. He is a partner of Maciel, Norman & Asociados Law Office in Buenos Aires (1991) with extensive experience in the general practice of law and in the fields of energy, natural resources, taxes and environmental issues. He is also renowned in the litigation and international arbitration fields. He is a member of the Association of International Petroleum Negotiators (AIPN) where he currently serves as Regional Secretary (2001-2004); the International Bar Association (IBA); and Rocky Mountain Mineral Law Foundation. He has represented and currently represents companies such as Anadarko Petroleum Corporation, ANR Pipeline Company (Coastal), Apache Corporation, BHP Petroleum (Americas) Inc., British Gas, Devon Energy Corporation, Parker Drilling, and Petroliam Nasional Berhad (Petronas). He is Vice President of BHP Petroleum (Argentina) S.A. and Computalog S.A. and a Regular Director of Noranda Exploración Argentina S.A., Petronas Argentina S.A. and Petrolera Rio Alto S.A., among others. He is also a member of the Statutory Syndic Committee of Petrobras Energía and an alternate member of the Statutory Syndic Committee of Petrolera Entre Lomas S.A.

Rogelio N. Maciel (69) is a founding partner of Maciel, Norman & Asociados Law Office. He is a renowned lawyer in the litigation and international arbitration fields. He was one of the members of the Argentine Aeronautical Code Drafting Committee and was a member of the Argentine delegation to the OACI. He is a member of the Buenos Aires Oil Club, the Association of International Petroleum Negotiators (AIPN) and the Rocky Mountain Mineral Law Foundation. He is Vice President of Noranda Exploración Argentina S.A. and Petronas Argentina S.A., a Regular Director of BHP Petroleum (Argentina) S.A. and an Alternate Director of Petrolera Rio Alto S.A., among others. He is also a member of the Statutory Syndic Committee of Petrobras Energía.

Olga M. Morrone de Quintana (69) is a partner of Morrone de Quintana, Seoane & Quintana. She is currently a member of the Statutory Syndic Committee of Petrolera Entre Lomas S.A., Petrobras Energía Internacional S.A., World Energy Business S.A., Propyme SGR, and an alternate member of the Statutory Syndic Committee of Petrobras Energía.

Mariana P. Ardizzone (32) graduated in Law from Universidad de Buenos Aires. She holds a Master of Laws from the University of Michigan and is currently enrolled in a post-graduate degree course in Business Administration and Electric Energy and Natural Gas Markets at the Instituto Tecnológico de Buenos Aires (ITBA). Since July 2001, she has been working as a lawyer at Maciel, Norman & Asociados law office. She is currently an alternate member of the Statutory Syndic Committee of Petrobras Energía.

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Maria Laura Maciel (42) graduated in Law from Universidad Catolica Argentina. She holds a post-graduate degree in Private International Law and in Aviation Law from American University in Washington D.C. (1986), and a post-graduate degree in IATA/FIATA in the International Association of Air Transportation, Montreal, Canada (2004). She is currently working as an associate at Maciel, Norman & Asociados law office, and is currently an alternate member of the Statutory Syndic Committee of Petrobras Energía.

Total compensation for the members of the Statutory Syndic Committee was P$0.054 million in 2004.

EMPLOYEES

The following table sets out the number of our employees by business segment for the fiscal years ended December 31, 2004, 2003 and 2002.


	As of December 31,
	2004		2003		2002
Oil and Gas Exploration and Production	945		900		884
Refining and Petrochemical	1,651	⁽¹⁾	1,551		1,505
Electricity	70		73		74
Farming and Forestry	—		209	⁽²⁾	212
Hydrocarbon Marketing and Transportation	27		25		22
Corporate	735		576		558

Total	3,428		3,334		3,255

(1)	As a consequence of the merger, which, upon registration with the Argentine Public Registry of Commerce, will have retroactive effect as from January 1, 2005, the number of employees will increase by 1,573 (1,508 from EG3 and 65 from Petrolera Santa Fe).

(2)	In January 2004, we completed the formalities necessary for execution of the transfer of our forestry industrial activities.

Currently, 28% of our workforce are members of labor unions and have entered into collective bargaining agreements with our company or our entities. We believe we generally have good relations with our employees and the unions, and expect to continue to enjoy good relations with our employees and the unions in the future. We can provide no assurance, however, that our employee compensation arrangements may not be subject to change or modification after the expiration of the contracts currently in effect.

SHARE OWNERSHIP

To our knowledge, none of our directors or members of our senior management owns more than 1% of our outstanding shares.

160

Item 7.

MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

MAJOR SHAREHOLDERS

Our share capital consists of 2,132,043,837 Class B shares. Our Class B shares have a par value of P$1.00. Our Class B shares are entitled to one vote per share.

On October 17, 2002, Petrobras Participaciones, S.L.U., a wholly owned subsidiary of Petrobras, acquired 58.6% of Petrobras Energía Participaciones’s capital stock from the Perez Companc Family and Fundación Perez Companc. Petrobras is a public Brazilian company, whose business is concentrated on exploration, production, refining, sale and transportation of oil and its by-products in Brazil and abroad. 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.

The table below sets forth certain information as of April 30, 2005 with respect to the ownership of our capital stock by each person who is known to us to be the owner of more than 5% of our shares.


	Class B Shares
Shareholder	Number of Shares	% of the Total Outstanding Shares

Petrobras Participaciones S.L.U.	1,249,716,746	58.6	%

RELATED PARTY TRANSACTIONS

Our strategy to grow as an integrated energy company led us to develop our business in various levels of the energy industry, and this in turn has led to an increase in transactions between our affiliates and subsidiaries, in particular between affiliates and subsidiaries in different business segments. These transactions are carried out in the ordinary course of our operations on an arm’s length basis. The terms of these transactions are comparable to those offered by or obtained from non-related third parties.

On January 21, 2005, the special shareholders’ meetings of Petrobras Energía, EG3, PAR, and PSF, approved the merger of EG3, PAR and PSF into Petrobras Energía. Prior to the merger, Petrobras, through its subsidiary PPSL, holds a 99.6% interest in EG3 and a 100% interest in each of PAR and PSF. Pursuant to the merger, PPSL is expected to receive 230,194,137 newly issued Class B shares of Petrobras Energía, representing 22.8% of Petrobras Energia’s capital stock. On March 3, 2005, the final merger agreement was signed providing that, once implemented, following receipt of necessary governmental approvals and registration with the public registry, the merger would be given retroactive effect to January 1, 2005. On June 28, 2005, the CNV approved the merger. The merger is in the process of being registered with the Argentine Public Registry of Commerce. After the merger, Petrobras Energía will be the surviving entity. See “Item 4. Information About the Company—Our History and Development—Petrobras Energía Merger.”

Even prior to this proposed merger, we have sought to capitalize on the synergies of our businesses with those of Petrobras, by exploiting a number of opportunities and initiatives that offer benefits to both companies.

The Refining segment has benefited most from the joint development of complementary businesses. In Argentina, we produce excess amounts of diesel oil at the San Lorenzo Refinery, which historically have been exported at lower prices to other countries in the region. EG3 does not have sufficient production capacity in its refinery in Bahía Blanca to supply its ample network of service stations. San Lorenzo Refinery can help fulfill EG3’s demand. During 2003 and 2004, we sold approximately 210,000 cubic meters and 382,000 cubic meters, respectively, of diesel oil to EG3. This has permitted us to profitably increase the volumes of crude oil processed in the San Lorenzo Refinery to levels greater than previous years. EG3, in turn, sold us its surplus of both component and finished gasolines.

161

Since 2003, we have been using the Petrobras flag in our service stations. Over the last few years, Petrobras has built an excellent image for its brands, products and services in Argentina, currently competing with the image of the leading competitors.

In mid 2004, we launched Podium, the gasoline with the highest octane rating in the Argentine market. Created jointly by our technicians and technicians from Petrobras, Podium is produced at the San Lorenzo Refinery and is distributed on an exclusive basis throughout the country, including through the EG3 network of gas stations.

In addition to the foregoing, we have entered into several financing arrangements with subsidiaries of Petrobras. In September 2004, Petrobras Internacional Braspetro BV, a subsidiary of Petrobras, granted a P$150 million loan (US$50 million), with an interest rate of 7.5% per annum. The loan is repayable semiannually in 42 months and may be prepaid without penalties. In 2005, we entered into a US$200 million loan facility with Petrobras Internacional Braspetro BV. This loan has a term of ten years and bears interest at an annual interest rate of 7,22%, net of taxes. The proceeds of this loan were used to prepay in part the Class K and M series notes. This loan can be prepaid at any time without a prepayment penalty. A significant portion of the repayments of debt that have been made during 2005 was financed with loans provided by Petrobras.

In addition, Petrobras Energía’s US$142 million contribution to the expansion of the San Martin Gas Pipeline (See “Item 4. Information About the Company—Hydrocarbon Marketing and Transportation—Regulated Energy Segment”) is being funded by a loan from Petrobras. The loan, which was approved by Petrobras Energía’s Board of Directors on February 25, 2005, was entered into with Petrobras Internacional Braspetro BV. The loan has a principal amount up to US$142 million and has a term of three years with an annual 5.35% interest rate, free of tax withholdings. This loan can be prepaid at any time without a prepayment penalty.

In January 2003, we closed transactions with a subsidiary of Petrobras to hedge oil price fluctuations during the second semester of 2003, covering a volume of 18,000 barrels per day. This agreement provides protection based on the actual WTI, setting a minimum price of US$22.87 per barrel. We paid a premium of P$12 million for this option.

In the first quarter of 2002, Petrobras Energía approved an asset swap transaction with IRHE (Argentine Branch) and Gentisur S.A., two companies related to our former controlling group. Pursuant to the terms of the asset swap, Petrobras Energía sold to IRHE and Gentisur its 50% interest in Pecom Agra S.A. for US$30 million, resulting in a P$81 million gain and, in turn, IRHE and Gentisur transferred to Petrobras Energía the following as consideration for the sale:

•

0.75% interest in the Puesto Hernández Hydrocarbon UTE for US$4.5 million;

•

7.5% equity interest in Citelec, the parent of Transener, for US$15 million; and

•

9.19% equity interest in Hidroneuquén S.A., a company holding a 59% interest in the capital stock of Hidroeléctrica Piedra del Aguila S.A., for US$5.5 million.

The remaining balance of US$5 million was settled through a document maturing in October 2002.

We have requested reports from consulting firms regarding our material related party transactions. These reports state that these transactions can be reasonably considered in conformity with ordinary market practices and conditions.

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Material transactions with our related entities (including companies under joint control) for the years ended December 31, 2004, 2003 and 2002, are as follows:


	2004		2003		2002
	Purchases	Sales	Purchases	Sales	Purchases	Sales
	(in millions of pesos)
Company:
Oleoductos del Valle S.A.	20	—	17	—	14	—
Transportadora de Gas del Sur S.A.	35	—	13	—	48	—
Refinería del Norte S.A.	106	—	55	1	60	—
Petrobras International Finance Co.	65	337	—	—	—	—
EG3 S.A.	105	514	26	196	—	1
Petroquímica Cuyo S.A.	—	—	—	—	—	5
Petrolera Entre Lomas S.A.	9	—	—	—	22	—
Petrobras Petroleo Brasileiro S.A.	—	35	—	149	—	79
Empresa Boliviana de Refinación S.A.	—	36	—	—	—	—
Petrolera Santa Fe S.R. L.	5	—	—	—	—	—

Total	345	922	111	346	144	85

The outstanding balances as of December 31, 2004, 2003 and 2002 from transactions with related companies (including companies under joint control) are as follows:


	2004
	Current					Long-term
	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Loans	Trade Receivables	Investments	Loans
	(in millions of pesos)
Company:
Oleoductos del Valle S.A.	—	—	2	—	—	—	—	—
Petroquímica Cuyo S.A.	—	1	—	—	6	—	—	—
Oleoductos de Crudos Pesados Ltd.	—	—	—	—	—	—	156	—
EG3 S.A.	247	8	18	9	—	—	—	—
Transportadora de Gas del Sur S.A.	1	—	3	1	—	—	—	—
Refinería del Norte S.A.	—	4	2	—	—	—	—	—
Petrobras International Finance Co.	11	—	—	—	—	—	—	—
Petrobras Bolivia Inversiones y Servicios	—	—	—	—	—	3	—	—
Braspetro	—	—	—	—	4	—	—	149
Other	4	3	5	2	—	—	—	—

Total	263	16	30	12	10	3	156	149

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	2003
	Current				Long-term
	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Investments
	(in millions of pesos)
Company:
Oleoductos del Valle S.A.	—	—	1	—	—
Petroquímica Cuyo S.A.	—	—	—	6	—
Oleoductos Crudos Pesados Ltd.	—	—	—	—	127
EG3 S.A.	55	—	2	—	—
Transportadora de Gas del Sur S.A.	9	—	4	—	—
Refinería del Norte S.A.	—	3	—	—	—
Petrobras Petroleo Brasileiro S.A.	10	—	—	—	—
Petrobras Energía Participaciones S.A.	—	—	—	—	—

Total	74	3	7	6	127


	2002
	Current
	Investments	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities
	(in millions of pesos)
Company:
Empresa Boliviana de Refinación S.A.	19	—	—	—	—
Oleoductos del Valle S.A.	—	—	—	3	—
Petroquímica Cuyo S.A.	—	1	2	—	—
Petrobras International Finance Company	—	17	—	—	—
Transportadora de Gas del Sur S.A.	—	—	—	3	—
Refinería del Norte S.A.	—	1	2	4	—
Coroil S.A.	—	—	—	—	48

Total	19	19	4	10	48

We do not have any other material related party transactions.

164

Item 8.

FINANCIAL INFORMATION

CONSOLIDATED FINANCIAL STATEMENTS

See “Item 18. Financial Statements.”

LEGAL PROCEEDINGS

We are involved in various litigation and regulatory proceedings arising in the ordinary course of our business. We do not believe that any of these proceedings is material to our operations or financial condition.

In addition, as a result of the Argentine crisis and the pesification of utility rates, some of our affiliates and companies under joint control have defaulted on their debt and are in discussions with creditors regarding possible restructurings. If the restructuring efforts are unsuccessful and creditors proceed against the assets of such affiliates and companies under joint control, we could lose some or all of our equity in these companies and our results would be affected accordingly. See “Item 3. Key Information—Risk Factors—Factors Relating to Argentina—The pesification of utility rates has affected and may continue to affect utility companies’ financial position, results of operations and their ability to generate cash.”

DIVIDENDS

We may only pay dividends from our retained earnings reflected in our annual audited financial statements as approved at our annual general regular shareholders’ meeting. While our Board of Directors may declare interim dividends, our Board of Directors and our statutory audit committee would be jointly and severally liable for any payments made in excess of retained earnings at fiscal year closing. The declaration, amount and payment of dividends to shareholders are subject to approval by the regular shareholders’ meeting. Under our by-laws, our net income is allocated as follows:

5% is allocated to a legal reserve until the legal reserve equals 20% of our outstanding capital,

to compensation of the members of the Board of Directors and statutory audit committee, and

to dividends on preferred stock, if any, and then to dividends on common stock or to a voluntary reserve or contingency reserve or to a new account, or as otherwise determined by the ordinary shareholders’ meeting.

Holders of our American Depositary Shares, or ADSs, will be entitled to receive any dividends payable in respect of our underlying Class B shares. We will pay cash dividends to the depositary in pesos, although we reserve the right to pay cash dividends in any other currency, including US dollars. The deposit agreement provides that the depositary will convert cash dividends received by the depositary in pesos to US dollars and, after a deduction or upon payment of fees and expenses of the depositary, will make payment to holders of our ADSs in US dollars.

The main source of funds for the payment of cash dividends will be the dividends received from our controlled company Petrobras Energía. We will distribute as cash dividends any cash dividends received from Petrobras Energía, net of taxes, if any, and minimum expenses.

Payment of cash dividends by Petrobras Energía depend upon its financial position, results of operations, cash requirements (including capital expenditures and payments of debt service), retained earnings minimum requirements and other requirements imposed by Argentine law and upon any other factors deemed relevant by Petrobras Energía’s Board of Directors for the purpose of resolving upon the declaration of dividends. If Petrobras Energía pays any dividend from corporate earnings that have not already been subject to Argentine corporate income tax determined in accordance with general income tax regulations, it will be required to deduct and withhold Argentine income tax from that amount at a rate of 35%.

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We did not pay dividends in 2004, 2003 or 2002.

Since the issuance of Class K and Class M series notes and other medium-term debt instruments, as from October 2002 and while any such debt remained outstanding, Petrobras Energía was subject to compliance with a series of restrictions and covenants including restrictions on the payment of dividends. As from April 2005, we have fully repaid these credit instruments and, as a result, Petrobras Energía is no longer subject to restrictions on the payment of dividends under its debt instruments. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Financing Activities—Payments, Prepayments and Refinancing.”

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Item 9.

OFFER AND LISTING

OFFER AND LISTING DETAILS

Our ADSs, each representing ten Class B shares, are listed on the New York Stock Exchange under the trading symbol “PZE.” The ADSs began trading on the New York Stock Exchange on January 26, 2000 and were issued by Citibank, N.A., as depositary. Our Class B shares are listed on the Buenos Aires Stock Market under the trading symbol “PBE.” The Class B shares began trading on the Buenos Aires Stock Market on January 26, 2000. The following table sets forth, for the periods indicated, the high and low closing sales price of the ADSs on the New York Stock Exchange and the Class B shares on the Buenos Aires Stock Market:


	ADS⁽¹⁾		Class B share⁽²⁾
	High	Low	High	Low
Full Year
2000	21.19	12.81	2.12	1.28
2001	18.75	9.18	1.98	0.92
2002	12.60	3.60	2.83	1.42
2003	11.25	6.52	3.34	1.99
2004	14.14	8.80	4.13	2.65
Quarterly
2002
First Quarter	12.60	7.04	2.83	1.88
Second Quarter	7.40	3.60	2.47	1.42
Third Quarter	7.10	4.40	2.50	1.65
Fourth Quarter	6.28	4.69	2.27	1.78
2003
First Quarter	7.56	6.52	2.46	2.07
Second Quarter	8.81	6.80	2.49	1.99
Third Quarter	8.88	7.50	2.64	2.18
Fourth Quarter	11.25	8.83	3.34	2.55
2004
First Quarter	14.14	11.31	4.13	3.20
Second Quarter	14.05	8.80	4.00	2.65
Third Quarter	11.13	9.20	3.35	2.77
Fourth Quarter	12.20	10.25	3.64	3.08
Monthly
December 2004	11.93	10.25	3.55	3.13
January 2005	11.80	10.98	3.47	3.25
February 2005	14.31	11.43	4.16	3.38
March 2005	14.47	11.54	4.14	3.44
April 2005	12.48	10.95	3.63	3.20
May 2005	12.20	11.60	3.57	3.39
June 2005⁽³⁾	12.59	11.70	3.63	3.36

⁽¹⁾	Amounts expressed in US dollars.

⁽²⁾	Amounts expressed in Argentine pesos.

⁽³⁾	Through June 21, 2005.

On May 31, 2005, there were approximately 24.3 million ADSs outstanding. Our ADSs represented approximately 11.3% of the total number of issued and outstanding Class B shares as of May 31, 2005.

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MARKETS

Buenos Aires Stock Market

The Buenos Aires Stock Market, which is affiliated with the Buenos Aires Stock Exchange, is the largest stock market in Argentina. The Buenos Aires Stock Market is a corporation whose shareholder members are the only individuals and entities authorized to trade in the securities listed on the Buenos Aires Stock Exchange. Trading on the Buenos Aires Stock Exchange is conducted by continuous open outcry and a computer-based negotiation system called SINAC from 10:00 a.m. to 6:00 p.m. each business day. The Buenos Aires Stock Exchange also operates an electronic trading market system from 11:00 a.m. to 5:00 p.m. each business day.

To control price volatility, the Buenos Aires Stock Market operates a system by which the trading of a security is suspended for 15 minutes whenever the price of such security changes 15% from its last closing price. Once the 15 minutes have elapsed, trading is resumed. From that point on, trading will be suspended for 10 minutes whenever the trading price changes 5% from the last suspended price.

Investors in the Argentine securities market are mostly individuals and companies. Institutional investors, which are responsible for a growing percentage of trading activity, consist mainly of institutional pension funds created under the amendments to the social security laws, enacted in late 1993.

Certain information regarding the Argentine equities market is set forth in the table below:


	2004		2003		2002		2001		2000
Market capitalization (billions of pesos)	690.0		543.3		348.1		192.5		165.8
As percent of GDP⁽¹⁾	205	%	205	%	111.2	%	70.9	%	58.1	%
Volume (in millions of pesos)	14,113		8,844		4,117		7,519		11,050
Average daily trading volume (in millions of pesos)	35.52		35.52		17.5		30.9		38.8
Number of listed companies⁽¹⁾	85		110		117		119		116

⁽¹⁾	End-of-period figures for trading on the Buenos Aires Stock Exchange.

Source: Bolsa de Comercio de Buenos Aires, CNV and Instituto Argentino de Mercado de Capitales.

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Item 10.

ADDITIONAL INFORMATION

MEMORANDUM AND ARTICLES OF ASSOCIATION

Register

Our by-laws were registered in the General Board of Corporations (Inspección General de Justicia) on January 6, 1999 under number 265, book 4 of Corporations, as amended on November 4, 1999 under number 16,283, book 7 of Corporations, on July 6, 2000 under number 9,534, book 11 of Corporations, on July 31, 2000 under number 11,102, book 12 of Corporations, on October 26, 2000 under number 16,086, book 13 of Corporations, on February 14, 2003 under number 2172, book 20 of Corporations, on 4 July, 2003 under number 9,190, book 22 of Corporations, on August 22, 2003 under number 11893, book 22 of Corporations and on June 23, 2004 under number 7632, book 25 of Corporations.

Objects and Purposes

The by-laws states that the purpose of our company is to do business as an investment company, either on our own account, or on account of or in association with third parties, investing money in its own securities transactions and/or making capital contributions to firms or business and industrial companies either existing at present or to be organized in the future, in order to agree on any present or future business, acquire and sell shares, bonds and debentures, act as guarantor, provide sureties, guarantees and bonds in favor of third parties, and make financial transactions granting loans and payment facilities whether or not secured by a real estate security interest, expressly excluding those activities prohibited under the Financial Entities Law. To such effect, the company has full legal capacity to acquire rights, incur obligations and perform any and all acts not prohibited by the law or these by-laws.

Provisions of the By-laws Relating to Directors

Article 9 of the by-laws states that the Board of Directors shall hold a meeting with the majority of its members present at the meeting, whether in person or remotely as long as they can each communicate among themselves through other means of simultaneous sound, image or word transmission, and shall adopt resolutions by the majority of the votes present thereat, including remote participants. In the event any members of the Board refrain from voting on account of having an interest contrary to our interest, the Board shall adopt resolutions by a majority of the members who did not refrain from voting for such reason. Participation and vote of remote participants as well as all transmission data shall be registered in the minutes of the meetings. Argentine corporate law requires that directors refrain from voting on matters in which such director may have a material interest. The by-laws establish that, should any members of the board refrain from voting in any matter on account of having an interest contrary to ours, the board shall adopt resolutions by a majority of the members who did not refrain from voting for such reason.

Capital Stock

Set forth below is a brief description of the material provisions of our by-laws and Argentine law and regulations relating to our capital stock. There are no longer Class A shares outstanding since they were converted, on October 17, 2002, into Class B shares as explained below.

Voting Rights

Each Class B share entitles the holder to one vote.

Transfers of Class A Shares

Class A shares were converted into Class B shares prior to the sale of Petrobras Energía Participaciones’s Class A shares from the Perez Companc Family to Petrobras. See “Item 7. Major Shareholders and Related Party Transactions—Major Shareholders.”

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Special Class Voting Rights

Under Argentine law, any action that would prejudice the rights of holders of a particular class of shares but not the rights of holders of other classes or affect the rights of holders of a particular class of shares in a manner different than holders of other classes of shares must be approved by the holders of the prejudiced class of shares at a special meeting. These special rights apply only to classes of shares as a whole and not to a minority of shares of one class against a majority of that same class. In addition, special shareholders’ meetings are governed by the same rules as ordinary shareholders’ meetings. In particular, a special meeting of Class A shareholders will be required in cases of (1) changing of our corporate legal status, (2) the anticipated dissolution of our company, (3) mergers, (4) spinoffs and (5) transfer of our domicile outside of Argentina. Amendments to the terms of issuance of employee profit-sharing certificates shall also require shareholder approval at a special meeting.

Cumulative Voting

Under Argentine law, a shareholder is entitled to cumulative voting procedures for the election of up to one-third of the directors being elected. If any shareholder notifies us of its decision to exercise its cumulative voting rights not later than three business days prior to the date of a meeting, all shareholders are entitled, but not required, to exercise their cumulative voting rights. Under cumulative voting, the aggregate number of votes that a shareholder may cast is multiplied by the number of vacancies to be filled in the election, and each shareholder may allocate the total number of its votes among a number of candidates not to exceed one-third of the number of vacancies to be filled. Shareholders not exercising cumulative voting rights are entitled to cast the number of votes corresponding to their shares for each candidate.

Preemptive Rights

In the event of a capital increase, a holder of existing common shares of a given class has a preemptive right to subscribe for a number of shares of the same class sufficient to maintain the holder’s existing proportionate holdings of shares of that class.

Preemptive rights also apply to the issuance of certain convertible securities (obligaciones negociables) but do not apply upon conversion of these securities. Holders of ADSs may be restricted in their ability to exercise preemptive rights if a prospectus under the Securities Act relating to those securities has not been filed or is not effective or an exemption from registration is not available. You should note that we are not obligated to file a registration statement with respect to the shares relating to preemptive or accretion rights. Preemptive rights are exercisable during the 30 days following the last publication of notice to the shareholders in the Official Gazette and an Argentine newspaper of wide circulation. Pursuant to Argentine corporate law, the 30-day period may be reduced to ten days by a decision of our shareholders adopted at an extraordinary shareholders’ meeting. Preemptive rights may be suspended or limited in extraordinary circumstances with the favorable vote of more than 50% of all outstanding voting shares at an extraordinary shareholders’ meeting at which all shares will be entitled to exercise one vote regardless of whether there are shares with multiple votes where the purpose of the capital increases is to issue shares as consideration for a contribution of assets to the company or to repay outstanding obligations.

Shareholders who have exercised their preemptive rights and indicated their intention to exercise additional preemptive rights are entitled to accretion rights, pro rata to their respective subscriptions, with respect to any unsubscribed shares by other shareholders during the preemptive rights period, in accordance with the terms of Article 194 et seq. of the Argentine Companies Law. Shares not subscribed by the shareholders by virtue of their exercise of preemptive rights or accretion rights may be offered to third parties.

Under Argentine law, we cannot issue any more shares with multiple votes, including more Class A shares.

Appraisal Rights

Whenever our shareholders approve (1) a spinoff or merger in which we are not the surviving corporation, (2) a change in our corporate legal status, (3) a fundamental change in our corporate purpose, (4) a change of our

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domicile to a location outside of Argentina, (5) a voluntary withdrawal from a public offering or delisting, (6) the continuation of our company in the case of a mandatory delisting or cancellation of the authorization for a public offering, (7) an increase of capital approved by an extraordinary shareholders’ meeting which would imply a disbursement by a shareholder or (8) a total or partial recapitalization following a mandatory reduction of capital or liquidation, any shareholder that voted against this action may withdraw from our company and receive the book value of his shares, determined on the basis of our latest balance sheet prepared or that should have been prepared in accordance with Argentine laws and regulations, provided that this shareholder exercises his appraisal rights within the period set forth below. However, because of the absence of legal precedent directly on point, there is doubt as to whether holders of our ADSs will be able to exercise appraisal rights either directly or through the depositary with respect to Class B shares represented by our ADSs. Appraisal rights must be exercised within the five days following the adjournment of the meeting at which the resolution was adopted, in the event that the dissenting shareholder voted against such resolution, or within 15 days following such adjournment if the dissenting shareholder did not attend such meeting and can prove that he was a shareholder on the date of such meeting. In the case of a merger or spinoff, appraisal rights may not be exercised if the shares to be received as a result of such transaction are authorized for public offering or listed. Appraisal rights are extinguished if the resolution giving rise to such rights is revoked at another shareholders’ meeting held within 60 days of the meeting at which the resolution was adopted.

Payment on the appraisal rights must be made within one year of the date of the shareholders’ meeting at which the resolution was adopted, except when the resolution was to delist our stock or to continue our company following our mandatory delisting, in which case the payment period is reduced to 60 days from the date of the related resolution.

Acquisition of Class B Shares by Class B Shareholders

Our by-laws also provide that if any person or group of persons acquires Class B shares or securities convertible into Class B shares representing at least three percent of our capital stock, then these persons must, within three days after the acquisition, give us notice of the acquisition, irrespective of any additional notice requirements under applicable rules of any stock exchange or regulatory agency. The notice must state the acquisition dates and prices, the voting power acquired, the purpose of the acquisition and the intention of the acquiror (including, without limitation, whether it intends to increase its holding or to obtain control). This provision also applies to subsequent acquisitions involving a number of Class B shares or securities convertible into Class B shares representing at least three percent of our capital stock.

Capital Increases and Reductions

Our capital stock may be increased by resolution of an ordinary shareholders’ meeting. Capital increases do not require an amendment of the by-laws, but must be approved by the CNV, published in the Official Gazette and registered with the Public Registry of Commerce. Capital reductions may be voluntary or mandatory. Voluntary reductions of capital must be approved by an extraordinary meeting of shareholders and may take place only after notice is published and creditors are given an opportunity to obtain payment or collateralization of their claims or attachment. Reductions of capital are mandatory when losses have exceeded reserves or more than 50% of our stated capital.

Shares issued in connection with any increase in capital must be divided among the various classes in proportion to the number of shares of each class outstanding at the date of the issuance, provided that the number of shares of each class actually issued may vary based on the exercise of preemptive rights and additional preemptive rights in accordance with the procedure described in the preceding section.

Redemption and Repurchase

Our shares are subject to redemption in connection with a reduction in capital by the vote of a majority of shareholders at an extraordinary shareholders’ meeting. Any shares so redeemed must be cancelled by us.

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We may repurchase fully paid shares of our capital stock with retained earnings or freely available reserves, upon a determination of the board that this repurchase is necessary in order to avoid a material adverse effect to us. The board’s determination must be explained to shareholders at the next annual shareholders’ meeting. We may also repurchase shares of our capital stock held by a company acquired by or merged with us. In either case, we are required to resell the shares purchased within one year and must give shareholders a preemptive right to purchase these shares. Any shares repurchased by us will not be considered in the determination of a quorum or a majority.

Preferred Shares

We may issue non-voting preferred shares or preferred shares with one vote per share. The economic preferences and rights of our preferred shares will be determined at the shareholders’ meeting authorizing the issue of the preferred shares. Non-voting preferred shares may vote one vote per share in the following circumstances: (1) if we are in default with respect to the payment of preferred share dividends, (2) if the events described under “—Meetings of Shareholders—Quorum and Voting Requirements” occur, and (3) if the preferred shares have been listed on a stock exchange and that listing is cancelled or suspended.

Liquidation

The liquidation of our company may be carried out by our Board of Directors or by one or more liquidators appointed by the shareholders to wind up its affairs. In the event of liquidation, our assets will be applied to satisfy our debts and liabilities including liquidation expenses. Any remaining amounts will be distributed as follows: (1) the amount of the preferred shares issued shall be reimbursed at its paid-in, nominal value; (2) the amount of common shares shall be reimbursed at their paid-in, nominal value; (3) cumulative dividends in arrears on preferred shares shall be paid; and (4) the remaining balance shall be distributed pro rata among all holders of common shares.

Changes in Shareholder Rights

See “—Capital Stock—Special Class Voting Rights” above and “—Meetings of Shareholders” below.

Audit Committee

The bylaws state that we shall have an Audit Committee composed of three regular directors and an equal or smaller number of alternate members. For more details on our Audit Committee refer to “Item 6. Directors, Senior Management and Employees—Board Practices—Audit Committee.”

Meetings of Shareholders

General

Shareholders’ meetings may be ordinary or extraordinary. We are required to hold an ordinary shareholders’ meeting within four months of the close of each fiscal year to consider the approval of our financial statements, the allocation of net income for the fiscal year, the approval of the reports of the Board of Directors and the statutory audit committee and the election and remuneration of directors and members of the statutory audit committee. Other matters which may be considered at an ordinary meeting include the responsibility of directors and members of the statutory audit committee, capital increases and the issuance of certain corporate bonds. Extraordinary shareholders’ meetings may be called at any time to consider matters beyond the authority of an ordinary meeting, including amendment of the by-laws, issuance of debentures, early dissolution, merger, spinoff, reduction of capital stock and redemption of shares, changing our company from one type of legal entity to another and limitation of shareholders’ preemptive rights.

Notices

Notice of shareholders’ meetings must be published for five days in the Official Gazette of the Republic of Argentina, in an Argentine newspaper of wide circulation and in the publications of Argentine exchanges or securities markets in which our shares are traded, at least ten days prior to the date on which the meeting is to be

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held as per Argentine Companies Law, and at least 20 days prior to the meeting as per Executive Order 677/01. The notice must include information regarding the type of meeting to be held, the date, time and place of the meeting and the agenda. If there is no quorum at the meeting, notice for a meeting on second call must be published for three days, at least eight days before the date of the second meeting, and must be held within 30 days of the date for which the first meeting was called. The first call and second call notices may be effected simultaneously in order for the meeting on second call to be held on the same day as the meeting on first call, but only in the case of ordinary shareholders’ meetings. Shareholders’ meetings may be validly held without notice if all shares of our outstanding capital stock are present and resolutions are adopted by unanimous vote.

The Board of Directors will determine appropriate publications for notice outside Argentina in accordance with requirements of jurisdictions and exchanges where our shares are traded.

Quorum and Voting Requirements

The quorum for ordinary meetings of shareholders on first call is a majority of the shares entitled to vote, and action may be taken by the affirmative vote of an absolute majority of the shares present that are entitled to vote on such action. If a quorum is not available, a second call meeting may be held at which action may be taken by the holders of an absolute majority of the shares present, regardless of the number of such shares. The quorum for extraordinary shareholders’ meeting on first call is sixty percent of the shares entitled to vote, and if such quorum is not available, a second call meeting may be held, for which there are no quorum requirement.

Action may be taken at extraordinary shareholders’ meetings by the affirmative vote of an absolute majority of shares present that are entitled to vote on such action, except that the approval of a majority of shares with voting rights, without application of multiple votes, is required in both first and second call for: (1) the transfer of our domicile outside Argentina, (2) a fundamental change of the corporate purpose set forth in the by-laws, (3) our anticipated dissolution, (4) the total or partial repayment of capital, (5) a merger of our company, if we are not the surviving entity, (6) a spinoff of our company, or (7) changing our corporate legal status.

Shareholders’ meetings may be called by the Board of Directors or the members of the statutory audit committee whenever required by law or whenever they deem it necessary. Also, the board or the members of the statutory audit committee are required to call shareholders’ meetings upon the request of shareholders representing an aggregate of at least five percent of our outstanding capital stock. If the board or the statutory audit committee fail to call a meeting following this request, a meeting may be ordered by the CNV or by the courts. In order to attend a meeting, a shareholder must deposit with us a certificate of book-entry shares registered in its name and issued by Caja de Valores at least three business days prior to the date on which the meeting is to be held. A shareholder may be represented by proxy. Proxies may not be granted to directors, members of the statutory audit committee or officers or employees of our company.

Conflict of Interest

A shareholder who votes on a matter involving our company in which its interest conflicts with ours may, under Argentine law, be liable for damages to us resulting from its decision, but only if the transaction would not have been approved without its vote.

Limitations on Foreign Investment in Argentina

Under the Argentine Foreign Investment Law, which as amended we refer to as the FIL, the purchase of stock by an individual or legal entity domiciled abroad or by a local company of foreign capital (as defined in the FIL) constitutes a foreign investment subject to the FIL. Foreign investments are generally unrestricted. However, foreign investments in certain industries are restricted to a certain percentage. No approval is necessary to purchase Class B shares. The FIL does not limit the right of non-resident or foreign owners to hold or vote Class B shares, and there are no restrictions in our by-laws limiting the rights of non-residents or non-Argentines to hold or vote our Class B shares.

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However, General Resolution No. 7 passed in September 2003 by the Inspección General de Justicia, or I.G.J., and other related regulations set forth certain requirements for foreign entities registered with the I.G.J. It implies, among other requirements, disclosure of information related to their proprietary interests in assets located outside Argentina to be at least equivalent in value to those located inside Argentina. The entities must comply with these requirements in order to (1) perform activities on a regular basis through their Argentine branches (Section 118 Argentine Corporate Law), or (2) exercise their ownership rights in Argentine Companies (Section 123 Argentine Corporate Law). In cases where the I.G.J. has concluded that the entities (a) do not have assets outside Argentina; or (b) have non-current assets that are not materially significant compared to those non-current assets which are owned by them and located in Argentina; or (c) the entity’s address in Argentina becomes the place where this entity makes a majority of its decisions, corporate or otherwise, the entities may be required to amend and register their by-laws to comply with Argentine law, thereby becoming an Argentine entity subject to Argentine law according to Section 124 of Argentine Corporate Law. In addition, Argentine companies with shareholders consisting of such entities that fail to comply with these requirements may be subject to the following sanctions: (1) the I.G.J. may not register corporate decisions adopted by the Argentine Company when its off-shore shareholder votes as a shareholder and when that vote is essential in attaining a majority and any decisions made pursuant to such vote related to the approval of its annual balance sheet may be declared null and void for administrative purposes; (2) whether or not the vote of the off-shore entity is necessary for purposes of determining quorum or majority, the I.G.J. may register the decision without considering that vote; and (3) the directors of the Argentine Company may be held personally liable for actions taken by the Argentine Company.

Change of Control

In 2001, Argentina adopted Decree-Law No. 677/2001, which, among others, establishes an Optional Statutory System for Binding Public Offers which regulates the change of control of a public company. According to this decree-law, if a person or entity, either directly or indirectly, acquires a determined percentage of the voting shares of a public company with the intention of obtaining control, then that person or entity must publicly tender to purchase all of the target company’s outstanding shares. Nevertheless, companies are free to opt out of the decree-law’s requirements, provided they do so expressly in their by-laws. Our shareholders had been called for an extraordinary meeting to be held July 8, 2003 to consider the incorporation an opt-out provision in our by-laws. The same proposal was submitted to the shareholders of Petrobras Energía. Both General Special Shareholders’ Meetings approved the non-adherence to the Optional Statutory System. This non-adherence does not restrain the voluntary exercise of such an offering.

COMPARISON OF NEW YORK STOCK EXCHANGE CORPORATE GOVERNANCE STANDARDS AND OUR CORPORATE GOVERNANCE PRACTICE

On November 4, 2003, the NYSE established new corporate governance rules. Under these rules, foreign private issuers are subject to a more limited set of corporate governance requirements than U.S. domestic issuers. As a foreign private issuer, pursuant to Rule 303 A 11 of the Listed Company Manual of the NYSE, we must provide a brief description of any significant difference between our corporate governance practices and those followed by U.S. companies under NYSE listing standards. As required by the NYSE, the table below discloses the significant differences between our corporate governance practices and the NYSE rules. Our corporate governance practices are described in further detail elsewhere in this annual report. See “Item 6. Directors, Senior Management and Employees” and “—Memorandum and Articles of Association.”

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Section of the NYSE Listed Company Manual	New York Stock Exchange Corporate Governance Rules for Domestic Issuers	Our Practices
Director Independence
303A.01	Listed companies must have a majority of independent directors. “Controlled companies,” which would include our company if it were a U.S. issuer, are exempt from this requirement. A controlled company is one in which more than 50% of the voting power is held by an individual, group or another company, rather than the public. A director is not independent if such director is: (1) a person who the board determines has a material direct or indirect relationship with the company, its parent or a consolidated subsidiary; (2) an employee, or an immediate family member of an executive officer, of the company, its parent or a consolidated subsidiary, other than employment as interim chairman or CEO; (3) a person who receives, or whose immediate family member receives, more than US$100,000 per year in direct compensation from the company, its parent or a consolidated subsidiary, other than director and committee fees or deferred compensation for prior services only (and other than compensation for service as interim chairman or CEO or received by an immediate family member for service as a non-executive employee); (4) a person who is affiliated with or employed, or whose immediate family member is affiliated with or employed in a professional capacity, by a present or former internal or external auditor of the company, its parent or a consolidated subsidiary; (5) an executive officer, or an immediate family member of an executive officer, of another company whose compensation committee’s membership includes an executive officer of the listed company, its parent or a consolidated subsidiary; or	Argentine law does not require that the majority of the board members be independent. Only the majority of the directors on the Audit Committee must be independent. At our annual shareholders meeting, our shareholders determine in accordance with Resolution No. 368 of the CNV and Decree No. 677/01 whether or not each of our directors is independent based on the following criteria. A director is not independent if such director is: (1) a member of management or an employee of shareholders who hold significant interests in the issuer, or of other entities in which these shareholders hold either directly or indirectly significant interests or over which these shareholders exercise a significant influence; (2) an employee of the issuer or has been an employee in the last three years; (3) a person who has professional relations or is part of a company or professional association that maintains professional relations with, or that receives remunerations or fees (other than directors’ fees) from the issuer or from its shareholders that hold either directly or indirectly significant interests in or exercise a significant influence over the issuer, or from which such shareholders hold either directly or indirectly significant interests or exercise a significant influence; (4) a person who is either directly or indirectly a holder of significant interests in the issuer or in an entity that has significant interests in or exercises a significant influence over the issuer; (5) the member is married or is a family member, up to fourth degree by blood or up to second degree by affinity, to an individual who would not qualify as independent; and (6) a person who sells or provides either directly or indirectly goods or services to the issuer or to shareholders that hold either directly or indirectly significant interests in or exercise a significant influence over the issuer and receives compensation for such services that is substantially higher than that received as a director.

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Section of the NYSE Listed Company Manual	New York Stock Exchange Corporate Governance Rules for Domestic Issuers	Our Practices
	(6) an executive officer or employee of a company, or an immediate family member of an executive officer of a company, that makes payments to, or receives payments from, the listed company, its parent or a consolidated subsidiary for property or services in an amount which, in any single fiscal year, exceeds the greater of US$1 million or 2% of such other company’s consolidated gross revenues (charities are not included, but any such payments must be disclosed in the company’s proxy (or, if no proxy is prepared, its Form 10-K/ annual report)). There is a three-year cooling off period before non-independent directors can be considered independent. “Immediate family member” includes a person’s spouse, parents, children, siblings, mothers and fathers-in-law, sons and daughters-in-law and anyone (other than domestic employees) who shares the person’s home. Individuals who are no longer immediate family members due to legal separation, divorce or death (or incapacity) are excluded.	“Significant interests” shall mean shareholdings that represent at least 35% of the capital stock of the relevant entity, or a smaller percentage when the person has the right to elect one or more directors by class of shares or by having entered into agreements with other shareholders relating to the governance and the management of the relevant entity or of its controlling shareholders. Nicolas Perkins, Roberto Alejandro Fortunati and Pablo Cavallaro are currently members of our Board of Directors who qualify as independent directors pursuant to the factors listed above.
303A.03	The non-management directors of each listed company must meet at regularly scheduled executive sessions without management.	Alberto da Fonseca Guimarães, Carlos Alberto Pereira de Oliveira, Daniel Jorge Maggi, Héctor Daniel Casal, Luiz Augusto Marciano da Fonseca, and Luis Miguel Sas each, in addition to serving on our Board, have management positions. Our other thirteen directors are non-management directors. The non-management directors do not meet at regularly scheduled executive sessions without the presence of the managerial directors. See “Item 6. Directors, Senior Management and Employees—Directors and Senior Management—Board of Directors.”
Nominating/Corporate Governance Committee
303A.04	Listed companies must have a nominating/corporate governance committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties. Exception for “controlled companies,” which would include our company if it were a U.S. issuer.	Argentine law does not require the establishment of a nominating committee. We do not have a nominating committee. We also do not have a corporate governance committee. Instead, the entire Board of Directors develops, evaluates and approves our corporate governance principles with the assistance of an advisory body consisting of certain of our officers.

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Section of the NYSE Listed Company Manual	New York Stock Exchange Corporate Governance Rules for Domestic Issuers	Our Practices
Management Resources and Compensation Committee
303A.05	Listed companies must have a compensation committee composed entirely of independent directors, with a written charter that covers certain minimum specified duties. Exception for “controlled companies,” which would include our company if it were a U.S. issuer.	Argentine regulations do not require the establishment of a compensation committee. We do not have a compensation committee.
Audit Committee
303A.06 303A.07	Listed companies must have an Audit Committee with a minimum of three independent directors that satisfy the independence requirements of Rule 10A-3 under the Exchange Act, with a written charter that covers certain minimum specified duties.	Our Audit Committee is an advisory committee to the Board of Directors. Argentine law requires that the audit committee be composed of three members from the Board of Directors (with a majority of independent directors), all of whom are well-versed in business, financial or accounting matters. We are not required to satisfy the audit committee requirements of Rule 10A-3 under the Exchange Act until July 31, 2005. The members of our audit committee will not need to satisfy the NYSE independence standards that are not required by Rule 10A-3. Nonetheless, our Audit Committee, established on May 7, 2004, is composed of three directors who each satisfy the independence requirements of Rule 10A-3. One member of the Audit Committee qualifies as a “financial expert” within the meaning of Item 16A of the Form 20-F. See “Item 16A. Audit Committee Financial Expert.” Our Audit Committee is responsible for, among other things: (1) monitoring and evaluating the activities of the internal and external auditors, (2) supervising the process for preparation of our financial statements, (3) ensuring that our financial statements comply with applicable legal requirements, (4) providing the market with complete information with respect to transactions where members of corporate bodies or controlling shareholders of ours have conflicts of interest, and (5) opine on the reasonableness of compensatory plans for directors and managers. See “Item 6. Directors, Senior Management and Employees—Board Practices—Audit Committee.”

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Section of the NYSE Listed Company Manual	New York Stock Exchange Corporate Governance Rules for Domestic Issuers	Our Practices
		Under Argentine law, the shareholders must appoint the external auditor. The Board of Directors may present a proposal regarding the appointment of the external auditor to the shareholders’ meeting. The Audit Committee must issue an opinion on any such proposal presented by the Board of Directors to the Shareholders. We also have an internal audit department. In accordance with Argentine law, we also have established a Statutory Syndic Committee that is comprised of three members and three alternate members, approved by our shareholders. Members of the Statutory Syndic Committee are not members of our Board of Directors. The primary responsibilities of the Statutory Syndic Committee are to monitor management’s compliance with the Companies Law, our by-laws and the shareholders’ resolutions. The Statutory Syndic Committee also performs other functions, including: (1) attending meetings of the Board of Directors and shareholders, (2) calling extraordinary shareholders’ meetings when deemed necessary or when required by shareholders, in accordance with the Business Companies Law, No. 19550, (3) presenting a report on the reports of the Board of Directors and the annual financial statements at regular shareholders’ meetings, and (4) investigating written complaints of shareholders representing not less than 2% of the capital stock. See “Item 6. Directors, Senior Management and Employees—Board Practices—Statutory Syndic Committee.”
Equity Compensation Plans
303A.08	Shareholders must be given the opportunity to vote on equity-compensation plans and material revisions thereto, with limited exemptions set forth in the NYSE rules.	Our Board of Directors approves the equity compensation plans for our executive officers and senior management. For a description of our stock option programs for our executive officers and senior management see “Item 6. Directors, Senior Management and Employees—Compensation.” The Audit Committee issues an opinion on the reasonableness of the Board of Directors’ proposals regarding fees and executive equity compensation plans.

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Section of the NYSE Listed Company Manual	New York Stock Exchange Corporate Governance Rules for Domestic Issuers	Our Practices
Corporate Governance Guidelines
303A.09	Listed companies must adopt and disclose corporate governance guidelines.	Corporate governance guidelines are not required by Argentine law, but the company has nonetheless adopted the practice of issuing corporate governance policies.
Code of Ethics for Directors, Officers and Employees
303A.10	Listed companies must adopt and disclose a code of business conduct and ethics for directors, officers and employees, and promptly disclose any waivers of the code for directors or executive officers.	We have adopted a Code of Conduct and Business Ethics applicable to all employees. See “Item 16B. Code of Ethics.” Any amendment to the code will be disclosed on our web site at www.petrobras.com.ar

MATERIAL CONTRACTS

We are party to a number of material financing agreements, including the underlying agreements for our Global Note Program, and letters of credit entered into to backstop certain financial commitments related to our investment in OCP and our commitment under the ship or pay contract with OCP. These agreements and other financing agreements are described under “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources” and “Item 5. Operating and Financial Review and Prospects—Contractual Obligations.”

Our agreements with related parties are described in “Related Party Transactions” under Item 7.

We also enter into a number of significant agreements in the ordinary course of our business, including an oil transportation agreement with OCP. See “Item 4. Information About the Company—Oil and Gas Exploration and Production—Production—Production Outside of Argentina—Ecuador—Ship or Pay Contract with Oleoducto de Crudos Pesados (OCP).”

EXCHANGE CONTROLS

The Argentine foreign exchange market was subject to exchange controls until December 1989. From 1989 to December 3, 2001, there were no foreign exchange controls preventing or restricting the conversion of pesos into US dollars.

Since early 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 strict restrictions for making transfers abroad, with the exception of those related to foreign trade and other authorized transactions. These regulations have been amended on a number of occasions since they were first promulgated and we cannot assure you as to how long these current regulations will be in effect or whether they will be made stricter.

Pursuant to resolutions issued by the Central Bank seeking a gradual normalization of the local foreign exchange market, effective January 8, 2003, prior authorization from the Central Bank is no longer required to transfer funds abroad for payment to foreign beneficiaries of corporate profits and dividends reported as payable under approved financial statements certified by an independent auditor.

In addition, for the remittance abroad of funds required for principal payments under financial loans, prior Central Bank authorization is no longer required as of May 6, 2003, provided such debts have been disclosed under the Informative Regime of External Debts (Régimen Informativo de Pasivos Externos).

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Interest payments on outstanding financial indebtedness no longer require Central Bank approval for their remittance abroad, provided that the transfer abroad in connection with such payments is made not more than 15 days in advance of their stated maturity date.

On June 9, 2005, the federal executive branch issued Executive Order 616/05. As a result of this executive order any cash inflow to the domestic market derived from foreign loans to the Argentine private sector shall have a maturity for repayment of at least 365 days as from the date of inflow of cash. In addition, 30% of the amount shall be deposited with domestic financial institutions. This deposit must be (1) registered, (2) non-transferable, (3) non-interest bearing, (4) made in US dollar, (5) have a term of 365 days and (6) cannot be used as security or collateral in connection with other credit transactions. Export and import financing operations, as well as, primary public offerings of debt securities listed on self-regulated markets are exempt from the foregoing provisions. See “Item 5. Operating and Financial Review and Prospects—Liquidity and Capital Resources—Changes to Exchange Market Regulations.”

TAXATION

Argentine Taxes

General

The following discussion describes the material Argentine tax matters relating to the acquisition, ownership and disposition of our ADSs or Class B shares.

The discussion describes the principal Argentine tax consequences of the acquisition, ownership and disposition of our ADSs or Class B shares, but it does not purport to be a comprehensive description of all of the Argentine tax considerations that may be relevant to your decision to acquire our ADSs or Class B shares. For purposes of the following discussion of Argentine tax law, the purchase, sale or disposition of ADSs is treated as a purchase, sale or disposition of Class B shares.

The discussion is based upon tax laws of Argentina, regulations thereunder, and administrative and judicial interpretations thereof, as in effect on the date of this annual report and subject to change with possibly retroactive effect. In addition, the summary is based in part on representations of the depositary and assumes that each obligation provided for in, or otherwise contemplated by, the deposit agreement for our ADSs or any related document will be performed in accordance with its terms. Prospective purchasers of ADSs or Class B shares should consult their own tax advisors as to the Argentine or other tax consequences of the acquisition, ownership and disposition of our ADSs or Class B shares in their particular circumstances.

Income Tax

Capital gains

Sales or other dispositions of our Class B shares or ADSs by non-residents of Argentina or Argentine resident individuals or undivided estates located in Argentina are exempt from paying income tax on capital gains resulting from the sale. However, capital gains of legal entities domiciled in Argentina resulting from the sale or other disposition of our Class B shares or ADSs will be subject to income tax at a 35% rate. Argentine pension funds, investment funds and some foundations are not subject to income tax. There will be no withholding by us on account of this tax.

Dividends

If any dividend is paid to you on our Class B shares and ADSs that is from corporate earnings that have not already been subject to Argentine corporate income tax determined in accordance with general income tax regulations, we will be required to deduct and withhold Argentine income tax at a rate of 35% on the amount of the dividend paid by us.

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However, so long as we distribute dividends to you on our Class B shares and ADSs that are derived from earnings of Petrobras Energía on which Argentine corporate income tax has been paid, we will not be required to withhold Argentine income tax on those dividends. Thus, we expect that dividends paid to you on our Class B shares and ADSs will not be subject to Argentine withholding tax under current Argentine law.

Capital reductions and other distributions

Capital reductions and redemptions of our Class B shares and ADSs are not subject to income tax up to an amount equivalent to the adjusted contributed capital corresponding to the Class B shares and ADSs to be redeemed plus accumulated taxable earnings after income taxes and dividends received. Any distribution exceeding this amount will be considered as a dividend for tax purposes and withholding tax would apply as described above.

Tax on personal property

Corporations, partnerships, establishments, financial trusts and other legal entities domiciled or located in Argentina are not subject to the personal assets tax.

Shareholdings or interests in companies governed by Law 19,550, that are held by individuals or undivided estates domiciled or located in Argentina or abroad, or by companies or other legal persons located abroad are subject to the personal assets tax. A company is liable for the personal assets tax payable by its shareholders in respect of their share ownership. A company liable for this tax payment will be entitled to seek reimbursement of the amount paid from the shareholders, by way of withholding or by foreclosing directly on the assets that gave rise to such payment. Consequently, we are liable to pay the personal assets tax in respect of our Class B shares and ADSs and we are entitled to seek reimbursement of the amount paid from the shareholders. The applicable tax rate is 0.50% on the equity value of the shares, calculated as of December 31 of the year under consideration.

For purposes of the above paragraph, shareholdings or interests in companies governed by Law 19,550, the holders of which are companies or any other kinds of legal persons domiciled or located abroad, are presumed to indirectly belong to individuals domiciled abroad or to undivided estates located abroad. Contrary evidence is not accepted to rebut this presumption.

Other taxes

There is no inheritance, gift, succession or value-added taxes applicable to the ownership, transfer, exchange or disposition of our Class B shares or ADSs. There are no Argentine stamp, issue, registration or similar taxes or duties payable by holders of our Class B shares or ADSs.

There is no Argentine gross revenue tax applicable on our Class B shares or ADSs or on income obtained from the disposition of our Class B shares or ADSs.

Our Class B shares or ADSs owned by legal persons (corporations, partnerships, certain associations and non-financial trusts organized in Argentina and permanent establishments owned by foreign beneficiaries) are exempt from tax on minimum presumed income.

Commissions paid in brokerage transactions for the sale of our Class B shares on the Buenos Aires Stock Exchange are subject to a value-added tax at a rate of 21%.

United States Federal Income Taxes

General

The following discussion summarizes the United States federal income tax considerations relevant to the acquisition, ownership and disposition of ADSs or Class B shares by U.S. holders (as defined below). This discussion is based on the United States Internal Revenue Code of 1986, as amended (referred to as the Code), Treasury regulations promulgated or proposed under the Code, published rulings, and administrative and judicial

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interpretations of the Code and the Treasury regulations, all as of the date hereof, and all of which are subject to change (possibly with retroactive effect) and to differing interpretations. This summary is based in part on representations of the depositary and assumes that each obligation provided for in or otherwise contemplated by the deposit agreement for our ADSs or any related document will be performed in accordance with its terms. This discussion is addressed only to U.S. holders and does not address any United States federal income tax considerations that might be relevant to persons other than U.S. holders. Further, this discussion deals only with U.S. holders that hold ADSs as capital assets (generally, property held for investment) within the meaning of Section 1221 of the Code, and does not address the tax treatment of holders that may be subject to special tax rules, such as banks, insurance companies, tax-exempt organizations, financial institutions, brokers or dealers in securities or currencies, traders in securities or currencies that elect mark-to-market treatment, persons that hold the ADSs as part of a hedge, “straddle,” “conversion transaction” or other integrated investment, persons that hold ADSs or Class B shares through a partnership or other pass-through entity, U.S. holders who have a “functional currency” other than the US dollar or U.S. holders that own or are treated as owning 10% or more of the voting power of our shares.

This discussion does not describe all aspects of United States federal income taxation that may be relevant to a particular investor in light of such investor’s particular circumstances. U.S. holders should consult their own tax advisors as to the specific tax consequences of the acquisition, ownership and disposition of our ADSs or Class B shares, including the application and effect of United States federal, state, local, foreign and other tax laws and the possible effects of changes in United States federal or other tax laws.

In general, for United States federal income tax purposes, if you hold our ADSs, you will be treated as the beneficial owner of our Class B shares represented by those ADSs. For purposes of this discussion, you are a U.S. holder if you are a beneficial owner of our Class B shares and you are, for United States federal income tax purposes, (a) an individual who is a citizen or resident of the United States, (b) a corporation (or other business entity created or organized in or under the laws of the United States or of any state or the District of Columbia treated as a corporation), or (c) otherwise subject to United States federal income taxation on a net income basis with respect to the ADSs or the Class B shares.

Taxation of our ADSs

Distributions

Distributions we make on our ADSs and Class B shares will be treated as taxable dividends to you to the extent of our current and accumulated earnings and profits as determined under United States federal income tax principles. A dividend, generally, will be included in the gross income of a U.S. holder when the dividend is actually or constructively received by the depositary. Such dividends will not be eligible for the dividends-received deduction generally allowed to U.S. corporations in respect of dividends received from other U.S. corporations.

Subject to certain exceptions for short-term and hedged positions, the US dollar amount of dividends received by an individual U.S. holder prior to January 1, 2009 with respect to the ADSs will be subject to taxation at a maximum rate of 15% if the dividends are “qualified dividends.” Dividends paid on the ADSs will be treated as qualified dividends if (1) the ADSs are readily tradable on an established securities market in the United States and (2) we were not, in the year prior to the year in which the dividend was paid, and are not, in the year in which the dividend is paid, (a) a passive foreign investment company, or PFIC, or (b) for dividends paid prior to the 2005 tax year, a foreign personal holding company, or FPHC, or foreign investment company, or FIC. The ADSs are listed on the New York Stock Exchange, and will qualify as readily tradable on an established securities market in the United States so long as they are so listed. Based on our audited financial statements and relevant market and shareholder data, we believe that we were not treated as a PFIC, FPHC or FIC for United States federal income tax purposes with respect to our 2003 or 2004 taxable year. In addition, based on our audited financial statements and our current expectations regarding the value and nature of our assets, the sources and nature of our income, and relevant market and shareholder data, we do not anticipate becoming a PFIC for our 2005 taxable year.

Based on existing guidance, it is not entirely clear whether dividends received with respect to the Class B shares will be treated as qualified dividends, because the Class B shares are not themselves listed on a U.S. exchange. In addition, the U.S. Treasury has announced its intention to promulgate rules pursuant to which U.S. holders of ADSs or common stock and intermediaries through whom such securities are held will be permitted to

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rely on certifications from issuers to establish that dividends are treated as qualified dividends. Because such procedures have not yet been issued, it is not clear whether we will be able to comply with them. U.S. holders of ADSs and Class B shares should consult their own tax advisors regarding the availability of the reduced dividend tax rate in the light of their own particular circumstances.

The amount of dividend income taxable to you generally will include the amount of Argentine taxes, if any, that we withhold (as described under “—Argentine Taxes”). Thus, in the event such withholding taxes are imposed, you most likely will be required to report income in an amount greater than the cash you receive in respect of payments in respect of the ADSs. Subject to various limitations, you may be eligible to claim the Argentine income tax withheld in connection with any distribution on ADSs as a credit or deduction for purposes of computing your United States federal income tax liability. Foreign tax credits will not be allowed for withholding taxes imposed with regard to certain short-term or hedged positions in securities and may not be allowed with regard to arrangements in which a U.S. holder’s expected economic profit is insubstantial. Dividends we pay in respect of our ADSs generally will be treated as foreign source income and generally will constitute “passive” income for foreign tax credit purposes. Special rules will apply to the calculation of foreign tax credits in respect of dividend income that is subject to preferential rates of United States federal income tax. U.S. holders should consult with their own tax advisors with regard to the availability of foreign tax credits and the application of the foreign tax credit limitations in light of their particular situation.

If a dividend is paid in pesos, the amount you must include in gross income will be the US dollar value of the distributed pesos, as determined on the date of receipt by the depositary, regardless of whether the payment is in fact converted into US dollars at that time. You will have a tax basis in such pesos for United States federal income tax purposes equal to the US dollar value on the date of such receipt. Any subsequent gain or loss in respect of such pesos arising from exchange rate fluctuations will be ordinary income or loss and will be treated as income from U.S. sources for foreign tax credit purposes.

It is unlikely that you will be able to claim a foreign tax credit for any Argentine personal property tax (as described in “—Argentine Taxes”), but you may be able to deduct such tax in computing your United States federal income tax liability, subject to applicable limitations.

Sale, exchange or other disposition

Deposits and withdrawals of our Class B shares by U.S. holders in exchange for our ADSs will not result in the realization of gain or loss for United States federal income tax purposes.

Upon a sale, exchange or other disposition of our ADSs, a U.S. holder generally will recognize capital gain or loss equal to the difference between the amount realized on such disposition (which, in the event of a redemption, will include any amount withheld by us in respect of Argentine taxes imposed on such redemption) and your adjusted tax basis in our ADSs (which, generally, is the US dollar cost thereof). Any gain that you recognize generally will be treated as U.S. source income for United States foreign tax credit purposes. Consequently, if a withholding tax is imposed on such gain, you will not be able to use any corresponding tax credit unless you have other foreign source income of the appropriate type in respect of which the credit may be used. Long-term capital gains recognized by an individual holder are taxable at a maximum rate of 15%.

Backup withholding

The information reporting requirements of the Code generally will apply to distributions to you. Subject to certain exceptions, “backup withholding” may apply to payments of dividends on our ADSs and to payments of the proceeds of a sale or exchange of the ADSs that are made to a non-corporate U.S. holder if such holder fails to provide a correct taxpayer identification number or otherwise comply with applicable requirements of the backup withholding rules. The backup withholding tax is not an additional tax and may be credited against a U.S. holder’s United States federal income tax liability, provided that correct information is provided to the Internal Revenue Service. U.S. holders should consult their own tax advisors regarding their qualification for exemption from backup withholding and the procedure for obtaining such exemption, if applicable.

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DOCUMENTS ON DISPLAY

We file reports, including annual reports on Form 20-F, and other information with the SEC pursuant to the rules and regulations of the SEC that apply to foreign private issuers. You may read and copy any materials filed with the SEC at its public reference rooms in Washington, D.C., at 450 5^th Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room. As a foreign private issuer, we were not required to make filings with the SEC by electronic means prior to November 4, 2002, although we were permitted to do so. Any filings we make electronically will be available to the public over the Internet at the SEC’s web site at http://www.sec.gov.

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Item 11.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following qualitative and quantitative information is provided about our exposure to market risks derived from the ordinary course of business.

This analysis comprises statements about future events which may not occur and may imply risks and uncertainties. Actual results may significantly differ due to several factors.

Qualitative Disclosures

Our results of operations and financial condition are exposed to three principal market risk categories: (1) commodity price risk, (2) foreign currency exchange rate risk, and (3) interest rate risk. We periodically review the risks associated with our businesses at a senior management level, based on an approach that has evolved from an independent analysis of each business unit to a risk management strategy that focuses on measuring and monitoring the risks that affect our overall portfolio of assets. We believe our risk management strategy, which is in line with the business integration strategy, allows for efficient growth in the vertical integration of our business, while balancing market risks in the business value chain

As part of this strategy, we use hedging derivative instruments, such as futures, swaps, options and other instruments, to mitigate risks related to results and cash flow volatility as a result of fluctuations in the price of crude oil and its by-products.

These financial operations expose us to credit risk. We apply strict requirements for the approval of lines of credit, apply several procedures to assess such risks and seek to reduce our credit exposure by using certain tools (such as agreements for collateral advance payment or collection of such operations and the offset of collections and payments). Such financial instruments are entered into subject to strict restrictions set by our senior management. The results of hedging operations are periodically reviewed by management in order to confirm they remain effective and relevant, consistent with market conditions. Such instruments are entered into in accordance with the goals of our market risk management strategy.

The boards of directors of our affiliates formulate their relevant risk management policies.

Commodity price risk

In the Oil and Gas Exploration and Production, Refining, and Petrochemicals businesses we are exposed to market risk in relation to price volatility, mainly of crude oil and by-products. 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.

Historically, we have prioritized a risk strategy that, principally through swaps and producer collars, was designed to set crude oil sale prices at certain intervals. As a result, the results of hedging derivative instruments were generally offset by changes in crude oil sale prices. This policy, although it proved effective to comply with the proposed objectives, especially in 1998 when oil prices were at all time lows, has prevented us from benefiting from price increases.

Since 2002, we have increased the use of option contracts within our crude oil prices hedging strategy. These contracts provide greater flexibility, provide protection against a drop in prices and allow the possibility for us to benefit from a high price scenario. Simultaneously, this strategy limits the financial risk associated with the collateral requirements of swaps and producers collars.

The chart below provides information as of December 31, 2004, regarding derivative contracts entered into by us in connection with our exposure to commodity price risks.

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Foreign exchange risk

Our results of operations and financial condition are sensitive to changes in the exchange rate between the Argentine peso and other foreign currencies.

As of December 31, 2004, a significant portion of our and affiliates’ debt was denominated either directly or indirectly in US dollars.

Historically, exposure of the Argentine peso to the US dollar had not been hedged since under the Convertibility Law, effective as of 1991, the BCRA was obliged to sell US dollars at a rate of exchange not exceeding one peso per US dollar. In the economic, financial and regulatory scenario prevailing as of December 31, 2001, our cash flow generation provided us with a natural hedge for our US dollar-exposure, since a significant portion of our and our subsidiaries’ income was directly or indirectly denominated in US dollars.

On January 6, 2002, the Argentine government enacted the Public Emergency Law that changed the convertibility system in force, which severely affected our US dollar-denominated operating cash flow. Measures such as the pesification of utility rates previously denominated in US dollars, the implementation of new taxes on hydrocarbon exports and the enforcement of policies limiting our ability to increase our peso-denominated prices to maintain our operating cash flows when measured in US dollars, negatively affected our ability to hedge the impact of the peso devaluation on the financial cost of our US dollar-denominated debt.

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

Interest rate risks

Interest rate risk management mainly aims at reducing overall financial costs and adjusting our exposure to risk.

In order to reduce interest rate volatility, we, by means of the application of mathematical models that incorporate historical volatility and correlation analyses, permanently evaluate the opportunity to enter into derivative instruments.

As of December 31, 2004, we maintained an interest rate risk hedging contract aimed at managing the risk related to LIBO rate volatility from our Class C notes, fixing the respective interest rate at 7.93% per annum. As a result of this hedging contract, as of December 31, 2004, approximately 63% our total financial debt was subject to fixed rates and 37% was subject to variable rates. The variable rate debt is mainly linked to the LIBO rate. This risk, however, is mitigated by the natural hedge provided by the portion of fees received for production activities in the Oritupano-Leona area and by certain financial assets, with cash flows determined by LIBO or a similar rate.

Quantitative Disclosure

The chart below provides quantitative information about our derivative financial instruments and other financial instruments as of December 31, 2004, that are sensitive to changes in commodity prices, interest rates and foreign exchange rates.

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Commodity Price Risk:


	Collections (Payments) Expected Maturity
	2005		Estimated Fair Value
Sales Price Exposure
Crude oil price swaps⁽¹⁾
Contract volumes (million barrels)	7.3		—
Average settlement prices (US$ per barrel)	19.00		—
Notional amount (in million of US$)	139		—
Expected cash flow (in million of US$)⁽²⁾	(170	)	(170	)

(1)	These transactions are swaps, which were originally issued as options that have been exercised by the counterparty.

(2)	The expected cash flow was calculated based on the closing price of future contracts of Light Sweet Crude Oil on the New York Mercantile Exchange as of December 31, 2004.

Foreign Currency Exchange Rate Risk and Interest Rate Risk:


	Expected Maturity
	2005	2006	2007	2008	2009	Thereafter	Total	Estimated Fair Value
	(in millions of pesos)
Short- and Long- Term Debt
US dollar:
Fixed Rate	580	74	842	160	541	1,637	3,834	4,032
Average interest rate (%)	6.7	4.2	8.9	7.4	9.0	8.6	—	—
Variable rate	552	544	503	70	62	369	2,100	2,100
Average interest rate (%)	6.1	6.0	6.1	6.6	6.7	4.4	—	—

Pesos converted to US dollar:
Fixed Rate	15	—	—	—	—	—	15	15
Average interest rate (%)	2.6	—	—	—	—	—	—	—

Total	1,147	618	1,345	230	603	2,006	5,949	6,147

Reconciliation table with our Financial Statements, which include the proportional consolidation of CIESA and Distrilec.


	Short-Term debt	Long-Term debt	Total
	(in million of pesos)
Debt obligations⁽¹⁾ (without proportional consolidation)	1,147	4,802	5,949
PEPSA’s interest in Distrilec’s debt obligations	44	159	203
PEPSA’s interest in CIESA’s debt obligations	461	1,287	1,748

Debt obligations⁽²⁾ (with proportional consolidation)	1,652	6,248	7,900

(1)	As reported in tabular presentation.

(2)	As reported in the consolidated balance sheet of our financial statements.

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Item 12-14. NOT APPLICABLE

Item 15.

CONTROLS AND PROCEDURES

(a) We carried out an evaluation under the supervision and with the participation of our management, including our chief executive officer and chief financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as of December 31, 2004. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon our evaluation, our chief executive officer and chief financial officer concluded that the disclosure controls and procedures as of December 31, 2004 were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported as and when required.

(b) There has been no change in our internal control over financial reporting during 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Recent Developments relating to compliance with the Sarbanes-Oxley Act

Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002, beginning with our Annual Report on Form 20-F for the fiscal year ending December 31, 2006, we will be required to furnish a report by our management on our internal control over financial reporting. This report will contain, among other matters, an assessment of the effectiveness of our internal control over financial reporting as of the end of the fiscal year, including a statement as to whether or not our internal control over financial reporting is effective. This assessment will include disclosure of any material weaknesses in our internal control over financial reporting identified by management. This report will also contain a statement that our auditors have issued an attestation report on management’s assessment of such internal controls.

To comply with this requirement, we are adopting a framework of internal control over financial reporting based on the recommendation of the Committee of Sponsoring Organizations of the Treadway Commission (COSO), formed by accounting and auditing companies in the United States. The COSO framework is the prevailing system adopted by companies subject to Section 404 of the Sarbanes-Oxley Act. The implementation of the COSO framework counts with the sponsorship and direct involvement of our chief financial officer and chief executive officer, and is lead by a special project team composed of members of all business and support areas of the company and the participation of Internal Audit, the Executive Committee, and the Audit Committee of the Board.

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Item 16A.

AUDIT COMMITTEE FINANCIAL EXPERT

At the Board of Directors meeting on May 7, 2004, our Directors determined and designated that Cedric Bridger is an “audit committee financial expert” within the meaning of this Item 16A.

Item 16B.

CODE OF ETHICS

We have adopted a code of ethics, as defined in Item 16B of this annual report on Form 20-F. Our code of ethics applies to our chief executive officer, chief financial officer, chief accounting officer, and persons performing similar functions as well as to our directors and other officers and employees. Our code of ethics is available on our web site at http://www.petrobras.com.ar.

Item 16C.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit and Non-Audit Fees

Fees for professional services provided to us by our independent auditors, Pistrelli, Henry Martin y Asociados S.R.L., a member firm of Ernst & Young Global and other member firms of Ernst & Young Global, during the fiscal years ended December 31, 2004 and 2003 in each of the following categories are:


	Year ended December 31,
	2004	2003
	(in thousands of pesos)
Audit fees	6,001	4,333
Audit-related fees	2,764	2,323
Tax fees	235	238

Total fees	9,000	6,894

Audit fees. Audit fees in the above table are mainly for in connection with the audit of our annual financial statements and the review of our quarterly reports, statutory audits of subsidiaries, and comfort letters.

Audit-related fees. Audit-related fees in the above table are mainly for (a) audit reports required by the parent company, (b) reviews of internal controls of our application systems and security of our technical infrastructure, and (c) documentation assistance in connection with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002.

Tax fees. Tax fees in the above table are fees mainly for tax compliance and tax advice.

Audit Committee Pre-Approval Policies and Procedures

The Audit Committee must pre-approve all services provided by the external auditors to ensure the auditors’ independence and compliance with all applicable legal restrictions. Pre-approval is either general or specific in nature. All services that are predictable and recurrent in nature and can be performed in a reasonably foreseeable time frame and at a cost that can be reasonably estimated may be approved by the Audit Committee in a general fashion on an annual basis. Services to be pre-approved on a general basis must be described in sufficient detail so that their scope is readily apparent. This description must also include an estimate of the fees payable for such services. Specific pre-approval is required for any services not subject to general pre-approval and/or exceeding the estimated cost of those services. Detailed, written descriptions of any proposed services must be delivered to the administrative manager, who will determine whether such services have already been pre-approved and bring to the Audit Committee’s attention those services that have not been pre-approved. Any doubts as to the scope of a pre-approved service must be resolved exclusively by the Audit Committee. Prior to Audit Committee meetings and at least three times a year, the administrative manager must provide a report on all services provided by the external auditor and related fees to the Audit Committee. The Audit Committee is also required to periodically discuss with the external auditors the services they provide to us and our affiliates and the compensation they receive for those services.

189

Item 16D.

NOT APPLICABLE

Not applicable.

Item 16E.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

From January 1, 2004 to December 31, 2004, no purchases were made by or on behalf of us or any affiliated purchaser of our ordinary shares or ADSs.

Item 17.

NOT APPLICABLE

Item 18.

FINANCIAL STATEMENTS

Reference is made to pages F-1 to F-107 of this annual report.

190

Item 19.

EXHIBITS

Pursuant to the rules and regulations of the SEC, we have filed certain agreements as exhibits to this annual report on Form 20-F. These agreements may contain representations and warranties by the parties. These representations and warranties have been made solely for the benefit of the other party or parties to such agreements and (1) may be intended not as statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements if those statements turn out to be inaccurate, (2) may have been qualified by disclosures that were made to such other party or parties and that either have been reflected in the company’s filings or are not required to be disclosed in those filings, (3) may apply materiality standards different from what may be viewed as material to investors and (4) were made only as of the date of such agreements or such other date(s) as may be specified in such agreements and are subject to more recent developments. Accordingly, these representations and warranties may not describe our actual state of affairs at the date hereof.


Exhibit No.		Description

1.1		English translation of Estatutos (by-laws) of Petrobras Energía Participaciones S.A.

2.1		Reference is made to the following Exhibits on file with the SEC contained in Petrobras Energía Participaciones S.A.’s Registration Statement on Form F-4 (333-11130) filed with the Commission on November 15, 1999: Exhibit No. 4.2, Form of Deposit Agreement among Petrobras Energía Participaciones S.A. (formerly PC Holdings S.A.), Citibank, N.A., as depositary, and the Holders and Beneficial Owners of American Depositary Shares evidenced by American Depositary Receipts issued thereunder, including the form of American Depositary Receipt; Exhibit No. 4.3, English translations of letters from members of the Perez Companc family to Petrobras Energía Participaciones S.A. (formerly PC Holdings S.A.) whereby such persons agree not to acquire an interest in certain entities; and Exhibit No. 4.4, English translation of Assignment Agreement among Class A shareholders and Petrobras Energía Participaciones S.A. (formerly PC Holdings S.A.) regarding the partial assignment of dividends to Class B shareholders.

2.2		Trust Deed dated June 29, 1993 between Compania Naviera Perez Companc S.A.C.F.I.M.F.A. and Citicorp Trustee Company Limited.*

2.3		Supplemental Trust Deed dated January 13, 1995 among Compania Naviera Perez Companc S.A.C.F.I.M.F.A., Citicorp Trustee Company Limited and others, Second Supplemental Trust Deed dated September 11, 1995 among Compania Naviera Perez Companc S.A.C.F.I.M.F.A., Citicorp Trustee Company Limited and others, Third Supplemental Trust Deed dated January 9, 1996 among Petrobras Energía Participaciones S.A., Citicorp Trustee Company Limited and others, Fourth Supplemental Trust Deed dated May 2, 1996 among Petrobras Energía Participaciones S.A., Citicorp Trustee Company Limited and others, Fifth Supplemental Trust Deed dated January 8, 1997 between Petrobras Energía Participaciones S.A. and Citicorp Trustee Company Limited, Sixth Supplemental Trust Deed dated May, 1997 between Petrobras Energía Participaciones S.A. and Citicorp Trustee Company Limited, Seventh Supplemental Trust Deed dated December 21, 1998 between Petrobras Energía Participaciones S.A. and Citicorp Trustee Company Limited, Eighth Supplemental Trust Deed dated November 28, 2000 between Petrobras Energía and Citicorp Trustee Company Limited, each relating to the Trust Deed dated June 29, 1993.*

2.4		Form of US$193,450,000 Restricted Global Note and Form of US$106,550,000 Unrestricted Global Note, related to Petrobras Energía’s 9% notes due 2004.*

2.5		Form of US$323,500,000 Restricted Global Note and Form of US$76,500,000 Unrestricted Global Note, related to Petrobras Energía’s 8.125% notes due 2007.*

2.6		Indenture dated May 1, 1998 between Petrobras Energía Participaciones, S.A. and Citibank, N.A., as Trustee.*

191



2.7		Form of US$92,200,000 Restricted Global Note and Form of US$107,800,000 Unrestricted Global Note, related to Petrobras Energía’s 9% Series B Notes due 2006.*

2.8		Third Supplemental Indenture dated July 17, 2001, to the Indenture dated May 1, 1998 and filed hereto as Exhibit 2(b)(v), among Petrobras Energía, Citibank N.A. as Trustee, Co-Security Registrar, Authenticating Agent and Transfer Agent in New York, Citibank N.A. acting through its Buenos Aires branch, as Security Registrar and Transfer Agent in Argentina, Bankers Trust Company as Administrative Agent, Calculation Agent, Paying Agent and Oil Agent, Deutsche Bank AG, London Branch, as Oil Purchaser and Deutsche Bank S.A. as Paying Agent in Argentina.*

2.9		Sixth Supplemental Indenture dated as of July 26, 2002, to the Indenture dated as of May 1, 1998, between Petrobras Energía and Citibank, N.A.**

2.10		Ninth Supplemental Trust Deed dated July 31, 2002, to the Trust Deed dated June 29, 1993, between Petrobras Energía S.A and Citicorp Trustee Company Limited.**

2.11		Amended and Restated Indenture, dated August 1, 2002, amending and restating the Indenture dated May 1, 1998, between Petrobras Energía and Citibank, N.A.**

2.12		First Supplemental Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated as of August 1, 2002 filed, among Petrobras Energía S.A., as Issuer, The Bank of New York, as Trustee, Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Short Term Floating Rate Trade Series J Notes due 2003.**

2.13		Second Supplement Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated as of August 1, 2002, among Petrobras Energía, as Issuer, The Bank of New York, as Trustee, Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Long Term Floating Rate Trade Series K Notes due 2007.**

2.14		Third Supplemental Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated as of August 1, 2002, among Petrobras Energía, as Issuer, The Bank of New York, as Trustee, Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Short Term Floating Rate Working Capital Series L Notes due 2003.**

2.15		Fourth Supplemental Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated as of August 1, 2002, among Petrobras Energía, as Issuer, The Bank of New York, as Trustee, Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Long Term Floating Rate Working Capital Series M Notes due 2007. **

2.16		Loan Agreement Number 0088/2005, dated February 21, 2005, between Petrobras Energía, as borrower, and Petrobras International Braspetro BV., as lender (English translation).

2.17		Loan Agreement Number 0087/2005 (English translation), dated February 21, 2005, between Petrobras Energía, as borrower, and Petrobras International Braspetro BV., as lender.

192



4.1		Oil Marketing and Delivery Agreement dated July 17, 2001 between Petrobras Energía as Issuer and Deutsche Bank AG, London Branch, as Oil Purchaser; and Crude Oil Purchase and Delivery Contract dated July 17, 2001 among Petrobras Energía, as Issuer, Deutsche Bank AG, London Branch, as Oil Purchaser and Bankers Trust Company as Oil Agent and as Administrative Agent.*

4.2		Contrato de Cesion dated December 14, 2001, among Petrobras Energía de Venezuela, S.A., Corod Producción, S.A., Petrobras Energía and Banco Latinoamerica de Exportaciones, S.A., with an English summary.*

4.3		Long-Term Incentive Plan for executive officers and senior managers approved in May 2000 together with an English summary attached thereof, filed with the Commission on June 18, 2001 as Exhibit 4(c) to our annual report on Form 20-F, and incorporated herein by reference. **

4.4		Letter of Credit Issuance and Reimbursement Agreement dated October 2, 2002 among Petrobras Energía S.A., the Lenders named therein, the Issuing Banks named therein, and JPMorgan Chase Bank, as Letter of Credit Administrative Agent. **

4.5		Master Settlement and Mutual Release Agreement dated as of April 16, 2004 among Petróleo Brasileiro S.A., Petrobras Energia, Petrobras Hispano Argentina S.A., Enron Corp., Enron Argentina Ciesa Holding S.A., Enron Pipeline Company Argentina S.A., and Podnerosa Assets, L.P.***

8.1		List of “significant subsidiaries” of Petrobras Energía as defined in Rule 1-02(w) of Regulation S-X.

12.1		CEO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated June 30, 2005.

12.2		CFO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated June 30, 2005.

13.1		CEO and CFO Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated June 30, 2005.

*	Incorporated herein by reference to our annual report for the year ended December 31, 2001 filed on June 28, 2002.

**	Incorporated herein by reference to our annual report for the year ended December 31, 2002 filed on June 30, 2003.

***	Incorporated herein by reference to our annual report for the year ended December 31, 2003 filed on June 30, 2004.

Omitted from the exhibits filed with this annual report are certain instruments and agreements with respect to our long-term debt, none of which authorizes securities in a total amount that exceeds 10% of our total assets. We hereby agree to furnish to the SEC copies of any such omitted instruments or agreements as the SEC requests.

193

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.


PETROBRAS ENERGÍA PARTICIPACIONES S.A.

By:		/s/ Alberto Guimarães
Name: Alberto Guimarães
Title: Chief Executive Officer


By:		/s/ Luis Miguel Sas
Name: Luis Miguel Sas
Title: Chief Financial Officer

Date: June 30, 2005

194

INDEX TO FINANCIAL STATEMENTS

PETROBRAS ENERGIA PARTICIPACIONES S.A.


Report of independent registered public accounting firm of Petrobras Energía Participaciones S.A.		F-2
Report of independent registered public accounting firm of Compañia de Inversiones de Energía S.A.		F-4
Report of independent registered public accounting firm of Transportadora de Gas del Sur S.A.		F-6
Report of independent registered public accounting firm of Compañia Inversora en Transmisión Eléctrica Citelec S.A.		F-7
Report of independent registered public accounting firm of Distrilec S.A.		F-9

Consolidated statements of income and loss for the years ended December 31, 2004, 2003 and 2002		F-11
Consolidated balance sheets as of December 31, 2004 and 2003		F-12
Statements of changes in shareholders’ equity for the years ended December 31, 2004, 2003 and 2002		F-13
Consolidated statements of cash flows for the years ended December 31, 2004, 2003 and 2002		F-14
Notes to the consolidated financial statements for the years ended 2004, 2003 and 2002		F-15

F - 1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Petrobras Energía Participaciones S.A.:

We have audited the accompanying consolidated balance sheets of Petrobras Energía Participaciones S.A. (an Argentine Corporation) and its subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of income, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

The financial statements of the affiliates Compañía Inversora en Transmisión Eléctrica Citelec S.A. (Citelec), Compañía de Inversiones de Energía S.A. (CIESA) and Transportadora de Gas del Sur S.A. as of and for the years ended December 31, 2004 and 2003 and the financial statements of the affiliate Distrilec Inversora S.A. (Distrilec) as of and for the year ended December 31, 2003, have been audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for those affiliates, before considering the adjustments mentioned in note 9 to the consolidated financial statements, is based solely on the reports of the other auditors, some of which include an explanatory paragraph for going concern uncertainties as explained in paragraph 6. The Company´s share in the total assets included in the financial statements of CIESA (for 2004 and 2003) and Distrilec (for 2003), which have been proportionally consolidated, represents 16% and 27% of total consolidated assets as of December 31, 2004 and 2003, respectively, and 7% and 16% of net consolidated sales for the years then ended. The Company’s investment in the other affiliates, which have been accounted for using the equity method, is stated at Argentine pesos 278 million and Argentine pesos 310 million, respectively, as of December 31, 2004 and 2003, and the Company´s equity in the affiliates’ net income/loss is stated at Argentine pesos 31 million-loss and Argentine pesos 42 million-income for the years then ended, before considering the adjustments discussed in note 9 to the consolidated financial statements.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.

As described in note 3 to the consolidated financial statements, the Company prepares its financial statements in accordance with the National Securities Commission regulations, which differ from generally accepted accounting principles effective in Argentina, as approved by the Professional Council of Economic Sciences of the City of Buenos Aires, as follows:

The Company has not recognized the effects of the variations in the purchasing power of the Argentine peso from March 1 to September 30, 2003, affecting the financial position as of December 31, 2004 and 2003 and the results of the operations for the years then ended.

F - 2

The Company has not discounted the nominal values of the deferred tax assets and liabilities, affecting the financial position as of December 31, 2004 and 2003 and the results of the operations for each of the three years in the period ended December 31, 2004.

The effects of the matters mentioned above have not been quantified by the Company.

In our opinion, based on our audits and the reports of other auditors referred to in paragraph 2, the financial statements referred to in paragraph 1 present fairly, in all material respects, the consolidated financial position of Petrobras Energía Participaciones S.A. and its subsidiaries at December 31, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with the pertinent regulations of the Business Association Law and the National Securities Commission and, except for the effect of the matters discussed in paragraph 4, with generally accepted accounting principles effective in Argentina, as approved by the Professional Council of Economics Sciences of the City of Buenos Aires, applicable to consolidated financial statements, which differ in certain respects from U.S. generally accepted accounting principles (see notes 22 through 24 to the consolidated financial statements).

The financial statements and the reports of the other auditors of the affiliates Citelec and CIESA as of and for the years ended December 31, 2004 and 2003 state that they have been prepared assuming that such affiliates will continue as going concerns. CIESA, which has been proportionally consolidated, represents assets constituting 15% and 17% as of December 31, 2004 and 2003, respectively, and net sales constituting 7% and 8% for the years then ended of the Company’s respective consolidated totals. The Company’s investment in Citelec, which has been accounted for using the equity method, is stated at Argentine pesos 116 million and Argentine pesos 158 million as of December 31, 2004 and 2003, respectively, and the Company’s equity in the net income/loss of such affiliate is stated at Argentine pesos 42 million-loss and Argentine pesos 87 million-income for the years then ended. As discussed in note 9 to the consolidated financial statements, such affiliates have been negatively impacted by the Argentine Government’s adoption of various economic measures including the de-dollarization of revenue rates, the renegotiation of License and Concession contracts and the devaluation of the Argentine peso. In addition, such affiliates have suspended the payment of their financial debt. These circumstances raise substantial doubt about the affiliates’ ability to continue as going concerns. The affiliates managements’ plans in regard of these matters are also described in note 9 to the consolidated financial statements. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Buenos Aires, Argentina

June 21, 2005

PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.

(Member firm of Ernst & Young Global)

/s/ Enrique C. Grotz

ENRIQUE C. GROTZ

Partner

F - 3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Compañía de Inversiones de Energía S.A.

We have audited the accompanying consolidated balance sheets of Compañía de Inversiones de Energía S.A. and its subsidiaries at December 31, 2004 and 2003, and the related consolidated statements of income, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As indicated in Notes 2.c. and 2.h., the Company has discontinued the restatement of financial statements into constant currency as from March 1, 2003 and has recorded deferred income tax assets and liabilities on a non-discounted basis as required by resolutions issued by the Comisión Nacional de Valores (“CNV”). Since generally accepted accounting principles in Argentina require companies to prepare price-level restated financial statements through September 30, 2003 and to recognize deferred taxes on a discounted basis, the application of the CNV resolutions represent a departure from generally accepted accounting principles in Argentina.

In our opinion, except for the effects of the matters described in the preceding paragraph, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Compañía de Inversiones de Energía S.A. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in Argentina.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As indicated in Notes 6 and 7, the Company and its subsidiary, Transportadora del Gas del Sur S.A. (“TGS”) have been negatively impacted by the deterioration of the Argentine economy, the devaluation of the Argentine peso and the Argentine government’s adoption of various economic measures including the violation of the contractually-agreed License terms of TGS. In view of these circumstances, the Company has suspended the payment of its financial debt since April 22, 2002. These circumstances raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Notes 6 and 7. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

F - 4

Accounting principles generally accepted in Argentina vary in certain significant respects from the accounting principles generally accepted in the United States of America and as allowed by Item 18 to Form 20-F. Information relating to the nature and effect of such differences is presented in Note 12 to the consolidated financial statements.

/s/ Héctor A. López

PRICE WATERHOUSE & CO. S.R.L.

Héctor A. López (Partner)

Buenos Aires, Argentina

June 21, 2005

F - 5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Transportadora de Gas del Sur S.A.

We have audited the accompanying consolidated balance sheets of Transportadora de Gas del Sur S.A. and its subsidiary at December 31, 2004 and 2003, and the related consolidated statements of income, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

As indicated in Notes 2.c and 2.h, the Company has discontinued the restatement of financial statements into constant currency as from March 1, 2003 and has recorded deferred income tax assets and liabilities on a non-discounted basis as required by resolutions issued by the Comisión Nacional de Valores (“CNV”). Since generally accepted accounting principles in Argentina require companies to prepare price-level restated financial statements through September 30, 2003 and to recognize deferred taxes on a discounted basis, the application of the CNV resolutions represent a departure from generally accepted accounting principles in Argentina.

In our opinion, with the exceptions of the matters described in the preceding paragraph, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Transportadora de Gas del Sur S.A. and its subsidiary at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in Argentina.

/s/ Héctor A. López

PRICE WATERHOUSE & CO. S.R.L.

Héctor A. López (Partner)

Buenos Aires, Argentina

February 3, 2005 (except with respect to the

matters discussed in Note 12 to the consolidated

financial statements, which is as of June 17, 2005)

F - 6

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of

Compañía Inversora en Transmisión Eléctrica Citelec S.A.:

We have audited the accompanying consolidated balance sheets of Compañía Inversora en Transmisión Eléctrica Citelec S.A. and its subsidiaries as of December 31, 2004 and 2003, and the related consolidated statements of operations, of changes in shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 3.a. to the consolidated financial statements, in order to comply with regulations of the legal control authorities, the Company discontinued inflation accounting as from March 1, 2003 as well as recognized deferred income tax assets and liabilities on a non-discounted basis. The application of these regulations represent a departure from accounting principles generally accepted in Argentina, which require inflation accounting be discontinued as from October 1, 2003 and the recognition of deferred income tax assets and liabilities on a discounted basis.

In our opinion, except for the effects of not recognizing inflation accounting until September 30, 2003 and not discounting deferred tax assets and liabilities as discussed in the preceding paragraph, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Compañía Inversora en Transmisión Eléctrica Citelec S.A. and its subsidiaries at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in Argentina.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2, during 2002 the Company was negatively impacted by the devaluation of the Argentine Peso and the Argentine Government adoption of various economic measures, including the conversion of dollar-denominated tariffs to Argentine pesos at an exchange rate of Ps.1 = US$ 1. As a result of these circumstances, the Company did not comply with certain restrictive covenants contained in its debt agreements and suspended the payment of its financial debts. In February, 2005 the Company published an exchange offer, which was accepted by 98.8% of the creditors in April, 2005. At present the Company will carry out the exchange of its outstanding financial indebtedness. These circumstances raise substantial doubt about the Company’s ability to continue as a going concern. Management plans in regard to these matters are also described in Note 2. The accompanying consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

F - 7

Accounting principles generally accepted in Argentina vary in certain significant respects from accounting principles generally accepted in the United States of America and as allowed by Item 17 to Form 20-F. Information relating to the nature and effect of such differences is presented in Note 15 to the consolidated financial statements.

/s/ Miguel A. Urus

PRICE WATERHOUSE & CO. S.R.L.

Miguel A. Urus (Partner)

Buenos Aires, Argentina

June 21, 2005

F - 8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

(English translation of the report originally issued in Spanish)

To the Chairman and Directors of

Distrilec Inversora S.A.

1.	We have audited:

The accompanying balance sheet of Distrilec Inversora S.A. as of December 31, 2003, and the related statements of income, changes in shareholders’ equity and cash flows for the year then ended.

The accompanying consolidated balance sheet of Distrilec Inversora S.A. and its subsidiary Empresa Distribuidora Sur Sociedad Anónima (EDESUR S.A.) as of December 31, 2003 and the related consolidated statements of income and cash flows for the year then ended, included in Chart I as supplementary accounting information.

These financial statements are the responsibility of the Company’s Board of Directors. Our responsibility is to express an opinion on these financial statements based on our audit conducted with the scope described in paragraph 2.

We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements, taken as a whole, are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by Company’s Management, as well as evaluating the overall financial statement presentation.

3.	In our opinion:

The financial statements mentioned in paragraph 1.a) present fairly, in all material respects, the financial position of Distrilec Inversora S.A. as of December 31, 2003, the results of its operations, the evolution of its shareholders´ equity and its cash flows for the year then ended, in accordance with accounting principles generally accepted in Argentina approved by the Professional Council of Economic Sciences of the City of Buenos Aires.

F - 9

The financial statements mentioned in paragraph 1.b) present fairly, in all material respects, the consolidated financial position of Distrilec Inversora S.A. and its subsidiary Empresa Distribuidora Sur Sociedad Anónima (EDESUR S.A.) as of December 31, 2003, the consolidated results of their operations and their consolidated cash flows for the year then ended, in accordance with accounting principles generally accepted in Argentina approved by the Professional Council of Economic Sciences of the City of Buenos Aires.

The financial statements as of and for the year ended December 31, 2002, presented for comparative purposes, were audited by other independent auditors who issued their audit report with an unqualified opinion on February 7, 2003. The information as of and for the year ended December 31, 2002 has been modified by the Company’s Management in order to comply with the changes in the accounting principles generally accepted in Argentina mentioned in note 2.II to the stand alone financial statements and has been restated in constant currency up to February 2003.

Accounting principles generally accepted in Argentina vary in certain significant respects from accounting principles generally accepted in the United States of America. Application of accounting principles generally accepted in the United States of America would have affected the determination of the shareholders´ equity as of December 31, 2003 and the results of operations for the year then ended to the extent summarized in note 11 to the consolidated financial statements. Certain additional information required by the Securities and Exchange Commission (SEC), prepared in conformity with accounting principles generally accepted in the United States of America, was included in note 12 to the consolidated financial statements.

Buenos Aires, February 9, 2004.

DELOITTE & Co. S.R.L.

/s/ Carlos A. Lloveras

CARLOS A. LLOVERAS

Partner

F - 10

PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(Stated in millions of Argentine pesos - See Note 2.c)


	2004		2003		2002
Net sales	6,974		5,494		5,106
Costs of sales (Note 27.c)	(4,210	)	(3,386	)	(3,284	)

Gross profit	2,764		2,108		1,822
Administrative and selling expenses (Note 27.e)	(640	)	(559	)	(609	)
Exploration expenses (Note 27.e)	(89	)	(196	)	(58	)
Other operating expenses, net (Note 18.c)	(304	)	(121	)	(28	)

Operating income	1,731		1,232		1,127
Equity in earnings (loss) of affiliates (Note 9.b)	76		163		(638	)

Financial income (expense) and holding gains (losses)
Generated by assets:
Interest	50		65		88
Exchange difference	54		(155	)	1,986
Gain from remeasurement and translation	—		—		3,742
Loss due to exposure to inflation	—		(27	)	(2,967	)
Holding gains (losses)	28		9		5
Holding gains and income from sale of listed shares and government securities	104		98		(15	)
Other financial (expenses) income, net	(22	)	1		17

	214		(9	)	2,856
Generated by liabilities:
Interest	(599	)	(623	)	(882	)
Exchange difference	(92	)	554		(10,402	)
Loss from remeasurement and translation	—		—		(2,242	)
Gain due to exposure to inflation	—		67		9,472
Derivatives	(688	)	(294	)	(524	)
Other financial expenses, net	(96	)	(112	)	(105	)

	(1,475	)	(408	)	(4,683	)
Other expenses, net (Note 18.d)	(27	)	(421	)	(187	)

Income before income tax and minority interest in subsidiaries	519		557		(1,525	)

Income tax provision (Note 13)	198		(18	)	(82	)

Minority interest in subsidiaries	(39	)	(158	)	28

Net income (loss)	678		381		(1,579	)

Earnings per share - Stated in Argentine pesos	0.319		0.179		(0.744	)

The accompanying notes are an integral part of these consolidated financial statements.

F - 11

PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2004 AND 2003

(Stated in millions of Argentine pesos - See Note 2.c)


	2004		2003
CURRENT ASSETS
Cash	128		153
Investments (Note 9.a)	790		802
Trade receivables	1,210		886
Other receivables (Note 18.a)	629		861
Inventories (Note 8)	487		319
Other assets	1		3

Total current assets	3,245		3,024

NON-CURRENT ASSETS
Trade receivables	39		36
Other receivables (Note 18.a)	648		131
Inventories (Note 8)	56		61
Investments (Note 9.a)	1,323		1,284
Property, plant and equipment (Note 27.a)	11,280		11,238
Other assets	19		43

Total non-current assets	13,365		12,793

Total assets	16,610		15,817

CURRENT LIABILITIES
Accounts payable	893		741
Short-term debt (Note 12)	1,652		3,204
Payroll and social security taxes	90		93
Taxes payable	163		172
Reserves (Note 14)	31		44
Other liabilities (Note 18.b)	655		379

Total current liabilities	3,484		4,633

NON-CURRENT LIABILITIES
Accounts payable	26		7
Long-term debt (Note 12)	6,248		5,098
Payroll and social security taxes	12		6
Taxes payable	141		11
Other liabilities (Note 18.b)	160		262
Reserves (Note 14)	71		75

Total non-current liabilities	6,658		5,459

Total liabilities	10,142		10,092

TRANSITORY DIFFERENCES
Measurement of derivative financial instruments designated as effective hedge	(2	)	(18	)
Foreign currency translation	(47	)	(56	)

Total transitory differences	(49	)	(74	)


MINORITY INTEREST IN SUBSIDIARIES	1,006		966


SHAREHOLDERS’ EQUITY (Per respective statements)	5,511		4,833

	16,610		15,817

The accompanying notes are an integral part of these consolidated financial statements.

F - 12

PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL STATMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(Stated in millions of Argentine pesos - See Note 2.c)


	2004									2003		2002
	Capital stok			retained earnings
	Capital stok	Adjustment to capital stock	Additional paid- in capital	Legal reserve	Unapropriated retained earnings		Treasury stock (a)		Total	Total		Total
Balances at beginning of the year	2,132	2,554	160	—	20		(33	)	4,833	4,813		6,014
Change in balances at beginning of the year due to change in accounting method (Note 3)	—	—	—	—	—		—		—	(361	)	17

Adjusted balances at beginning of the year	2,132	2,554	160	—	20		(33	)	4,833	4,452		6,031

Special Shareholders’ Meeting decision of March 19, 2004:
- Legal Reserve	—	—	—	20	(20	)	—		—	—		—
Net income (loss)	—	—	—	—	678		—		678	381		(1,579	)

Balances at end of the year	2,132	2,554	160	20	678		(33	)	5,511	4,833		4,452

(a)	See Note 4.n).

The accompanying notes are an integral part of these consolidated financial statements.

F - 13

PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(Stated in millions of Argentine pesos - See Note 2.c)


	2004		2003		2002
Cash provided by (used in) operations:
Net income	678		381		(1,579	)

Reconciliation to net cash provided by (used in) operating activities:
Minority interest in subsidiaries	39		158		(28	)
Equity in earnings of affiliates (Note 9.b)	(76	)	(163	)	638
Financial income (expense), net	45		(585	)	140
Dividends collected (Note 9.c)	84		26		20
Depreciation of property, plant and equipment	1,058		1,016		1,051
Debt to exploitation partners in Venezuela allowance	15		27		42
Impairment of assets	12		346		117
Impairment of unproved oil and gas properties	80		180		17
Income (loss) from sale of oil and gas areas and participation in joint ventures	—		27		(41	)
Debt restructuring	—		—		17
Income tax provision	(198	)	18		82
Income tax paid	(66	)	(48	)	(27	)
Accrued interest	585		598		878
Interest paid	(627	)	(488	)	(814	)
Other	(10	)	(7	)	87

Changes in assets and liabilities:
Trade receivables	(328	)	(115	)	208
Other receivables	18		(82	)	44
Inventories	(151	)	(12	)	(70	)
Other assets	45		73		—
Accounts payable	34		(66	)	(16	)
Payroll and social security taxes	(26	)	17		(34	)
Taxes payable	101		(9	)	75
Other liabilities	151		61		(97	)

Net cash provided by operations	1,463		1,353		710

Cash provided by (used in) investing activities:
Acquisition of property, plant and equipment and interest in companies and oil and gas areas	(1,031	)	(829	)	(674	)
Net decrease in investments other than cash and cash equivalents	(11	)	(97	)	32
Contributions and advances to unconsolidated affiliates	(6	)	(12	)	(127	)
Reimbursement of contributions	9		—		—
Sales of investments	—		20		593
Other	—		3		(6	)

Net cash used in investing activities	(1,039	)	(915	)	(182	)

Cash provided by (used in) financing activities:
Net increase (decrease) in short term debt	79		(196	)	(193	)
Payments of long-term debt	(1,241	)	(646	)	(1,762	)
Increase in long-term debt from related companies	150		—		—
Increase in long-term debt	580		591		130
Cash dividends paid	—		—		(2	)

Net cash used in financing activities	(432	)	(251	)	(1,827	)

Effect of exchange rate change and inflation on cash	(6	)	(88	)	755

Increase in cash	(8	)	99		(544	)
Cash and cash equivalents at beginning	927		725		1,269
Cash and cash equivalents at beginning from proportional interest in CIESA	—		103		—

Cash and cash equivalents at beginning	927		828		1,269

Cash and cash equivalents at end	913		927		725

(a)	Cash and cash equivalents include highly liquid, temporary cash investments with original maturities of three months or less when purchased.

The accompanying notes are an integral part of these consolidated financial statements.

F - 14

PETROBRAS ENERGÍA PARTICIPACIONES S.A.

AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

(Amounts stated in millions of Argentine pesos — see Note 2.c, unless otherwise indicated)

1. Business of the Company, change of corporate name and business reorganization

Petrobras Energía Participaciones S.A. (hereinafter “Petrobras Participaciones” or “The Company”), holds 98.21% of Petrobras Energía S.A. (hereinafter “Petrobras Energía”), an integrated energy company, focused in oil and gas exploration and production, refining, petrochemical activities, generation, transmission and distribution of electricity and sale and transmission of hydrocarbons. It has businesses in Argentina, Bolivia, Brazil, Ecuador, Peru and Venezuela. Petrobras Energía has a significant share of the regional energy market.

The Company’s Special and Regular Shareholders’ Meeting held on April 4, 2003, approved the change of corporate name from Perez Companc S.A. to Petrobras Energía Participaciones S.A. This change in corporate name remained subject to the Comisión Nacional de Defensa de la Competencia (CNDC, Argentine anti-trust authorties) approving the transaction whereby Petrobras Participaciones SL purchased stock representing a majority interest in the Company.

In addition, the Regular and Special Shareholders’ Meeting of Petrobras Energía held on April 4, 2003, approved the change of corporate name from Pecom Energia S.A. to Petrobras Energía S.A, also subject to the approval mentioned above.

The CNDC approved the transaction on May 13, 2003. Pursuant to this resolution, Petrobras Energía undertook to divest of all of its equity interest in Transener S.A., in accordance with Law No. 24,065 that provides the Electric Power Regulatory Framework; such process is subject to supervision by the Argentine Regulatory Entity of Electricity (“Ente Nacional Regulador de la Electricidad” or “ENRE”) and the approval of the Argentine Secretary of Energy. (See Note 26.4))

On July 4, 2003, the IGJ (regulatory agency of business associations) granted its approval for and registered both changes of corporate name, which were also approved by the Argentine Security Commission (“Comisión Nacional de Valores” or “CNV”) on June 9, 2003.

On November 12, 2004, the Boards of Directors of Petrobras Energía, EG3 S.A. (hereinafter, “EG3”) and Petrobras Argentina S.A. (PAR) and the Management of Petrolera Santa Fe S.R.L. (hereinafter, “PSF”), in their respective meetings, approved the preliminary agreement for the merger of EG3, PAR, and PSF with and into Petrobras Energía S.A., with the former companies being dissolved without liquidation.

The abovementioned merger was approved by the Special Shareholders’ Meetings of Petrobras Energía, EG3, PAR and by the Special Partners´ Meeting of PSF held on January 21, 2005.

As the result of the merger, Petróleo Brasileiro S.A. — Petrobras (hereinafter “Petrobras”), which owns a 99.6% equity interest in EG3 and 100% equity interest in PAR and PSF through its subsidiary Petrobras Participaciones SL, will receive — through such subsidiary — 230,194,137 new shares of class B stock in Petrobras Energía, with a nominal value of ARS 1 each and entitled to one vote per share, representing 22.8% of capital stock. Accordingly, the new capital stock of Petrobras Energía will be set at 1,009,618,410.

Once the merger has been registered with the Public Registry of Commerce, the equity interest of Petrobras Participaciones in Petrobras Energía will be 75.8%. Given that Petrobras has a 58.62% equity interest in Petrobras Participaciones, Petrobras will indirectly hold a 67.2% equity interest in Petrobras Energía.

The effective merger date was set as January 1, 2005, as from when all assets, liabilities, rights and obligations of the absorbed companies shall be considered incorporated into Petrobras Energía.

On March 3, 2005, the final merger agreement was subscribed and authorization for public offering of the Petrobras Energía shares, which will be issued upon the swap under the merger, was formally requested from

F - 15

the CNV (Argentine Securities Commission) on March 4, 2005. As of the issuance date of the accompanying financial statements, the CNV’s approval was still pending as well as the registration with the Public Registry of Commerce.

As December 31, 2004, the non-consolidated summarized financial situation of Petrobras Energía before and after the merger would be as follows:


	Before Merging		Incorporated Companies ‘(1)	Adjudtments end eliminations		After Merging
Current Assets	2,119		670	(287	)	2,502
Non -Curent Assets	10,197		1,276	—		11,473
Current Liabilities	2,240		688	(287	)	2,641
Non -Current Liabilities	4,497		24	—		4,521
Transitory Translation Differences	(49	)	—	—		(49	)

Shareholder’s Equity	5,628		1,234	—		6,862

‘(1)	Eg3, PAR and PSF.

Corporate reorganization accounting effects

Petrobras Energía and the Company will book the effects of the corporate reorganization indicated in Note 1 in accordance with the pooling-of-interest method described in Technical Resolution No. 18 of the FACPCE (Argentine Federation of Professional Councils in Economic Sciencies).

Although Argentine professional accounting standards refer to business combinations, they do not mention the treatment applicable to the merger between entities under common control. Given the lack of a particular regulation, FACPCE Technical Resolution No. 17, as amended by Resolution C.D. No. 243/01 of the CPCECABA (Professional Council in Economic Sciences of the City of Buenos Aires), establishes that the situations not regulated will be resolved pursuant to generally applicable international standards, taking into account especially the market and the standards regulating the issuer of financial statements.

In this regard, taking into account that the Company’s “Class B” shares are listed on the New York Stock Exchange, the accounting standards effective for such market (Statement of Financial Accounting Standard No 141 – SFAS 141) set forth that the merger between entities under common control should be accounted for using the pooling-of-interest method.

According to the method, the assets, liabilities and shareholders’ equity of the transferring entities are recognized in the combined entity based on their carrying amounts, as of the effective merger date.

Accordingly, as of December 31, 2005, Petrobras Participaciones´s consolidated financial statements for all periods prior to the merger will be restated to reflect the results of operations, financial position and cash flows as though, Eg3, PAR and PSF had always been a part of Petrobras Energía.

2. Basis of presentation

Petrobras Energía Participaciones S.A. consolidated financial statements have been prepared in accordance with the regulations of the CNV and except for the matters described in Note 3, with Generally Accounting Accepted Principles effective in Argentina, as approved by the CPCECABA applicable to consolidated financial statements (“Argentine GAAP”).

Certain disclosures related to formal legal requirements for reporting in Argentina have been omitted for purposes of these consolidated financial statements, since they are not required for the United States Securities and Exchange Commission (“SEC”) reporting purposes.

F - 16

The preparation of financial statements in conformity with Argentine GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. While it is believed that such estimates are reasonable, actual results could differ from those estimates.

a) Basis of consolidation

In accordance with the procedure set forth in Technical Resolution No. 21 of the FACPCE, Petrobras Participaciones has consolidated line by line its financial statements with the financial statements of the companies over which Petrobras Participaciones exercises control or joint control. Joint control exists where all the shareholders, or only the shareholders owning a majority of votes, have resolved, on the basis of written agreements, to share the power to define and establish a company’s operating and financial policies.

In the consolidation of controlled companies, the amount of the investment in such subsidiaries and the interest in their income (loss) and cash flows are replaced by the aggregate assets, liabilities, income (loss) and cash flow of such subsidiaries, reflecting separately all minority interests in the subsidiaries. Related party receivables, payables and transactions within the consolidated group are eliminated. The unrealized intercompany gains (losses) from transactions within the consolidated have been completely eliminated.

In the consolidation of companies over which the Company exercises joint control, the amount of the investment in the subsidiary under joint control and the interest in its income (loss) and cash flows are replaced by the Company’s proportional interest in the subsidiary’s assets, liabilities, income (loss) and cash flows. Related party receivables, payables and transactions within the consolidated group and companies under joint control have been eliminated in the consolidation pro rata to the shareholding of the company.

The data about the companies over which the Company exercises control, joint control and significant influence are disclosed in Note 27.f).

The companies under joint control are Distrilec Inversora S.A., Compañía de Inversiones de Energía S.A., and Citelec S.A. The Company has not consolidated proportionately on a line-by-line basis the assets, liabilities, income (loss) and cash flows of the interest in Citelec S.A. since Petrobras Energía agreed to divest such interest in connection with the transfer of 58.62% of the shares of Petrobras Participaciones to Petrobras (see Notes 21, 1 and 26.4). The Company did proportionally consolidate on a line by line basis the assets, liabilities, income (loss) of CIESA as of the years ended December 31, 2004 and December 31, 2003. For the year ended December 31, 2002, the Company did not proportionally consolidate on a line-by-line basis the assets, liabilities, income (loss) and cash flows of CIESA since, as of that date, such equity interest was stated at zero value (See Note 9.III)

b) Foreing Currency translation

The Company applies the translation method established by Technical Resolution no. 18 of the FACPCE for the translation of financial statements of foreign subsidiaries, affiliates, branches and joint ventures. This method is applied on a prospective basis as from January 1, 2003 in accordance with the transition standards.

In the opinion of the Company’s Management, the transactions carried out abroad have been classified as “not integrated” to the Company’s transactions in Argentina. Such transactions are not an extension of the Company’s transactions due to, among others, the following reasons:

transactions with the Company are not a high proportion of the entity’s activities abroad;

activities of foreign business are partially financed with funds from their own transactions and with local loans;

sales, workforce, materials and other costs of goods and services related to transactions abroad are settled mainly in a currency other than the currency of the investor’s financial statements; and

Company’s cash flows are independent from the day-to-day activities of the foreign business and are not directly affected by the size or frequency of the activities of foreign business.

F - 17

Upon applying the translation method, first the foreign transaction are remeasured into US dollars (functional currency for such transactions), as follows:

•

Assets and liabilities stated at current value are converted at the closing exchange rates.

•

Assets and liabilities measured at historical values and the income (loss) are converted at historical exchange rates.

•

Remeasurement results are recognized in the results for the fiscal year.

After the transactions are remeasured into US dollars, they are translated into Argentine pesos as follows:

•

Assets and liabilities are translated by using the closing exchange rate.

•

Income (loss) is translated at the historical exchange rates.

The translation effect arising from the translation of the financial statements is disclosed in the “Transitory differences - foreign currency translation” account for the years ended on December 31, 2004 and 2003, and in the “Statement of Income” for the year ended on December 31, 2002, in accordance with the transition standards, affecting the comparability between these financial statements.

The above also applies to exchange differences arising from liabilities in foreign currency assumed to hedge the net investment in the foreign entity.

c) Restatement in constant currency

The Company presents its consolidated financial statements in constant money following the restatement method established by Technical Resolution No. 6 of the FACPCE and in accordance with CNV General Resolutions No. 415 and 441.

Under such method, the consolidated financial statements integrally recognize the effects of the changes in the purchasing power of Argentine peso through August 31, 1995. As from September 1, 1995, under CNV General Resolution No. 272, the Company interrupted the use of such method maintaining the restatements made through such date. This method was accepted by professional accounting standards through December 31, 2001.

On March 6, 2002, the CPCECABA (Professional Council in Economic Sciences of the City of Buenos Aires) approved Resolution MD No. 3/2002 providing, among other things, the reinstatement of the adjustment-for-inflation method for the interim periods or years ended as from December 31, 2002, allowing for the accounting measurements restated based on the change in the purchasing power of the peso through the interruption of adjustments, such as those whose original date is within the stability period, to be stated in pesos as of December 2001. Through General Resolution No. 415 dated July 25, 2002, the CNV required that the information related to the financial statements to be filed after the date on which the regulation became effective be disclosed adjusted for inflation.

The restatement in constant pesos method is applied to the accounting cost values immediately preceding the capitalization of the exchange differences mentioned in note 4.p), which represent an anticipation of the effects of variances in the purchasing power of the Argentine peso, which will be subsequently absorbed by the restatement in constant pesos of the assets indicated in such note.

F - 18

On March 25, 2003, the Executive Branch of Government issued Executive Order No. 664 establishing that the financial statements for years ending as from such date be filed in nominal currency. Consequently, and under CNV Resolution No. 441, the Company no longer applied inflation accounting as from March 1, 2003. This method was not in accordance with professional accounting standads effective in the city of Buenos Aires. The CPCECABA, thorugh Resolution N° 287/03 discontinued, the application of the restatement method as from October 1, 2003.

d) Accounting for the transactions of oil and gas exploration and production joint ventures and foreign branches

The Company´s interests in oil and gas involve exploration and production joint ventures which have been proportionally consolidated. Under this method, the Company recognizes its proportionate interest in the joint ventures’ assets, liabilities, revenues, costs and expenses on a line-by-line basis in each account of its financial statements. Foreign branches have been fully consolidated.

e) Financial statements used

The financial statements of the subsidiaries and companies under joint control as of December 31, 2004, 2003 and 2002 used for consolidation purposes were adapted to apply the Company´s valuation methods on a consistent basis and to reflect a time period consistent with the financial statements of the Company.

3. Accounting standards

These financial statements have been prepared in accordance with professional Argentine GAAP. and the applicable CNV regulations, which differ from Argentine GAAP as follows:

a) valuation of deferred tax at nominal value without applying any discounted values as required by CNV General Resolution No. 434.

b) the date of discontinuance of the restatement in constant money provided for in FACPCE Technical Resolution No. 6, as described in note 2.c).

c) the special treatment enabling the financial costs of payables to finance the investment in large infrastructure works and accrued after the total or partial launch of the facilities (as provided for in Section 4 of Resolution CD No. 243/01) may not be applied.

d) the possibility of capitalizing the financial costs of financing with the Company’s own capital may not be applied.

As from January 1, 2003, FACPCE Technical Resolutions Nos. 16, 17, 18, 19, and 20, approved as amended by the CPCECABA and adopted by the CNV through its General Resolution No. 434. These new technical resolutions are a consequence of the process whereby Argentine professional accounting standards are being made consistent with the international accounting standards issued by the International Accounting Standards Committee (IASC); in addition, they provide clarification for certain issues which had not been provided for in past regulations.

The main changes included in the technical resolutions, that have resulted in significant effects on the Company’s financial statements, are: (i) guidelines regarding the recognition, measurement, and disclosure of derivatives and hedging transactions; (ii) amendment of the method to translate the financial statements of foreign subsidiaries stated in foreign currency; (iii) the mandatory requirement to apply the deferred tax method to recognize income tax; (iv) measurement of asset and liability amounts on discounted bases; (v) changes in the frequency and method to compare assets with the recoverable values thereof; (vi) incorporation of guidelines to assess whether certain transactions including financial instruments, irrevocable capital contributions and preferred stock, among others, should be classified as liabilities or shareholders’ equity; (vii) incorporation of new disclosure requirements including proportional consolidation of companies under joint control, change in the disclosure of direct sales revenues, information by segment, earnings per share, and the comparative information to be disclosed.; viii) disbursements for maintenance costs, which may be allocated to the income for the period when they are made or capitalized, as appropriate.

F - 19

The Company amended the method used to recognize future estimated abandonment costs in oil & gas areas. Consistently with Statement of Financial Accounting Standards (“SFAS”) N° 143 guidelines, such costs discounted at a rate estimated upon initial measurement are capitalized together with the assets from which they originate and are depreciated by the production units method. In addition, a liability is recognized on such account at the estimated value of the amounts payable discounted at a rate estimated in its initial measurement.

Adopting new accounting standards has resulted in income in the amount of (74) and (378) for the years ended December 31, 2003 and 2002, respectively, and a 361 reduction to retained earnings at the beginning of the fiscal year ended on December 31, 2003, as disclosed below:


	Gains (losses)				Retained earnings as of December 31,
	Income for				Retained earnings as of December 31,
	2003		2002		2002
Derivatives financial instruments (1)	(133	)	(334	)	(417	)
Foreign currency translation (2)	55		—		—
Future abandonment costs (3)	—		15		45
Labor costs	18		19		(24	)
Effects on affiliates	—		18		(8	)
Maintenance expenses (4)	—		—		16
Discounted effect of nominal values of assets and liabilities (5)	13		(4	)	(4	)
Deferred tax (6)	(27	)	(92	)	31

	(74	)	(378	)	(361	)

(1)	Previously, the fair value of such instruments was not booked but the related income (loss) was recorded in income when losses and/or gains occurred as a result of the hedged position. Premiums paid were capitalized and amortized over the term of the option.

(2)	Previously, gains (losses) on foreign currency translation were charged to income.

(3)	Previously, these costs were accrued at nominal value and charged as a higher depreciation using the production units method.

(4)	Previously, maintenance costs were accrued.

(5)	Calculated as provided for in CPCECABA Resolution MD No. 32/2002.

(6)	Previously, the Company estimated income tax applying the effective rate on taxable income for the period regardless of any temporary differences between book and taxable income.

As established in the new accounting standards, there are certain transition regulations enabling to apply prospectively the valuation and disclosure method incorporated thereto. The transition standards applied by the Company, affecting the comparability of the financial statements, are:

a) The new methods for translating the financial statements of foreign subsidiaries stated in foreign currency were not applied retroactively.

b) The beginning balances resulting from the recognition, measurement, and booking of derivative financial instruments qualified as effective hedge were not corrected.

4. Valuation methods

The main valuation methods used in the preparation of the consolidated financial statements have been as follows:

a) Accounts denominated in foreign currency:

At the prevailing exchange rates at the end of each fiscal year, including accrued interest, if applicable. The summary of accounts denominated in foreign currency is disclosed in Note 27.d).

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b) Inventories:

Crude oil stock: at reproduction cost.

Materials: of high-turnover, at replacement cost; of low-turnover, at the last purchase price, restated in constant money, according to Note 2.c).

Work in progress and finished products relating to refining and petrochemical activities: at replacement or reproduction cost, as applicable, applied proportionally in the case of goods in process according to the degree of process of the related good.

Stock of liquid petroleum gases (NGL) in the gas pipeline system in excess of the line pack and held by third parties and stock of NGL obtained from the natural gas processing: at replacement or reproduction cost, as appropriate.

The carrying amount of these assets does not exceed their recoverable value.

c) Investments:

Listed shares and government securities:

- Available for sale: at market value at the end of each year, less the estimated selling expenses. Any gain or loss due to market fluctuations is reflected currently in income in the “Financial income (expense) and holding gains (losses)” account.

- Held to maturity: at original value increased based on its internal rate of return at acquisition. Interest gain is credited to income on an accrual basis. As of December 31, 2004, the Company maintained investments with market value of 5 and its book value of 6.

Certificates of deposit and loans to affiliates over which significant influence is exercised: at face value plus accrued interest.

Unlisted Government securities: at the original value increased based on the internal rate of return at acquisition limited by the recoverable value. In this respect, as of December 31, 2004, Petrobras Energía’s holdings of Bonos Patrióticos, for a nominal value of US$ 15.5 million, have been reduced to fair market value, in view of the decision to include such holdings in the debt restructuring offer made by the government with respect to defaulted government debt.

Tax credit certificates: at the estimated value based on the application of the certificates to the payment of federal taxes.

Investments in mutual funds: at market prices at the end of each year.

Shares — Participation in affiliates, in which the Company exercises significant influence:

By the equity method. For the determination of the Company’s equity in affiliates over which significance influence is excercised, the Company has used financial statements from affiliates, or the best available financial information.

For the determination of the Company’s equity in affiliates, consideration has been given to the adjustments to adapt the valuation methods of some affiliates to those of the Company, irrevocable contributions made by others, elimination of reciprocal investments, intercompany profits and losses, the difference between acquisition cost and book value of affiliates at the time of the acquisition and the holding of preferred stock and dividends by the affiliates. Cash dividends from affiliates approved by shareholders’ meetings held prior to the date of issuance of these financial statements, which are placed at the shareholders’ disposal within a term not exceeding one year are deducted from the value of the investment and included in current investments.

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Other shares – interests in affiliates in which the Company does not exercise significant influence: at acquisition cost restated in constant currency as shown in Note 2.c).

d) Trade receivables and payables:

Trade receivables and payables have been valued at the spot cash estimated at the time of the transaction, plus accrued financial components, net of payments collected. As of the date of the balance sheet, receivables and payables should be presented to reflect their principal amount plus accrued implicit and/or explicit financial components. The principal amount is equal to the cash price, if available, or the nominal price less implicit interest calculated at the prevailing interest rate on the date of the original transaction. No implicit financial components inherent in our trade receivables and payables, which generally have terms that do not exceed 90 days, were identified.

Trade receivables include billed uncollected services and services rendered but not yet billed as of each year. The services rendered but not yet billed were estimated on the basis of series of actual historical data billings subsequent to the end of each year. The total amount of receivables is net of an allowance for doubtful accounts, which is based on estimates of collection carried out by the subsidiary.

e) Financial receivables and payables:

Financial receivables and payables have been valued according to the money paid and collected, respectively, net of transaction costs, plus accrued financial gains (losses) on the basis of the explicit or estimated rate at such time.

f) Other receivables and payables:

Other receivables and payables have been valued on the basis of the best possible estimate of the amount to be collected and paid, respectively, discounted in the relevant cases, using the estimated rate at the time of initial measurement, except for the deferred tax assets and liabilities. As established by CNV regulations, deferred tax assets and liabilities have not been discounted. This criterion does not comply with accounting standards effective in the City of Buenos Aires, which required that such balances have to be discounted.

g) Property, plant & equipment:

Property, plant & equipment, except as indicated below, have been valued at acquisition cost restated in constant currency, according to Note 2.c), less related accumulated depreciation. Property, plant & equipment related to foreign operations were converted into US dollars since that is the functional currency for such operations, at its historical exchange rates, and they have been translated into Argentine pesos at the exchange rate effective as of closing in accordance with the method for converting foreign operations described in note 2.b).

The Company uses the successful efforts method of accounting for its oil and gas exploration and production activities. This method involves the capitalization of: (i) the cost of acquiring properties in oil and gas production areas; (ii) the cost of drilling and equipping exploratory wells that result in the discovery of reserves; (iii) the cost of drilling and equipping development wells, and (iv) the estimated future costs of abandonment and restoration.

Exploration costs, excluding exploratory well costs, are charged to expense during the year in which they are incurred. Drilling costs of exploratory wells are capitalized until determination is made on whether the drilling resulted in proved reserves that justify commercial developement. If such reserves are not found, such drilling costs are charged to expense. Occasionally, an exploratory well may determine the existence of oil and gas reserves but they cannot be classified as proved when drilling is completed. In those cases, one of the following would be applicable: (I) if the well finds reserves in an area requiring major capital expenditures before production may start, classification of such reserves as proved is dependent upon whether any additional reserves are found justifying the abovementioned investment. In this case, the cost of the exploratory well continues capitalized as long as it meets the following two conditions: (a) reserves found

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are sufficient to justify completion of the well to a producer well if the capital investment is made, and (b) the drilling of additional exploratory wells is in progress or firmly planned for the near future. Otherwise, drilling costs are charged to expense; (II) if the reserves are not classified as proved for any other reason, drilling costs of exploratory wells should not remain capitalized for a period exceeding one year after the completion of the drilling. If after one year no reserves are classified as proved, exploratory well costs should be charged to expense. As December 31, 2004, 2003 and 2002, the Company has capitalized costs of exploratory wells amounting to 3, 95 and 218, respectively.

Effective April 2005, through the interpretation of FASB Staff Position 19-1, certain criteria under SFAS No.19 were modified. An exploratory well may be determined to have found oil and gas reserves, but those reserves cannot be classified as proved when drilling is completed. In those cases, the capitalized drilling costs shall continue to be capitalized if the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the economic and operating viability of the project.

The Company depreciates productive wells, as well as machinery, furniture and fixtures and camps in the production areas according to the units of production method, by applying the ratio of oil and gas produced to the proved developed oil and gas reserves. The acquisition cost of property with proved reserves is depreciated by applying the ratio of oil and gas produced to estimated proved oil and gas reserves. Acquisition costs related to properties with unproved reserves is valued at cost and its recoverability is assessed from time to time on the base of geological and engineering estimates of possible and probable reserves that are expected to be proved over the life of the concession.

Estimated future restoration and abandonment well costs in hydrocarbons areas discounted at an estimated rate at the time of their initial measurement, are included in the value at which the assets that gave rise to such costs are capitalized, and are depreciated using the units of production method. Additionally, a liability is recognized for such costs at the estimated value of the amount payable, discounted at an estimated rate at the time of its initial measurement.

The Company estimates its reserves at least once a year. As of December 31, 2004, 2003 and 2002, total oil and gas reserves were audited by Gaffney, Cline & Associates Inc., independent international technical and management advisors.

The Company ‘s remaining property, plant & equipment are depreciated by the straight-line method based on their existing exploitation concession terms and their estimated useful lives as the case may be.

The cost of works in progress, whose construction will extend over time, includes the computation of financial costs accrued on loans granted by third parties, if applicable, and the costs related to putting the facilities into operation that are considered net of any income obtained from the sale of commercially valuable production during such process.

On the sale or retirement of a complete unit of a proved property, the cost and related accumulated depreciation, depletion, and amortization are eliminated from the property accounts, and the resultant gain or loss is recognized.

The value of CIESA’s property, plant and equipment transferred under the Gas del Estado privatization process (that occurred in 1992) was determined on the basis of the price actually paid for the 70% equity interest in Transportadora de Gas del Sur S.A. (“TGS”). Such price served as the basis for determining the value of the entire capital stock, to which was added the value of the initial debts assumed under the Transfer Agreement, in order to determine the initial value of property, plant and equipment. Such value, translated at the exchange rate effective at the date of the Transfer Agreement, has been restated into constant pesos as explained in Note 2.c).

The value of property, plant & equipment, measured for each identifiable business unit or line of business, i.e. producing an independent stream of revenues for the Company, does not exceed their recoverable value.

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h) Comparison with recoverable values

Company Management assesses the value of property, plant and equipment items whenever there occur events or changes in circumstances (including significant decreases in the market value of inventories, in the prices of the main products sold by the Company or in oil and gas reserves, as well as changes in the regulatory framework for Company activities, significant increases in operating expenses, or evidence of obsolescence or physical damage) that could indicate that the value of an asset or of a group of assets might not be recoverable on the basis of undiscounted net cash flows. The Company assesses the recoverability of such assets (including oil and gas areas) on the basis of a variety of indicators, including operating results, business plans, economic projections and expected cash flows. The net book value of an asset is adjusted to fair value if the expected undiscounted cash flows are lower than the book value of the asset in question. Fair values are based on premises related to the amounts and the timeframe of cash flows assuming discount rates that reflect different degrees of perceived risk.

i) Environmental costs:

The costs incurred to limit, neutralize or prevent environmental pollution are only capitalized if at least one of the following conditions is met: (a) such costs relate to improvements in the plant’s (or some other production asset’s) capacity and safety; (b) environmental pollution is prevented or limited; or (c) the costs are incurred to prepare the assets for sale and the book values of such assets together with the additional cost do not exceed their respective recoverable values.

Liabilities related to future remediation costs are recorded when environmental assessments are probable, and the costs can be reasonably estimated. The timing and magnitude of these accruals are generally based on the Company´s commitment to a formal plan of action, such as an approved remediation plan or the sale or disposal of an asset. The accrual is based on the probability that a future remediation commitment will be required.

The Company records the related liabilities based on its best estimate of future costs, using currently available technology and applying current environmental regulations as well as the Company´s own internal environmental policies.

j) Income tax, tax on minimum presumed income, royalties and withholdings on export of hydrocarbons:

The Company and its affiliates estimate income tax on individual basis under the deferred tax method.

The deferred tax balance as of the end of each year has been determined on the basis of the temporary differences generated in certain items that have a different accounting and tax treatment.

To book such differences, the Company uses the liability method, which established the determination of net deferred tax assets and liabilities on the basis of temporary differences determined between the accounting measurement of assets and liabilities and the related tax measurement. Temporary differences determine the balance of tax assets and liabilities where their future reversal decreases or increases the taxes determined. Where there are unused Tax loss carryforwards that may be offset against future taxable income, the Company recognize a deferred tax asset, only to the extent that recovery of such asset is probable.

As of December 31, 2004, deferred tax assets net of valuation allowances amounted 713, and deferred tax liabilities amounted 329.

Deferred tax assets and liabilities have been valued at their nominal value, as established by CNV’s General Resolution No. 434. The professional accounting standards effective in the City of Buenos Aires require that such nominal value be discounted at a current rate estimated as of each year-end.

The tax on minimum presumed income is supplementary to income tax, since while the latter is levied on the year’s taxable income, the tax on minimum presumed income is a minimum tax levied on the potential income of certain productive assets at the rate of 1%, so that the Company’s final liability will be equal to the higher of both taxes. However, should the tax on minimum presumed income exceed the income tax on in any given year, such excess may be applied to reduce any excess of income tax over the tax on minimum presumed income in any of the ten succeeding years.

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For the operations in Argentina, Venezuela, Brazil, Peru, Ecuador and Bolivia the income tax accrual was calculated at the tax rates of 35%, 34%, 34%, 30%, 36.25% and 25%, respectively. Additionally, payment of Bolivian-source income to beneficiaries outside Bolivia is subject to a 12.5% withholding income tax and, a 34% income tax is levied on the dividends paid by Venezuelan companies, in event of income in excess of taxable income.

Law No. 25,239 and its Administrative Order No. 1,037/2000 amended income tax law to establish, among other things, that shareholders residing in Argentina of companies organized or operating in countries with low or no-taxation with non-operating income exceeding 50% of net income, are to book accrued passive income such as interest, dividends, royalties, rents or other similar passive income to the fiscal year, although the income was not remitted or credited to any account. The Law and Administrative Order also establish that such companies shall not generate Argentine tax credits for the tax paid abroad.

Royalties are paid in Argentina and Bolivia for the production of crude oil and for effectively used volumes of natural gas. Those royalties are 12% and from 40% to 60%, respectively, of the wellhead estimated price for oil and gas. The wellhead price represents the final sales price less treatment, storage and transportation costs. Royalties are charged to production costs in the “Oil and gas royalties” account. In Venezuela, for the Acema, Mata and La Concepción (Third Round) areas, 30% royalties are paid with respect to the excess production, calculated based on the crude wellhead estimated price. Under contractual terms, royalties of the Third Round areas are deducted from the sales price. In Peru, the royalties paid for the production of crude oil are determined on the basis of the price of a basket of varieties of crude oil, starting at rate of 13% for prices of up to US$ 23.9 per barrel. The royalty rate applicable as of December 31, 2004, was 17.6%. Production of natural gas is subject to a fixed royalty of 24.5%.

As regards the Pichi Picún Leufú Hydroelectric Complex, as provided in the concession agreement, the Company pays hydroelectric royalties of 1% increasing at a rate of 1% per annum up to the maximum percentage of 12% of the amount resulting from applying the rate for the bulk sale to the power sold under the terms of Section No. 43 of Law No. 15,336, as amended by Law No. 23,164. In addition, the Company is subject to a license fee payable monthly to the Federal Government for the use of the power source equivalent to the 0.5% of the same basis used for the calculation of the hydroelectric royalty.

The Public Emergency and Exchange System Reform Law No. 25,561 establishes the creation of a system of withholdings on exports of hydrocarbons for five years, since March 1, 2002. The current withholding rate is 5% for refined products, 20 % for LPG, and 20% for natural gas. There is a special withholding regime on crude oil exports, starting at 25% if the price per barrel equals or is less than US$ 32, plus increasing withholdings rates ranging from 3% to 20%, depending on whether the price per barrel of crude oil varies from US$ 32.01 to US$ 45, with a maximum withholding of 45% when the price exceeds US$45.

k) Liabilities for labor costs:

Liabilities for labor costs are accrued in the periods in which the employees provide the services that trigger the consideration.

For purposes of determining the estimated cost of postretirement benefits granted to employees, the Company has used actuarial calculation methods, making estimates with respect to the applicable demographic and financial variables.

l) Contingencies:

Certain conditions may exist as of the date of financial statements which may result in a loss to the Company, but which will only be resolved when one or more future events occur or fail to occur. Such contingent liabilities are assessed by the Company’s management based on the opinion of Petrobras Participaciones’s legal counsel and the available evidence.

Such contingencies include outstanding lawsuits or claims for possible damages to third parties in the ordinary course of the Company´s business, as well as third party claims arising from disputes concerning the interpretation of legislation.

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If the assessment of a contingency indicates that it is probable that a loss has been incurred and the amount of the loss can be estimated, a liability is accrued in the Reserves account. If the assessment indicates that a potential loss contingency is not probable but is reasonably possible, or is probable but cannot be estimated, then the nature of the contingent liability, together with an estimate of the possibility of occurrence, is disclosed in a note to the financial statements. Loss contingencies considered remote are not disclosed unless they involve guarantees, in which case the nature of the guarantee is disclosed.

Significant litigations in which the Company is involved and the movements of reserves are disclosed in Note 14.

m) Earnings per share:

Earnings per share for the years ended December 31, 2004, 2003 and 2002, were calculated on the basis of the number of outstanding shares in each year. Since the Company does not have preferred assets or convertible debt securities, the basic earnings per share is equal to the diluted earnings per share.

n) Shareholders – equity accounts:

They were restated into constant currency, according to Note 2.c), as of year-end, except for “Capital stock” that represents subscribed and paid-in capital. The adjustment arising from the restatement into constant currency is disclosed under “Adjustment to capital stock”. The account “Treasury stock” relates to the purchases of shares of the Company by Petrobras Energía, and are deducted from the shareholders’ equity at acquisition cost, disclosed in a separate line in the statement of changes in shareholders’ equity.

o) Revenue recognition:

The Company generally sells crude oil, natural gas and petroleum, petrochemical, and other products. In all cases, revenues are recognized when the products are delivered, which occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. Sales between group companies are based on prices generally equivalent to commercially available prices.

Revenues from the production of oil and natural gas properties in which the Company has an interest with other producers are recognized on the basis of the Company’s net working interest.

Revenues from gas transport are recognized when the services are rendered, based on the quantities transported measured according to procedures defined in each service contract.

Revenues from sales resulting from the natural gas transportation under firm agreements are recognized by the accrued reserve of the transportation capacity hired, regardless of the volumes carried.

Revenues from sales of electricity, of refining-marketing activities and of petrochemical products are recorded upon transfer of title, according to the terms of the related contracts.

p) Statement of income accounts:

Restated into constant currency through the end of the period, according to Note 2.c), considering the following:

Depreciation and consumption expenses related to non monetary assets were charged to income (losses) taking into account the restated costs of such assets.

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Financial income (expense) and holding gains (losses) are broken down between those generated by assets and those generated by liabilities. “Financial (expense) income, net” discloses financial income and expenses, exchange differences and income (loss) from changes in the quotation of government securities and shares, at their restated nominal value, according to Note 2.c). Additionally, it also discloses the effects of inflation of monetary assets and liabilities in the balance sheet.

CNV General Resolution No. 398 allows, as an exceptional treatment, the one provided for in Resolution M.D. No. 3/2002 of the CPCECABA, whereby the exchange differences originated as from January 6, 2002, from liabilities in foreign currency existing as of such date directly related to the acquisition, construction, or production of property, plant & equipment, intangibles, and long-term investments in other companies organized in the country should be allocated at the cost values of such assets with a number of conditions established in such professional standard. Direct financing shall mean that granted by the supplier of the goods, billed in foreign currency, or that obtained from financial institutions for identical purposes. In the cases in which there is an indirect relation between the financing and the acquisition, production, or construction of the assets, such exchange differences may also be allocated, under certain conditions, to the cost values of such assets. The Company has adopted the method of capitalizing exclusively the foreign exchange differences resulting from direct financing. Subsequently, in July 2003, the CPCECABA put into effect Resolution C.D. No. 87/03, which - among other measures - abrogated the provisions of Resolution M.D. No. 3/2002 mentioned above. Consequently, as from such date, the Company ceased to apply the exchange difference capitalization / de-capitalization method.

As described above, as of December 31, 2004 and 2003, the Company has capitalized exchange differences, principally through the investments in Ciesa and Citelec, amounting to a residual value of 46 and 48, respectively.

5. Accounting for derivative financial instruments

Hedging and other derivatives:

The Company uses various derivative financial instruments such as options, swaps and others, mainly to mitigate the impact of changes in crude oil prices, interest rates and future exchange rates.

Such derivative instruments are designated as hedging specific exposures, highly correlated to the risk exposure in question and highly effective in offsetting changes in cash flows inherent to the covered risk.

The use of derivative financial instruments exposes the Company to credit risk. In addition, the Company uses strict policies for the approval of lines of credit, applies several procedures to evaluate these risks and seeks to reduce this credit exposure by means of the use of certain tools, such as anticipated collections or payment agreements for such operations and the offsetting of collections and payments.

Derivative financial instruments are measured at their fair value, determined as the amount of cash to be collected or paid to settle the instrument as of the date of measurement, net of obtained or paid advances.

a) Instruments that qualify for hedge accounting

Changes in the accounting measurement of derivative financial instruments designated as cash flow hedge, which have been designated as effective hedges, are recognized under “Transitory differences-Measurement of derivative financial instruments designated as effective hedge”, and any other change is recognized under financial income (expense) for the year. Changes in the accounting measurement of derivate financial instruments recognized under “Transitory differences-Measurement of derivative financial instruments designated as effective hedge” are subsequently reclassified to income (loss) for the period in which the hedged item affects such results.

A hedge is considered to be effective when at its inception, as well as during its life, its changes offset from eighty to one hundred and twenty five percent the opposite changes of the hedged item. In this respect, the Company excludes the specific component attributable to the time-value of an option when measuring the effectiveness of instruments that qualify for hedge accounting.

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Hedge accounting must cease for the future upon occurrence of any of the following events: (a) the hedge instrument has matured or has been settled; (b) the hedge transaction is no longer effective; or (c) the projected transaction does not have a high likelihood of occurrence. Should that be the case, the income (loss) arising from the hedge instrument that would have been allocated to “Transitory differences-Measurement of derivative financial instruments designated as effective hedge” should remain there until the committed or projected transactions occurs in the case of (a) and (b), and is charged to income in the case of (c).

Pursuant to the transitional standards of FACPCE Technical Resolution No. 20, as from January 1, 2003 the Company applied on a prospective basis the standard of booking derivative positions at their market value, affecting the comparability of the financial statements as of December 31, 2002. As indicated as of December 31, 2002, the gains (losses) on hedge transactions related to the crude oil price, without distinguishing between hedge and non-hedge transactions, were deferred until the related anticipated transaction was recognized, when they were booked as an integral part of hedged sales.

Hedge of produced crude oil price

These instruments use the West Texas Intermediate (WTI) as reference price, which is used mainly to determine the sale price in the market.

As of December 31, 2004 the Company did not have positions in derivatives of the crude oil price related to the future production that qualify for hedge accounting purposes.

As of December 31, 2003 and 2002 the accrued portions of hedge instruments represented lower sales of 81 and 373, respectively.

Hedge of interest rates

As of December 31, 2004, the Company has an agreement for the purpose of hedging class “C” notes exposed to fluctuations with the LIBOR, fixing the rate at 7.93% per annum. Such contract term expires in July 2005, payable in quarterly installments as from 2004. The market value for the year amounts to 4.

During the period, the changes in “Transitory differences-Measurement of derivative financial instruments designated as effective hedge” was:


	Interest Rate
Book value at the beginning of the period by application of Technical Resolution No. 20	18
Reclassification to net income	(16	)

Book value at the end of the period	2

Instruments that do not qualify for hedge accounting

Changes in the accounting measurement of derivative financial instruments that do not qualify for hedge accounting are recognized in the statement of income under “Financial income (expense) and holding gains (losses)”. For the years ended December 31, 2004, 2003 and 2002, losses from derivative financial instruments that do not qualify for hedge accounting amount to 688, 294 and 524, respectively.

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The main conditions and terms by type of instrument as of December 31, 2004 are as follows:


	Expected maturity 2005
Sales price exposure
Crude oil price swap (1)
Contract volumes (million barrel)	7.30
Average settlement prices (US$ per barrel)	19.00
Fair value before advanced payments	(507.00	)

(1)	Options on swaps exercised by the other party.

6. Oil and gas areas and participation in joint ventures

As of December 31, 2004, the Company was part of the oil and gas consortiums, joint-ventures and areas indicated in Note 27.g). As of that date, the aggregate joint venture and consortia assets, liabilities and results in which the Company is a party, included in each account of the balance sheet and the statement of income, respectively, utilizing the proportionate consolidation method are disclosed in Note 27.h).

The production areas in Argentina, Ecuador and Peru indicated in Note 27.g) are operated pursuant to concession production agreements with free crude oil availability. Those related to Venezuela are exploitation service agreements, in which Petróleos de Venezuela S.A. (“PDVSA”) owns all the oil and gas produced and is responsible for the payment of all royalties and taxes related to the production and will receive, upon expiration of the agreement term, the exclusive ownership of all operating facilities, property and equipment used by the joint ventures to perform the activities under the agreement. In Bolivia it is a shared-risk contract signed with Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”) with free production availability.

In Ecuador, operation contracts for Block 18 stipulate the free disposition of the oil produced and differential production percentages to go to the Ecuadorean Government. In the Pata field, the Government receives a production share ranging from 25.8%, if daily production is lower than 35,000 barrels per day, to 29%, if production exceeds 45,000 barrels per day. For the middle range, the share is about 26.1%. As for operation of the Palo Azul field, the percentages are determined in accordance with a formula that takes into account the final price of the crude produced and the level of total proved reserves. Namely, if the crude from Palo Azul is sold at less than US$ 15 per barrel, the Government receives about 30% of the crude produced, while, if the price of the crude is US$ 24 or higher, the Government receives about 50% of production. For the other price ranges, a price scale was agreed. The selling price of the Palo Azul crude is calculated considering as reference the barrel of WTI after the standard market discount for the Oriente crude. As of December 31, 2004, the Government’s share of the oil produced at the Pata and Palo Azul fields was 25.8% and 50%, respectively.

Block 31 has no production yet, being in its early stages of development, but as soon as it produces its first barrel, the Government’s share will range from 12.5% to 18%, depending on daily production volumes and oil density. The concession agreement for Block 31 provides for the free availability of the crude oil produced.

The Company is jointly and severally liable with the other joint venturers for meeting the contractual obligations under these arrangements.

As regards the Oritupano-Leona area, in Venezuela, the joint venture awarded the area receives a variable operation fee based on production volumes, which amounts to US$ 6.8 per barrel as of December 31, 2004, plus a capital fee for reimbursement of certain exploration and development investments. Under the terms of the service agreement executed with PDVSA, the total amount to be paid may not exceed approximately US$ 37.9 per barrel, variable according to a basket of oil market prices.

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In relation to the Mata, Acema and La Concepción fields, also in Venezuela, the joint ventures awarded the areas are paid a fee for the operation services rendered, which covers investments and production costs plus a gross profit. The fee has a fixed component related to contractual baseline production and a variable component related to incremental production, that covers investments and production costs plus a gross profit up to a maximum tied to a basket of international oil prices.

Divestments of equity in oil and gas areas

In August 2003, the Company sold to Central International Corporation, Argentine Branch, an 85% interest over the rights and obligations on the concession of the Catriel Oeste area. Considering the transfer price agreed, of US$ 7 million, the Company recognized a loss of 28 presented under “Other expenses, net”.

In June 2003, the Company sold to Geodyne Energy Inc., Argentine branch, a 50% equity interest over the rights and obligations pertaining to the Faro Vírgenes concession area, recognizing a loss of 11, disclosed under “Other expenses, net”. This transaction shall be settled over a ten-year period, in quarterly installments, whose value in US dollars shall be determined as 8.8% of the total production of gas from the Faro Vírgenes area for each quarter. The Company has the option to receive such consideration directly in gas.

In October 2002, the Company signed an association agreement with Teikoku Oil Co., Ltd., whereby it transferred 50% of is rights and obligations to exploit gas in exploratory areas in San Carlos and Tinaco, located in the State of Cojedes, Venezuela. The participation assignment agreement provides for an initial cash payment of US$ 1 million and a subsequent disbursement of US$ 2 million, which shall finance the plan of exploratory investments of the Tinaco area, as regards geological studies, 2D seismic and evaluations and interpretation thereof. Also if the development of those areas is agreed, the Company will receive an additional payment of US$ 3 million. Considering the recoverable value as of December 31, 2002, the Company recognized a loss of 37, disclosed under “Other expenses, net”.

Investment commitments

Petrobrás Energía Perú S.A. has arrived at an agreement with the Peruvian Government, whereby it undertook the commitment to make investments in Lot X amounting to at least US$ 97 million approximately over the period 2004-2011. In compensation, the Peruvian Government undertook to reduce the royalties for oil and gas extraction that it charges to the company. The tasks initially planned for this project comprise the drilling of 51 wells, the reconditioning of 526 wells, the rehabilitation of 177 wells that had been abandoned temporarily and the implementation and expansion of water injection project. As of December 31, 2004, U.S 18 million has already been invested.

The Company has retained a portion of Block 31 in Ecuador to continue exploration, undertaking the commitment to perform an environmental impact study, as well as 120 sq. km of 3D seismic readings, processing and interpretation, reprocessing 500 km of 2D seismic studies for integration with the new 3D seismic and the drilling of an exploratory well, representing an investment of about US$ 16 million. Meanwhile, in Block 18, the Company has commitments amounting to about US$ 47 million related to the operation of the Pata and Palo Azul fields and including production well drilling and construction of crude-oil treatment plants (see Note 26.1).

7. Credit risk

The Company provides credit in the normal course of business to refiners, petrochemical companies, marketers of petroleum products, crude oil exporting companies, electric power generation companies, retail customers, natural gas distributors, electric power large users and power distribution companies, among others.

Sales for the year ended December 31, 2004, were made mainly to Petróleos de Venezuela S.A., Petroperú Petróleos del Perú S.A., EG3 S.A. and Glencore AG, and sales to such entities represented about 12%, 7%, 6% and 3%, respectively, of sales for such year, before deducting export duties.

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Sales for the year ended December 31, 2003, were made mainly to Petróleos de Venezuela S.A., Petroperú Petróleos del Perú S.A., Repsol - YPF Trading y Transporte S.A. and Glencore A.G. and represented about 11%, 7%, 5% and 4%, respectively, of sales for such year, before computing gain (loss) generated by derivative financial instruments and before deducting export duties.

Sales for the year ended December 31, 2002, were made mainly to Petróleos de Venezuela S.A., Petroperú Petróleos del Perú S.A., Repsol - YPF Trading y Transporte S.A. and Petrobras, and sales to such entities represented about 16%, 8%, 7% and 6%, respectively, of sales for such year, before computing gain (loss) generated by derivative financial instruments and before deducting export duties.

The Company participates in the conformation of the fund created by Resolution S.E. No. 712/04 (“FONINVEMEM”), aimed to increase available electric power generation supply in Argentina, through the contribution to that fund of 65% of the difference between sales price and variable generation costs, generated from 2004 through 2006. The contributed capital during 2004 amounted to nominal value US$ 5 million. The total estimated contributed capital from 2004 through 2006 would amount to nominal value US$ 35 million, which represents 8% of the fund’s capital. The final amount will depend, among other factors, on hydric conditions, on the dispatches that CAMMESA makes from the Company’s generation units and on the resulting sales prices.

As a result of the business of the Company and sale locations, the portfolio of receivables is well diversified, and such diversification makes the credit risk moderate. Thus, the Company constantly performs credit evaluations of the financial capacity of its clients, which minimizes the potential risk of losses from bad debts.

8. Inventories

The breakdown of current and non-current inventories as of December 31, 2004 and 2003, is as follows:


	2004				2003
	Current		Non-current		Current		Non-current
Crude oil stock	60		—		41		—
Materials	142		58		125		63
Work in progress and finished products - refining and petrochemical	273		—		122		—
Advances to suppliers	8		—		33		—
Other	6		—		2		—
Reserve for materials’ obsolescence (Note 14)	(2	)	(2	)	(4	)	(2	)

	487		56		319		61

9. Investments, equity in earnings of affiliates and dividends collected from affiliates

The breakdown of current and non-current investments as of December 31, 2004 and 2003, and the equity in earnings of affiliates and dividends collected from affiliates for the years ended December 31, 2004, 2003 and 2002, are as follows:

F - 31

a) Investments


	2004		2003
Name and issuer	Cost	Book value	Book value
Current:
Government securities	5	5	51
Certificates of deposit	569	569	146
Mutual funds	216	216	626
Reserve for impairment of government securities (Note 14)	—	—	(23	)
Other	—	—	2

	790	790	802

Non-current:
Government securities	70	24	2
Advances to joint ventures	154	154	157
Related companies (Note 19)	156	156	127
Equity in affiliates (Note 27 b)	1,005	988	996
Other	—	1	2

	1,385	1,323	1,284

b) Equity in earnings of affiliates


	2004		2003		2002
Cerro Vanguardia S.A.	—		—		59
Cia. de Inversiones de Energía S.A.	—		(33	)(i)	(398	)
Citelec S.A.	(42	)	87	(iii)	(241	)
Empresa Boliviana de Refinación S.A.	18		(5	)	12
Enron de Inversiones en Energía S.C.A.	—		—		(32	)
Oleoducto de Crudos Pesados Ltd.	1		(5	)	—
Inversora Mata S.A.	4		4		(9	)
Oleoductos del Valle S.A.	7		2		11
Petrolera Entre Lomas S.A.	17		13		12
Petroquimíca Cuyo S.A.	16		16		(10	)
Refinería del Norte S.A.	40		28		9
Transportadora de Gas del Sur S.A.	10	(ii)	52	(ii)	(52	)
Yacylec S.A.	3		2		2
Others	2		2		(1	)

	76		163		(638	)

(i)	Corresponds to non-recognized losses of year 2002 because the valuation of the equity interest in CIESA amounted to zero, as such interest valued under the equity method would have represented a negative amount (see Note 9.III)

(ii)	Net of the adjustments incorporated to adapt TGS´s accounting principles to those of the Company amounted to 1 and 31 for 2004 and 2003, respectively (see Note 9.III).

(iii)

Includes the reversal of 2002 allowance, which amounted to 66 (see Note 9.III).

F - 32

c) Dividends collected from affiliates


	2004	2003	2002
Yacylec S.A.	3	3	1
Empresa Boliviana de Refinación S.A.	13	—	4
Petroquimíca Cuyo S.A.	9	—	—
Petrolera Entre Lomas S.A.	12	9	12
Oleoductos del Valle S.A.	6	7	3
Refinería del Norte S.A.	41	7	—

	84	26	20

I. Investment in companies over which joint control or significant influence is exercised and are subject to transfer restrictions:

a) Distrilec Inversora S.A. (“Distrilec”):

Distrilec is able to change its equity interest and sell its shares of Edesur S.A. (“Edesur”) only with the approval of the ENRE (Federal Power Regulation Authority).

In addition, over the entire term of the concession, the Class “A” shares in Edesur shall remain posted as bond to guarantee compliance with the obligations undertaken in the Concession Agreement. This bond in no way limits the exercise of financial and voting rights associated with the Edesur shares.

As of December 31, 2004 and 2003, the valuation of the Company’s interest in Distrilec, a proportionally consolidated company, amounts to 678 and 691 respectively. These amounts include 83 and 91 corresponding to the purchase price allocated to Distrilec’s fixed assets booked by the Company at the time of the acquisition of a portion of its interest.

b) Cía. de Inversiones de Energía S.A. (“CIESA”):

Shareholders of CIESA, parent company of Transportadora de Gas del Sur S.A. (“TGS”), may not sell to companies that do not belong to the same economic group, over 51% of its Class “A” shares which represents 51% of CIESA’s capital stock, without the prior authorization of the regulatory agency and the approval of the shareholders of CIESA.

In April 2004, the shareholders of CIESA celebrated a framework agreement whereby Petrobras Energía and Enron will reciprocally waive any right to make claims arising from or related to certain agreements executed by such groups in connection with their interests in CIESA and TGS. In addition, and in order to provide the flexibility necessary to make progress in restructuring CIESA’s financial debt, the framework agreement also provides for the following share transfer. During the first phase (a), subject to the approval by the ENARGAS (Argentine gas regulatory agency), Enron will transfer 40% of the shares issued by CIESA to a trust to be organized or an alternative entity; and (b) Petrobras Energía will transfer common class “B” shares issued by TGS (representing 7.35% of the capital stock of TGS) to Enron. If CIESA successfully renegotiate its financial debt, during the second phase, Enron would transfer its remaining interest in CIESA to the abovementioned trust or to an alternative institution while CIESA would simultaneously transfer common class “B” shares issued by TGS (representing about 4.3 % of the capital stock of TGS) to Enron. In no case shall the Company hold (directly or indirectly) more than 50% of the capital stock currently held in CIESA or any controlling interest in CIESA. The Framework Agreement includes the terms under which the Technical Assistance Contract is to be transferred to the Company. The bankruptcy court handling the Enron bankruptcy approved the Framework Agreement in May 2004. The shareholding transfers involved were submitted for approval by CNDC, which has confirmed the transfer, and ENARGAS, which has not raised objections against the operation in its competence, but it has conditioned the approval to a favorable opinion from the Treasury Attorney General. As of the date of this Financial Statements the Company does not know whether this opinion has already been rendered.

F - 33

c) Compañía Inversora en Transmisión Eléctrica Citelec S.A. (“Citelec”):

The Company may not modify or sell its equity interest in Citelec in a proportion and number of shares exceeding 49% of its shareholding without prior approval by the ENRE.

On July 28, 2004, CNDC authorized Petrobras Energía to exercise the right of first refusal on 17,406 book-entry Class A shares of common stock, representing 0.007% of Citelec’s capital stock, thus taking its equity interest to 50%. Petrobras Energía exercised such option within the framework of the purchase agreement for the entire equity interest that National Grid Finance B.V. had in Citelec, executed with Dolphin Fund Management.

Upon obtaining approval by CNDC for the acquisition by Petrobras Participaciones SL of a majority shareholding in Petrobras Participaciones, Petrobras Energía agreed to divest its entire equity interest in Citelec S.A., in accordance with Law No. 24,065, which establishes the Regulatory Framework for the Electric Power Sector. Such transfer is to be overseen by Argentina’s ENRE (Electric-Power Federal Regulatory Entity) and approved by the Argentine Secretary of Energy (See Note 26.4).

Citelec is not permitted to modify its 65% equity interest in Compañía de Transporte de Energía en Alta Tensión Transener S.A. (“Transener”) nor sell its Class “A” shares which represent 51% of Transener’s capital stock, without prior approval by the ENRE.

Transener may not modify or sell its shareholding in Empresa de Transporte de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires Transba S.A., without prior approval by the ENRE.

d) Yacylec S.A. (“Yacylec”):

Yacylec’s Class “A” shares will remain pledged during the term of the concession, as security for the compliance with the obligations undertaken under the concession agreement. Any transfer of shares requires ENRE’s prior authorization.

II. Enecor S.A.

For the entire term of the concession, the Class “A” shares in Enecor shall remain posted as bond to guarantee compliance with the obligations undertaken in the Concession Agreement. Prior authorization from the ENRE is required for any transfer of shares.

III. Situation of the interests in public utility companies

The scenario after enactment of the Law on Public Emergency deeply changed the financial equation of public utility companies. Particularly, the tremendous effect of the devaluation, within a context where revenues remained fixed, as a consequence of de-dollarization of rates, has affected the financial and cash flow position of companies, as well as their ability to comply with certain loan covenants. This situation has extremely conditioned the financial ability to comply with obligations.

The Public Emergency Law provided for the conversion into Argentine pesos and the elimination of indexation clauses on public service rates, thus fixing them at the exchange rate of ARS 1 = US$ 1. In addition, the Executive Branch was empowered to renegotiate those agreements entered into to provide public services, along the following criteria: (i) rates impact on economic competitiveness and revenue allocation, (ii) service quality and investment plans, to the extent that they were contractually agreed upon, (iii) users interests and access to services, (iv) the safety in the system involved, and (v) utilities profitability.

On February 12, 2002, the Executive Branch of Government issued Decree No. 293/02 whereby it recommended the Ministry of Economy to renegotiate the agreements executed with public utilities. The Ministry of Economy should have submitted a renegotiation proposal or termination recommendation to the Executive Branch of Government and then it should be sent to the applicable Congress bicameral commissions.

F - 34

To allow for preserving the provision of public services, and considering the renegotiation process underway, the Executive Branch of Government issued Decree No. 146/03 authorizing an increase in gas and electric power rates. This caused a 10% increase for TGS, 9% for Edesur and 22% for Transener. The increase in rates was objected by the ombudsman and consumer associations. On February 25, 2003, a trial court issued an injunction and suspended the increase in rates.

The UNIREN (public service agreement renegotiation and analysis unit) was created in July 2003. Such agency reports to the Ministries of Economy & Production, and Federal Planning, Public Investment & Services. The UNIREN took over the work of the Renegotiation Commission and its aim is to provide assistance in the public works and services renegotiation process, execute comprehensive or partial agreements, and submit regulatory projects related to transitory rate adjustments, among other things.

On October 1, 2003, Argentine Congress passed a bill that established the extension to December 2004 of the term granted by the Executive Branch of Government by virtue of Public Emergency Law to renegotiate the agreements executed with privatized public-service companies. Such law also will allow the Executive Branch of Government to fix public utilities rates until the completion of the renegotiation process. Subsequently, Law No. 25,792 again extended the term for renegotiating public works and utilities contracts until December 31, 2005.

The impact of the measures adopted by the Argentine Government on the financial statements of CIESA, TGS, Transener and Citelec have been recognized in accordance with the evaluations and estimates made by their respective managements. Actual future results could differ from the evaluations and estimates made and such differences could be significant. In addition, it is not possible to predict the future development of the rates and concession agreements renegotiation processes or their effects on such companies’ results of operations and financial position.

CIESA and Transener have defaulted on their debt and strive to reschedule it. These companies have drafted and implemented a plan of action to mitigate the adverse impact caused by these circumstances. The Company cannot guarantee the success in implementing it and whether it will fulfill the proposal aims. CIESA, Transener and Citelec have prepared their financial statements assuming that they will continue as going concerns and have not included any adjustments or reclassifications that could result from the uncertainties mentioned above. (See Note 26.4)

As of December 31, 2004, the book value of the equity interests in CIESA, TGS and Citelec amounts to 206, 151 and 116 (net of adjustments made to adapt Ciesa´s and TGS´s valuation methods to those of the Company of 43 and 11). As of December 31, 2003, the valuation of the equity interests in CIESA, TGS and Citelec amounted to 190, 140 and 158 (net of adjustments made to adapt Ciesa´s and TGS´s valuation methods to those of the Company of 45 and 12, respectively). CIESA has been proportionally consolidated. As of December 31, 2002, the valuation of the equity interests in CIESA, TGS and Citelec amounted to zero, 88 and 71 (net of adjustments made to adapt TGS´s valuation methods to those of the Company of 43). The equity interest in CIESA valued under the equity method in conformity with accounting principles consistent with those applied by the Company would have represented an amount of 33 negative. However, considering that the Company has not undertaken commitments to contribute capital or provide financial aid to its affiliates, such equity interest has been stated at zero value, thus restricting the recognition of losses related to the respective book value. The value of the equity interest in Citelec was presented net of the allowance for impairment amounted to 66, determined as mentioned below.

The book value of such equity interests does not exceed their recoverable value. The estimates made for their respective recoverable values depend on the significant uncertainties mentioned above, which limit the quality of the premises, estimations and evaluations that involve such estimations. Consequently, in the actual scenario, shares’ market value is the most objective standard / tool / guide for the establishment of the net realizable value of such interests. Extension of uncertainties, and development of several possible scenarios of future projections with extremely subjective likelihood of occurrence, including the consensus on the applicable discount rate, affect the pertinence and confidence of the values that may arise.

F - 35

Expansion of TGS’s gas transportation system

In light of the lack of expansion of the natural gas transportation system over recent years (as a consequence of the “pesification” of tariffs and the fact that the renegotiation of the License is still pending) and a growing gas demand in certain segments of the Argentine economy, the Argentine Government established—through Executive Branch Decree No. 180/04 and Resolution No. 185/04 issued by the Ministry of Federal Planning, Public Investment and Utilities- the framework for the creation of a trust fund (“the Trust Fund”) that would be used as a vehicle to finance gas transportation system expansions.

In June 2004, TGS submitted to the Energy Department a project to expand the transportation capacity of the San Martín gas pipeline by about 2.9 million cubic meters per day. The project involves the construction of about 500 km of pipeline and a 27,700 HP increase in compression capacity obtained by building a new compression plant and boosting the power of some compression units. TGS held an open competitive bidding process to contract the additional 2.9 million cubic meters per day transportation capacity and launched the bidding process for the purchase of the pipe on account and behalf of the Trust.

On November 3, 2004, TGS, the Argentine Government, Petrobras and Nación Fideicomisos S.A., among others, executed an agreement to perform the expansion works. Such agreement was ratified by the Argentine Executive Branch of Government through Decree No. 1,658/04 of November 25, 2004. TGS will be in charge of managing the project and operating and maintaining the new facilities.

Petrobras Energía has agreed to act on account and behalf of Petrobras by providing up to US$142 million of the funds to finance the project until the financing, which includes financing for exports from Brazilian suppliers, is made available by BNDES. In turn, a financial trust created for the project’s financing will deliver debt securities in equivalent value to Petrobras Energía. TGS will be in charge of managing the project and operating and maintaining the new facilities. As of May 31, 2005, Petrobras Energía has contributed US$53 million to the trust on account and behalf of Petrobras. On May 25, 2005, BNDES made an initial disbursement of US$14 million and, since then, the financing facility with BNDES became effective.

On February 25, 2005, Petrobras Energía’s Board of Directors approved entering into a loan-for-consumption agreement with Petrobras Internacional Braspetro BV, a subsidiary of Petroleo Brasileiro S.A. The loan has a principal amount up to US$142 million and has a term of three years with an annual 5.35% interest rate, free of tax withholdings. This loan can be prepaid at any time without a prepayment penalty.

IV. Operations in Ecuador.

In Ecuador the Company operates Blocks 18 and 31, and as of December 31, 2004, the Company has a 70% and 100% share in such blocks, respectively (see Note 26.1). In addition, as of December 31, 2004, the Company has a 11.42% share in Oleoductos de Crudos Pesados Ltd. (OCP).

Block 18 is a field that has significant potential light crude oil reserves, of 28 to 33 degrees API. The concession to Block 18 was granted for an initial period of 20 years, beginning October 2002, extendable for a further five years.

Block 31 is an area with significant potential oil reserves. The exploratory work performed in the block was successful and discovered significant reserves of heavy crude. In August 2004, the Ecuadorian Energy Ministry approved the Environmental Impact Studies, and with this all requirements for block development approval were fulfilled. As from such approval date, the twenty-year operation period is running.

OCP has been granted the concession to build and operate for twenty years the 503-km-long oil pipeline from the Ecuadorian northeast to the Balao distribution terminal on the Pacific Ocean coast. The pipeline has a transportation capacity of 450,000 barrels per day and officially came into operation on November 10, 2003. In May 2004, the Company increased its equity interest in OCP by 2.46%, for which the Company paid US$ 14 million, pursuant to Techint International Construction Corp having exercised its irrevocable put option on shares and subordinate debt.

F - 36

In relation to the exploitation of Blocks 18 and 31, the Company has executed an agreement with OCP, whereby it has guaranteed an oil transportation capacity of 80,000 barrels per day for a 15-year term as from November 10, 2003 As from July 2004 and until January 2012, the Company sold a portion of this transportation capacity (8.000 barrels daily). The type of transportation agreement is “Ship or Pay”. Therefore, the Company is required to meet its contractual obligations for the entire volume hired, although no crude oil is transported, paying, like the other producers, a rate that covers OCP operating costs and financial services, among others. As of December 31, 2004 this amounted to US$ 2.2 per barrel. The costs for the transportation capacity are billed by OCP and charged to expenses monthly. In this regard, the costs related to the crude oil volume effectively transported are charged to “Administrative and selling expenses” line, whereas the surplus, related to transportation capacity hired but not used is disclosed in the “Other operating expenses, net” line.

In order to guarantee the compliance with the Company’s business commitments related to the “Ship or Pay” transportation agreement executed with OCP and OCP’s related financial obligations.

As of December 31, 2004, the Company obtained letters of credit for a total amount of approximately US$214 million. Of this total amount, US$148 million had to be secured by cash collateral. As of that date, the Company deposited US$41 million of this cash collateral and had to deposit the balance of this cash collateral on a yearly basis according to the following schedule:


	2005	2006	2007	TOTAL
In Millions of US$	35	36	36	107

As of May 31, 2005 the obligation to secure commercial obligations were reduced to US$ 133. In connection therewith, the Company have standby letters of credit in place without any cash collateral commitment. The Company is required to renew or replace these letters of credit as they mature, otherwise, it will be required to repay the amounts due in cash at maturity, which will have an adverse effect on its cash flows.

V. Assets exchange

The Regular Shareholders’ Meeting held on April 3, 2002, approved an agreement with economic effects as from January 1, 2002, whereby:

Petrobras Energía sold to IRHE (Argentine Branch) and GENTISUR S.A. (a company wholly owned by IRHE) its 50% equity interest in Pecom Agra S.A. in the amount of US$ 30 million, which represented a gain of 81, disclosed in the “Other expenses, net” line.

ii)

IRHE (Argentine Branch) and GENTISUR S.A. transfered to Petrobras Energía:

0.75% interest in the Puesto Hernández joint venture in the amount of US$ 4.5 million;

7.5% interest in Citelec, in the amount of US$ 15 million;

9.187% interest in Hidroneuquén S.A., a company holding 59% of Hidroeléctrica Piedra del Águila S.A. stock, in the amount of US$ 5.5 million.

The remaining balance, US$ 5 million, was settled through a document maturing in October 2002, which accrues interest at six-month LIBOR plus annual 3% spread.

F - 37

VI. Sale of companies

a) Disposal of farming, forestry and mining activity assets

The agreements made in relation to the transfer of the controlling shares of Petrobras Energía Participaciones granted Petrobas an option, whereby if, within a 30-day term subsequent to the end of the purchase-sale of shares, Petrobras Energía would not have sold the assets related to agricultural, forestry and mining activities, Petrobras would be entitled to, but not required to, make the seller acquire those assets in an amount of US$ 190 million or, if any of those assets had been sold, the amount resulting from deducting from such amount, the price received in consideration of the sale made.

Under

these agreements, during 2002 Petrobras Energía performed the following transactions:

In July 2002, Petrobras Energía sold to Anglogold its indirect ownership interest of 46.25% in Cerro Vanguardia S.A., and the assets associated therewith. The price of the transaction has been fixed at US$ 90 million. The transaction represented a profit of 123, disclosed in the “Other expenses, net” line.

-	In September 2002, Petrobras Energía sold to Argentina Farmland Investors LLC the ownership interest representing 100% of the capital stock of Pecom Agropecuaria S.A. The price of the transaction totaled US$ 53 million, which implied a profit of 27, disclosed in the “Other expenses, net” line.

In December 2002, it concluded the disposal of the operations that form part of the forestry business, which included the sale of the 100% shareholding in Pecom Forestal S.A., jointly with the ownership of forestry located in the Paraná delta region, to DRT Investments LLC. In addition, it transferred the going concern related to forestry activities in Misiones to Alto Paraná S.A. In January 2004, the Company completed all the formalities needed for the transfer of the going concern of forestry related industrial activities. The total price of the abovementioned transactions amounted to US$ 53.16 million, resulting in a 153 loss, disclosed in the “Other expenses, net” line.

b) Sale of interest in Combustibles Nucleares Argentinos S.A. (CONUAR)

In October 2002, the Company sold its 66.67% shareholding in CONUAR to Sudacia S.A., a company controled by the Perez Companc Family, including the 68% interest in Fabricación de Aleaciones Especiales S.A. The transaction price amounted to US$ 8 million, while no income (loss) was derived from such sale.

10. Impairment of assets

I. Operations in Argentina

The Argentine peso devaluation, the enactment of Public Emergency Law and the different events that took place caused a significant change in the Company’s estimation of the future income (loss) evolution and the flow of certain businesses and assets. Considering the uncertainties existing with respect to the final breakdown of the economic and financial equation and their recoverability, the Company adjusted the book value of certain investments and assets to their related recoverable values, booking these allowances:

Gas areas: Considering the significant adverse impact on gas and power local prices, and the limited possibilities of negotiating price increases within the context of Public Emergency Law, during 2003 and 2002 the Company adjusted the book value of certain investments in gas producing areas in Argentina, booking looses that amounted to 37 and 44, respectively, in the “Other expenses, net” line (see Note 14).

Argentine Government public securities: After it declared the cessation of public debt payments, the Argentine Government suspended the possibility of paying taxes using Bonos Patrioticos until after the debt swap has ended. As of December 31, 2003, the allowance for impairment in value of these government securities amounted to 23.

-	Tax loss carry forwards: As of December 31, 2003 it was not possible to assure that future taxable gains would offset deferred tax assets and accumulated tax loss carry forwards. Consequently, the Company had booked allowances on certain tax loss carryforwards (see Note 13).

F - 38

As of December 31, 2004, taking into account the profitability expectations arising from the Company’s Business Plan, the Company partly reversed the abovementioned deferred tax valuation allowance, thus recognizing a gain of 268. Among other key issues, the analysis took into account the expected horizon of sustained high prices for commodities and the current relative stability of the main macroeconomic variables, including the first definitions of the Argentine Government as regards the recovery of energy and gas prices.

As of December 31, 2004, the Company has still booked allowances on tax loss carry forwards amounting to 1,336. In future fiscal years Company Management will analyze the feasibility of reversing such allowances as and when the assumptions of its Business Plan become confirmed, mainly as to the positive behavior of macroeconomic variables, the recovery of the Argentine economy and the degree of resolution of structural issues such as the restructuring of Argentine sovereign debt and the renegotiation of public service agreements. The tax loss carryforwards in question can be used through fiscal year 2007.

-	Tax on minimum presumed income credit: As of December 31, 2004 and 2003, the Company carries allowances covering the tax payments on minimum presumed income for a total amount of 72.

-	Interests in companies: Additionally, as mentioned in Note 9.III, the Company adjusted the valuation of the interest in Hidroneuquén as of December 31, 2004 and 2003 at its recoverable value, considering the default on its consolidated financial debt, booking an allowance of 10.

II. Operations in Ecuador

The prospects regarding operations in Ecuador have changed significantly during 2003 and 2002 mainly as a result of the restrictions caused by the Argentine economic crisis, which determined an important change in the pace of the Company’s global plan of investments, including a delay in the investments planned for the development of Block 31.

Considering the new pace of investments planned for the development of Blocks 18 and 31, together with the review of the potentiality of Block 31’s reserves, the Company estimated that there would be successive deficits of crude oil produced with respect to the total transportation capacity hired for the term of the “Ship or Pay” transportation agreement (See Note 9.IV).

During the year ended December 31, 2003, the accounting effects related to such deficit were disclosed setting an allowance, which was included in liabilities. To reflect more appropriately the impairment of the assets, corresponding to operations in Ecuador, based on the estimated future deficits described above, and in order to conform the disclosure criterion to the accounting principles generally accepted in United States of America (US GAAP), as from June 30, 2004, the Company presents such allowance, which amounts to 324, by reducing the book value of these assets. The Company has modified, for comparative purposes, the information for the year ended December 31, 2003.

The book value of assets in Ecuador, after computing the referred allowance, does not exceed its recoverable value at December 31, 2004 and 2003.

11. Pichi Picún Leufú Hydroelectric Complex (“the Complex”)

The Company, through Petrobras Energía, has a thirty-year concession for the generation of hydroelectric power in the Complex from August 1999.

To ensure completion of works within the term of the concession and a profitability to make the investment viable, the Energy Department granted the Company the amount of 25, to be taken out of a Unified Fund created by section 37 of Law No. 24,065. For the purpose of determining whether or not such amount should be repaid, a support price system was implemented for the electric power to be generated by the Complex and sold on the Wholesale Electric Power Market.

Such support price system will be applied over a ten-year term, which will be divided into two consecutive five-year periods, as from December 1999. In order to implement such system, an Annual Monomial Support Price (AMSP) was set in the amounts of $/Kwh 0.021 and $/Kwh 0.023 for the first and second period, respectively. In order to determine the amount to be reimbursed, every year of the above mentioned term, the difference between the Annual Average Monomial Price of the Complex bars generation, and the aforesaid AMSP, valued in terms of the electric power generated by the Complex during such year will be determined.

F - 39

Due to the depressed selling prices set for the energy generated by the Complex, and the prices estimated for the remaining term of the initial five-year period, and considering that the above support price system entails a profitability reassurance to make the investment practicable, as of December 31, 2004, the Company accrued income of 20.

12. Financing

The detail of debt as of December 31, 2004 and 2003, is as follows:


	2004		2003
	Current	Non-current	Current	Non-current
Financial institutions	283	933	923	293
Notes	1,292	4,821	2,214	4,474
Investment agreement with IFC	67	345	61	331
Related companies (Note 19)	10	149	6	—
Purchase of 10% interest in Distrilec - remaining balance	—	—	—	—

	1,652	6,248	3,204	5,098

I. Petrobras Energía’s Global Programs of nonconvertible notes

a) US$ 2.5 billion program

The Regular Shareholders’ Meeting of Petrobras Energía held on April 8, 1998, approved the establishment of a global corporate bond program for up to a maximum principal amount outstanding at any time of US$ 1 billion or its equivalent in other currency. Later, the Regular and Special Shareholders’ Meeting held on June 20, 2002, authorized the increase of the maximum program amount outstanding at any time during the effectiveness of the program up to US$ 2.5 billion or its equivalent in other currency.

The Regular and Special Shareholders’ Meeting of Petrobras Energía held on July 8, 2003, extended the term of the Petrobras Energía Medium-Term Corporate Bonds Program for five years counted as from May 5, 2003, or the maximum term that may be allowed under any new regulations that might become applicable in the future.

The establishment of the Program was authorized by Certificate No. 202, dated May 4, 1998, and Certificate No. 290, dated July 3, 2002 and Certificate No. 296 dated September 16, 2003, of the CNV.

As of December 31, 2004, there remained outstanding the following classes of corporate bonds under the medium-term global program:

Class B, for US$ 5 million, payable in a single installment in May 2006, at a 9% fixed annual rate.

Class C, for US$ 220 million, with the last maturity in July 2005, which will be amortized in quarterly installments as from 2004. As of December 31, 2004, the amount of US$ 63 million is effective in this class. Class C notes shall accrue interest at LIBOR plus 3%. As to this transaction, the Company arranged an interest rate swap, fixing the annual interest rate at 7.93%. In April 2005, the Company settled these payables in advance.

Class F, for a face value of US$ 64.4 million maturing in August 2005, at a 7.875% annual rate.

Class G, for a face value of US$ 250 million maturing in January 2007 at a 9% annual rate.

Class H, for a face value of US$ 181.5 million maturing in May 2009, at a 9% annual rate.

Class I, for a face value of US$ 349.2 million maturing in July 2010, at a 8.125% annual rate.

Class K, for a face value of US$ 286.3 million, quarterly payable as from January 2004 and with final maturity date in October 2007, accruing interest at three month LIBOR per annum, plus 4%. As of December 31, 2004, the amount of US$ 223 million is effective in this class. As of the date of the issuance of these financial statements, the Company settled these payables in advance.

F - 40

Class M, for a face value of US$ 181.8 million, quarterly payable as from January 2004 and with final maturity date in October 2007, accruing interest at three month LIBOR per annum, plus 4.75%. As of December 31, 2004, the amount of US$ 142 million is effective in this class. As of the date of the issuance of these financial statements, the Company settled these payables in advance.

Class N, for a face value of US$ 97 million, with principal amortized in two installments, the first – equivalent to 9.9099% of nominal value – settled on the same day of issuance, January 24, 2003, and the remaining due in June 2011, accruing interest at nine-month LIBOR plus 1%. As of December 31, 2004, the amount of US$ 87 million is effective in this class.

Class Q, for a face value of US$ 3.98 million, with two principal amortization installments: the first equivalent to 10% of the face value settled on the same day of issuance, April 25, 2003, and the remainder in April 2008, at an interest rate of 5.625%. As of December 31, 2004, the Company is carrying US$ 170,000 of such issue in its own portfolio.

Class R, for a face value of US$ 200 million, with due in October 2013, accruing interest at 9.375%.

b) US$1.2 billion program

As of December 31, 2004, under the medium-term Global Program which term for the issuance of new notes expired in June 1998, the Sixth Series is outstanding in the amount of US$ 32.6 million, the only installment of which becomes due in July 2007 and bears interest at a 8.125% fixed annual rate.

The proceeds from all issuances of the all the corporate notes under both programs, were used to refinance liabilities, increase working capital, for capital expenditures of fixed assets located in Argentina or capital contributions to affiliates.

The obligations arising out of issuances are disclosed net of the issuance discounts to be accrued. The deferred costs for such issuances are included in Prepaid expenses and interests within “Other receivables” account.

II. Cross default covenants

Class F, G, H, I, N, Q and R notes include cross default covenants, whereby the Trustee, as instructed by the noteholders representing at least 25% of the related outstanding capital, shall declare all the amounts owed due and payable, if any debt of the Company or its significant subsidiaries is not settled upon the maturity date, provided that those due and unpaid amounts exceed the higher of US$ 25 million or 1% of Petrobras Energía’s shareholders’ equity upon those maturities, and that the default has not been defeated or cured within 30 days after the Company has been served notice of the default.

Class K and M notes include cross default covenants, whereby the Trustee, as instructed by the noteholders representing at least the majority of the respective outstanding capital, shall declare all the amounts owed due and payable, if any debt of the Company or its significant subsidiaries is not settled upon the maturity date, provided that those due and unpaid amounts exceed the higher of US$ 15 million or 1% of Petrobras Energía’s shareholders’ equity upon those maturities. As of the date of the issuance of these financial statements, the Company settled these payables in advance, so the above-mentioned cross default covenants no longer apply.

Class C notes issued under the US$2.5 billion program, as well as certain loan agreements, include cross default covenants, whereby the Trustee or the creditor bank, as appropriate, shall declare all the amounts owed as due and payable, if any debt of the Company is not settled upon the maturity date, provided that those due and unpaid amounts exceed the amount of US$ 10 million or 1% of Petrobras Energía’s shareholders’ equity in relative terms, upon those maturities. In April 2005, the Company settled these payables in advance, so the above-mentioned cross default covenants no longer apply.

F - 41

The remaining outstanding amount of the Sixth Series and Class B notes does not include cross default covenants, as unanimously decided by the special meetings held by the noteholders of those series on July 10, 2002.

III. Covenants

Since the issuance of Class K and M corporate bonds as well as other medium-term credit instruments (“the refinanced debt”), effective as from October 2002, and while a portion of such payables remained outstanding, Petrobras Energía has been subject to the compliance with a series of restrictions and commitments that included, among others, restrictions on the payment of dividends, capital investments, granting encumbrances, incurring in a new debt, the financial debt maturity schedule and limits to the consolidated financial indebtedness level.

As from April 2005, as a result of the full redemption of refinanced debt, the mentioned restrictions and commitments no longer apply.

IV. Financing of the Genelba Electric Power Generation Plant

The investment was financed through loans granted by international banks, which are being semiannually repaid from June 1998 over a period of 10 years. They may be paid in advance at any time, at Petrobras Energía’s discretion, and the remainder with the use of cash inflows. The loans may be prepaid at any time at Petrobras Energía’s option. As of December 31, 2004, the amounts outstanding from the financing of the plant were US$ 36 million, of which US$ 15 million is related to a contract which contains restrictive covenants, including restriction on selling or leasing more than 40% of the plant during the year in which the debt is outstanding.

V. Loan from International Finance Corporation (“IFC”) to Innova S.A. (“Innova”)

In October 1999, Innova executed a long-term loan agreement for US$ 80 million comprising tranches A and B of US$ 20 million and US$ 60 million, respectively. Amortization of principal will be as from June 2002, in 16 and 12 semiannually installments for tranches A and B, respectively. The applicable interest rate is LIBOR plus 3.25%.

The loan was secured by a mortgage on certain real property owned by Innova. In addition, unless certain conditions indicated in the loan agreement occur, Petrobras Energía guarantees its timely payment.

The IFC financing was completed by issuing preferred stock in the amount of US$5 million, fully paid-in during December 1999.

Certain covenants in the agreement prescribe restrictions in relation to dividends, investments in property, plant and equipment, restrictions upon the transfer, sale or rental of an important part of the assets, incurring long-term debt and providing mortgages. In addition, Petrobras Energía directly or through its subsidiaries, is committed to retain a 51% participating interest in Innova’s common stock.

The funds provided by the IFC were used to construct styrene and polystyrene plants in the Brazilian State of Rio Grande do Sul.

F - 42

VI. Payable for purchase of 10% interest of Distrilec

In June 1999, the Company, through its subsidiary Petrobras Bolivia International S.A., or PBI, acquired a 10% interest in Distrilec for an amount of US$ 101 million. The related payment was documented through a promissory note issued by PBI and secured by Petrobras Energía for the benefit of Entergy, with a maturity date in June 2002, at a 7% annual fixed rate. The note was later transferred to a financial trust located in Argentina through a securitized transaction, whereby bonds denominated in US dollars were issued and placed among Argentine investors.

Upon the promissory note maturity date, the Company and holders of trust certificates represented contrary interpretations with respect to the application to that debt of measures related to the translation into pesos (dedollarization) of payable obligations stated in foreign currencies issued under the Public Emergency and Foreign Exchange System Reform Law. At the request of the trustee, the Company started a mediation process to reach an agreement that documents the debt payment. This agreement expired without fulfilling its terms and conditions.

In November 2002, PBI irrevocably transfered all its rights and duties by virtue of the promissory note issuance to Petrobras Energía. Afterwards, on January 8, 2003, Petrobras Energía launched a Class “N” corporate bonds swap offer for a face value amounting up to US$ 101 million maturing in 2011, for all and each of the debt securities, stating that such offer was not a waiver or release from any of the Company’s rights in favor of the conversion of the abovementioned promissory note in Argentine pesos, or an acknowledgement or acceptance of any claim against such conversion.

Petrobras Energía received and accepted offers from debt security holders equivalent to 96.0594% of their outstanding face value. To offset this, and according to the conditions of the swap offer, Petrobras Energía S.A. issued class “N” corporate bonds amounting to a face value of US$ 97 million (see Note12.I.a). Given that the terms and conditions of the new debt instruments differ substantially from the original as regards both maturity and financial expense, upon refinancing, the Company recognized a new liability that has been measured in accounts on the basis of the best estimate of the discounted value of total amount payable. On such a basis, the original liability was reduced to US$ 77 million, giving rise to a gain of 34.

On April 16, 2003, the Company launched an offer to exchange every and all trust debt securities that had not been entered into the previous exchange for Class Q Corporate Bonds for an aggregate face value of up to US$ 4 million and maturing in 2008. Due to the offers received, the Company issued Class Q bonds for a nominal value of US$ 3.98 million (see Note12.I.a).

As of December 31, 2004, the Company offset the receivable resulting from its trust debt-securities against the payable resulting from the promissory note issued by PBI, which amounted to about US$ 100 million, considering that it has the financial capacity to settle it in full.

VII. Loan agreement signed between Petrobras Energía Venezuela S.A. and the IFC

In July 2003, Petrobras Energía Venezuela S.A., a wholly-owned subsidiary of Petrobras Energía, executed loan agreements in the amount of US$ 105 million with the IFC.

The loan is primarily composed of a Tranche A for US$ 80 million, maturing in a term of eights years and a half, including one grace period, payable semiannually and at an annual LIBO nominal rate + 4.75%, and a Tranche C for US$ 25 million, maturing in a term of 9 years and a half, at an annual LIBO nominal rate + 1.50%.

The funds obtained from this loan were used in executing the investment plan related to the development of the Acema, Mata, La Concepción and Oritupano Leona areas, in Venezuela.

VIII. Edesur Indebtedness

Certain loan agreements entered into by Edesur S.A. contain “cross-default” covenants, whereby creditor banks are entitled to declare all amounts owed to be due and payable if any debt item is not paid when due and the outstanding past due amounts exceed the respective amounts set forth in the agreements.

Some of the abovementioned agreements include “cross-acceleration” covenants, whereby the creditor banks are entitled to declare all amounts owed to be due and payable in the event of Edesur S.A. being subject to the acceleration of any other debt in circumstances provided for in such agreements.

F - 43

Also, some agreements include restrictive clauses that basically consist in meeting certain financial ratios. As of December 31, 2004, Edesur meets with such ratios.

Additionally, loan agreements do not establish any type of guarantee.

On October 5, 2004, Edesur – under its medium-term debt-securities issuance program – issued Corporate Notes denominated in pesos for a value of 120 in two series: Class 5, with a term of 18 months, and Class 6, with a term of 3 years.

The Class 5 corporate notes were issued for a nominal value of 40 at an issuance price of 97.32% with a fixed coupon of 8.5% per annum, while Class 6 was issued for a face value of 80, accruing interest at a variable rate calculated on the basis of a reference rate published by the Central Bank of Argentina, with a minimum of 4% per annum, plus a differential margin of 3% per annum.

Edesur will apply the net proceeds from this issuance to refinancing its financial liabilities.

IX. CIESA and TGS indebtedness

As of December 31, 2004, CIESA’s financial debt relates to the issuance of corporate bonds with a par value of up to US$ 220 million and with original maturity in April 2002.

In the wake of the new Argentine macroeconomic situation, as from the enactment of Public Emergency Law (see Note 9.III), CIESA did not pay the principal and the last interest installment upon maturity or cap and collar agreements. Consequently, CIESA´s indebtedness included pursuant to the proportional consolidation, has been disclosed in the “Short-term debt” line.

CIESA’s is currently negotiating with the creditors to agree to extend the term to fulfill the related payment. No pledges have been made by CIESA’s shareholders to provide financial aid. In order to create the flexibility necessary to make progress in restructuring CIESA’s financial debt, CIESA’s shareholders executed, in April 2004, the Framework Agreement described in Note 9.I b).

On February 24, 2003, TGS started a global rescheduling process of US$ 1.027 billion of its current financial indebtedness, which represents almost the entire debt.

On May 15, 2003, as TGS could not meet the required majority, it withdrew the referred rescheduling proposal and simultaneously announced the postponement of the interest payment.

On October 1, 2004, TGS made a new restructuring proposal covering US$ 1.018 billion of its financial debt, which ended on November 12, 2004. By such date the debt presented for swapping amounted to US$ 1.016 billion, which represents about 99.76% of TGS’s financial debt. The creditors that accepted the proposal received a cash payment equivalent to 11% of the outstanding principal amount and new debt securities for the remaining 89% of the outstanding principal amount, structured into two tranches, A and B, with amortization terms of 6 and 9 years respectively, accruing interest rates ranging from 5.3% to 10 %.

In addition, the creditors that accepted the debt swap received a cash payment of the accrued and outstanding interest on the previous debt, calculated at the interest rate stipulated by contract for each instrument up to December 31, 2003, and at an annual rate of 6.18% from January 1 to December 15, 2004. The interest payment was considered full settlement of any claim for interest owed, including punitive interest.

Pursuant to the financing agreements executed in connection with the debt restructuring, TGS is required to comply with a series of restrictions, which include, among others, restrictions on debt issuance, new investments, sale of assets, payment of technical assistance fees and dividend distribution.

F - 44

X. Detail of long-term debt

Long-term debt as of December 31, 2004, is made up as follows:


Type	Amount	Currency	Annual interest rate
	(In millions of pesos)
Financial institutions	29	US$	Libo+0.125
	18	US$	Libo+0.75
	12	US$	Libo+2.00
	69	US$	Libo+4.65
	30	US$	Libo+3
	30	US$	Libo+2.35
	56	US$	Libo+3.1
	12	US$	6.65%
	10	US$	5.64%
	10	US$	5.20%
	23	US$	5.85%
	24	US$	5.24%
	5	$	9.70%
	16	US$	5.44%
	59	US$	3.55%
	3	US$	7.65% to 9.00%
	262	US$	5.30% to 7.50%
	265	US$	7.00% to 10.0%

Investment agreement with IFC	89	US$	Libo+3.25
	181	US$	Libo+4.75
	75	US$	Libo+1.50

Related companies (See Note 19)	149	US$	7.50%

Notes
Serie Sixth	97	US$	8.125%
Class B	15	US$	9.00%
Class G	745	US$	9.00%
Class H	541	US$	9.00%
Class I	1,041	US$	8.125%
Class K	444	US$	Libo+4
Class M	282	US$	Libo+4.75
Class N	233	US$	Libo+1
Class Q	10	US$	5.625%
Class R	600	US$	9.375%
Serie 6	39	$	7.00%
Serie 5	19	$	8.50%
Serie A	375	US$	5.30% to 7.50%
Serie B-A y B-B	380	US$	7.00% to 10.00%

	6,248

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The maturities of long-term debt as of December 31, 2004, are as follows:


From 1 to 2 years		790
From 2 to 3 years		1,470
From 3 to 4 years		369
From 4 to 5 years		777
Over 5 years		2,842

		6,248

13. Income tax and deferred tax

The Company’s provision for income tax was comprised of the following:


	2004		2003		2002
Current	(64	)	(40	)	(66	)
Deferred tax gain - (loss)	262		22		(16	)

Total income tax	198		(18	)	(82	)

The tax effect of the significant differences between the book value and the tax value of the Company´s assets and liabilities and tax loss carryfowards are as follows:


	2004		2003
Deferred tax assets
Tax loss carryfowards and other tax losses	1,899		1,898
Non-current investments	—		6
Reserve for contingencies	40		77
Pension plan obligations	3		7
Derivates	191		216
Receivables	11		10
Other	72		66

Valuation allowance (Note 18.a)	(1,503	)	(1,786	)

Deferred tax liability
Revenue recognition	(44	)	(33	)
Current investments	—		(14	)
Property, plant and equipment	(185	)	(137	)
Prepaid expenses	(15	)	(25	)
Timber	—		(16	)
Discounted assets and liabilities	—		(11	)
Non-current investments	(83	)	(124	)
Other	(2	)	(12	)

	384	(1)	122

(1)	501 are included in the “Other receivables” line and 117 are disclosed in the non-current “Payroll and social security taxes” line.

F - 46

The reconciliation of tax provision at the statutory rate of 35% to the tax provision, (before taxes) and the minority interest in the subsidiary’s earnings (losses), is as follows:


	2004		2003		2002
Income before income tax and minority interests in the subsidiaries’ income	519		557		(1,525	)
Statutory tax rate	35	%	35	%	35	%

Statutory tax rate applied to income for the period	182		195		(534	)
Permanent differences at income tax rate
- Equity in losses of non-current investments	(186	)	(59	)	85
- Inflation adjustment	127		116		(26	)
- Changes in allowances for tax loss carryforwards	(283	)	(525	)	1,176
- Losses (gains) in foreign subsidiaries	(67	)	277		(639	)
- Tax on minimum presumed income	—		—		19
- Other	29		14		1

	(198	)	18		82

Tax loss carryforward and deferred losses include the following items and may be used through the dates indicated below:


Items	2004	2003	2002
General tax loss carryforward	1,732	1,691	1,867
Deferred losses	167	207	279

	1,899	1,898	2,146


Use up to	2004	2003	2002
2004	—	—	58
2005	—	15	27
2006	—	43	54
2007 and thereafter	1,899	1,840	2,007

	1,899	1,898	2,146

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14. Contingencies, allowances and environmental matters

The movements of reserves for contingencies and allowances were as follows:


Account	Balances at beginning	Net increase (decrease)		Balances at end
Deducted from assets:

Current
For investments (a)	23	(23	)	—
For doubtful accounts	42	31		73
Tax loss carryforwards	69	(69	)	—
Deferred losses	66	(66	)	—
Inventories’ obsolescence	4	(2	)	2

	204	(129	)	75
Non-current
For other receivables
Tax loss carryforwards	1,503	(167	)	1,336
Deferred losses	148	19		167
Tax on minimum presumed income (a)	72	—		72
For investments (a)	10	—		10
For property, plant and equipment (a)	383	4		387
Inventories’ obsolescence	2	—		2

	2,118	(144	)	1,974

TOTAL 2004	2,322	(273	)	2,049

TOTAL 2003	2,299	23		2,322

Included in liabilities:

Current
Labor and commercial contingencies	44	(13	)	31

	44	(13	)	31
Non-current
Labor, commercial and other contingencies	75	(4	)	71

	75	(4	)	71

TOTAL 2004	119	(17	)	102

TOTAL 2003	114	5		119

(a)	See Notes 9 and 10.

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a) Environmental matters

The Company is subject to extensive environmental regulation at both the federal and local levels in Argentina and in other countries in which it operates. Petrobras Energía Participaciones´s management believes that its current operations are in material compliance with applicable environmental requirements, as these are currently interpreted and enforced, including sanitation commitments assumed. The Company and its subsidiaries have not incurred any material liabilities for pollution as a result of their operations to date. Petrobras Energía Participaciones undertakes environmental impact studies for new projects and investments and, to date, environmental requirements and restrictions imposed on such new projects have not had material adverse impact on Petrobras Participaciones’s business. There are no significant lawsuits or administrative proceedings against the Company related to environmental issues.

The Company conducts its business considering excellence in Safety, Health and Environmental matters as a cornerstone of its corporate strategy.

With its Quality Assurance, Safety, Health and Environmental Protection policies, the Company commits itself to ensuring the quality of its products and services, preserving the safety and health of its personnel, contractors and neighboring communities and protecting the environment.

The Company has been a pioneer in environmental practices certification (ISO 14001) both in Argentina and in the oil industry worldwide. The Company has over 90 Environment (ISO 14001), Quality (ISO 9001) and Security & Occupational Health (OHSAS 18001/IRAM 3800) certifications with regular external audit procedures held by third parties audit firms.

During fiscal year 2003, the Company engaged the services of an international consulting company to perform an environmental audit of its operations. Such audit’s final report identified a set of actions necessary to put into fully practice the standards of its Occupational Health and Safety and Environmental Protection Policy. On such basis, the Company will make investments amounting to about US$ 23 million, which include improvements in its prevention systems and production facilities. In addition, the Company will implement a variety of corrective and remediation measures, in relation to which the Company recorded a loss of 45 for the fiscal year ended December 31, 2003. Including the prior amount, the total expenses incurred by the Company for fiscal year 2003 amounted to 58.

In April 2004, the Company launched its new Quality, Safety, Health and Environmental Protection policies (designated by the Spanish initials “SMS”), each of which mark a step forward from the standards in effect until then. The new SMS policies incorporate leading edge concepts such as eco-efficiency, and operations sustainability and life cycle.

In this context, the Company performed an environmental study, supplementary to the environmental audit performed in fiscal 2003. Such study found that, under the new SMS policies, remediation measures were required. Accordingly, the Company booked a loss of 33. The charges to income for remediation expenses over fiscal year 2004 totaled 51.

b) TGS stamp tax

As of the date of issuance of these financial statements, TGS is party to claims by the Tax Bureaus of the Provinces of Río Negro and La Pampa for stamp tax purportedly due on the contracts and service provision offers between TGS and its customers. The total amount claimed is 506 (including fines and interest calculated as of the date of each claim).

In both cases, TGS filed administrative appeals before the respective Provincial Tax Bureaus. Subsequently, TGS petitioned the Supreme Court of Justice of the Nation (“SCJN”) for declaratory judgments on the legitimacy of each of the provincial claims. The SCJN granted the precautionary measures requested and ordered each province to abstain from any acts aiming to collect such stamp tax until such court has ruled on the basic issue. As of the date of these financial statements, the Río Negro Provincial Tax Bureau has rejected, in the administrative proceedings, the appeals filed; therefore, TGS is awaiting the final decision by the SCJN.

F - 49

Nevertheless, TGS´s Management considers that the contracts and transportation offers are not subject to the tax in question. Should such instruments eventually be considered taxable, TGS understands that such event should be considered as a change in the interpretation of a tax rule and, hence, the effects should be passed on to the rates, as provided for in the regulations specifically applicable to such cases. The ENARGAS has stated that the provincial stamp tax claims lack legal basis and, therefore, are illegitimate.

Similar claims have been made by the Tax Bureaus of the provinces of the Santa Cruz, Chubut and Neuquén, and the latter also claims stamp tax on the Share Transfer Agreement executed when the former federal-government-owned company Gas del Estado was privatized and on the Technical Assistance Agreement.

In April 2004, the SCJN declared the tax claim by the province of Santa Cruz to be inappropriate and inapplicable, thus laying an important court precedent for the resolution of the claims made by the other provinces, which are similar to that made by the province of Santa Cruz.

On June 7, 2004, the Neuquén Provincial Executive issued Decrees Nos. 1,133 and 1,134, which accept the appeals by TGS regarding the Gas del Estado transfer agreement and the Technical Assistance Contract, and thus the provincial tax authorities laid their claims to rest in such cases. Both Decrees have been incorporated into the file of the case pending before the SCJN.

In July 2004, the Chubut Provincial Tax Bureau, in administrative proceedings, by Resolution No 198/04, withdrew its claim, in view of the SCJN judgment. Such resolution was ratified by the Chubut Province Ministry of Economy and Public Credit through Resolution No. 143 of August 20, 2004, which accepted the appeals filed by TGS.

Although no assurance can be given, TGS Management believes it has strong arguments for defense against the claims mentioned above and that any obligation that might eventually be assessed will not have significant adverse effects on the Company’s results of operations or financial position.

c) Fixed charges for connection with Transener

The ENRE authorized, by Resolution No. 1650/98, an increase in the connection charge, in full compliance with effective rules and regulations. Many generation companies filed administrative appeals before the Energy Department seeking that such increase be reversed; the Energy Department rejected such appeals. Only Central Térmica Güemes S.A. filed an appeal directly with the Federal Administrative-Contentious Court of Appeals, which decided in favor of the request. Transener and the ENRE filed an extraordinary appeal before the Supreme Court of Justice of the Nation. On June 27, 2003, the Court of Appeals admitted the motion for appeal before the Supreme Court. The record of proceedings was remitted to the Supreme Court of Justice of the Nation. In late December the Supreme Court remitted the record of proceedings to the Procurador (Head Legal Counsel for the Government), whose office is currently analyzing such proceedings.

As reported by the legal counsel, Transener considers that the final outcome of this issue will not give rise to any significant obligation. Therefore, no provisions have been booked in this regard.

d) Tax issues

The AFIP (Argentine Federal Public Revenues Administration) has filed a claim for collection of the tax on the transfer of fuel which, according to the tax claim, would tax the import of benzene without considering its petrochemical destination. The aggregate amount claimed, including interest, is 114. The Company’s Management and legal advisors believe there are legal reasons to hold that such a claim is not valid, and has filed a motion in Court challenging the legal basis of the same. The Company’s position is grounded in the law regulating this tax which provides exemptions for the transfer of fuels, whether for a valuable consideration or not, having as destination the chemical and petrochemical industries, without considering whether the fuel is acquired within the country, imported or produced by the Company.

The Company holds others interpretative differences with the AFIP and provincial tax authorities about taxes applicable on oil and gas activity. Company Management and its legal advisors estimate that the outcome of the matters previously discussed will not have significant adverse effects on the Company’s financial position or results of operations.

F - 50

e) Value-added tax on operations in Ecuador

As of December 31, 2004, the Company -as is the case of many other companies producing and exporting oil in Ecuador- has a tax credit from Ecuadorean tax authorities (“SRI”), which is based on the VAT to be reimbursed upon exporting oil. The SRI has issued notice that it will not make such reimbursement because it interprets that such item had already been considered when determining the parties respective shares of the oil produced. Such resolution has been appealed before the Tax Court, which to date has not issued any ruling in this respect. On July 1, 2004, an international arbitration award was passed in favor of one of the oil-producing and exporting companies in dispute with the Ecuadorean Government in this connection. The international arbitration award established that the VAT in question should be reimbursed. The Ecuadorean Government has objected such arbitration and considered it void. On August 11, 2004, the Ecuadorean National Congress passed a VAT interpretation law, which provides that the reimbursement of such tax is not applicable to the oil industry. According to the Company’s management and legal advisors, it is likely that such VAT interpretation law will be declared unconstitutional; in such a case, the VAT reimbursement sought by the Company would probably take place.

In the opinion of its legal advisors, the Company is entitled to the VAT reimbursement, whether by SRI or by a renegotiation of its share of the oil produced, given that, when the respective shares of oil production were stipulated, the exports of goods and the rendering of services were not subject to VAT. Should the final outcome be adverse to the Company, the value of the VAT accounts receivable should be booked under PP&E in an amount of about US$ 2 million, and under losses, in an amount of about US$ 12 million.

15. Contractual commitments, warranty bond, suretyships and guarantees granted

The warranty bonds, suretyships and guarantees as of December 31, 2004, which are not disclosed in the remaining notes, amount to 74.

In addition, as of December 31, 2004, the Company had the following contractual commitments:


	Total (units)	Total (millions of Ps)	Until
Purchase Commitments
Ship or pay agreement with OCP (in millions of bbls.) (1)	389	2,413	2018
Long–term service agreement	—	88	2007
Gas transportation agreement with TGS (in MMm3)	10,674	402	2014
Bolivian gas transportation agreement (in MMm3)	5,213	180	2017
Ethylene (in thousands of tons)	337	714	2015
Benzene (in thousands of tons)	930	2,425	2015

Sales commitments
Natural gas (in MMm3)	19,729	1,928	2019
Crude oil (in millions of barrels)	4	370	2020
Styrene (in thousands of tons)	52	151	2007
Electric power (in MWh)	587,291	26	2007
LPG (in thousands of tons)	32	31	2005

(1)	Net of transportation capacity sold to third parties (see Note 9.IV)

F - 51

16. Contribution, benefit pension and stock option plans of Petrobras Energía

a) Contribution

and benefit pension plans

•

Defined contribution plan:

The Company sponsors a defined contribution plan that applies to all employees of Petrobras Energía with salaries above a specified level. Through this plan, the Company matches contributions by employees which are in excess of legally required amounts. Such contributions are charged to expenses in the year they are paid. Due to the significant changes in the Argentine economic scenario and the uncertainties posed by the Argentine economic conditions, as from January 2002, Petrobras Energía has suspended, for the moment, this benefit. Such benefit will be reestablished as soon as there is a social security savings means considered adequate to such end.

•

Defined benefit pension plan:

All employees of the Company, that take part without interruption in the defined contribution plan, that have joined the Company prior to May 31, 1995, and that qualify subject to certain years of service, are participants in this plan. The employee benefit is based on the last computable salary and years of service of the employee.

The plan is of a supplemental nature, that is to say the benefit to the employee is represented by the amount determined under the provisions of this plan, after deducting benefits payable to the employee under the contribution plan and the public retirement system, in order that the aggregate benefit to each employee from the three plans equals the one stipulated in the plan. Once retired, the employees are entitled to a fixed monthly payment.

The plan calls for a contribution to a fund exclusively by the Company and without any contribution by the employees, provided that they should make contributions to the retirement system for their whole salary. Assets of the fund were contributed to a trust and they are invested mainly in bonds, corporate bonds, mutual funds, and certificates of deposits. The Bank of New York is the trustee and Watson Wyatt is the managing agent. The Company determines the liability related to this plan by applying actuarial calculation methods. As of December 31, 2004, the most relevant actuarial information on the defined-benefits pension plan is as follows:


Plan assets	45
Projected benefit obligations	(68	)

Position covered	(23	)
Unrecognized actuarial loss	15

Net liability recognized	(8	)

According to its By-laws, the Company contributes to the fund through a contribution proposed to the Shareholders’ meeting by the Board of Directors and can increase up to a maximum of 1.5% of the net income for the year. During the years ended December 31, 2004, 2003 and 2002, the Board of Directors did not make use of this power.

Should there be an excess (duly certified by an independent actuary) of the funds under the trust agreement to be used to settle the benefits granted by the plan, the Company will be entitled to make a choice and use it, in which case it would have to notify the trustee thereof.

During the last quarter of 2002, Petrobras Energía admitted the advanced collection of this plan by benefiaries should they expressly state so. All the individuals that exercised the abovementioned option before February 13, 2003, have lost their rights to collect their retirement supplement, thus they are no longer plan beneficiaries.

F - 52

b) Stock

option plan

The Board of Directors of Petrobras Energía approved the establishment of a long-term incentive program for the purpose of aligning the interests of officers and shareholders.

As part of this program, the Board of Directors of Petrobras Energía approved the Plans for year 2001 (“2001 Plan”) and for year 2000 (“2000 Plan”), focused on senior officers of Petrobras Energía. Both plans consist in granting the right to exercise certain options to receive Petrobras Participaciones shares or the cash equivalent at market, as described below:

2001 Plan

5,364,125 options to receive the value arising from the positive difference between the average listed price of Petrobras Participaciones shares on the New York Stock Exchange during the 20 days prior to exercising the option and 1.64 Argentine pesos per share, for such number of shares (“appreciation rights”).

Regarding these options, 1,609,237 options may be exercised as from March 5, 2002, 1,609,238 options may be exercised as from March 5, 2003, and 2,145,650 options as from March 5, 2004. As of December 31, 2004 the exercised options amount to 3,617,026, almost integrally in cash.

ii.

596,014 options to receive the same number of shares at no cost for the beneficiary. These options may be exercised as from March 5, 2005 (“full value”).

Beneficiaries of this plan will be entitled to exercise their rights until March 5, 2007, from the dates mentioned above.

2000 Plan

3,171,137 options to receive the value arising from the positive difference between the average listed price of Petrobras Participaciones shares on the New York Stock Exchange during the 20 days prior to exercising the option and 1.48 Argentine pesos per share, for such number of shares (“appreciation rights”).

Regarding these options, 951,341 options may be exercised as from May 29, 2001, 951,341 options may be exercised as from May 29, 2002, and 1,268,455 options as from May 29, 2003. As of December 31, 2004 the exercised options amount to 2,455,465, almost integrally in cash.

ii.

352,347 options to receive the same number of shares at no cost for the beneficiary. These options may be exercised as from May 29, 2004 (“full value”). As of December 31, 2004 the exercised options amount 215,941, almost integrally in cash.

Beneficiaries of this plan will be entitled to exercise their rights until May 29, 2006, from the dates mentioned above.

The cost of such benefit is allocated on proportional basis to each year within the vesting years and adjusted in accordance with the listed price of the share. Accordingly, 6 and 8 were charged to operating expenses for the years ended December 31, 2004 and 2003, respectively.

17. Capital stock and restrictions on unappropriated retained earnings

As of December 31, 2004 the Company’s capital stock totaled 2,132 fully subscribed, issued, paid-in and registered shares. Changes in capital stock in the last three fiscal years:


	December 31,
	2004	2003	2002
Common stock – face value $	1	1	1

Class B: 1 vote per share	2,132	2,132	2,132

	2,132	2,132	2,132

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Since January 26, 2000, the Company’s Class B shares are listed on the Buenos Aires Stock Exchange and on the New York Stock Exchange.

Based on the change of control described in Note 21, on October 17, 2002, the BCBA (Buenos Aires Stock Exchange) authorized the conversion of class “A” common shares into the same number of class “B” common shares and their admission to listing. In addition, the CNV approved their public offer.

According to outstanding legal provisions, 5% of the net income of the fiscal year should be assigned to increase the balance of the legal reserve up to an amount equivalent to 20% of capital stock. Due to a decrease of 37 in the legal reserve approved by Special Shareholders’ Meeting held on April 4, 2003, the Company shall not distribute benefits until reimbursement of this amount to the reserve.

Under Law No. 25,063, any dividends distributed, in cash or in kind, in excess of the taxable income accumulated as of the year-end immediately prior to the respective payment or distribution date, will be subject to a thirty-five percent income withholding tax, as single and definitive payment. For this purpose, taxable income is deemed to be that resulting from adding up the income as determined under the general provisions of the income tax law and the dividends or income obtained from other corporations and limited liability companies not taken into account in determining the former for the same tax period or periods.

18. Other receivables, other liabilities, other operating income, and other expenses, net.


	2004			2003
	Current	Non-current		Current		Non-current
a) Other receivables

Joint ventures	25	—		53		—
Related companies (Note 19)	16	—		3		—
Tax credits	194	180		171		139
Deferred tax assets	13	1,991		251		1,657
Advisory services to other companies	13	—		40		—
Receivables from the sale of companies	—	9		89		16
Advances and hedge instruments premium	—	—		—		—
Letters of credit advances	121	—		175		—
Prepaid expenses and interest	41	23		66		22
Gas oil supply stability agreement	—	—		—		—
Other collaterals	64	—		23		—
Minimum presumed income tax accrual (Note 14)	—	(72	)	—		(72	)
Deferred tax allowance (Note 13)	—	(1,503	)	(135	)	(1,651	)
Other	142	20		125		20

	629	648		861		131


	2004		2003
	Current	Non-current	Current	Non-current
b) Other liabilities

Sale of capital fees (a)	—	—	107	—
Debt for investment in companies	11	—	16	—
Derivatives	385	—	102	98
Unified Fund - Basic Price of Electric Power (Note 11)	1	4	5	5
Related companies (Note 19)	12	—	—	—
Receivables in advance	54	—	34	—
Accrual for expenses
- Environmental remediation	43	44	—	66
- Other	41	—	52	—
Joint ventures	5	—	7	—
Innova preferred stock	—	15	—	17
Abandonment costs in oil & gas areas	—	91	—	73
Other	103	6	56	3

	655	160	379	262

(a)

In December 2001, the Company, through its subsidiaries Petrobras Energía Venezuela S.A. and Corod Producción S.A., assigned to an international lending institution a part of the capital fees (related to investments made by such companies) to be collected from PDVSA, as provided by the Oritupano Leona Consortium Service Agreement (see Note 6), in the amount of US$ 120 million. Capital fees assigned were

F - 54

settled by PDVSA in twelve quarterly, equal, and consecutive installments starting February 2002. This transaction was made, net of the discount made at LIBOR plus 2.75%. In order to guarantee the lending institution that PDVSA met the obligations under this agreement, the Company assigned an additional part of the capital fees collected from PDVSA in the amount of US$ 10 million.


	12/31/2004		12/31/2003		12/31/2002
c) Other operating expenses, net

Advisory services to other companies	35		36		37
Idle facilities	—		(7	)	(10	)
Environmental remediation expenses	(51	)	(58	)	(15	)
Taxes on bank transactions	(56	)	(45	)	(37	)
Contingencies	(28	)	(57	)	—
Oil transportation agreement with OCP	(184	)	—		—
Fundopem (a)	27		—		—
Other, net	(47	)	10		(3	)

	(304	)	(121	)	(28	)

(a)	Tax benefits enjoyed by Innova S.A. consisting in a partial reduction of certain taxes in accordance with a program of incentives that the Brazilian state of Rio Grande do Sul provides to companies located there.


	12/31/2004		12/31/2003		12/31/2002
d) Other expenses, net

Income (loss) from sale of:
- Pecom Agra S.A.	—		—		81
- Pecom Agropecuaria S.A.	—		—		27
- Cerro Vanguardia S.A.	—		—		123
- San Carlos Area	—		—		(37	)
- Forestry Activity	—		12		(153	)
- Catriel Oeste Area	—		(28	)	—
- Faro Vírgenes Area	—		(11	)	—
- Other assets	—		—		(5	)
Impairment of assets:
- Acema Area	(12	)	—		—
- Operations in Ecuador	—		(309	)	(63	)
- Gas Areas	—		(37	)	(44	)
- Hidroneuquén S.A.	—		—		(10	)
- Other assets	(20	)	(12	)	(8	)
Gain from AE (out-of-court composition with creditors) - Edesur S.A.	18		—		—
Debt to exploitation partners in Venezuela allowance	(15	)	(27	)	(42	)
Debt restructuring	(12	)	—		(17	)
Other, net	14		(9	)	(39	)

	(27	)	(421	)	(187	)

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19. Balances and transactions with related companies

The outstanding balances from transactions with related companies as of December 31, 2004 and 2003, are as follows:


	2004
	Current					Non-current
Company	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Loans	Trade Receivables	Investments	Loans
Oleoductos del Valle S.A.	—	—	2	—	—	—	—	—
Petroquímica Cuyo S.A.	—	1	—	—	6	—	—	—
Oleoductos de Crudos Pesados Ltd.	—	—	—	—	—	—	156	—
EG3 S.A.	247	8	18	9	—	—	—	—
Transportadora de Gas del Sur S.A.	1	—	3	1	—	—	—	—
Refinería del Norte S.A.	—	4	2	—	—	—	—	—
Petrobras International Finance Co.	11	—	—	—	—	—	—	—
Petrobras Bolivia Inversiones y Servicios	—	—	—	—	—	3	—	—
Braspetro	—	—	—	—	4	—	—	149
Other	4	3	5	2	—	—	—	—

Total	263	16	30	12	10	3	156	149


	2003
	Current				Noncurrent
Company	Trade Receivables	Other Receivables	Accounts Payable	Loans	Investment
Oleoductos del Valle S.A.	—	—	1	—	—
Petroquímica Cuyo S.A.	—	—	—	6	—
Oleoductos de Crudos Pesados Ltd.	—	—	—	—	127
EG3 S.A.	55	—	2	—	—
Transportadora de Gas del Sur S.A.	9	—	4	—	—
Refinería del Norte S.A.	—	3	—	—	—
Petrobras International Finance Co.	10	—	—	—	—

Total	74	3	7	6	127

The main transactions with affiliates for the years ended December 31, 2004, 2003 and 2002, are as follows:


	2004		2003		2002
Company	Purchases	Sales	Purchases	Sales	Purchases	Sales
Oleoductos del Valle S.A.	20	—	17	—	14	—
Transportadora de Gas del Sur S.A.	35	—	13	—	48	—
Refinería del Norte S.A.	106	—	55	1	60	—
Petrobras International Finance Co.	65	337	—	—	—	—
EG3 S.A.	105	514	26	196	—	1
Petroquímica Cuyo S.A.	—	—	—	—	—	5
Petrolera Entre Lomas S.A.	9	—	—	—	22	—
Petróleo Brasileiro S.A.	—	35	—	149	—	79
Empresa Boliviana de Refinación.S.A.	—	36	—	—	—	—
Petrolera Santa Fe S.R.L.	5	—	—	—	—	—

Total	345	922	111	346	144	85

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20. Business segment and geographic consolidated information

Petrobras Participaciones’s business is mainly concentrated in the energy sector, especially through its activities in oil and gas exploration and production, hydrocarbons marketing and transportation, refining, petrochemicals and electricity. According to this, the identified business segments are as follows:

The Oil and Gas Exploration and Production segment is composed of Petrobras Energía’s directly held oil and gas operations.

The Refining segment includes Petrobras Energía’s operations in Refinería San Lorenzo and its interests in Refinería del Norte S.A. and Empresa Boliviana de Refinación S.A.

The Petrochemical segment includes Petrobras Energía’s operations in PASA, and its interests in Innova S.A. and Petroquímica Cuyo S.A.

The Hydrocarbons Marketing and Transportation segment mainly includes the sale of gas produced in Argentina and of the liquids obtained from gas processing, together with the gas and LPG brokerage service activities, and its interest in Transportadora de Gas del Sur S.A., Oleoductos del Valle S.A. and Oleoducto de Crudos Pesados Ltd.

The Electricity segment includes Petrobras Energía´s operations in the Genelba plant and Pichi Picún Leufú Hydroelectric Complex, and its interest in Edesur S.A., Transener S.A., Enecor S.A., Yacylec S.A. and Hidroneuquén S.A.

Assets and results of operations related to the Central Services Structure, those not attributable to any given business segment, discontinued operations and intercompany eliminations are all disclosed together.

The applicable valuation methods to report business segment information are those described in Note 4 to these financial statements. The inter-segment transfers are made at market value.

The following information shows total assets, total liabilities and net income (loss) for each of the business segments identified by the Company’s management:


	2004
	Oil and Gas Exploration and Production	Refining	Petrochemical	Hydrocarbons Marketing and Transportation	Electricity	Corporate and Eliminations	Total
Total Assets	8,036	887	1,380	2,920	2,414	973	16,610
Total Liabilities	4,201	252	619	1,922	467	2,681	10,142


	2003
	Oil and Gas Exploration and Production	Refining	Petrochemical	Hydrocarbons Marketing and Transportation	Electricity	Corporate and Eliminations	Total
Total Assets	7,488	642	1,100	3,096	2,461	1,030	15,817
Total Liabilities	3,421	179	361	2,078	592	3,461	10,092

F - 57


	2004
	Oil and Gas Exploration and Production		Refining		Petrochemical		Hydrocarbons Marketing and Transportation		Electricity		Corporate and Eliminations		Total
Statement of income
Net sales
To third parties	1,953		1,541		1,857		812		811		—		6,974
Inter-segment	1,406		204		20		49		14		(1,693	)	—

	3,359		1,745		1,877		861		825		(1,693	)	6,974
Cost of sales	(1,594	)	(1,563	)	(1,503	)	(591	)	(628	)	1,669		(4,210	)

Gross profit	1,765		182		374		270		197		(24	)	2,764
Administrative and selling expenses	(212	)	(60	)	(123	)	(22	)	(75	)	(148	)	(640	)
Exploration expenses	(89	)	—		—		—		—		—		(89	)
Other operating (expenses) income, net	(282	)	(2	)	27		(1	)	—		(46	)	(304	)

Operating income (loss)	1,182		120		278		247		122		(218	)	1,731
Equity earnings of affiliates	23		58		16		18		(39	)	—		76
Other (expenses) income	(935	)	1		2		(202	)	(33	)	38		(1,129	)

Net income (loss)	270		179		296		63		50		(180	)	678


	2003
	Oil and Gas Exploration and Production		Refining		Petrochemical		Hydrocarbons Marketing and Transportation		Electricity		Corporate and Eliminations		Total
Statement of income
Net sales
To third parties	1,785		1,231		1,294		502		680		2		5,494
Inter-segment	944		71		—		19		11		(1,045	)	—

	2,729		1,302		1,294		521		691		(1,043	)	5,494
Cost of sales	(1,448	)	(1,179	)	(982	)	(281	)	(523	)	1,027		(3,386	)

Gross profit	1,281		123		312		240		168		(16	)	2,108
Administrative and selling expenses	(178	)	(57	)	(110	)	(34	)	(73	)	(107	)	(559	)
Exploration expenses	(196	)	—		—		—		—		—		(196	)
Other operating (expenses) income, net	(46	)	(12	)	(17	)	(1	)	17		(62	)	(121	)

Operating income (loss)	861		54		185		205		112		(185	)	1,232
Equity earnings of affiliates	19		22		16		16		90		—		163
Other expenses	(943	)	10		(39	)	26		(19	)	(49	)	(1,014	)

Net income (loss)	(63	)	86		162		247		183		(234	)	381

F - 58


	2002
	Oil and Gas Exploration and Production		Refining		Petrochemical		Hydrocarbons Marketing and Transportation		Electricity		Corporate and Eliminations		Total
Statement of income
Net sales
To third parties	2,033		942		1,254		16		755		106		5,106
Inter-segment	773		66		—		—		11		(850	)	—

	2,806		1,008		1,254		16		766		(744	)	5,106
Cost of sales	(1,600	)	(944	)	(892	)	(11	)	(608	)	771		(3,284	)

Gross profit	1,206		64		362		5		158		27		1,822
Administrative and selling expenses	(224	)	(48	)	(123	)	(2	)	(92	)	(120	)	(609	)
Exploration expenses	(58	)	—		—		—		—		—		(58	)
Other operating (expenses) income, net	(22	)	(16	)	11		13		23		(37	)	(28	)

Operating income (loss)	902		—		250		16		89		(130	)	1,127
Equity earnings of affiliates	2		20		(10	)	(470	)	(239	)	59		(638	)
Other expenses	447		190		191		—		271		(3,167	)	(2,068	)

Net income (loss)	1,351		210		431		(454	)	121		(3,238	)	(1,579	)

The following information shows total assets and net sales by geographic area.


	2004
	Argentina	Venezuela	Bolivia	Peru	Brazil	Ecuador	Other	Eliminations		Total
Total Assets	10,605	3,638	483	830	680	288	86	—		16,610
Net sales	4,640	811	108	458	774	211	11	(39	)	6,974

	2003
	Argentina	Venezuela	Bolivia	Peru	Brazil	Ecuador	Other	Eliminations		Total
Total Assets	10,264	3,549	461	678	547	265	53	—		15,817
Net sales	3,804	594	108	374	502	115	2	(5	)	5,494

	2002
	Argentina	Venezuela	Bolivia	Peru	Brazil	Ecuador	Other	Eliminations		Total
Net sales	3,368	700	112	359	561	28	3	(25	)	5,106

21. Controlling Group

On October 17, 2002, Petrobras Participaciones, S.L., a wholly-owned subsidiary of Petrobras, acquired 58.6% of Petrobras Energía Participaciones’s capital stock from the Perez Companc Family and Fundación Perez Companc. Petrobras is a Brazilian company, whose business is concentrated on exploration, production, refining, sale and transportation of oil and its byproducts in Brazil and abroad.

F - 59

22. Summary of significant differences between accounting principles followed by the Company and applicable consolidated financial statement and US GAAP

The Company’s financial statements have been prepared in conformity with Argentine GAAP, except for the matters discussed in Note 3, which differ in certain respects from US GAAP. The differences are reflected in the amounts provided in Note 23 and relate to the items discussed in the following paragraphs.

a) Restatements of financial statements for general price-level changes

Prior to September 1, 1995, Argentine GAAP required the restatement of non-monetary assets and liabilities into constant Argentine pesos as of the date of the financial statements. Effective September 1, 1995, the CNV passed General Resolution No. 272 which provided that public companies would no longer be permitted to present financial statements that were adjusted to recognize the effect of inflation prevailing after such date. Therefore for periods ending subsequent to September 1, 1995, and until December 31, 2001, there had been no further restatement of non-monetary items or recognition of monetary gains and losses. This resolution matched Argentine GAAP so long as the change in the price index applicable to the restatement did not exceed 8% per annum.

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

On July 16, 2002, the Argentine government issued Decree 1,269/02, instructing the CNV and other regulatory authorities 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 664/03 rescinded the requirement that financial statements be prepared in constant currency. On April 8, 2003, the CNV issued Resolution 441/03 discontinuing inflation accounting as of March 1, 2003. Through Resolution No. 287/03 the CPCECABA also discontinued inflation accounting, but as from October 1, 2003. Accordingly, inflation accounting for the period from March 1, 2003 to September 30, 2003 is required by the CPCECABA but not allowed by the CNV.

In accordance with the above, our financial statements for the fiscal year ended December 31, 2002 were restated in constant pesos as of February 28, 2003 based on changes in the Argentine wholesale price index published by 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 general price variation or price variations for the products or services sold by us. After March 1, 2003, in accordance with the CNV standards described above, we no longer apply adjusting-for-inflation accounting.

Under US GAAP, general price level adjusted financial statements are not required. However, pursuant to the SEC’s rules, these adjustments are not removed when performing the reconciliation to US GAAP included in Note 23.

F - 60

b) Capitalization of exchange differences

Under Argentine GAAP, Resolution No. 3/2002 of the CPCECABA requires that exchange differences resulting from the peso devaluation on liabilities denominated in foreign currencies existing as of January 6, 2002, that are directly related to the acquisition, construction or production of property, plant and equipment, intangibles and long-term investments in other companies incorporated in Argentina, should be capitalized at the cost values of such assets, subject to a number of conditions.

As described in Note 4.p), as of December 31, 2004 and 2003, the Company records capitalized negative foreign exchange differences through its affiliates Citelec and CIESA.

Under US GAAP, foreign currency exchange gains or losses are recognized currently in income.

c) Accounting for peso devaluation in January 2002

Under Argentine GAAP, assets and liabilities in foreign currency as of December 31, 2001, have been valued at the P$1=U.S.$ 1 exchange rate that was in effect when transactions in the foreign exchange market were suspended. Accordingly, all the effects of the devaluation of the Argentine peso were recognized in the 2002 fiscal year.

Under US GAAP, such assets and liabilities in foreign currency should be valued at the exchange rate effective as of the date of reopening of the exchange market (January 11, 2002), which was P$ 1.70 to US$ 1.00. As a result, the effects of such devaluation were recognized in 2001 fiscal year, and included as an adjustment in the reconciliation of net income to US GAAP in Note 23, on the following line items: (a) Exchange differences and (b) US GAAP adjustments applicable to equity in earnings of affiliates.

Since no difference in exchange rates is verified as of December 31, 2002, the effects described above are reversed on 2002 fiscal year in the reconciliation presented in Note 23.

d) Income taxes

Both Argentine GAAP and US GAAP, require the liability method to be used to account for deferred income taxes. Under this method, deferred income tax assets or liabilities are recorded for temporary differences that arise between the financial and tax bases of assets and liabilities at each reporting date. The benefits of tax loss carry-forwards are recognized as deferred income tax assets, with an appropriate valuation allowance. A valuation allowance is provided when it is more likely than not (under US GAAP) or probable (under Argentine GAAP) that some portion or all of the deferred tax assets will not be realized.

However, Argentine GAAP and US GAAP may differ under certain circumstances in deferred income tax accounting. Under Argentine GAAP, differences between accounting and tax basis generated due to the recognition of the inflation effect on non-monetary assets, are accounted for as permanent differences for deferred income tax purposes. Under US GAAP, pursuant to Emerging Issues Task Force (EITF) No. 93-9, such differences are accounted for as temporary differences for deferred income tax purposes.

F - 61

e) Deferred charges

Under Argentine GAAP, costs such as organization and preoperating expenses may be deferred and amortized over the resultant period of benefit, under certain circumstances.

For US GAAP purposes these amounts are expensed as incurred.

f) Discounting of certain receivables and liabilities

Under Argentine GAAP, certain receivables and liabilities which are valued on the basis of the best possible estimate of amount to be collected and paid, are required to be discounted using the estimated rate at the time of the initial measurement.

Under US GAAP, receivables and liabilities arising from transactions with customers and suppliers in the normal course of business, which are done in customary trade terms not exceeding one year, are accounted for at nominal value, including accrued interest, if applicable.

g) Proportionate consolidation

Under Argentine GAAP, an investor is required to consolidate proportionally line by line its financial statements with the financial statements of the companies over which it exercises joint control. Joint control exists where all the shareholders, or only the shareholders owning a majority of votes, share the power to define and establish a company’s operating and financial policies on the basis of written agreements. In the consolidation of companies over which an investor exercises joint control, the amount of the investment in the company under joint control and the interest in its income (loss) and cash flows are replaced by the investor’s proportional interest in the company’s assets, liabilities, income (loss) and cash flows. Under Argentine GAAP, participations in Distrilec and CIESA qualify for proportionate consolidation.

Under US GAAP, participation in companies over which the investor exercises joint control is accounted for by the equity method and no proportional consolidation is allowed. However, pursuant to the SEC’s rules, differences in classification or display that result from using proportionate consolidation in the reconciliation to US GAAP, may be omitted if certain requirements are met. Such requirements are met by Distrilec but not by CIESA. As a result such differences corresponding to proportional consolidation of Distrilec are not presented in (see US GAAP Summarized Consolidated Data in Note 23). The proportional consolidation of CIESA for fiscal years 2004 and 2003 under Argentina GAAP has been reversed for purposes of the US GAAP reconciliation.

h) Accounting for business combinations

In July 2001, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations” and SFAS No. 142 “Goodwill and Other Intangible Assets”. These standards change the accounting for business combinations by, among other things, prohibiting the prospective use of pooling-of-interests accounting. In addition, SFAS No. 142 requires that, effective January 1, 2002, goodwill included in the carrying value of investments accounted for using the equity method of accounting, and certain other intangible assets deemed to have an indefinite useful life, cease amortizing. The new rules also require that goodwill and certain intangible assets be assessed for impairment using fair value measurement techniques. The Company has completed the annual impairment test of goodwill under the new standard and no additional adjustment was required. Business combinations performed before June 30, 2001 were accounted for under APB Opinion No. 16.

Under this past standard, goodwill was amortized on a straight-line basis over 40 years. As from January 1, 2002, goodwill is no longer amortized. All business combinations described below were performed before June 30, 2001.

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1) Petrobras Energía share exchange offer

Under US GAAP, the 2000 exchange offer was accounted for under the purchase method. The purchase price of 6,766, calculated based upon the market price of Petrobras Energía common stock, has been allocated to the identifiable assets acquired and liabilities assumed based upon their fair value as of the acquisition date. The excess of the purchase price over the fair value of the net assets acquired has been reflected as goodwill, which was amortized on a straight-line basis over 40 years until December 31, 2001. The purchase price has been allocated as follows:


Fair value of assets acquired	10,927
Goodwill	928
Fair value of liabilities assumed	(5,089	)

Total purchase price	6,766

Under Argentine GAAP, the accounting practice followed in 2000 fiscal year for nonmonetary exchange of shares was to recognize net assets at book value. Accordingly, issued shares of Petrobras Energía Participaciones S.A. were subscribed and accounted for at the book value of Petrobras Energía shares exchanged. Therefore, the US GAAP reconciliation of shareholders’ equity reflects the additional purchase price of Petrobras Energía capital stock, and the reconciliation of net income reflects the incremental depreciation, depletion, amortization, effective interest rate of liabilities and the related effects on the deferred income tax, as a result of the purchase price allocation mentioned above.

Beginning 2003 fiscal year, new Argentine GAAP pursuant to CNV Resolution N° 434 adopted the purchase method or the pooling of interests method, depending on the circumstances. However, such new standards are not applied on a retroactive basis.

2) Impairment of goodwill, property, plant and equipment, and equity in affiliates

As described above, the purchase price of Petrobras Energía has been allocated under US GAAP (but not under Argentine GAAP) to the identifiable assets acquired and liabilities assumed, based upon their fair values as of acquisition date, being the excess reflected as goodwill.

In 2001 fiscal year, the company recognized impairment charges of goodwill, Property, plant and equipment and equity in affiliates, to reduce the book value under US GAAP to fair values as of year-end, because such goodwill was not reflected under Argentine GAAP and book value of Property, plant and equipment, and equity in affiliates subject to impairment was higher under US GAAP, as explained above.

Impairment losses reflected under US GAAP in 2001 fiscal year were a consequence of the crisis in Argentina as described in Note 9.III), and included identified goodwill and equity in the affiliates: CIESA, TGS, Enron de Inversiones de Energía S.C.A. (“Edidesca”), Distrilec and Citelec. For purposes of determining impairment loss, fair values were estimated based on quoted market prices and other information available.

As of December 31, 2004 and 2003 under US GAAP the book value of the Company’s interest in Citelec, and CIESA accounted for under the equity method is nil. As of such dates, the book value of the interest in TGS amounts to 92 and 82, respectively, under US GAAP.

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3) Negative goodwill

For the Hidroeléctrica Pichi Picún Leufú S.A. (“HPPL”) acquisition, the fair value of assets was substantially represented by the acquired deferred tax assets, consisting of the tax effects of the difference between tax and book basis of fixed assets and net operating loss carry forwards, which were only recognized under US GAAP. To the extent of the excess of such deferred tax assets acquired over the consideration paid, a negative goodwill was recognized under US GAAP, which was amortized over a 30 year period beginning at the plant start-up of operations until December 31, 2001. As the Company adopted SFAS 142 effective January 1, 2002, such negative goodwill has been reversed, and a cumulative effect of change in accounting principle of 179 was recognized in 2002.

Neither the deferred tax assets nor the related negative goodwill and its reversal were recognized under Argentine GAAP.

4) Deferred charges in privatized companies acquired

In Argentina, it is an accepted practice for costs associated with voluntary retirement programs incurred in the acquisition and start-up of a privatized company to be recognized as a liability with a corresponding deferred asset, which is amortized over the period expected to be benefited.

The only difference between US and Argentine GAAP related to qualifying liabilities assumed is that for Argentine GAAP the offsetting purchase price is allocated to intangible assets and for US GAAP the offsetting purchase price is allocated to the fair value of the acquired assets which, in this case, is property, plant and equipment (“PP&E”). Therefore, the US GAAP reconciliation of net income and shareholders’ equity reflects in this respect, the difference between intangible asset amortization and property, plant and equipment depreciation.

i) Foreign Currency Translation

Under Argentine GAAP, all foreign operations are remeasured into U.S. dollars, which is the functional currency of operation of our foreign subsidiaries. Assets and liabilities, stated at current values are to be converted at the closing exchange rates, assets and liabilities measured at cost and revenues, expenses, gains and losses are to be converted at the historical exchange rates. Once the transactions are remeasured into U.S. dollars, assets and liabilities are translated into pesos at current rate, and revenues, expenses, gains and losses are translated at historical exchange rates. Resulting remeasurement and translation gain or loss is recognized currently in earnings in the “Financial income (expense) and holding gain (losses) account for fiscal year 2002.

In accordance with new accounting standards pursuant to CNV Resolution No. 434 as from fiscal year 2003, the translation gain or losses arising from the translation into pesos of the financial statements of all foreign operations is presented in the “Transitory differences—foreign currency translation” account, a separate component of the balance sheet.

Under US GAAP, gains or losses resulting from translation of U.S. dollars remeasured operations into pesos, are included as other comprehensive income, a separate component of shareholder’s equity.

A portion of the company’s foreign currency denominated debt portfolio is designated as a hedge of the volatility in the investments in foreign subsidiaries caused by changes in the functional currency exchange rates with respect to the peso. Exchange differences resulting from such debt are reflected in the “Transitory differences – Foreign currency translation” account under Argentine GAAP (for 2004 and 2003), and in the cumulative translation adjustment account under US GAAP (for all periods presented), thereby offsetting the translation gain or loss from hedged foreign subsidiaries’ net assets. Remaining exchange differences recognized in income differ from Argentine GAAP to US GAAP, as a result of differences in the book value of foreign subsidiaries’ net assets and resulting designated debt.

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j) Capitalization of interest costs on certain assets

Prior to January 1, 1993, Argentine GAAP did not require capitalization of interest charges relating to the financing of major projects under construction. Capitalization of interest as part of the acquisition cost of an asset is required under US GAAP. However, qualifying assets and eligible interest cost may differ under certain circumstances. Under US GAAP, foreign currency exchange gains or losses are excluded from interest cost base.

k) Depreciation of Property, plant and equipment

Under Argentine GAAP, depreciation of certain non-oil and gas fixed assets is accounted for by the Company by applying rates established for technical revaluation, which are based on engineering formulas.

Under US GAAP depreciation of such assets is calculated primarily using the straight-line method over the useful lives of the assets.

l) Minority interest

An adjustment to record the portion of all US GAAP adjustments attributable to minority interests in consolidated subsidiaries has been recorded.

m) Accounting for derivative instruments

Under US GAAP, SFAS No. 133 as amended by SFAS No. 137 and SFAS No. 138, requires that all derivative financial instruments be recognized in the consolidated balance sheets as either an asset or liability measured at fair value. SFAS No. 133 requires that changes in the derivative’s fair value be recognized in earnings unless specific hedge accounting criteria are met. For derivatives accounted for as hedges, fair value adjustments are recorded to earnings or other comprehensive income, a component of shareholders’ equity, depending upon the type of hedge and the degree of hedge effectiveness. For hedges classified as fair value hedges, adjustments are recorded through earnings with an offsetting, partial mark to fair value of the hedged item currently through earnings. For hedges classified as cash flow hedges, adjustments are recorded to other comprehensive income, and the gain or loss on the derivative is removed from equity and recognized in earnings in the same period as the loss or gain on the hedged cash flow.

Under Argentine GAAP from fiscal year 2003, changes in the fair value of derivatives accounted for as effective hedges are recognized in the “Transitory differences—Measurement of derivative financial instruments determined as effective hedge” account, a separate component of the balance sheet.

Prior to the adoption of new accounting standards in fiscal year 2003 pursuant to CNV Resolution No. 434, under Argentine GAAP there were no specific requirements governing derivatives accounting and the Company used hedge accounting for derivatives in fiscal year 2002 in conjunction with its risk management objectives.

Pursuant to special transition standards, the balances as of December 31, 2002 resulting from the recognition, measurement and booking of financial instruments, which qualified as effective hedges, were not adjusted retroactively.

n) Valuation of timber

Under Argentine GAAP, timber was valued at current values, recognizing their organic growth currently in income.

Under US GAAP, timber is valued at historical cost. Forestry operations were sold in 2002.

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o) Debt refinancing costs

Under Argentine GAAP, unamortized deferred costs incurred with third parties related to debt issuance are charged to expenses when such debt is restructured, while such costs related to the new debt are capitalized and amortized on a straight – line basis.

Under US GAAP, SFAS No. 15, SFAS No. 140 and related EITF issues require for debt restructuring not considered to be an “extinguishment”, the Company continues amortizing those costs related to the old debt and charge to expenses for debt restructuring direct costs.

p) Guarantor’s Accounting for Guarantees

Under US GAAP, FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, clarifies that at the time a company issues a guarantee, the company must recognize an initial liability for the fair value, or market value, of the obligations it assumes under that guarantee.

Under Argentine GAAP guarantees issued are generally not recognized as liabilities.

q) Accounting for stock option plans

For both Argentine and U.S. GAAP, the Company has accounted for these awards as liability awards similar to stock appreciation rights, pursuant to the guidance in FASB Interpretation No. 28, “Accounting for Stock Appreciation Rights and Other Variable Stock Option or Award Plans”. We, accordingly, recognized compensation expenses over the length of the award period, based on the market price of our shares at the time of recognition. Since Petrobras Energía’s stock option plan is a liability award, there is no differences in the reported net income and earning per share for the years 2004, 2003 and 2002 based on SFAS No. 123, “Accounting for stock –based compensation”, amended by SFAS No. 148.

r) Classification of sale of future revenues

Under Argentine GAAP, net proceeds from an assignment of future capital fees to be earned in Venezuela are presented in the Balance Sheet as current and noncurrent other liabilities for US$ 36 million as of December 31, 2003, respectively.

Under US GAAP, a sale of future revenues of this nature is classified as debt. Therefore, a reclassification was made for purposes of US GAAP consolidated balance sheet data presented in Note 23.

s) Classification of impairment losses

Under Argentine GAAP, impairment losses for fixed assets, if any, are generally presented in the income statement as non-operating expenses.

US GAAP requires such losses to be presented as operating. Therefore, impairment losses recognized under Argentine GAAP and additional impairment losses recognized under US GAAP, are included in the Operating income (loss) subtotal of the US GAAP Consolidated income data presented in Note 23.

t) Accounting for discontinued operations

Under Argentine GAAP, the gain or loss on sales of a business segment is presented in the “Other expenses, net” account.

According to US GAAP, the results of continuing operations should be presented separately from discontinued operations and any gain or loss from disposal of a component of business segment should be reported in conjunction with the result of discontinued operations. Therefore, required reclassifications have been made for purposes of US GAAP consolidated income data presented in Note 23.

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u) Accounting for changes in accounting principles - Asset Retirement Obligations

Under Argentine GAAP, changes in accounting principles are generally accounted for on retroactive basis.

Under US GAAP, such changes are generally recognized as a cumulative effect in current earnings for the period the change is effective.

In connection with the adoption of SFAS No. 143 “Accounting for Asset Retirement Obligations” for both US GAAP and Argentine GAAP as from January 1, 2003, the reconciliation of net income presented in Note 23 reflects the difference described above in recognizing such change in accounting principle.

v) Accounting for inventories

Under Argentine GAAP, inventories must be accounted for at reproduction or replacement cost or, in other words, at the price we would pay at any given time to replace or reproduce such inventory, whereas under U.S. GAAP, inventories must be accounted for at cost. This difference, however, is not material to our financial statements given the high turnover of our inventories and, therefore, reconciliation is not required.

w) Consolidation of Variable Interest Entities

Under US GAAP, FASB Interpretation No 46R (FIN 46R) clarifies the application of Accounting Research Bulletin No. 51 (ARB No. 51) “Consolidated Financial Statements”, to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. FIN 46R requires the consolidation of those entities, known as variable interest entities (“VIEs”), by the primary beneficiary of the entity. The primary beneficiary is the entity, if any, that will absorb a majority of the entity’s expected losses, receives a majority of the entity’s residual returns, or both. We do not currently have any interests that we believe fall within the scope of FIN 46 or FIN 46R.

Under Argentine GAAP, such entities are not required to be consolidated.

x) Pension Plan obligations

Recognition of pension plan obligations between Argentine and US GAAP are essentially the same, except for the following:

Under US GAAP, recognition of an additional minimum liability is required if an unfunded accumulated benefit obligation exists and the liability already recognized as unfunded accrued pension cost is less than the unfunded accumulated benefit obligation. FAS 87 stipulates that if an additional liability is recognized, an equal amount shall be recognized as an intangible asset, provided that the asset recognized shall not exceed the amount of unrecognized prior service cost. Because as of December 31, 2004 an unrecognized prior service cost does not exist in the Company’s pension plan, this additional liability is reported as other comprehensive income, net of tax.

y) Troubled debt restructuring of TGS.

On December 15, 2004, TGS concluded its debt restructuring process. Under Argentine GAAP the Company followed the provisions contained in RT No. 17 and accordingly, recorded gain on restructuring due to the forgiveness of default interest and a gain related to a decrease in interest rates applied retroactively as from January 1, 2004.

Under US GAAP, TGS followed the provisions contained in Statement of Financial Accounting Standards No. 15 “Accounting by Debtors and Creditors for Troubled Debt Restructurings” (“SFAS No.15”) which states that in the case of a troubled debt restructuring (as this term is defined by SFAS No. 15) involving a

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cash payment and a modification of terms, a debtor shall reduce the carrying amount of the payable by the total fair value of the assets transferred and no gain on restructuring of payables shall be recognized unless the remaining carrying amount of the payable exceeds the total future cash payments (including amounts contingently payable) specified by the terms of the debt remaining unsettled after the restructuring. Future interest expense, if any, shall be determined by applying the interest rate that equates the present value of the future cash payments specified by the new terms (excluding amounts contingently payable) with the carrying amount of the payable. Based on the above, no gain on restructuring has been recorded by the Company under US GAAP. The adjustment recorded at December 31, 2004 represents the net effect of (i) the reversal of the gain on restructuring recorded under Argentine GAAP, and (ii) smaller interest expense recorded under US GAAP between December 15, 2004 and December 31, 2004.

z) New accounting standards and developments under US GAAP

Compensation costs relating to share-based payments

The FASB has issued FASB Statement No. 123R, “Share-Based Payment” (“SFAS 123R”) in December 2004 which requires that compensation cost relating to share-based payments be recognized at their fair value in the company’s financial statements. The company currently accounts for those payments under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. The company is preparing to implement this standard effective January 1, 2006. Although the transition method to be used to adopt the standard has not been selected, the impact of adoption is expected to have a minimal impact on the company’s results of operations, financial position and liquidity.

Accounting for Suspended well costs

FASB has recently issued FASB Staff Position 19-1 “Accounting for Suspended Well Costs” (FSP 19-1) in March 2005 which applies to enterprises that use the successful efforts method of accounting stated in SFAS No. 19. FSP 19-1 requires drilling costs of exploratory wells to be capitalized until it is assessed if proved reserves justifying the commercial development thereof are found. If such reserves are not found, such drilling costs are charged to expense. Occasionally, an exploratory well may determine the existence of oil and gas reserves but they cannot be classified as proved when drilling is completed. In those cases, the cost of the exploratory well continue capitalized as long as it meets the following two conditions: (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well, and (b) the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Otherwise, the exploratory well is assumed impaired and its costs are charged to expense. This FSP is effective for the first reporting period beginning after April 4, 2005 and should be applied prospectively. This change in the accounting principle will have no impact on the company’s financial statements.

Accounting for Conditional Asset Retirement Obligations

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” FIN 47 clarifies that the term “conditional asset retirement obligation” as used in SFAS No. 143, “Accounting for Asset Retirement Obligations,” refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company does not expect there to be any material effect on the Company’s consolidated financial statements upon adoption of the new standard.

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Accounting for Inventory costs

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs,” which amends the guidance in ARB No. 43, Chapter 4, “Inventory Pricing.” This amendment clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage). SFAS No. 151 requires that those items be recognized as current-period charges regardless of whether they meet the criteria specified in ARB 43 of “so abnormal.” In addition, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on normal capacity of the production facilities. SFAS No. 151 is effective for financial statements for fiscal years beginning after June 15, 2005. The Company is currently assessing the impact of SFAS No. 151 on its consolidated financial statements.

Disclosure requirements for drilling and mineral rights of oil and gas producing entities:

The EITF was considering at the end of 2003 whether oil and gas drilling rights were subject to the classification and disclosure provisions of SFAS No. 142 “Goodwill and Other Intangible Assets”. In September 2004, the FASB issued FASB Staff Position (FSP) FAS 142-2, “Application of FASB Statement No. 142 Goodwill and Other Intangible Assets to Oil and Gas Producing Entities”. This FSP confirms that SFAS No. 142 did not change the balance sheet classification or disclosure requirements for drilling and mineral rights of oil and gas producing entities. The Company classify the cost of oil and gas drilling and mineral rights as properties and equipment.

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23. Reconciliation of net income and shareholders’ equity to US GAAP

The following is a summary of the significant adjustments to net income for the years ended December 31, 2004, 2003 and 2002, and the shareholders’ equity as of December 31, 2004 and 2003, which would be required if US GAAP had been applied instead of Argentine GAAP in the Company’s financial statements.

Reconciliation of net income to US GAAP


	2004		2003		2002
Net income (loss) in accordance with Argentine GAAP	678		381		(1,579	)

US GAAP adjustments:

Exchange differences from devaluation of the Argentine peso	—		—		218
Foreign currency translation adjustment	16		(108	)	87
Valuation of timber	—		—		(2	)
Deferred charges	—		—		1
Amortization of deferred charges	8		3		5
Debt refinancing costs	18		24		(64	)
Deferred income taxes	124		66		(1,123	)
Derivatives	—		88		91
Depreciation of PP&E	(162	)	(168	)	(252	)
Fair value of liabilities	(36	)	(36	)	12
Negative goodwill	—		—		179
Discounted value of assets and liabilities	9		17		—
Difference in accounting basis for assets sold	—		(29	)	(92	)
Asset retirement obligations	—		45		(15	)
Minority Interest	(9	)	(4	)	46
Other	7		41		20
Deferred income taxes on US GAAP adjustments	87		97		148
US GAAP adjustments applicable to equity in earnings of affiliates
Exchange differences from devaluation of Argentine peso	—		—		803
Deferred income taxes	40		(130	)	581
Depreciation of PP&E	(10	)	(8	)	(7	)
Capitalized exchange difference	2		50		(10	)
Minority Interest	(6	)	6		(316	)
Reversal of equity in earnings of CIESA and Citelec (a)	15		(242	)	(263	)
Debt restructuring	(48	)	—		—
Other	27		7		(22	)

Total US GAAP adjustments	82		(281	)	25

Reclassification of discontinued operations and cumulative effect of changes in accounting principles, net of income tax	—		9		(314	)

Income (loss) from continuing operations	760		109		(1,868	)

Discontinued operations:
Income (loss) from operations (1)	—		7		72
Income (loss) from disposal (2)	—		(46	)	63

Income (loss) before cumulative effect of changes in accounting principles	760		70		(1,733	)

Cumulative effect of changes in accounting principles, net of tax (3)	—		30		179

Net income (loss) under US GAAP	760		100		(1,554	)

(a)

This amounts corresponds to the adjustment to reverse equity in earnings of CIESA and CITELEC accounted for under Argentine GAAP and the effects of other US GAAP adjustments recognized in items listed above respect to CIESA and CITELEC. As of December 31, 2004, 2003 and 2002, CIESA and CITELEC had negative shareholders equity under US GAAP, and were valued at zero.

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	2004	2003		2002
Basic net income (loss) per share under US GAAP
Class B	0.356	0.047		(0.729	)
Diluted net income (loss) per share under US GAAP	0.356	0.047		(0.729	)
Basic net income (loss) per share under US GAAP
Class B
Continuing operations	0.356	0.051		(0.876	)
Discontinued operations	—	(0.018	)	0.063
Cumulative effect of changes in accounting principles	—	0.014		0.084
Diluted net income (loss) per share under US GAAP
Continuing operations	0.356	0.051		(0.876	)
Discontinued operations	—	(0.018	)	0.063
Cumulative effect of changes in accounting principles	—	0.014		0.084
Basic net income (loss) per share under Argentine GAAP
Class B	0.318	0.179		(0.744	)
Diluted net income (loss) per share under Argentine GAAP	0.318	0.179		(0.744	)

Number of shares - in millions (4)	2,132	2,132		2,132

(1)	Net of applicable income tax expense of 26 for the year ended December 31, 2002.

(2)	Including applicable income tax benefit of 10 and 3 for the years ended December 31, 2003 and 2002.

(3)	Net of applicable income tax expense of 15 for the year ended December 31, 2003.

(4)	Earnings per share are calculated based on the weighted average number of shares outstanding during the year.

Consolidated proforma income data

As mentioned in Note 22, SFAS No. 142 and SFAS No. 143 were effective from January 1, 2002 and January 1, 2003, respectively. If the new standards had been effective before January 1, 2001, net income for the years ended December 31, 2004, 2003 and 2002, would have been as follows:


	2004	2003		2002
Net income (loss) under US GAAP	760	100		(1,554	)
Reversal of negative goodwill	—	—		(179	)
Accounting for asset retirement obligation, net of tax	—	(30	)	10

Proforma net income (loss) under US GAAP	760	70		(1,723	)

Proforma basic net income (loss) per share under US GAAP
Class B	0.356	0.033		(0.808	)
Proforma diluted net income (loss) per share under US GAAP	0.356	0.033		(0.808	)

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Consolidated statement of comprehensive income


	2004		2003		2002
Net income (loss) under US GAAP	760		100		(1,554	)
Foreign currency translation adjustment:
Net change during period, net of tax	3		(78	)	(374	)
Deferred Pension Plan Obligations
(Increase) decrease in additional minimum liability, net of tax	(10	)	—		—
Deferred hedge gains and losses, net of tax:
Reclassification to net income	16		(15	)	78
Deferred hedge (loss) gains	(6	)	17		(54	)

Total Comprehensive Income	763		24		(1,904	)

Cumulative Other Comprehensive Income :
Amounts not recognized as net periodic pension costs, net of tax	(10	)	—		—
Foreign currency translation adjustment, net of tax	(45	)	(48	)	30
Deferred hedge gains and losses, net of tax	(2	)	(12	)	(14	)

Total Cumulative Other Comprehensive Income	(57	)	(60	)	16

Reconciliation of shareholders’ equity to US GAAP


	2004		2003
Shareholders’ equity in accordance with Argentine GAAP	5,511		4,833

US GAAP adjustments:

Deferred charges	(21	)	(29	)
Debt refinancing costs	(23	)	(41	)
Pension plan obligations	(15	)	—
Deferred income taxes	(1,118	)	(1,242	)
Minority interest	123		132
Derivatives	(2	)	(18	)
Foreign currency translation adjustment	(154	)	(161	)
PP&E	1,372		1,513
Goodwill	155		155
Fair value of liabilities	50		86
Discounted value of assets and liabilities	26		17
Other	18		11
Deferred income taxes on U.S. GAAP adjustments	(281	)	(360	)
US GAAP adjustments applicable to equity in affiliates
Deferred income taxes	(641	)	(681	)
PP&E	(116	)	(106	)
Capitalized exchange difference	(46	)	(48	)
Minority Interest	240		246
Reversal of equity in affiliates of CIESA and Citelec (a)	298		283
Debt restructuring	(48	)	—
Other	(42	)	(67	)

Total US GAAP adjustments	(225	)	(310	)

Shareholders’ equity in accordance with US GAAP	5,286		4,523

(a)

This amounts corresponds to the adjustment to reverse Company’s investment in of CIESA and CITELEC accounted for under Argentine GAAP and the effects of other US GAAP adjustments recognized in items listed above respect to CIESA and CITELEC. As of December 31, 2004, 2003 and 2002, CIESA and CITELEC had negative shareholders equity under US GAAP, and were valued at zero.

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Description of changes in shareholders’ equity under US GAAP


	2004	2003		2002
Shareholders’ equity under US GAAP as of beginning of the year	4,523	4,499		6,403
Other comprehensive income	3	(76	)	(350	)
Net income (loss) under US GAAP	760	100		(1,554	)

Shareholders’ equity under US GAAP as of the end of the year	5,286	4,523		4,499

US GAAP Summarized Consolidated Data

The consolidated income data and the consolidated cash flow data for the years ended December 31, 2004, 2003 and 2002, and the consolidated balance sheets data as of December 31, 2004 and 2003, presented below have been adjusted to reflect the differences between US GAAP and Argentine GAAP discussed above:


	Year ended December 31,
	2004		2003		2002
US GAAP consolidated income and loss data
Sales	6,562		5,192		5,321
Less - taxes on sales and services	(119	)	(114	)	(139	)

Net sales	6,443		5,078		5,182
Cost of sales	(4,028	)	(3,282	)	(3,374	)

Gross profit	2,415		1,796		1,808
Administrative and selling expenses	(623	)	(529	)	(645	)
Exploration expenses	(89	)	(196	)	(58	)
Other operating income (expense), net	(295	)	(449	)	(275	)

Operating income	1,408		622		830
Equity in earnings of affiliates	110		65		(125	)
Financial income (expense) and holding gains (losses)	(1,157	)	(663	)	(1,564	)

Income (loss) before income taxes, minority interest, discontinued operations and cumulative effect of changes in accounting principles	361		24		(859	)
Income tax (expenses) benefit	413		92		(1,089	)
Minority interest in subsidiaries	(14	)	(7	)	80
Discontinued operations
Income (loss) from discontinued operations, net of income taxes (1)	—		7		72
Income (loss) from disposal, net of income taxes (2)	—		(46	)	63
Cumulative effect of changes in accounting principles (3)	—		30		179

Net income (loss) for the year	760		100		(1,554	)

(1)	Net of income tax expense of 26 for the year ended December 31, 2002.

(2)	Net of income tax benefit of 10 and 3 for the years ended December 31, 2003 and 2002.

(3)	Net of income tax expense of 15 for the year ended December 31, 2003.

F - 73


	Year ended December 31,
	2004	2003
US GAAP condensed consolidated balance sheet data
Current assets	3,013	2,614

Investments	1,143	1,071
Property, plant and equipment	10,477	10,522
Other non current assets	382	301

Total non current assets	12,002	11,894

Total assets	15,015	14,508

Short-term debt (1)	1,168	1,304
Other liabilities	1,729	1,282

Total current liabilities	2,897	2,586

Long-term debt	4,931	5,027
Other non current liabilities	1,477	1,967

Total non current liabilities	6,408	6,994

Total liabilities	9,305	9,580

Minority interest in subsidiaries	424	405
Shareholders’ equity	5,286	4,523

	15,015	14,508

(1)	Includes 924 and 876 corresponding to current portion of Long Term Debt for the years ended December 31, 2004 and 2003. In addition, the weighted average annual interest rates for outstanding short-term borrowings were 3.13% and 6.43% at December 31, 2004 and 2003, respectively.


	Year ended December 31,
	2004		2003		2002
US GAAP condensed consolidated cash flow data

Net cash provided by operations	1,519		1,209		826
Net cash used in investing activities	(990	)	(886	)	(172	)
Net cash used in financing activities	(369	)	(369	)	(1,953	)

(Decrease) Increase in cash	160		(46	)	(1,299	)
Effect of the exchange rate on cash	(6	)	(88	)	(63	)
Cash and cash equivalent at beginning	591		725		2,087

Cash and cash equivalent at end	745		591		725

F - 74

24. Additional financial statements disclosures required by US GAAP and the SEC

a) Income taxes

The tax effect of the significant differences between the book value under US GAAP and the tax value of the Company’s assets and liabilities and tax loss carryfowards are as follows:


	2004		2003
Deferred tax assets
Tax loss carryforwards	1,462		1,399
Other tax losses	138		207
Property, plant and equipment	103		62
Reserve for contingencies	40		76
Non-current investments	77		82
Pension plan obligations	8		7
Derivatives	191		216
Receivables	11		10
Accounts payable	—		12
Other deferred tax assets, not significant individually	67		68
Less-Valuation allowance	(1,362	)	(1,619	)

Deferred tax liabilities
Revenue recognition	(44	)	(40	)
Current investments	—		(16	)
Fair value of liabilities	(18	)	(30	)
Prepaid expenses	(20	)	(29	)
Property, plant and equipment	(1,435	)	(1,551	)
Non-current investments	(271	)	(351	)
Other deferred tax liabilities, not significant individually	(17	)	(41	)

Net deferred tax liabilities	(1,070	)	(1,538	)

The tax loss carryforwards as of December 31, 2004 totally expire beyond 2007. The valuation allowance on tax loss carryforwards as of such date amounted to 1,119.

F - 75

The reconciliation of tax provision at the statutory rate to the tax provision for the years ended December 31, 2004, 2003 and 2002, computed in accordance with US GAAP, is as follows:


	2004		2003		2002
Pre-tax income in accordance with U.S. GAAP	361		6		(523	)
Statutory tax rate	35	%	35	%	35	%

Statutory tax rate applied to pre-tax income (loss)	126		2		(183	)
Equity in earnings and dividends from affiliates	(238	)	(56	)	(97	)
Inflation adjustment on nommonetary assets and liabilities	(7	)	13		973
Inflation adjustment, remeasurement and foreign earnings	(67	)	332		1
Increase (decrease) in valuation allowances	(257	)	(422	)	333
Tax on minimum presumed income	—		11		19
Impairment, amortization and other decreases of goodwill	—		13		39
Tax adjustments and other, net	30		20		27

Tax (benefit) expense	(413	)	(87	)	1,112

The Company’s provision for income taxes under US GAAP was comprised of the following:


	2004		2003		2002
Current
Argentina	—		—		44
Foreign	64		48		22

	64	(2)	48	(1)	66
Deferred
Argentina	(421	)	(74	)	1,118
Foreign	(56	)	(61	)	(72	)

	(477	)	(135	)	1,046

Total tax (benefit) expense	(413	)	(87	)	1,112

(1)	Net of 483 for loss tax carryforward utilization in 2003.

(2)	Net of 299 for loss tax carryforward utilization in 2004.

b) Suspended well costs

The Company carries as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is under way or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that sufficient progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense.

F - 76

The following table provides the year-end balances and movements for suspended exploratory well costs:


	2004 (1)		2003 (1)		2002 (2)
					Argentine GAAP		US GAAP
Balance at beginning of the year	95		218		165		234
Additions	3		58		45		45
Transferred to development	(13	)	(4	)	(6	)	(6	)
Charged to expense	(80	)	(149	)	(29	)	(29	)
Sale of participations in exploration fields	—				(34	)	(34	)
Inflation and foreign currency translation adjustment	(2	)	(28	)	77		8

Balance at end of the year	3		95		218		218

Number of wells at year end	1		2		5		5

(1)	For both Argentine and US GAAP

(2)	The difference between Argentine and US GAAP results from the different treatment of the devaluation of the Argentine Peso as of December 31, 2001, as explained in Note 22.c

An aging of suspended well costs is shown below


	2004		2003
	Amount	Wells	Amount	Wells
Less than one year	3	1	95	2
Between one and three years	—	—	—	—

	3	1	95	2

c) Fair value of financial instruments

US GAAP requires disclosure of the estimated fair value of the Company’s financial instruments. The following methods and assumptions were used to estimate the fair value of each class of financial instruments.

The carrying amounts of cash, cash equivalents, accounts receivables and short-term obligations approximate its fair value, because of the short-term maturities of these instruments.

Fair value of trading and held-to-maturity investments is based on quoted market prices. The fair value of publicly traded long-term debt is based on quoted market prices, and for the remaining long-term debt was estimated based on the current rates available to the Company for debt of similar remaining maturities. Fair values of derivative financial instruments represent the estimated amount that would have been required to terminate the contracts. The fair value of performance bonds and other guarantees approximate the notional amount of these instruments.

F - 77

The estimated fair values of financial instruments are as follows, except for those financial instruments noted above for which the carrying values approximate fair values:


	2004				2003
	Carrying amount under US GAAP		Fair Value		Carrying amount under US GAAP		Fair Value
Financial assets:
Held-to-maturity securities	2		1		2		1
Financial liabilities:
Long-term debt	4,931		4,994		5,027		5,161
Derivative financial instruments:
Energy commodities price swaps and options:
Accounted for as non-hedge:
• Favorable	—		—		—		—
• Unfavorable	(606	)	(606	)	(583	)	(583	)
Foreign currency and interest rate:
Accounted for as a hedge:
• Unfavorable	(4	)	(4	)	(23	)	(23	)

d) Held-to-maturity securities

Held-to-maturity securities:

The change in the carrying amount of held-to-maturity securities has been as follows:


	2004	2003
Balance at beginning of the year	2	14
• Increase for securities to held to maturity	—	—
• Inflation and remeasurement effect	—	(2	)
• Decrease for securities to held to maturity	—	(2	)
• Redemption and interest collection	—	(8	)

Balance at end of year	2	2

At December 31, 2004 and 2003 the outstanding held-to-maturity securities are scheduled to mature in one to sixteen years.

F - 78

e) Summarized financial information of unconsolidated affiliates

The following table provides summarized financial information on a 100% basis, for the main affiliates accounted for by the equity method, combined per business unit, under Argentine GAAP.

Each business unit includes the following companies as of December 31, 2004, 2003 and 2002:

Oil and Gas Exploration and Production: Petrolera Entre Lomas S.A., Inversora Mata S.A. and Coroil S.A.

Refining: Refinería del Norte S.A. and Empresa Boliviana de Refinación S.A.

Petrochemical: Petroquímica Cuyo S.A.

Hydrocarbons marketing and Transportation: TGS S.A., Oleoductos del Valle S.A. and Oleoducto de Crudos Pesados Ltd.

Electricity: Citelec S.A., Yacylec S.A. and Urugua-í S.A.


	2004
	Oil and Gas Exploration and Production	Refining	Petrochemical	Hydrocarbons marketing and Transportation	Electricity
Current Assets	144	944	106	1,051	342
Noncurrent Assets	520	599	108	8,653	2,124
Current Liabilities	68	847	55	712	1,799
Noncurrent Liabilities	27	105	17	6,337	141
Shareholders’ Equity	569	591	142	2,655	352
Minority interest	—	—	—	—	174
Sales	327	2,425	293	1,914	356
Gross profit	174	388	91	1,049	89
Income (loss) from continuing operations before extraordinary items and Cumulative effect of changes in accounting principles	101	178	40	194	(68	)
Net income	101	178	40	194	(68	)

F - 79


	2003
	Oil and Gas Exploration and Production	Refining	Petrochemical	Hydrocarbons marketing and Transportation	Electricity
Current Assets	115	893	105	1,221	263
Noncurrent Assets	517	524	115	8,864	2,209
Current Liabilities	49	848	60	3,862	1,208
Noncurrent Liabilities	32	17	34	3,739	614
Shareholders’ Equity	551	552	126	2,484	430
Minority interest	—	—	—	—	220
Sales	278	1,988	225	1,196	324
Gross profit	150	350	68	582	96
Income (loss) from continuing operations before extraordinary items and Cumulative effect of changes in accounting principles	78	87	21	236	50
Net income	78	87	21	236	50


	2002
	Oil and Gas Exploration and Production	Refining	Petrochemical		Hydrocarbons marketing and Transportation		Electricity
Current Assets	130	878	110		1,182		172
Noncurrent Assets	575	535	121		13,728		2,391
Current Liabilities	73	819	114		8,428		1,252
Noncurrent Liabilities	22	42	12		3,086		715
Shareholders’ Equity	610	552	105		2,603		398
Minority interest	—	—	—		793		198
Sales	272	2,145	211		2,000		343
Gross profit	143	340	69		1,070		131
Income (loss) from continuing operations before extraordinary items and Cumulative effect of changes in accounting principles	46	151	(2	)	(1,154	)	(319	)
Net income	46	151	(2	)	(1,154	)	(319	)

f) Summarized financial information of proportionally consolidated jointly controlled companies

The following table provides summarized financial information on a proportional basis, for jointly controlled companies, which are proportionally consolidated under Argentine GAAP:


	2004						2003						2002 (a) (b)
	CIESA (b)		Distrilec		Total		CIESA (b)		Distrilec		Total		Distrilec
Current Assets	306		145		451		406		129		535		115
Noncurrent Assets	2,293		1,326		3,619		2,348		1,372		3,720		1,488
Current Liabilities	564		241		805		2,053		348		2,401		481
Noncurrent Liabilities	1,293		195		1,488		7		103		110		63
Shareholders Equity	250		591		841		234		600		834		606
Minority Interest	492		444		936		460		450		910		453
	—		—		—		—		—		—
Sales	472		535		1,007		432		447		879		519
Gross Profit	253		86		339		232		74		306		113
Income (loss) from continuing operations before extraordinary items and cumulative effect of changes in accounting principles	14		(9	)	5		110		(6	)	104		(9	)
Net Income (loss)	14		(9	)	5		110		(6	)	104		(9	)
Cash provided by (used in):
Operating activities	62		130		192		261		90		351		177
Investing activities	(49	)	(78	)	(127	)	(31	)	(28	)	(59	)	(69	)
Financing activities	(181	)	(47	)	(228	)	1		(46	)	(45	)	(74	)

(a)	As mentioned in Note 2.a, as of December 31, 2002, CIESA was not proportionally consolidated under Argentine GAAP since such equity interest was stated at zero value.

(b)	For us reporting purposes, CIESA was not proportionally consolidated, as explained in Note 22 g).

F - 80

g) Supplemental cash flow information

Cash and cash equivalents include:


	2004	2003	2002
Cash	124	147	93
Time deposits and Mutual Funds	621	441	582
Securities	—	3	50

	745	591	725

Non-cash investing and financing activities for the years ended December 31, 2004, 2003 and 2002, include an increase in accounts payable for the acquisition of property, plant and equipment in the amount of 177, 141 and 50, respectively. Additionally, an increase in the “Other receivables” account is included for the sale of subsidiaries and other business in the amount of 106 for the year ended December 31, 2002.

h) Pension plan:

Defined contribution plan:

During 2004, 2003 and 2002 fiscal years, no contributions were made under this plan (see Note 16.a).

Defined benefit pension plan:

The goals with respect to asset investment are (1) the preservation of capital in U.S. Dollars, (2) the maintenance of high levels of liquidity and (3) the attainment of the highest yields possible on a 30-day basis.

Information for the Company’s major defined benefit plan is as follows:


	2004		2003
Change in benefit obligation
Benefit obligation at beginning	51		78
Service cost	1		1
Interest cost	4		2
Actuarial gain	17		9
Effect of remeasurement in constant money	—		(1	)
Benefits paid	(4	)	(5	)
Curtailment effect	(1	)	(33	)

Benefit obligation at end of year	68		51


Change in plan assets
Fair value of plan assets at beginning	47		97
Actual return on plan assets	2		(11	)
Effect of remeasurement in constant money	—		(1	)
Benefits paid	(4	)	(5	)
Settlement payments	—		(33	)

Fair value of plan assets at end of year	45		47

F - 81


Reconciliation of funded (unfunded) status
Unfunded status, end of year	(23	)	(4	)
Additional liability included in long term liabilities	(15	)	—
Unrecognized net actuarial (gain) / loss	15		(3	)

Net amount recognized	(23	)	(7	)

Amounts recognized in the statement of financial position consist of:
Accrued benefit liability	(8	)	(7	)
Accumulated other comprehensive income	(15	)	—

Net amount recognized	(23	)	(7	)

Projected benefit obligation	68		51
Accumulated benefit obligation	68		51
Fair value of plan assets	45		47

Components of net periodic benefit cost
Service cost	1		1
Interest cost	4		2
Expected return on plan assets	(2	)	(3	)
Amortization of unrecognized transition obligation			—
Amortization of unrecognized gains			(1	)
Gains from settlements	(1	)	(14	)
Effect of remeasurement in constant money	—		1

Net periodic benefit (gain) cost	1		(14	)


Weighted-average assumptions
Discount rate	4	%	4	%
Expected return on plan assets	4	%	4	%

The compulsory rate of 4% was established by the National Insurance Control Entity (Superintendencia de Seguros de la Nación), which is based on the historical analysis of fixed income investments.

As of December 31, 2004 and 2003, pension plan assets are investments in mutual funds. As of the date of the issuance of these financial statements, the Board of Directors did not approve contributions to its pension plan fund in 2005.

Benefit obligations are expected to be paid as follows:


		Pension Benefits
2005		5
2006		5
2007		5
2008		5
2009		5
2010-2014		25

F - 82

i) Stock option plans

As of December 31, 2004, the Company has two stock-based employee compensation plans, both of which are described in more detail in Note 16.b). The following table presents a summary of the status of the Company’s two stock option plans for at December 31, 2004 and 2003 and the changes for each year:


	2004			2003
	Options (a)		Weighted- Average Exercise Price	Options (a)		Weighted- Average Exercise Price
Outstanding at beginning of year	7,557,205		1.59	9,339,012		1.58
Granted	—		—	—		—
Exercised	(4,362,013	)	1.58	(1,781,807	)	1.56

Outstanding at end of year	3,195,192		1.60	7,557,205		1.59

Exercisable at end of year	2,599,178		1.59	4,463,194		1.56

(a)	Includes both options to receive an “appreciation right” and “full value,” which options are described in Note 16.b).

As of December 31, 2004, 852,078 options and 2,343,114 options out of 3,195,192 total options outstanding have exercise prices of US$1.48 and US$1.64, respectively, with a weighted average price of US$1.60 and a weighted average remaining contractual life of 1.9 years. 2,599,178 of these options are exercisable.

The costs associated with stock-based employee compensation plans, which were charged as operating expenses in 2004, 2003 and 2002 amounted to 6, 8 and 5, respectively.

j) Business segment consolidated information

The Company determines operating segments based on differences in the nature of their operations, consistent with the measure of profit and the basis used by its management in making strategic decisions. The Company applies the same accounting policies to each of the segments that are used in the preparation of the consolidated financial statements under Argentine GAAP. Intersegment revenues are generally representative of market prices or arms-length negotiated transactions. Likewise, affiliated sales are not segregated because they are generally made at market prices. Management’s measure of segment profit does not include interest, income taxes and other non-operating income and expenses. Other non-cash items in segment income are principally comprised of undistributed earnings of affiliates.

The following information shows additional disclosures under Argentine GAAP about the Company’s business segments as defined by its management.

F - 83


	2004
	Oil and Gas Exploration and Production		Refining		Petrochemical		Hydrocarbons marketing and Transportation		Electricity		Corporate, other Investments and Eliminations		Total

Unaffiliated revenues	1,953		1,541		1,857		812		811		—		6,974

Intersegment revenues	1,406		204		20		49		14		(1,693	)	—

Total revenues	3,359		1,745		1,877		861		825		(1,693	)	6,974


Depreciation, depletion and amortization	(710	)	(22	)	(71	)	(138	)	(87	)	(30	)	(1,058	)

Equity in earnings of unconsolidated affiliates	23		58		16		18		(39	)	—		76

Interest expense	(261	)	(1	)	(17	)	(117	)	(22	)	(181	)	(599	)

Interest revenue	18		1		5		2		9		15		50

Dividends received from unconsolidated affiliates	12		54		9		6		3		—		84

Additions to property, plant and equipment	808		27		86		62		50		14		1,047

Identifiable assets	7,837		658		1,327		2,571		2,256		973		15,622

Investments in and advances to unconsolidated affiliates	199		229		53		349		158		—		988

Total assets	8,036		887		1,380		2,920		2,414		973		16,610


	2003
	Oil and Gas Exploration and Production		Refining		Petrochemical		Hydrocarbons marketing and Transportation		Electricity		Corporate, other Investments and Eliminations		Total

Unaffiliated revenues	1,785		1,231		1,294		502		680		2		5,494

Intersegment revenues	944		71		—		19		11		(1,045	)	—

Total revenues	2,729		1,302		1,294		521		691		(1,043	)	5,494


Depreciation, depletion and amortization	653		20		77		86		147		33		1,016

Equity in earnings of unconsolidated affiliates	19		22		16		16		90		—		163

Interest expense	(267	)	(1	)	(30	)	(134	)	(23	)	(168	)	(623	)

Interest revenue	28		1		5		9		12		10		65

Dividends received from unconsolidated affiliates	9		7		—		7		3		—		26

Additions to property, plant and equipment	187		23		37		12		40		33		332

Identifiable assets	7,289		419		1,054		2,768		2,261		1,030		14,821

Investments in and advances to unconsolidated affiliates	199		223		46		328		200		—		996

Total assets	7,488		642		1,100		3,096		2,461		1,030		15,817

F - 84


	2002
	Oil and Gas Exploration and Production		Refining	Petrochemical		Hydrocarbons marketing and Transportation		Electricity		Corporate, other Investments and Eliminations		Total

Unaffiliated revenues	2,033		942	1,254		16		755		106		5,106

Intersegment revenues	773		66	—		—		11		(850	)	—

Total revenues	2,806		1,008	1,254		16		766		(744	)	5,106


Depreciation, depletion and amortization	749		18	94		—		150		40		1,051

Equity in earnings of unconsolidated affiliates	2		20	(10	)	(470	)	(239	)	59		(638	)

Interest expense	(350	)	—	(42	)	—		(52	)	(438	)	(882	)

Interest revenue	12		1	11		—		33		31		88

Dividends received from unconsolidated affiliates	12		4	—		3		1		—		20

Additions to property, plant and equipment	366		5	30		—		37		(264	)	174

Identifiable assets	8,575		367	1,251		(17	)	2,467		1,174		13,817

Investments in and advances to unconsolidated affiliates	189		225	29		275		114		—		832

Total assets	8,764		592	1,280		258		2,581		1,174		14,649

F - 85

k) Derivative financial instruments

As described in Note 5, the Company holds several derivative financial instruments to reduce exposure to crude oil price fluctuations and changes in interest rates. Changes in the accounting measurement of derivative financial instruments designated as cash flow hedge, which have been determined as effective hedge, are recognized under US GAAP in the other comprehensive income account. The following information refers to the other comprehensive income accounted for the years ended December 31, 2004, 2003 and 2002:

Commodity Price Risk

As of December 31, 2004 and 2003, there are no unrealized gains or losses in the accumulated other comprehensive income. As of December 31, 2002 the Company has a net unrealized gain of 14 after taxes on derivative instruments entered into to hedge production recorded in accumulated other comprehensive income. Net income (loss) under US GAAP for 2002 fiscal year includes 99 of net loss, due to recognition of unrealized gains and losses related to hedge ineffectiveness.

Interest rate risk

As of December 31, 2004, 2003 and 2002, the Company has an after taxes net unrealized loss of 2, 12, and 28 respectively, on a derivative instrument entered into to hedge interest rate recorded in accumulated other comprehensive income. Approximately, 2 of net loss in the accumulated other comprehensive income balance as of December 31, 2004, is expected to be reclassified into financial expenses during 2005 as hedged transaction occurs.

l) Asset Retirement Obligations

The following table summarizes the activity of the liabilities booked for Asset Retirement Obligations for the years ended December 31, 2004 and 2003:


	2004	2003
Beginning balance	73	93
Cumulative effect of accounting change (1)	—	(20	)
Accretion expense and other provisions	1	4
Payments made	—	—
Liabilities incurred	7	—
Foreign currency translation/other	9	(4	)

Ending Balance	90	73

(1)

Cumulative Effect of 2003 Accounting Change


Increase in net PP&E	25
Decrease in ARO liability	20
Increase in deferred tax liability	(15	)

Total after-tax earnings	30

The cumulative adjustment for the change in accounting principle reported in 2003 was after-tax income of 30 (net of 15 of income tax effects)

F - 86

25. Oil and Gas Supplementary Disclosures (unaudited)

The following information for the oil and gas producing activities has been prepared in accordance with the methodology prescribed by Statement of Financial Accounting Standards N° 69 “Disclosures about Oil and Gas Producing Activities” and includes the Company and its subsidiaries oil and gas production activities as well as the equity shares in its affiliates valued by the equity method. The Company has oil and gas properties in the Argentina and other countries of Latin America; the respective detail is disclosed in note 24.e). to the financial statements.

The amounts derived from minority interest in consolidated subsidiaries are not significant, therefore, they have not been included.

Amounts in millions of pesos are stated as mentioned in note 2.c. to the financial statements.

Capitalized costs

The following table presents the capitalized costs as of December 31, 2004 and 2003, for proved and unproved oil and gas properties, and the related accumulated depreciation, depletion and amortization.


	2004				2003
	Argentine GAAP		US GAAP		Argentine GAAP		US GAAP
	(in millions of constant pesos – note 2.c.)

Consolidated companies:

Proved properties:

Equipment, camps and other facilities	2,775		2,665		2,036		1,926

Producing properties and wells	7,685		8,528		7,372		8,192

Unproved properties	391		391		569		569

Total capitalized costs	10,851		11,584		9,977		10,687

Accumulated depreciation, depletion and amortization, and allowances which reduce the value of assets	(4,575	)	(4,108	)	(3,849	)	(3,234	)

Subtotal of consolidated companies	6,276		7,476		6,128		7,453

Company’s share in capitalized costs by unconsolidated affiliates	185		264		198		285

Total net capitalized costs	6,461		7,740		6,326		7,738

F - 87

Costs incurred

The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended as of December 31, 2004, 2003 and 2002. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, and drilling costs and exploratory well equipment. Development costs include drilling costs and equipment for developmental wells, costs incurred in improved recovery, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.


	2004			2003
	Argentina and US GAAP			Argentina and US GAAP
	Argentina	Rest of Latin- America	Total	Argentina	Rest of Latin- America	Total
	(in millions of constant pesos – note 2.c.)

Consolidated companies:

Acquisition of properties:

- Proved	—	—	—	—	—	—

- Unproved	—	—	—	—	—	—

Exploration costs	9	9	18	—	103	103

Development costs	376	556	932	343	346	689

Total Costs incurred by consolidated companies	385	565	950	343	449	792

Company’s share in costs incurred by unconsolidated companies	9	5	14	9	5	14

Total costs incurred	394	570	964	352	454	806


	2002
	Argentina and US GAAP
	Argentina	Rest of Latin- America	Total
	(in millions of constant pesos – note 2.c.)

Consolidated companies:

Acquisition of properties:

- Proved	26	—	26

- Unproved	—	—	—

Exploration costs	22	67	89

Development costs	222	262	484

Total Costs incurred by consolidated companies	270	329	599

Company’s share in costs incurred by unconsolidated companies	7	10	17

Total costs incurred	277	339	616

F - 88

Results of operations

The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2004, 2003 and 2002. These activities are a part of the Oil and Gas Exploration and Production segment. This breakdown does not include any allocation of financial costs or expenses from Corporate and therefore it is not necessarily an indicator of the contribution in operations for oil and gas producing activities to the net income of the Company. Income tax for the years presented was calculated utilizing the deferred income tax criteria.


	2004
	Argentine GAAP						US GAAP
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of constant pesos – note 2.c.)
Results of operations of consolidated companies:

Net sales:

- to third parties	353		1,600		1,953		353		1,600		1,953

- transfers to other operations	1,406		—		1,406		1,406		—		1,406

Total net sales	1,759		1,600		3,359		1,759		1,600		3,359

Production costs:

- Operating Costs	(261	)	(290	)	(551	)	(261	)	(290	)	(551	)

- Royalties and other	(294	)	(398	)	(692	)	(294	)	(398	)	(692	)

Total production costs	(555	)	(688	)	(1,243	)	(555	)	(688	)	(1,243	)

Exploration costs	(6	)	(83	)	(89	)	(6	)	(83	)	(89	)

Depreciation, depletion, amortization and allowances which reduce the value of assets	(362	)	(336	)	(698	)	(400	)	(447	)	(847	)

Results of operations before income tax	836		493		1,329		798		382		1,180

Income tax	(344	)	(155	)	(499	)	(329	)	(117	)	(446	)

Results of operations - consolidated companies	492		338		830		469		265		734

Company’s share in results of operations by unconsolidated affiliates	17		6		23		14		4		18

Total	509		344		853		483		269		752

F - 89


	2003
	Argentine GAAP						US GAAP
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of constant pesos – note 2.c.)
Results of operations of consolidated companies:

Net sales:

- to third parties	594		1,191		1,785		681		1,191		1,872

- transfers to other operations	944		—		944		944		—		944

Total net sales	1,538		1,191		2,729		1,625		1,191		2,816

Production costs:

- Operating costs	(242	)	(247	)	(489	)	(242	)	(247	)	(489	)

- Royalties and other	(245	)	(161	)	(406	)	(245	)	(161	)	(406	)

Total production costs	(487	)	(408	)	(895	)	(487	)	(408	)	(895	)

Exploration costs	(11	)	(185	)	(196	)	(11	)	(185	)	(196	)

Depreciation, depletion, amortization and allowances which reduce the value of assets	(368	)	(593	)	(961	)	(388	)	(726	)	(1,114	)

Results of operations before income tax	672		5		677		739		(128	)	611

Income tax	(235	)	(1	)	(236	)	(228	)	46		(182	)

Results of operations - consolidated companies	437		4		441		511		(82	)	429

Company’s share in results of operations by unconsolidated affiliates	13		5		18		9		2		11

Total	450		9		459		520		(80	)	440

F - 90


	2002
	Argentine GAAP						US GAAP
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of constant pesos – note 2.c.)

Results of operations of consolidated companies:

Net sales:

- to third parties	849		1,184		2,033		1,006		1,292		2,298

- transfers to other operations	773		—		773		777		—		777

Total net sales	1,622		1,184		2,806		1,783		1,292		3,075

Production costs:

- Operating costs	(257	)	(267	)	(524	)	(236	)	(267	)	(503	)

- Royalties and other	(238	)	(159	)	(397	)	(238	)	(159	)	(397	)


Total production costs	(495	)	(426	)	(921	)	(474	)	(426	)	(900	)

Exploration costs	(21	)	(37	)	(58	)	(21	)	(37	)	(58	)

Depreciation, depletion, amortization and allowances which reduce the value of assets	(356	)	(391	)	(747	)	(395	)	(593	)	(988	)


Results of operations before income tax	750		330		1,080		893		236		1,129

Income tax	(280	)	(32	)	(312	)	(519	)	102		(417	)

Results of operations - consolidated companies	470		298		768		374		338		712

Company’s share in results of operations by unconsolidated affiliates	23		8		31		20		—		20

Total	493		306		799		394		338		732

F - 91

Estimated oil and gas reserves

Proved reserves represent estimated quantities of oil (including crude oil, condensate and natural gas liquids) and natural gas, which available geological and engineering data demonstrates with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods.

The Company believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with Rule 4-10 of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States of America. The Company’s reserve estimates as of December 31, 2004, 2003 and 2002, were audited by Gaffney, Cline & Associates Inc., international technical advisors. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history.

Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be accurately measured, and the reserve estimation depends on the quality of available information and the interpretation and judgment of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.

F - 92

The following table sets forth the estimated proved reserves of oil (includes crude oil, condensate and natural gas liquids) and natural gas as of December 31, 2004, 2003 and 2002:


	CRUDE OIL, CONDENSATE AND NATURAL GAS LIQUIDS IN THOUSAND OF BARRELS										NATURAL GAS IN MILLION OF CUBIC FEETS
	CONSOLIDATED COMPANIES				UNCONSOLIDATED COMPANIES						CONSOLIDATED COMPANIES				UNCONSOLIDATED COMPANIES
	ARGENTINA		REST OF LATIN- AMERICA		ARGENTINA		REST OF LATIN- AMERICA		TOTAL		ARGENTINA		REST OF LATIN- AMERICA		ARGENTINA		REST OF LATIN- AMERICA	TOTAL
Proved reserves (developed and undeveloped)
Reserves as of December 31, 2001*	230,437		490,126		6,843		11,766		739,172		1,111,357		495,053		18,129		—	1,624,539

Increase (Decrease) originated in:

Revisions of previous estimates	(14,493	)	(112,545	)	(375	)	(880	)	(128,293	)	(247,448	)	(123,594	)	(10,702	)	—	(381,744	)

Improved recovery	4,027		3,510		168		—		7,705		64,550		9,687		11,821		—	86,058

Extensions and discoveries	6,839		9,596		99		461		16,995		88,265		10,662		—		—	98,927

Purchase of proved reserves in place	516		—		—		—		516		—		—		—		—	—

Sale of proved reserves in place	—		—		—		—		—		—		—		—		—	—

Year’s production	(20,225	)	(21,029	)	(494	)	(469	)	(42,217	)	(90,860	)	(22,352	)	(1,324	)	—	(114,536	)

Reserves as of December 31, 2002*	207,101		369,658		6,241		10,878		593,878		925,864		369,456		17,924		—	1,313,244

Increase (Decrease) originated in:

Revisions of previous estimates	(18,987	)	(3,215	)	(39	)	(63	)	(22,304	)	(127,415	)	23,110		(4,549	)	—	(108,854	)

Improved recovery	9,292		15,045		790		347		25,474		—		7,261		—		—	7,261

Extensions and discoveries	3,174		18,303		84		—		21,561		60,416		7,571		954		—	68,941

Purchase of proved reserves in place	—		—		—		—		—		—		—		—		—	—

Sale of proved reserves in place	(7,707	)	—		—		—		(7,707	)	(49,450	)	—		—		—	(49,450	)

Year’s production	(20,538	)	(20,367	)	(559	)	(376	)	(41,840	)	(72,819	)	(22,517	)	(1,006	)	—	(96,342	)

Reserves as of December 31, 2003*	172,335		379,424		6,517		10,786		569,062		736,596		384,881		13,323		—	1,134,800

Increase (Decrease) originated in:

Revisions of previous estimates	(21,242	)	(4,468	)	(109	)	(1,285	)	(27,104	)	13,665		(1,749	)	611		—	12,527

Improved recovery	2,262		9,555		291		—		12,108		11,482		—		699		—	12,181

Extensions and discoveries	5,309		36,966		—		—		42,275		7,165		6,498		—		—	13,663

Purchase of proved reserves in place	—		—		—		—		—		—		—		—		—	—

Sale of proved reserves in place	—		—		—		—		—		—		—		—		—	—

Year’s production	(18,734	)	(24,147	)	(583	)	(365	)	(43,829	)	(71,565	)	(23,643	)	(1,003	)	—	(96,211	)

Reserves as of December 31, 2004*	139,930		397,330		6,116		9,136		552,512		697,343		365,987		13,630		—	1,076,960

(*)Includes proved developed reserves:

As of December 31, 2001	147,560		198,964		4,364		4,844		355,732		548,526		290,638		13,308		—	852,472
As of December 31, 2002	141,891		173,820		4,428		4,056		324,195		539,731		209,854		14,373		—	763,958
As of December 31, 2003	117,765		166,349		4,320		3,576		292,010		444,951		207,144		10,514		—	662,609
As of December 31, 2004	93,697		165,634		3,999		2,485		265,815		434,619		208,440		9,785		—	652,844

The estimated reserves were subjected to economic tests to determine economic limits. Such estimated reserves in Argentina, Perú 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, the reserves are stated after such percentage. In Venezuela, the Company receives, for its interest in the “Oritupano-Leona” Block, a fee per barrel delivered to the Government of Venezuela. Additionally, the Company receives a fee for reimbursement of certain capital expenditures. In the Mata, Acema and La Concepción areas, the Company collects a variable fee per barrel delivered that contemplates production costs plus a mark-up. Under these contracts, the Venezuelan government maintains full ownership of all hydrocarbons in fields. The reserve volumes in Venezuela are computed by multiplying the Company’s working interest by the gross proved recoverable volumes for the contract area. In accordance with the agreement governing current petroleum operations in Venezuela, the Company is exempt from production royalty payments.

F - 93

Had the economic method of calculating proved reserves (future expected cash flows of each field divided by the oil market prices at year end) been used, the reported amounts of crude oil, condensate and natural gas liquids proved reserves for consolidated companies in “Rest of Latin America” would have decreased by approximately 26.8%, 22.9% and 28.4%, and the reported crude oil, condensate and natural gas liquids proved reserves for unconsolidated companies in “Rest of Latin America” would have decreased by approximately 40.4%, 37.3% and 42% as of December 31, 2004, 2003 and 2002, respectively. The information in this paragraph was not audited by Gaffney, Cline & Associates.

On November 12, 2004, the Boards of Directors of consolidated company Petrobras Energía S.A. and Petrobras Argentina S.A. (PAR) and the Management of Petrolera Santa Fe S.R.L. (PSF), in their respective meetings, approved the preliminary agreement for the merger of PAR and PSF with and into Petrobras Energía S.A., with the former companies being dissolved without liquidation. The before mentioned merger was approved by the Special Shareholders’ Meetings of PESA and PAR, and by the Special Partners’ Meeting of PSF held on January 21, 2005. The effect of such merger on the volume of reserves as of December 31, 2004, as regards the reported amounts of crude oil, condensate and liquids from natural gas, and natural gas of the consolidated companies in the “Argentina” column would represent an increase of about 20.7% and 54.7%, respectively. Information in this paragraph was not audited by Gaffney, Cline & Associates.

Standardized measure of discounted future net cash flows

The following table discloses estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate, natural gas liquids and natural gas. As prescribed by Statement of Financial Accounting Standards N° 69, such future net cash flows were estimated using each year-end prices and costs held constant for the life of the reserves and using a 10% annual discount factor. Future development costs include estimated drilling costs, exploitation installations and abandonment costs. These future development costs were estimated based on evaluations made by the Company and the operators of the fields in which the Company has an interest. The future income tax was calculated by applying the tax rate in effect as of the date this supplementary information was filed.

F - 94

This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Company’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed below. For all these reasons, this information does not necessarily indicate the perception the Company has on the discounted future net cash flows derived from the reserves of hydrocarbons.


	2004						2003						2002
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of pesos – note 2.c.)
Consolidated companies:

Future cash flows	16,447		30,131		46,578		15,158		22,513		37,671		19,873		25,149		45,022

Future production costs	(3,799	)	(7,228	)	(11,027	)	(3,522	)	(6,653	)	(10,175	)	(3,793	)	(6,994	)	(10,787	)

Future development and abandonment costs	(1,387	)	(3,695	)	(5,082	)	(1,379	)	(2,875	)	(4,254	)	(1,389	)	(3,023	)	(4,412	)

Future income tax	(3,530	)	(5,518	)	(9,048	)	(3,158	)	(3,308	)	(6,466	)	(4,794	)	(3,868	)	(8,662	)

Future net cash flows	7,731		13,690		21,421		7,099		9,677		16,776		9,897		11,264		21,161

10% annual discount	(2,907	)	(6,099	)	(9,006	)	(2,784	)	(4,466	)	(7,250	)	(4,079	)	(5,268	)	(9,347	)

Subtotal of consolidated companies	4,824		7,591		12,415		4,315		5,211		9,526		5,818		5,996		11,814

Company’s share in standardized measure by unconsolidated affiliates	198		162		360		150		117		267		156		143		299

Total	5,022		7,753		12,775		4,465		5,328		9,793		5,974		6,139		12,113

As described in note 5 to the financial statements, the Company uses various derivative financial instruments to mitigate the impact of changes in crude oil prices. Had such instruments been considered, the effects on (a) Future cash flows (b) Total would have been as follows.


	2004			2003			2002
	Argentina	Rest of Latin- America	Total	Argentina	Rest of Latin- America	Total	Argentina		Rest of Latin- America	Total
Effect on - increase (decrease):
(a) Future cash flows	—	—		—	—	—	(38	)	—	(38	)
(b) Total	—	—		—	—	—	(22	)	—	(22	)

The effect of the merger described above on the Future cash flows as of December 31, 2004, would represent an increase of about 22% in the “Argentina” column and, on the Standarized measure of discounted future net cash flows would represent an increase of about 15% in the “Argentina” column.

F - 95

Changes in the standardized measure of discounted future net cash flows

The following table discloses the changes in the standardized measure of discounted future net cash flows for the years ended December 31, 2004, 2003 and 2002:


	Consolidated and unconsolidated Companies
	2004						2003						2002
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of constant pesos – note 2.c.)
Standardized measure at beginning of year	4,465		5,328		9,793		5,974		6,139		12,113		2,770		3,032		5,802

Changes related to oil & gas activities:

Sales net of production costs	(1,308	)	(1,147	)	(2,455	)	(1,161	)	(805	)	(1,966	)	(1,396	)	(900	)	(2,296	)

Net change in sales prices, net of future production costs	1,819		2,813		4,632		(1,520	)	(2,015	)	(3,535	)	6,734		7,047		13,781

Changes in future development costs	(302	)	(997	)	(1,299	)	(326	)	(111	)	(437	)	(201	)	(658	)	(859	)

Extensions, discoveries and improved recovery, net of futures production and associated costs	442		1,570		2,012		444		800		1,244		897		256		1,153

Development costs incurred	385		561		946		352		351		703		229		272		501

Revisions of quantity estimates	(860	)	(40	)	(900	)	(1,003	)	(56	)	(1,059	)	(1,043	)	(2,774	)	(3,817	)

Purchase of reserves in place	—		—		—		—		—		—		15		—		15

Sale of reserves in place	—		—		—		(164	)	—		(164	)	—		—		—

Net change in income taxes	(249	)	(1,248	)	(1,497	)	944		230		1,174		(2,136	)	(1,306	)	(3,442	)

Accretion of discount	662		741		1,403		899		835		1,734		365		394		759

Changes in production rates	(59	)	188		129		(30	)	(181	)	(211	)	(482	)	353		(129	)

Other changes	27		(16	)	11		56		141		197		222		423		645

Standardized measure at end of year	5,022		7,753		12,775		4,465		5,328		9,793		5,974		6,139		12,113

F - 96

26. Subsequent events

1. Agreement with Teikoku Oil Co Ltd.

In January 2005, Petrobras Energía entered into an agreement with Teikoku Oil Co., Ltd., or Teikoku, whereby, following approval by the Ministry of Energy of Ecuador, Petrobras Energía will transfer 40% of our rights and interest in Blocks 18 and 31. In addition, once production in Block 31 reaches an average of 10,000 barrels of oil per day for a period of 30 consecutive days, Teikoku has agreed to assume 40% of our rights and obligations resulting from the crude oil transportation agreement entered into with OCP. Allocation of the transportation capacity to Teikoku would enable us to reduce the oil production deficit. Teikoku, in turn, will make a US$15 million payment. In addition, Teikoku has agreed to make investments in Block 31 in excess of its interest in the joint venture, causing accelerated development of the block. Once approval by the Ministry of Energy of Ecuador occurs, our interests in Blocks 18 would be reduced from our current level of 70% to 30% and our interest in Block 31 would be reduced from 100% to 60%, but we will continue acting as operator for both blocks.

2. Rate renegotiation.

The following paragraphs presents the latest steps that were taken in the renegotiation process with regards to the following companies:

TGS

In July 2004, UNIREN submitted to TGS a proposal for the adjustment of the contractual terms and conditions of its license, which provides for, among other things, a tariff increase off 10% effective as from January 2005, an overall tariff review to come into force since 2007 and the resignation from any claim or lawsuit in connection with the effects of the Emergency Law No. 25,561 prior to the coming into effect of the agreement, as well as keeping unharmed the Argentine Government from any claim or lawsuit that could prosper related the same cause.

As this proposal differed from discussions TGS previously had with UNIREN, TGS rejected it choosing instead to seek to reach an overall agreement with UNIREN by the end of 2004 (in line with the originally outlined in the “Preliminary Renegotiation Guidelines” and to carry out the respective process of approval during the first semester of 2005.

On April 27, 2005, at a public hearing called by UNIREN to analyze the proposal made on July 2004, UNIREN repeated its 10% increase proposal and proposed to accelerate effectiveness of the comprehensive rate review process to 2006, and TGS has decided to continue negotiating in order to seek to improve these terms.

Transener / Transba

On February 2, 2005, Transener and Transba entered into a Memorandum of understanding with UNIREN, which contain principal terms (including a new tariff scheme) and conditions for a comprehensive renegotiation of both companies’ concession contracts.

On March 18, 2005, in order to allow the participation of the users and the rest of the community in the rate increase process, the public hearing took place.

On May 17, 2005, Transener entered into an agreement with the UNIREN, which confirmed the same conditions mentioned in the Memorandum of Understanding. The terms of the agreement are pending congressional approval and ratification, and if approved, will be in force retroactively as of June 1, 2005

Edesur

On June 16, 2004, Edesur, entered into a memorandum of understanding with UNIREN in connection with the renegotiation of Edesur’s concession contract. The memorandum of understanding

F - 97

establishes terms and conditions which will be the basis for the comprehensive agreement for renegotiation of the concession contract between the federal executive branch and Edesur. The memorandum of understanding provides for the implementation of a transitional tariff scheme as from November 1, 2005, that increases the utility’s average tariff by up to 15% and requires prior regulatory approval for the payment of dividends during that transitionary period. In addition, the memorandum provides for a comprehensive tariff revision process to take place between the June 16, 2004 and September 30, 2006 in order to establish a new tariff scheme with a 5-year term that would commence on November 1, 2006.

As of the date of issuance of these financial statements, no further steps have been taken in the renegotiation of agreements or in the rate restructuring of the remaining utility companies.

3. Ecuador- Block 31: Transport agreement with Occidental Exploration and Production Company (“Oxy”)

In January 2005, the Company entered into a crude oil transportation agreement with Occidental Exploration and Production Company, or Oxy. Under this agreement, we will be able to use a pipeline owned by Oxy to transport oil produced by Block 31 to the head of the OCP pipeline. The agreement becomes effective thirty days after the earlier of (1) the date that Block 31’s first volumes of crude oil are ready for transportation or (2) January 1, 2007, and runs through July 2019. A ship or pay clause is included in the agreement for an amount of approximately US$10 million, which is spread over 13 years and equals 25% of the production related to the Apaika Nenke Field’s proved reserves. To comply with the agreement, Oxy’s facilities must be expanded, which will require an investment of approximately US$14 million. This investment will be financed by us and will be reimbursed by reducing the transportation rate charged to us. This agreement remains subject to approval by the Ecuadorian government.

4. Divesture of Petrobras Energía’s equity interest in Transener:

Petrobras Energía S.A. is committed to divesting its aggregate equity interest in Transener as required in connection with the CNDC’s resolution approving the purchase of our majority stock by Petrobras. This divestiture would be subject to supervision by the ENRE.

On May 26, 2005, a notice addressed to Petrobras was received, with a copy of Resolution 757 of the Argentine Secretary of Energy attached thereto. Under this resolution, March 31, 2006 is fixed as the deadline for Petrobras to divest its equity interest in Transener. The resolution also requires that a divestment plan be submitted within 15 days after receipt of notice. On June 17, 2005, the Secretary of Energy suspended Resolution 757.

Transener is controlled by Citelec, who owns 65% of the capital of Transener. Citelec, in turn, is owned on a 50/50 basis by Dolphin Fund Management, or Dolphin, and Petrobras Energía S.A.

5. Social and Political instability in Bolivia.

Recent political unrest in Bolivia has targeted foreign companies’ participation in Bolivia’s natural gas industry, which in May 2005 resulted in a significant increase in royalties and taxes and calls by some groups for nationalization of the energy industry. The Bolivian political, economic and social situation, generally, and the country’s energy policy, in particular, remains extremely volatile and unpredictable.

Our operations in Bolivia, are mainly represented by our 100% interest in the “Colpa Caranda” oil and gas field, and through our 49% interest in “Empresa Boliviana de Refinación” (EBR).

During 2004, our Bolivian operations represented approximately 1.8%, 0.9%, 2.0%, and 0.9% of our consolidated net income, gross profit, total assets and liabilities for the year ended December 31, 2004.

6. Operations in Venezuela

F - 98

of the value of oil and gas produced under the related agreement. On April 15, 2005, PDVSA notified our subsidiary Petrobras Energía Venezuela, S.A. about this situation and advised that the Venezuelan Energy and Oil Ministry will, as soon as possible, contact them to fix a date to begin the related discussions. Without opining on the proposed changes or the legitimacy of the operating agreements, The Company have expressed its willingness to engage in discussions with PDVSA and the Venezuelan Government.

7. Renegotiation of Transener’s debt:

On February 22, 2005, Transener proposed an exchange offer to its creditors, which in April 2005 was accepted by 98.8% of them. Pursuant to a restructuring agreement entered into on May 19, 2005, Transener has 45 business days to comply with the terms of the exchange offer, otherwise ther restructuring agreement may be terminated at creditor’s option. This exchange offer restructured Transener’s overdue indebtedness, which principal, as of March 31, 2005 amounted to P$1,353 million. In the offer, Transener will issue to its creditors an aggregate of: (1) US$80 million in par notes due 2016, with interest accruing at an increasing rate from 3% to 7% per annum, (2) US$199.8 million in discount notes due 2015 with interest accruing at an increasing rate from 9% to 10% per annum and (3) 84,475,000 shares (or cash in lieu of shares). (As a result of the issuance of the shares in (3) above, Citelec’s interest in Transener will be reduced from 65% to 52.652% and our indirect interest will be reduced from 32.5% to 26.326%.) In addition, Transener will redeem indebtedness with a nominal value of US$110 million, by paying US$550 in cash for every US$1,000 of outstanding debt. The issuance of the new debt and the new shares has been approved by CNV.

27. Other consolidated information

The following tables present additional consolidated financial statement disclosures required under Argentine GAAP.

a)	Property, plant and equipment.

b)	Equity in affiliates

c)	Costs of sales.

d)	Foreign currency assets and liabilities.

e)	Consolidated detail of expenses incurred and depreciation.

f)	Information about ownership in subsidiaries and affiliates.

g)	Oil and gas areas and participation in joint ventures.

h)	Combined joint ventures and consortia assets, liabilities and results.

F - 99

a) Property, plant and equipment as of December 31, 2004, 2003 and 2002

(Stated in millions of Argentine Pesos - See Note 2.c)


	2004
	Oil and Gas Exploration and Production		Refining		Petrochemical		Electricity		Hydrocarbons Marketing and Transportation		Corporate, Other Discontinued Investments and Eliminations		Total

Net book value at beginning of the year	6,128		181		652		2,016		2,124		137		11,238

Effect of translation	50		—		3		—		—		—		53

Net increase	808		27		86		62		50		14		1,047

Depreciation	(710	)	(22	)	(71	)	(138	)	(87	)	(30	)	(1,058	)

Net book value at end of the period	6,276		186		670		1,940		2,087		121		11,280


	2003
	Oil and Gas Exploration and Production		Refining		Petrochemical		Electricity		Hydrocarbons Marketing and Transportation		Corporate, Other Discontinued Investments and Eliminations		Total

Net book value at beginning of the year	7,225		178		770		2,123		—		137		10,433

Net book value at beginning of the year from proportional interest in CIESA	—		—		—		—		2,198		—		2,198

Effect of translation	(631	)	—		(78	)	—		—		—		(709	)

Net increase	187		23		37		40		12		33		332

Depreciation	(653	)	(20	)	(77	)	(147	)	(86	)	(33	)	(1,016	)

Net book value at end of the period	6,128		181		652		2,016		2,124		137		11,238


	2002
	Oil and Gas Exploration and Production		Refining		Petrochemical		Electricity		Hydrocarbons Marketing and Transportation	Corporate, Other Discontinued Investments and Eliminations		Total

Net book value at beginning of the year	5,888		191		633		2,236		—	441		9,389

Effect of translation	1,720		—		201		—		—	—		1,921

Net increase	366		5		30		37		—	(264	)	174

Depreciation	(749	)	(18	)	(94	)	(150	)	—	(40	)	(1,051	)

Net book value at end of the period	7,225		178		770		2,123		—	137		10,433

F - 100

b) Equity in affiliates as of December 31, 2004 and 2003

(Stated in millions of Argentine Pesos - See Note 2.c)


	12/31/2004						12/31/2003
	Description of securities						12/31/2003
Name and issuer	Fase value		Amount	Cost	Book value		Book value
Citelec S.A. (Note 9.III)	$	1	73,154,437	298	116		158
Coroil S.A.		Bs 1,000	490	47	49		56
Empresa Boliviana de Refinación S.A.	$	B11,000	178,752	103	121		114
Hidroneuquén S.A.	$	10	25,744,097	26	26		26
Inversora Mata S.A.		Bs 1,000	490	70	100		98
Oleoducto de Crudos Pesados Ltd.	US$	0.01	31,500	98	91		81
Oleoductos del Valle S.A.	$	10	2,542,716	61	81		80
Petrolera Entre Lomas S.A.	$	1	96,050	2	50		45
Petroquímica Cuyo S.A.	$	0.083	240,000,000	43	53		46
Refinería del Norte S.A.	$	10	2,610,809	63	108		109
Transportadora de Gas del Sur S.A. (Note 9.III) (1)	$	1	58,408,751	169	177		167
Yacylec S.A.	$	0.1	100,000,000	25	26		26
Reserve for impairment of investments		—			(10	)	(10	)

				1,005	988		996

(1)	Considering that as of December 31, 2004 and 2003, Ciesa capitalized exchange differences of 26 and 27, respectively.

F - 101

c) Costs of sales for the years ended December 31, 2004, 2003 and 2002

(Stated in millions of Argentine Pesos - See Note 2.c)


	2004
	Oil and Gas Exploration and Production		Refining		Petrochemical		Electricity		Hydrocarbons Marketing and Transportation		Corporate, Other Discontinued Investments and Eliminations		Total

Inventories at beginning	110		129		155		35		8		(57	)	380

Effect of traslation	1		—		—		—		—		—		1

Costs (Section e)	1,524		62		163		296		319				2,364

Holding gain (losses)	(5	)	9		37		(17	)	—		4		28

Purchases, consumption and other	88		1,545		1,426		347		267		(1,693	)	1,980

Inventories at end	(124	)	(182	)	(278	)	(33	)	(3	)	77		(543	)

Costs of sales	1,594		1,563		1,503		628		591		(1,669	)	4,210


	2003
	Oil and Gas Exploration and Production		Refining		Petrochemical		Electricity		Hydrocarbons Marketing and Transportation		Corporate, Other Discontinued Investments and Eliminations		Total

Inventories at beginning	129		97		169		38		—		(38	)	395

Investories at beginning from proportional interest in CIESA	—		—		—		—		3		—		3

Effect of traslation	(10	)	—		(6	)	—		—		—		(16	)

Costs (Section e)	1,383		54		149		283		156		1		2,026

Holding gain (losses)	2		12		—		1		—		(6	)	9

Purchases, consumption and other	54		1,146		824		236		133		(1,044	)	1,349

Inventories at end	(110	)	(129	)	(155	)	(35	)	(8	)	57		(380	)

Costs of sales	1,448		1,180		981		523		284		(1,030	)	3,386


	2002
	Oil and Gas Exploration and Production		Refining		Petrochemical		Electricity		Hydrocarbons Marketing and Transportation	Corporate, Other Discontinued Investments and Eliminations		Total

Inventories at beginning	92		75		130		28		2	231		558

Effect of traslation	4		—		3		—		—	—		7

Costs (Section e)	1,538		40		157		337		3	55		2,130

Holding gain (losses)	16		(43	)	(4	)	5		—	21		(5	)

Purchases, consumption and other	79		969		775		299		6	(939	)	1,189

Assets for sales	—		—		—		(23	)	—	(177	)	(200	)

Inventories at end	(129	)	(97	)	(169	)	(38	)	—	38		(395	)

Costs of sales	1,600		944		892		608		11	(771	)	3,284

F - 102

d) Foreign currency assets and liabilities as of December 31, 2004 and 2003

(Stated in millions of Argentine Pesos - See Note 2.c)


	Foreign currency and amount		Exchange rate	Book amount in local currency
CURRENT ASSETS
Cash	US$	14	2.9800	42
	BS	14,221	0.0015	22

				64

Investments	US$	246	2.9800	733
	Rs	16	1.1222	18

				751

Trade receivables	US$	207	2.9800	617
	Rs	120	1.1222	135
	BS	2,586	0.0015	4

				756

Other receivables	US$	100	2.9800	297
	BS	61,409	0.0015	95
	$ Bol	16	0.3697	6
	Rs	26	1.1222	29

				427

Other assets	U$S	4	2.9800	12

	TOTAL 2004			1,946

	TOTAL 2003			1,909


NON-CURRENT ASSETS

Trade receivables	US$	6	2.9800	18

Other receivables	US$	5	2.9800	15
	BS	49,774	0.0015	77

				92

Investments	US$	107	2.9800	320

	TOTAL 2004			430

	TOTAL 2003			441

TOTAL ASSETS	2004			2,376

	2003			2,350


	Foreign currency and amount		Exchange rate	Book amount in local
CURRENT LIABILITIES
Accounts payable	US$	144	2.9800	428
	Rs	55	1.1222	62
	BS	39,431	0.0015	61
	Sol	1	0.9089	1

				552

Short-term debt	US$	541	2.9800	1,613

Payroll and social security taxes	$ Bol	3	0.3697	1
	Sol	2	0.9089	2
	BS	1,293	0.0015	2
	Rs	4	1.1222	5
	US$	1	2.9800	3

				13

Taxes payable	US$	5	2.9800	16
	Rs	21	1.1222	24
	$ Bol	27	0.3697	10
	BS	23,917	0.0015	37

				87

Other liabilities	Rs	2	1.1222	2
	U$S	151	2.9800	449

				451

	TOTAL 2004			2,716

	TOTAL 2003			4,069


NON-CURRENT LIABILITIES
Accounts payable	US$	7	2.9800	22

Long-term debt	US$	2,076	2.9800	6,185

Taxes payable	Rs	20	1.1222	23
	BS	6,464	0.0015	10
	U$S	33	2.9800	98

				131

Other liabilities	US$	31	2.9800	92
	BS	1,939	0.0015	3

				95

	TOTAL 2004			6,433

	TOTAL 2003			5,534

TOTAL LIABILITIES	2004			9,149

	2003			9,603

US$	Millions of American Dollars

BS	Millions of Bolivares

RS	Millions of Reales

$ Bol

Millions of Bolivian Pesos

Sol	Millions of Peruvian Soles

F - 103

e) Consolidated detail of expenses incurred and depreciation for the years ended December 31, 2004, 2003 and 2002

(Stated in millions of Argentine Pesos - See Note 2.c)


	2002		2003		2004
Accounts	Total		Total		Total		Costs		Administrative and selling expenses		Exploration expenses
Salaries and wages	268		266		286		123		162		1
Social security taxes	32		37		43		20		23		—
Other benefits to personnel	58		100		98		32		66		—
Taxes, charges and contributions	51		47		53		46		6		1
Fees and professional advisory	81		80		99		40		59		—
Depreciation of property, plant and equipment	1,051		1,016		1,058		987		71		—
Amortization of other assets	8		14		8		6		2		—
Oil and gas royalties	348		332		350		350		—		—
Spares and repairs	103		110		136		134		2		—
Geological and geophysical expenses	28		6		7		—		—		7
Transportation and freights	156		178		201		37		164		—
Construction contracts and other services	328		309		405		312		93		—
Impairment of unproved oil and gas properties	17		180		80		—		—		80
Fuel, gas, energy and other	37		35		44		43		1		—
Other operating costs and consumption	290		170		310		255		55		—
Recovery of expenses	(59	)	(99	)	(85	)	(21	)	(64	)	—

Total 2004					3,093		2,364		640		89

Total 2003			2,781				2,026		559		196

Total 2002	2,797						2,130		609		58

F - 104

f) Information about ownership in subsidiaries and affiliates as of December 31, 2004


	% OF OWNERSHIP AND VOTES		BUSINESS SEGMENT
Subsidiaries	DIRECT	INDIRECT	BUSINESS SEGMENT
Corod Producción S.A. (Venezuela)	—	98.21	Oil and Gas Exploration and Production
Ecuadortlc S.A. (Ecuador)	—	98.21	Oil and Gas Exploration and Production
Enecor S.A.	—	68.74	Electricity
Innova S.A. (Brasil)	—	98.21	Petrochemical
PESA Energía de México S.A. de C.V. (México)	—	98.21	Oil and Gas Exploration and Production
Petrobras Finance Bermuda (Islas Bermudas)	—	98.21	Electricity
Petrobras Holding Austria AG (Austria)	—	98.21	Corporate
Petrobras de Valores Internacional de España S.A. (España)	—	98.21	Corporate
Petrobras Energía Internacional S.A.	—	98.21	Corporate
Petrobras Energía Operaciones S.A. (Ecuador)	—	98.21	Oil and Gas Exploration and Production
Petrobras Financial Services Ltd, (Gran Cayman)	—	98.21	Corporate
Petrobras Financial Services Austria GMBH (Austria)	—	98.21	Corporate
Petrobras Hispano Argentina S.A. (España)	—	98.21	Corporate
Petrobras Bolivia Internacional S.A. (Bolivia)	—	98.21	Corporate
Petrobras Energía Ecuador (Gran Cayman)	—	98.21	Oil and Gas Exploration and Production
Petrobras Energia Perú S.A. (Perú)	—	98.21	Oil and Gas Exploration and Production
Petrobras Energia Venezuela S.A. (Venezuela)	—	98.21	Oil and Gas Exploration and Production
Petrolera San Carlos S.A. (Venezuela)	—	98.21	Oil and Gas Exploration and Production
Petroleum Commercial Supply, Inc. (EEUU)	—	98.21	Other investment
Transporte y Servicios de Gas en Uruguay S.A.	—	66.93	Hydrocarbons Marketing and Transportation
World Energy Business S.A.	—	99.21	Hydrocarbons Marketing and Transportation
World Fund Global Investment (Gran Cayman)	—	98.21	Corporate
World Fund Financial Services (Gran Cayman)	—	98.21	Corporate
Petrobras Energia S.A.	98.21	—	Corporate

Main affiliates - join control

Cia. de Inversiones de Energía S.A.	—	49.10	Hydrocarbons Marketing and Transportation
Citelec S.A.	—	49.10	Electricity
Distrilec Inversora S.A.	—	47.63	Electricity
Edesur S.A.	—	26.84	Electricity
Transba S.A.	—	28.72	Electricity
Transener S.A.	—	31.91	Electricity
Transportadora de Gas del Sur S.A.	—	34.37	Hydrocarbons Marketing and Transportation

Main affiliates - significance influence

Coroil S.A. (Venezuela)	—	48.12	Oil and Gas Exploration and Production
Empresa Boliviana de Refinación S.A. (Bolivia)	—	48.10	Refining
Hidroneuquén S.A.	—	9.02	Electricity
Inversora Mata S.A. (Venezuela)	—	48.12	Oil and Gas Exploration and Production
Oleoducto de Crudos Pesados Ltd. (Gran Cayman)	—	11.22	Hydrocarbons Marketing and Transportation
Oleoducto de Crudos Pesados S.A. (Ecuador)	—	11.22	Hydrocarbons Marketing and Transportation
Oleoductos del Valle S.A.	—	22.69	Hydrocarbons Marketing and Transportation
Propyme S.G.R	—	49.08	Corporate
Petrolera Entre Lomas S.A.	—	18.87	Oil and Gas Exploration and Production
Petroquímica Cuyo S.A.	—	39.28	Petrochemical
Refinería del Norte S.A.	—	27.99	Refining
Urugua-í S.A.	—	28.80	Electricity
Yacylec S.A.	—	21.82	Electricity

F - 105

g) Oil and gas areas and participation in joint-ventures as of December 31, 2004


NAME	LOCATION	WORKING INTEREST (2)		OPERATOR	DURATION THROUGH
Production

Argentina

25 de Mayo - Medanito S.E.	La Pampa y Río Negro	100.00	%	Petrobras Energía	2016
Jagüel de los Machos	Río Negro y La Pampa	100.00	%	Petrobras Energía	2015
Puesto Hernández - U.T.E.	Mendoza y Neuquén	38.45	%	Petrobras Energía	2016
Bajada del Palo - La Amarga Chica - U.T.E.	Neuquén	80.00	%	Petrobras Energía	2015
Santa Cruz II - U.T.E.	Santa Cruz	100.00	%	Petrobras Energía	2017
Río Neuquén	Neuquén y Río Negro	100.00	%	Petrobras Energía	2017
Entre Lomas	Neuquén y Río Negro	17.90	%	Petrolera Entre Lomas S.A.	2016
Aguada de la Arena	Neuquén	80.00	%	Petrobras Energía	2022
Veta Escondida y Rincón de Aranda - U.T.E.	Neuquén	55.00	%	Petrobras Energía	2016
Santa Cruz I - U.T.E.	Santa Cruz	71.00	%	Petrobras Energía	2016

Foreign

Colpa - Caranda	Bolivia	100.00	%	Petrobras Energía	2029
Oritupano - Leona	Venezuela	55.00	%	PE Venezuela	2014
Acema	Venezuela	86.23	%	Petrolera Coroil	2017
La Concepción	Venezuela	90.00	%	PE Venezuela	2017
Mata	Venezuela	86.23	%	Petrolera Mata	2018
Lot X	Perú	100.00	%	PE Perú	2024
Block 18 (3)	Ecuador	70.00	%	Ecuadortlc	2022
Block 31 (3)	Ecuador	100.00	%	Petrobras Energía	2024

Exploration

Argentina

Glencross (1)	Santa Cruz	96.68	%	Petrobras Energía	1999
Santa Cruz I - Oeste	Santa Cruz	100.00	%	Petrobras Energía	2006
Santa Cruz II - Oeste (1)	Santa Cruz	100.00	%	Petrobras Energía	2005

Foreign

San Carlos	Venezuela	50.00	%	Pet. San Carlos	2005
Tinaco	Venezuela	50.00	%	PE Venezuela	2005

(1)	Petrobras Energía has requested that the lot be declared operational with commercial operation held in suspense.

(2)	Indirect interest through Petrobras Energía and its subsidiaries.

(3)	See Note 26

F - 106

h) Combined joint-ventures and consortia assets and liabilities as of December 31, 2004 and 2003 and results for the years ended December 31, 2004, 2003 and 2002.

(Stated in millions of Argentine Pesos - See Note 2.c)


	2004	2003
Assets and liabilities

Current assets	920	687
Non-current assets	3,536	2,726

Total assets	4,456	3,413

Current liabilities	390	353
Non-current liabilities	74	25

Total liabilities	464	378


	2004		2003		2002
Statement of income
Net sales	1,437		1,071		1,224
Costs of sales	(678	)	(536	)	(661	)

Gross profit	759		535		563

Administrative and selling expenses	(72	)	(40	)	(66	)
Exploration expenses	(6	)	(6	)	(25	)
Other operating (expenses) income, net	(111	)	18		(13	)
Financial income and holding gains	92		2		1,195
Income tax provision	(22	)	13		(14	)

Net income	640		522		1,640

F - 107