Edgar Filing: PETROBRAS ENERGIA PARTICIPACIONES SA

Year ended December 31,

Production (thousands of tons)

Sales (in millions of pesos)

Form 20-F

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, 2005

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, 2005 was:


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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.

Yes ¨ No x

If this report is an annual or transitional report, indicate by check mark if the registrant is not required to file reports pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934.

Yes ¨ No x

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 whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer ¨		Accelerated filer x		Non-accelerated filer ¨

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

Item 17 ¨ Item 18 x

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ¨ No x

TABLE OF CONTENTS


		Page
Items 1-2.	Not Applicable	2

Item 3.	Key Information	2

	Selected Financial Data	2

	Exchange Rates	6

	Risk Factors	7

Item 4.	Information About the Company	14

	Oil and Gas Exploration and Production	19

	Refining and Distribution	38

	Petrochemicals	43

	Gas and Energy	47

	Regulation of Our Businesses	61

	Organization Structure	81

Item 5.	Operating and Financial Review and Prospects	84

	Factors Affecting our Consolidated Results of Operations	87

	Discussion of Results	99

Item 6.	Directors, Senior Management and Employees	143

Item 7.	Major Shareholders and Related Party Transactions	154

Item 8.	Financial Information	157

Item 9.	Offer and Listing	158

Item 10.	Additional Information	160

Item 11.	Quantitative and Qualitative Disclosures About Market Risk	176

Items 12-14.	Not Applicable	179

Item 15.	Controls and Procedures	179

Item 16A.	Audit Committee Financial Expert	180

Item 16B.	Code of Ethics	180

Item 16C.	Principal Accountant Fees and Services	180

Item 16D.	Not Applicable	181

Item 16E.	Purchases Of Equity Securities By The Issuer And Affiliated Purchasers	181

Item 17.	Not Applicable	181

Item 18.	Financial Statements	181

Item 19.	Exhibits

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.

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

FORWARD-LOOKING STATEMENTS

Some of the information included in this annual report contains information that is forward looking, including statements regarding capital expenditures, competition and sales, oil and gas reserves and prospects and trends in the oil and gas, refining and distribution, 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 and oil products;

•

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.

Forward-looking statements speak only as of the date they were made. 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. In light of these limitations, you should not place undue reliance on forward looking statements contained in this annual report.

Items 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) or 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), or Argentine GAAP. Argentine GAAP differs in certain significant respects from generally accepted accounting principles in the United States, or U.S. GAAP. Note 21 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 22 provides a reconciliation to U.S. GAAP of net income, shareholders’ equity and certain other selected financial data.

Petrobras Energía Merger

Our selected financial data relating to the fiscal years ended December 31, 2005, 2004 and 2003 has been derived from our financial statements included in this annual report. The selected financial data relating to the years ended December 31, 2004 and 2003 has been restated to reflect the effects of the merger of Petrobras Argentina S.A., Petrolera Santa Fe S.A., and EG3 S.A. into Petrobras Energía S.A. as if the merger had occurred on January 1, 2003, according to the pooling of interest method. According to the pooling of interest method, total shareholders’ equity and net income relating to the years ended December 31, 2004 and 2003 remain unchanged as compared to amounts presented prior to the merger and the balancing items resulting from the addition of assets, liabilities and results are recorded under Minority Interest in Subsidiaries See “Item 4. Information About the Company—Petrobras Energía Merger”. Selected financial data for the years ended December 31, 2002 and 2001 is not presented because we were not able to restate it to give effect to the abovementioned merger without unreasonable effort or expense.

Presentation of figures in constant Argentine pesos

Under Argentine GAAP, we may be required to restate our financial statements in constant pesos depending on the level of inflation. In 2002, Argentina experienced a high rate of inflation, with the wholesale price index increasing by approximately 118%. We were required by CNV Resolution No. 415/2002 to restate our financial statements in constant pesos. As the inflation rate declined, in April 2003 the CNV through Resolution No. 441/2003 discontinued inflation accounting as of March 1, 2003. As a result, our financial statements as of and for the year ended December 31, 2003 include the effects of inflation through February 28, 2003, and we have not restated our financial statements for inflation since February 28, 2003.

Proportional consolidation of companies under which we exercise joint control

In accordance with the procedure set forth in Technical Resolution No. 21 of the Argentine Federation of Professional Councils in Economic Science, or FACPCE, we have consolidated our financial statements line by line on a proportional basis with the companies in which we exercise joint control (other than Compañía Inversora en Transmisión Eléctrica Citelec S.A., or Citelec). 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 weighted average number of shares outstanding during each year (assuming all Class A shares are converted into Class B shares);

•

for 2005, 2004 and 2003 , net income per share was calculated by dividing net income by the weighted average number of shares outstanding during each year (as of October 2002, all outstanding Class A shares were converted into Class B shares);

U.S. GAAP Information

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 U.S. GAAP information.

The proportional consolidation of Compañía de Inversiones de Energía S.A., which we refer to as CIESA, another company under joint control, in 2005, 2004 and 2003 under Argentine GAAP has been reversed in the U.S. GAAP information. This reversal was a result of (1) CIESA having negative shareholders’ equity for the years ended 2005, 2004 and 2003 for purposes of U.S. GAAP, and (2) our not having assumed commitments to make capital contributions 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,
	2005		2004		2003
	(in millions of pesos, except for per share amounts and share capital or as otherwise indicated)
Income Statement Data
Argentine GAAP:
Net sales	10,655		8,763		7,113
Cost of sales	(7,058	)	(5,791	)	(4,759	)

Gross profit	3,597		2,972		2,354
Administrative and selling expenses	(941	)	(847	)	(770	)
Exploration expenses	(34	)	(133	)	(360	)
Other operating (expense) income, net	(329	)	(324	)	(123	)

Operating income	2,293		1,668		1,101
Equity in earnings of affiliates	166		76		163
Financial income (expense) and holding gains (losses)	(899	)	(1,265	)	(387	)
Other (expense) income, net	(332	)	(40	)	(447	)

Income (loss) before income tax and minority interest in subsidiaries	1,228		439		430
Income tax provision	(381	)	211		(29	)
Minority interest in subsidiaries	(234	)	28		(20	)

Net income (loss)	613		678		381
Basic net (loss) income per share:
Class A⁽¹⁾	—		—		—
Class B	0.289		0.319		0.179
Diluted net (loss) income per share	0.289		0.319		0.179
Number of shares outstanding (in millions):
Class A⁽¹⁾	—		—		—
Class B	2,132		2,132		2,132
U.S. GAAP:
Net sales	10,129		8,232		6,697
Operating income	613		1,348		647
Income (loss) from continuing operations⁽²⁾	(77	)	760		109
Income (loss) from discontinued operations	—		—		(39	)
Cumulative effect of changes in accounting principles	—		—		30
Net income (loss)⁽³⁾	(77	)	760		100
Basic net (loss) income per share:
Class A⁽¹⁾	—		—		—
Class B	(0.036	)	0.356		0.047
Diluted net (loss) income per share	(0.036	)	0.356		0.047
Basic net (loss) income per share:
Class A⁽¹⁾
Continuing operations	—		—		—
Discontinued operations	—		—		—
Class B
Continuing operations	(0.036	)	0.356		0.051
Discontinued operations	—		—		(0.018	)
Cumulative effect of changes in accounting principles	—		—		0.014

⁽¹⁾	As of October 2002, there are no Class A shares outstanding.

⁽²⁾	After minority interest in subsidiaries and income tax (expense) benefit.

⁽³⁾

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, 2003, net income (loss) for the year ended December 31, 2003 would have been P$70 million.

Balance Sheet Data



	Year Ended December 31,
	2005		2004		2003
	(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	104		139		168
Investments	857		934		952
Trade receivables	1,596		1,181		996
Other receivables	626		756		921
Inventories	782		627		433
Other assets	1		1		3

Total current assets	3,966		3,638		3,473
Non-current assets
Trade receivables	78		47		41
Other receivables	672		784		210
Inventories	79		71		77
Investments	1,172		1,323		1,284
Property, plant and equipment	12,847		12,347		12,312
Other assets	47		65		88

Total non-current assets	14,895		14,637		14,012

Total assets	18,861		18,275		17,485

Liabilities
Current liabilities
Accounts payable	1,483		1,181		950
Short-term debt	1,805		1,709		3,238
Payroll and social security taxes	177		98		99
Taxes payable	228		215		214
Other current liabilities	216		688		432

Total current liabilities	3,909		3,891		4,933
Non-current liabilities
Accounts payable	14		26		7
Long-term debt	5,708		6,248		5,098
Other liabilities	543		332		300
Reserves	103		76		79

Total non-current liabilities	6,368		6,682		5,484

Total liabilities	10,277		10,573		10,417

Transitory differences
Measurement of derivative financial instruments designated as effective hedge	—		(2	)	(18	)
Foreign currency translation	(22	)	(47	)	(56	)
Total transitory differences	(22	)	(49	)	(74	)
Minority interest in subsidiaries	2,482		2,240		2,309
Total shareholders’ equity	6,124		5,511		4,833
Total liabilities and shareholders’ equity	18,861		18,275		17,485

Capital Stock	2,132		2,132		2,132

Dividends
Per Class A share	—		—		—
Per Class B share	—		—		—
U.S. GAAP:
Total assets	16,158		16,751		16,211
Shareholders’ equity	5,233		5,286		4,523

EXCHANGE RATES

From April 1, 1991 until the end of 2001, the Convertibility Law established a fixed exchange rate under which the Central Bank was obliged to sell U.S. dollars at a fixed rate of one peso per U.S. dollar. On January 6, 2002, the Argentine Congress enacted the Public Emergency and Foreign Exchange System Reform Law No. 25,562 (“The Public Emergency Law”), which suspended certain provisions of the Convertibility Law, including the fixed exchange rate of P$1 to U.S.$1, and granted the executive branch of the Argentine government the power to set the exchange rate between the peso and foreign currencies and to issue regulations related to the foreign exchange market. Following a brief period during which the Argentine government established a temporary dual exchange rate system, pursuant to the Public Emergency Law, the peso has been allowed to float freely against other currencies since February 2002.

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


	Exchange Rate
	High	Low	Average⁽¹⁾			Period End
	(in pesos)
Year Ended December 31,
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
2005

Most Recent Six Months:
December, 2005⁽²⁾	3.04	2.97		3.01	3.03
January, 2006⁽²⁾	3.06	3.03		3.05	3.06
February, 2006⁽²⁾	3.08	3.07		3.07	3.08
March, 2006⁽²⁾	3.08	3.07		3.08	3.08
April, 2006⁽²⁾	3.09	3.04		3.07	3.05
May, 2006⁽²⁾	3.04	2.97		3.01	3.03
June, 2006⁽²⁾⁽³⁾	3.08	3.08		3.08	3.08

⁽¹⁾	Based on monthly average exchange rates.

⁽²⁾	Source: Banco de la Nación Argentina.

⁽³⁾	Through June 16, 2006.

Exchange controls

Prior to December 1989, the Argentine foreign exchange market was subject to exchange controls. From December 1989 until April 1991, Argentina had a freely floating exchange rate for all foreign currency transactions, and the transfer of dividend payments in foreign currency abroad and the repatriation of capital were permitted without prior approval of the Central Bank. From April 1, 1991, when the Convertibility Law became effective, until December 21, 2001, when the Central Bank decided to close the foreign exchange market, the Argentine currency was freely convertible into U.S. dollars.

On December 3, 2001, the Argentine government imposed a number of monetary and currency exchange control measures, which included restrictions on the free disposition of funds deposited with banks and tight restrictions on transferring funds abroad without the Central Bank’s prior authorization subject to specific exceptions for transfers related to foreign trade. The Central Bank has gradually eased these restrictions with a view to gradually normalizing the domestic exchange market, and as a result, most restrictions relating to the repayment of foreign creditors and the payment of dividends to foreign shareholders have been lifted. In June 2003 the Argentine government set restrictions on capital flows into Argentina, which mainly consisted of a prohibition against the transfer abroad of any funds until 180 days after their entry into the country. Furthermore, in June 2005 the Argentine government established further restrictions on capital flows into Argentina, including increasing the period that certain incoming funds, must remain in Argentina to 365 calendar days and requiring that 30% of incoming funds be deposited with a bank in Argentina in a non-transferable, non-interest bearing account for 365 calendar days. Export and import financing operations, as well as primary public offerings of debt securities listed on self-regulated markets, are exempt from the foregoing provision.

RISK FACTORS

Factors Relating to Argentina

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

We are an Argentine corporation (sociedad anónima). As of December 31, 2005, approximately 58% of our total assets, 66% of our net sales, 54% of our combined crude oil and gas production and 40% of our proved oil and gas reserves were located in Argentina. Fluctuations in the Argentine economy and government actions adopted by the Argentine government have had and may continue to have a significant effect on Argentine entities, including us. Specifically, we have been affected and might be affected by interest rates, the value of the peso against foreign currencies, price controls, business and 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. During 2001 and 2002, Argentina went through a period of severe political, economic and social crisis. See “Item 4. Information About the Company–Business Overview–Our Principal Market” for a description of the crisis.

The crisis had significant and adverse consequences on our company, including (1) losses derived from the effects of peso devaluation on our and our affiliates’ net borrowing position, which primarily was denominated in U.S. dollars, (2) the impairment of the book value of certain gas areas and tax assets due to material changes in the prospects of our operations, (3) a decrease in U.S. dollar cash flows due to 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 reduced our investment plan and reached an agreement with our financial creditors to extend the maturity of a substantial portion of our debt, at face value. During this period, we continued to make scheduled payments on our debt. 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.

Although the economy has recovered significantly over the past three years, uncertainty remains as to whether the current growth and relative stability is sustainable. Sustainable economic growth is dependent on a variety of factors, including international demand for Argentine exports, the stability and competitiveness of the peso against foreign currencies, confidence among consumers and foreign and domestic investors and a stable and relatively low rate of inflation. As in the recent past, Argentina’s economy may suffer if political and social pressures inhibit the implementation by the Argentine government of policies designed to maintain price stability, generate growth and enhance consumer and investor confidence. Further, Argentine government actions concerning the economy, including with respect to inflation, interest rates, price controls, foreign exchange controls and taxes, have had, and may continue to have, a material adverse effect on Argentine 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 on 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 market. The prospects for all Argentine companies, including us, of accessing financial markets are challenging. If we are unable to have access to the international financial markets to refinance our indebtedness at reasonable cost or under adequate conditions, we may have to reduce our projected capital expenditures, which, in turn, may affect the implementation of our business plan.

Fluctuations in the value of the peso may adversely affect the Argentine economy and our financial condition and result of operations.

The value of the peso has fluctuated significantly in the past and may do so in the future. Since the end of the U.S. dollar-peso parity in January 2002, the peso has fluctuated significantly in value. As a result, the Central Bank has taken several measures to stabilize the exchange rate and preserve its reserves. The marked devaluation of the peso in 2002 had a negative impact on the ability of the Argentine government and Argentine companies to honor their foreign currency-denominated debt, led to very high inflation initially, significantly reduced real wages, had a negative impact on businesses whose success is dependent on domestic market demand, including public utilities.

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 U.S. dollars. Before the enactment of the Public Emergency Law, our cash flow, generally denominated in U.S. 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.

If the peso devalues significantly, all of the negative effects on the Argentine economy related to such devaluation could recur, with adverse consequences to our business. On the other hand, a substantial increase in the value of the peso against the U.S. dollar also presents risks for the Argentine economy and may lead to a deterioration of the country’s current account balance and the balance of payments.

We are unable to predict whether, and to what extent, the value of the peso may further depreciate or appreciate against the U.S. dollar and how any such fluctuations would 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 U.S. 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%.

Despite a decline to 3.7% in 2003, the consumer price index increased again to 6.1% in 2004 and to 12.3% in 2005. Wholesale inflation has also shown clear signs of acceleration in recent periods, with the wholesale price index increasing by 7.9% in 2004 and 10.8% in 2005. Uncertainty surrounding future inflation could slow the rebound in the economy. A return to a high inflation environment would also undermine Argentina’s foreign competitiveness by diluting the effects of the peso devaluation, with the same negative effects on the level of economic activity and employment. 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. 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.

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 to pay dividends.

Limits on exports of hydrocarbons and related oil products have affected and may continue to affect our results of operations.

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 and related oil products.

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. In April 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. During 2005, the Secretary of Energy requested producers to redirect export gas to supply thermal plants and gas distribution companies. This decision limited our total gas export volumes by an average of about 110 thousand cubic meters per day, which deprived us of the higher margins offered by export prices. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Natural Gas” for further details.

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—Refining—Modifications to the Regulatory Framework”.

We cannot assure you that the Argentine government will not impose additional export restrictions on hydrocarbons and related oil products. If it were to do so, our results of operations could be adversely affected.

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 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 U.S.$32.01 per barrel to 20% when the price is U.S.$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 prevented us from fully benefiting from the significant increases in international oil, oil products and gas 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 in 2002, 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. See “Item 4 – Regulation of our Businesses”.

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.

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 2007.

With respect to electricity generation, in December 2004, the Secretary of Energy agreed 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 following the start of commercial operations of the new generation capacity derived from the government maintained fund called FONINVEMEM, 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 capacity at the U.S. 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 price increases fail to be implemented by the Argentine government or (2) the government applies its regulatory emergency authority or adopts other laws to control prices or supply.

Downstream margins

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

In line with Argentine macroeconomic indicators and the economic recovery started in 2003, in 2005 the gas oil domestic market grew for the third year in a row, ending a four-year period of decline since 1999. Total sales volumes increased 8% and 9% in 2005 and 2004, respectively. During the first four months of 2006 the diesel oil market confirmed this upward trend, showing a 3.5% rise compared to the same period of 2005. In terms of supply, refining units in Argentina are operating at levels very close to maximum installed capacity. The lack of elasticity in supply could result in temporary shortages.

Since this situation might hinder the evolution of the Argentine economy, regulatory framework changes led refining companies to take all actions necessary to meet a growing demand, including import of the product. Considering the differential between import and retail prices and the impossibility to pass it through to consumers, imports of diesel oil have resulted in significant losses to refining companies.

We cannot assure you that new regulations will be adopted that oblige us to import diesel oil and, if so, what impact these changes will have on our financial condition and results of operation.

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 macroeconomic state of the country after the 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 and pay dividends. Although some of these utility companies have been successful in restructuring their indebtedness, their return to financial stability and profitability on a long-term basis depends on a successful negotiation of tariff increases with the Argentine government. UNIREN (the agency created by the Argentine government 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 stated that UNIREN’s latest proposals were not sufficient. See “Item 4. Information About the Company— Gas and Energy — Gas Transportation - TGS—Regulated Energy Segment” and “Item 4. Information About the Company—Gas and Energy—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener” and “Information About the Company—Regulation of Our Businesses—UNIREN”. We cannot assure you that these discussions will ultimately result in a level of tariff increases sufficient to return to financial stability and profitability on a long-term basis.

Factors Relating to the Company

Substantial or extended declines in the prices of crude oil and oil products may have a material adverse effect on our results of operations and financial condition.

A significant amount of our revenue is derived from sales of crude oil and oil products. We do not and will not have control over factors affecting international prices for crude oil and its by-products. These factors include: political developments in crude oil producing regions; the ability of the Organization of Petroleum Exporting Countries (OPEC) and other crude oil producing nations to set and maintain crude oil production levels and prices; global supply and demand for crude oil; competition from other energy sources; government regulations; weather conditions; and global conflicts or acts of terrorism.

Changes in crude oil prices typically result in changes in prices for oil products. International oil prices have fluctuated widely over the last ten years. In 2005, crude oil prices continued their upward trend, exceeding 2004 historical records. The WTI closed at U.S.$61.1 per barrel, with an average of U.S.$56.6 per barrel during the year. During 2004 and 2003 the average WTI was U.S.$41.5 and U.S.$31 per barrel, respectively, compared to an average of U.S.$22.56 per barrel for the period 1994-2003.

Substantial or extended declines in international crude oil prices may have a material adverse effect on our business, results of operations and financial condition, and the value of our proved reserves. In addition, significant decreases in the price of crude oil may cause us to reduce or alter the timing of our capital expenditures, and this could adversely affect our production forecasts in the medium term and our reserve estimates in the future.

Our crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time.

The proved crude oil and natural gas reserves set forth in this annual report are our estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions (i.e. with prices and costs as of the date the estimate is made). Our proved developed crude oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Our reserve estimates have been audited by Gaffney, Cline & Associates, an international technical consulting firm for the oil and gas industry. As of December 31, 2005, the auditors’ technical review covered 95% of the Company’s estimated reserves for 2005. 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—Estimate 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.

In recent years, we have experienced a decline in reserves and production. In particular during the period 2003-2005, our reserves and production in Argentina have declined approximately 19% and 12%, respectively. See “Item 5. “Operating and Financial Review and Propects – Oil and gas production in Argentina”.

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 successful 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. We consider exploration, which carries inherent risks and uncertainties, the main vehicle for future growth and for replacing 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 and production may continue to decline and, therefore, may adversely affect our future results of operations and financial position.

Production of oil in Block 31 in Ecuador may be delayed significantly.

Block 31 is principally located in the Yasuní National Park, a highly ecologically sensitive area in the Amazon region of Ecuador (an area included in the National Heritage of Natural Areas and Protective Woods and Vegetation). Indigenous associations, NGA’s and environmental groups have made public demonstrations against the development of Block 31 arguing that hydrocarbon activities would endanger the park’s biodiversity.

On July 7, 2005, the Ministry of the Environment decided not to authorize the beginning of certain construction works on the Tiputini River (boundary of Parque Nacional Yasuní), and denied us entry to Parque Nacional Yasuní. This suspension prevents us from continuing our developement works in Block 31. In May 2006, we presented a new work proposal to the Ministry of the Environment in order to address its concerns on these issues, and the proposal is currently under evaluation by the Ministry of Energy and Mines and the Ministry of the Environment.

We cannot predict when, if or to what extent competent authorities will ultimately authorize us to commence planned works to develop the block. Further delays in the development of Block 31 will have an adverse impact on our results of operations and financial position, in light of our ship or pay obligations under a transportation agreement executed with OCP, under which we must fulfill our contractual obligations for the total volume committed even if no crude oil is transported.

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. In recent periods, many governments in Latin America have taken steps to assert greater control over or increase their share of revenues from the energy sector, spurred by soaring oil and gas prices and nationalistic politics. See “Item 4 – Regulation of our Businesses—Other Countries’ Regulatory Framework”.

These steps have included:

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In March 2006, prompted by changes in the Venezuelan regulatory framework, our affiliate in Venezuela entered into memorandum of understanding (“MOUs”) in order to effect the conversion of the Oritupano Leona, La Concepción, Acema and Mata’s operating agreements into mixed companies. Pursuant to these MOUs the Venezuelan government interest in these new companies will be 60% and private investors will hold the remaining 40%. This will cause our economic interests in the Oritupano Leona, La Concepción, Acema and Mata areas to decline to 22%, 36%, 34.5% and 34.5%, respectively. In view of the new contractual framework, as of December 31, 2005 we recognized impairment charges of P$424 million during 2005 to adjust the book value of our assets in Venezuela to their estimated recoverable value. As of the date of this report, there is no reliable data available regarding the definitive terms and conditions regarding future operational arrangements in Venezuela that would allow us to determine with a reasonable degree of certainty the impact of the migration on our reserves. Notwithstandig, we estimate that the conversion of our operating agreements in Venezuela is likely to adversely impact our reserves.

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In May 2006, the Bolivian government enacted Supreme Decree No. 28,701, which provides, among other things, that as from May 1, 2006 oil companies must deliver to YPFB the property of all hydrocarbon production for sale and that the Ministry of Hydrocarbons and Mines will determine, on a case-by-case basis, the interest in each field corresponding to oil companies by means of investment audits, operational costs and profitability indicators. In addition, the abovementioned decree provides, among other things, that the Bolivian government shall recover full participation in the entire oil and gas production chain, and for this purpose provides for the nationalization of the shares of stock necessary for YPFB to have at least 50% plus one of the shares in a number of companies, among which is Petrobras Bolivia Refinación. We are currently in the process of evaluating the effects of the recently announced measures on our operations. The implementation of these measures requires a number of steps that have not yet been fully defined, including a comprehensive restructuring of YPFB.

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In April 2006, the Ecuadorian government approved the Oil & Gas Reform Law, which assigns to the government an interest of at least 50% of the excess revenues resulting from the increase in the price of Ecuadorian crude (effective monthly average price of FOB price) over the average monthly sales price of such oil at the execution date of the relevant production agreement, expressed in constant values as of the calculation date. As of the date of this annual report, the administrative order implementing the terms of this law has not been issued; therefore, we cannot reasonably estimate its impact of such on our operations at this time.

These measures, and any other similar measures taken in the future by governments in countries where we conduct business, may have a material adverse effect on our business and results of operations.

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

Some of our operations are subject to environmental risks that may arise unexpectedly, and result in material adverse effects on our results of operations and financial position. In 2005, 2004 and 2003 environmental remediation costs charged to income totaled P$29 million, P$51 million and P$58 million, respectively. We may have to incur additional costs related to the environment 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 and the other countries where we operate 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 and distribution, petrochemicals and gas and energy. We conduct operations in Argentina, Bolivia, Brazil, Colombia, 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., 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 a Brazilian company whose business concentrates on exploration, production, refining, sale and transportation of oil and by-products in Brazil and abroad. Petrobras 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.

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 effective January 1, 2005. As result of the merger our interest in Petrobras Energía decreased to 75.82% from 98.21%.

History of Petrobras Energía

Petrobras Energía was founded in 1946 as a shipping company by the Perez Companc family. In 1960, Petrobras Energía began servicing oil wells and, over time, its maritime operations were gradually discontinued and replaced by oil-related activities. Petrobras Energía has become one of the largest oil and gas producers in Argentina.

Since 1994, when Petrobras Energía was awarded an exploration and production service contract for the Oritupano Leona area in Venezuela, Petrobras Energía has expanded its operations outside Argentina. Currently Petrobras Energía conducts operations in Venezuela, Peru, Ecuador, Brazil, Bolivia, Colombia and Mexico as part of its strategy to become a leading integrated energy company with an international presence.

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, forestry and mining. These businesses were sold by Petrobras Energía 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, PAR, and 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. Subsequently, on March 3, 2005 the definitive merger agreement was executed. On June 28, 2005, the CNV approved the merger and authorized the public offering of the Petrobras Energía shares. On September 16, 2005, the merger was registered in the Public Registry of Commerce. The effective merger date was set at January 1, 2005: as from this date all assets, liabilities, rights and obligations of the absorbed companies are considered incorporated into Petrobras Energía. After the merger, Petrobras Energía is the surviving entity. Pursuant to the merger, PPSL received 230,194,137 newly issued Class B shares of Petrobras Energía, representing 22.8% of Petrobras Energía’s capital stock. As a result of the merger, our ownership interest in Petrobras Energía decreased from 98.21% to 75.82%.

Through this merger, Petrobras Energía enlarged its oil and gas assets with the incorporation of six fields (a gas field in the Noroeste Basin and five crude oil fields in the Neuquén, San Jorge and Cuyana Basins). As of December 31, 2004, these areas had an aggregate production volume of approximately 19,000 barrels of oil equivalent per day and proved reserves of 95 million barrels of oil equivalent. Petrobras Energía also incorporated the Bahía Blanca refinery, which has a processing capacity of 31,000 barrels per day, strategically located to receive crude oil coming from the Neuquen Basin, and a wide network of gas stations (approximately 620) throughout the country, that operate under the Petrobras and EG3 brands.

Petrobras Energía recorded the effects of the merger under the pooling of interests method. According to this method, the assets, liabilities and shareholders’ equity of the combining entities are recorded by the surviving entity according to the accounting measurements used by the combining entities on the effective date of the merger. In addition, according to the “pooling of interest method”, financial statements for previous years reflect the assets, liabilities, results and cash flows of the surviving entity as if the pooling of interests had occurred at the beginning of the earliest fiscal year presented.

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 an international presence, 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 in Argentina and elsewhere in South America 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 the regional petrochemicals market, 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 recognized 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 four business segments: (1) Oil and Gas Exploration and Production, (2) Gas and Energy, (3) Refining and Distribution, and (4) Petrochemicals. In keeping with management’s evaluation of our businesses, during 2005, we implemented certain minor changes to our segment information. We grouped electricity and sale and transport of gas under the Gas and Energy segment. The sale and transport of gas formerly comprised, along with sale and transport of petroleum, the Hydrocarbon Marketing and Transportation business segment. We grouped sale and transport of petroleum with the Oil and Gas Exploration and Production segment. The information in this annual report for all periods is presented in accordance with the current management’s evaluation.

Our Principal Market

We are an Argentine corporation and, as of December 31, 2005, 58% of our total assets, 66% of our net sales, 54% of our combined crude oil and gas production and 40% 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, 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 U.S. dollar. To address these pressures, the Argentine government during this period implemented various plans and utilized a number of exchange rate systems and controls.

In April 1991, the Argentine government launched a plan aimed at controlling inflation and restructuring the economy, enacting the Convertibility Law. The Convertibility Law fixed the exchange rate at one peso per U.S. dollar and required that the Central Bank maintain reserves in gold and foreign currency at least equivalent to the monetary base. Following the enactment of the Convertibility Law, inflation declined steadily and the economy experienced growth through most of the period from 1991 to 1997. In the fourth quarter of 1998, however, the Argentine economy entered into a recession that caused the gross domestic product to decrease by 3.4% in 1999, 0.8% in 2000 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 U.S. dollar led to a massive withdrawal of deposits from banks and capital outflows. To prevent further capital outflows, on December 1, 2001, the Argentine government implemented a number of monetary and exchange control measures 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 U.S. dollar-peso parity established since the enactment of the Convertibility Law in 1991, leading to a significant devaluation of the Argentine peso. The Public Emergency Law also empowered the federal executive branch of Argentina to implement, among other things, additional monetary, financial and exchange measures to overcome the economic crisis in the short term, such as determining the rate at which the peso was to be exchanged into foreign currencies.

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

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

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

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Implementation of taxes on hydrocarbon exports and certain oil 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.

In May 2003, Mr. Kirchner took office as Argentina’s president. Under his leadership, Argentina conducted several rounds of negotiations 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 over the next several years.

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

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.

During 2005, Argentina experienced high growth rates. Real GDP growth was 9.2% for the year. All GDP components improved significantly, particularly investment and imports. Industrial production continued to grow, and some industrial sectors were close to the limit of their installed capacity. After three years of growth at around 9%, the Argentine economy was able to surpass the levels recorded in 1998, before the crisis. Argentine exports hit a historic record of U.S.$40 billion, although it was not enough to keep the trade surplus of the last years due to increased imports (around 30%). In line with the explicit decision of the government to maintain a stable exchange rate between the U.S. dollar and the peso, the Central Bank systematically intervened in the foreign exchange market to prevent the Argentine peso from appreciating. Continued purchases by the Central Bank put international reserves over U.S.$28 billion by late December 2005. Furthermore, in 2005, inflation notably accelerated and reached 12.3% for retail prices and 10.8% for wholesale prices.

In 2005, the administration was able to restructure the government debt in default (76% of creditors accepted the government’s exchange proposal) with a significant nominal reduction in principal amount, a term extension and a reduction in interest coupons. It also called for the first debt auction after the default. These factors, together with an international favorable climate, helped reduce the country risk to an annual average of 450 basis points (Boden 2012). In addition, in January 2006, Argentina fully prepaid the full amount of debt outstanding with the IMF (around U.S.$10 billion), using Central Bank reserves.

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 oil and gas reserves and 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:

•

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

•

Optimizing our investment portfolio by balancing exploration projects with development projects.

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

As of December 31, 2005 our combined crude oil and natural gas proved reserves, including our shares of the reserves of our unconsolidated investees, were estimated at 760 million barrels of oil equivalent, approximately 50.6% of which were proved developed reserves and approximately 49.4% of which were proved undeveloped reserves. Crude oil accounted for approximately 70.8% of our combined proved reserves, while natural gas accounted for about 29.2%. As of December 31, 2005, 39.8% of our total combined proved reserves were located in Argentina and 60.2% were located abroad.

For the year ended December 31, 2005, our combined crude oil and natural gas production, including our share of the production of our unconsolidated investees, averaged 171,400 barrels of oil equivalent per day, a decrease of 6.3% compared to 182,900 barrels of oil equivalent per day in 2004. Crude oil production volume decreased 4.6% to 122.5 thousand barrels per day and gas volumes decreased 10.2% to 293.7 million cubic feet. Approximately 55.5% of our oil production and 21.1% of our gas production were outside of Argentina.

As of December 31, 2005, estimated proved oil and gas reserves attributable to operations in Venezuela amounted to 269 million of barrels of oil equivalent, accounting for 35.4% of the Company’s total reserves, and accounted for 27.9% of our total average production in barrels of oil equivalent. Information on oil and gas producing activities as of December 31, 2005 attributable to the Company’s operations in Venezuela was calculated on the basis of the contractual structure in force as of such date. See “—Production—Production outside of Argentina—Venezuela”. The contractual structure governing our investments in fields in Venezuela has changed significantly since December 31, 2005, and this change is likely to adversely impact our reserves.

Estimated proved reserves as of December 31, 2005, attributable to our operations in Bolivia were certified under the agreements and the regulatory framework in force as of December 31, 2005. However, as provided by the Supreme Decree No. 28,701, issued in May 2006, as from May 1, 2006 oil companies will have to deliver to YPFB the property of all hydrocarbons for sale. We are currently in the process of evaluating the effects of this decree on our reserves in Bolivia. See “Production – Production Outside Argentina Bolivia”.

Our integrated business vision places our Refining and Distribution, Petrochemicals and Gas and Energy businesses as primary links in our business value chain, through which the potential of our hydrocarbon reserves may be maximized. Integration with our Refining and Distribution 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 2.8 million cubic meters of natural gas per day of our own reserves. In addition, we supply gas to our petrochemical operations in Argentina.

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, 2005, we had interests in forty-two blocks; twenty-six production blocks (eighteen in Argentina and eight outside of Argentina) and sixteen exploration blocks, (ten in Argentina and six outside of Argentina). We are directly or indirectly the contractual operator of thirty-five of the forty-two blocks in which we have an interest.

As of December 31, 2005, our total gross and net productive wells were as follows:


	Oil	Gas	Total
Gross productive wells⁽¹⁾	5,551	275	5,826
Net productive wells⁽²⁾	4,064	211	4,275

⁽¹⁾	Refers to number of wells completed.

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

As of December 31, 2005, our total producing and exploration acreage, both gross and net, is shown in the following table:


	Average
	Producing⁽¹⁾		Exploration⁽²⁾
	Gross	Net⁽³⁾	Gross	Net⁽³⁾
	(in thousands of acres)
Argentina	4,971	3,408	2,084	1,192
Peru	116	116	8,686	7,706
Venezuela	585	383	282	141
Ecuador	775	691	—	—
Bolivia	56	56	—	—

Total	6,503	4,654	11,052	9,039

⁽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 or areas that are not in the stage of development.

⁽³⁾	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 or 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,
	2005		2004		2003
	Argentina	Outside Argentina	Argentina	Outside Argentina	Argentina	Outside Argentina
Gross wells drilled:
Production:
Productive wells:
Oil	256	85	275	45	223	20
Gas	7	2	5	—	8	1
Dry wells	2	—	2	1	8	—

Total	265	87	282	46	239	21

Exploration:
Discovery wells:
Oil	11	—	3	1	—	2
Gas	—	—	—	—	—	—
Dry wells	—	—	—	1	—	1

Total	11	—	3	2	—	3

Net wells drilled:
Production:
Discovery wells:
Oil	110.7	75.2	131.1	35.2	213.2	17.7
Gas	2.9	1.0	2.8	—	6.6	0.6
Dry wells	1.7	—	1.7	0.9	6.2	—

Total	115.3	76.2	135.6	36.1	226.0	18.3

Exploration:
Discovery wells:
Oil	8.5	—	2	2.0	—	1.4
Gas	—	—	—	—	—	—
Dry wells	—	—	—	0.7	—	1.0

Total	8.5	—	2	2.7	—	2.4

Production

Argentine Production

Our proved reserves in Argentina as of December 31, 2005 were 143.8 million barrels of crude oil and 950.9 billion cubic feet of natural gas. For the year 2005, our daily production was 54.5 thousand barrels of crude oil and 231.8 million cubic feet of natural gas. Oil and gas production activities in Argentina are mainly developed in mature fields undergoing secondary recovery operations, which are capital-intensive projects.

According to official data from the Argentine Oil and Gas Institute, proved oil and natural gas reserves in Argentina have had a downward trend since 2000. Based on these estimates, oil and gas reserves for the 2000-2004 period dropped approximately 24%.

In this context, in 2005, oil production in Argentina declined for the eighth year in a row to 664,000 barrels a day, accounting for a reduction of approximately 4.3% compared to 2004, principally as a consequence of the natural decline of drainage mechanisms in the different oilfields. The significant investments made in the sector, especially in drilling, workover and infrastructure to expand primary development and improve secondary recovery only partially mitigated this decline.

In the last three years, the Company’s mature asset base in Argentina has experienced, in the aggregate, a decline in production and reserves. Our major challenge is to position exploration as the main vehicle for reserve replacement. Our business plan provides for major exploratory investments, including offshore exploration opportunities. Due to the risks inherent in exploration activities, we cannot be certain that the downward trend in hydrocarbon reserves and production in Argentina will be reversed in the future.

In the fiscal year ended December 31, 2005, our oil and gas production accounted for 8.2% and 7% of total oil and gas production in Argentina, respectively. As of December 31, 2005, we had interests in eighteen Argentine oil and gas production fields, with production rights in approximately 3,408,000 net acres. As of such date, we had 2,883 productive wells in Argentina.

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. Concessionaires in Argentina are entitled to gross proceeds from production sales. All permanent fixtures, materials and equipment are under the control of the concessionaire, although they revert to the Argentine government at the end of the concession. Royalties based on production are paid to the respective Argentine provinces. Throughout the country, these royalties are fixed at 12% of the wellhead price for oil and gas.

Our production is concentrated mainly in five basins, the Neuquén, Austral, San Jorge, Cuyana and Noroeste basins. This positioning helps us to optimize our operating efficiency and to capitalize on the operating synergies of our assets. The Neuquén basin is the most important basin in Argentina in terms of oil and gas production. We own approximately 664,000 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 2,459,000 net acres under production concessions, with Santa Cruz I and Santa Cruz II being our main concessions.

In 2005, we pursued intense development activities: we drilled 265 wells for production and injection and performed 281 workovers. In the Neuquén basin, with 179 wells drilled and 106 workovers, operations were aimed at extending water injection at our secondary recovery projects. Additionally, primary production projects were implemented to maintain production levels and to partially offset the decline in production due to higher levels of water. In order to increase our potential of gas production, we carried out reservoir characterization studies at the El Mangrullo field and commenced works required for the start of production, expected in 2007. At the Austral basin, we drilled 18 wells and conducted 12 workovers. Capital investments were also allocated to infrastructure works for our interconnection project, which has allowed us to deliver gas and condensate from our La Porfiada, La Paz and Boleadoras fields to the General San Martín gas pipeline. Furthermore, construction of a mercury stripper plant was completed at the Santa Cruz II Block. This plant will enhance crude oil quality and, consequently, terms of sales.

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, 2005, 60.2% of our combined proved reserves were located outside of Argentina. In addition, approximately 55.5% of our oil production and 21.1% of our gas production came from outside of Argentina in 2005. We have working interests in eight oil and gas production blocks 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

As of December 31, 2005, estimated proved oil and gas reserves attributable to operations in Venezuela amounted to 269 million barrels of oil equivalent, accounting for 35.4% of the Company’s total reserves. In 2005, our net production in Venezuela was approximately 47,900 barrels of oil equivalent per day or 27.9% of the Company’s total production. Information on oil and gas producing activities as of December 31, 2005 attributable to our operations in Venezuela was calculated on the basis of the contractual structure in force as of such date.

As of December 31, 2005 our rights were held under operating service contracts. In March 31, 2006, we, Petróleos de Venezuela S.A. (PDVSA) and Corporación Venezolana del Petróleo S.A. (CVP), entered into memorandums of understanding (MOUs) in order to effect the migration of the operating agreements to partially state-owned companies (“mixed companies”), whereby the interest of PDVSA in each mixed company will be 60%. The economic effects of the migration are effective since April 1, 2006.

In 1994 we were awarded the first service contract by PDVSA at the Oritupano Leona field to provide production services for a 20-year period. We had a 55% interest in the block. For the provision of production services, we received (1) a variable fee based on production volumes, (2) an additional fee for reimbursement of capital expenditures, and (3) since the first quarter of 2005, an incentive fee for having achieved an accumulated production of 155 million barrels of oil.

In 1997 PDVSA awarded us three 20-year service contracts for the exploration and production of La Concepción, Acema and Mata blocks, with interests of 90%, 86.23% and 86.23% respectively. Under these contracts we received 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 covered investments and production costs, plus a gross profit up to a maximum that is tied to a basket of international oil prices.

During 2005, the Venezuelan government instructed PDVSA that the total amount of accumulated payments to contractors under operating service contracts could not exceed 66.67% of the value of oil and gas produced under the related agreement.

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. According to the Venezuelan Energy and Oil Ministry, each of these operating agreements includes clauses that do not comply with the Venezuelan Hydrocarbon Law enacted in 2001. The Venezuelan government instructed PDVSA to take measures in order to convert all effective operating agreements into mixed companies in order to grant the Venezuelan government, through PDVSA, more than 50% ownership of each field.

According to these provisions, in March 31, 2006, we, PDVSA and CVP, entered into MOUs in order to effect the migration of the Oritupano Leona, La Concepción, Acema and Mata’s operating agreemets into mixed companies. Pursuant to these MOUs, the equity interest of private investors in the mixed companies will be 40%, with the Venezuelan government holding a 60% interest. Petrobras Energía’s indirect interest in the Oritupano Leona, La Concepción, Acema and Mata areas will be 22%, 36%, 34.5% and 34.5%, respectively. The MOUs establish that CVP will recognize a divisible and transferable credit in favor of Petrobras Energía of U.S.$88.5 million. The credit will not bear interest and may be used for the payment of mineral rights offered by the Venezuelan government in the future. The Venezuelan Congress has approved the conversion, but the contracts documenting the conversion and the regime applicable to mixed companies have not yet been executed between private operators and PDVSA. We cannot assure you that the Venezuelan government will not take further measures, either before or after the execution of these new contracts that would further adversely affect our operations and results of operations.

In the future, the mixed companies will be subject to royalty payments based on production of 33.33%. In addition, they will be required to pay to the government an amount equivalent to any difference between (1) 50% of the value of oil and gas sales during each calendar year and (2) the sum total of royalty payments made during such year plus income tax and any other tax or duty calculated on the basis of the sales revenues of the mixed companies paid during such year. Each mixed company shall be the operator of the areas, and the crude oil produced by the mixed companies is required to be sold and delivered to PDVSA at market prices.

The Venezuelan government may set a limit on the oil production of mixed companies. Venezuela is a member of OPEC and has set forth a policy of strict compliance with the production quotas decided upon 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 will affect PDVSA and mixed companies. See “—Regulation of Our Businesses—Venezuelan Regulatory Framework—Petroleum and Gas—Additional Matters—OPEC”.

•

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, 2005, Lote X had 2,415 productive wells. Perupetro S.A.’s Talara refinery is the sole customer for our crude oil production.

As of December 31, 2005, estimated proved oil and gas reserves attributable to operations in Peru amounted to 109.2 million of barrels of oil equivalent, accounting for 14.4% of the Company’s total reserves. In 2005, our net daily production in Peru was 14.2 thousand of barrels of oil equivalent or 8.3% of the Company’s total production.

In 2005, we drilled 50 wells and performed 141 workovers. Additionally, we extended our secondary recovery project, with 26 conversions of producing wells to injectors.

In November 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.

In accordance with the new law, we entered into an agreement with the Peruvian government whereby we undertook to make investments of approximately U.S.$97 million in Lote X during the 2004-2011 period. Works covered by this agreement include the drilling of 51 wells, the workover of 525 wells, the reactivation of 177 temporarily abandoned wells and the implementation, expansion of a water injection project and the development of a gas injection project. As of December 31, 2005, Petrobras Energía Perú S.A. had invested about U.S.$55 million. The Peruvian government, in turn, reduced the royalty rate for crude oil and gas production. Due to this decrease in royalties, our economic projections in connection with operations in Peru have improved. In Peru, the royalties paid for the production of crude oil are determined on the basis of the price of a basket of varieties of crude oil, starting at the rate of 13% for prices of up to U.S.$ 23.9 per barrel. The royalty rate applicable in 2005 was 21.9%. Production of natural gas in Peru is subject to a fixed royalty of 24.5%.

•

Ecuador

In Ecuador we operate Blocks 18 and 31 under participation agreements, in which as of December 31, 2005, we hold a 70% and 100% interest, respectively. Under these agreements, Petroecuador, the Ecuadorian national oil company, is entitled to a share in production, which fluctuates depending on oil prices and production levels.

As of December 31, 2005, estimated proved oil and gas reserves attributable to operations in Ecuador amounted to 51.3 million of barrels of oil equivalent, accounting for 6.8% of the Company’s total reserves. In 2005, our oil production in Ecuador totaled 9 thousand barrels per day, accounting for 5.3% of our total average production in barrels of oil equivalent in 2005.

In January 2005, we entered into a preliminary agreement with Teikoku Oil Co. Ltd. (Teikoku), whereby, subject to obtaining approval from the Ministry of Energy and Mines of Ecuador, we would transfer 40% of our working interests in Blocks 18 and 31.

In 2001, we acquired our working interest in Block 18, located in the Oriente Basin. Block 18 covers approximately 197,000 net acres and has 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 provide for the possibility of a five-year extension period.

Block 18 comprises the Pata and Palo Azul Fields. In the Palo Azul Field the agreement includes differential production sharing percentages according to a formula that considers the selling price and the level of total proved reserves. If the crude from Palo Azul is sold at less than U.S.$15 per barrel, the government receives about 30% of the crude produced, while, if the price of the crude is U.S.$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. 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. As of December 31, 2005, the government’s share of oil produced at the Pata and Palo Azul Fields was 25.8% and 50%, respectively.

As of December 31, 2005, Block 18 had twenty-three productive wells, eighteen located at the Palo Azul Field and five at the Pata Field. The block has early production facilities, which can handle a daily gross production of approximately 30 thousand barrels per day. We started works to expand production facilities in order to increase capacity to 40 thousand barrels per day.

In 2005, production significantly increased as a result of the investments made: 11 development wells were drilled and 3 workovers were completed with very good results; a 12-inch, 15.6 km-long export pipeline was built; and an expansion of the temporary processing plant was completed.

A large part of Block 31 is located in Parque Nacional Yasuní, 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 daily production volumes and oil density.

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 Ecuadorian Ministry of the Environment approved the environmental management plan for the development and production of Block 31 and granted an environmental license in connection with the development phase for the Nenke and Apaika fields. In addition, in August 2004, the Ministry of Energy and Mines approved the development plan for Block 31, thereby establishing the start date of the 20-year exploitation term. Native and environmentalist groups made public statements against the Block 31 development, arguing that the oil and gas activity endangered the park’s biodiversity.

On July 7, 2005, the Ministry of the Environment decided not to authorize the beginning of certain construction works on the Tiputini River (boundary of Parque Nacional Yasuní) and denied us entry to Parque Nacional Yasuní. This suspension prevents us from continuing our development works in Block 31. In May 2006, we presented a new work proposal to the Ministry of the Environment in order to address its concerns on these issues, and the proposal is currently under evaluation by the Ministry of Energy and Mines and the Ministry of the Environment. The new proposal minimizes activities within the Yasuní National Park and employs advanced oil production technologies for environmental protection.

In April 2006, the Ecuadorian government approved the Oil & Gas Reform Law, which assigns to the government an interest of at least 50% of the excess revenues resulting from the increase in the price of Ecuadorian crude (effective monthly average price of FOB price) over the average monthly sales price of such oil at the execution date of the relevant production agreement, expressed in constant values as of the calculation date. As of the date of this annual report, the administrative order implementing the terms such law has not been issued; therefore, we cannot reasonably estimate the impact of such legislation and regulations on our operations at this time.

Ship or Pay Obligation with Oleoducto de Crudos Pesados (OCP)

With respect to the exploitation of Blocks 18 and 31, we executed a transportation agreement with OCP whereby we acquired an oil transportation capacity of 80,000 barrels per day for a 15-year term, starting November 10, 2003. Under the “ship or pay” clause included in the agreement, we must fulfill our ship or pay contractual obligations for the aggregate oil volume committed even when no crude oil is transported and pay, as well as all other producers, a fee covering OCP operating costs and financial services. As of December 31, 2005, such fee amounted to U.S.$2.26 per barrel. Costs in connection with the transportation capacity are invoiced by OCP and charged to expenses on a monthly basis.

We expect that during the effective term of the transportation agreement, oil production will be lower than the aggregate committed transportation capacity. This assumption is based on: (i) the estimated delays in the development of Block 31 and (ii) the current vision of reserve potential in Block 31. Considering this expectation, we sold transportation capacity for approximately 8,000 barrels a day from July 2004 through termination of the agreement with OCP.

Pursuant to the preliminary agreement signed with Teikoku, whereby after obtaining approval from the Ministry of Energy of Ecuador, 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 current oil production deficit. Until reaching such production level, only with effect among the parties and subject to the terms and conditions mentioned above, Teikoku will assume 20% of our rights and obligations resulting from the agreement, as from July 1, 2006. In addition to the abovementioned, and only with effect among the parties and subject to the agreed upon conditions, Teikoku will also assume an additional 20% of our rights and obligations resulting from the agreement and which will be effective for the shorter of the following periods: (a) July 1, 2006 until Block 31 reaches the aforementioned production level, or (b) the consecutive 18 months prior to such production level.

•

Bolivia

Petrobras Energía has operated the Colpa Caranda block since 1989 under a share risk contract signed with YPFB. As of December 31, 2005, we hold a 100% interest in Colpa Caranda block. Colpa Caranda is an approximately 56,000 net acre block located in the Sub Andina Central basin that has 46 producing wells.

As of December 31, 2005, estimated proved oil and gas reserves attributable to operations in Bolivia amounted to 28.4 million barrels of oil equivalent, accounting for 3.7% of our total reserves. In 2005, our net daily production in Bolivia was 7.1 thousand barrels of oil equivalent or 4.1% of our total production. Approximately 88% of our proved developed reserves in Bolivia are gas reserves. These fields, which originally exported gas to Argentina, currently have priority in the delivery of gas to the Santa Cruz-São Paulo pipeline that transports gas to Brazil.

In January 2005, we entered into an assignment agreement with Petrobras Bolivia whereby we transfered, subject to the approval of YPFB, a 5% interest in Colpa Caranda. As of the date of this annual report, the approval of YPFB is pending.

As of December 31, 2005, oil and gas production in Bolivia was subject to royalties and direct taxes that overall represent 50% of the estimated wellhead value.

In May 2006, the Bolivian government enacted the Supreme Decree No. 28,701, which provides that as from May 1, 2006 oil companies must deliver to YPFB the property of all hydrocarbon production for sale. Oil companies will have a 180-day transition period to subscribe to new agreements, which must be individually authorized and approved by the Bolivian Legislature. The Ministry of Hydrocarbons and Mines will determine, on a case by case basis, the interest in each field corresponding to oil companies by means of investment audits, operational costs and profitability indicators. The current distribution of the oil and gas production value will be maintained during the transition period in the case of fields with a certified average production of natural gas for 2005 was lower than 100 million cubic feet per day, such as the Colpa Caranda area. We are currently in the process of evaluating the effects of the recently announced measures on our operations. The implementation of these measures requires a number of steps that have not yet been fully defined, including a comprehensive restructuring of YPFB.

Statistical Information Relating to Oil and Gas Production

The following table sets forth our oil and gas production during 2005. In addition, the table includes our working interest in each field, the number of producing wells and the expiration date of the concessions, in each case as of December 31, 2005. Although some of these concessions may be extended at their expiration, the expiration dates set forth below do not include any extensions.


			2005 Production		Oil and Gas Wells
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	Neuquina	4,871	1,632	537	100.00	%	2016
El Mangrullo	Neuquén	Neuquina	—	—	—	100.00	%	2025
Jagüel de los Machos	Río Negro and La Pampa	Neuquina	984	2,761	83	100.00	%	2015
Puesto Hernández	Mendoza and Neuquén	Neuquina	4,579	—	714	38.45	%	2016
Bajada del Palo – La Amarga Chica	Neuquén	Neuquina	72	—	4	80.00	%	2015
Santa Cruz II	Santa Cruz	Austral	2,434	13,898	87	100.00	%	2017
Río Neuquén	Neuquén and Río Negro	Neuquina	570	8,507	131	100.00	%	2019
Entre Lomas	Neuquén and Río Negro	Neuquina	787	1,561	376	17.90	%	2016
Veta Escondida and Rincón de Aranda U.T.E.	Neuquén	Neuquina	—	—	—	55.00	%	2016
Aguada de la Arena	Neuquén	Neuquina	69	6,641	10	80.00	%	2022
Santa Cruz I U.T.E.	Santa Cruz	Austral	2,519	30,537	93	71.00	%	2016
Sierra Chata	Neuquén	Neuquina	32	6,736	38	19.89	%	2022
Atamisqui	Mendoza	Cuyana	148	—	14	100.00	%	2016
Refugio Tupungato	Mendoza	Cuyana	439	—	37	100.00	%	2016
Atuel Norte	Mendoza	Cuyana	10	—	6	50.00	%	2016
La Tapera - Puesto Quiroga	Chubut	San Jorge				21.95	%	2016
El Tordillo	Chubut	San Jorge	2,117	1,221	698	21.95	%	2016
Aguaragüe	Salta	Noroeste	258	11,124	55	15.00	%	2017

Total in Argentina			19,889	84,618	2,883


Production Areas	Location	Basin	2005 Production		Oil and Gas Wells	Interest		Expiration
Production Areas	Location	Basin	Oil⁽¹⁾	Gas⁽²⁾	Oil and Gas Wells	Interest		Expiration
Outside of Argentina:
Colpa Caranda⁽³⁾	Bolivia	Sub Andina Central	466	12,696	46	100.00	%	2029
Oritupano Leona⁽³⁾	Venezuela	Oriental Maturin	10,479	—	263	55.00	%	2014
Acema⁽³⁾	Venezuela	Oriental Maturin	649	—	20	86.23	%	2017
La Concepción⁽³⁾	Venezuela	Lago Maracaibo	4,274	6,254	117	90.00	%	2017
Mata⁽³⁾	Venezuela	Oriental Maturín	1,051	—	57	86.23	%	2017
Lote X	Peru	Talara	4,592	3,627	2,415	100.00	%	2024
Block 31	Ecuador	Oriente	—	—	—	100.00	%	2024
Block 18	Ecuador	Oriente	3,303	—	23	70.00	%	2022

Total outside Argentina			24,814	22,577	2,941

Total			44,703	107,195	5,816

⁽¹⁾	In thousands of barrels

⁽²⁾	In millions of cubic feet

⁽³⁾	Interests were calculated on the basis of the contractual structure in force as of December 31, 2005.

The following table sets forth our average daily production of oil, including other liquid hydrocarbons, for the three fiscal years ended December 31, 2005, 2004 and 2003. This table includes our net share of production for both consolidated subsidiaries and unconsolidated investees.


	Year ended December 31,
	2005	2004	2003
	(average barrels per day)
Argentina	54,516	61,427	66,038
Outside of Argentina	67,962	66,973	56,827

Total	122,478	128,400	122,865

The following table sets forth our average daily gas production for the three fiscal years ended December 31, 2005, 2004 and 2003. This table includes our net share of production for both consolidated subsidiaries and unconsolidated investees.


	Year ended December 31,
	2005	2004	2003
	(average thousands of cubic feet per day)
Argentina	231,830	262,371	265,129
Outside of Argentina	61,855	64,657	61,679

Total	293,685	327,028	326,808

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, 2005, 2004 and 2003, of our consolidated subsidiaries.


	Year ended December 31,
	2005	2004	2003
Argentina:
Oil (in pesos per barrel of oil equivalent)	99.91	86.72	69.56
Gas (in pesos per million cubic feet)	2.74	2.01	1.80
Outside of Argentina:
Oil (in pesos per barrel of oil equivalent)	94.65	61.91	52.70
Gas (in pesos per million cubic feet)	5.21	3.79	4.37

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, 2005, 2004 and 2003. This table includes the net share of production of our consolidated subsidiaries.


	Year ended December 31,
	2005	2004	2003
	(in pesos per barrel of oil equivalent)
Argentina:
Lifting Cost	11.05	7.91	6.86
Royalties	7.73	6.35	5.39
Depreciation	12.95	11.28	9.88

Total	31.73	25.54	22.13

Outside of Argentina:
Lifting Cost	10.03	8.92	9.42
Royalties	8.08	5.08	5.52
Depreciation	13.97	11.67	12.78

Total	32.08	25.67	27.72

Exploration

We consider exploration as the main vehicle for future growth and replacement of reserves. We have a strategy of constantly searching for new exploration opportunities aligned with our growth targets. Accordingly, we expect an increase in our exploration investments, including new opportunities in Argentina’s offshore areas. In exploring offshore 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.

The following table lists exploration areas as of December 31, 2005, the location and basin of each area, our working interest and the expiration date for the exploration authorization.


	Location	Basin	Interest		Expiration
Argentina:
Glencross	Santa Cruz	Austral	96.68	%	1999	⁽¹⁾
Estancia Chiripá	Santa Cruz	Austral	100.00	%	2001	⁽¹⁾
Santa Cruz I – Oeste	Santa Cruz	Austral	50.00	%	2006
Cerro Manrique	Rio Negro	Neuquina	50.00	%	—	⁽⁴⁾
Parva Negra	Neuquen	Neuquina	47.63	%	2001	⁽³⁾
Cerro Hamaca	Mendoza	Neuquina	39.64	%	2004	⁽³⁾
Gobernador Ayala	La Pampa	Neuquina	22.51	%	2004	⁽³⁾
Coirón Amargo	Neuquen	Neuquina	100.00	%	2006
Cañadón del Puma	Neuquen	Neuquina	50.00	%	2006
Puesto Zúñiga	Río Negro	Neuquina	100.00	%	2006
Outside of Argentina:
San Carlos	Venezuela	Guarico	50.00	%	2005	⁽²⁾
Tinaco	Venezuela	Guarico	50.00	%	2006
Block 57	Peru	Madre de Dios	35.15	%	2008
Block 58	Peru	Madre de Dios	100	%	2007
Block 110	Peru	Madre de Dios	100	%	2007
Block 112	Peru	Marañon	100	%	2007

⁽¹⁾	We have requested that the block be declared operational with commercial operation held in suspense.

⁽²⁾	In April 2006, this area was returned to the Venezuelan government.

⁽³⁾	We have requested an exploitation concession with respect to this field, which is still pending.

⁽⁴⁾	The grant of the exploration permit is in progress.

Exploration in Argentina

As of December 31, 2005, we hold interests in approximately 2,084 thousand gross exploration acres (1,192 thousand net acres) in Argentina. In 2005, we completed a 793 km² 3D seismic survey in the Santa Cruz I area at the Austral Basin, and a 513 km² survey at the Neuquén Basin in the Veta Escondida and Rincón de Aranda areas to carry out exploratory activities. A total area of 1,206 km² of 3D seismic was acquired (a technology to identify and improve the definition of exploratory projects, hence enhancing the drilling success rates). At the Austral Basin, 8 exploratory wells were drilled and tested, 4 of which, located at Estancia Agua Fresca and Puesto Oliverio Fields, were oil discoveries. Additionally, two wells that were spudded at the end of 2005 and were finished during the first half of 2006, resulted in non-commercial hydrocarbon discoveries. Both wells are located in the Neuquén Basin, in Puesto Zúñiga and in Chevron-operated Cuesta del Toro, and have been temporarily closed. At the Austral Basin, drilling is temporarily suspended at a well that was spudded at the end of 2005 in El Campamento, waiting for production testing.

In April 2006, we and Energía Argentina S.A. (Enarsa) signed an association agreement whereby a consortium was created for the exploration, development, production and commercialization of hydrocarbons in two offshore areas located on the Argentine continental shelf, approximately 250 km east of the city of Mar del Plata (Province of Buenos Aires), at depths ranging from 150-200 meters to 3,000 meters. We will have a 25% working interest in the consortium that will explore a combined area of 8,664,000 acres.

Exploration Outside of Argentina

•

Peru

In 2004, we entered into a contract with Repsol Exploración Perú S.A. to perform exploration activities jointly in Block 57, which is located in the Ucayali Basin. Pursuant to this agreement, our interest in the Block is 35.15%. In 2005, we pursued an aggressive policy to increase our acreage position, through exploration license applications and farm-ins. During 2005, we applied for four exploration blocks: Block 58 in the Madre de Dios Basin, Block 110 in the Madre de Dios Basin and Blocks 112 and 117 in the Marañón Basin (the first three were granted during 2005 and the last one was granted during 2006).

As of December 31, 2005, total gross acreage increase to 8,686 thousand acres.

In addition, through a farm-in, we acquired a 30% working interest in Lote 103, which is operated by Occidental, in the Huallaga Basin. The assignment is subject to approval by the governmental authorities.

In Perú, exploration licenses are granted for a total of seven years. The first exploration period of 12 to 24 months typically requires a low level of capital expenditures, primarily on geological studies or seismic reprocessing. Subsequent periods require more substantial investments in seismic registration and drilling.

•

Venezuela

As of December 31, 2005, our exploration rights in Venezuela are composed of 50% working interests in the San Carlos and Tinaco Blocks, which have licenses for the exploration and production of gas. In April 2006, the San Carlos Block was returned to the Venezuelan government. In June 2001, upon the opening of free gas (hydrocarbon that is extracted from a field which does not contain crude oil) exploration areas, we were awarded a license for the exploration and production of gas in the Tinaco area. We expect to complete the first exploratory well in Tinaco in the second half of 2006. If gas reserves are commercialized in the future, we will be required to pay 23.21% in royalties. In Venezuela, gas licenses are granted for a 35-year period, which comprise exploration and exploitation.

•

Colombia

In 2005, we agreed to acquire a 10% working interest in the Tierra Negra Block from Petrobras, who operates the block with a 60% working interest. The block has a high reserve potential and is located in the Llanos Orientales Basin, adjacent to the main oilfields and pipelines in Colombia. Entry into Colombia, in association with Petrobras opens up new prospects for the development of our exploration and production business in this country. Completion of the first exploratory well is expected for the first half of 2007.

•

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, which include, an environmental impact study, as well as the registration, processing and interpretation of 120 sq. km of 3D seismic, reprocessing 500 km of 2D seismic and integration with the new 3D seismic and the drilling of an exploratory well, representing an investment of about U.S.$16 million. The Block 31 exploration drilling and seismic acquisition program was suspended because the authorities have not issued the necessary environmental licenses Furthermore, for planned exploration activity in the western part of Block 18, local communities did not allow the company to enter the area to carry out fieldwork. This prompted us to invoke force majeure and request an extension of the remaining exploration period until the problem is solved. As of the date of this annual report, we have not been granted the extension.

Service Agreement in Mexico

In 2003, as part of a bidding process 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 administrative, technical and operating support required for the operation of these blocks.

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 known 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, 2005, 2004 and 2003. The technical revision covered 95%, 95% and 92% of the Company’s estimated reserves for the years 2005, 2004 and 2003, respectively. Reserves which have not been certified are attributable to estimated reserves related to areas where the Company does not act as operator.

As of December 31, 2005, liquid hydrocarbon and natural gas proved developed and undeveloped reserves, amounted to 760.2 million barrels of oil equivalent (538.4 million barrels of oil and 1,330.7 billion cubic feet of natural gas), representing a 8.1% decline compared to the reserves certified as of December 31, 2004 (a decline of 7.6% for liquid hydrocarbons and 9.2% for natural gas).

Liquid hydrocarbons and natural gas accounted for 70.8% and 29.2%, respectively, of our total proved reserves as of December 31, 2005. Approximately 60.2% of our total proved reserves as of December 31, 2005 were located outside of Argentina as compared to 56.5% as of December 31, 2004. As of December 31, 2005, our proved developed reserves of crude oil equivalent represented 50.6% of our total proved reserves of crude oil equivalent.

During fiscal year 2005, production totaled 63 million barrels of oil equivalent and a decrease of net reserves of approximately 4 million barrels of oil equivalent was recorded as detailed below:

•

A decrease of 9 million barrels of oil equivalent was recorded as a result of adjustments in secondary recovery projects in the Neuquén Basin in Argentina.

•

A net reduction of 14 million barrels of oil equivalent was recorded for technical revisions, mainly attributable to adjustments in gas projects at the Austral Basin in Argentina, and partially offset by positive revisions in Peru resulting from successful drilling projects.

•

An increase of 19 million barrels of oil equivalent mostly from drilling in Argentina and Venezuela, through extensions of known accumulations that allowed for the expansion of the proved area.

As of December 2005, we had proved reserves equal to 12.1 years of production at 2005 rates.

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 net share of the proved reserves of our consolidated subsidiaries and unconsolidated investees. Our net share of the proved reserves of our unconsolidated investees represented only 2.1% of our total proved reserves as of December 31, 2005.


	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, 2003	216,175		390,210		606,385		946,309		384,881		1,331,190		828.3
Proved developed reserves as of December 31, 2003	142,927		169,925		312,852		651,855		207,144		858,999		456.0
Increase (decrease) originated in:
Revisions of previous estimates	(25,266	)	(5,753	)	(31,019	)	229,916		(1,749	)	228,167		7.0
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	(22,481	)	(24,512	)	(46,993	)	(96,056	)	(23,643	)	(119,699	)	(66.9	)
Total proved developed and undeveloped reserves as of December 31, 2004	176,290		406,466		582,756		1,099,515		365,987		1,465,502		827.0
Proved developed reserves as of December 31, 2004	118,654		168,119		286,773		554,138		208,440		762,57,48		413.9
Increase (decrease) originated in:
Revisions of previous estimates	(7,165	)	4,183		(2,982	)	(87,864	)	22,612		(65,252	)	(13.9	)
Improved recovery	(9,485	)	—		(9,485	)	56		—		56		(9.5	)
Extensions and discoveries	4,082		8,762		12,844		23,774		13,787		37,561		19.1
Purchase of proved reserves in place	—		—		—		—		—		—		—
Sale of proved reserves in place	—		—		—		—		—		—		—
Year’s production	(19,889	)	(24,814	)	(44,703	)	(84,618	)	(22,577	)	(107,195	)	(62.6	)
Total proved developed and undeveloped reserves as of December 31, 2005	143,833		394,597		538,430		950,863		379,809		1,330,672		760.2
Proved developed reserves as of December 31, 2005	98,093		176,227		274,320		457,378		203,255		660,633		384.4

The amount of proved reserves as of December 31, 2005 include 183.84 million barrels of oil equivalent of proved reserves and 92.96 million barrels of oil equivalent of proved developed reserves that correspond to the 24.18% minority interests in Petrobras Energía, of which 22.80% is held by Petrobras, through PPSL.

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, 2005, 2004 and 2003.


	2005			2004			2003
	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	384.4	50.6	%	413.9	50.0	%	456.0	55.1	%
Proved undeveloped reserves	375.8	49.4	%	413.1	50.0	%	372.3	44.9	%

Total Proved Reserves	760.2	100	%	827.0	100.0	%	828.3	100	%

Approximately 8.3% of our proved developed reserves as of December 31, 2005 are non-producing reserves.

Estimated reserves in Argentina, Peru and Bolivia are stated before 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 share of production and takes it in kind, reserves are stated after royalties.

Information on oil and gas producing activities as of December 31, 2005 attributable to our operations in Venezuela is calculated on the basis of the contractual structure in force as of such date. At that date the government maintained full ownership of all hydrocarbons. Reserve volumes in Venezuela were computed by multiplying our working interest by the gross proved recoverable volumes for the contract area. In Venezuela, for the Acema, Mata and La Concepción areas, 30% royalties were paid, calculated based on the crude wellhead estimated price. Under contractual terms, the third round blocks’ royalties were deducted from the sales price. Pursuant to operating agreements, we were exempt from production royalty payments in the Oritupano Leona field. As described in this annual report, we have undertaken the migration of our working interests in Venezuela into partially state-owned companies (“mixed companies”) that will be majority-owned by the Venezuelan government through Petróleos de Venezuela S.A. As of the date of this report, there is no reliable data available regarding the definitive terms and conditions regarding future operational arrangements in Venezuela that would allow us to estimate with a reasonable degree of certainty the impact of the migration on our reserves. Based on currently available information, we estimate, nonetheless, that the conversion is likely to adversely our total reserves and estimated net cash flows. As of December 31, 2005, we recognized impairment charges of P$424 million to adjust the book value of our assets in Venezuela to their estimated recoverable value, See “Item 5. Operating and Financial Review and Prospects”.

Based on the corporate structure established to carry out the migration of operating agreements, our interest in operations in Venezuela will be shown on the Unconsolidated Companies line in our Supplementary information on oil and gas producing activities once the migration is completed.

Estimated proved reserves as of December 31, 2005 attributable to our operations in Bolivia were certified under the agreements and the regulatory framework in force as of December 31, 2005. However, as provided by Supreme Decree No. 28,701, issued in May 2006, as from May 1, 2006 oil companies will have to deliver to YPFB the property of all hydrocarbons for sale. We are currently in the process of evaluating the effects of this decree on our reserves in Bolivia. See “Production – Production Outside Argentina – Bolivia”.

Had the economic method of calculating proved reserves (future expected contractual revenues of each field divided by the revenues calculated based upon oil market prices at year end) been used, the reported amounts of crude oil, condensate and natural gas liquids proved reserves outside of Argentina would have decreased by approximately 27.9%, 27.1% and 23.4% as of December 31, 2005, 2004 and 2003, respectively. Gaffney, Cline & Associates Inc. did not audit the information in the preceding sentence.

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. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Accordingly, we cannot ensure 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 crude oil and natural gas reserve estimates involve some degree of uncertainty and may prove to be incorrect over time”.

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 3D seismic process, horizontal and step out wells, underbalance drilling and reservoir numerical stimulation are also used.

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.

Sales for the year ended December 31, 2005, were made mainly to Petróleos de Venezuela S.A., Petroperú Petróleos del Perú S.A., Petrobras International Finance Co. and Empresa Nacional de Petróleo (ENAP), and sales to such entities represented about 25%, 15%, 6% and 6%, respectively, of sales for such year for the Oil and Gas Exploration and Production business segment, before deducting export duties. During 2005, oil and gas exports totaled approximately P$301 million or 6% of total consolidated crude oil and gas sales (calculated before deducting export duties). In 2005, exports sales were made principally to Chile.

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, 2005, we held an 11.42% interest in OCP. OCP’s other shareholders are Encana, Perenco, Occidental, Repsol-YPF and AGIP.

The oil pipeline has a transportation capacity of approximately 450,000 barrels per day, of which at least 350,000 barrels per day have been committed under transportation agreements that include a ship or pay clause. Because 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 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.

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 transportation agreement that includes a ship or pay clause 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)”.

Oleoductos del Valle S.A. – 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 term 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 pipeline between Allen and Puerto Rosales has a transportation capacity of approximately 265,000 barrels per day, with one million barrels of storage capacity.

During 2005, oil volumes transported by Oldelval from Allen to Puerto Rosales totaled 65.4 million barrels, accounting for a 1.6% slight decline compared to the previous year. In 2005, the flow of crude oil pumped into the pipeline by the Neuquén Basin producers reflected a drop in line with the natural decline in the production profile of the basin fields, which was offset in part by lower exports to Chile transported through the Trasandino Oil Pipeline.

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.

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.

REFINING AND DISTRIBUTION

The Refining and distribution business is a key link in the vertical integration of our operations, which starts with crude oil exploration and ends with customer service at the gas station.

Our main strategy in the Refining and Distribution segment is to grow in the Argentine market, with quality differentiated products and services.

Our refining and distribution operations are developed in Argentina and Bolivia. In Argentina, we operate two refineries which are located in San Lorenzo and Bahía Blanca, and we have a 746 gas stations network. In addition, we have a 28.5% interest in Refinería del Norte S.A., or Refinor.

In Bolivia, we had a 49% interest in Petrobras Bolivia Refinación S.A., or PBR.

The Refining and Distribution Business in Argentina

In 2005, after a 48% reduction in sales in the 1995-2003 period (mainly due to high taxes imposed on gasoline and to a lesser extent on diesel comsumption, that encouraged the use of compressed natural gas), the Argentine market of liquid fuels grew for the second year in a row.

Domestic demand for diesel oil grew about 7.5% to above 12 million cubic meters, in line with Argentine macroeconomic indicators and the economic recovery experienced since 2003. Domestic demand for gasoline, in turn, reached 3.7 million cubic meters, accounting for an 8.9% growth compared to the previous year. The increase in demand for gasolines with an octane rating of over 95 continued, while gasolines with an octane rating below 85 declined in the last four years.

Several factors drove the recovery in liquid fuels, including a 17% increase in the price of Compressed Natural Gas (CNG) at the pump during 2005, and the uncertainty as to gas availability at gas stations. Another key factor in driving recovery was price stability at the pump. In an effort to avoid inflationary escalation, the Argentine government exerted pressure to limit the increase in retail prices for gasoline and diesel oil that would have resulted from higher costs due to the peso devaluation, domestic inflation and particularly increases in WTI prices (notwithstanding the fixing of reference prices for crude oil purchases in the domestic market). The inability to raise prices, however, adversely affected the sector’s profitability. The Company’s nature as an oil producer allowed it to mitigate the distortive effect of the government’s actions.

Refining Division

We have a total refining capacity of 68,700 barrels of oil per day from our two refineries: the San Lorenzo refinery (located in San Lorenzo, Province of Santa Fe) and the Ricardo Eliçabe refinery (located in Bahía Blanca, Province of Buenos Aires).

San Lorenzo Refinery

Our refinery in San Lorenzo, Province of Santa Fé, is strategically located along the central product distribution system. This refinery capacity is approximately 37,700 barrels of oil per day 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. We are one of the few oil companies in Argentina that owns facilities for the production of asphalt goods. This unique feature has enabled us to supply asphaltic products for many of the most important road construction works in the country. 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. In line with a growing market demand, two new tanks were added to the refinery to allow production

of increased volumes of Podium gasoline, the first 100-octane gasoline produced and marketed in the Argentine market. The refinery has a storage capacity of final products of 194,000 cubic meters.

Ricardo Elicabe Refinery

The Ricardo Elicabe Refinery is located in Bahía Blanca, Buenos Aires Province, in a strategic location for the reception of crude oil coming from the Neuquén Basin or by sea from the south of Argentina or from international markets. With a crude processing capacity of approximately 31,000 barrels per day, it manufactures a wide variety of products: high-grade gasoline, regular gasoline, super 97 SP gasoline, and raw materials for the production of solvents and petrochemical products—including kerosene, diesel oil, fuel oil, asphalts base, propane, propylene and butanes.

Refining Master Plan

In line with our business strategy, we have designed and begun to implement a plan (The Refining Master Plan) aimed at expanding and upgrading the installed capacity of our refineries with a view to grow in the local market with enhanced product quality and according to stricter environmental standards. The plan encompasses a significant number of works, which are expected to be completed by 2009. By that time, our own production of diesel oil is expected to have increased by almost 40% and our fuels are expected to have met the most stringent standards relating to sulfur content in diesel oil and sulfur, benzene and aromatics content in gasoline.

Total crude oil processing capacity is expected to be increased to approximately 83,300 barrels of oil per day. The San Lorenzo Refinery capacity is expected to increase by over 50,000 barrels of oil per day. Works are expected to be completed during 2006. In the Ricardo Pedro Elicabe Refinery, works to be performed include the revamping of the topping and vacuum units to increase installed capacity to 33,300 barrels of oil per day. These works are expected to be completed during 2007 and will allow for processing heavier crude oils, with increased availability and reduced purchase costs.

Distribution division

As of December 31, 2005 we had a commercial network of gas stations, to deliver products and services to a number of regions in Argentina.

We have a network of 746 gas stations, located all around the country. We have pursued a business strategy involving the development and growth of Petrobras’ image across gas stations, from our former SL and EG3 brands. Throughout 2005, 120 retail outlets were reidentified under the Petrobras brand, reaching 451 gas stations under the Petrobras brand as of December 31, 2005. We also have 20 Agro-centers, outlets designed to meet the needs of the agricultural sector. We will continue the development of Petrobras gas stations and the rebranding of gas stations to the Petrobras brand, aimed at capitalizing on the positive attributes associated with our brand. Petrobras has built an excellent image for Petrobras brands, products and services in Argentina, currently competing with the image of the leading companies in the country.

Petrobras Energía’s points of sale (gas stations) in Argentina were as follows:


		As of December 31, 2005
Owned ⁽¹⁾		141
Franchised ⁽²⁾		605

Total		746

⁽¹⁾	Owned or controlled by Petrobras Energía under long-term commercial contracts or other types of contractual relationships that secure a long-term direct influence over such points of sale.

⁽²⁾

The term “franchised” refers to service stations owned by third parties with which Petrobras Energía has signed a franchise agreement that provides Petrobras Energía with the right (i) to become the service stations’ exclusive supplier and (ii) to brand the service station with its corporate image. Current laws establish that the duration of contracts for gas stations should be 5 years for existing stations, and 8 years for new constructions.

Petrobras Energía sells gasoline to the public in Argentina under the Petrobras, EG3, and San Lorenzo brand names with the following distribution at December 31, 2005:

Gas Stations


Petrobras		451
EG3		248
SL		47

Total Gas Stations		746

We are developing convenience stores, named Spacio 1, throughout our gas station network. In the first stage, we are opening convenience stores in Gas Stations owned by us. The Company currently has 18 convenience stores, 8 more compared to 2004.

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, Petrobras Energía’s premium gasoline and the first 100-octane gasoline in the Argentine market, which offers the best performance within its category. Podium was created jointly by the Company’s technicians and technicians from Petrobras. It is produced at the San Lorenzo refinery, in Santa Fe, and is distributed on an exclusive basis throughout our gas station network, all around the country.

Podium 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.

Since it was launched in 2004, Podium has been well received by the Argentine market. With Podium, our share of the premium gasoline market grew by 2% to 9.7% during 2005.

Through our extensive gas station network, we also market Lubrax lubricants. These lubricants, which are manufactured by Petrobras, enjoyed an 8.8% share of the domestic lubricant market in 2005. Petrobras’ technical, commercial and advertising efforts for the development of the Lubrax brand give considerable support to our sales growth in this business.

We also sell petroleum products to the industry and, marine markets. Products sold in these markets include bunker products (marine fuels and lubricants) asphalts, and other products.

As of December 31, 2005, we had a market share of approximately 14.5% in the gasoline market, 14.2% in the diesel oil market and 12.4% in the fuel oil market.

In Argentina, with market share of 50.6%, we are a leading company in the bunkering segment (production and provision of marine fuels and lubricants).

We have a leading position in the asphalts market in Argentina, with a 40% of market share and in Bolivia and Paraguay. In 2005, we started selling to other markets such as Uruguay and Chile.

The following table shows production and sales for our consolidated Refining and Distribution business segment for the fiscal years ended December 31, 2005, 2004 and 2003:


	Year Ended December 31,
	2005	2004	2003
Production (thousands of tons):
Virgin naphtha	810	742	780
Diesel oil	1,226	1,220	1,200
Other products	1,156	1,203	1,090

Sales:
Aromatics (thousands of tons)	46	37	57
Benzene (thousands of tons)	58	54	50
Gasoline (thousands of m3)	715	689	709
Diesel oil (thousands of m3)	1,741	1,787	1,752
Other medium distillates (thousands of m3)	13	15	18
Asphalts (thousands of tons)	188	153	116
Reformer plant products (thousands of tons)	135	93	150
Other heavy products (thousands of tons)	686	674	666
Paraffins (thousands of tons)	163	193	139

Sales (in millions of pesos):
Argentina	2,991	2,594	2,058
Outside of Argentina	865	765	644
Total	3,856	3,359	2,702

During 2005, 2004 and 2003 we processed an average of 62,900, 63,100 and 61,100 barrels per day through our two refineries. In 2005 crude oil volumes processed accounted for about 91.6% of the refining capacity.

Refinor

We have a 28.5% interest in Refinor. Refinor’s other shareholders are Repsol-YPF (50%) and Pluspetrol 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 approximately 26,100 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, and natural gasoline. 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, 2005, Refinor had a commercial network comprising 75 gas stations (14 operated by Refinor) located in the Provinces of Salta, Tucumán, Jujuy, Córdoba, Santiago del Estero, La Rioja, Catamarca and Chaco and has started developing a commercial network in Bolivia, where it has 12 gas stations operating under its brand. For logistics and distribution purposes, Refinor operates a 1,112 km pipeline that extends from the pumping station in Campo Durán (Salta) to Montecristo (Córdoba). Along the pipeline, layout pumping plants 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 petroleum 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 petroleum gas).

In addition, the poliduct discharges a large volume of products, such as petrochemical naphta and liquefied petroleum 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, 2005, 2004 and 2003:


	Year ended December 31,
	2005	2004	2003
Production:
Gasoline (thousands of m3)	102	101	122
Virgin naphtha (thousands of m3)	441	387	420
Diesel oil (thousands of m3)	358	354	330
Natural gasoline (thousands of m3)	121	132	129
Propane/butane (thousands of tons)	357	363	313
Other products (thousands of m3)	138	158	138
Sales:
Gasoline (thousands of m3)	106	109	121
Virgin naphtha (thousands of m3)	573	529	550
Diesel oil (thousands of m3)	505	406	378
Propane/butane (thousands of tons)	352	354	297
Other products (thousands of m3)	111	81	97
Sales (in millions of pesos):
Argentina	696	557	478
Outside of Argentina	733	533	4043

Total	1,429	1,090	882

During 2005 Refinor’s installed capacity usage remained high at about 95.4%, with 19.1 million cubic meters of gas processed per day in 2005. In 2004 and 2003, it processed 19.1 million cubic meters of gas per day and 16.7 million cubic meters of gas per day, respectively. Crude oil processing grew 3% in 2005 to 17,900 barrels of oil per day compared to 17,400 barrels of oil per day in 2004. In 2003, it processed 17,600 barrels of oil per day.

In 2005 Refinor’s market share in terms of motor gasoline and diesel oil sales in its area of influence in the northern region of Argentina was 22.8% and 21.0%, respectively. Considering the size of its service centers network, Refinor continues to be the oil company with the second highest number of retail outlets in the northern region of Argentina.

Petrobras Bolivia Refinación (PBR)

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

PBR owns two refineries located in Cochabamba and Santa Cruz de la Sierra, Bolivia, with an estimated maximum production capacity of 60,000 barrels of oil per day, accounting for 98% of Bolivia’s total refining capacity. During 2005, PBR processed record levels of crude oil, averaging 39,800 barrels per day. During 2004 and 2003, crude oil processed averaged 37,460 and 32,620 barrels per day, respectively.

PBR wholly owns Petrobras Bolivia Distribución a company that has a commercial network of 104 gas stations in Bolivia (12 of which were added during 2005).

The following table sets forth PBR’s sales and production for the fiscal years ended December 31, 2005, 2004 and 2003:


	Year ended December 31,
	2005	2004	2003
Production:
Gasoline (thousands of m3)	600	618	552
Diesel oil (thousands of m3)	669	660	507
Propane/butane (thousands of tons)	76	69	61
Reconstituted Oil (thousands of tons)	565	467	457
Other products (thousands of m3)	398	360	383
Sales:
Gasoline (thousands of m3)	552	606	540
Diesel oil (thousands of m3)	655	666	483
Propane/butane (thousands of tons)	80	71	57
Reconstituted Oil (thousands of m3)	427	379	371
Other products (thousands of m3)	386	280	358
Sales (in millions of pesos):
Bolivia	620	582	486
Outside of Bolivia	183	87	82
Total	803	669	568

In 2005 PBR’s market share in terms of motor gasoline and diesel oil sales in Bolivia was 100% and 63%, respectively.

In May 2006, the Bolivian government issued Supreme Decree N° 28,701, which provides, among other things, that the Bolivian government shall recover full participation in the entire oil and gas production chain, and for this purpose provides for the nationalization of the shares of stock necessary for YPFB to have at least 50% plus one of the shares in a number of companies, among which is PBR. We are currently in the process of evaluating the effects of the recently announced measures on our operations. The implementation of these measures requires a number of steps that have not yet been fully defined, including a comprehensive restructuring of YPFB.

Competition

We compete in Argentina principally with Repsol-YPF S.A., Shell CAPSA and Esso S.A., which hold shares of approximately 53.6%, 14.5% and 12.7%, respectively, of the domestic market for motor gasoline and diesel oil sales.

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 supply; and

•

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

Our petrochemical operations are performed in Argentina and Brazil. We produce a wide array of products, such as styrene monomer, 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 substantial 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 South America.

We also have an ethylene plant located in San Lorenzo. The plant has a production capacity of 20,000 tons per year. It is located along the Paraná river coast, near to our 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. This ethylene plant allows us to expand our business value chain and our product offering, resulting in an increase in our share of the plastic raw material market. The plant, which was acquired in 2004, has allowed us to increase production capacity at the Puerto General San Martín ethylbenzene plant from 116,000 tons to 180,000 tons per year. This additional capacity allows us to make full use of the installed capacity at the Puerto General San Martín and Innova styrene plants.

With a view to maintaining our leading position in 2006, we plan to expand our styrene production capacity at the Puerto General San Martín complex. This project will lead to an increase in the plant production capacity to 160,000 tons per year in 2006, and allow us to expand our product offering and increase our share in styrene market, and meet the regional market deficit, which is currently satisfied by imports.

With a view to capitalizing on the business opportunities offered by a rapidly expanding regional market for synthetic rubber, particularly due to the growth in the tire industry, and by good margins in the international market due to limited supply, we made capital expenditures that will enable us to expand our production capacity for synthetic rubber to 59,000 tons per year by 2007.

As of December 31, 2005, 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 2005, we exported 36%, 49% and 42% of our total sales volumes of styrene, rubber and polystyrene, respectively. Exports were primarily to Mercosur member countries and Chile. In 2005 we exported 10.4 tons of bioriented polystyrene, primarily to Europe, the United States and South America.

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 producer of 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. Our installed production capacity for liquid fertilizer is 640,000 tons per year.

Liquid storage capacity totaled 70,000 tons, which, together with an automatic and computerized loading facility, has allowed us to manage the growth in the production of liquids.

In line with the development strategy associated with liquid fertilizers, in mid 2006, we will see the start up of a production plant of potassium thiosulphate at the Campana Complex. Production of thiosulphate potassium offers several competitive advantages: it requires low capital expenditures and has a strong synergy with the production of ammonium thiosulphate, improves the liquid fertilizer technological portfolio devoted to regional intensive crops, and also opens up prospects for the production of water treatment industrial products.

We have 600 customers throughout Argentina. Of these, 130 are distributors with their own storage facility centers, complementing our warehouses and assistance centers in twelve different strategically-located agronomic regions.

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, 2005, 2004 and 2003:


	Year ended December 31,
	2005	2004	2003
Production (thousands of tons):
Styrene ⁽¹⁾	107	111	106
Synthetic rubber ⁽²⁾	55	58	56
Urea	169	188	193
UAN	261	248	184
Polystyrene	58	62	57
Bops	13	12	11
Sales (thousand of tons):
Styrene ⁽¹⁾	89	52	44
Synthetic rubber ⁽²⁾	53	60	57
Fertilizers	676	713	543
Polystyrene and Bops	65	63	59
Propylene	23	20	25
Sales (in millions of pesos):
Argentina	963	873	567
Outside of Argentina	413	270	230

Total	1,376	1,143	797

(1)	Including ethylbenzene.

(2)	Including SBR, NBR and butadiene.

Petroquímica 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 scheduled 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.

In 2005, Cuyo started an investment plan, which is expected to allow it to increase its production capacity to 130,000 tons per year. Total estimated investments total U.S.$12 million. The additional productions aim to satisfy local demand as well as demand in neighboring countries.

The following table sets forth Cuyo’s production and sales for the fiscal years ended December 31, 2005, 2004 and 2003.

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. 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.

Innova is the leading styrene and polystyrene producer and supplier in Brazil with a combined market share of approximately 38%.

With Innova projecting sustained growth of its operations, and with us looking to consolidate our leading position in an increasingly competitive regional market, in 2006 Innova plans to make investments to build a new ethylbenzene plant, with possible production capacity of 540,000 tons per year. The plant is expected to operate at 50% of this capacity (270,000 tons per year) at the start of production, sufficient to feed the actual styrene plant.

The following table sets forth Innova’s production and sales of styrene and polystyrene for the fiscal years ended December 31, 2005, 2004 and 2003.


	2005	2004	2003
Production (in thousands of tons):
Styrene	205	202	175
Polystyrene	95	105	86
Sales (in thousands of tons:
Styrene	118	101	92
Polystyrene	95	103	89
Other	53	58	—
Sales (in millions of pesos):
Brasil	856	720	466
Outside of Brasil	116	53	36

Total sales	972	773	502

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 polystyrene, operates a 120,000-ton capacity plant in Manaus.

GAS AND ENERGY

The Gas and Energy segment serves to link the Company’s energy businesses. As part of this segment, we provide oil and gas and liquified petroleum gas brokerage and trading services as well as, through our stake in Transportadora de Gas del Sur S.A. or TGS, we are engaged in the transportation of gas in the south of Argentina and in the processing and marketing of natural gas liquids. In the electricity business, we are engaged in all the industry segments: generation, transmission and distribution.

In the Gas and Energy segment our main business objectives are:

•

Focusing on electricity generation to accelerate the monetization of gas reserves.

•

Restoring profitability to the regulated businesses.

•

Developing new marketing opportunities.

Marketing

We provide oil, gas and liquefied petroleum gas (LPG) brokerage and trading services in order to expand production opportunities. This business enables the Company to position itself as a major commercial service provider because we assist clients not only in sales, but also in logistics, foreign trade and market knowledge. During 2005, sales volumes in Argentina for gas produced by us and imported gas totaled 260.9 million cubic feet per day and 274.5 million of cubic feet per day during 2004. Liquid fuels sales volumes totaled 267.1 thousand tons in 2005 and 309.5 thousand tons in 2004. We sold 18 million cubic feet per day in the gas and LPG brokerage services in 2005 and 3 million cubic feet per day in 2004.

Gas Transportation – TGS

Our interest in TGS and Corporate Developments

We hold indirectly a 27.65% interest in TGS. TGS’s controlling shareholder is CIESA, which as of the date of this annual report holds approximately 55.3% of TGS’s common stock. A portion of TGS’s capital stock (30%) is listed on the Buenos Aires Stock Exchange and on the New York Stock Exchange. The remaining 14.7% is own by D.E. Shaw Laminar Emerging Markets. As of the date of this annual report, the common stock of CIESA is owned 50% by Petrobras Energía (directly and indirectly through its subsidiary Petrobras Hispano Argentina S.A.); 40% by an Argentine affiliate of ABN AMRO BANK N.V Trust (the Trust), and the reminder 10% by a subsidiary of Enron Corp. The current ownership of CIESA’s and TGS’s common stock is the result of the implementation of the first stage of the Master Settlement and certain Mutual Release Agreement, signed by Petrobras Energía and certain Enron subsidiaries on April 16, 2004 (the “Master Settlement Agreement”) in connection with the restructuring of CIESA’s indebtedness.

CIESA’s Board of Directors is composed of 3 of our representatives, 2 of the Trustee’s representatives and 1 Enron representative. TGS’ Board of Directors is composed of 6 representatives of CIESA (3 of whom are our representatives, 2 are the Trustee’s representatives and 1 is an Enron representative.). Pursuant to a Shareholders’ Agreement entered into on August 29, 2005 by Enron (the Shareholder Agreement), the Trust and us, 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 U.S.$220 million and derivative instruments of approximately U.S.$2 million in value. CIESA’s shareholders, including us, have not assumed any financial obligations to assist CIESA.

In 2004, TGS successfully restructured substantially all of its debt (U.S.$1,019 million), pursuant to a proposal accepted by close to 100% of its creditors.

Regarding CIESA’s debt restructuring, in July 2005, ENARGAS approved the implementation of the first stage of the transactions contemplated by the Master Settlement Agreement, and as a result, on August 29, 2005, (a) Enron transferred 40% of CIESA’s shares to a newly created trust and (b) Petrobras Energía and its subsidiary, Petrobras Hispano Argentina transferred class “B” common shares of TGS representing 7.35% of TGS’s capital stock to subsidiaries of Enron, which in turn were subsequently sold to D.E. Shaw Laminar Emerging Markets.

On September 1, 2005, CIESA, its current shareholders and creditors entered into a Restructuring Agreement, which provides for the implementation of the second phase of the transactions contemplated by the Master Settlement Agreement. As a first step, CIESA refinanced approximately U.S.$23 million in debt. As a second step, CIESA’s creditors will cancel all of CIESA’s remaining debt in exchange for TGS class “B” common shares representing approximately 4.3% of TGS’s capital stock (which will be simultaneously exchanged for the 10% of CIESA’s outstanding shares held by a subsidiary of Enron), and the issuance of new CIESA’s shares to the creditors in such amount that the creditors will own 50% of CIESA’s common stock. At that time, the Trust will be automatically terminated. This second step is subject to, and will be implemented upon, receipt of approvals from ENARGAS and Comisión Nacional de Defensa de la Competencia. Upon the implementation of this second step, we will own 50% of CIESA’s capital stock and the creditors will own the remaining 50%, and CIESA will own 51% of TGS’s common stock.

We provide services to TGS 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, pursuant to a Technical Assistance Agreement entered into by Enron Pipeline Company Argentina S.A. and TGS in 1992. This agreement was assigned to us in July 15, 2004, pursuant to the terms of the Master Settlement Agreement. 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’s net income before financial income (expense) and holding gains (losses) and income taxes.

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 62% of the gas consumed. TGS is also one of the leading natural gas liquids producers and traders, both in the domestic and international markets, and an important provider of midstream services, including business and financial structuring, turnkey construction and 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, 2005, 2004 and 2003.


	2005		2004		2003
Regulated Segment:
Average firm committed capacity⁽¹⁾	68.3		63.6		61.7
Average daily deliveries⁽¹⁾	64.6		61.5		52.6
Annual load factor⁽²⁾	95	%	97	%	85	%
Unregulated Segment:
Liquids total production⁽³⁾	885.5		969.0		929.1
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’ pipeline system connects Argentina’s southern and western gas reserves with the main consumption centers in those regions, including Greater Buenos Aires. TGS has an exclusive license for the use 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 7,900 km of pipelines, of which almost 7,500 km belongs to TGS, with a current firm contracted capacity of, as of December 31, 2005, 71.4 million cubic meters per day (annual average of 68.3 million cubic meters per day). 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. 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.

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. Some important industries and electrical power plants are also located within TGS’s operational area, to which TGS renders direct transportation services and represent approximately 19% of TGS’ total firm transportation capacity.

TGS has made significant investments in its business since the privatization. As a result, approximately 833 km of gas pipelines have been laid in addition to the existing pipelines, compression power has been increased from 429,030 horsepower in 1992 to 550,230 horsepower in 2005 and transportation capacity has been increased from 42.9 million cubic meters per day to 71.7 million cubic meters per day by the end of 2005.

As a consequence of the enactment of the Public Emergency Law, which pesified and froze tariffs, revenues from the regulated segment have significantly decreased. In 2005, the gas transportation segment accounted for 43% of TGS’s total revenues compared to 44% and 47% in 2004 and 2003, respectively, and to approximately 80% since the start of the service until 2001.

Gas Trust

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 terms of the utility contracts is still pending) and a growing gas demand in certain segments of the Argentine economy, the Argentine government established the framework for the creation of a trust fund, the Gas Trust, that would finance gas transportation system expansions.

In June 2004, TGS submitted to the Secretary of Energy a project for the expansion of capacity of the San Martín pipeline transportation by approximately 2.9 million cubic meters per day. This project involved the construction of approximately 509 km of pipeline and an increase in compression capacity of 30,000 horsepower, through the construction of a new compressor plant and the revamping of some existing units. The project was completed in August 2005. In its role as project manager, TGS rendered engineering, project management and control, procurement and administrative services. TGS is responsible for the operation and maintenance of the new pipelines, which are owned by the Trust Fund.

The Gas Trust financed U.S.$311 million, including VAT, of this project, while TGS invested approximately U.S.$40 million. TGS investment will be recovered by applying 80% of the revenues obtained from the additional transportation capacity. The remaining 20% and a specific tariff charge will be allocated to repay the investment of the Gas Trust. This tariff charge will be effective until the total amount invested by the Gas Trust is recovered.

In April 2006, the Ministry of Federal Planning and Public Service, the Federal Energy Bureau and gas transporters, among others, signed a letter of intent to carry out the second expansion of the gas pipeline system. This new expansion will increase the system’s transportation capacity by 20 million cubic meters per day, of which approximately 6.5 million cubic meters per day correspond to TGS’s system. In a first stage, TGS’s expansion would be for an additional transportation capacity of 3.3 million cubic meters per day, which is expected to be completed between 2007 and 2008. This expansion will be financed by the shippers who supported the additional capacity.

Renegotiation process

TGS is still engaged in discussions with UNIREN regarding the renegotiation of its tariffs. As a result, and despite of contracted capacity increases, the profitability of the regulated business has not yet been restored.

After several proposals aimed to adjust TGS’s license contractual terms, which were rejected by TGS considering that they did not reflect preliminary agreements, in 2005, UNIREN proposed a 10% tariff increase and an overall tariff review effective in 2006. This proposal requires that TGS and its shareholders waive any future claim against the Argentine government resulting from the Public Emergency Law and/or the failure to adjust tariffs during 2000 and 2001 based on the United States Producer Price Index. TGS responded by rejecting the initial 10% increase as insufficient, and jointly with Petrobras Energía agreed not to pursue any such claims if the parties reach a reasonably satisfactory agreement on tariff adjustments. Currently, the tariff renegotiation process is delayed by, among other issues, the refusal by Ponderosa Assets L.P. to abandon a claim jointly initiated with Enron Corp. against the Republic of Argentina before the International Center for the Settlement of Investment Disputes (“ICSID”). Ponderosa has stated that it will only consider the abandonment of this claim if Ponderosa is fairly compensated.

Non-regulated 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 traders of natural gas liquids (NGL). NGL 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 sells 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.

NGL production and commercialization net revenues accounted for approximately 51%, 51% and 48% of net revenues in 2005, 2004 and 2003, respectively. In 2005, 33% of total NGL production, which represented approximately 323,168 short tons, was exported.

During 2005, long-term agreements were concluded to ensure both the supply of the raw materials (natural gas and richness contribution) and the sale of the products in order to consolidate this business and provide for production increases.

Markets and principal customers

TGS sells it NGL production to brokers and refineries in the local market and part of the production is exported to Petrobras International Finance Company, a subsidiary of Petrobras at current international market prices. Ethane is entirely sold in the domestic market to PBB-Polisur S.A. at agreed prices.

Midstream services

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.

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 on 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 2005. 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.

Electricity

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

We believe that electricity generation allows us to accelerate the monetization of our 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 adversely impacted the financial equation of the electricity business in Argentina. 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 significantly 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 thorough restructuring of the electricity sector, transforming it into a more decentralized system with greater private sector participation. Up to then, the electricity system was characterized by an inability to meet short- and long-term demand and low service quality, all within a framework of a limited 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 5.8%, exceeding the growth in gross domestic product for the same period. In 2005, electricity demand grew approximately 5.8% to 87,779 GWH from 82,967 GWH in 2004. Total electricity generation including exports increased 5.7%. As of December 2005, installed generation capacity reached 24,080 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, 2005, thermal and hydroelectric power accounted for 55% and 41%, respectively, of total supply. Serving as an integrating link, the system’s transportation capacity increased by 20% between 1994 and 2005. These improvements in installed capacity have 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 U.S. 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, infrastructure investments in the Argentine 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 recognizing the greater costs resulting from the recovery of natural gas prices.

In order to restore the regular operation of the wholesale electricity market (“WEM”) as a competitive market with 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 capacity with the U.S. dollar values that were in effect prior to the enactment of the Emergency Law, once the market returns to normal following the start of commercial operations of the additional capacity to be contributed by the Fondo de Inversiones Necesaria que permitan incrementar la oferta de energía eléctrica en el Mercado Eléctrico Mayorista (“FONINVEMEM”).

FONINVEMEM is an investment fund aimed at increasing the available supply of electric power generation in Argentina and achieving energy sustainability. On October 17, 2005 and under the provisions of Resolution No. 1,193 issued by the Secretary of Energy, we together with other WEM creditors agreed to engage in the construction, operation and maintenance of two plants of at least 800 MW each, with gas turbines estimated to start operations in December 2007 and complete combined cycles estimated to become operational in June 2008. The construction of these generators will be partially financed with credit balances of generators resulting from the spread between the sales price of energy and generation variable cost, which will be deposited with FONINVEMEM. We participate with 65% of the credit balances recorded for the 2004-2006 period with respect to this spread. Our total contribution for the entire 2004-2006 period would amount to U.S.$35 million. However the final amount will depend on, among others, water conditions, the dispatch at our generation units determined by CAMMESA, and the resulting energy prices. Petrobras Energías’s share in combined cycles is estimated at 10%, and ultimately will be determined in December 2006, subject to the total amounts paid under the committed contributions.

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 2.8 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.

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.

As a result of its excellent performance, the Genelba Power Plant stands out in the Argentine electricity market for its high reliability and efficiency. The Power Plant is recognized as one of the combined cycle electric power plants with highest availability.

In 2005, Genelba achieved certification to SA8000 Standard – A Social Accountability System – and Petrobras Energía thus became the first company in the Argentine energy sector and one of the three companies in the country to achieve this certification.

We were awarded a 30-year concession beginning in August 1999 for hydroelectric power generation at HPPL. The complex has three generating units with an installed capacity of 285 MW. 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 are 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 same amount used for the calculation of these hydroelectric royalties.

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, 2005, 2004 and 2003.


	For the year ended December 31,
	2005	2004	2003
Generation (Gwh)	6,114	5,689	5,400
Sales (Gwh):
Contracted sales	1,255	1,437	1,588
Spot market	5,486	4,719	4,450
Total sales	6,741	6,156	6,038
Sales (in millions of pesos)	355	280	235

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 2005, HPDA sold 6,499 GWh in the wholesale electricity market, 6,090 GWh of which were supplied by its own generation (close to its historical average) and 409 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 U.S.$119 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, through Petrobras Energía, an indirect participation of 26.8% in Transener. Transener is the leading power transmission company in Argentina. Transener is controlled by Citelec, who owns 52.7% of the capital of Transener. Citelec, in turn, is owned on a 50/50 basis by Dolphin Fund Management, or Dolphin, and Petrobras Energía. We 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. No time limit was set to effect this divestiture. Pursuant to Resolution No. 941, Petrobras Energía presented to the Argentine Secretary of Energy a plan to divest completely its equity interest in Citelec. In June 2006, the Board of Directors of Petrobras Energía accepted the terms of the binding offer submitted by Eton Park Capital Management for the acquisition of its 50% equity interest in Citelec and, as part of this offer, its 22.22% interest in Yacylec. The terms of the offer provide for the transfer of the shareholding in Citelec at a fixed price of U.S.$54 million, plus an earn out relating to the result of the comprehensive rate review determined for Transener. We are currently negotiating the terms and conditions of the definitive agreements for the sale of Transener and Yacylec. The transfer of Citelec’s and Yacylec’s shares must be approved by the pertinent regulatory agencies and authorities.

Under a 95-year concession, which is due to expire in 2088, Transener operates approximately 8,581 km of extra high and high voltage power lines (most of them 500 Kv lines) and 34 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 1,280 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 6,005 km of electricity transmission lines (most of them 132 Kv lines) and 83 transformer stations.

Transener operates approximately 95% 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. 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 four transformer stations located in the Goias and Minas Gerais states.

In August 2005, Transener executed new agreements with the MUNIRAH and TSN Consortium to operate and maintain 350 km and 1,000 km high voltage line and eight transformer stations in Brazil. In addition, engineering studies have begun in order to operate the NOVATRANS Consortium, that includes nine 1,100 km high voltage and six transformer stations.

The following chart details the evolution of Transener’s failure rate for the fiscal years ended December 31, 2005, 2004 and 2003. 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 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 June 30, 2005, Transener concluded the restructuring of its financial debt, pursuant to a proposal accepted by 98.8% of its creditors. As part of the restructuring, Transener redeemed debt with a nominal value of about U.S.$ 460 million, in exchange for a combination of cash payments and new issuances of shares and corporate bonds. Following the restructuring, Citelec’s participation in Transener decreased from 65% to 52.7%.

On February 2, 2005, Transener entered into a Memorandum of Understanding (MOU) with UNIREN, in connection with the renegotiation of its tariffs. This MOU contemplates:

(i) a 31% increase in tariffs over those outstanding at the time of the agreement and other minor service adjustments, applicable until the completion of the integral revision of Transener’s tariffs. In the case of TRANSBA, the increase is of 25%;

(ii) an investment plan for the refurbishment and maintenance of the company’s assets and the extensions of the useful life of its equipment; and

(iii) the rules for an integral revision of Transener’s tariffs, which should, within ENRE’s framework, be applicable for the five-year period between 2006 and 2011. In that respect, in August 2005, Transener presented to ENRE a proposal for the recalculation of its compensation for such five-year period, as well as revisions of its asset base and rate of return.

The executive branch of the Argentine government ratified the MOU in November 2005, and the 31% and 25% increase in Transener and Transba tariffs was retroactively applied as from the date of the MOU.

Regarding the tariff proposal submitted by Transener, in connection with the integral review contemplated by the MOU, the ENRE, through Resolution N° 51/2006, called a Public Hearing for February 23, 2006. However, this Public Hearing was postponed by the ENRE through Resolution Nº 60/2006 citing observations made by the Unión Industrial Argentina (Argentine Industry Organization) at a similar hearing called by the ENRE regarding the distribution company EDELAP S.A. The ENRE has not yet established a new date for the hearing. See “Item 4. Information About the Company—Regulation of Our Businesses—Electricity and UNIREN”.

Yacylec S.A (“Yacylec”)

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. On June 2006, the Board of Directors of Petrobras Energía accepted an offer for the transfer of its equity in Yacylec for U.S.$6 million (See “—Transener”). 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 S.A.

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.

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. By the end of 2005, Edesur’s clients numbered 2,164,581, accounting for a 1.21% net increase compared to 2004. 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.

The license will expire in 2087 and is renewable 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 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 June 2005, Edesur signed a Letter of Agreement with the UNIREN as part of the renegotiation process involving the related concession contract. Based on this Letter of Agreement, in August 2005, the parties signed a Memorandum of Understanding (“MOU”) that includes, among other matters, the terms and conditions that, once the procedures established by regulations are fulfilled, shall form the substantive basis for amending the concession agreement. The MOU establishes that from its execution through June 30, 2006, an integral tariff review will be performed, which would allow Edesur to fix a new rate system effective August 1, 2006, and for the following five years. Also, it established a transition period for which the following was agreed upon: (i) a transitional rate system as from November 1, 2005, with an increase in the average service rate not exceeding 15%, applicable to all rate categories, except for residential rates; (ii) a mechanism to monitor costs, which allows for reviewing rate adjustments; (iii) restrictions on dividend distributions and debt interest payments during 2006; (iv) investment commitments for 2006; (v) service provision quality standards; and (vi) restrictions on Distrilec regarding a change in its interest or the sale of its shares in Edesur. As a preliminary condition for the Executive Branch to ratify the MOU, Edesur and its shareholders shall suspend all pending claims that are based on the measures taken pursuant to or in furtherance of the Public Emergency Law. As of the date of this annual report, the MOU is awaiting approval by the Federal Executive Branch, and no tariff increase has been applied.

The chart below sets forth Edesur’s annual power sales for each type of customer for the fiscal years ended December 31, 2005, 2004 and 2003.


	Annual sales in Gwh
	2005	2004	2003
Type of customer:
Residential	5,046	4,796	4,304
General	2,948	2,798	2,785
Large users	6,024	5,729	5,569

Total	14,018	13,323	12,658

Since its privatization, Edesur has made investments of approximately P$3,150 million, most of which were done before the enactment of the Public Emergency Law. As a result of these investments, Edesur has been able to satisfy an increase in demand of over 35% – 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 11.4%. During 2005 Edesur was able to reduce energy losses for the second year in a row. Energy losses dropped 0.40 percentage points — an improvement compared to 0.08 percentage points in 2004— and consequently the variable annual rate declined from 11.75% to 11.4%.

Notwithstanding these improvements, and due to the growth on the demand for electricity in line with Argentine economic growth, which have surpassed consumption levels recorded prior to the 2001 crisis, EDESUR’s network is close to overloading.

Competition

We compete with other generators in the wholesale electricity market, both in the spot market and for contracts (mainly short-term contracts).

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:

•

U.S.$420 million for each and every loss in our Argentine styrenics petrochemical business;

•

U.S.$350 million for each and every loss in our Brazilian styrenics petrochemical business;

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U.S.$190 million for each and every loss in our fertilizers business;

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U.S.$130 million for each and every loss in our San Lorenzo refining plant;

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U.S.$181 million for each and every loss in our Bahía Blanca’s refining plant;

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U.S.$180 million with respect to our thermoelectric generation businesses; and

•

U.S.$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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U.S.$100 million for ocean marine and non-ocean marine third-party liability;

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U.S.$7.5 million for well control costs in Argentine fields;

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U.S.$40 million for wells in Bolivia;

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U.S.$40 million for wells in Ecuador;

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U.S.$25 million for fields in Venezuela; and

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

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U.S.$5,000,000 for in well control costs;

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U.S.$5,000,000 in non-ocean marine third-party liability; and

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U.S.$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. 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).

Our QSEH policy, which was launched in April 2004, incorporates state-of-the-art concepts, including: ecofficiency, 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.

We have 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, called– Management Quality Excellence (MQE), started in 2004 through the Vector Units (Genelba, Lubricant Plant, Innova, E&P-Venezuela and E&P-Argentina), and continued in 2005 with the evaluation of new units: Pichi Picún Leufu Hidroelectric Complex, Bahía Blanca Refinery, Poliestirenos Argentina and Information Technology Areas, and our own network of gas stations.

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

To guarantee the effective implementation of the new Safety, Environmental and Health (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 this period, PSP sought to review business production unit action plans, production and centralized functions through the progress and enhancement of several projects. The major items are summarized below:

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.

Our policy expands SEH management to our contractors by implementing the several actions, among others, establishing a Contractor Staff Ranking and Certification process. To that end, the Company signed an agreement with Universidad Tecnológica Nacional (UTN, the National Technological University) to train 3,000 people in SEH issues, performed audits on companies that provided people-and-fuel transport services, trained gas station staff as to commercial downstream issues, and drafted a training map with the minimum SEH contents for staff members on contract.

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.

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, redefined our waste treatment plans and started projects to improve the performance of effluent treatment plants and fire fighting systems.

Since July 2003, we have put into operation a project called “Inventory System of Atmospheric Emissions,” or SIGEA. The main goal of this project is the creation of a tool for the management of atmospheric emissions that will help in the decision-making process for new investments (especially related to energy conservation and ecoefficiency). In the second place, the purpose of SIGEA is to help us detect improvements that will support our participation in the carbon credit markets. At the San Lorenzo Refinery and at the Austral Basin, the survey helped to identify project prospects that could result in energy efficiencies and which could help meet the requirements of the Clean Development Mechanism (CDM) of the Kyoto Protocol.

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.

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.

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

In 2005, we implemented fourteen emergency response bases distributed throughout different strategic points in the country (five nautical bases, eight ground bases and a logistic base), all of them with the required equipment and personnel for effective performance in an emergency.

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. As a result, 1,500 of our staff and related family members are exercising at those facilities.

Actions undertaken in 2005 included over 160 workshops on stress reduction, changing sedentary life-style, giving up cigarette smoking and a healthy diet, with 1,600 individuals in attendance. In addition, the Company provided CPR (cardiopulmonary resuscitation) and first-aid training to 2,000 individuals, and more than 90 individuals participated in the cigarette smoking reduction plan.

REGULATION OF OUR BUSINESSES

ARGENTINE REGULATORY FRAMEWORK

Petroleum

The Argentine oil and gas industry is regulated by 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 with respect to the powers of provinces, (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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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 must 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, on 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 a 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.

By Decrees 225/2006 and 226/2006, the Province of Neuquen sought to change the reference price to be used for calculating royalties using the West Texas Intermediate Crude reference price, or WTI, for petroleum and import prices at the border for gas. Those decrees are currently being challenged by all the upstream companies which have activities in Neuquén Province.

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.

Law 25,943, enacted on October 20, 2004, established the creation of a federal state-owned energy company called Energía Argentina S.A. (“ENARSA”), whose stated purpose is to carry out, through third parties or through joint ventures with third parties, (1) the study, exploration and exploitation of hydrocarbon natural reserves, (2) the transportation, processing and sale of hydrocarbons and their direct and indirect by-products, (3) the transportation and distribution of natural gas and (4) the generation, transportation, distribution and sale of electricity.

Furthermore, Law 25,943 granted to ENARSA exploration permits over all the national offshore areas not covered by existing exploration permits or exploitation concessions at the time of its enactment. Therefore, any future exploration of offshore areas must be done in joint venture with ENARSA.

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.

This resolution 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 U.S.$20,000,000 for offshore 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 in the revocation of a company’s registry with the Secretary of Energy as a petroleum company. To comply with these requirements, other companies, local or foreign, 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 a 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 gas or crude oil 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 for tariffs on storage, use of buoys and the handling of liquid hydrocarbons; and

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Maximum amounts that may be deducted 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 transferred to the Argentine government at no cost.

Refining

Hydrocarbon refining activities by oil producers and other third parties have been regulated ever since the enforcement of National Decree No. 1212/89, by the regulations under Hydrocarbons Law No. 17,319. Together with several other rules and regulations that have been 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 sell their products in the domestic market as they would otherwise in the international market (except for diesel oil and liquefied petroleum gas exports, which are subject to prior approval by the Secretary of Energy) and to freely install gas stations identified by their own or third-party brands, provided that their own gas stations or those directly operated by oil companies do not exceed 40% of their distribution network.

The Secretary of Energy also regulates the quality content of fuels. These regulations have become significantly more stringent in recent periods, with a number of new regulations enacted in 2003, and in 2004 a structure of economic sanctions was approved for violations of these quality controls. The new quality content regulations are applicable according to the following schedule: (1) regular and special gasolines starting as of January 1, 2006, to end as of January 2009, and (2) gas oil and fuel oil as of January 1, 2008 As of November 2004, certain rules and regulations have been put into effect that have impacted the refinery segment:

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Secretary of Energy Resolution No. 1104/04 requires refineries and gas station owners to submit monthly sales information or face financial penalties.

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Secretary of Energy Resolution No. 1679/04 requires oil producers to obtain governmental approval prior to exporting crude or diesel oil. In general, producers must demonstrate that they have either satisfied local demand requirements by refiners or granted the domestic market the opportunity to purchase oil on similar terms, in order to obtain approval to export. In addition, this resolution requires companies that wish to export diesel oil to register for prior governmental approval in order to guarantee a sufficient domestic supply of oil.

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Secretary of Energy Resolution No. 1102/04 created a regulatory framework for new gas stations, other fuel-sale outlets and distribution channels including the creation of a registry for 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 owners jointly responsible for breaches by companies operating under their brands.

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National Law No. 26.022 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 reporting issues.

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National Law No. 26.074 exempts up to 800,000 cubic meters of gas oil and diesel oil imports for domestic consumption from the Fuel Liquids and Gas Natural Tax, as well as from the Gas Oil Tax. The Secretary of Energy has the authority to increase that amount by up to 20% for 2006 and to exempt an amount for 2007 that is up to 20% higher than the amount exempted during 2006.

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Secretary of Energy Resolutions Nos. 1834/05 and 1879/05 create a mechanism to guarantee the supply of gas oil by refiners to gas stations and permit gas stations to acquire gas oil from third parties if regular suppliers fail to deliver gas oil. In the latter case, refiners must bear any additional costs borne by gas stations in procuring the diesel 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. However, as explained elsewhere in this report, since 2002, the Argentine government has imposed restrictions on the export of hydrocarbons. See “—Refining” and “—Taxation”.

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.

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.

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.

In January 2002, the Public Emergency Law established a five-year export tax on hydrocarbon exports and empowered the federal executive branch to establish the applicable tax rate. 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 products. In May 2004, the tax on exports of crude oil and liquefied petroleum gas was 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%, 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 U.S.$32.01 per barrel to 20% when the price is U.S.$45 or more per barrel.

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.

Quarterly agreements for the supply of diesel oil to public transportation companies

In light of the request by the Federal Executive Branch to maintain the conditions for the supply of diesel oil at differential prices for regulated-rate public transportation services, as provided under Decree No. 675/03 and the amending Decrees No. 159/04, 945/04, 280/05 and 564/05, several agreements were signed afterwards whereby refining companies undertook to supply diesel oil at lower than market price, depending on the kind of services provided by the transportation companies.

Refining companies, in turn, will receive economic compensation for the lower revenues resulting from compliance with the agreement. In order to calculate the lower revenues received, the government will consider the difference between net revenues from the sale of diesel oil at prices fixed by agreement and the net revenues that would have been obtained from the sale of the same diesel oil volumes at market price.

Refining companies processing the crude oil they produce, as is the case of PESA, will be entitled to a direct compensation, by deducting it from any amount payable for export duties. The Secretary of Energy will issue a fiscal credit certificate for the appropriate amount of compensation.

Stability of Fuel Prices

In an effort to mitigate the impact of the significant increase in the 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 federal executive branch, hydrocarbon producers and refineries entered into a series of temporary agreements, which contained price limits with respect to crude oil deliveries. In the last part of 2004, in light of further increases in the WTI, the Argentine government established a series of measures to ensure the supply of crude oil to local refiners at price levels consistent with the local retail price of refined products, which in the case of diesel oil and gasoline have remained constant, in peso terms, from July 29, 2004 to the present.

Royalties—Exchange Rates

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. These claims are still pending in the Supreme Court.

Natural Gas

In 1992, the Natural Gas Act was passed providing for the privatization of Gas del Estado, or GdE, and the deregulation of the price for natural gas. To effect the privatization, the assets of GdE were divided among two new transportation companies and eight new regional 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. A majority of the shares of each of the transportation and distribution companies was sold to private bidders.

The Natural Gas Act established a regulatory framework for the privatized industry and created ENARGAS, an autonomous entity under the Ministry of Economy and Public Works that is responsible for the regulation of the transportation, distribution, marketing and storage of natural gas.

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 systems. In addition, exploitation concessionaires may transport their own gas production pursuant to certain concessions granted under the Hydrocarbons Law.

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 of the natural gas industry must be reported to ENARGAS, which may refuse to authorize 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 regarding the natural gas industry, 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 review. ENARGAS’s decisions may be appealed through an administrative proceeding to the Ministry of Economy or directly to the federal courts.

Rate Regulation

Prior to the enactment of the Public Emergency Law, the provisions of the Natural Gas Act regulated the rates for gas transportation and distribution services, including those of TGS. Tariffs to end-users consist of the sum of three components: (1) the price of the gas purchased; (2) a transportation tariff for transporting gas from the production area through the distribution system; and (3) a distribution tariff. Under the Natural Gas Act and TGS license, TGS was permitted to adjust rates (1) semi-annually to reflect changes in the U.S. 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 were subject to adjustment 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 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 designed to allow regulated companies to retain a portion of the economic benefits arising from efficiency gains.

UNIREN

The Public Emergency Law pesified tariffs for public utility services at a P$1=U.S.$1 parity and prohibited the increase of these tariffs based on indexation factors. Pursuant to this law, the Argentine federal executive branch was authorized to renegotiate the terms of contracts relating to the provision of public utility services without being constrained by the applicable regulatory framework. This authority was later delegated by the executive to the Ministry of the Economy, which created, in July 2003, the Unidad de Renegociación, or UNIREN, for the purpose of assisting in the renegotiation process. The renegotiation must take into account the following criteria, 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 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. TGS is in the process of re-negotiating a tariff structure with UNIREN. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework— Electricity—UNIREN”.

Modifications to the regulatory framework

On February 16, 2004, the government, through Decree No. 180/04, took a number of significant steps that have altered the regulatory framework for the Argentine gas industry. The decree authorized the Secretary of Energy to take any necessary measures to maintain an adequate level of services in the event of a supply crisis. In addition, Decree No. 180/04 provided for:

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The creation of a trust fund (to be funded by tariffs payable by users of the service, special credit programs and contributions from direct beneficiaries) to finance the expansion of the industry and the creation of an electronic market;

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The creation of an electronic wholesale market to coordinate “spot” transactions of the sale of natural gas and secondary market transactions for transportation and distribution of natural gas. This electronic market was in full operation as of the date of this Annual Report; and

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A prohibition on distributors or their shareholders from having a controlling participation in more than one gas dealer.

Decree No. 181/04 also instructed the Secretary of Energy to design a framework for the normalization of prices of natural gas at the wellhead. 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. Natural gas prices for residential consumers were excluded from the process. It also authorizes the Secretary of Energy to create a new category of users who must buy gas directly from producers.

The prices resulting from this new framework shall be used as a reference for calculating and paying royalties and will be used by ENARGAS in calculating any necessary adjustments in tariffs that result from variations in the price of purchased gas. In addition, the decree requires that all agreements for the sale of natural gas be filed with the gas electronic market, and grants authority to the Secretary of Energy to regulate the sale of gas (1) between producers and (2) between producers and their affiliates.

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 to: (1) distributors for the supply to industrial users, (2) clients of distributors, or new direct consumers, who are required to buy directly from producers and (3) power stations that generate electricity for the local market;

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Authorization for producers to increase the prices of natural gas for sales to industrial users, electric generation companies and direct consumers 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;

•

Distribution and generation companies must renegotiate the price and volumes of their supply contracts with producers in line with this 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;

•

Regulated prices through June 31, 2005 for new direct customers; and

•

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 approved by Resolution No. 208 of the Ministry of Federal Planning, Public Investments and Utilities.

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 with producers, as from December 31, 2006 new direct consumers will be able to buy natural gas through the electronic gas market, which was originally created for “spot” transactions but now permits long-term operations. In order to purchase gas in the electronic market, new direct customers must post irrevocable purchase orders that contain the following minimum terms:

•

Term: 36 months;

•

Price: export parity; and

•

Volume: 1,000 cubic meters per day.

If the irrevocable offer is not accepted, new direct consumers may require the Secretary of Energy to require export producers 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.

Restrictions on Exports of Gas

In March 2004, in order to prevent a crisis in the supply of gas to the domestic market, the Secretary of Energy suspended all prior export authorizations and exports of natural gas surplus volumes and instructed the Undersecretary of Fuels to create a program for the rationing of gas exports and the use of the country’s transportation capacity. The Undersecretary of Energy subsequently adopted a program, known as the Program for the Rationalization of Natural Gas Exports, that established a mechanism for the determination of export restrictions based on various factors and contemplated monthly and quarterly limits on gas exports. In addition, during 2004, the Undersecretary of Fuels did not authorize exports of volumes (excluding surplus volumes) in excess of those exported during 2003. This program was replaced in June 2004 with the Complementary Program to Supply Natural Gas to the Domestic Market, which eased the monthly and quarterly limits established under the Program for the Rationalization of Natural Gas Exports.

During 2005, as part of the Complementary Program to Supply Natural Gas to the Domestic Market, the Secretary of Energy requested producers to redirect export gas to supply thermal plants and gas distribution companies. This decision limited our total gas export volumes by an average of about 110 thousand cubic meters per day, which deprived us of the higher margins offered by export prices. See “Item 3. Key Information—Risk Factors—Factors Related to Argentina— Limits on exports of hydrocarbons have lowered and may continue to lower our anticipated U.S. dollar-denominated cash receipts”.

Since March 2004, exports of natural gas have been subject to a 20% tax.

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

Compressed Natural Gas for Vehicles

Effective April 1, 2006, distributors may not provide compressed natural gas to gas stations. Instead, gas stations will be required to purchase compressed natural gas through the electronic wholesale market pursuant to a mechanism of irrevocable purchase orders designed by the Secretary of Energy. See “—Natural Gas—Modifications to the regulatory framework”. The mechanism is decided to conceal the identity of buyers and sellers. Buyers will be able to make joint offers, and agreements may not have a term that expires after April 30, 2007. If any purchase orders are not satisfied through this system, exports of natural gas will be diverted to cover the unsatisfied demand. This mechanism is expected to continue until the Secretary of Energy determines that it is no longer necessary, in light of the status of the domestic supply of natural gas.

Liquefied Petroleum Gas

Prior to the enactment of Law No. 26,020 on April 8, 2005, the Argentine liquefied 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. Under Resolutions No. 49/01 and No. 52/01, the Secretary of Energy was responsible for enforcing the rules and regulations applicable to the liquefied petroleum gas industry and a liquefied petroleum gas board, which reports to the National Refining and Marketing Board, which, in turn, reports to the Undersecretary of Fuels, was in charge of supervising and auditing the industry.

Regulatory framework

In 2005, the Argentine Congress established, pursuant to Law 26,020, a new regulatory framework for the liquefied petroleum gas industry that is intended to guarantee regular, reliable and cost effective provision of liquefied petroleum gas to low-income residential sectors that currently are without natural gas network services. This new regime regulates the production, fractioning, transportation, storage, distribution and sale of liquefied petroleum gas. These activities are considered of public interest. The enforcement of Law 26,020 is in the charge of the Secretary of Energy, which may delegate supervision and control tasks to ENARGAS. The relevant portions of this law are summarized below:

•

Prices. The Secretary of Energy determines reference prices (which must be below export parity prices) for the domestic market with the goal of guaranteeing regular supply in that market and may establish price stabilization mechanisms in order to avoid price fluctuations in the domestic market. The Secretary of Energy will determine and disseminate a reference price for each region every six months.

•

Market limitations. The Secretary of Energy together with the Antitrust Commission, or CNDC, are authorized to analyze the sector, for the purpose of fixing limits at each stage of vertical integration of the industry.

•

Open Access. An open access regime is established in connection with the storage of liquefied petroleum and the Secretary of Energy establishes terms and conditions for the determination of maximum tariffs for storage.

•

Imports/Exports. No restrictions are imposed, and no prior authorization is required, for the import of liquefied petroleum gas, and the Secretary of Energy may authorize the export of liquefied petroleum gas without restriction, so long as the domestic market is satisfied. No shortage of supply is currently experienced in the domestic market.

•

Trust Fund. A trust fund was established for the purpose of subsidizing the consumption of liquefied petroleum gas by the low-income residential sector and expanding the distribution network to areas without service. The trust is to be funded from the sanctions collected under this law and contributions from the national budget.

Electricity

By 1990, virtually all of the electricity supply in Argentina was controlled by the public sector (97% of total generation). In 1991, as part of the economic plan adopted by former President Carlos Menem, the Argentine government undertook an extensive program of privatization of all major state-owned industries, including the electricity generation, transmission and distribution sectors. In January 1992, the Argentine federal congress adopted the Regulatory Framework Law (Law No. 24,065), which established guidelines for the restructuring and privatization of the electricity sector. This Regulatory Framework Law, which continues to provide the framework for regulation of the electricity sector since the privatization of this sector, distinguished the generation, transmission and distribution of electricity as separate businesses and subjected each to appropriate regulation.

The ultimate objective of the privatization process was to reduce rates paid by users and improve quality of service through competition. The privatization process commenced in February 1992 with the sale of several large thermal generation facilities, and continued with the sale of transmission and distribution facilities (including those currently operated by our company) and additional thermoelectric and hydroelectric generation facilities.

The Public Emergency Law, combined with the devaluation of the peso and high rates of inflation, had a severe effect on public utilities in Argentina. Because public utilities were no longer able to increase tariffs at a rate at least equal to the rate of inflation in Argentina, increases in the rate of inflation led to decreases in their revenues in real terms and a deterioration of their operating performance and financial condition. Most public utilities had also incurred large amounts of foreign currency indebtedness under the Convertibility regime and, following the elimination of the Convertibility regime and the resulting devaluation of the peso, the debt service burden of these utilities increased sharply, which led many of these utilities to suspend payments on their foreign currency debt in 2002. This situation caused many Argentine electricity generators, transmission companies and distributors to defer making further investments in their networks. As a result, Argentine electricity market participants, particularly generators, are currently operating at near full capacity, which could lead to insufficient supply to meet a growing national energy demand.

To address the electricity crisis generated by the economic crisis, the Argentine government has repeatedly intervened in and modified the rules of the wholesale electricity market since 2002. These modifications include the establishment of caps on the prices paid by distributors for electricity power purchases and the requirement that all prices charged by generators be calculated based on the price of natural gas (which are also regulated by the Argentine government), regardless of the fuel actually used in generation activities, which together have created a huge structural deficit in the operation of the wholesale electricity market. More recently, in December 2004, the Argentine government adopted new rules to readapt or readjust the marketplace, but these rules will not come into effect until the construction of two new 800 MW combined cycle generators is completed. The construction of these generators is scheduled to be completed in late 2008 and will be partially financed with credit balances of generators resulting from the spread between the sales price of energy and generation variable cost, which will be deposited with the Fund for Investments Required to Increase Electricity Supply in the Wholesale Electricity Market (Fondo de Inversiones Necesarias que permitan incrementar la oferta de energía eléctrica en el Mercado Eléctrico Mayorista, or FONINVEMEM). We cannot assure you that the Argentine government will complete these projects in a timely manner, or at all.

The planned construction of these new generators reflects a recent trend by the Argentine government to take a more active role in promoting energy investments in Argentina. In addition to these projects, in April 2006 the Argentine congress enacted a law that authorized the executive branch to create a special fund to finance infrastructure improvements in the Argentine energy sector through the expansion of generation, distribution and transmission infrastructure relating to natural gas, propane and electricity. The fund will obtain funds through cargos específicos (specific charges) passed on to customers as an itemization on their energy bills. We cannot assure you that the Argentine government will complete the implementation of these new projects in a timely manner, or at all.

Regulatory authorities

The principal regulatory authorities responsible for the Argentine electricity industry are:

(1)

the Secretary of Energy of the Ministry of Federal Planning, Public Investment and Services, and

(2)

the National Electricity Regulator (Ente Nacional Regulador de la Electricidad, or ENRE).

The Secretary of Energy advises the Argentine government on matters related to the electricity sector and is responsible for the application of the policies concerning the Argentine electricity industry.

The ENRE is an autonomous agency created by the Regulatory Framework Law. The ENRE has a variety of regulatory and jurisdictional powers, including, among others:

•

enforcement of compliance with the Regulatory Framework Law and related regulations;

•

control of the delivery of electric services and enforcement of compliance with the terms of concessions;

•

adoption of rules applicable to generators, transmitters, distributors, electricity users and other related parties concerning safety, technical procedures, measurement and billing of electricity consumption, interruption and reconnection of supplies, third-party access to real estate used in the electricity industry and quality of services offered;

•

prevention of anticompetitive, monopolistic and discriminatory conduct between participants in the electricity industry;

•

imposition of penalties for violations of concessions or other related regulations; and

•

arbitration of conflicts between electricity sector participants.

The ENRE is managed by a five-member board of directors appointed by the executive branch of the Argentine government. Two of these five members are nominated by the Federal Council on Electricity (Consejo Federal de la Energía Eléctrica, or CFEE). The CFEE is funded with a percentage of revenues collected by CAMMESA (as defined below) for each MWh sold in the market. Sixty percent of the funds received by the CFEE are reserved for the Fondo Subsidiario para Compensaciones Regionales de Tarifas a Usuarios Finales (Regional Tariff Subsidy Fund for End Users), from which the CFEE makes distributions to provinces that have met certain specified tariff provisions. The remaining forty percent is used for investments related to the development of electrical services in the interior regions of Argentina.

The Wholesale Electricity Market

Overview

The Secretary of Energy established the wholesale electricity market in August 1991 to allow electricity generators, distributors and other agents to buy and sell electricity in spot transactions or under long-term supply contracts at prices determined by the forces of supply and demand.

The wholesale electricity market consists of:

•

a term market in which generators, distributors and large users enter into long-term agreements on quantities, prices and conditions;

•

a spot market, in which prices are established on an hourly basis as a function of economic production costs, represented by the short-term marginal cost of production measured at Ezeiza 500 Kv substation, the system’s load center; and

•

a stabilization system for spot market prices applicable to purchases by distributors, which operates on a quarterly basis.

Operation of the wholesale electricity market

The operation of the wholesale electricity market is administered by the Wholesale Electricity Market Administration Company (Compañía Administradora del Mercado Mayorista Eléctrico S.A., or CAMMESA). CAMMESA was created in July 1992 by the Argentine government, which currently owns 20% of CAMMESA’s capital stock. The remaining 80% is owned by various associations that represent wholesale electricity market participants, including generators, transmitters, distributors, large users and electricity brokers.

CAMMESA is in charge of:

•

managing the national interconnection system pursuant to the Regulatory Framework Law and related regulations, which includes:

•

determining technical and economic dispatch of electricity in the national interconnection system;

•

maximizing the system’s security and the quality of electricity supplied;

•

minimizing wholesale prices in the spot market;

•

planning energy capacity needs and optimizing energy use pursuant to the rules set out from time to time by the Secretary of Energy; and

•

monitoring the operation of the term market and administering the technical dispatch of electricity pursuant to any agreements entered into in such market;

•

acting as agent of the various wholesale electricity market participants;

•

purchasing or selling electricity from or to other countries by performing the relevant import/export operations; and

•

providing consulting and other services related to these activities.

The operating costs of CAMMESA are covered by mandatory contributions made by wholesale electricity market participants. CAMMESA’s annual budget is subject to a mandatory cap equivalent to 0.85% of the aggregate amount of transactions in the wholesale electricity market projected for that year.

Wholesale electricity market participants

The main participants in the wholesale electricity market are generation, transmission and distribution companies. Large users and traders participate also in the wholesale electricity market, but to a lesser extent.

Generators

According to a recent report issued by CAMMESA, there are 43 generation companies in Argentina, most of which operate more than one generation plant. As of March 31, 2006, Argentina’s installed power capacity was 24,080 MW. Of this amount, 55% was derived from thermal generation, 41% from hydraulic generation and 4% from nuclear generation, provided by 40 private companies using conventional thermal equipment and hydraulic generation technology, 2 bi-national companies using hydraulic generation technology and one national state-owned company using nuclear generation technology. Private generators participate in CAMMESA through the Argentine Association of Electric Power Generators (Asociación de Generadores de Energía Eléctrica de la República Argentina, or AGEERA), which is entitled to appoint two acting and two alternate directors of CAMMESA.

Transmitters

Electricity is transmitted from power generation facilities to distributors through high voltage power transmission systems. Transmitters do not engage in purchases or sales of power. Transmission services are governed by the Regulatory Framework Law and related regulations promulgated by the Secretary of Energy.

In Argentina, transmission is carried at 500 Kv, 220 Kv and 132 Kv through the national interconnection system. The national interconnection system consists primarily of overhead lines and sub-stations and covers approximately 90% of the country. The majority of the national interconnection system, including almost all of the 500 Kv transmission lines, has been privatized and is owned by Transener, which is partially owned by us. Regional transmission companies, most of which have been privatized, own the remaining portion of the national interconnection system. Supply points link the national interconnection system to the distribution systems, and there are interconnections between the transmission systems of Argentina, Brazil, Uruguay and Paraguay allowing for the import or export of electricity from one system to another.

Transmission companies also participate in CAMMESA by appointing two acting and two alternate directors through the Argentine Association of Electric Power Transmitters (Asociación de Transportistas de Energía Eléctrica de la República Argentina, or ATEERA).

Distributors

Each distributor supplies electricity to consumers and operates the related distribution network in a specified geographic area pursuant to a concession. Each concession establishes, among other things, the concession area, the quality of service required, the rates paid by consumers for service and an obligation to satisfy demand. ENRE monitors compliance by federal distributors with the provisions of their respective concessions and with the Regulatory Framework Law, and provides a mechanism for public hearings at which complaints against distributors can be heard and resolved. In turn, provincial regulatory agencies monitor compliance by local distributors with their respective concessions and with local regulatory frameworks.

The largest distribution companies are Edesur and Empresa Distribuidora y Comercializadora Norte S.A.

Distributors participate in CAMMESA by appointing two acting and two alternate directors through the Argentine Association of Electric Power Distributors (Asociación de Distribuidoras de Energía Eléctrica de la República Argentina, or ADEERA).

Large users

The wholesale electricity market classifies large users of energy into three categories: Major Large Users (Grandes Usuarios Mayores, or GUMAs), Minor Large Users (Grandes Usuarios Menores, or GUMEs) and Particular Large Users (Grandes Usuarios Particulares, or GUPAs).

Each of these categories of users has different requirements with respect to purchases of their energy demand. For example, GUMAs are required to purchase 50% of their demand through supply contracts and the remainder in the spot market, while GUMEs and GUPAs are required to purchase all of their demand through supply contracts.

Large users participate in CAMMESA by appointing two acting and two alternate directors through the Argentine Association of Electric Power Large Users (Asociación de Grandes Usuarios de Energía Eléctrica de la República Argentina, or AGUEERA).

Traders

Since 1997, traders are authorized to participate in the wholesale electricity market by intermediating block sales of energy. Currently, there are eight authorized traders in the wholesale electricity market, several of which conduct transactions with Comercializadora de Energía del Mercosur S.A. (CEMSA) in the export market.

Spot market

Spot prices

The emergency regulations enacted after the Argentine crisis in 2001 had a significant impact on energy prices. Among the measures implemented pursuant to the emergency regulations were the pesification of prices in the wholesale electricity market, known as the spot market, and the requirement that all spot prices be calculated based on the price of natural gas, even in circumstances were alternative fuel such as diesel is purchased to meet demand due to the lack of supply of natural gas.

Prior to the crisis, energy prices in the spot market were set by CAMMESA, which determined the price charged by generators for energy sold in the spot market of the wholesale electricity market on an hourly basis. The spot price reflected supply and demand in the wholesale electricity market at any given time, which CAMMESA determined using different supply and demand scenarios that dispatched the optimum amount of available supply, taking into account the restrictions of the transmission grid, in such a way as to meet demand requirements while seeking to minimize the production cost and the cost associated with reducing risk of system failure.

The spot price set by CAMMESA compensated generators according to the cost of the last unit to be dispatched for the next unit as measured at the Ezeiza 500 Kv substation, which is the system’s load center and is in close proximity of the City of Buenos Aires. Dispatch order was determined by plant efficiency and the marginal cost of providing energy. In determining the spot price, CAMMESA also would consider the different costs incurred by generators not in the vicinity of Buenos Aires.

In addition to energy payments for actual output at the prevailing spot market prices, generators would receive compensation for capacity placed at the disposal of the spot market, including stand-by capacity, additional stand-by capacity (for system capacity shortages) and ancillary services (such as frequency regulation and voltage control).

Seasonal Prices

The emergency regulations also made significant changes to the seasonal prices charged to distributors in the wholesale electricity market, including the implementation of a cap (which varies depending on the category of customer) on the cost of electricity charged by CAMMESA to distributors at a price significantly below the spot price charged by generators.

Prior to implementation of the emergency regulations, seasonal prices were regulated by CAMMESA as follows:

•

prices charged by CAMMESA to distributors and large users changed only twice per year (in summer and winter), with interim quarterly revisions in case of significant changes in the spot price of energy, despite prices charged by generators in the wholesale electricity market fluctuating constantly;

•

prices were determined by CAMMESA based on the average cost of providing one MW of additional energy (its marginal cost), as well as the costs associated with the failure of the system and several other factors; and

•

CAMMESA would use seasonal database and optimization models in determining the seasonal prices and would consider both anticipated energy supplies and demand as follows:

•

in determining supply, CAMMESA would consider energy supplies provided by generators based on their expected availability, committed imports of electricity and the availability declared by generators;

•

in determining demand, CAMMESA included the requirements of distributors and large users purchasing in the wholesale electricity market as well as committed exports.

Stabilization Fund

The stabilization fund, managed by CAMMESA, absorbs the difference between purchases by distributors and large users at seasonal prices and payments to generators for energy sales at the spot price. When the spot price is lower than the seasonal price, the stabilization fund increases, and when the spot price is higher than the seasonal price, the stabilization fund decreases. The outstanding balance of this fund at any given time reflects the accumulation of differences between the seasonal price and the hourly energy price in the spot market. The stabilization fund is required to maintain a minimum amount to cover payments to generators if prices in the spot market during the quarter exceed the seasonal price.

Billing of all wholesale electricity market transactions is performed monthly through CAMMESA, which acts as the clearing agent for all purchases between participants in the market. Payments are made approximately 40 days after the end of each month.

The stabilization fund was adversely affected as a result of the modifications to the spot price and the seasonal price made by the emergency regulations, pursuant to which seasonal prices were set below spot prices resulting in large deficits in the stabilization fund. As of February 2006, the stabilization fund deficit totaled P$1,710.6 million. This deficit has been financed by the Argentine government through loans to CAMMESA and by generators through contributions to FONINVEMEM.

Term market

Historically, generators were able to enter into agreements in the term market to supply energy and capacity to distributors and large users. Distributors were able to purchase energy through agreements in the term market instead of purchasing energy in the spot market. Term agreements typically stipulated a price based on the spot price plus a margin. Prices in the term market were at times lower than the seasonal price that distributors were required to pay in the spot market. However, as a result of the emergency regulations, spot prices are currently higher than seasonal prices, particularly with respect to residential tariffs, making it unattractive to distributors to purchase energy under term contracts while prices remain at their current levels.

Renegotiation of Utility Tariffs

Our affiliates Edesur, Transener and Transba are negotiating their utility contracts with UNIREN. These discussions are in different stages. See “Item 4. Gas and Energy —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.

VENEZUELAN REGULATORY FRAMEWORK

Petroleum and Gas

The Venezuelan state owns all hydrocarbon fields and has established methods for regulating the exploitation of hydrocarbons in Venezuelan fields that are different from those in Argentina.

The Gas Hydrocarbons Organic Law published on September 23, 1999 regulates the exploitation of free or non-associated gas and the transportation, distribution, collection, storage, industrialization, handling and internal and external sale of associated (gaseous hydrocarbon that is extracted jointly with crude oil) gas and free or non-associated gas (hydrocarbon that is extracted from a field which does not contain crude oil), permitting the private sector’s participation in these activities.

The new Venezuelan Constitution, effective December 1999, contains provisions related to petroleum activity, including Article 12, which states that oil fields are the property of the Venezuelan state, and Article 302, which reserves petroleum activity to the Venezuelan state. The Constitution tasks Petróleos de Venezuela S.A., PDVSA, a state-owned entity, with responsibility for managing petroleum activity.

The new Hydrocarbons Organic Law published on November 13, 2001 effectively reversed 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 (which include exploration, extraction and initial transportation and storage) and to the sale of crude oil and specific products.

The Hydrocarbons Organic Law regulates the exploration, exploitation, refinery, industrialization, transportation, storage, sale and conservation of hydrocarbons and refined products. 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 maintains direct control by owning fifty percent (50%) or more of the shares or quotas that represent the capital stock. The sale of natural hydrocarbons and certain specified by-products 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 to the property of the Venezuelan state.

The National Assembly must grant prior approval to the creation of these entities and the conditions under which they will carry out their activities. These entities must meet the following minimum conditions: (1) each must have a maximum duration of 25 years (which may be extended for 15 years), (2) each must provide information regarding location, orientation and extension of the area, (3) all of the entity 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.

Traditionally, our interest in Venezuelan oil and gas fields have been held through operating service agreements with PDVSA, which established the terms of our compensation for production activities and investments. These contracts were awarded during 1994 and 1997 through bidding processes known as second round bids and third round bids, respectively. In 2005, the Venezuelan government announced that these operating service agreements did not comply with the Hydrocarbons Organic Law and instructed the Ministry of Energy and Petroleum to commence negotiations with private operators to convert all operating agreements into mixed-ownership ventures where more than 50% of each field is state-owned. These negotiations were completed in March 2006, and as a result, all operating service agreements previously awarded during the second and third bidding rounds will be converted to mixed ownership companies (empresa mixta) in which the Venezuelan government, through the Corporación Venezolana de Petróleo, S.A. (“CVP”), will hold at least 60% of the share capital and private companies will hold the remainder. The shareholdings allocated to private companies were determined on the basis of the value attributed to the different operating service agreements during the negotiations.

The National Assembly has approved (i) the principal terms of the conversion agreements and the form of organizational documents for the mixed ownership companies, (ii) amendments to the Hydrocarbons Organic Law and certain tax laws to allow the mixed ownership companies to sell their production of crude oil to PDVSA and its affiliates and to qualify as exporters for value-added tax purposes and (iii) a new law, the Law for Regulating the Participation of Private Entities in Primary Activities, that allows private companies to participate in primary activities in Venezuela only through mixed ownership companies.

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. Entities that wish to carry out activities related to the processing or domestic sale of refined hydrocarbons must obtain a permit from the Ministry of Energy and Mines.

Relevant Tax Features

•

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 by-products for export. 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 the value 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 export 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 operating agreements with state companies are also subject to a 50% rate.

•

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 VAT at a rate of 8%.

•

Municipal taxes

Hydrocarbon activities are not subject to municipal taxes, as these taxes 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 generally subject to a municipal tax on gross income.

Additional Matters

•

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 ensure 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 established within OPEC. Article 6 of the new Hydrocarbons Organic Law requires all persons who perform activities regulated by the Hydrocarbons Law to comply with production cuts, such as those that may be set by OPEC. Hence any production cuts may directly affect private producers and contractors as well as PDVSA.

•

Royalties

Since January 2002, royalties on oil and gas production have been set at a rate of 30%.

•

Exchange control system

On February 5, 2003, the Venezuelan government set forth an exchange control system. These regulations state that companies established for the purpose of developing any of the activities described in the Hydrocarbons Organic Law may maintain accounts in currency other than the currency of Venezuela in banking or similar institutions outside of Venezuela only for purposes of meeting their obligations outside Venezuela. The Central Bank of Venezuela must approve these accounts. Any other foreign currency generated by these 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 same exchange control measures will also be applicable to mixed-ownership companies.

ECUADORIAN REGULATORY FRAMEWORK

Petroleum and Gas

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

The executive branch regulates hydrocarbon policies. The Ministry of Energy and Mines is responsible for developing hydrocarbon policies for the President’s consideration.

The National Directorate of Hydrocarbons, which 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, also under the authority of the Ministry of Energy and Mines, is in charge of approving environmental impact studies and environmental management plans that apply to Natural Protected Areas.

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, or Petroecuador, by and through third parties.

The award of exploration and exploitation agreements is performed through a special tender mechanism. 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, that contractor 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. A minimum average investment of U.S.$120 to U.S.$180 per hectare, either on land and/or in seawater, must 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. The contractor is not obliged to pay royalties on contracts for specified services or for marginal or participation fields. 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 must 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 provides exploration and exploitation services in the agreed area at its own risk and expense. If the contractor finds commercially exploitable fields, it has the right to be reimbursed for its investments, costs and expenses and to be paid for its services.

Prior to initiating any work, an environmental impact study and an environmental management plan must be prepared, in accordance with consultation and participation procedures referred to in the National Constitution.

In April 2006, the Ecuadorian Hydrocarbons Law was amended to require that the government benefit from at least 50% of any income derived from oil price increases over the average monthly sales price for such oil at the execution date of the relevant production agreement, expressed in constant values as of the calculation date. The government’s share is only dependent on oil price fluctuations and not on the volume of oil produced. Regulations implementing this amendment have not yet been adopted.

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 Organic Hydrocarbon Law No. 26221 and has assumed significant powers within the Peruvian energy industry. It represents the Peruvian State as contracting party and has authority to grant areas for hydrocarbon exploration and exploitation activities and to supervise the activities carried out in those areas. Perupetro was also given the authority to negotiate contracts, including the payment of royalties, which is further governed by a series of national decrees. Certain consultation and participation procedures must be followed.

In Bolivia, the petroleum and gas industry is regulated by the System of Regulation by Sectors, which regulates, controls and supervises telecommunications, electricity, hydrocarbons, transportation and water activities, to ensure that they operate efficiently and protect the interest of users, service providers and the Bolivian state by contributing to the development of the country. In May 2005, a new hydrocarbons law, Law No.3058 was enacted, which, among other things, significantly increased taxes for companies in the industry. The law imposed an 18% royalty and a 32% direct tax on hydrocarbons (DTH) applicable on 100% of production. These new taxes are in addition to applicable taxes under existing law, Law No.843.

In May 2006, the Bolivian government enacted the so-called “hydrocarbon nationalization” under Supreme Decree No. 28,701. This Decree provides that as from May 1, 2006 oil companies must deliver to YPFB the property of all hydrocarbon production for sale. Oil companies will have a 180-day transition period to subscribe new agreements, which must be individually authorized and approved by the Bolivian Legislature. The Ministry of Hydrocarbons and Mines will determine, on a case by case basis, the interest in each field corresponding to oil companies by means of investment audits, operational costs and profitability indicators. The current distribution of the oil and gas production value will be maintained during the transition period, in the case of fields whose certified average production of natural gas for 2005 was lower than 100 million cubic feet per day. In addition, the abovementioned decree provides, among other things, that the Bolivian government shall recover full participation in the entire oil and gas production chain, and for this purpose provides for the nationalization of the shares of stock necessary for YPFB to have at least 50% plus one of the shares in a number of companies, among which is Petrobras Bolivia Refinación. We are currently in the process of evaluating the effects of three recently announced measures on our operations. The implementation of these measures requires a number of steps that have not yet been fully defined, including a comprehensive restructuring of YPFB. 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

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

In addition to the companies included in this chart, we have holding companies in Spain, Austria, Bolivia, the Cayman Islands the Bermudas and Argentina, which are not reflected in the chart. Some of our material subsidiaries and affiliates are held through such holding companies.

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 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 “Item 4. Information about the Company – Business Overview”.

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 21 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 22 provides a reconciliation to U.S. GAAP of net income, shareholders’ equity and certain other selected financial data.

Analysis of Consolidated Results of Operations

Petrobras Energía’s Corporate Reorganization

Effective January 1, 2005, EG3, PAR and PSF merged into Petrobras Energía, and as from such date all the assets, liabilities, rights and obligations of EG3, PAR and PSF have been assumed by Petrobras Energía. See “Item 4. Information About the Company–Our History and Development– Petrobras Energía Merger”.

Accounting principles generally accepted in Argentina do not contemplate the accounting treatment to be given to business combinations among entities belonging to the same economic group. Argentine GAAP in force as of December 31, 2005, provides that, in the absence of applicable local rules, transactions should be recorded in accordance with generally accepted international rules, in particular those applicable in markets and jurisdictions that are relevant to the issuer of the financial statements. Since our Class B Shares are listed on the New York Stock Exchange, we looked to U.S. GAAP, in particular to Statement of Financial Accounting Standard No. 141, which provides that business combinations among entities under common control shall be accounted under the pooling of interest method.

According to this method, the assets, liabilities and shareholders’ equity of the combining entities are recorded by the surviving entity according to the accounting measurements used by the combining entities on the effective date of the merger. In addition, according to the pooling of interest method, financial statements for previous years reflect the assets, liabilities, results and cash flows of the surviving entity as if the pooling of interests had occurred at the beginning of the earliest fiscal year presented.

Accordingly, this annual report presents information for the years ended as of December 31, 2004 and 2003, assuming that the merger of EG3, PAR and PSF into Petrobras Energía had occurred on January 1, 2003. Considering that the effective date of the merger is January 1, 2005, total shareholders’ equity and net income for the previous years shown on a comparative basis do not change as a result of the merger. For this reason, the balancing item of the net effect of additions, both in terms of the shareholders’ equity and net income, is recorded under Minority Interest in Subsidiaries.

PROPORTIONAL CONSOLIDATION AND PRESENTATION OF DISCUSSION

In accordance with the procedures set forth in Technical Resolution No. 21 of the Argentine Federation of Professional Councils in Economic Sciences, or FACPCE, we are 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 the company’s 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 the company’s assets, liabilities and income (loss) and cash flows. In addition, related party receivables, payables and transactions among members of the consolidated group and companies under joint control are eliminated on a pro rata basis pursuant to our ownership share in those companies.

The Company has joint control over the following companies:

•

Citelec, a company engaged in the electricity transmission business in Argentina through its subsidiary, Transener.

•

CIESA, a company mainly engaged in the gas transportation business in the south of Argentina through its subsidiary, TGS.

•

Distrilec, a company engaged in the electricity distribution business in the southern area of the Federal Capital and 12 districts of the Province of Buenos Aires, through its subsidiary, Edesur.

The three companies are considered part of the Gas and Energy 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 such interest 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—Gas and Energy—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener”.

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. To this effect, the Company’s equity in the earnings of companies under joint control is shown under Equity in Earnings of Affiliates.


	With Proportional Consolidation For the Year Ended December 31,						Without Proportional Consolidation For the Year Ended December 31,
	2005		2004		2003		2005		2004		2003
Net sales	10,655		8,763		7,113		9,512		7,756		6,234
Costs of sales	(7,058	)	(5,791	)	(4,759	)	(6,255	)	(5,123	)	(4,190	)

Gross profit	3,597		2,972		2,354		3,257		2,633		2,044
Administrative and selling expenses	(941	)	(847	)	(770	)	(850	)	(765	)	(675	)
Exploration expenses	(34	)	(133	)	(360	)	(34	)	(133	)	(360	)
Other operating expenses, net	(329	)	(324	)	(123	)	(321	)	(296	)	(106	)

Operating income	2,293		1,668		1,101		2,052		1,439		903
Equity in earnings of affiliates	166		76		163		182		79		371
Financial income (expense) and holding gains (losses)	(899	)	(1,265	)	(387	)	(752	)	(1,101	)	(538	)
Other expenses, net⁽²⁾	(332	)	(40	)	(447	)	(321	)	(33	)	(434	)

Income before income tax and minority interest in subsidiaries	1,228		439		430		1,161		384		302
Income tax provision	(381	)	211		(29	)	(355	)	237		(58	)
Minority interest in subsidiaries	(234	)	28		(20	)	(193	)	57		137

Net income	613		678		381		613		678		381

OVERVIEW

We are an integrated energy company engaged in:

•

The exploration and production of oil and gas;

•

Refining and distribution;

•

Petrochemicals; and

•

Gas and energy.

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 Venezuela, Ecuador, Peru, Bolivia, Brazil, Colombia and Mexico. Approximately 58% of our total assets, 66% of our net sales, 54% of our combined crude oil and gas production and 40% of our proved oil and gas reserves were located in Argentina as of December 31, 2005. 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 Key Information—Risk Factors”.

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 U.S. dollars;

•

Fluctuations in the Argentine peso/U.S. dollar exchange rate;

•

Interest rates;

•

Changes to our capital expenditures plan;

•

Price controls; and

•

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

FACTORS AFFECTING OUR CONSOLIDATED RESULTS OF OPERATIONS

1) Economic Developments 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 interest rates, the value of the peso against foreign currencies, price controls, business and tax regulations and in general by the political, social and economic scenario in and affecting Argentina.

a) Argentine Peso Devaluation

As of December 31, 2005, the peso’s nominal exchange rate was P$3.03 to U.S.$1.00 compared to P$2.98 and P$2.94 to U.S.$1.00 rates as of December 31, 2004 and 2003, respectively.

Almost all our financial debt and a significant portion of our affiliates’ debt are denominated in U.S. dollars. This exposes us to foreign exchange risks. Diversification of the Company’s businesses with foreign operations having a cash flow primarily denominated in U.S. dollars, commodity prices that are sensitive to dollar price changes, and an export-oriented trade policy for oil crude by-products, help us mitigate our U.S. dollar-exposure. Exchange differences arising from liabilities in foreign currency assumed to hedge the net investment in foreign entities are not charged to income but recorded under Transitory differences – foreign currency translation, where the effect arising from the translation of foreign operations is recorded.

Considering the mitigating factors mentioned above, exchange differences accounted for a P$31 million and a P$36 million loss in 2005 and 2004, respectively, and a P$419 gain in 2003.

b) Inflation

Historically, the Argentine economy has exhibited significant volatility, characterized by periods with high rates of inflation.

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.

In March 2003, 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.

Inflation has significantly accelerated since 2004, driven by the pace of economic growth in Argentina. The consumer price index increased by 6.1% in 2004 and by 12.3% in 2005, while the wholesale price index increased by 7.9% in 2004 and by 10.8% in 2005.

In accordance with accounting principles generally accepted in Argentina, the existence or non-existence of an inflation or deflation context should be permanently evaluated by the Argentine Federation of Professional Councils in Economic Sciences. If inflation accounting were reinstated, financial statements would have to be stated in constant currency.

In the past, inflation has materially undermined the Argentine economy and the government’s ability to stimulate economic growth. While inflation indexes currently are within reasonable parameters, we cannot assure you that this situation will remain stable. Sustained inflation in Argentina, without the passing through to prices of products sold by us in the domestic market, would have an adverse effect on our results of operations and financial position.

c) 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 pesification of tariffs at a rate of P$1.00 to U.S.$1.00 basis and (3) financial debts primarily denominated in foreign currency, adversely affected 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, TGS, and Transener defaulted on their debt. TGS and Transener restructured their financial debt through restructuring proposals, which were accepted by about 99.8% and 98.8% of the related creditors, respectively. In September 2005, CIESA signed an agreement to restructure its financial debt with all its creditors. The consummation of the restructuring is subject to certain regulatory approvals. See “Item 4. Information About the Company–Gas and Energy—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener” and “Item 4. Information About the Company–Gas and Energy—Gas Transportation-TGS—Our interests in TGS and Corporate Developments”. Until a successful restructuring of this debt, substantial doubt will remain surrounding the ability of CIESA to continue operating as a going concern.

The Public Emergency Law granted the Argentine government broad authority to renegotiate utility contracts, and the law has been extended to December 2006. 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. UNIREN (the agency created to, among other purposes, 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, 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 stated that UNIREN’s latest proposals were not sufficient. See “Item 4. Information About the Company—Regulation of Our Businesses—Argentine Regulatory Framework—Electricity—UNIREN” “Item 4. Gas and Energy—Gas Transportation—TGS—Regulated Energy Segment” and “Item 4. Information About and Company—Gas an Energy—Electricity—Electricity Transmission: Transener, Yacylec and Enecor—Transener”.

We are unable to predict the future development of the renegotiation process involving rates and concession contracts or the impact it may have on the results of operations or the financial position of those companies. In general, our utility affiliates will not be able to return to adequate levels of profitability and sound financial condition until reasonable tariff increases are approved.

d) 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 in the domestic market. We have gradually renegotiated the terms and conditions of gas sales agreements entered into with industrial clients in order to reflect the effects of the peso devaluation and the subsequent inflation. In addition, we have also attempted to maximize export opportunities in an effort to capitalize on higher prices offered by foreign markets. Gas exports, mainly to Chile from the Austral Basin, accounted for approximately 15% of total gas sold by us from our operations in Argentina in both 2005 and 2004. In light of the energy crises experienced by Argentina in recent periods and for the purpose of securing gas supply for domestic consumption and thermal generation, during 2005 the Secretary of Energy requested producers to redirect export gas to supply thermal plants and gas distribution companies. This decision limited total gas export volumes by an average of about 110 thousand cubic meters per day, which deprived us of the higher margins offered by export prices.

In February 2004, the Argentine government, through Decree No.181/04, mandated the creation of a plan for the recovery of natural gas prices. 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 would culminate in complete deregulation of the wellhead price of natural gas by 2007. Pursuant to the agreement, scheduled increases in gas wellhead prices have been applicable to sales to generation companies, and on a pro rata basis to distributors based on the distributor’s percentage of sales to industrial clients. As from September 1, 2005, gas wellhead prices have been deregulated for sales to electricity generation companies and gas distribution companies supplying industrial clients directly, with the Gas Electronic Market (Mercado Electrónico del Gas) starting operations only for such gas surplus spot transactions. With respect to lower consumption users, including residential consumers, the Secretary of Energy is expected to furnish a price normalization schedule sometime during 2007. We cannot assure you that this process will be completed satisfactorily or in a timely manner.

•

Hydrocarbons

In order to mitigate the impact of the significant rise in the price of WTI on domestic prices and secure price stability for crude oil, gasoline and diesel oil, in January 2003 at the request of the Argentine Executive Branch, hydrocarbon producers and refineries entered into a temporary agreement which provided that crude oil deliveries would be invoiced and paid based on a WTI reference price of U.S.$28.5 per barrel. Any positive or negative difference between the actual WTI price and the reference price, not exceeding U.S.$36 per barrel, would be paid out of any balances generated in the periods in which the actual WTI price fell below U.S.$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 effective until June 2004, which provided that, while the WTI per barrel ranged between U.S.$32 and U.S.$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 U.S.$36 per barrel, or (2) 80% of the WTI, in cases when this price exceeded U.S.$36 per barrel. In August 2004, with the WTI having exceeded the U.S.$42 cap per barrel, the Argentine government established a cap on the domestic price of crude oil equal to the international market price net of export taxes. As from October 2004, hydrocarbon producers and refiners negotiate crude prices based on the export parity reference price.

With a view to discouraging exports and securing domestic supply, on March 1, 2002, the Argentine government imposed, for a five-year term, a 20% tax on exports of crude oil and a 5% tax on exports of certain oil products. In May 2004, the tax on exports of crude oil and LPG 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 25% when the price per barrel is U.S.$32 or lower and applied additional incremental taxes ranging between 3% and 20% when the price per barrel of oil ranges between U.S.$32.01 and U.S.$45, with a cap set at 45% when the price exceeds U.S.$45.

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.

•

Downstream margins

Downstream margins have significantly declined since the enactment of the Public Emergency Law. As part of its effort to control inflation, the Argentine government has limited 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. As a result, the Refining and Distribution business segment gross profit declined 58.4% from 2004 to 2005. The Company’s position as an oil producer allowed it to partially mitigate the distortive effect of these regulations.

The downstream business in Argentina has been and may continue to be subject to extensive regulatory changes that have affected the sector’s prices and profitability, and these changes have had and may continue to have an adverse effect on the results of our operations.

•

Electricity Generation

Following the enactment of the Public Emergency Law, the Argentine government implemented the pesification of dollar-denominated prices in the Wholesale Electricity Market, or WEM, and set a price cap for gas supplied for electric power generation. This had the impact of fixing the price for energy sold in the spot market and causing generators to set prices based on the price of natural gas, regardless of the fuel actually used in generation activities. This regulatory change implied a deviation from the marginal cost system previously applied.

As a result of the Argentine government’s measures, electricity prices have failed to reflect total generation costs adequately. This discrepancy led to the gradual depletion of the Stabilization Fund (Fondo de Estabilización), causing an increasing deficit, which in turn prevented Compañía Administradora del Mercado Eléctrico S.A., or CAMMESA from settling accounts with market agents. In an effort to restore the Stabilization Fund, the Argentine government first made successive contributions to the fund and subsequently reinstated seasonal adjustments for certain periods, recognizing increased costs resulting from the recovery of natural gas prices in the determination of wholesale spot prices.

In order to replenish the Stabilization Fund, the Secretary of Energy created an investment fund called FONINVEMEM. This fund encouraged WEM creditors to participate in investments in electric power generation in order to increase the available supply of electric power generation in Argentina. The Secretary of Energy invited WEM agents to participate in these investments by contributing outstanding credits balances against CAMMESA resulting from the spread between sale prices and generation variable costs, and determined that non-participating agents would only receive payment on any such credits as from the date on which the generators constructed with FONINVEMEM’s resources provide sufficient funds. We will therefore participate with 65% of the credit balances recorded for the 2004-2006 period with respect to this spread. Total credit balances contributed as of December 31, 2005 amounted to P$54 million, of which P$41 million are attributable to the 2005 fiscal year. Our estimated total contribution for the entire 2004-2006 period would amount to U.S.$35 million. The final amount will depend on, among other factors, water conditions, the dispatch of the Company’s generation units determined by CAMMESA and the resulting energy prices.

On October 17, 2005, we, together with other WEM creditors, formally announced our decision to participate in the construction, operation and maintenance of two plants, Termoeléctrica Manuel Belgrano S.A. and Termoeléctrica Jose de San Martín S.A., of at least 800 megawatts each, with gas turbines estimated to start operations in December 2007 and complete combined cycles estimated to become operational in June 2008. After start-up of the power plants, amounts contributed to FONINVEMEN, converted into U.S. dollars and adjusted at a rate of LIBOR plus 1% per year, will be reimbursed in 120 monthly installments. Our interest in combined cycles is estimated at 10%, and will be determined in December 2006, upon payment of the committed contributions mentioned above.

In order to restore the regular operation of the WEM as a competitive market that provides sufficient supply, in December 2004, the Secretary of Energy committed to approving successive seasonal price increases to reach values covering at least total monomic costs by November 2006. In addition, it committed to compensating 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, once the market returns to normal conditions with the start of commercial operation of the additional capacity contributed by FONOINVEMEM. Once this occurs, WEM prices are expected to be determined in the same manner as they were determined prior to the Public Emergency Law and successive resolutions. Once the market returns to normal, the financial situation of WEM’s generation companies is expected to be restored with prices expected at around U.S.$30 per MWh for energy and U.S.$10 per MWh for power capacity, accounting for a significant improvement compared to 2005 (when the price for energy averaged U.S.$17 per MWh and the price for power capacity was U.S.$4 per MWh.)

e) Recoverability of Assets

Tax loss carry forwards: As of December 31, 2003, Petrobras Energía recorded a P$1,397 million allowance on tax loss carry forwards. Considering the Argentine economic situation, the uncertainties related to recovery from the 2002 crisis, and particularly the exposure of the Company’s results to fluctuations in the Argentine economy and actions taken by the Argentine government, the recoverability of such tax loss carry forwards remained uncertain at December 31, 2003.

As of December 31, 2005 and 2004, taking into consideration profitability expectations in connection with Petrobras Energía’s business plan, Petrobras Energía partially reversed this allowance and recorded P$197 million and P$268 million gains in 2005 and 2004, respectively. These reversals were due, among other key factors, to expectations of high and sustained prices for commodities, the recovery of the Argentine economy, the relative stability of and expectations for the main macroeconomic variables in Argentina and measures taken by the Argentine government in connection with the recovery of energy and gas prices. As of December 31, 2005, Petrobras Energía maintained a P$805 million allowance for tax loss carry forwards, which can be primarily used until the fiscal year ending December 31, 2007.

Minimum presumed income tax credit: As of December 31, 2004, Petrobras Energía recorded a P$72 million allowance on credits paid as a minimum presumed income tax from 1998 to 2002, considering the uncertainty with respect to our ability to use amounts paid under alternative minimum tax rules for the reduction of our future income taxes.

The minimum presumed income tax is complementary to the income tax, since, while the latter is levied on the taxable income for the year, the former represents a minimum tax on potential income on certain assets at a 1% rate. Therefore, Petrobras Energía’s tax liability will be the higher of both taxes. However, if the taxpayer’s liability under the minimum presumed income tax exceeds its liability under the income tax for a given year, the amount in excess may be credited against any income tax payment over the minimum presumed income tax during the following ten fiscal years.

As of December 31, 2005, since our management believed that it was highly probable that those payments would be used within the statute of limitations period, the relevant allowance was reversed, accounting for a P$45 million gain (attributable to the discounted value of such payments).

Gas areas in Argentina: In 2005 the Company recorded a P$44 million gain from the reversal of impairment charges on gas areas recorded in 2002 and 2003. The Argentine government’s measures aimed at restoring profitability in the gas business, including the creation of a plan to recover prices by 2007, have improved expectations regarding the future evolution of the gas business.

2) Conversion of Operating Agreements in Venezuela

Operations in Venezuela are an important component of our businesses. As of December 31, 2005, our total combined proved reserves in Venezuela, calculated on the basis of the contractual structure in force as of such date, totaled 269 millions of barrels of oil equivalent, accounting for 35.4% of our total reserves. In 2005, production in Venezuela accounted for approximately 27.9% of our total average production in barrels of oil equivalent. In addition, assets in Venezuela provide a significant percentage of our total free cash flow.

In April 2005, the Venezuelan Energy and Oil Ministry (“MEP”) 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. According to MEP, such operating agreements included clauses that were not in compliance with the Venezuelan Hydrocarbon Law in force, enacted in 2001.

The Venezuelan government instructed PDVSA to take measures in order to convert all effective operating agreements into mixed companies and grant the Venezuelan government more than 50% ownership of each field, through PDVSA. In addition, the MEP instructed PDVSA to limit the total amount of accumulated payments to contractors to no more than 66.67% of the value of oil and gas produced under the related agreement.

During 2005, through different actions, PDVSA exercised pressure on the effective operating agreements as a way to promote migration. Among others:

(a)

PDVSA approved a reduced amount of development investments for the Oritupano Leona area;

(b)

Operators experienced difficulties from PDVSA in delivering production to PDVSA;

(c)

Operators in Venezuela received part of their compensation in local currency (bolivars). In this regard, in June 2005, PDVSA notified Petrobras Energía Venezuela, S.A. that it would thereafter pay in bolivars the portion of the compensation provided in the operation contracts related to the domestic component of the materials and services provided. This decision departs from the stipulations of the operation contracts mentioned above, under which PDVSA is required to make such payments in U.S. dollars. During the transition phase, and until PDVSA performed an audit to determine the portion attributable to the domestic component, PDVSA paid 50% of the operators’ contractual compensation in U.S. dollars and the remaining 50% in bolivars. Subsequently and based on the collections related to 2005 third quarter production, the portion of the contractual compensation payable in bolivars was reduced to 25%;

(d)

The SENIAT (National Integrated Tax Administration Service) performed several tax inspections on the companies that operate the 32 oil operating contracts and, as a result, challenged prior tax filings. As of December 31, 2005, we booked a P$54 million loss; and

(e)

The applicable income tax rate was increased from 34% to 50%.

Petrobras Energía Venezuela S.A signed provisional agreements with PDVSA in September 2005, whereby it agreed to negotiate the terms and conditions of the conversion of the operating agreements and acquiesced to the application of the 66.67% cap on the compensation paid to contractors.

In March 2006, our affiliate in Venezuela entered into memorandum of understanding (“MOUs”) in order to effect the conversion of our investments in operating agreements to minority interests in partially state-owned companies, for the Oritupano Leona, La Concepción, Acema and Mata areas. Pursuant to these agreements, the Venezuelan government will hold a 60% interest in these new companies and private investors will hold the remaining 40%. This will cause our economic interests in the Oritupano Leona, La Concepción, Acema and Mata areas to decline to 22%, 36%, 34.5% and 34.5%, respectively. The economic effects of the conversion were effective April 1, 2006.

The MOUs establish that Corporación Venezolana del Petróleo S.A (CVP) will recognize a divisible and freely transferable credit in favor of PESA in the amount of U.S.$88.5 million. These credits will not bear interest and may be used only for the payment of investments in any new mixed company for the development of oil exploration and production activities in Venezuela or licenses for the development of gas exploration and production operations in Venezuela.

In view of the new contractual framework, as of December 31, 2005, we recognized impairment charges of P$424 million to adjust the book value of our assets in Venezuela to their estimated recoverable value. Of this amount, P$255 million related to property, plant and equipment, P$110 million to deferred tax assets, and P$59 million to non-current investments.

Due to the ownership structure and governance system defined for the mixed companies, we will discontinue the consolidation of our investments in Venezuela in our financial statements as from the date when the relevant mixed companies are organized.

3) Commodity Prices

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 affects the profitability of our operations and capital expenditures”.

In 2005, crude oil prices continued their upward trend, exceeding 2004 historical records. The WTI closed at U.S.$61.1 per barrel, with an average of U.S.$56.6 per barrel during the year (U.S.$43.3 per barrel and U.S.$41.5 per barrel, respectively, in 2004). High prices were sustained both by demand and supply factors. The acceleration in world growth, the tension in the Middle East and the series of adverse weather events that caused oil facilities in the Mexican Gulf to close down, among other factors, led to an escalation of prices with no signs of a rapid decline.

In 2005, styrene international prices remained at high levels boosted by raw material costs, and reflected a high volatility derived from price inbalances among the different regions and weather adversities that affected the producing area at the Mexican Gulf and the southeast of the USA. Within this context, the price spread of styrene against its raw materials increased 29% compared to 2004. Polystyrene international prices followed the benzene trend and recorded high levels. Synthetic rubber price increases resulted from the rise in raw material prices, especially butadiene prices, which rose 40%. In the fertilizer sector, the average international price of urea was 25% higher compared to 2004.

In line with our business integration strategy, our risk management policy is focused on measuring our net risk exposure and monitoring the risks that affect our overall portfolio of assets. Within this policy, the Company’s management regularly evaluates the possibility of using derivative instruments to hedge the exposure to commodity prices. In Argentina, as the Company grows as an integrated energy company and assigns a greater portion of its crude oil production to processing at the Company’s own refineries, we reduce our exposure to fluctuations in the price of crude oil and create a risk profile that is increasingly tied to the price of oil products.

4) Derivative financial instruments

On January 1, 2003, a new set of accounting standards became effective in Argentina 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 Board or IASB, provide that financial derivatives are recorded at their fair value and, as to their balancing item, allow, on a very restrictive basis and in certain cases, the implementation of hedge accounting under which changes in the accounting measurement of such derivatives are recognized under “Transitory differences—Measurement of derivative financial instruments designated as effective hedge,” and are subsequently reclassified to income (loss) for the year or years in which the hedged item affects such results. If the financial derivative instrument is not designated as an effective hedge, changes in the accounting measurement of such derivative are directly recognized in the income statement under “Financial Income (Expense) and Holding Gains (losses)”. For hedge accounting purposes, changes in the derivative’s value, both at its inception and during its life, must offset between 80% and 125% of the opposite changes in the hedged item.

Notwithstanding the objectives behind the relevant derivative contract, under the new accounting pronouncements some of our derivative instruments do not qualify for hedge accounting. Therefore, and in connection with instruments not designated as efficient hedges, a significant asymmetry is shown in the 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 position was fully composed of instruments that did not qualify for hedge accounting. We recognized financial losses attributable to such instruments in the amount of P$295 million, P$688 million, and P$294 million in 2005, 2004 and 2003 respectively. As of December 31, 2003 the accrued portion of hedge instruments represented a lower sales total of P$81 million. As of December 31, 2005, the Company no longer had any crude oil hedging derivative instruments.

5) Oil and gas production in Argentina

Oil and gas production activities in Argentina are mainly developed in mature fields under secondary recovery methods, which are capital-intensive projects. According to official data from the Argentine Oil and Gas Institute, proved oil and natural gas reserves in Argentina have followed a downward trend since 2000. Based on these estimates, oil and gas reserves for 2000-2004 period dropped approximately 24%.

In this context, our oil and gas reserves in Argentina for the 2003-2005 period declined approximately 19%. Along these lines, 2005 oil and gas production decreased approximately 12% compared to 2004.

Our business plan provides for major exploratory investments in Argentina, including offshore exploration opportunities. Due to risks inherent to exploration activities, the Company’s Management cannot assure you that this downward trend in hydrocarbon reserves and oil production in Argentina can be reversed in the future.

6) Investment in Enecor S.A.

In July 2005, the Dirección Provincial de Energía de Corrientes or DPEC (Provincial Energy Agency of Corrientes) resolved not to approve any payment to Enecor S.A. under the electroduct contract and demanded guarantors to render null and void the irrevocable guaranties from time to time granted. Therefore, not only the payment of fees to Enecor S.A., but the guarantees in favor of Enecor S.A. were suspended. As a result, Enecor S.A. demanded the DPEC and the guarantors to pay due and unpaid fees and to abstain from changing the electroduct contract and guarantee scheme. In addition, some actions to protect constitutional rights have been initiated against intervening authorities based on the manifest illegality of their resolutions. On September 21, 2005 the ENRE was required to intervene in its capacity as enforcement authority in connection with the electroduct agreement.

As a consequence of the status of DPEC actions, as mentioned above, and the uncertainty regarding the resolution of such controversy as of December 31, 2005, we booked an allowance in the amount of P$16 million in order to write down the book value of the investment to its probable recoverable value.

7) Operations in Ecuador

Block 31

Block 31 is a developing area with a significant reserve potential. Exploratory works performed in such block were successful and allowed the discovery of important heavy crude oil reserve volumes. Block 31 is mostly located in the Yasuní National Park, a highly ecologically sensitive area in the Amazon region of Ecuador (an area included in the National Heritage of Natural Areas and Protective Woods and Vegetation).

In 2000, as a result of the successful drilling of two exploratory wells, heavy crude oil reserves were discovered. The significant volume of reserves would have allowed to complete the wells and turn them into producing wells, as long as significant infrastructure investments were made, such us oil pipelines and facilities. Accordingly, in 2001, Oleoducto de Crudos Pesados S.A. (OCP) began to build an oil pipeline to transport production. The oil pipeline started operations late in 2003. Reductions made to the Company’s 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 area’s reserve potential. 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 accordance with SFAS 19 guidelines, we charged to expenses P$106 million of previously capitalized exploratory costs in connection with the drilling of the first two wells, while exploratory costs for wells where less than one year had elapsed since the completion of drilling were capitalized, as set forth in such guidelines. In 2004, as one year had elapsed since the completion of drilling, we charged to income P$80 million of these exploratory costs.

In August 2004, the Ecuadorian Ministry of the Environment approved the Environmental Management Plan in connection with the Project for the Development and Production of Block 31 and granted an environmental license in connection with the Nenke and Apaika fields for the construction stage of the project. In addition, in August 2004, the Ministry of Energy and Mines approved the development plan for Block 31, representing the start of the 20-year exploitation term.

Native and environmental groups have made public statements against the Block 31 development, arguing that the oil activity endangers the park’s biodiversity.

On July 7, 2005, the Ministry of the Environment decided not to authorize the beginning of certain construction works on the Tiputini River (boundary of Parque Nacional Yasuní), and denied us entry to Parque Nacional Yasuní. This suspension prevents us from continuing our development works in Block 31. In May 2006, we presented a new work proposal to the Ministry of the Environment in order to address its concerns on these issues, and the proposal is currently under evaluation by the Ministry of Energy and Mines and the Ministry of the Environment.

Crude oil transportation agreement with Oleoductos de Crudos Pesados Ltd. (OCP)

Regarding the exploitation of Blocks 18 and 31, we have an agreement with OCP, whereby an oil transportation capacity of 80,000 barrels per day is secured for a 15-year term, starting November 10, 2003. Under the “ship or pay” transportation agreement clause, we must fulfill our ship or pay contractual obligations for the aggregate oil volume committed, even though no crude oil is transported, and pay, as well as all other producers, a fee covering OCP operating costs and financial services. As of December 31, 2005, this fee amounted to U.S.$2.26 per barrel. Costs in connection with the transportation capacity are invoiced by OCP and charged to expenses on a monthly basis. In such respect, costs in connection with crude oil volumes actually transported are recorded under “Administrative and Selling Expenses,”while the portion attributable to the committed and unused transportation capacity is recorded under “Other operating income (expense)”.

We expect that during the effective term of the transportation agreement, oil production will be lower than the aggregate transportation capacity committed. This expectation is based on: (i) estimated delays in the development of Block 31 and (ii) the current vision of reserve potentiality in Block 31. Considering this situation, starting in July 2004 and through the termination of the agreement with OCP, the Company sold approximately 8,000 barrels a day. The impact of the net deficit is considered for the purpose of analyzing the recoverability of assets located in Ecuador. As of December 31, 2005, we maintained a P$330 million allowance in connection with assets in Ecuador. In this regard, in 2003, we recorded a P$309 million impairment loss.

Tax credits derived from operations

We as well as other companies engaged in oil production and export activities in Ecuador, maintain tax credits with the Ecuadorian Tax Authority (SRI) with respect to value added taxes to be refunded at the time of oil export. As of December 31, 2005, the Company’s VAT credits amounted to P$78 million.

The SRI informed us that this tax credit would not be refunded, because these value added taxes were considered at the time of determining the sharing of oil production between the government and producers. This disagreement was challenged in the Tax Court. As of the date of this annual report, no resolution has yet been issued.

In our counsel’s opinion, the Company is entitled to this refund, whether it be by the SRI or by renegotiating its share of oil production, since the export of goods and the rendering of services were not within the scope of the VAT at the time of determining the Company’s oil production share. We intend to protect our rights vigorously, but have, nonetheless, and without waiving any of our rights, recorded an impairment allowance for the amount of the credits as of December 31, 2005.

Preliminary agreement with Teikoku Oil Co Ltd. – Teikoku

Until reaching such production level, only with effect among the parties and subject to the terms and conditions mentioned above, Teikoku will assume 20% of our rights and obligations resulting from the agreement, as from July 1, 2006. In addition to the abovementioned, and only with effect among the parties and subject to the agreed upon conditions, Teikoku will also assume an additional 20% of our rights and obligations resulting from the agreement and which will be effective for the shorter of the following periods: (a) July 1, 2006 until Block 31 reaches the aforementioned production level, or (b) the consecutive 18 months prior to such production level.

8) 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 U.S.$97 million in Lote X during the 2004-2011 period. The Peruvian government, in turn, reduced the royalties percentage it receives for hydrocarbon production. Works initially contemplated in this agreement include drilling of 51 wells, workover of 525 wells, reactivation of 177 temporarily abandoned wells, and the implementation and expansion of a water injection project.

In light of this agreement, our economic projections in connection with operations in Peru have improved. As a result, in 2004 Petrobras Energía Perú S.A. 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. As a result of the investments made, in 2005 our production of oil equivalent in Perú increased 12%.

9) Operations in Bolivia

The new Hydrocarbons Law No. 3058, effective May 19, 2005, abrogates former Hydrocarbons Law No. 1689 enacted on April 30, 1996.

This Law provides, among other things, increased taxes for companies in this sector by means of a 18% royalty percentage and a 32% Direct Tax on Hydrocarbons (DTH) directly applicable on 100% of production. Such taxes are in addition to the taxes in force under Law No. 843.

In May 2006, the Bolivian government established the so-called “hydrocarbon nationalization” under Supreme Decree No. 28,701. This Decree provides that as from May 1, 2006 oil companies will have to deliver to YPFB the property of all hydrocarbon production for sale. Oil companies will have a 180-day transition term to subscribe the new agreements, which will be individually authorized and approved by the Bolivian Legislature. The Ministry of Hydrocarbons and Mines will determine, on a case by case basis, the interest corresponding to oil companies by means of investment audits, operational costs and profitability indicators. The current distribution of the oil and gas production value will be maintained during the transition period, in the case of fields, such as the Colpa Caranda Field, that had certified average production of natural gas for 2005 lower than 100 million cubic feet per day. In addition, the abovementioned decree provides, among other things, that the Bolivian government shall recover full participation in the entire oil and gas production chain, and for this purpose provides for the nationalization of the shares of stock necessary for YPFB to have at least 50% plus one of the shares in a number of companies, among which is PBR. Due to the fact that the abovementioned decree has recently been issued and that several instrumentation and application procedures, including the restructuring of YPFB, we are analyzing the effects of the abovementioned decree on our operations.

Our net assets in Bolivia total P$221 million, comprised by our interest in the Colpa Caranda area (P$44 million) and our 49% interest in Petrobras Bolivia Refinación (P$177 million).

10) Tax benefits regarding Innova operations – FUNDOPEM

We, through Innova’s operations in Brazil, enjoy a tax benefit pursuant to an incentive program granted by the Rio Grande do Sul State, in Brazil, for companies located in that state. The benefit consists of a 60% reduction of the ICMS (interstate goods transport tax) until 2007.

Under this program, we recorded P$42 million and P$27 million gains in 2005 and 2004, respectively.

In 2006, Innova will start construction of a new ethylbenzene plant. This new plant is expected to meet the legal requirements necessary to qualify for the tax benefit.

11) Environmental matters

Liabilities for future environmental remediation costs are recorded when environmental assessment is probable and costs of remediation can be reasonably estimated.

Remediation liabilities are determined on the basis of our best estimate of future costs, using available technology and applying environmental protection rules and regulations in force, as well as our own environmental protection policies. Actual remediation costs may differ from previously estimated liabilities as a result of a number of factors, including changes in environmental laws and regulations or in available technology and increased knowledge of applicable conditions.

In 2005, 2004 and 2003 environmental remediation costs charged to income totaled P$29 million, P$51 million and P$58 million, respectively.

12) Changes in professional accounting standards

On August 10, 2005, the Board of the Professional Council in Economic Sciences of the City of Buenos Aires (CPCECABA) approved Resolution CD No. 93/2005, which introduced a series of changes to professional accounting standards. Through General Resolutions Nos. 485 and 487 dated December 29, 2005 and January 26, 2006, the CNV approved the abovementioned changes, which are effective for fiscal years beginning as from January 1, 2006.

The effects of these changes, which should adjust retroactively the beginning balance of the shareholders’ equity item as of January 1, 2006, are described below:


	(unaudited)
Comparison with recoverable values (i)	(143	)
Deferred tax (ii)	(804	)

Total effect on unappropriated retained earnings	(947	)

Deferred results (iii)	(22	)

Total effect on Shareholders’ equity	(969	)

The changes that could significantly impact our financial statements are described below:

(i)

In calculating the recoverability of Property, Plant & Equipment and certain intangible assets, the recoverable value is considered to be the higher of the net realizable value and the discounted value of the expected cash flows, eliminating the comparison with the nominal value of expected cash flows.

(ii)

The difference between the inflation-adjusted book value of Property, Plant & Equipment and other non-monetary assets and their tax basis is considered to be a temporary difference that gives rise to the recognition of a deferred liability, which – as provided by CNV General Resolution No. 487 – can either be booked or disclosed in notes to financial statements. The Company Management opted to book this effect in accordance with international financial reporting standards (IFRS).

(iii)

The effects of the measurement of the derivative instruments considered to be an effective hedge and the effects of the translation of foreign operations net of the foreign-exchange differences generated by the debt denominated in foreign currency designated as hedge for net investment abroad are no longer disclosed as an item between liabilities and shareholders’ equity (“mezzanine account”) and, instead, are disclosed in shareholders’ equity.

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, 2005, 2004 and 2003, 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. Intersegment transactions are made at market prices.

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,
	2005		2004		2003
	(in millions of pesos)
Net Sales:⁽¹⁾
Oil and Gas Exploration and Production	4,657		3,647		2,989
Refining and Distribution	3,856		3,359		2,702
Petrochemicals	2,178		1,877		1,294
Gas and Energy	2,136		1,804		1,212
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(2,172	)	(1,924	)	(1,084	)

Total	10,655		8,763		7,113

Gross Profit:⁽³⁾
Oil and Gas Exploration and Production	2,623		1,900		1,389
Refining and Distribution	107		257		261
Petrochemicals	377		374		312
Gas and Energy	530		465		408
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(40	)	(24	)	(16	)

Total	3,597		2,972		2,354

Operating Income:
Oil and Gas Exploration and Production	2,027		1,260		786
Refining and Distribution	(149	)	10		(2	)
Petrochemicals	267		278		185
Gas and Energy	450		378		317
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(302	)	(258	)	(185	)

Total	2,293		1,668		1,101

⁽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.

Without Proportional Consolidation


	For the year ended, December 31,
	2005		2004		2003
	(in millions of pesos)
Net Sales:⁽¹⁾
Oil and Gas Exploration and Production	4,657		3,647		2,989
Refining and Distribution	3,856		3,359		2,702
Petrochemicals	2,178		1,877		1,294
Gas and Energy	972		784		319
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(2,151	)	(1,911	)	(1,070	)

Total	9,512		7,756		6,234

Gross Profit:⁽³⁾
Oil and Gas Exploration and Production	2,623		1,900		1,389
Refining and Distribution	107		257		261
Petrochemicals	377		374		312
Gas and Energy	190		129		98
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(40	)	(27	)	(16	)

Total	3,257		2,633		2,044

Operating Income:
Oil and Gas Exploration and Production	2,027		1,260		786
Refining and Distribution	(149	)	10		(2	)
Petrochemicals	267		278		185
Gas and Energy	209		149		119
Corporate and Other Discontinued Investments and Eliminations⁽²⁾	(302	)	(258	)	(185	)

Total	2,052		1,439		903

⁽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.

Year ended December 31, 2005 compared to year ended December 31, 2004

Net income: Net income decreased P$65 million, or 9.6%, to P$613 million in 2005 from P$678 million in 2004.

Operations for the year were developed within a favorable international context characterized by high prices of crude oil and its principal by-products, and as a result our operating income increased significantly.

However, the estimated significant negative effects resulting from the migration of operating agreements in Venezuela had a strong impact on the results for the year and offset the operating income improvement. In addition, the increase in the income tax charge, which in 2004 was offset against the allowance provided for tax loss carry forwards, had a negative impact on our results.

Conversely, the reduced position of derivative instruments that do not qualify for hedge accounting resulted in a significant reduction in related losses.

Net sales: Net sales increased P$1,892 million, or 21.6%, to P$10,655 million in 2005 from P$8,763 million in 2004. Sales for 2005 include P$513 million and P$651 million attributable to our share of the net sales (net of intercompany sales of P$21 million) of CIESA and Distrilec, respectively. Net sales for 2004 include P$485 million and P$535 million, attributable to our share of the net sales (net of intercompany sales of P$13 million) of CIESA and Distrilec, respectively.

100

Without proportional consolidation, net sales increased P$1,756 million, or 22.6%, to P$9,512 million in 2005 from P$7,756 million in 2004, boosted by the significant increase in the WTI and in the price for the main petrochemical and refined products. Sales in the Oil and Gas Exploration and Production, Petrochemicals and Refining and Distribution business segments (including intercompany sales) increased P$1,010 million (27.7%), P$301 million (16%) and P$497 million (14.8%), respectively. Intercompany sales increased to P$2,172 million in 2005 from P$1,924 million in 2004. Most of these sales were attributable to the Oil and Gas Exploration and Production and the Refining and Distribution business segments.

Gross profit: Gross profit increased P$625 million, or 21%, to P$3,597 million in 2005 from P$2,972 million in 2004. Gross profit for 2005 includes P$243 million and P$97 million attributable to our share of the gross profit of CIESA and Distrilec, respectively. Gross profit for 2004 includes 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.

Without proportional consolidation, gross profit increased P$624 million, or 23.7%, to P$3,257 million in 2005 from P$2,633 million in 2004. This increase mainly stemmed from a rise in gross profit from the Oil and Gas Exploration and Production (P$723 million) and Electricity (P$52 million) business segments, partially offset by a decline of P$150 million in gross profit from the Refining and Distribution segment. See “Analysis of Operating Income”.

Administrative and selling expenses: Administrative and selling expenses increased P$94 million, or 11.1%, to P$941 million in 2005 from P$847 million in 2004. Administrative and selling expenses for 2005 include P$18 million and P$73 million attributable to our share of the administrative and selling expenses of CIESA and Distrilec, respectively. Administrative and selling expenses for 2004 include P$16 million and P$66 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$85 million, or 11.1%, to P$850 million in 2005 from P$765 million in 2004. See “Analysis of Operating Results by Business Segment”.

Exploration expenses: Exploration expenses decreased P$99 million to P$34 million in 2005 from P$133 million in 2004. See “Analysis of Operating Income – Oil and Gas Exploration and Production”.

Other operating income (expense), net: Other operating income (expense), net accounted for P$329 million losses in 2005 compared to P$324 million losses in 2004. Other operating income (expense), net for 2005 includes losses of P$3 million and P$5 million, attributable to our share of other operating income (expense), net of CIESA and Distrilec, respectively. Other operating income (expense), net for 2004 includes losses of P$19 million and P$6 million, attributable to our share of other operating income (expense), net of CIESA and Distrilec, respectively, and P$3 million in eliminations.

Without proportional consolidation, other operating income (expense), net accounted for losses of P$321 million in 2005 and P$296 million in 2004, which were principally attributable to losses recorded by our Oil and Gas Exploration and Production business segment. See “Analysis of Operating Results by Business Segment”.

Operating income: Operating income grew P$625 million, or 37.5%, to P$2,293 million in 2005 from P$1,668 million in 2004. Operating income for 2005 includes P$222 million and P$19 million attributable to our share of the operating income of CIESA and Distrilec, respectively. Operating income for 2004 includes P$215 million and P$14 million attributable to our share of operating income of CIESA and Distrilec, respectively.

Without proportional consolidation, operating income increased P$613 million, or 42.6%, to P$2,052 million in 2005 from P$1,439 million in 2004. This increase mainly derived from the rise in gross profit in the Oil and Gas Exploration and Production segment. See “Analysis of Operating Results by Business Segment – Figures without proportional consolidation – Exploitation Income.”

101

Equity in earnings of affiliates: Equity in earnings of affiliates increased P$90 million, or 118.4%, to P$166 million in 2005 from P$76 million in 2004. Without proportional consolidation, equity in earnings of affiliates increased P$103 million, or 130.4%, to P$182 million in 2005 from P$79 million in 2004. This increase basically derived from improvements in the results of Citelec, CIESA and PBR, which were partially offset by impairment charges recognized by affiliates in Venezuela in connection with the migration process of operating agreements.

For a discussion of our equity in the earnings of companies over which we exercise joint control in 2005 and 2004, and the factors that affected these companies’ results see “—Equity in Earnings of Affiliates and Companies under Joint Control”.

Financial income (expense) and holding gains (losses): Financial income (expense) and holding gains (losses) decreased P$366 million, or 28.9%, to P$899 million in 2005 from P$1,265 million in 2004. Losses for 2005 include financial expenses of P$128 million and P$19 million, attributable to our share of the financial income (expense) and holding gains (losses) of CIESA and Distrilec, respectively. Losses for 2004 include financial expenses of P$144 million and P$20 million, attributable to our 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$752 million in 2005 and P$1,101 million in 2004. The decrease was primarily attributable to the decline in losses from derivative instruments used to hedge the price of crude oil to P$295 million in 2005 from P$687 million in 2004, as a consequence of: (a) a lower volume of our crude oil sales covered by these instruments, and (b) a lower increase in the future curve of oil prices, a 30.4% increase in 2005 compared to a 53.9% increase in 2004.

Conversely, results from the sale of securities in 2005 resulted in a P$4 million loss compared to a P$103 million gain in 2004, mainly on account of the changes implemented by PDVSA in the payment of the compensation under the operating agreements. Interest expense increased by 1.9% to P$479 million in 2005 from P$470 million in 2004, consistent with the impact on our U.S. dollar-denominated indebtedness of the decline in the value of the peso against the U.S. dollar. Our average indebtedness in terms of U.S. dollars fell 5%.

Other expenses, net: Other expenses, net were P$332 million in 2005 and P$40 million in 2004. Other expenses, net include a P$11 million loss in 2005 attributable to our share of other expenses, net of Distrilec, whereas they include a P$14 million loss in 2004 attributable to our share of other expenses, net of CIESA and a P$7 million gain attributable to our share of other expenses, net of Distrilec.

In 2005 and 2004, without proportional consolidation, other expenses, net accounted for P$321 million and P$33 million losses, respectively.

Other expenses, net for 2005 mainly reflect:

•

a P$255 million impairment charge on assets in Venezuela.

•

a P$55 million allowance on loans granted to joint venture partners in Venezuela.

•

a P$16 million impairment charge on our interest in Enecor S.A.

•

a P$54 million assessment by SENIAT – Venezuela.

•

a P$44 million gain from the reversal of an impairment charge on the Río Neuquén gas area.

Other expenses, net for 2004 mainly reflect:

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a P$12 million impairment charge on the Acema area in Venezuela.

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a P$15 million allowance on loans granted to joint venture partners in Venezuela.

Income Tax: Income tax accounted for a loss of P$381 million in 2005 compared to a gain of P$211 million in 2004. The income tax charge for 2005 includes losses of P$10 million and P$16 million attributable to our share of the income tax of CIESA and Distrilec, respectively. The income tax charge for 2004 includes losses of P$6 million and P$20 million attributable to our share of the income tax of CIESA and Distrilec, respectively.

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Without proportional consolidation, income tax accounted for a loss of P$355 million in 2005 compared to a gain of P$237 million in 2004.

Our income tax expense for 2005 includes:

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a P$197 million gain from the reversal of previously created allowances on Petrobras Energía’s loss carry forwards;

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a P$45 million gain from the reversal of previously created allowances on tax credits recorded with respect to minimum presumed income taxes in Argentina between 1998 and 2002; and

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a P$110 million impairment charge on deferred tax assets in Venezuela.

Our income taxes in 2004 include a P$299 million gain from the reversal of previously created allowances on tax loss carry forwards of Petrobras Energía and Petrobras Energía Perú .

In addition to the effects mentioned above, income tax charge for 2005 increased to P$487 million compared to P$62 million in 2004, mainly due to: (1) in 2004 tax expense attributable to Petrobras Energía S.A. was offset against tax loss carry forwards, (2) the rise in the income tax rate in Venezuela (from 34% to 50%) and (3) improved results of operations in Ecuador and Peru.

ANALYSIS OF OPERATING RESULTS BY BUSINESS SEGMENT

Oil and Gas Exploration and Production

Operating income: Operating income for the Oil and Gas Exploration and Production business segment increased P$767 million, or 60.9%, to P$2,027 million in 2005 from P$1,260 million in 2004. This increase was predominately due to a 34.7% rise in average sales prices of oil equivalent resulting from (i) a 36.5% increase in the WTI, and (ii) the accrual of the additional incentive compensation provided for in the operating agreements of the Oritupano Leona area in Venezuela, net of the 66.67% limit imposed by the Venezuelan government, which accounted for additional sales in the amount of P$284 million.

Net sales: Net sales for this business segment increased P$1,010 million, or 27.7%, to P$4,657 million in 2005 from P$3,647 million in 2004. This increase was predominately due to a 34.7% rise in the average sales price of oil equivalent, which was partially offset by a 5% reduction in sales volumes of oil equivalent.

In 2005, daily oil and gas sales volumes decreased to 170.9 thousand barrels of oil equivalent from 179.9 thousand barrels of oil equivalent in 2004. Oil sales volumes dropped 2.5% to 120.8 thousand barrels per day in 2005 from 123.9 thousand barrels per day in 2004, while daily gas volumes fell 10.8%, totaling 300 million cubic feet in 2005 and 336.2 million cubic feet in 2004.

Net sales in Argentina

Net sales in Argentina increased P$138 million, or 6.7%, to P$2,182 million in 2005 from P$2,044 million in 2004.

Combined oil and gas daily sales volumes decreased 10.3% to 91.7 thousand barrels of oil equivalent in 2005 from 102.2 thousand barrels of oil equivalent in 2004. This decrease was mainly attributable to the considerable natural decline of oilfields in Argentina, which are mature fields under production through secondary recovery. We made significant investments in our Argentine oilfields, basically to improve the oilfields’ basic production curves, which allowed us to partially mitigate the curves’ decline.

Crude oil sales increased P$94 million, or 5.1%, to P$1,944 million in 2005 from P$1,850 million in 2004. This increase was attributable to a 15.2% increase in the average sales price, to P$99.9 per barrel in 2005 from P$86.7 per barrel in 2004. We were not able to fully benefit from increases in international crude oil prices as a result of applicable export taxes in Argentina and the use of the export parity price as a reference to establish domestic sales prices to downstream operators in line with the Argentine government’s efforts to stabilize prices in the domestic fuel markets. Daily sales volumes of crude oil dropped 8.7% to 53.2 thousand barrels in 2005 from 58.3 thousand barrels in 2004.

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Total gas sales increased P$38 million, or 19.7%, to P$232 million in 2005 from P$194 million in 2004, mainly as a result of a 36.6% rise in the average sales price, which was partially offset by a 12.1% decline in daily sales volumes. The average sales price for gas increased to P$2.74 per million cubic feet in 2005 from P$2.01 per million cubic feet in 2004, mainly as a consequence of scheduled price increases in line with the May 2004 agreement with the Secretary of Energy, higher export prices for methanol and the renegotiation of contracts with industrial clients. Daily gas sales volumes fell to 231.7 million cubic feet in 2005 from 263.7 million cubic feet in 2004.

Net sales outside of Argentina

Combined oil and gas sales outside of Argentina increased P$875 million, or 55.1%, to P$2,462 million in 2005 from P$1,587 million in 2004. Total daily oil and gas sales volumes increased by 1.4% to 78.8 thousand barrels of oil equivalent in 2005 from 77.7 thousand barrels of oil equivalent. The average sales price per barrel of oil equivalent increased 53.1% to P$85.4 from P$55.8.

Net Sales in Venezuela

In Venezuela, oil and gas sales grew P$364 million, or 44.9%, to P$1,175 million in 2005 from P$811 million in 2004. In 2005, the average price per barrel of oil grew 55.3% to P$72.2 from P$46.5. This increase was predominately attributable to the increase in the WTI and the accrual of additional compensation under the operating agreement for the Oritupano Leona area. Accumulated production at the Oritupano Leona oilfield during 2005 first quarter exceeded 155 million barrels, which triggered the application of additional incentive compensation to any incremental production. This additional compensation was subsequently limited by the application of a 66.67% cap on total compensation based on sales prices imposed by the Venezuelan government under the provisional agreements relating to the migration to partially-state owned companies. Considering this limit, this incentive compensation accounted for additional sales in the amount of P$284 million.

Daily sales volumes of oil equivalent dropped to 47.6 thousand barrels of oil equivalent, or 7.2%, in 2005 from 51.3 thousand barrels of oil equivalent in 2004 mainly as a consequence of the significant cuts in the investment plan for the Oritupano Leona area established by PDVSA at the time of approval of the 2005 fiscal year budget. Since fields in the Oritupano Leona area are mature fields, the reduced investments did not allow us to revert the oilfields’ natural decline.

In March 31, 2006, we, PDVSA and CVP, entered into MOUs in order to effect migration of the Oritupano Leona, La Concepción, Acema and Mata areas to mixed ownership companies. (See “Conversion of Operating Agreements in Venezuela”).

Net Sales in Ecuador

In Ecuador, oil sales increased 113.4% to P$446 million in 2005 from P$209 million in 2004, reflecting increased volumes and higher sales prices. Daily oil sales volumes rose to 9.5 thousand barrels in 2005, or 63.8%. Oil sales in 2005 include the sale of 202.7 thousand barrels attributable to December 2004 production, which was postponed to January 2005 for commercial reasons. Without considering these sales, daily sales volumes increased to 8.9 thousand barrels or 40.7%. This improvement was mainly attributable to the progressive development of Block 18, in line with investments. Investments during 2005 included drilling of eleven wells and different workovers.

Average sales price increased 30.6% to P$129.4 per barrel in 2005 from P$99.1 per barrel in 2004 mainly due to the rise in the international reference price (Oriente crude oil). The increase in the Oriente crude oil reference price was lower than that of the WTI due to an increased discount for this type of crude oil.

Net Sales in Peru

In Peru, oil and gas sales increased P$247 million or 53.9% to P$705 million in 2005 from P$458 million in 2004, mainly as a result of a 36.9% increase in the average sales price of oil equivalent and a 12.4% rise in sales volumes of oil equivalent.

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Average crude oil price increased 40.3% to P$147.9 per barrel from P$105.4 per barrel boosted by a 39% increase in the international reference price (a combination of Oriente crude oil and WTI). Average gas price decreased by 4.3% to P$4.9 from P$5.12 per million cubic feet, as a consequence of the increase in gas supply resulting from the entry into the gas market of the Camisea field, which is the most important gas reserve in Peru and one of the largest gas reserves in Latin America.

Daily sales volumes of oil equivalent increased to 14.5 thousand barrels in 2005 from 12.9 thousand barrels in 2004. This improvement was driven by the drilling of 30 producing wells and performance of 15 primary and secondary repair works.

Net Sales in Bolivia

In Bolivia, oil and gas sales increased to P$136 million in 2005 from P$108 million in 2004. Combined oil and gas daily sales volumes dropped 4.3% to 7.4 thousand barrels of oil equivalent due to reduced gas deliveries to Brazil.

Average sales price for gas increased 40.9% to P$7.37 per million cubic feet in 2005 from P$5.23 per million cubic feet in 2004. This improvement was mainly attributable to the rise in fuel oil price, which is included in the formula for calculation of the price for exports to Brazil.

Net Sales in Mexico

In 2005, sales for other services increased to P$12 million, or 20%, compared to P$10 million in 2004.

Gross Profit: Gross profit for this business segment increased P$723 million, or 38.1%, to P$2,623 million in 2005 from P$1,900 million in 2004. Margin on sales rose to 56.3% from 52.1%. This improvement was mainly attributable to the increase in average sales prices of oil equivalent. Average lifting costs rose 26.4% to P$11 per barrel of oil equivalent in 2005 from P$8.7 per barrel of oil equivalent in 2004, predominately as a consequence of the increases in cost of services and electricity and to incremental costs associated with the implementation of new safety and environmental standards.

Administrative and selling expenses: Administrative and selling expenses rose P$27 million, or 12.2%, to P$248 million in 2005 from P$221 million in 2004. This increase was mainly attributable to increases in the cost of crude oil transportation derived from the rise in sales volumes and in transportation applicable rates in Ecuador and, to a lesser extent, in labor costs.

Exploration expenses: Exploration expenses totaled P$34 million in 2005 and P$133 million in 2004. Expenses for 2005 were mainly attributable to 3D seismic works at the Austral and Neuquén basins. In 2004, the Company charged to income exploratory investments in the amount of P$80 million for Block 31 in Ecuador and in the amount of P$41 million for the Aguaragüe and Puesto Zuñiga areas in Argentina.

Other operating income (expense), net: Other operating income (expense), net accounted for losses of P$314 million in 2005 and P$286 million in 2004. Losses for 2005 was were mainly attributable to costs associated with the unused transportation capacity under the ship or pay contract with OCP in Ecuador (P$184 million), an allowance for tax credits in Ecuador relating to VAT (P$78 million) and environmental remediation expenses (P$27 million). In 2004, other operating income (expense), net mainly reflects costs associated with the unused transportation capacity under the ship or pay contract with OCP (P$184 million), environmental remediation expenses (P$51 million), project discontinuance (P$5 million) and losses derived from contract renegotiation (P$10 million).

Refining and Distribution

Operating income: Operating income for the Refining and Distribution business segment reflected a loss of P$149 million in 2005, compared to a P$10 million gain in 2004.

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Our operating income in the Refining and Distribution business segment during 2005 was affected by a 17% increase in the cost of crude oil. In such respect, the oil export tax regime helped us to partially mitigate the increase in the international WTI price. Given government measures to control inflation, we were not able to increase gasoline and diesel oil domestic prices in order to fully offset the increased cost of crude oil.

In addition, this segment’s gross profit was affected by negative margins on imports of diesel oil made to meet a growing domestic demand and due to production deficits derived from the scheduled shutdown for maintenance works at the refineries. Notwithstanding provisional tax exemptions on imports of diesel oil and liquid fuels the sale of diesel oil imports resulted in significant negative import margins due to the combined effect of increases in international import prices and domestic sale price controls.

During 2005, diesel oil imports dropped to 272 thousand cubic meters from 322 thousand cubic meters in 2004. However, due to the increase in international prices, losses on the sale of imported diesel oil rose to P$82 million in 2005 from P$21 million in 2004.

Net sales: Net sales for refinery products increased P$497 million, or 14.8%, to P$3,856 million in 2005 from P$3,359 million, mainly due to an increase in sales prices of products not subject to price control measures. Total sales volumes increased 2.6%, with an 8% rise in domestic sales, partially offset by a reduction in exports.

In line with the significant 36.5% rise in the price of WTI, average sales prices of bunker diesel oil, heavy distillates, asphalts, paraffins and reformer plant by-products, improved 63%, 47%, 35%, 26% and 15%, respectively.

Crude oil volumes processed at the refineries in 2005 and 2004 were at similar levels, averaging 62.9 thousand barrels per day and 63.1 thousand barrels per day, respectively.

Total diesel oil sales volumes declined 2.6% to 1,741 thousand cubic meters in 2005, mainly due to a drop in export volumes, which was partially offset by increased sales in the domestic market. The reduction in export volumes was mainly attributable to changes in policies as from the merger of Petrobras Energía’s operations with those of EG3. In 2004, prior to the full integration of operations, surplus production from our San Lorenzo refinery was sold in the export market, while EG3 purchased from third parties any diesel oil needs that were not satisfied by production at its Bahía Blanca refinery. Although our domestic sales increased 4%, the combined effect of the reduction in diesel oil imports and a 7.5% increase in the domestic market for diesel oil resulted in a slight decline in our market share to 14.2% in 2005 from 14.6% in 2004.

Total gasoline sales volumes rose 3.8% to 715 thousand cubic meters in 2005, mainly due to a 7.4% increase in domestic sales. During 2005, the domestic market for gasoline increased by 8.9%. Within this context, our market share was 14.5% in 2005 and 14.7% in 2004. In the premium gasoline market, in which we participate with Podium gasoline, our market share improved from 7.8% in 2004 to 9.7% in 2005.

Asphalt sales volumes grew 23.2% in 2005, mainly as a result of increased demand resulting from a program of infrastructure works performed by the government, mainly in the south of the country. Within this context, domestic market sales grew 31%, while exports declined 10%.

As regards heavy distillates, sales volumes for 2005 and 2004 were at similar levels. Sales volumes of reformer plant by-products rose 36%, principally due to 91% and 34% increases in domestic market sales of LPG and hexane, respectively, and a 48% rise in exports of paraffin varieties.

Gross profit: Gross profit for 2005 declined P$150 million, or 58.4%, to P$107 million from P$257 million in 2004. Gross margin on sales declined to 2.8% from 7.7% in 2004. Gross margin was adversely affected by price control measures that prevented us to pass through crude oil increases to market prices and by losses on the resale of diesel oil imports. Crude oil cost increased 16.9% to P$111.5 barrels per day from P$95.4 barrels per day.

Administrative and selling expenses: Administrative and selling expenses increased 2.9% to P$251 million in 2005 from P$244 million in 2004, mainly due to a rise in transportation and shipment costs.

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Other operating income (expense), net: Other operating income (expense), net recorded losses of P$5 million in 2005 and P$3 million in 2004.

Petrochemicals

Operating income: Operating income for the Petrochemical business segment dropped P$11 million, or 3.9%, to P$267 million in 2005 from P$278 million in 2004.

Net sales: Net sales (net of eliminations in the amount of P$170 million and P$39 million for intersegment sales) increased P$301 million, or 16%, to P$2,178 million in 2005 from P$1,877 million in 2004, due to increased styrenics sales volumes, both in Argentina and Brazil, and to higher sales prices in line with increases in the respective international reference prices.

Net Sales of Styrenics - Argentina

In Argentina, styrenics sales increased P$218 million, or 32.7%, to P$884 million in 2005 from P$666 million in 2004 due to the combined effect of an 18% increase in sales volumes and a 13% improvement in average sales prices. These amounts include exports to Innova in the amount of P$136 million and P$39 million, respectively. The start-up of the ethylene plant in October 2004 allowed the segment to increase production at the ethylbenzene plant, which allowed us to make full use of the installed capacity at the Puerto General San Martín plant in Argentina and the Innova plant in Brazil.

In 2005, in line with the rise in international reference prices, average sales prices for this business segment improved 13% compared to 2004, with increases of 10%, 8% and 34% for the styrene, polystyrene and synthetic rubber lines, respectively.

Styrenics performance was as follows:

a) Styrene monomer sales volumes increased approximately 9%, to 46 thousand tons, with a 30% rise in export volumes. In 2005, due to interruptions in production at the polystyrene plant, a styrene surplus was recorded, which was mainly sold to export markets.

b) Polystyrene and bops sales volumes climbed to 65 thousand tons or 3% in 2005, with similar percentage increases both in domestic sales and exports. Although a 7% reduction in polystyrene production volumes was recorded as a consequence of trade union conflicts at the Zarate plant, the demand was satisfied by imports from Innova.

c) Ethylbenzene sales volumes, as from the start of operations of the ethylene plant during the fourth quarter of 2004, totaled 43 thousand tons in 2005 and 9.5 thousand tons of 2004.

d) Synthetic rubber sales volumes decreased to 52.6 thousand tons, or 13%, compared to 2004, mainly due to a 23% drop in export volumes. This drop resulted from the combined effect of increased supply at the international level, a drop in regional market activity and high levels of customer inventories at the end of 2004.

Net Sales of Styrenics - Brazil - Innova

Innova sales increased P$199 million, or 25.7%, to P$972 million in 2005 from P$773 million in 2004, due to the combined effect of a 20% improvement in average sales prices and a 5% rise in sales volumes.

In 2005, styrene and polystyrene prices rose 20% and 19%, respectively, as a consequence of an increase in international reference prices.

Styrene sales volumes rose 18% mainly due to a reduction in stock and to a lesser extent, due to a slight increase in production, resulting from the lighter availability of ethylbenzene imported from Argentina operations. These higher sales were directly mainly to exports to Argentina. Conversely, polystyrene sales volumes decreased 8% due to lower domestic sales (16%) as a consequence of greater competition in the Brazilian market. The decline in domestic sales was partially offset by increased exports to Argentina in order to satisfy the demand created by trade union conflicts at the Zarate plant.

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Net Sales of Fertilizers

Fertilizers sales increased P$15 million, or 3.1%, to P$492 million in 2005 from P$477 million in 2004, mainly due to a 9% increase in the average sales price as a consequence of the rise in the international price of urea. The increase in average sales price was partially offset by a 5% drop in sales volumes derived from lower demand due to reduced corn and wheat sown areas (accounting for approximately 70% of the demand), drought in several regions at the time of fertilization, increased costs of some fertilizers and reduced grain prices.

Gross profit: Gross profit increased P$3 million, or 0.8%, to P$ 377 million in 2005 from P$374 million in 2004, reflecting principally an improvement in styrenics in Argentina, which was partially offset by a reduction in gross profit for Innova. Gross margin on sales decreased to 17.3% from 19.9% reflecting the impact of reduced margins for Innova.

Gross Profit of Styrenics - Argentina

Gross profit increased P$51 million, or 38.6%, to P$183 million in 2005 from P$132 million in 2004, mainly due to the strong rise in sales volumes. Gross margin on sales rose slightly, to 20.7% from 19.8%.

Gross Profit of Styrenics - Brazil

Gross profit decreased P$50 million, or 38.8%, to P$79 million in 2005 from P$129 million in 2004. Gross margin on sales declined to 8.1% from 16.7% as a consequence of the rise in raw material costs, mainly benzene, which could only be partially passed through to sales prices, and of increased fixed production costs derived from scheduled plant shutdowns in 2005.

Gross Profit of Fertilizers

Gross profit increased P$2 million, or 1.8%, to P$115 million in 2005 from P$113 million in 2004, and gross margin on sales was at similar levels in both fiscal years. The growing share of liquid fertilizers in the product mix, with a rise of approximately 12% in 2005, allowed the segment to offset the impact of the decline in sales volumes on gross profit.

Administrative and selling expenses: Administrative and selling expenses increased P$20 million, or 16.2%, to P$143 million in 2005 from P$123 million in 2004, primarily due to higher labor costs and increased variable selling expenses (both due to inflation adjustment) and higher freight costs derived from increased ethylbenzene exports.

Other operating income (expense), net: Other operating income (expense), net recorded P$33 million and P$27 million gains in 2005 and 2004, respectively, mainly attributable to the collection of FUNDOPEM tax benefits granted by Rio Grande do Sul State, Brazil.

Gas and Energy

Gas marketing

Operating income: Operating income for the Gas Marketing Sector of the Gas and Energy Segment increased P$35 million, or 14.3%, to P$280 million in 2005 from P$245 million in 2004. Operating income includes P$222 million and P$215 million gains in 2005 and 2004, respectively, attributable to the proportional consolidation of CIESA. Excluding proportional consolidation, operating income for the this sector increased P$28 million, or 93.3%, to P$58 million in 2005 from P$30 million in 2004.

Net sales: Sales revenues increased P$112 million to P$606 million in 2005 from P$494 million in 2004, mainly due to the rise in gas and liquid fuel prices. Gas sales prices increased due to scheduled price increases in line with the May 2004 agreement with the Secretary of Energy and to the increase in international reference prices as applicable to certain export sales and sales to industrial clients. As regards fuel liquids, improved prices derived from an increase in international reference prices.

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Revenues from the sale of gas and liquid fuels produced by us and imported gas and liquids totaled P$309 million and P$262 million in 2005, respectively, and P$205 million and P$270 million in 2004, respectively. Sales volumes of gas declined to 260.9 million cubic feet per day in 2005 from 274.5 million cubic feet per day in 2004 as a consequence of the combined effect of the drop in our production in Argentina and a trade union strike held at the Austral basin during the last quarter of 2005. Sales volumes of liquid fuels declined to 267.1 thousand tons in 2005 from 309.5 thousand tons in 2004, as a consequence of reduced gas volumes processed and lower yields obtained from processing gas with lower richness and heavier crude oils.

Gas and LPG brokerage services accounted for P$35 million and P$19 million in sales revenues during 2005 and 2004, respectively. The increase in 2005 was attributable to gas brokerage operations performed for the purpose of offsetting the decline in our production. Within this context, sales volumes increased to 18 million cubic feet per day in 2005 from 3 million cubic feet per day in 2004.

Gross profit: Gross profit in 2005 improved P$9 million, or 50%, to P$27 million from P$18 million. This significant rise was mainly attributable to increased margins on sales.

Other operating income (expense), net: Other operating income (expense), net (mainly attributable to income from technical assistance services to TGS) totaled P$35 million and P$18 million gains in 2005 and 2004, respectively. As from July 2004, within the framework of the agreement signed with Enron in connection with the restructuring of CIESA’s indebtedness, we are providing technical assistance services to TGS.

Electricity

Operating income: Operating income for the Electricity sector of the Gas and Energy business segment increased P$37 million, or 27.8%, to P$170 million in 2005 from P$133 million in 2004. Operating income includes gains of P$19 million in 2005 and P$14 million in 2004, due to our share of the operating income of Distrilec. Excluding proportional consolidation, operating income rose to P$151 million in 2005 from P$119 million in 2004, primarily due to increased generation margins as a result of a rise in average prices and an increased volume of energy delivered.

Electricity Generation

Net sales: Net sales of electricity increased P$75 million, or 26.8%, to P$355 million in 2005 from P$280 million in 2004, primarily due to a 17% improvement in generation prices and a 9.5% rise in sales volumes. The Company’s competitive advantages resulting from being an integrated energy company and operating both thermal and hydroelectric generation plants allowed the Company to capitalize on market opportunities and increase sales volumes during 2005 as compared to 2004.

The increase in average energy prices was primarily attributable to (i) higher demand for energy within a context of lower water flow at the different basins during the first half of the year and gas supply restrictions, which resulted in energy deliveries by less efficient generators, (ii) the pass through of increased gas costs to sales prices as a result of scheduled price increases in line with the May 2004 agreement with the Secretary of Energy.

Net sales attributable to the Genelba Power Plant increased P$66 million, or 29.5%, to P$290 million in 2005 from P$224 in 2004, primarily due to the combined effect of improved sales prices and increased generation volumes. The average sales price increased 16.5% to P$52.9 per MWh in 2005 from P$45.4 per MWh in 2004. Payment of additional compensation for guaranteed supply to the electricity market reflected increased sales of P$30 million in 2004. Energy delivered increased 11.3%, to 5,486 GWh in 2005 from 4,930 GWh in 2004. In 2005, the plant recorded a significant generation increase (8.5%) compared to 2004. During 2005, the integration of operations with the Oil and Gas business segment was a key factor in overcoming gas supply restrictions faced by thermal plants. The Genelba Power Plant factor increased to 91% from 83% and the availability factor climbed to 94% from 85%, during 2004, the plant’s availability factor was affected by a scheduled plant shutdown.

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Net sales attributable to the Pichi Picún Leufú Hydroelectric Complex increased P$12 million, or 23.1%, to P$64 million in 2005 from P$52 million in 2004, due to the combined effect of an improvement in sales prices and higher generation volumes. The average sales price increased 20.8% to P$51.2 per MWh in 2005 from P$42.4 per MWh in 2004, due to the abovementioned market reasons and the implementation of a dynamic and flexible policy in terms of the mix of spot and futures sales. During 2005, energy delivered increased to 1,255 GWh, or 2.4%, from 1,226 GWh in 2004, primarily due to increase consumption of water stored in the upper reservoir of the Comahue Basin’s power plants, in order to substitute thermal supply, which was not available due to fuel supply problems.

Gross profit: Gross profit for the generation business sector increased P$51 million, or 46.4%, to P$161 million in 2005 from P$110 million. This significant increase is attributable to the combined effect of improved prices and increased sales volumes.

Administrative and selling expenses: Administrative and selling expenses for the generation business sector increased P$2 million, or 20%, to P$12 million in 2005 from P$10 million in 2004.

Other operating income (expense), net: Other operating income (expense), net dropped P$16 million to P$1 million from P$17 million mainly due to the decline in income from technical assistance services provided to Chilectra S.A., as technical operator of Edesur S.A. In November 2004, Chilectra S.A. and Edesur S.A. renegotiated the terms of the technical assistance agreement, with a substantial reduction in the contractual compensation terms of the former agreement.

ANALYSIS OF EQUITY IN EARNINGS OF AFFILIATES

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 the earnings of CIESA and TGS increased P$23 million to P$49 million in 2005 from P$26 million in 2004 mainly as a consequence of reduced financial expenses in 2005.

Financial expense, net decreased to P$288 million from P$348 million, mainly as a consequence of reduced interest expenses resulting from TGS’s lower average indebtedness. In line with the global restructuring of its financial debt, TGS’s average indebtedness declined approximately 13% in 2005.

Sales revenues increased 5.8%, or P$56 million, to P$1,026 million in 2005 from P$970 million in 2004.

Sales revenues from the gas transportation segment increased 5.9% or P$26 million to P$460 million. This improvement was mainly attributable to the execution of new firm transportation agreements in connection with: (i) the expansion of the General San Martín Gas Pipeline completed in August 2005, which resulted in an increase of transportation capacity of 2.9 million cubic meters per day, (ii) a new contract with a joint venture of gas producers at the Austral basin, effective February 2005, which allowed an increase in transportation capacity of 1 million cubic meters per day, and (iii) open bids for transportation capacity carried out by TGS in March 2004, which resulted in increases in committed transportation capacity of 3.6 million cubic meters per day.

Revenues from NGL production and marketing activities increased 7.9% or P$43 million to P$526 million mainly as a result of a 12% increase in the average sales price of NGL due to the rise in international reference prices, which was partially offset by reduced sales volumes (approximately 4%).

Operating income of CIESA decreased P$11 million, or 2.4%, to P$442 million in 2005, mainly as a consequence of (1) an increase in export taxes and (2) higher production costs derived from the rise in natural gas price and, to a lesser extent, increased labor costs.

Distrilec: Our equity interest in the earnings of Distrilec accounted for a P$4 million increase in losses to P$17 million in 2005 from P$13 million in 2004.

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Distrilec’s income from services increased 21.3% to P$1,339 million in 2005 from P$1,104 million in 2004, due to the combined effect of a 14.5% rise in sales prices and a 5.3% growth in the demand for energy.

Distrilec’s operating income increased 30% to P$39 million from P$30 million in 2004 reflecting the rise in sales, which was partially offset by increased costs for the purchase of energy and the application of fines by the regulatory entity.

Distrilec’s financial income (expense) was similar in both fiscal years, accounting for losses of P$39 million and P$41 million in 2005 and 2004, respectively.

Distrilec’s other operating income (expense), net accounted for a loss of P$22 million in 2005 compared to a P$14 million gain in 2004. The gain in 2004 resulted principally from a P$36 million gain recorded on the settlement reached with Alstom Argentina in connection with January 15, 1999 events at the Azopardo substation.

Refinería del Norte S.A. (Refinor): In 2005, our equity in the earnings of Refinor increased P$6 million to P$46 million from P$40 million in 2004. This increase resulted primarily from a significant increase in sales.

Refinor’s sales increased 31.1% or P$339 million to P$1,429 million in 2005 from P$1,090 million in 2004, mainly as a result of the significant rise in sales prices (both international prices of fuels and domestic prices of LPG) and, to a lesser extent, increased processed volumes of crude oil. In 2005, in line with the increase in international reference prices, Refinor’s average sales price was 36% higher than in 2004. The volume of crude oil processed increased 2.3%, to 17.9 thousand barrels per day with greater crude oil availability from Bolivia. This allowed Refinor to more than offset the drop in production volumes at the Cuenca del Norte oilfields in Argentina. The volume of gas processed averaged 19.1 million cubic meters per day, a level similar to that recorded in 2004.

Refinor’s operating income climbed to P$245 million from P$217 million in 2004.

Citelec: Equity in earnings of Citelec accounted for a gain of P$27 million in 2005, compared to a loss of P$42 million in 2004. As of September 30, 2005, upon submittal of our plan for Citelec’s divestment, our equity interest in Citelec has been valued at the recoverable value determined on the basis of the probable net realization value. On June 2006, the Board of Director accepted an offer for the transfer of the 50% in Citelec S.A. See “Item 4. Information about the Company – Gas and Energy – Electricity – Transener.”

Petroquímica Cuyo S.A. (Cuyo): Our equity interest in the earnings of Cuyo decreased P$9 million to P$7 million in 2005 from P$16 million in 2004. This decline was basically attributable to a significant reduction in margins on sales mainly as a consequence of increased costs derived from the rise in crude oil prices and, to a lesser extent, increased costs derived from a scheduled plant shutdown in 2005. Cuyo was not able to fully mitigate higher costs fromn the rise of crude oil with increased sales prices.

Cuyo’s sales increased 14.7% to P$336 million in 2005 from P$293 million in 2004, mainly due to a 25% increase in sales prices, partially offset by a 8.5% decline in sales volumes. The improvement in average sales prices reflected the rise in crude oil prices, which resulted in significant increases in international reference prices for the petrochemical industry. The decline in sales volumes was attributable to the scheduled plant shutdown in 2005.

Cuyo’s operating income decreased to P$33 million from P$63 million in 2004 mainly due to the combined effect of reduced margins on sales and lower sales volumes.

Petrobras Bolivia de Refinación (PBR): Our equity interest in the earnings of PBR moved up P$36 million to P$54 million in 2005 from P$18 million in 2004 as a consequence of the combined effect of improved margins, with a 14% rise in the average sales price, and increased sales volumes.

In 2005, contribution margins significantly improved, mainly due to the fact that PBR’s operations were positively affected by the rise in international reference prices and better discounts in crude oil and gasoline exports.

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In addition, in 2005 PBR achieved record levels in crude oil, diesel oil and lubricants processing amounting to 39.8 thousand barrels per day, 55.5 thousand cubic meters per month and 1.16 thousand cubic meters per month, respectively. Along these lines, reconstituted crude oil sales set record levels with average monthly volumes of 269 thousand barrels, and diesel oil sales amounted to levels similar to those in 2004 with 54.5 thousand cubic meters per month. In the domestic market, marketing activities were performed through its subsidiary PBD, with an increase in its market share to about 30%, with a commercial network of 104 retail points, of which 12 were added in 2005.

Oleoductos del Valle S.A. (Oldelval): Our equity interest in the earnings of Oldelval decreased P$4 million to P$3 million from P$7 million as a consequence of the recognition of a gain derived from the unusual sale of crude oil surplus in 2004.

Oldelval’s sales revenues increased 5% to P$118 million due to a 9% rise in rates effective April 2005, partially offset by a 1% slight decline in transported volumes, to 65.4 million barrels, as a direct consequence of the natural decline trend in the Neuquén basin oilfields. In addition, operating costs increased basically due to the performance of maintenance works for the purpose of securing reliability in the pumping system.

Petrolera Entre Lomas S.A (PELSA): Our equity interest in the earnings of PELSA increased P$9 million to P$26 million from P$17 million, mainly due to the combined effect of an improvement in margins on sales and increased sales volumes, both of crude oil and natural gas.

Sales revenues increased 34.3% to P$368 million from P$ 274 million due to the combined effect of a 24% improvement in prices attributable to the rise in the international price of crude oil and increased volumes (8%).

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Year ended December 31, 2004 compared to year ended December 31, 2003

Net income: In 2004, we reported net income of P$678 million, compared to a net income of 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: In 2004, our net sales increased P$1,650 million, or 23.2%, to P$8,763 million, from P$7,113 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).

In 2004 without proportional consolidation, our net sales increased P$1,522 million, or 24.4%, to P$7,756 million, from P$6,234 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 and Distribution business segments, equal to P$658 million (22%), P$583 million (45.1%) and P$657 million (24%), respectively (including intercompany sales). The Electricity sector 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, Gas Marketing sector sales increased P$419 million. As the business operations continue to integrate, intersegment sales increased to P$1,924 million in 2004 from P$1,070 million in 2003. The majority of these sales are between our Exploration and Production segment and our Refining and Distribution segment.

Gross Profit: In 2004, our gross profit increased P$618 million, or 26.3%, to P$2,972 million, from P$2,354 million in 2003. Our gross profit for 2004 includes 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. Our gross profit for 2003 includes gains of P$236 million and P$74 million, attributable to our share of the gross profit of CIESA and Distrilec, respectively.

In 2004, without proportional consolidation, our gross profit for 2004 grew P$589 million, or 28.8%, to P$2,633 million from P$2,044 million in 2003. This increase in our 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. Our gross profit for the Oil and Gas Exploration and Production segment increased P$511 million, or 36.8%, predominately due to an increase in sales and margins resulting from a 19.4% increase in average sales prices of oil equivalent. In contrast, our gross profit from Refining and Distribution segment decresed P$4 million, or 1.5%. Our gross profits for our Petrochemicals and Gas and Energy segments also increased 19.9% and 31.6%, respectively.

Administrative and selling expenses: In 2004, our administrative and selling expenses increased P$77 million, or 10%, to P$847 million, from P$770 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. In 2004, without proportional consolidation, our administrative and selling expenses declined by P$90 million or 13.3% to P$765 million, from P$675 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: In 2004, exploration expenses decreased P$227 million to P$133 million, from P$360 million in 2003. During 2004 and 2003, we expensed certain exploratory drilling costs that had been capitalized in prior years. See “—Analysis of Operating Results by Business Segment—Oil and Gas Exploration and Production”.

Other operating (expense), net: In 2004, our other operating expenses increased on a net basis by P$201 million, or 163.4%, to P$324 million, from P$123 million in 2003. Our other operating expense, net for 2004, includes losses of P$19 million and P$6 million, attributable to our share of CIESA and Distrilec, respectively, and P$3 million in eliminations. Our other operating income (expense), net for 2003 includes losses of P$12 million and P$5 million, attributable to our share of other operating income (expense), net of CIESA and Distrilec, respectively.

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Without proportional consolidation, other operating income (expense), net accounted for losses of P$296 million for 2004 and P$106 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.

Operating income: In 2004, our operating income grew P$567 million, or 51.5%, to P$1,668 million, from P$1,101 million in 2003. Our operating income for 2004 includes P$215 million and P$14 million, attributable to our share of operating income of CIESA and Distrilec, respectively. Operating income for 2003 includes P$194 million and P$4 million, attributable to our share of operating income of CIESA and Distrilec, respectively.

In 2004, without proportional consolidation, our operating income increased P$536 million, or 59.4%, to P$1,439 million, from P$903 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: In 2004, our equity in earnings of affiliates decreased P$87 million, or 53.4%, to P$76 million, from P$163 million in 2003.

Without proportional consolidation, our equity in earnings of affiliates decreased P$292 million, or 78.7%, to P$79 million in 2004 from P$371 million in 2003, 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 U.S. 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.

For a discussion of our equity in the earnings of companies over which we exercise joint control in 2004 and 2003, and the factors that affected these companies’ results 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$878 million, or 226.9%, to P$1,265 million, from P$387 million in 2003. Our financial expenses and holding losses for 2004 includes financial expenses of P$144 million and P$20 million, attributable to our share of the financial income (expense) and holding gains (losses) of CIESA and Distrilec, respectively. Our financial expenses and holding losses for 2003 includes financial income in the amount of P$123 million and P$28 million, attributable to our share of the financial income (expense) and holding gains (losses) of CIESA and Distrilec, respectively.

Without proportional consolidation, our financial income (expense) and holding gains (losses) reflected losses of P$1,101 million in 2004 and P$538 million in 2003. The increase in 2004 is principally attributable to the following:

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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 U.S. 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$17 million loss in 2004 compared to a P$155 million gain in 2003; and

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An offsetting decrease in interest expense in the amount of P$470 million in 2004, or 1.6%, from P$427 million in 2003, reflecting a decline in our U.S. dollar-denominated average indebtedness.

Other expenses, net: In 2004, our other expenses, net equaled losses of P$40 million and P$447 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$7 million, attributable to our 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.

In 2004, without proportional consolidation, our other expenses, net accounted for losses of P$33 million in 2004 and P$434 million in 2003. These decreases primarily reflected 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.

The other expenses, net for 2003 primarily reflect the following:

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P$309 million impairment charge for the operations in Ecuador;

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P$39 million loss attributable to the sale of oil and gas areas;

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P$37 million impairment charge for oil production areas; and

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P$27 million allowance for the book value of loans granted to joint venture partners in Venezuela.

Income tax: In 2004, our income tax accounted for a gain of P$211 million, compared to a loss of P$29 million in 2003. Our income tax in 2004 includes losses of P$6 million and P$20 million, attributable to our share of the income tax of CIESA and Distrilec, respectively. Our income tax charge for 2003 includes 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.

In 2004, without proportional consolidation, income tax accounted for a gain of P$237 million in 2004 compared to a loss of P$58 million in 2003. As of December 31, 2004, after taking into consideration the profitability expectations arising from its business plan, Petrobras Energía partially reversed an allowance for tax loss carry forwards and recognized a gain of P$268 million. In addition, Petrobras Energía Perú recorded a gain of P$31 million from the reversal of tax allowances, derived from improved economic expectations for Lote X.

ANALYSIS OF OPERATING RESULTS BY BUSINESS SEGMENT

Oil and Gas Exploration and Production

Operating income: Operating income for the Oil and Gas Exploration and Production business segment increased P$474 million, or 60.3%, to P$1,260 million in 2004 from P$786 million in 2003. This increase was predominately due to the 19.8% 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.

In 2004, international prices were highly favorable for our Oil and Gas Exploration and Production business segment. The WTI averaged U.S.$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.

Net sales: Net sales for the Oil and Gas Exploration and Production business segment increased P$658 million, or 22%, to P$3,647 million in 2004 from P$2,989 million in 2003. This increase was predominately due to 19.8% increase in the average sales price of oil equivalent and, to a lesser extent, to a 1.8% increase in volume sales of oil equivalent.

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In 2004, daily oil and gas sales volumes increased to 179,900 barrels of oil equivalent from 177,200 barrels of oil equivalent in 2003. Oil sales volumes increased to 123,900 barrels per day, or 3.4%, in 2004 from 119,900 barrels per day in 2003, while gas daily volumes remained substantially unchanged, totaling 336.2 million cubic feet in 2004 and 344.3 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 19.3% to P$73.6 from P$61.7, mainly 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$246 million, or 13.7%, to P$2,044 million from P$1,798 million in 2003. Combined oil and gas daily sales volumes decreased 6.9% to 102,200 barrels of oil equivalent in 2004 from 109,800 barrels of oil equivalent in 2003.

Crude oil sales increased by P$235 million, or 14.6%, to P$1,850 million in 2004 from P$1,615 million in 2003. This increase was due to a 24.7% increase in the average sales price to P$86.7 per barrel in 2004 from P$69.6 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.

Daily oil sales volumes declined 8.4% to 58,300 barrels in 2004 from 63,600 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 6.6% to P$194 million in 2004 from P$182 million in 2003, mainly as a result of a 11.5% increase in the average sales price, which was partially offset by a 4.6% decline in sales volumes. The average sales price for gas increased to P$2.01 per million cubic feet in 2004 from P$1.8 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.

Daily gas sales volumes declined 5% to 263.7 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$398 million, or 33.5%, to P$1,587 million from P$1,189 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:

Net Sales in 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.

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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.

Net Sales in 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.

Net Sales in 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.

Net Sales in 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: In 2004, gross profit for this business segment increased by P$511 million, or 36.8%, to P$1,900 million in 2004 from P$1,389 million in 2003. The margin on sales increased to 52.1% from 46.5% 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 10.4% to P$8.7 per barrel of oil equivalent in 2004 from P$7.88 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: In 2004, Administrative and selling expenses increased P$26 million, or 13.3%, to P$221 million in 2004 from P$195 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$133 million in 2004 and P$360 million in 2003. Expenses for 2004 were mainly attributable to the expensing of exploratory drilling costs in Block 31 in Ecuador for P$80 million and the Aguaragüe and Puesto Zuñiga areas in Argentina in the amount of P$41 million.

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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 (loss), net: In 2004, other operating income (expense), net accounted for losses of P$286 million in 2004 and P$48 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.

Refining and Distribution

Operating income: In 2004, our operating income for the Refining and Distribution business segment increased P$12 million, or 600%, to P$10 million gain in 2004 compared to a P$2 million loss 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.

Net sales: In 2004, net sales of refinery products increased P$657 million, or 24.3%, to P$3,359 million in 2004 from P$2,702 million in 2003. This increase was primarily a result of significant price increases and to a lesser extent, a 0.6% average rise in sales volumes and the reallocation of the oil brokerage activities to this segment. Below we highlight certain significant trends in sale prices and volumes for refined products in 2004:

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In 2004, average sales prices of reformer plant products increased 38%, respectively, mainly as a result of the significant increase in crude oil and bencene international prices.

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In 2004, crude oil volumes processed at the refinery increased 3.3% to 63.1 thousand barrels per day.

•

Domestic sales volumes increased 4.7% in 2004 compared to 2003, primarily due to diesel oil and premium gasoline sales. On the contrary, export sales volumes decreased 11.2%, primarily as a result of satisfying the internal market.

•

Sales volumes of diesel oil increased 1.9% in 2004, to 1,787 thousands of cubic meters, reflecting a 7% rise in local market, partially compensated by a decline of 33% in exports. Sales increased in Argentina, predominately due to increased demand from the agricultural sector.

•

Total gasoline sales volumes declined 2.8% to 689 thousands of cubic meters in 2004, due to a 35% reduction on exports, partially compensated by higher sales in the local market, 16%, (including sales of our premium gasoline “Podium”). Our market share was 14.7% in 2004 and 12.9% 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 and SP). This figure exceeded our expectations, and Podium has improved our overall performance in the premium gasoline segment, reaching to 7.8% of market share in the premium gasoline segment, from 5.5%.

•

Asphalt sales volumes grew 24% in 2004. 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. Increased sales to the domestic market resulted in a reduction in export levels, predominately to Paraguay and Bolivia. The market share in the road asphalt segment decreased to 37.5% in 2004 from 39.2% in 2003.

•

Sales volumes for heavy distillates grew 1.8% in 2004, primarily due to a 29.7% growth in the domestic sales market, particularly in fuel oil sales to thermal power plants. Exports declined 9.7%, 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.

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•

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: In 2004, gross profit decreased P$4 million, or 1.5%, to P$257 million in 2004 from P$261 million in 2003. Gross margin on sales decreased to 7.7% in 2004 from 9.7% in 2003.

Administrative and selling expenses: In 2004, administrative and selling expenses for the Refining and Distribution segment decreased P$7 million, or 2.8%, to P$244 million, from P$251 million.

Other operating expenses, net: In 2004, other operating expenses, net for the Refining and Distribution segment recorded losses of P$3 million in 2004 and P$12 million in 2003. 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.

Petrochemicals

Industry Overview: In 2004, the styrenics business, and in line with the upward trend in oil prices, was characterized by high international prices for both finished products and major raw materials. International prices of styrene, polystyrene and benzene (main feedstock) 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 U.S.$175 per ton, or 25.9%, in 2004 from an average of U.S.$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: In 2004, total 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 from P$1,294 million in 2003, primarily due to increased sales prices and, to a lesser extent, increased sales volumes.

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Net Sales of Styrenics – Argentina

In 2004, total sales of styrenics in Argentina increased P$181 million, or 37.3%, to P$666 million 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.

Styrenic monomer sales volumes slightly decreased 3% to 42 thousand tons. 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.

Polystyrene sales volumes increased an average of 7%, to 62.9 thousand tons 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).

Synthetic rubber sales volumes increased 5.8% to 60.2 thousand tons, 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.

Net Sales of Styrenics-Brazil – Innova

In 2004 Innova sales increased P$271 million, or 54%, to P$773, 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 10% and 16%, respectively. Export sales of polystyrene increased 10% compared to 2003, mainly due to increased sales to the United States and Africa.

Net Sales of Fertilizers

In 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: In 2004, gross profit increased P$62 million, or 19.9%, to P$374 million, 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.

Gross Profit of Styrenics – Argentina

In 2004, gross profit increased P$3 million, or 2.3%, to P$132 million, 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.

Gross Profit of Styrenics - Brazil

In 2004, gross profit increased P$40 million, or 44.9%, to P$129 million, 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.

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Gross Profit of Fertilizers

In 2004, gross profit increased P$19 million, or 20.2%, to P$113 million, 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: In 2004, administrative and selling expenses increased P$13 million, or 11.8%, to P$123, 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: In 2004, other operating income (expense), net recorded a gain of P$27, 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.

Gas and Energy

Gas marketing

In 2004, we implemented changes in the way we allocate certain product sales among different business segments. As a result, the Gas Marketing 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 Gas marketing’s operations include gas and liquified petroleum and gas brokerage activities, which were previously provided by our Oil and Gas Exploration and Production business segment. Also, as of 2004, oil brokerage services are now provided through our Refining and Distribution 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: In 2004, our operating income for the Gas Marketing sector of the Gas and Energy segment increased P$40 million, or 19.5%, in 2004 to P$245 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.

In 2004, without proportional consolidation, our the operating income for this business segment increased by P$19 million, or 172.7%, in 2004 to P$30 million from P$11 million in 2003, reflecting principally increased net sales.

Net sales: In 2004, our sales revenues without proportional consolidation increased P$419 million to P$494 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$205 million and P$270 million, respectively. Sales volumes of gas produced by us in Argentina totaled 274.5 million cubic feet per day, and sales volumes of liquids amounted to 309.5 thousand tons. Gas and liquified petroleum and gas brokerage services accounted for P$19 million and P$75 million in sales revenues during 2004 and 2003, respectively.

Gross profit: In 2004, as a consequence of the segment reallocation changes implemented, gross profit without proportional consolidation increased P$14 million to P$18 million in 2004 from P$4 million in 2003.

Other operating income, net: In 2004, 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, 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.

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Electricity

Operating income: In 2004, our operating income for this sector increased P$21 million, or 18.7%, to P$133 million, from P$112 million in 2003. Our operating results reflect gains of P$14 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.

Electricity generation

Net sales: Net sales of electricity generation sector 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, 4,930 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 Pichi Picún Leufú Hydroelectric Complex or 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 abovementioned 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 business sector increased P$2 million, or 25%, to P$10 million in 2004 from P$8 million in 2003.

ANALYSIS OF EQUITY IN EARNINGS OF AFFILIATES

CIESA/TGS: In 2004, our equity in earnings of CIESA and TGS decreased P$212 million, or 89.1%, to P$26, 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 U.S. 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 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.

Revenues 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$453 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: In 2004, our equity in earnings of Distrilec accounted for losses of P$13 million, from 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 increased to P$30 million in 2004 from P$8 million in 2003, principally due to increase in demand. Distrilec’s financial income (expense) accounted for a loss of P$41 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 U.S. dollar-denominated net borrowing position.

Distrilec’s other operating income (expense), net accounted for a gain of P$14 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: In 2004, our equity in earnings of Citelec accounted for a loss of P$42, 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 U.S. 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.

Petroquímica Cuyo S.A. (Cuyo): In 2004, our equity in earnings of Cuyo accounted for P$16 million gains in both years.

Cuyo sales in 2004 increased 30.2% to P$293 million, from P$225 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 abovementioned increase in prices. This effect, however, was principally offset by higher income taxes.

Petrobras Bolivia Refinación S.A (PBR): In 2004, our equity in earnings of PBR accounted for a gain of P$18 million, compared to a loss of P$5 million loss in 2003, due to the combined effect of improved margins and higher volumes.

In 2004, PBR 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 PBR. In 2003, as a result of this regulatory framework, PBR had no refining margins.

In addition, PBR 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 PBR’s extended commercial network, which in 2004 added 11 new sale points through its subsidiary Empresa Boliviana de Distribución.

Refinor: In 2004, our equity in earnings of Refinor increased P$12 million, or 42.9%, to P$40 million, 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$208 million, or 23.6%, to P$1,090 million in 2004 from P$882 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 19.1 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: In 2004, our equity in earnings of Oldelval increased to P$7 million, 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 approximately 2% to 66.5 million barrels in 2004. This increase was generally due to declines in exports to Chile.

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CRITICAL ACCOUNTING POLICIES

The preparation of financial statements in accordance with Argentine 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 represent our critical accounting policies. Our accounting policies are more fully described in notes 1 to 5 to our financial statements.

Estimates 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 than reasonable certainty of recoverability and are classified as either probable or possible. Probable reserves are reserves that are more likely than not to be recovered and possible reserves are less likely to be recovered.

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 estimates, as well as future production profiles, are often different from the quantities of hydrocarbons that are ultimately recovered. The accuracy of such estimates 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; or (b) an immediate write-down of an asset’s book value. If, on the other hand, the oil and gas reserve quantities were revised upward, our per barrel depreciation and depletion expense would be lower. Changes in proved oil and gas reserves will also affect the standardized measure of discounted cash flows presented in note 24 to our financial statements.

Significant changes in market or political conditions, such as the pesification of gas prices during 2002 and the changes in the Venezuelan regulatory regime during 2005, 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 used to allocate costs of upstream assets to the revenues recognized. 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 except for leasehold acquisition costs. Proved undeveloped reserves are considered in the amortization of leasehold acquisition costs. The volumes produced and asset cost are known and while proved developed and undeveloped reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. This variability may result in net upward or downward revisions of proved reserves in existing fields, as more information becomes available through research and production. We

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revised our proved reserves in the last three years, decreasing our proved reserves by 14 million barrels of oil equivalent in 2005, increasing our proved reserves by 7 million barrels of oil equivalent in 2004 and decreasing our proved reserves by 51 million barrels of oil equivalent in 2003. 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 long-lived assets.

Our long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Impairment can also occur when we decide to dispose of assets.

The Company tests the recoverability our long-lived assets based on their respective values in use, defined as the addition of the expected net cash flows that arise as a direct result of the use and eventual disposition of the assets. To such end, among other elements, the premises that represent the best estimate made by our management of the economic conditions that will prevail throughout the useful life of the assets are considered. The book value of a long-lived asset is adjusted to its recoverable value if its carrying amount exceeds the undiscounted value in use. From a regulatory standpoint, recoverable value is defined as the larger of net realizable value and discounted value in use.

In the determination of the discounted value in use, discount rates used by market participants to evaluate the time value of money and the specific risk of the asset are considered.

Under Argentine GAAP, impairment charges can be reversed in subsequent years so that the reduced carrying amount does not represent the new cost basis of the long-lived assets should the facts and circumstances change in the future. In general, we do not view temporarily low prices as a trigger event for conducting the impairment tests. The markets for crude oil and natural gas and oil related products 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 recoverability tests that we perform make use of our long-term price assumptions. 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 prices could lead to impairments in the future, if such decreases were considered to be indicative of long-term trends. In 2005, we recorded a P$255 million impairment with respect to our assets in Venezuela, as a result of the recent changes in the Venezuelan regulatory framework. See “Conversion of operating agreements in Venezuela”. In 2004 and 2003, we recorded P$12 million and P$346 million respectively in impairments of our oil and gas assets. In addition, in 2005 we recorded a P$44 million gain from reversal of an impairment charge in the Gas areas in Argentina item that was originally provided in 2002 and 2003.

Successful efforts method of accounting.

We follow the successful efforts method of accounting for our oil and gas activities.

Occasionally, an exploratory well may determine the existence of oil and gas reserves but the reserves cannot be classified as proved when drilling is complete.

In those cases, incorporating prospectively the changes introduced by the interpretation FASB Staff Position 19-1, starting July 2005, such costs continue to be capitalized insofar as (i) the well has determined the existence of sufficient reserves to warrant its completion as a production well and (ii) the company is making sufficient progress in evaluating the economic and operating feasibility of the project.

Before such interpretation, SFAS 19 provided: (I) if the well found 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 to be capitalized as long as it meets the following two conditions: (a) reserves found are sufficient to justify completion of the well as producing 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.

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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. 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).

As of December 31, 2005, and 2004, we maintained suspended well costs amounting to P$61 million and P$5 million, respectively.

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. As of December 31, 2005 and 2004, contingent liabilities (including current and non-current) amount to P$151 millon and P$107 million, respectively.

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 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 “probable” that some portion or all of the deferred tax asset will be realized.

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 “probable” 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. Due to the fact that uncertainty exists surrounding our ability to generate sufficient taxable income from operations before the expiration of the loss carry forwards, we have provided a valuation allowance of P$1,164 million against tax loss carry forwards as at December 31, 2005. In future periods, we, after evaluating more recent data about our recent tax history and future performance and prospects, may reverse a part of this allowance. In 2005 and 2004, for example, after taking into consideration the profitability expectations arising from our business plan, we partially reversed an allowance for tax loss carry forwards and recognized gains of P$197 and P$299 million, respectively.

Asset retirement obligations.

Future costs related to hydrocarbon wells abandonment obligations are capitalized along with the related assets, and are depreciated using the unit-of-production method. As compensation, a liability is recognized for this concept at the same estimated value of the discounted payable amounts. Future estimated retirement obligations and removal costs are based on our management’s best estimate of the time that the event will occur and the assertion of costs to be met with the removal of the asset. Asset removal technologies and costs, as well as political, environmental and safety, are constantly changing. As a result, the timing and future cost of dismantling are subject to significant modification. The timing and the amount of future expenditures of dismantling are reviewed annually. As such, any change in variables used to prepare such assumptions and estimates can have, as a consequence, a significant effect in the liability and the related capitalized asset and in the future charges related to the retirement obligations.

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LIQUIDITY AND CAPITAL RESOURCES

During 2005, the Argentine government successfully restructured a substantial portion of its sovereign debt, which was previously in default. Although this represents a significant step towards the reintegration of our country in the international financial market, Argentina and Argentine companies are still subject to a series of significant restrictions on access to the international debt markets. In spite of a positive growth scenario in Latin America, typical fluctuations in emerging markets may generate volatility in financial and income indicators and capital flows to the region.

In view of these limitations, we closely monitor liquidity levels in order to secure compliance with our obligations and achievement of our growth objectives. Along these lines, and as a guiding principle, financial solvency is the foundation on which sustainable development of our businesses is built.

Pursuant to these strategic guidelines, we seek to:

•

Gradually reduce our level of indebtedness, by designing a capital structure in line with industry standards adaptable to the financial markets in which we operate and by establishing a debt maturity profile that is consistent with cash generation.

•

Gradually reduce indebtedness costs.

•

Have adequate flexibility to overcome the volatility inherent to emerging capital markets, by adhering to a conservative cash management policy that minimizes the risks of financial distress.

•

Limit the level of investments in order to focus on cash generation, by prioritizing profitable projects with faster returns.

By adhering to these guidelines, the Company treats financial management as a key element in the value-creation process.

Consistent with these guidelines, we achieved the following during 2005:

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13% growth in operating cash flow.

•

Strict compliance with all financial obligations, with a 5% decline in our annual average indebtedness, measured in U.S. dollars.

•

During the first quarter of 2005, we prepaid at face value the remaining outstanding notes and other debt instruments originally issued in October 2002 (the “refinanced debt”) for a total amount of approximately P$1,069 million (U.S.$365 million). While any portion of this refinanced debt remained unpaid, we complied with a series of restrictions and commitments, including, among others, restrictions on the payment of dividends, capital expenditures, liens and incurrence of new debt. We are free from these restrictions as from the prepayment date and have gained increased financial flexibility.

•

In December 2005, our subsidiaries Innova and Petrobras Energía Venezuela fully paid in advance loans granted by the International Finance Corporation (“IFC”) for a total amount of approximately P$415 million (U.S.$137 million). The Company is now free from restrictions and commitments contained in such loans.

•

A significant increase in investments, supporting our growth strategy.

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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) fluctuations in production levels and demand for our products, (3) fluctuations in margins in refining and distribution and petrochemicals, (4) the conversion of operating agreements in Venezuela, (5) changes in regulations, such as taxes, taxes on exports, changes in royalties payments and price controls and (6) fluctuations in exchange and interest rates.

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 experienced a delay in our projects in Ecuador in connection with the development of Block 31, 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 our results and financial condition separately from the results and financial condition of affiliates under joint control. The discussion below, therefore, relates to our liquidity and capital resources and that of our subsidiaries, excluding proportional consolidation of companies over which we exercise joint control, and as a result may not be directly comparable to figures reflected in our financial statements.

The table below reflects our statements of cash flow for the fiscal years ended December 31, 2005, 2004 and 2003 under Argentine GAAP and, for comparative purposes, the pro forma results excluding the effect of proportional consolidation of companies under joint control.


	With Proportional Consolidation						Without Proportional Consolidation
	2005		2004		2003		2005		2004		2003
	(in millions of pesos)
Cash and cash equivalents at beginning of year⁽¹⁾	1,067		1,091		911		846		709		879
Additions (deductions) of cash and cash equivalents from proportional interest in CIESA at beginning of period	—		—		103		—		—		—
Net cash provided by operations	1,998		1,632		1,532		1,626		1,438		1,182
Net cash used in investing activities	(1,682	)	(1,199	)	(958	)	(1,544	)	(1,072	)	(900	)
Net cash provided by (used in) financing activities	(602	)	(451	)	(409	)	(463	)	(222	)	(364	)
Devaluation and inflation effects on cash	9		(6	)	(88	)	9		(7	)	(88	)

Cash and cash equivalents at end of year	790		1,067		1,091		474		846		709

⁽¹⁾	For 2003, this amount does not include cash and cash equivalents from our proportional interest in CIESA.

Cash

Cash and Cash equivalents excluding the proportional consolidation of companies under joint control was P$474 million in 2005, P$846 million in 2004 and P$709 million in 2003.

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Our goal is to maintain excess cash primarily in U.S. dollars and in short-term investments in order to ensure adequate liquidity levels. We use predominately money market mutual funds and overnight deposits.

Operating activities

Net cash from operations, excluding proportional consolidation, totaled P$1,626 million in 2005, P$1,438 million in 2004 and P$1,182 million in 2003.

Net cash from operations in 2005 increased by P$188 primarily due to the increase in commodity prices, particularly in the WTI.

Net cash from operations in 2004 increased by P$256 million from 2003 to 2004, due to the increase in the WTI, an increase in our refining margins and increased sales volumes of petrochemical and refined products.

Investing activities

Cash used in investing activities, excluding proportional consolidation of companies under joint control, was P$1,544 million in 2005, P$1,072 million in 2004 and P$900 million in 2003.

Supported by the increase in operating cash flow and with our liquidity at target levels, capital expenditures steadily increased, by P$552 million to P$1,619 million in 2005, and by P$143 million to P$1,067 million in 2004.

The table below reflects total capital expenditures, net:


(in million of pesos)	2005	2004	2003
Oil and Gas Exploration and Production	1,235	872	764
Petrochemical	119	96	32
Refining and Distribution	199	81	103
Corporate and others	66	18	25

Total capital expenditures	1,619	1,067	924
Divestments	—	—	(20	)

Total net capital expenditures	1,619	1,067	904

Oil and Gas Exploration and Production

Capital expenditures in the Oil and Gas Exploration and Production segment totaled P$1,235 million, P$872 million and P$764 million in 2005, 2004 and 2003, respectively.

In 2005, capital expenditures in the Oil and Gas Exploration and Production segment were primarily directed towards maintaining production levels and prioritizing investments in countries and products with higher expected profit margins. Consequently, 352 wells were drilled, of which 265 are located in Argentina, and 369 units were repaired, of which 281 are located in Argentina. In addition, significant infrastructure works were carried out. In Argentina, the development of reserves continued through well drilling and the expansion of surface facilities. Capital investments were also allocated to infrastructure works for our interconnection project, which has allowed us to deliver gas and condensate from our La Porfiada, La Paz and Boleadoras fields to the General San Martín gas pipeline. Works relating to La Porfiada Field interconnection project continued, with completion in early 2006. In Venezuela, capital expenditures were primarily directed towards construction of development wells and drilling of 21 wells during the year. Also in 2005, as in 2004, we also made improvements in connection with extraction and surface and bottom equipment. In Ecuador, at Block 18, eleven wells were drilled and expansion works in production facilities continued both for the Palo Azul and Pata Fields; approximately 70% of the works will be performed and will become operational by the end of 2006. In Peru, investments in well drilling, repair works and reactivation were developed as part of water injection implementation projects. In addition, we started the installation of alternative extraction systems for the purpose of optimizing operating costs. We also performed geological and geophysical works, in connection with our exploitation activities.

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Refining and Distribution

Capital expenditures in the Refining and Distribution segment totaled P$199 million, P$81 million and P$103 million in 2005, 2004 and 2003, respectively.

In 2005, capital expenditures at the San Lorenzo refinery were directed towards maintaining efficient operating conditions including the replacement of furnaces at Topping III. The most significant investment in 2005 at the Bahía Blanca refinery was the construction of a new dispatch plant, “Caleta Paula” to improve product distribution logistics. In the Distribution segment, major investments were directed towards the rebranding of 120 gas stations, as part of a campaign to strengthen Petrobras, image in the domestic market.

Petrochemicals

In the Petrochemicals segment, capital expenditures totaled P$119 million, P$96 million and P$32 million in 2005, 2004 and 2003, respectively. In 2005, capital expenditures in styrene focused on increasing operating efficiency. A plot of land was acquired for the construction of a super simple phosphate plant for the production of a new fertilizer product that until 2005 was imported for resale. In addition, significant capital expenditures were made in relation to the supply of liquid fertilizers, plant maintenance and commercial development.

Financing activities

Net cash used in financing activities, excluding proportional consolidation of companies under joint control, totaled P$463 million, P$222 and P$364 in 2005, 2004 and 2003, respectively.

We paid off long-term debt in the amount of P$1,967 million, P$988 million and P$629 million in 2005, 2004 and 2003.

•

In 2005, Classes C, M and K Notes under the U.S.$2.5 billion Corporate Notes Program were fully prepaid in advance, in the amount of P$1,251 million (U.S.$428 million). In connection with Class F under the same program, we paid at maturity the amount of P$184 (U.S.$64 million). Petrobras Energía Venezuela S.A. and Innova S.A. paid debt owed to the International Finance Corporation (“IFC”) in the amount of P$415 million (U.S.$137 million). In addition, we repaid bank loans in the amount of P$117 million.

•

In 2004, we made principal payments on Classes C, M and K Notes under the U.S.$2.5 billion Corporate Notes Program and paid in full at maturity Class O and P Notes under that Program and the Fourth Series of the U.S.$1.2 billion Global Program, for a total payment of P$881 million. In addition, we paid P$107 million mainly in debt, principally bank loans.

•

In 2003, we paid at maturity Class E, J and L notes under our Global Notes Program in an amount of P$421 million (U.S.$146 million). In addition, we repaid bank loans and long-term lines of credit in an amount of P$208 million.

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Cash provided by long-term financing totaled P$747 million, P$669 million and P$591 million in 2005, 2004 and 2003, respectively:

•

In 2005, Petrobras Internacional Braspetro BV, a subsidiary of Petrobras, granted us a P$582 million (U.S.$200 million) loan. See Item 7. Major Shareholders and Related Party Transactions. The funds were use to pre-pay Class M and K notes. Cash provided by other bank financing totaled P$165 million (U.S.$56 million).

•

In April 2004, we issued a second Series of Class R corporate notes for a face value of U.S.$100 million, in the amount of P$289 million, which represents a single class with the Class R Notes issued in October 2003. In September 2004, Petrobras Internacional Braspetro BV granted us a P$150 million (U.S.$50 million) loan, See Item 7. Major shareholders and related Party transactions. The IFC completed the financing granted in 2003 to our subsidiary Petrobras Energía Venezuela S.A. in the amount of P$85 million (U.S.$29 million) and Petrobras Energía del Perú S.A. received financing in the amount of P$85 million (U.S.$30 million), which partly completed the financing granted in 2003 by a syndicate of Banks. In addition, cash provided by foreign trade financing totaled P$60 million.

•

In October 2003, we issued Class R notes in the amount of P$286 million (U.S.$100 million). In December 2003, the first disbursement in the amount of P$206 million (U.S.$76 million) was received under a U.S.$105 million loan entered into between Petrobras Energía Venezuela S.A. and the IFC. In August 2003, our subsidiary Petrobras Energía del Perú S.A. received a first disbursement of P$87 million (U.S.$30 million) under a loan agreement entered into with a syndicate of banks. Cash provided by other bank financing totaled P$12 million.

The cash dividends paid totaled P$41 million in 2004. This amount corresponds to dividends paid by Petrolera Santa Fe S.R.L, a company that was merged with and into Petrobras Energía S.A.

Net cash provided by short-term financing totaled P$757 million in 2005, primarily from foreign trade financing, and P$138 million in 2004, compared to P$326 million of cash used in short-term financing in 2003.

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Description of Indebtedness

Most of our financial debt and a significant portion of the debt of the Company’s main affiliates are denominated in U.S. dollars.

As of December 31, 2005, total indebtedness, excluding the proportional consolidation of companies under joint control, totaled P$5,646 million, of which P$4,367 million was long-term indebtedness. This compares to P$6,006 million and P$6,097 million as of December 31, 2004 and 2003, respectively, of which P$4,802 and P$5,009 were long term indebtedness. As of December 31, 2005, short-term indebtedness totaled P$1,279 million, of which P$106 million represents the current portion of long-term obligations and P$1,173 million represents short-term indebtedness with financial institutions under loan agreements and foreign trade financing.

Petrobras Energía maintains a global corporate note program under which possibility to issue notes will expire in May 2008, for a minimum principal amount at any time outstanding of U.S.$2.5 billion or its equivalent in any currency. This program was authorized by the CNV under Certificate N. 202 dated May 4, 1998, Certificate N. 290 dated July 3, 2002 and Certificate N. 296 dated September 16, 2003 As of December 31, 2005, notes in an aggregate principal amount of U.S.$1,077 million were outstanding under this program. Notes under the program are not subject to acceleration in the event that the credit ratings are downgraded.

The following is our debt maturity profile as of December 31, 2005:


	1 year	2 years	3 years	4 years	5 years	6 or more years
Millions of pesos	1,279	1,003	223	602	1,085	1,454

On June 9, 2005, the federal executive branch issued Executive Order 616/05, establishing that 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 the cash inflow. In addition, 30% of the amount shall be deposited with domestic financial institutions. This deposit (1) must be registered, (2) must be non-transferable, (3) must be non-interest bearing, (4) must be made in U.S. dollars, (5) must 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 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 kind of foreign financial loans.

Cross default covenants

Class 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 U.S.$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 U.S.$10 million, or 1% of our shareholders’ equity is not paid when due.

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FUTURE CAPITAL REQUIREMENTS

We estimate our investments for 2006 at approximately U.S.$650 million. This level of investments is part of our strategy for sustained growth, which we have pursued in accordance with growth and expansion targets contemplated in our business plan.

We estimate that our capital expenditure 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, the enforcement of and changes in Argentine and foreign regulations, changes in applicable taxes and royalties, and the political, economic and social situations prevailing in the countries where we operate.

Oil and Gas Exploration and Production

Our 2006 business plan focuses on the Oil and Gas Exploration and Production segment, with special emphasis on operations in Argentina and Ecuador. Projected investments in this segment will be in line with reserve replacement and production goals, as a crucial step in securing our sustainable growth.

Argentina. Efforts will continue at the Neuquén Basin to develop oil reserves through well drilling and expansion of secondary recovery projects and relevant surface facilities. Construction of gas production facilities and ducts will continue in order for the El Mangrullo Field to become operational. At the Austral Basin, investments will be directed mainly towards well drilling for the development and delimitation of oil reserves, the start-up of an interconnection system (which occured in early 2006) and a mercury removal plant. In addition, exploration activities involving seismic shooting and well drilling will be performed.

Ecuador. Development of Block 18 will continue through drilling and construction of facilities to increase treatment capacity. In Block 31, works relating to the construction of facilities and infrastructure, subject to the relevant approvals, will continue in order to prepare for the start of production activities at the Apaika Nenke Field. In addition, drilling of exploratory wells will be performed on other areas within the block.

Peru. The capital expenditure program contemplates studies and seismic shooting aimed at evaluating the exploration blocks added during 2005. In addition, drilling activities aimed at the expansion of Lote X’s primary development will continue on an intensive basis.

Refining and Distribution

In 2006, we will start certain works outlined in the refining master plan aimed at producing fuels, according to stringent quality specifications.

At the Bahía Blanca refinery, works relating to the light reformate plant and sulfur recovery unit will continue, with both works estimated to be completed by December 2006. The light reformate plant will allow us to improve the quality of our gasolines and to produce a variety with a high benzene content, a high value input for the petrochemical industry that is regulated and limited under environmental standards when used in gasolines. The sulfur recovery unit will transform this fuel contaminant into raw material for the production of fertilizers. Other significant works to be performed at the Bahía Blanca refinery in 2006 include revamping of the topping and vacuum units in order to increase installed capacity from 30,500 bbl/d to 33,300 bbl/d. These works are expected to be completed during 2008 and will allow for the processing of heavier crude oils, with increased availability and reduced purchase costs.

At the San Lorenzo Refinery, crude oil processing capacity will be expanded by 33%. In addition, a new benzene tower will be erected and a revamping of the aromatics recovery unit will be performed. These works are expected to be completed during 2006 and will allow for the processing of light reformate streams from the Bahía Blanca refinery and other suppliers of gasolines with high benzene contents.

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A new splitter tower for fluid catalytic cracking gasoline process will be erected at the Bahía Blanca refinery. This project is expected to be completed before the end of the year 2006, and it will enable us to produce gasoline with lower sulfur content, as well as to increase the production of diesel oil and also to produce components for our highest grade gasoline, Podium.

In the distribution business segment, we will continue with the rebranding of gas stations, with a view to a selective growth of new businesses and a focus on service, quality and brand development.

Petrochemicals

In 2006 in the Petrochemicals business segment, at the Puerto General San Martín Plant, equipment will be replaced in the styrene unit reaction area. This investment, in addition to the revamping of the unit distillation area, will increase installed styrene capacity from 110,000 tons/year to 160,000 tons/year. At the San Lorenzo Ethylene Plant, construction of the loading area for the dispatch of liquid ethylene will be completed. Basic, extended and detailed engineering will be completed and construction of the cooling tower will commence. Works will be completed during 2007 and will significantly contribute to a reduction in the unit’s operating costs.

Construction of Innova’s new ethylbenzene plant will start in 2006, with an initial estimated production capacity of 270 thousand tons/year.

With respect to our fertilizers business, one of the ammonia plants will be revamped to increase production capacity by 12% to 290 thousand tons/year. Operating improvements at the plant are also planned, aimed at achieving increased yield and safety for operating processes. In 2006, the potassium thiosulphate plant project will be completed and the simple superphosphate plant project will be commenced, with completion estimated by 2008. New products, which until 2005 were imported for resale, will be produced at the abovementioned plants. From the commercial viewpoint, investments will continue to be made in storage and logistics, including port facilities, in order to maintain sales of liquid fertilizers to the agricultural sector.

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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 to guarantee a portion of OCP’s financial obligations. As of December 31, 2005, we had procured letters of credit for U.S.$128 million. These letters of credit with maturity dates through December 2018, 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.

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CONTRACTUAL OBLIGATIONS

The following table summarizes certain contractual obligations as of December 31, 2005. The table does not include accounts payable. Amounts in the table do not include interest.


	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	5,646	1,279	1,226	1,687	1,454
Purchase Obligations
Ship or pay agreement with OCP ^(1)(2)(6)	2,512	184	368	368	1,592
Long–term service agreement ⁽⁶⁾	68	34	34	—	—
Bolivian gas transportation agreement ⁽⁶⁾	219	16	34	31	138
Petroleum services and materials ⁽⁶⁾	509	170	339	—	—
Gas transportation agreement with TGS ⁽³⁾⁽⁶⁾	559	62	124	124	248
Ethylene ⁽⁴⁾⁽⁶⁾	1,427	159	317	317	634
Benzene ⁽⁵⁾⁽⁶⁾	3,688	410	820	820	1,639
Gas purchase agreements for Genelba ⁽⁶⁾	105	35	70
Pension Plan Liabilities ⁽⁷⁾	128	7	17	22	82
Investment commitments	230	130	100	—	—
Total	15,091	2,486	3,449	3,369	5,722

⁽¹⁾	Net of transportation capacity sold to third parties.

⁽²⁾	Estimated price U.S.$2.30 per barrel.

⁽³⁾	Estimated price P$0.052 million per millions of cubic meters.

⁽⁴⁾	Estimated price U.S.$1,040 per ton. Contractual prices are in U.S. dollars. Peso amounts translated using exchange rate as of December 31, 2005.

⁽⁵⁾	Estimated price U.S.$949 per ton. Contractual prices are in U.S. dollars. Peso amounts translated using exchange rate as of December 31, 2004.

⁽⁶⁾

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, 2005 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.

⁽⁷⁾	To see additional information about our pension plan, please see Note 15 to our financial statements.

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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, 2005.


	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)	356	26	52	52	226
Bolivian gas transportation agreement (in millions of cubic meters)	6,352	463	974	900	4,015
Gas transportation agreement with TGS (in thousand of cubic decameters)	10,791	1,199	2,398	2,398	4,796
Ethylene (in thousands of tons)	453	50	101	101	201
Benzene (in thousands of tons)	1,283	143	285	285	570
Gas purchase agreements for Genelba (in thousand of cubic decameters)	460	153	307	—	—
Sales Obligations
Natural gas (in millions of cubic meters)	18,415	3,132	3,457	3,283	8,544
Styrene (in thousands of tons)	14	14	—	—	—
Electric power (in MWh)	1,707	1,707	—	—	—
LPG (in thousands of tons)	32	32	—	—	—

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 starting with the 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 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)”.

Bolivian gas transportation agreement: We entered into a gas transportation agreement with Transredes, in order to comply with the contract signed with YPFB, through which we export gas to Brasil.

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 firm gas 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 U.S.$97 million approximately over the period 2004-2011. As of December 31, 2005, U.S.$55 million of this amount had already been invested. In addition, we have some exploratory commitments.

We have the resources to perform an environmental impact study in Block 31, as well as 120 square km of 3D seismic readings, processing and interpretation, the reprocessing of 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 U.S.$16 million.

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Additionally, we have undertaken an investment commitment related to our share in the Cañadón del Puma area for 50% of the total U.S.$8 million commitment, to be completed by May 2006. As of December 31, 2005 the consortium had invested U.S.$5 million.

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U.S. GAAP RECONCILIATION

We had net loss under U.S. GAAP of P$77 million in 2005, as compared to net income of P$760 million in 2004 and net income of P$100 million in 2003. Under Argentine GAAP, we reported net income of P$613 million in 2005, P$678 million in 2004 and P$381 million in 2003.

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 2005 net income are mainly related to purchase price allocation and its impact on impairment, depreciation of property, plant and equipment, the accounting for derivative instruments, debt restructuring and deferred income taxes. See note 21 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 2005, 2004 and 2003 under Argentine GAAP has been reversed in the reconciliation to U.S. GAAP.

RECONCILIATION TABLES

The following tables reconciliate our results for the years ended December 31, 2003, 2004 and 2005 with proportional consolidation (as required by Argentine GAAP), with our results as adjusted to reflect the elimination of proportional consolidation:


	For the Year Ended December 31, 2005
	With Proportional Consolidation		CIESA⁽¹⁾		Distrilec⁽¹⁾		Without Proportional Consolidation
	(in millions of pesos)
Net sales⁽²⁾	10,655		(492	)	(651	)	9,512
Costs of sales	(7,058	)	249		554		(6,255	)

Gross profit	3,597		(243	)	(97	)	3,257
Administrative and selling expenses	(941	)	18		73		(850	)
Exploration expenses	(34	)	—				(34	)
Other operating income (loss) net	(329	)	3		5		(321	)

Operating income	2,293		(222	)	(19	)	2,052
Equity in earnings of affiliates	166		33		(17	)	182
Financial income (expense) and holding gains (losses)	(899	)	128		19		(752	)
Other expenses, net	(332	)	0		11		(321	)

Income (loss) before income tax and minority interest in subsidiaries	1,228		(61	)	(6	)	1,161
Income tax provision	(381	)	10		16		(355	)
Minority interest in subsidiaries	(234	)	51		(10	)	(193	)

Net income (loss)	613		—		—		613

⁽¹⁾	Both the results of CIESA and Distrilec are proportionally consolidated in our Gas and Energy segment.

⁽²⁾	Net of P$21 million in intercompany sales.

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	For the Year Ended December 31, 2004
	With Proportional Consolidation		CIESA⁽¹⁾		Distrilec⁽¹⁾		Without Proportional Consolidation
	(in millions of pesos)
Net sales⁽²⁾	8,763		(472	)	(535	)	7,756
Costs of sales	(5,791	)	219		449		(5,123	)

Gross profit	2,972		(253	)	(86	)	2,633
Administrative and selling expenses	(847	)	16		66		(765	)
Exploration expenses	(133	)	—		—		(133	)
Other operating income (loss) net	(324	)	22		17		(296	)

Operating income	1,668		(215	)	(14	)	1,439
Equity in earnings of affiliates	76		16		(13	)	79
Financial income (expense) and holding gains (losses)	(1,265	)	144		20		(1,101	)
Other expenses, net	(40	)	14		(18	)	(33	)

Income (loss) before income tax and minority interest in subsidiaries	439		(41	)	(14	)	384
Income tax provision	211		6		20		237
Minority interest in subsidiaries	28		35		(6	)	57

Net income (loss)	678		—		—		678

⁽¹⁾	Both the results of CIESA and Distrilec are proportionally consolidated in our Gas and Energy segment.

⁽²⁾	Net of P$13 million in intercompany sales.


	For the Year Ended December 31, 2003
	With Proportional Consolidation		CIESA⁽¹⁾		Distrilec⁽¹⁾		Without Proportional Consolidation
Net sales⁽²⁾	7,113		(432	)	(447	)	6,234
Costs of sales	(4,759	)	196		373		(4,190	)

Gross profit	2,354		(236	)	(74	)	2,044
Administrative and selling expenses	(770	)	30		65		(675	)
Exploration expenses	(360	)	—		—		(360	)
Other operating income (loss) net	(123	)	12		5		(106	)

Operating income	1,101		(194	)	(4	)	903
Equity in earnings of affiliates	163		219		(11	)	371
Financial income (expense) and holding gains (losses)	(387	)	(123	)	(28	)	(538	)
Other expenses, net	(447	)	1		12		(434	)

Income (loss) before income tax and minority interest in subsidiaries	430		(97	)	(31	)	302
Income tax provision	(29	)	(58	)	29		(58	)
Minority interest in subsidiaries	(20	)	155		2		137

Net income (loss)	381		—		—		381

⁽¹⁾	Both the results of CIESA and Distrilec are proportionally consolidated in our Gas and Energy segment.

⁽²⁾	Net of P$14 million in intercompany sales.

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The following tables reconciliate our statements of cash flow for the fiscal years ended December 31, 2005, 2004 and 2003 with proportional consolidation as required by Argentine GAAP to these statements as adjusted to reflect the elimination of proportional consolidation.


	For the Year Ended December 31, 2005
	With Proportional Consolidation		CIESA		Distrilec		Without Proportional Consolidation
	(in millions of pesos)
Cash and cash equivalent at the beginning of the year	1,067		168		53		846
Net cash provided by operations	1,998		299		73		1,626
Net cash used in investing activities	(1,682	)	(84	)	(54	)	(1,544	)
Net cash used in financing activities	(602	)	(126	)	(13	)	(463	)
Effect of exchange rate change on cash	9		—		—		9

Cash and cash equivalent at the end of the year	790		257		59		474


	For the Year Ended December 31, 2004
	With Proportional Consolidation		CIESA		Distrilec		Without Proportional Consolidation
	(in millions of pesos)
Cash and cash equivalent at the beginning of the year	1,091		336		46		709
Net cash provided by operations	1,632		62		132		1,438
Net cash used in investing activities	(1,199	)	(49	)	(78	)	(1,072	)
Net cash used in financing activities	(451	)	(181	)	(48	)	(222	)
Effect of exchange rate change on cash	(6	)	—		1		(7	)

Cash and cash equivalent at the end of the year	1,067		168		53		846


	For the Year Ended December 31, 2003
	With Proportional Consolidation		CIESA		Distrilec		Without Proportional Consolidation
	(in millions of pesos)
Cash and cash equivalent at the beginning of the year	1,014	(i)	103		32		879
Net cash provided by operations	1,532		263		87		1,182
Net cash used in investing activities	(958	)	(31	)	(27	)	(900	)
Net cash used in financing activities	(409	)	1		(46	)	(364	)
Effect of exchange rate change on cash	(88	)	—		—		(88	)

Cash and cash equivalent at the end of the year	1,091		336		46		709

(i)	This amount includes cash and cash equivalents from proportional interest in CIESA at the beginning of the year in the amount of 103.

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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 twenty-one 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 April 28, 2006.

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
Decio Fabricio Oddone Da Costa	2005	—	Chairman	2006
Daniel Lima de Oliveira	2006	—	Vice Chairman	2006
José Eduardo de Barros Dutra	2003	—	Director	2007
André Garcez Ghirardi	2006	—	Director	2007
Carlos Tadeu da Costa Fraga	2006	—	Director	2006
Solange da Silva Guedes	2006	—	Director	2006
Venina Velosa da Fonseca	2006	—	Director	2007
Sydney Granja Affonso	2006	—	Director	2006
Alberto da Fonseca Guimarães	2003	2002	Director	2007
Cedric Bridger	2004	—	Director	2007
Tomás Marcos Fiorito	2004	—	Director	2006
Nicolas Perkins	2004	—	Director	2006
Luis Miguel Sas	2003	1984	Director	2006
Carlos Alberto Pereira de Oliveira	2004	2003	Director	2007
João Bezerra	2006	2006	Director	2006
Vilson Reichemback Da Silva	2005	2004	Director	2007
Héctor Daniel Casal	2003	1991	Director	2007
Claudio Fontes Nunes	2006	2006	Director	2007
Rui Antonio Alves da Fonseca	2006	2003	Director	2007
Heitor Cordeiro Chagas	2006	2006	Alternate Director	2006
Geraldine Trouilh	2006	—	Alternate Director	2006

In compliance with Resolution No. 368 of the National Securities Commission (CNV), Nicolas Perkins, Tomás Marcos Fiorito and Geraldine Trouilh qualify as independent directors, and the other directors are not independent in accordance with the (CNV) 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) from, the issuer or from its shareholders that hold either directly or indirectly significant interests in or

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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:

Decio Fabricio, Oddone Da Costa (45) graduated in Electrical 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 Harvard University Business School and the Advanced Management Programme at the Insead, France. He received an honorary Master Degree in Management and Administration from the Alta Escuela de Dirección y Administración de Empresas in Madrid, Spain, and an Honoris Causa Doctoral Degree in education from Aquino’s University, Bolivia. He has occupied several managerial positions within Petrobras in Brazil, Argentina, Angola, Libya and Bolivia where he held the position of President of Petrobras Bolivia S.A. and other companies of the group. Currently he also is responsible for Petrobras’s Activities in Cono Sur. He also acts as President of Petrobras subsidiary companies in Bolivia, Uruguay, Chile, Paraguay and Spain and as a member of the board of Petrobras Energía and other companies of the Petrobras group.

Daniel Lima de Oliveira (54) graduated in 1975, with a Mechanical Engineering degree from Industrial Engineering School in S.J. dos Campos. In 1976 he joined Petrobras as a supply engineer in the Commercial Department. In 1982 he moved to the Financial Department of Petrobras, having work in the Short Term Credit Division, and as Assistant to the General Manager. From 1984 to 1988 he served as Financial Manager of the Petrobras London Office. From 1988 to 1992 he worked as manager at Braspetro, responsible for insurance and financing for the Company foreign operations. From 1992 until 1995 he served as head of the Medium and Long Term Credit Division with the responsibility for raising funds to the company investment program. From 1995 to 1999 he was assigned to the Petrobras New York Office as Financial Manager, responsible for negotiating trading lines, supporting the Head Office in structured transactions, Investor Relations and liaising with U.S. and Canadian export agencies. From September 1999 to July 2005 he was designated Deputy Executive Manager of the Financial Department with the responsibility for coordinating financial activities among several subsidiaries. In this position he has served on the Board of Directors of the following subsidiaries: BRASOIL, CATLEIA, PIB BV, Petrobras Participaciones S.L., POG, PEMID, PEL, FRADE INVERSIONES. In March 2004 he was appointed as member to the board of REFAP S/A. Since July 2005 he has been the Executive Manager of Petrobras Corporate Finance. Currently, he is member of the Board of Directors of Petrobras Energía.

José Eduardo de Barros Dutra (50) 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’

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Party from 1996 to 1997, and as a member of the Workers’ Party National Executive Committee. From January 2003 to August 2005 he was appointed Chairman of Petrobras. Currently, he is member of the Board of Directors of Petrobras and of Petrobras Energía.

André Garcez Ghirardi (55) graduated in Industrial Engineering from Universidade de São Paulo, Brazil, where he also pursued graduate studies in Operations Research. He has a Masters Degree from the Massachusetts Institute of Technology with dissertation on Strategic Petroleum Stockpiling. He holds a Ph.D in Energy and Resources from the University of California Berkeley, with a thesis on the Use of Alcohol Fuels in Brazil. He is a former staff member of U.S. Department of Energy’s Lawrence Berkeley Laboratory, in Berkeley, California, where he conducted studies on energy demand in Latin America and West Africa. He is on leave from the School of Economics at Universidade Federal da Bahia where he holds an Associate Professorship teaching Energy Economics and Econometrics at graduate and undergraduate levels. He has conducted studies on the reform of the electric power sector in Brazil, and has worked as consultant for COELBA, the electric power distribution company in the state of Bahia, Brazil. He served as assistant to the Chief Financial Officer of Petrobras, and currently serves as adviser to the Chief Executive Officer of Petrobras. Currently, he is member of the Board of Directors of Petrobras Energía.

Carlos Tadeu da Costa Fraga (48) graduated with a Bachelors Degree in Civil Engineering from UFRJ (Federal University of Rio de Janeiro) in 1980. He joined Petrobras Energía in 1981, where he attained his qualification in Petroleum Engineering. He has participated in several technical and managerial training programs in Brazil and overseas, including a course in Petroleum Engineering at Alberta University, in Canada, a course in Business Management at Columbia University, in New York, a course in Technology Management at INSEAD, in France, and a course in Strategic Leadership at London Business School. He held many executive managerial positions, as the manager of major deepwater operations both in Brazil and in the Gulf of Mexico. Since 2003 he has been the head of Petrobras Research & Development Center, being responsible for all Research & Development and basic engineering projects, on upstream, downstream and renewables areas. Currently, he is a member of the Board of Directors of Petrobras Energía.

Solange da Silva Guedes (45) graduated in Civil Engineering from the Federal University of Juiz de Fora in 1982. She joined Petrobras in 1985, when she took a specialization course in Petroleum and Production Engineering at the Petrobras University. In 1988 she got a M. Sc. degree in Civil Engineering from the Federal University of Rio de Janeiro (UFRJ). In 1998 she attended a Doctoral program at the State University of Campinas (UNICAMP). In November 2000, she was designated Marlim South Reservoir Sector Manager of the Exploration and Production Business Unit. Since 2003 she has been Executive Manager for Exploration and Production for the North and Northeast region in Petrobras. She is member of the Board of Directors of Petrobras Energía.

Venina Velosa da Fonseca (43) graduated in Geological Engineering from Ouro Preto Federal University. She took a specialization course in Petroleum Geology (CIGEP-UFRJ) and an improvement course in Petroleum Geology and obtained an MBA degree in Economy and Management of Natural Gas and Energy. She joined Petrobras in 1990 and has since held several positions, including Manager of Implementation of Integrated Management Systems and Downstream Manager. Currently she is Executive Manager of Corporate Downstream. She is a member of the Board of Directors of Petrobras Energía.

Sydney Granja Affonso (54) graduated in Mechanical Engineering from the School of Engineering of Universidade Federal do Rio de Janeiro. He joined Petrobras–UFRJ in 1977 as Equipment Engineering, after taking a course in Industrial Equipment and Systems (CEMANT - Petrobras - UFRJ). He served in several areas of Petrobras: Information Resource Planning, Petrobras System Planning Division and Strategic Analysis, Gas and Power Planning, and Business Performance General Manager. Since July 2003 he has served as Planning General Manager of the Gas and Energy business unit in Petrobras. Currently, he serves as Executive Manager for Natural Gas Logistics and Partnerships, and he is a member of the Board of Directors of Petrobras Energía.

Alberto da Fonseca Guimarães (56) graduated in Mechanical Engineering from UNESP, Guaratingueta, São Paulo State. He holds a MBA degree in Administration from Coppead, Rio de Janeiro and has attended the Industrial Marketing Program of INSEAD, France. 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 he served seven-year term as Commercial Manager of Petrobras in New York and London. He was the Executive Manager of New Business Development when Perez Companc and EG3 controls were acquired by

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Petrobras. Currently, he is a Director and Chief Executive Officer of Petrobras Energía. He is also a Director of Petrolera Entre Lomas S.A.

Cedric Bridger (70) 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 S.A.and President of Patagonia Natural Products S.A.

Tomás Marcos Fiorito (33) graduated cum laude in Law from Universidad Católica Argentina. He has a Master’s Degree in Law from Harvard Law School, U.S.A being Fulbright Scholar and a YPF Foundation Scholar. In 1998 and 1999 he worked as a lawyer at Latham & Watkins in New York, U.S.A. From June 2000 to January 2004, he worked at the law firm of Bruchou, Fernandez Madero, Lombardi & Mitrani where his practice was devoted primarily to mergers and acquisitions, advice to banks and large companies and financial debt restructuring. Since February 2004 he has worked at the law firm of Fortunati & Lucero Abogados.

Nicolas Perkins (33) graduated in Law from Universidad Católica Argentina in 1995. He obtained a Masters Degree in Comparative Jurisprudence from New York University in 1998. From 1996 to 1998, he worked as an associate at the law firm Cárdenas, Cassagne & Asociados, 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 Legal Counsel for Latin America for Schlumberger-Schlumbergersema. He is currently a partner of Fortunati & Lucero law firm.

Luis Miguel Sas (43) 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 Austral. He joined Petrobras Energía in 1984. In 1990 he was appointed head of the Financial Operations Division when Petrobras Energía took over Telecom Argentina S.A. 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 Hispano Argentina S.A. and Petrobras de Valores Internacional de España S.A., as Vicepresident of Petrobras Energía Internacional S.A., and as Director of Petrobras Energía, World Energy Business and Distrilec. He is also a Member of Supervisory Board of Petrobras Holding Austria AG.

Carlos Alberto Pereira de Oliveira (48) graduated in Mechanical Engineering from the Instituto Militar de Engenharia of Rio de Janeiro and in Administration at the Federal University of Rio de Janeiro, both in 1980. He specialized in petroleum engineering at Petrobras in 1981 and in Petroleum Finance and Administration at the University of Texas in 1997. He has a Master in Finance and Investments at the Pontifícia Universidade Católica of Rio de Janeiro. He entered in Petrobras in 1981 and assumed several executive positions, as Reserves and Reservoir General Manager from 1997 to 1998 and Exploration and Production Executive Manager from 1999 to 2003. He is currently Director of the Oil and Gas Exploration and Production Business Unit of Petrobras Energía S.A. and Director of Petrobras Energía, Petrobras Energía Perú S.A. and Petrolera Entre Lomas S.A.

João Bezerra (48) has a degree in Electrical Engineering from Pernambuco Federal University and holds a Ph.D from Cranfield University, England, where he developed a GETI management model that guarantees a balance of interests among the stakeholders of a business. He joined Petrobras in 1986 and served in the Exploration and Production, Refining, Quality, Human Resources, Business Development and Market Integration areas. As Manager of Business Development, he conducted the process involving the acquisition of EG3, Pecom Energía S.A. and Petrolera Perez Companc S.A. He currently performs as Chairman of TGS, Citelec, TRANSBA S.A., C.I.E.S.A. and Distrilec and as Vice Chairman of Edesur, Companía. Mega S.A. and Transener. He presently performs as Director of Gas and Energy and member of the Board of Directors of Petrobras Energía.

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Vilson Reichemback Da Silva (55) graduated in Law from the Universidade Federal do Ceará in 1995. He currently serves as Vice Chairman of EG3 RED S.A. and EG3 Asfaltos S.A. He is also Director of the Commercial Downstream Business Unit and Director of Petrobras Energía.

Héctor Daniel Casal (50) graduated in Law. He serves as Director 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, Transener, Transba, Petrolera Entre Lomas S.A., Petrobras Financial Services Austria Gmbh, Petrobras Holding Austria and as an alternate Director of Edesur.

Claudio Fontes Nunes (51) graduated in Civil Engineering specialized in Hydraulic Works from Universidade Federal do Rio de Janeiro. He specialized in Petroleum Engineering at Petrobras. He is also a graduate of the Advanced Management Program from Harvard University. He joined Petrobras in 1980 and was in charge of Well Evaluation Operations, Projects Analysis, Contracts, Production Engineering, Engineering and Health, Safety and Environment. He currently serves as Director of Services and member of the Board of Directors of Petrobras Energía.

Rui Antonio Alves da Fonseca (49) majored in Mechanical Engineering at Universidade Federal do Rio de Janeiro and completed MBA courses for managers and executives at 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 Director of Quality, Environment, Safety and Occupational Health and member of the Board of Directors of Petrobras Energía.

Heitor Cordeiro Chagas (61) graduated in Law from Universidad Federal Fluminense. He specialized in Human Resource Development at Getúlio Vargas Foundation, Rio de Janeiro, where he worked as professor and served on the Governing Board. He is a widely experienced consultant and lecturer. He received an award twice from the Brazilian Human Resource Association. He was responsible for the Human Resource Department in two opportunities at Petrobras S.A. and other public and private agencies including, among others, Banco Boavista, BANERJ, the Federal Administration Secretary and the Ministry of Health. . He also served as Corporate Affairs Director at Xerox of Brazil and Director of PETROQUISA. He currently holds the position of Director of Human Resources and member of the Board of Directors of Petrobras Energía.

Geraldine Trouilh (32) graduated in Law from Universidad de Buenos Aires in 1998 and since then she has been a member of the “Colegio Público de Abogados de la Capital Federal” (Federal Capital Bar Association). In April 2003 she joined Fortunati & Lucero Law Firm. From 1996 to 2003 she worked as lawyer at Cárdenas, Cassagne & Asociados Law Firm. Her main areas of practice are Banking Law, Commercial Law, Contract Law, Corporate Law, Finance, Investments and Trusts.

Administration and Organization

Our operations are conducted through Petrobras Energía. Petrobras Energía’s operations are divided into four business segments that are in turn supported by corporate functions. The four business segments are: Oil and Gas Exploration and Production, Refining and Distribution, Petrochemicals and Gas and Energy.

Petrobras Energía is managed by a committee made up of 7 members: the Chief Executive Officer, the Chief Financial Officer, the Director of each business unit and the Director of Services. 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

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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 A. Pereira de Oliveira		Director of Oil and Gas Exploration and Production Business Unit
Carlos Alberto de Meira Fontes		Director of Refining and Petrochemicals Business Units
João Bezerra		Director of Gas & Energy Business Unit
Vilson Reichemback Da Silva		Director of the Commercial Downstream Business Unit
Heitor Cordeiro Chagas		Director of Human Resources
Héctor Daniel Casal		Director of Legal Affairs
Claudio Fontes Nunes		Director of Services
Rui Antonio Alves da Fonseca		Director of Quality, Environmental and Safety and Occupational Health
Michael Ditchfield		Executive Manager of Planning and Management Control
Pablo Maria Puiggari		Executive Manager of Communications

The following is a brief summary of the principal business and academic experience of Petrobras Energía’s executive officers who are not also directors (for the summary regarding executive officers who are directors, see above).

Carlos Alberto de Meira Fontes (56) 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. and Petroquímica Triumfo, among others.

Michael Ditchfield (43) graduated both in Economic Sciences from University of Rio de Janeiro and Civil Engineering from the Federal University of Rio de Janeiro. He obtained an MBA with a concentration in Finance and Strategy from the London Business School. Since 1991 he has held several executive positions at Petrobras, including General Manager of Petrobras in London, Executive Manager of Planning and Services of Petrobras International Area, CFO and member of Petrobras Internacional’s Board of Directors. He has a vast experience in finance, acquisitions and merger and integration processes, strategic planning, business management support, implementation of management systems in several countries, corporate matters and assessment, purchase and sale of companies. He is currently a member of the Board of Directors of World Energy Business S.A. and a member of the Supervisory Board of Petrobras Holding Austria AG

Pablo María Puiggari (43) graduated in Law from Buenos Aires University. He completed post-graduated courses in Mass Communications from Boston University (College of Communications) where he received an Honorary Masters Degree. He has occupied several managerial positions in Petrobras Energía, such as Institutional Relations Manager and Publicity Sponsorships Manager.

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

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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 the staff, such as life insurance, health care plan, meal allowance, and defined benefits plan, which is described in the Financial Statements.

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 2005, we paid an aggregate of approximately P$12 million to our directors and to the executive officers of Petrobras Energía.

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. 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. 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.

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 April 28, 2006, Cedric Bridger, Tomás Marcos Fiorito and Nicolás Perkins were appointed as regular members of the Audit Committee and Geraldine Trouilh was appointed as an alternate member.

Once per year our Audit Committee prepares a working plan with respect to the Audit Committee’s goals and work schedule for the fiscal year to be reported to the Board of Directors. The remaining directors, members of the Statutory Syndic Committee, managers and external auditors will be bound, at the Audit Committee’s request, to attend the Committee’s meetings, assist the Committee and provide it with any information available to them. For a

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better performance of its duties, the Committee may retain, on the Company’s account, advisory services of a counsel and other independent professionals on the basis of a budget previously approved at the Shareholders’ Meeting. The Committee shall have access to the information and documentation deemed necessary for the fulfillment of its functions.

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.

•

To opine with respect to the reasonableness of the compensation and stock option plans proposed by the Board of Director at the meetings.

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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.

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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.

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To issue an opinion on the proposal submitted by the Board for the appointment (or revocation) of the independent auditor and communicate it to the shareholders’ meeting.

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To evaluate the qualifications and independence of the independent auditors.

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To issue and maintain pre-approval procedures in connection with any service (whether audit-related or not) to be provided by the independent auditor, under which the Committee will be exclusively authorized to pre-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.

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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 April 28, 2006:


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 the Board of Directors’ and 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.

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.

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 (61) graduated in Public Accounting from Universidad de Buenos Aires. He is currently a Head of Cincotta Asesores, formerly a partner at Ernst & Young, Grant Thornton and 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 and Member of the Developing Nations Committee of the International Federation of Accountants (IFAC). He is currently a member of the Statutory Syndic Committee of Petrobras Energía.

Justo F. Norman (61) 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, oil and gas regulations 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 has served 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 National Berhad (Petronas). He is a Regular Director of Noranda Exploración Argentina S.A., Petronas Argentina S.A. and Apache Petrolera Argentina S.A., among others. He is also a member of the Statutory Syndic Committee of Petrobras Energía S.A.

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Rogelio N. Maciel (70) 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 (70) 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 (33) 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.

Maria Laura Maciel (43) graduated in Law from Universidad Católica 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$0.04 million in 2005.

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EMPLOYEES

The following table sets out the number of our employees by business segment for the fiscal years ended December 31, 2005, 2004 and 2003.


	As of December 31,
	2005	2004	2003
Oil and Gas Exploration and Production	1,053	987	897
Refining and Distribution	2,872	2,918	2,793
Petrochemical	210	208	197
Gas and Energy	104	95	95
Corporate and Discontinued Investment	797	746	811

Total	5,036	4,954	4,793

Currently, 39% 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.

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Item 7.

MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS

MAJOR SHAREHOLDERS

Our share capital consists of 2,132,043,387 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 (formerly Petrobras Participaçoes 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 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 May 31, 2006 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.	1,249,716,746	58.6	%

RELATED PARTY TRANSACTIONS

Related party 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 received 230,194,137 newly issued Class B shares of Petrobras Energía, representing 22.8% of Petrobras Energía’s capital stock. As a result of the merger, our ownership interest in Petrobras Energía decreased from 98.21% to 75.82%.

As part of the Petrobras group, and taking into account the synergies of our business with those of Petrobras, we seek to identify and exploit opportunities and initiatives that offer benefits to both companies.

In 2005, we agreed to acquire from Petrobras a 10% interest in the Tierra Negra Block in Colombia. We will pay U.S.$1.4 million for this transaction. The entrance into Colombia, in association with Petrobras, which already had major operations in that country, opens us new prospects for the development of our exploration and production business.

Since 2003, we have been using the Petrobras brand in our service stations. Petrobras has built an excellent brand image, 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.

We have entered into several financing arrangements with subsidiaries of Petrobras. In September 2004, Petrobras Internacional Braspetro BV, a subsidiary of Petrobras, granted a U.S.$50 million loan, with an interest rate of 7.5% per annum. The loan is repayable semiannually over 42 months and may be prepaid without penalties. In 2005, we entered into a U.S.$200 million loan facility with Petrobras Internacional Braspetro BV. This loan has a term of ten years and bears interest at an a nnual interest rate

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of 7.22%, plus 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 debt repayments made during 2005 was financed with loans provided by Petrobras.

Petrobras Energía provided the funds to provisionally finance on account and on behalf of Petrobras the expansion of TGS’s pipeline transportation capacity by approximately 2.9 million cubic meters per day. TGS and the Argentine government, among others, agreed that Petrobras would be the project’s financing arranger and Petrobras would request that Banco Nacional de Desenvolvimento Económico e Social de Brasil (“BNDES”) – or any other institution to be appointed by Petrobras – grant and document a loan to finance works for an amount of at least U.S.$142 million or Petrobras would otherwise obtain the resources and/or contribute the funds, until the loan is disbursed. On February 25, 2005, Petrobras Energía’s Board of Directors approved entry into a loan agreement with Petrobras Internacional Braspetro BV, for an amount of up to U.S.$142 million at an annual 5.35% interest rate payable twice per year, free of tax withholdings, for a term of up to three years. On May 25, 2005, BNDES made the first disbursement, making the financing effective. Total disbursements made by Petrobras Internacional Braspetro BV to finance Petrobras Energía’s contributions on account and behalf of Petrobras, totaled U.S.$41.8 million. In July 2005 this loan was cancelled.

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 U.S.$22.87 per barrel. We paid a premium of P$12 million for this option.

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Material transactions with our related entities (including companies under joint control) for the years ended December 31, 2005, 2004 and 2003, are as follows (in millions of pesos):


	2005		2004		2003
Company	Purchases	Sales	Purchases	Sales	Purchases	Sales
Oleoductos del Valle S.A.	15	—	20	—	17	—
Transportadora de Gas del Sur S.A.	30	—	35	—	13	—
Refinería del Norte S.A.	122	82	77	46	57	43
Petrobras International Finance Co.	118	977	121	488	47	209
Petrolera Entre Lomas S.A.	344	1	198	—	118	—
Petróleo Brasileiro S.A.	—	10	—	240	6	155
Petrobras Bolivia Refinación.S.A.	3	34	—	36	—	—

Total	632	1,104	451	810	258	407

The outstanding balances as of December 31, 2005, 2004 and 2003 from transactions with related companies (including companies under joint control) are as follows (in millions of pesos):


	2005
	Current						Non-current
Company	Investments	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Loans	Other receivables	Investments	Loans
Petroquímica Cuyo S.A.	—	8	4	—	—	6	—	—	—
Oleoducto de Crudos Pesados Ltd.	—	—	—	—	—	—	—	142	—
Transportadora de Gas del Sur S.A.	—	9	—	6	—	—	—	—	—
Refinería del Norte S.A.	—	17	5	40	—	—	—	—	—
Petrobras International Finance Co.	—	95	—	5	—	—	—	—	—
Petróleo Brasileiro S.A. -Petrobras	—	3	15	17	—	—	3	—	—
Petrolera Entre Lomas S.A.	2	—	—	69	—	—	—	—	—
PROPyME	—	—	—	—	—	—	—	6	—
Petrobras Internacional - Braspetro B.V.	—	—	25	—	—	20	—	—	758
Others	—	2	7	2	2	—	—	2	—

Total	2	134	56	139	2	26	3	150	758


	2004
	Current						Non-current
Company	Investments	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Loans	Trade Receivables	Investment	Other Receivables	Loans
Petroquímica Cuyo S.A.	—	—	1	—	—	6	—	—	—	—
Oleoductos de Crudos Pesados Ltd.	—	—	—	—	—	—	—	156	—	—
Petrolera Entre Lomas S.A.	—	—	—	46	—	—	—	—	—	—
Transportadora de Gas del Sur S.A.	—	1	—	3	1	—	—	—	—	—
Refinería del Norte S.A.	—	9	6	17	—	—	—	—	—	—
Petrobras International Finance Co.	119	23	—	5	—	—	—	—	—	—
Petróleo Brasileiro S.A.- Petrobras	—	11	9	—	—	—	—	—	—	—
Petrobras Internacional - Braspetro B.V.	—	—	—	—	—	4	—	—	4	149
Others	—	4	2	7	1	—	3	—	—	—

Total	119	48	18	78	2	10	3	156	4	149


	2003
	Current					Non-current
Company	Investments	Trade Receivables	Other Receivables	Accounts Payable	Loans	Investment	Other Receivables
Petroquiinica Cuyo S.A.	—	—	—	—	6	—	—
Oleoducto de Crudos Pesados Ltd.	—	—	—	—	—	127	—
Transportadora de Gas del Sur S.A.	—	9	—	4	—	—	—
Refineria del NorteS.A.	—	3	3	—	—	—	—
Petroleo Brasileiro - Petrobras	—	10	5	—	—	—	—
Petrobras International Finance Co.	111	22	—	—	—	—	—
Petrolera Entre Lomas S.A.	—	—	—	36	—	—	—
Others		—	3	1		—	5

Total	111	44	11	41	6	127	5

We do not have any other material related party transactions.

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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.

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 U.S. dollars. The deposit agreement provides that the depositary will convert cash dividends received by the depositary in pesos to U.S. dollars and, after a deduction or upon payment of fees and expenses of the depositary, will make payment to holders of our ADSs in U.S. dollars.

The source of funds for the payment of cash dividends will be the dividends received from our controlled company, Petrobras Energía. 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%.

We did not pay dividends in 2005, 2004 or 2003.

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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
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
2005
Quarterly
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
2005
First Quarter	14.47	10.98	4.16	3.25
Second Quarter	12.59	10.95	3.63	2.20
Third Quarter	16.17	11.43	4.64	3.22
Fourth Quarter	16.28	11.45	4.61	3.51
Monthly
December 2005	12.81	11.45	3.82	3.51
January 2006	13.33	12.54	4.08	3.79
February 2006	12.7	11.7	3.87	3.62
March 2006	12.52	11.1	3.89	3.40
April 2006	12.09	10.76	3.64	3.28
May 2006	12.70	9.85	3.83	3.02
June 2006⁽³⁾	10.73	9.91	3.27	3.06

⁽¹⁾	Amounts expressed in U.S. dollars.

⁽²⁾	Amounts expressed in Argentine pesos.

⁽³⁾	Through June 16, 2006.

On May 31, 2006, there were approximately 27.5 million ADSs outstanding. Our ADSs represented approximately 12.8% of the total number of issued and outstanding Class B shares as of May 31, 2006.

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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:


	2005		2004		2003		2002		2001
Market capitalization (billions of pesos)	771		690.0		543.3		348.1		192.5
As percent of GDP⁽¹⁾	163	%	152	%	144	%	111.2	%	70.9	%
Volume (in millions of pesos)	19,938		14,113		8,844		4,117		7,519
Average daily trading volume (in millions of pesos)	79.12		56.0		35.52		17.5		30.9
Number of listed companies⁽¹⁾	87		85		110		117		119

⁽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 or IGJ) 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 and on August 17, 2005 under number 8492, book 28 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 Companies 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.

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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 companies 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 annual 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 and applicable ADS agreements.

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 is 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 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 Companies 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 offshore 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 offshore 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. Companies are free to opt out of the decree-law’s requirements, provided they do so expressly in their by-laws. We, with the approval of our shareholders, have opted out of the requirements of this decree-law. This does not prevent an acquiror from voluntarily commencing an offer for all our shares.

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 U.S.$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 (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	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 was an employee of the issuer 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 payable to a director. “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 management of the relevant

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Section of the NYSE Listed Company Manual	New York Stock Exchange Corporate Governance Rules for Domestic Issuers	Our Practices

	which, in any single fiscal year, exceeds the greater of U.S.$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.	entity or of its controlling shareholders. Nicolas Perkins, Tomás Fiorito, and Geraldine Trouilh 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, Héctor Daniel Casal, Luis Miguel Sas, João Bezerra, Vilson Reichemback da Silva, Claudio Fontes Nunes and Rui Antonio Alves da Fonseca, in addition to serving on our Board, have management positions. Our other eleven 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, and 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, and 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. Our Audit Committee is composed of three directors, who each satisfy the independence requirements of Rule 10A-3. Our Audit Committee members do not need to satisfy the NYSE independence standards other than those required by Rule 10A-3. One member of our audit committee, Mr. Cedric Bridger, qualifies as “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 Board of Director’s and management’s compliance with the Argentine Companies Law, our by-laws and our 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 ordinary 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 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—Off Balance Sheet Transactions” and “Item 5. Liquidity and Capital Resources”.

On September 1, 2005, CIESA, its current shareholders and creditors entered into a Restructuring Agreement relating to CIESA’s debt. See “Item 4. Information About the Company— Gas and Energy — Gas Transportation—TGS—Regulated Energy Segment” and Exhibit 4.6 to this annual report.

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 U.S. 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

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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).

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 U.S. 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.

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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.

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 Argentine Companies Law 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%.

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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 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 U.S. 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 U.S. dollar amount of dividends received by an individual U.S. holder prior to January 1, 2011 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 passive foreign investment company (a “PFIC”). 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 for United States federal income tax purposes with respect to our 2004 or 2005

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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 2006 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 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 made 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 U.S. 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 U.S. dollars at that time. You will have a tax basis in such pesos for United States federal income tax purposes equal to the U.S. 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 U.S. 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

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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.

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 100 F Street, N.E., 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 have been required to make filings with the SEC by electronic means since November 4, 2002. 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 our business integration strategy, allows for efficient growth in the vertical integration of our business, while balancing market risks in the business value chain.

Within this context, the Company’s management evaluates from time to time the possibility of using hedging derivative instruments. These financial operations, when and if used by us, might expose us to credit risk of our counterparts. We apply strict requirements for the approval of lines of credit, and we also 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).

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 Distribution, and Petrochemicals businesses we are exposed to market risk in relation to price volatility, mainly of crude oil and by-products. In Argentina, as the Company grows as an integrated energy company and assigns a greater portion of its crude oil production to processing at the Company’s own refineries, we are increasingly principally exposed to risks from the price volatility of oil products rather than to the volatility of crude oil.

Historically, we have prioritized a risk strategy that, principally through swaps, producer collars and options, was designed to set crude oil sale prices at certain intervals. As of the date of this annual report, we do not have a position in any derivative instruments, but we may decide to enter into derivative instruments in the future.

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, 2005, a significant portion of our and our affiliates’ debt was denominated either directly or indirectly in U.S. dollars. This exposes us to foreign exchange risks. Diversification of the Company’s businesses with foreign operations having a cash flow primarily denominated in U.S. dollars, commodity prices that are sensitive to dollar price changes and an export-oriented trade policy for oil products, help us mitigate our U.S. dollar-exposure.

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In addition, we make forward sales of U.S. dollars in exchange for Argentine pesos. As of December 31, 2005, the nominal value of effective contracts amounted to U.S.$52 million at an average exchange rate of P$3 per U.S.$1.

Interest rate risks

Interest rate risk management mainly aims at reducing overall financial costs and adjusting our exposure to increasing interest rates.

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, 2005, approximately 86% our total financial debt was subject to fixed rates and 14 % 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 certain liquid financial assets or marketable securities, with remuneration determined by LIBO or a similar rate.

Quantitative Disclosure

The chart below provides quantitative information about our financial debt as of December 31, 2005, that is sensitive to changes in interest rates and foreign exchange rates.

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Foreign Currency Exchange Rate Risk and Interest Rate Risk:


	Expected Maturity
	2006	2007	2008	2009	2010	Thereafter	Total	Estimated Fair Value
	(in millions of pesos)
Short- and Long-Term Debt
U.S. dollar:
Fixed Rate	1,130	917	162	550	1,058	1,212	5,029	5,158
Average interest rate (%)	5.3	8.7	7.4	9.0	8.1	8.3	—	—
Variable rate	149	86	61	52	27	242	617	617
Average interest rate (%)	6.7	6.7	7.2	7.0	6.1	5.6	—	—

Pesos converted to U.S. dollar:
Fixed Rate		—	—	—	—	—
Average interest rate (%)		—	—	—	—	—	—	—

Total	1,279	1,003	223	602	1,085	1,454	5,646	5,775

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	1,279	4,367	5,646
PEPSA’s interest in Distrilec’s debt obligations	83	109	192
PEPSA’s interest in CIESA’s debt obligations	443	1,232	1,675

Debt obligations⁽²⁾ with proportional consolidation	1,805	5,708	7,513

⁽¹⁾	As reported in tabular presentation.

⁽²⁾	As reported in the consolidated balance sheet of our financial statements.

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Items 12-14

NOT APPLICABLE

Item 13.

NOT APPLICABLE

Item 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, 2005. 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 our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the applicable rules and forms, and that it is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate to allow timely decisions regarding required disclosure

(b) There has been no change in our internal control over financial reporting during 2005 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.

This effort is conducted 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. The company is adopting a framework of internal control over financial reporting based on the recommendation of the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The COSO framework is the prevailing system adopted by companies subject to Section 404 of the Sarbanes-Oxley Act.

The project team maintains regular communications with the Audit Committee of the Board, so that our management, with the oversight of the Audit Committee, may comply with all the requirements established in Section 404. In this framework, the Company is implementing some initiatives to enhance the effectiveness of the internal control over financial reporting.

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Item 16A.

AUDIT COMMITTEE FINANCIAL EXPERT

Our Board of Directors has determined that Cedric Bridger is an “audit committee financial expert”, and that Mr. Bridger is independent, 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 and our chief financial officer, 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 Martiny 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, 2005 and 2004 in each of the following categories are:


	Year ended December 31,
	2005	2004
	(in thousands of pesos)
Audit fees	6,366	6,001
Audit-related fees	3,052	2,764
Tax fees	154	235

Total fees	9,572	9,000

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.

Independent Auditors. From the year ended December 31, 2003 through December 31, 2005, Pistrelli, Henry Martin y Asociados S.R.L., a member firm of Ernst & Young Global, served as our independent auditors and audited our financial statements for each of the years ending December 31, 2005, 2004 and 2003. The Shareholders’ Meeting of Petrobras Energía Participaciones held on April 28, 2006 designated Sibille, member firm of KPMG, as our independent auditors for the year ended December 31, 2006.

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.

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Item 16D.

NOT APPLICABLE

Not applicable.

Item 16E.

PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS

From January 1, 2005 to December 31, 2005, no purchases were made by or on behalf of us or any affiliated purchaser of our ordinary shares or ADSs.

Item 17.

NOT APPLICABLE

Not applicable.

Item 18.

FINANCIAL STATEMENTS

Reference is made to pages F-1 to F-122 of this annual report.

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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		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. *****

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		Sixth Supplemental Trust Deed dated May, 1997 between Petrobras Energía Participaciones S.A. and Citicorp Trustee Company Limited.*

2.4		Form of U.S.$323,500,000 Restricted Global Note and Form of U.S.$76,500,000 Unrestricted Global Note, related to Petrobras Energía’s 8.125% notes due 2007.*

2.5		Indenture dated May 1, 1998 between Petrobras Energía Participaciones, S.A. and Citibank, N.A., as Trustee.*

2.6		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.**

2.7		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.**

2.8		Amended and Restated Indenture, dated August 1, 2002, amending and restating the Indenture dated May 1, 1998, between Petrobras Energía and Citibank, N.A.**

2.9		Loan Agreement Number 0088/2005, dated February 21, 2005, between Petrobras Energía, as borrower, and Petrobras International Braspetro BV., as lender (English translation).****

4.1		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. **

4.2		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. **

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4.3		Master Settlement and Mutual Release Agreement dated as of April 16, 2004 among Petróleo Brasileiro S.A., Petrobras Energía, Petrobras Hispano Argentina S.A., Enron Corp., Enron Argentina Ciesa Holding S.A., Enron Pipeline Company Argentina S.A., and Ponderosa Assets, L.P.***

4.4		Restructuring Agreement dated as of September 1, 2005 among Compañía de Inversiones de Energía S.A., Petrobras Energía S.A., Petrobras Hispano Argentina S.A., Enron Pipeline Company Argentina S.A., ABN AMRO BANK N.V., Sucursal Argentina, and the Creditors.

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 29, 2006.

12.2		CFO Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002, dated June 29, 2006.

13.1		CEO and CFO Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated June 29, 2006.

*	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.

****	Incorporated herein by reference to our annual report for year ended December 31, 2004 filed on June 30, 2005.

*****

Incorporated herein by reference to Exhibit No. 4.2 to Petrobras Energía Participaciones S.A.’s Registration Statement on Form F-4 (333-11130) filed with the SEC on November 15, 1999.

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.

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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 29, 2006

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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-5
Report of independent registered public accounting firm of Compañia Inversora en Transmisión Eléctrica Citelec S.A.		F-6
Report of independent registered public accounting firm of Distrilec S.A.		F-7
Report of independent registered public accounting firm of Refinería del Norte S.A.		F-9
Consolidated statements of income and loss for the years ended December 31, 2005, 2004 and 2003		F-10
Consolidated balance sheets as of December 31, 2005 and 2004		F-11
Statements of changes in shareholders’ equity for the years ended December 31, 2005, 2004 and 2003		F-12
Consolidated statements of cash flows for the years ended December 31, 2005, 2004 and 2003		F-13
Notes to the consolidated financial statements for the years ended 2005, 2004 and 2003		F-14

REFINERIA DEL NORTE S.A.

Consolidated statements of income and loss for the years ended December 31, 2005, 2004 and 2003		F-101
Consolidated balance sheets as of December 31, 2005 and 2004		F-102
Statements of changes in shareholders’ equity for the years ended December 31, 2005, 2004 and 2003		F-103
Consolidated statements of cash flows for the years ended December 31, 2005, 2004 and 2003		F-104
Notes to the consolidated financial statements for the years ended 2005, 2004 and 2003		F-105

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, 2005 and 2004, 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, 2005. 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) and Compañía de Inversiones de Energía S.A. (CIESA) as of December 31, 2005 and 2004, and for each of the three years in the period ended December 31, 2005, 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, one of which includes an explanatory paragraph for going concern uncertainties as explained in paragraph 7. The Company’s share in the total assets and sales included in the financial statements of CIESA (for 2005, 2004 and 2003) and Distrilec (for 2003), which have been proportionally consolidated, represents 14% and 14% of consolidated total assets as of December 31, 2005 and 2004, respectively, and 5%, 6% and 12% of consolidated net sales for the years ended December 31, 2005, 2004 and 2003, respectively. The Company’s investment in the other affiliates, which have been accounted for using the equity method, is stated at Argentine pesos 288 million and Argentine pesos 278 million, respectively, as of December 31, 2005 and 2004, and the Company’s equity in the affiliates’ net income/loss is stated at Argentine pesos 172 million-income, Argentine pesos 31 million-loss and Argentine pesos 42 million-income for the years ended December 31, 2005, 2004 and 2003, respectively, 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 and, consequently, the Company has not discounted the nominal values of the deferred tax assets and liabilities for the fiscal years 2005, 2004 and 2003. Such discount is required by generally accepted accounting principles effective in Argentina, as approved by the Professional Council of Economics Sciences of the City of Buenos Aires, for the fiscal years ended December 31, 2005, 2004 and 2003. This effect has not been quantified by the Company.

Our report dated June 21, 2005 on the consolidated financial statements of Petrobras Energía Participaciones S.A. and its subsidiaries as of December 31, 2004 and 2003 included a qualification for not recognizing the non-quantified effects of the variations in the purchasing power of the Argentine peso from March 1 to September 30, 2003 as required by generally accepted accounting principles effective in Argentina, as approved by the Professional Council of Economic Sciences of the City of Buenos Aires, but not accepted by the National Securities Commission regulations. After issuing such financial statements, and as described in Note 2 to the accompanying consolidated financial statements, the Company quantified such effects and determined that they are not material. Accordingly, our present opinion over those financial statements, as presented herein, is no longer qualified.

F-2

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, 2005 and 2004, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2005, in conformity with the pertinent regulations of the Business Association Law and the National Securities Commission and, except for the effect of the matter 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 21 through 23 to the consolidated financial statements).

The financial statements and the reports of the other auditors of the affiliate CIESA as of and for the years ended December 31, 2005 and 2004 state that they have been prepared assuming that such affiliate will continue as going concern. CIESA, which has been proportionally consolidated, represents assets constituting 14% and 14% as of December 31, 2005 and 2004, respectively, and net sales constituting 5%, 6% and 6% for the years ended December 31, 2005, 2004 and 2003 of the respective consolidated totals, respectively. As discussed in note 9 to the consolidated financial statements, CIESA and its subsidiary Transportadora de Gas del Sur S.A. 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, CIESA has suspended the payment of its financial debt. These circumstances raise substantial doubt about the affiliate’s ability to continue as going concern. The affiliate management’s 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

February 15, 2006,

except for notes 21, 22, 23 and 25, as to which the date is June 12, 2006.

PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.

(Member firm of Ernst & Young Global)

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, 2005 and 2004, 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, 2005. 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 Note 2.b., effective March 1, 2003, the Company has discontinued the restatement of financial statements into constant currency 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, the application of the CNV resolutions represent a departure from generally accepted accounting principles in Argentina. Had those regulations been applied, the Company’s shareholders equity at December 31, 2005 and 2004 would have decreased by Ps. 39 million and Ps. 37 million, respectively, the results for the years ended December 31, 2005 and 2004 would have increased by Ps. 2 million in each year and the results for the year ended December 31, 2003 would have decreased by Ps. 36 million.

In our opinion, except for the effects of the matter discussed 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 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 de 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. Notwithstanding, on September 7, 2005 a restructuring agreement between the Company, its financial creditors and its shareholders was signed. This agreement refinances US$ 20 million of principal CIESA’s outstanding debt and also establishes that the remainder financial debt (approximately US$ 201 million of principal) will be settled, among other things, through a combination of transference of assets and granting equity interest, subject to the prior authorization of the Ente Regulador del Gas, the CNV and the Comisión Nacional de Defensa de la Competencia, which have not yet been obtained. These circumstances raise substantial doubt about the Company’s ability to continue as a going concern. Management’s actions 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.

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.

PRICE WATERHOUSE & CO. S.R.L.

Ruben O. Vega (Partner)

City of Buenos Aires, Argentina

February 8, 2006 (except with respect to the matters discussed in

Note 12 to the consolidated financial statements, which is as of June 12, 2006)

F-4

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.

PRICE WATERHOUSE & CO. S.R.L.

Ruben O. Vega (Partner)

City of 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-5

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, 2005 and 2004, 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, 2005. 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. 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. Had those regulations been applied, the Company’s shareholders equity at December 31, 2005 and 2004 would have decreased by Ps. 15 million and Ps. 19 million, respectively, the impact on the results for the year ended December 31, 2005 and 2004 would not have been significant, and the results for the year ended December 31, 2003 would have decreased by Ps. 12 million.

In our opinion, except for the effects on the 2004 and 2003 financial statements for not recognizing inflation accounting until September 30, 2003 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, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in Argentina.

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 regarding the application of accounting for the effects of inflation. Information relating to the nature and effect of such differences is presented in Note 15 to the consolidated financial statements. As described in Note 15, the effects of not accounting for the effects of inflation though September 30, 2003 is material to the information presented for all periods.

Miguel A. Urus

Buenos Aires, Argentina

February 8, 2006 (except with respect to the

matters discussed in Note 15 to the

consolidated financial statements, which is as of June 12, 2006)

F-6

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.

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.

F-7

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-8

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of

Refinería del Norte S.A.:

We have audited the accompanying balance sheet of Refinería del Norte S.A. (an Argentine Corporation) as of December 31, 2005, and the related statements of income, changes in shareholders equity and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). These standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit 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 includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above, present fairly, in all material respects, the financial position of Refinería del Norte S.A. as of December 31, 2005, and the results of its operations and its cash flows for the year then ended in conformity with generally accepted accounting principles in Argentina, as approved by the Professional Council of Economics Sciences of the City of Buenos Aires, which differ in certain respects from U.S. generally accepted accounting principles (see note 8 to the financial statements).

Buenos Aires, Argentina,

February 8, 2006

PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.

(Member firm of Ernst & Young Global)

GERMAN E. CANTALUPI

Partner

F-9

PETROBRAS ENERGÍA PARTICIPACIONES AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

CONSOLIDATED STATEMENTS OF INCOME

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(Stated in millions of Argentine pesos - See Note 2.c)


	2005		2004		2003
Net sales	10,655		8,763		7,113

Costs of sales (Note 22.c)	(7,058	)	(5,791	)	(4,759	)

Gross profit	3,597		2,972		2,354

Administrative and selling expenses (Note 22.e)	(941	)	(847	)	(770	)

Exploration expenses (Note 22.e)	(34	)	(133	)	(360	)

Other operating expenses, net (Note 17.c)	(329	)	(324	)	(123	)

Operating income	2,293		1,668		1,101

Equity in earnings of affiliates (Note 9.b)	166		76		163

Financial income (expense) and holding gains (losses)
Generated by assets;
Interest	88		53		72
Exchange difference	53		62		(157	)
Loss due to exposure to inflation	—		—		(28	)
Holding gains	40		38		9
Holding (losses), gains and income from sale of listed shares and government securities	(4	)	104		97
Other financial (expenses) income, net	(2	)	(25	)	8

	175		232		1
Generated by liabilities;
Interest	(586	)	(609	)	(626	)
Exchange difference	(84	)	(98	)	576
Gain due to exposure to inflation	—		—		67
Derivatives	(332	)	(688	)	(294	)
Other financial expenses, net	(72	)	(102	)	(111	)

	(1,074	)	(1,497	)	(388	)
Other income (expenses), net (Note 17.d)	(332	)	(40	)	(447	)

Income before income tax and minority interest in subsidiaries	1,228		439		430

Income tax (Note 12)	(381	)	211		(29	)

Minority interest in subsidiaries	(234	)	28		(20	)

Net income	613		678		381

Earnings per share - Stated in Argentine pesos	0.289		0.319		0.179

The accompanying notes are an integral part of these consolidated financial statements.

F-10

PETROBRAS ENERGÍA PARTICIPACIONES AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

CONSOLIDATED BALANCE SHEETS

AS OF DECEMBER 2005 AND 2004

(Stated in millions of Argentine pesos - See Note 2.c)


	2005		2004
CURRENT ASSETS
Cash	104		139
Investments (Note 9.a)	857		934
Trade receivables	1,596		1,181
Other receivables (Note 17.a)	626		756
Inventories (Note 8)	782		627
Other assets	1		1

Total current assets	3,966		3,638

NON-CURRENT ASSETS
Trade receivables	78		47
Other receivables (Note 17.a)	672		784
Inventories (Note 8)	79		71
Investments (Note 9.a)	1,172		1,323
Property, plant and equipment (Note 22.a)	12,847		12,347
Other assets	47		65

Total non-current assets	14,895		14,637

Total assets	18,861		18,275

CURRENT LIABILITIES
Accounts payable	1,483		1,181
Short-term debt (Note 10)	1,805		1,709
Payroll and social security taxes	177		98
Taxes payable	228		215
Reserves (Note 13)	48		31
Other liabilities (Note 17.b)	168		657

Total current liabilities	3,909		3,891

NON-CURRENT LIABILITIES
Accounts payable	14		26
Long-term debt (Note 10)	5,708		6,248
Payroll and social security taxes	17		12
Taxes payable	187		142
Other liabilities (Note 17.b)	339		178
Reserves (Note 13)	103		76

Total non-current liabilities	6,368		6,682

Total liabilities	10,277		10,573

TRANSITORY DIFFERENCES
Measurement of derivative financial instruments designated as effective hedge	—		(2	)
Foreign currency translation	(22	)	(47	)

Total transitory differences	(22	)	(49	)

MINORITY INTEREST IN SUBSIDIARIES	2,482		2,240

SHAREHOLDERS’ EQUITY (Per respective statements)	6,124		5,511

	18,861		18,275

The accompanying notes are an integral part of these consolidated financial statements.

F-11

PETROBRAS ENERGÍA PARTICIPACIONES AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

STATEMENTS OF CHANGES IN SHAREHOLDERS’EQUITY

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(Stated in millions of Argentine pesos - See Note 2.c)


	2005									2004	2003
	Capital stock			retained earnings
	Capital stock	Adjustment to capital stock	Additional paid- in capital	Legal reserve	Unappropriated retained earnings		Treasury stock(a)		Total	Total	Total
Balances at beginning of the year	2,132	2,554	160	20	678		(33	)	5,511	4,833	4,452
Extraordinary and Ordinary Shareholders’ Meeting decision of March 31, 2005:
- Legal Reserve	—	—	—	34	(34	)	—		—	—	—
Net income	—	—	—	—	613		—		613	678	381

Balances at the end of the year	2,132	2,554	160	54	1,257		(33	)	6,124	5,511	4,833

(a)	See Note 4.m).

The accompanying notes are an integral part of these consolidated financial statements.

F-12

PETROBRAS ENERGÍA PARTICIPACIONES AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

CONSOLIDATED STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003 (a)

(Stated in millions of Argentine pesos - See Note 2.c)


	2005		2004		2003
Cash provided by (used in) operations:

Net income	613		678		381

Reconciliation in net cash provided by (used in) operating activities:

Minority interest in subsidiaries	234		(28	)	20
Equity in earnings of affiliates (Note 9.b)	(166	)	(76	)	(163	)
Financial expense, net	29		45		(585	)
Dividends collected from equity investments (Note 9.c)	72		84		26
Depreciation of property, plant and equipment	1,221		1,166		1,121
Reserve for Enecor’s investment	16		—		—
Debt to exploitation partners in Venezuela allowance	55		15		27
Financial debt settled in advance	9		—		—
Impairment of assets - Areas in Venezuela (Note 6)	255		12		—
Impairment of assets - Operations in Ecuador	—		—		309
Impairment of assets - Gas areas in Argentina (Note 6)	(44	)	—		37
Impairment of assets - Other assets	—		2		19
Seniat claim - Venezuela	54		—		—
Impairment of unproved oil and gas properties	16		119		343
Income (loss) from sale of oil and gas areas and participation in joint ventures	—		—		27
Income tax provision	381		(211	)	29
Income tax paid	(17	)	(66	)	(48	)
Accrued interest	552		585		598
Interest paid	(515	)	(627	)	(488	)
Other	(12	)	(6	)	12

Changes in assets and liabilities:

Trade receivables	(375	)	(409	)	(68	)
Other receivables	(110	)	(72	)	(101	)
Inventories	(169	)	(174	)	(15	)
Other assets	8		45		73
Accounts payable	96		333		(46	)
Payroll and social security taxes	90		(25	)	18
Taxes payable	(6	)	83		(48	)
Other liabilities	(289	)	159		54

Net cash provided by operations	1,998		1,632		1,532

Cash provided by (used in) investing activities:

Acquisition of property, plant and equipment and interest in companies and oil and gas areas	(1,757	)	(1,189	)	(975	)
Net (decrease) increase in investments other than cash and cash equivalents	62		(13	)	6
Contributions and advances to unconsolidated affiliates	(1	)	(6	)	(12	)
Sale of interest in oil and gas areas	—		—		20
Reimbursement of contributions	14		9		—
Other	—		—		3

Net cash used in investing activities	(1,682	)	(1,199	)	(958	)

Cash provided by (used in) financing activities:

Net increase in short term debt	671		101		(354	)
Receipts of long-term debt	205		580		591
Receipts of long-term debt from related companies	583		150
Payments of long-term debt	(2,061	)	(1,241	)	(646	)
Cash dividends paid	—		(41	)	—

Net cash (used in) provided by financing activities	(602	)	(451	)	(409	)

Effect of exchange rate change on cash	9		(6	)	(88	)

(Decrease) increase in cash and cash equivalents	(277	)	(24	)	77

Cash and cash equivalents at beginning	1,067		1,091		911
Cash and cash equivalents at beginning from proportional interest in CIESA	—		—		103
Cash and cash equivalents at the beginning	1,067		1,091		1,014

Cash and cash equivalents at the end (See Note 17.e)	790		1,067		1,091

(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-13

PETROBRAS ENERGÍA PARTICIPACIONES S.A.

AND SUBSIDIARIES AND COMPANIES UNDER JOINT CONTROL

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(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. (“Petrobras Participaciones” or “the Company”) is a holding company that operates exclusively through our subsidiary Petrobras Energía S.A. (“Petrobras Energía”) and its subsidiaries. Petrobras Participaciones is a corporation organized and existing under the laws of the Republic of Argentina with a duration of 99 years from the date of the incorporation, September 25, 1998.

The Company holds 75.8% of Petrobras Energía, an integrated energy company, focused in oil and gas exploration and production, refining and distribution, petrochemical activities, generation, transmission and distribution of electricity and sale and transmission of hydrocarbons. Petrobras Energía has business in Argentina, Bolivia, Brazil, Ecuador, Peru, Venezuela, México and Colombia.

Petrobras Participaciones’s original name was PC Holdings S.A. The Company was formed in 1998 for the sole purpose of owning shares of Petrobras Energía, and both, the Company and Petrobras Energía, were controlled at the time by members of the Perez Companc family. As of December 31, 1999, the Company owned 28.92% of Petrobras Energía’s common stock.

The Company 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 the ownership interest in Petrobras Energía to 98.21%. Since January 26, 2000, the Class B shares have been listed on the Buenos Aires Stock Exchange and the American Depositary Shares, each representing ten Class B shares, have been listed on the New York Stock Exchange. In July 2000, the change in our corporate name from PC Holdings S.A. to Perez Companc S.A was completed.

On October 17, 2002, Petrobras Participaciones, S.L., or PPSL, a wholly owned subsidiary of Petróleo Brasileiro S.A. – Petrobras (“Petrobras”), acquired from the Perez Companc family and Fundación Perez Companc their entire ownership interest, or 58.6%, in Petrobras Participaciones capital stock. Petrobras is a Brazilian company whose business concentrates on exploration, production, refining, sale and transportation of oil and by-products in Brazil and abroad. Petrobras 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 the corporate name to Petrobras Energía Participaciones S.A. from Perez Companc S.A. On the same date, shareholders of Pecom Energía S.A. approved the change of its name to Petrobras Energía S.A.

On November 12, 2004, the Boards of Directors of Petrobras Energía, Eg3 S.A. (“Eg3”) 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 Eg3, PAR, and PSF with and into Petrobras Energía, with the former companies being dissolved without liquidation. The effective merger date was set as January 1, 2005, as from when all assets, liabilities, rights and obligations of the absorbed companies would be considered incorporated into Petrobras Energía.

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, Petrobras, owner of a 99.6% equity interest in EG3 and 100% equity interest in PAR and PSF through its subsidiary Petrobras Participaciones SL, received, through such subsidiary, 230,194,137 new shares of class B stock in Petrobras Energía, with a nominal value of Argentine Pesos 1 each and entitled to one vote per share, representing 22.8% of capital stock. Accordingly, the new capital stock of Petrobras Energía was set at Argentine pesos 1,009,618,410. As a result of the merger, Petrobras Energía Participaciones’s ownership interest in Petrobras Energía decreased from 98.21% to 75.82%. On March 3, 2005, the final merger agreement was subscribed and subsequently, on June 28, 2005, the CNV (Argentine Securities Commission) approved the merger and authorized the public offering of the Petrobras Energía shares. On September 16, 2005, the merger was registered in the Public Registry of Commerce.

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2. Basis of presentation

Petrobras Participaciones’s 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 Accepted Accounting Principles in Argentina, as approved by the Consejo Profesional de Ciencias Económicas de la Ciudad Autónoma de Buenos Aires (“CPCECABA”, Professional Council in Economic Sciences of the City of Buenos Aires) 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.

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 (Argentine Federation of Professional Councils in Economic Sciences), 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 group have been completely eliminated.

In the consolidation of companies over which the Company exercises joint control, the amount of the investment in the affiliate under joint control and the interest in its income (loss) and cash flows are replaced by the Company’s proportional interest in the affiliate’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 22.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 commited to divest such interest in connection with the transfer of 58.62% of the shares of Petrobras Participaciones to Petrobras (see Note 9.I).

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 starting January 1, 2003 in accordance with the transition standards.

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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;

foreign business activities 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

the 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 foreign business activities.

Upon applying the translation method, the foreign transactions are first remeasured into US dollars (the 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”.

The above also applies to exchange differences arising from liabilities in US dollar assumed to hedge the net investment in the foreign entity.

c) Restatement in constant money

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. Starting September 1, 1995, under CNV General Resolution No. 272, the Company has interrupted the use of this method and maintained the restatements made through such date. This method has been accepted by professional accounting standards through December 31, 2001.

On March 6, 2002, the CPCECABA 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 after 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 requires that the information related to the financial statements that are to be filed after the date on which the regulation became effective be disclosed adjusted for inflation.

The restatement according to the constant pesos method is applied to the accounting cost values immediately preceding the capitalization of the exchange differences capitalization of the exchange differences mentioned in note 4.o), 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.

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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 standards effective in the city of Buenos Aires. The CPCECABA, through Resolution N° 287/03 discontinued the application of the restatement method starting October 1, 2003. The effects thereof do not significantly affect the Company’s shareholders’ equity and results of operations.

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, 2005, 2004 and 2003 or the best available accounting information at such dates, were used for consolidation purposes and adapted to an equal period of time with respect to the financial statements of the company, after considering the adjustments to correspond to the Company’s valuation methods.

f) Accounting effects of Petrobras Energía’s corporate reorganization

Petrobras Energía recorded the effects of the corporate reorganization indicated in Note 1 in accordance with the pooling-of-interest method.

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, 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 this market (Statement of Financial Accounting Standard No 141) set forth that the merger between entities under common control be accounted for using the pooling-of-interest method.

According to the method, the assets, liabilities and components of the shareholders’ equity of the transferring entities are recognized in the combined entity based on their carrying amounts as of the effective merger date.

According to the method, consolidated financial statements have been restated for all periods prior to the merger to include the results of operations, financial position and cash flows of Eg3 S.A., Petrobras Argentina S.A. and Petrolera Santa Fe S.R.L. as though they had always been a part of PESA. According to the pooling of interest method, as the merger effective date was January 1, 2005, total shareholders’ equity and net income relating to the years ended December 31, 2004 and 2003 remain unchanged as compared to amounts presented prior to the merger and the balancing items resulting from the addition of assets, liabilities and results are recorded under Minority Interest in Subsidiaries.

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The assets and liabilities of Eg3 S.A., Petrobras Argentina S.A. and Petrolera Santa Fe S.R.L. as of December 31, 2004 incorporated in the combination are as follows:


	EG3 S.A.	Petrobras Argentina S.A.	Petrolera Santa Fe S.R.L.
CURRENT ASSETS
Cash	5	1	2
Investments	7	4	132
Trade receivables	200	20	24
Other receivables	99	28	20
Inventories	127	1	5

Total current assets	438	54	183

NON-CURRENT ASSETS
Trade receivables	8	—	—
Other receivables	75	14	39
Inventories	15	—	—
Investments	26	—	—
Property, plant & equipment	628	125	295
Other assets	46	—	—

Total non-current assets	798	139	334

TOTAL ASSETS	1,236	193	517


	EG3 S.A.	Petrobras Argentina S.A.	Petrolera Santa Fe S.R.L.
CURRENT LIABILITIES
Accounts payable	513	16	31
Short-term debt	42	11	4
Payroll and social security taxes	6	—	—
Taxes payable	22	1	28
Other liabilities	1	2	11

Total current liabilities	584	30	74

NON-CURRENT LIABILITIES
Taxes payable	1	—	—
Other liabilities	—	12	6
Reserves	5	—	—

Total non-current liabilities	6	12	6

TOTAL LIABILITIES	590	42	80

The net sales and net income (loss) previously reported by the combined companies for the year ended December 31,2004, are as follows:


	EG3 S.A.		Petrobras Argentina S.A.		Petrolera Santa Fe S.R.L.
Net Sales	3,620		80		242
Net (loss) income	(109	)	(26	)	68

g) Changes in professional accounting standards

On August 10, 2005, the Board of the CPCECABA approved Resolution CD No. 93/2005, which introduced a series of changes to professional accounting standards, effective for fiscal years beginning as from January 1, 2006. In addition, it contemplates transition standards that defer the obligatory effectiveness of certain changes for fiscal years beginning as from January 1, 2008.

The changes that could be of relevance to the Company are described below:

In calculating the recoverability of Property, Plant and Equipment and certain intangible assets, the recoverable value is considered to be the higher of the net realizable value and the discounted value of the expected cash flows, eliminating the first comparison with the nominal value of expected cash flows.

The transitory differences arising from the conversion of financial statements and the income recognized from the investment in not integrated entities, will be disclosed in the shareholders equity instead of being disclosed in the “Transitory differences - foreign currency translation” account.

iii

It is established that the difference between the Property, Plant and Equipment carrying value adjusted for inflation (and other non-monetary assets) and their tax value is a temporary difference for deferred income tax purposes that would result in the recognition of a deferred tax. This effect can either be booked or disclosed in notes to financial statements.

In addition, an amendment was introduced in the measurement of deferred tax assets and liabilities, which shall not be discounted for the entities included in the public offering, thus unifying the treatment thereof with CNV standards.

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Through General Resolutions Nos. 485 and 487 dated December 29, 2005, and January 26, 2006, the CNV approved the abovementioned changes, which are effective for fiscal years beginning as from January 1, 2006.

Under the abovementioned changes, eliminating the use of undiscounted cash flows as the first measurement guideline to perform impairment tests of assets would entail a shareholders’ equity reduction of about 143. Such figure does not include the effect, if any, that could result from analyzing the recoverability of certain interests in certain affiliates. In connection with transitory differences, the disclosure thereof in a special shareholders-equity account would entail its reduction by 22 as of December 31, 2005 (See Note 25).

As of the date of issuance of these financial statements, the Company’s Board of Director has not made a decision regarding the recognition of a deferred tax mentioned above in item (iii). The potential recognition of this effect would imply an increase of the Company’s liabilities and a reduction of its shareholders equity of 804 (See Note 25).

3. Accounting standards

These financial statements have been prepared in accordance with professional Argentine GAAP and the applicable CNV regulations. The CNV regulations differ from Argentine GAAP as follows:

a) the valuation of deferred income tax credit or liability at nominal value without applying any discounted values as required by CNV General Resolution No. 434 (See Note 2).

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.

4. Valuation methods

The main valuation methods used in the preparation of the consolidated financial statements are 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 22.d).

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.

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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 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, net of payments collected. Interest gain is credited to income on an accrual basis. As of December 31, 2005, the Company maintained investments with a market value of 6 and a book value of 6.

Certificates of deposit and loans to affiliates over which significance influence is exercised: at face value plus accrued interest.

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 exercised, 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, inter-company profits and losses, the difference between acquisition cost and book value of affiliates at the time of the acquisition. 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.

Other shares – interests in affiliates in which the Company does not exercise significant influence: at acquisition cost restated in constant money 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. 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.

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 each year. The total amount of receivables is net of an allowance for doubtful account, which is based on estimates of collections.

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, net of payments or collections.

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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, which are at nominal value.

g) Property, plant and equipment:

Property, plant and 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 and equipment related to foreign operations were converted into US dollars, as US dollars 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 in accordance with the Statement of Financial Accounting Standard No. 19 (SFAS N°19). This method involves the capitalization of: (i) the cost of acquiring properties in oil and gas exploitation and production areas; (ii) the cost of drilling and equipping exploratory wells that result in the discovery of reserves economically exploited; (iii) the cost of drilling and equipping development wells, and (iv) the estimated future costs of abandonment and restoration.

In accordance with SFAS N°19, 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 the commercial development. 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 complete. In those cases, incorporating prospectively the changes introduced by the interpretation FASB Staff Position 19-1, starting July 2005 such costs continue to be capitalized insofar as the well has allowed to determine the existence of sufficient reserves to warrant its completion as a production well and the company is making sufficient progress in evaluating the economic and operating feasibility of the project. Before such interpretation, SFAS 19 provided: (I) if the well found 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 to be capitalized as long as it meets the following two conditions: (a) reserves found are sufficient to justify completion of the well as producing 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.

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 discounted amount payable.

The Company estimates its reserves at least once a year. The Company’s reserve estimates as of December 31, 2005, 2004 and 2003, were audited by Gaffney, Cline & Associates Inc., international technical advisors. The technical revision covered approximately the 95%, 95% and 92% of the Company’s estimated reserves for the years 2005, 2004 and 2003.

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The Company’s remaining property, plant and 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 actual costs of major maintenance and repairs are charged to expense when incurred.

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 the process.

The value of CIESA’s property, plant and equipment transferred under the Gas del Estado privatization process was determined based on the price paid for the acquisition of 70% of Transportadora de Gas del Sur S.A.’s common stock. This price was the basis to determine a total value of common stock, to which was added the value of the debts assumed under the Transfer Agreement, in order to determine the initial value of property, plant and equipment. Such value has been restated into constant pesos as explained in Note 2.c.

Company Management assesses the recoverability 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. The Company tests the recoverability of Property, Plant and Equipment based on the respective value in use, defined as the addition of the expected net cash flows that arise as a direct result of the use and eventual disposition of the assets. To such end, among other elements, the premises that represent the best estimation made by Management of the economic conditions that will prevail throughout the useful life of the assets are considered. The book value of a long-lived asset is adjusted to its recoverable value if its carrying amount exceeds the undiscounted value in use. From a regulatory standpoint, recoverable value is defined as the larger of net realizable value and discounted value in use. In the determination of the discounted value in use, discount rates used by market participants to evaluate the time value of money and the specific risk of the asset, are considered.

In subsequent periods, the reversal of the impairment is analyzed if changes in the assumptions used to determine the asset recoverable value arise. In such a case, the book value of the asset or group of assets is raised to the smaller of: a) the book value that the asset or group of assets would have had if the impairment had never been recognized; and b) its recoverable value.

The value of property, plant and equipment, measured for each identifiable business unit or line of business, producing an independent stream of revenues for the Company, does not exceed its recoverable value.

h) 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 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.

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i) Income tax, tax on minimum presumed income, royalties and withholdings on export of hydrocarbons:

The Company estimates income tax on an 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 the 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 when 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 recognizes a deferred tax asset, only to the extent that recovery of the asset is probable.

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 (see Note 2).

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 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.

For the operations in Argentina, Venezuela, Brazil, Peru, Ecuador and Bolivia the income tax accrual was calculated at the tax rates of 35%, 50%, 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 the 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 record 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 for the production of crude oil and for effectively used volumes of natural gas. Those royalties are 12% of the wellhead estimated price for oil and gas. The wellhead price represents the final sales price less treatment, storage and transportation costs. Oil and gas production in Bolivia are subject to royalties and direct taxes that, overall, represent 50% of the estimated wellhead value of such products, which is taken be the invoicing price less associated transportation expenses. 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 the rate of 13% for prices of up to US$ 23.9 per barrel. The royalty rate applicable as of December 31, 2005, was 21.9%. Production of natural gas in Peru is subject to a fixed royalty of 24.5%.

As regards the Pichi Picún Leufú Hydroelectric Complex, as provided in the concession agreement since 2002, the Company pays hydroelectric royalties of 1% increasing at a rate of 1% per year 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 0.5% of the same basis used for the calculation of 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

F-23

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 rate of 45% when the price exceeds US$ 45. The effect of such withholdings is deducted from the respective selling prices

j) Liabilities for labor costs:

Liabilities for labor costs are accrued in the years in which the employees provide the services that trigger the consideration.

For purposes of determining the estimated cost of post-retirement benefits granted to employees, the Company has used actuarial calculation methods, making estimates with respect to the applicable demographic and financial variables.

k) 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.

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 13.

l) Earnings per share:

Earnings per share for the years ended December 31, 2005, 2004 and 2003, were calculated on the basis of the number of outstanding shares in each year, net of treasury stock. 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.

m) 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.

n) Revenue recognition:

The Company generally sells crude oil, natural gas and petroleum, petrochemical, refined products and electricity. 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.

F-24

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 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 generated by interruptible gas transportation and by certain LNG production and transportation contracts, are recognized at the time the natural gas and the liquids, respectively, are delivered to the customers. For other LNG production contracts and other services, the revenues are recognized when services are rendered.

Sales between group companies are based on prices generally equivalent to commercially available prices.

o) Statement of income accounts:

Restated into constant currency, according to Note 2.c), considering the following:

•

The accounts accumulating monetary transactions at nominal value, less imputed financial components, where applicable.

•

Depreciation and consumption expenses related to non-monetary assets were charged to income (losses) taking into account the restated costs of such assets.

•

Financial income (expense) and holding gains (losses) are broken down between those generated by assets and those generated by liabilities.

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 that date directly related to the acquisition, construction, or production of property, plant and 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 which was granted by the supplier of the goods, that which was billed in foreign currency, or that which was 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 that date, the Company ceased to apply the exchange difference capitalization / de-capitalization method.

As described above, as of December 31, 2005, 2004 and 2003, the Company has capitalized exchange differences, principally through the investment in CIESA, amounting to a residual value of 25, 26 and 27. Additionally, as of December 31, 2004 and 2003, the Company has capitalized exchange differences, through the investment in Citelec, amounting to a residual value of 17 and 19.

5. Accounting for derivative financial instruments

From time to time, 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.

F-25

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.

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 year 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.

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 are charged to income in the case of (c).

Changes in the accounting measurement of derivative financial instruments that do not qualify for hedge accounting are recognized in the income statement under “Financial income (expense) and holding gains (losses)” line.

a) Instruments that qualify for hedge accounting

Hedge of produced crude oil price

These instruments use West Texas Intermediate (WTI) as the reference price, which is used mainly to determine the sale price in the market.

As of December 31, 2005 and 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 the accrued portions of hedge instruments represented a lower sale of 81.

Hedge of interest rates

As of December 31, 2004 and 2003 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 year. This contract term expired in July 2005. For 2004 and 2003, the effect of such agreement is disclosed in the “Transitory differences-Measurement of derivative financial instruments designated as effective hedge” account.

b) Instruments that do not qualify for hedge accounting

As of December 31, 2005, 2004 and 2003, losses of derivative financial instruments that do not qualify for hedge accounting amount to 295, 688 and 294, respectively.

c) Other operations with derivative instruments

The Company makes forward sales of US dollars in exchange for Argentine pesos. As of December 31, 2005, the nominal value of effective contracts amounts to US$ 52 million at the average exchange rate of 3.00 Argentine pesos per US dollar. During the current year, the Company recognized a loss of 4.

F-26

6. Oil and gas areas and participation in joint ventures

As of December 31, 2005, the Company was part of the oil and gas consortiums, joint ventures and areas indicated in Note 22.g). As of that date, the aggregate joint ventures and consortium 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 22.h).

The production areas in Argentina and Peru 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 (See Operations in Venezuela). In Bolivia it is a shared-risk contract signed with Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”) with free production availability.

The New Oil and Gas Law No. 3,058 became effective in Bolivia on May 19, 2005. Among other issues it provides for a larger tax burden for oil and gas companies through royalties that amount to 18% and a Direct Tax on Hydrocarbons (IDH) amounting to 32% to be directly applied on the total of production. These taxes complement the existing ones through Law No. 843. In addition, the new law provides for the migration of the shared-risk contracts to new ones in conformity with the premises established and introduces changes in the derivative products distribution business. To date, the Government of Bolivia has not provided oil companies with the new versions of the contracts mentioned in the Law (operation, shared production, and association). The impact of the migration of the current shared services contracts in the Company will be analyzed once the proposed versions and the regulations related thereto are published (See Note 25 - Oil and gas areas and participation in joint ventures - Bolivia).

In Ecuador, operation contracts for Block 18 stipulate the free disposition of the oil produced and differential production percentages to go to the Ecuadorian 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. It is also adjusted depending on the crude oil quality factor. 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 upon. The selling price of the Palo Azul crude is calculated using as a reference the barrel of WTI after the standard market discount for the Oriente crude. As of December 31, 2005, the Government’s shares of the oil produced at the Pata and Palo Azul fields was 25.8% and 50%, respectively.

Block 31 has no production yet, given that it is in the early stages of development, but as soon as it produces its first barrel, the Government’s share will range from 12.5% to 18.5%, depending on daily production volumes and oil density. The concession agreement for Block 31 provides for the free availability of the crude oil produced (See Operations in Ecuador).

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$ 8.4 per barrel as of December 31, 2005, plus a capital fee for reimbursement of certain exploration and development investments. The agreement establishes an additional compensation as an incentive for additional production once the area reaches an accumulated production of 155 million barrels. During the first quarter of 2005, the consortium reached the accumulated production established by the agreement. This compensation is based on an additional rate per barrel, adjusted according to the variations in a basket of crude oil prices.

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, which decreases in relation with the area profitability, up to a maximum tied to a basket of international oil prices.

F-27

Under the terms and conditions of the provisional agreements signed by Petrobras Energía Venezuela S.A., Coroil S.A. and Inversora Mata S.A. with PDVSA in September 2005, the total amount of accumulated payments to the contractors of Venezuelan joint ventures while they last should not exceed 66.67% of the total value determined in US dollars of the crude oil delivered (See Operations in Venezuela).

Investment commitments

Petrobras Energía Perú S.A. has arrived at an agreement with the Peruvian Government, whereby it has committed to invest at least US$ 97 million approximately in Lot X over the period 2004-2011. In compensation, the Peruvian Government undertook to reduce the royalties that it charges to the Company for oil and gas extraction. The tasks initially planned for this project comprise the drilling of 51 wells, the reconditioning of 525 wells, the rehabilitation of 177 wells that had been abandoned temporarily and the implementation and expansion of the water injection project. As of December 31, 2005, Petrobras Energía Perú S.A. had invested about US$ 55 million.

The Company has retained a portion of Block 31 in Ecuador to continue exploration, and has committed to performing an environmental impact study, as well as to registration, processing and interpretation of 120 sq. km of 3D seismic, reprocessing 500 km of 2D seismic and integration with the new 3D seismic and the drilling of an exploratory well, representing an investment of about US$ 16 million.

Additionally, the Company has undertaken an investment commitment related to its share in the Cañadón del Puma area for 50% of the total US$ 8 million commitment, to be completed by May 2006. As of December 31, 2005 the consortium had invested US$ 5 million.

Asset Retirement Obligations

The following table summarizes the movements in liabilities recorded for the asset retirement obligations for the years ended December 31, 2005 and 2004:


	2005		2004
Beginning balance	91		73
Accretion	8		7
Net increase and estimating changes	30		1
Foreign currency translation/other	(3	)	10

Ending balance	126		91

Suspended well costs

The following table provides the year-end balances and movements for suspended exploratory well costs:


	2005	2004		2003
Balance at the beginning of the year	5	115		218
Additions	56	5		78
Transferred to development	—	(13	)	(4	)
Charged to expense	—	(100	)	(149	)
Inflation and foreign currency translation	—	(2	)	(28	)

Balance at the end of the year	61	5		115

Number of well at year end	14	2		3

F-28

An aging of suspended well costs is shown below.


	2005		2004		2003
	Amount	Wells	Amount	Wells	Amount	Wells
Less than one year	56	12	5	2	115	3
Between one and three years	5	2	—	—	—	—

Total	61	14	5	2	115	3

The amount of 5 capitalized as suspended well costs as of December 31, 2005 that was suspended for more than one year according to the table above, correspond to two projects located in Argentina (Austral and Neuquén Basins), for which the Company has requested the corresponding exploitation concessions. In case those concessions are delivered the Company has firm plans and established timetables to develop those lots in the near future.

Divestments of equity in oil and gas areas

In August 2003, the Company sold to Central International Corporation, Argentine Branch, an 85% interest in the rights and obligations from the concession of the Catriel Oeste area. Considering the transfer price agreed upon, 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, the 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 will be settled over a ten-year period, in quarterly installments, whose value in US dollars will be determined to be 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.

Recoverability of investments in Argentine oil and gas areas

The approval of the Public Emergency Law, which provided limited possibilities to negotiate gas price increases in an inflationary and devaluated context, substantially modified the profitability conditions of the gas business in Argentina.

Considering that situation, during 2003 and 2002, the Company adjusted the book value of certain investments in gas producing areas in Argentina to their fair value. During 2003, the Company recorded a loss that amounted to 37 in the “Other expenses, net” line.

As of December 31, 2005, based on the change in the prospects of the gas business evolution in Argentina, and after analyzing the recoverability of its assets, the Company recognized earnings in the amount of 44 related to the reversal of prior impairments. This new scenario considers the regulatory changes made by the Argentine Government aimed at restoring the sector’s stability conditions, including the formulation of a price path that provides for the normalization of the price of gas for 2007.

Operations in Ecuador

License of Block 31

A large part of Block 31 is located in Parque Nacional Yasuní, a highly sensitive environmental area located in Ecuador’s Amazon area, which is part of the areas belonging to the National Heritage of Natural Areas, Protective Forests and Vegetation.

In August 2004, the Ecuadorian Ministry of the Environment approved the Environment Management Plan for the project related to the development and production of Block 31 and granted an environmental license for the Nenke and Apaika fields for the project construction phase. In addition, in August 2004, the Ministry of Energy and Mining approved the Block 31 development plan, which started the 20-year exploitation period.

F-29

In this respect, native and environmentalist groups made public statements against the Block 31 development, arguing that the oil and gas activity endangered the park biodiversity.

On July 7, 2005, the Ministry of the Environment decided not to authorize the beginning of certain construction works on the Tiputini River (boundary of Parque Nacional Yasuní) and denied us entry to Parque Nacional Yasuní. This suspension prevents from continuing the development works in Block 31. A constitutional rights protection action was filed by Petrobras Energía Ecuador against the Ministry of the Environment for the prohibition of entry into Parque Nacional Yasumí. The Trial Court’s unfavorable resolution was appealed to the Constitutional Court, which has not yet pronounced any judgment. In addition to the filing and resolution of such appeals, Petrobras Energía Ecuador is negotiating with the appropriate authorities to find a solution that enables the Company to continue with the development plan of the Nenke and Apaika fields.

Crude Oil Transportation Agreement with Oleoductos de Crudos Pesados Ltd. (OCP)

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 starting November 10, 2003. The type of transportation agreement is “Ship or Pay”. Therefore, the Company should meet its contractual obligations for the entire volume hired, although no crude oil is transported, paying, like the other producers, at a rate that covers OCP operating costs and financial services, among others. As of December 31, 2005 this figure amounted to US$ 2.26 per barrel. The costs for the transportation capacity are billed by OCP and charged monthly to expenses. Hence, 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.

The Company estimates that, during the effective term of the “Ship or Pay” transportation agreement, the crude oil produced will be lower than our committed transportation capacity. This presumption is based on: (i) the probability estimated for the Block 31 development and (ii) the new vision about the Block 31 reserves potentiality. Accordingly, from July 2004 to 2012, the Company sold a portion of this transportation capacity (at an average amount of 8,000 barrels a day). The net deficit impact is considered for the purpose of analyzing the recoverability of Ecuador’s assets. As of December 31, 2005 the Company keeps an allowance for the Ecuador’s assets depreciation of 330.

In order to guarantee the compliance with the Company’s financial commitments related to the “Ship or Pay” transportation agreement executed with OCP and OCP’s related business obligations, as of December 31, 2005, the Company issued letters of credit for a total amount of about US$ 128 million. These letters of credit, with maturity date of December 2018, are required to remain effective until the abovementioned commitments expire. As the letters of credit expire, the Company will be required to renew or replace them. Otherwise, the amounts due must be deposited in cash.

Preliminary Agreement with Teikoku Oil Co Ltd.

Until reaching such production level, only with effect among the parties and subject to the terms and conditions mentioned above, Teikoku will assume 20% of our rights and obligations resulting from the transportation agreement, as from July 1, 2006. In addition to the above-mentioned, and only with effect among the parties and subject to the agreed upon conditions, Teikoku will also assume an additional 20% of our rights and obligations resulting from the transportation agreement and which will be effective for the shorter of the following periods: (a) July 1, 2006 until Block 31 reaches the aforementioned production level, or (b) the consecutive 18 months prior to such production level.

F-30

This agreement enabled a 40% reduction in the letter of credits guarantying Petrobras Energía compliance with those commercial obligations assumed under the transportation agreement entered into with OCP.

Transportation agreement with Occidental Exploration and Production Company (“Oxy”)

In January 2005, the Company entered into a crude oil transport agreement with Oxy. Under this agreement, the Company will be able to use a pipeline owned by Oxy to transport oil produced by Block 31 to OCP’s header, carrying approximately 25% of the production related to the proved reserves from Block 31. This agreement is subject to approval by the Ecuadorian Government.

The agreement is effective starting the thirty days from the beginning of operations in Block 31, or from January 2007, if it is previous, until July 2019. A ship or pay clause is included in connection with a financial obligation for the amount of about US$ 10 million along the agreement duration. To comply with the agreement, it will be necessary that Oxy facilities be expanded; this expansion will require an investment of about US$ 14 million. This investment will be financed by Petrobras Energía Ecuador and will be reimbursed in the form of an offset to the transport rate to be paid, which will be about 0.7 US$/bbl -adjusted based on the type of crude oil transported. During the construction phase, a stand-by letter of credit for US$ 9 million will be granted. The ship or pay obligation will be guaranteed by means of a stand-by letter of credit for US$ 2 million, which will be effective until the field produces 10,000 barrels per day.

Operations in Venezuela

In April 2005, the Venezuelan Energy and Oil Ministry (“MEP”) ordered Petróleos de Venezuela, S.A. (“PDVSA”) to review the thirty-two operating agreements signed by PDVSA’s affiliates with oil companies from 1992 through 1997, including the agreements signed by the Company to operate the exploitation of Oritupano Leona, La Concepción, Acema and Mata areas. According to MEP, such operating agreements include clauses that are not consistent with the current Organic Oil and Gas Law, enacted in 2001.

These instructions establish that all the necessary measures shall be taken to convert all operating agreements currently effective into partially state-owned companies (“mixed companies”) in which the Government will hold an ownership interest of over 50% through PDVSA. With regards to these agreements, the MEP has instructed PDVSA that the total amount of accumulated payments to contractors during the remaining life of the operating contracts shall not exceed 66.67% of the value of oil and gas produced under the related agreement.

During 2005, through different actions, PDVSA exercised a pressure on the effective operating agreements as a way to promote migration. Among others:

(a)

PDVSA approved a reduced amount of development investments for the Oritupano Leona area;

(b)

Operators experienced difficulties from PDVSA in delivering production to PDVSA.

(c)

Operators in Venezuela received part of their compensation in local currency (bolivars). In this regard, in June 2005, PDVSA notified Petrobras Energía Venezuela S.A. that it would thereafter pay in bolivars the portion of the compensations provided in the operation contracts currently in effect related to the domestic component of the materials and services provided. This decision departs from the stipulations of the operation contracts mentioned above, under which PDVSA is required to make such payments in US dollars. During the transition phase, and until PDVSA performed an audit to determine the portion attributable to the domestic component, PDVSA paid 50% of the operators contractual compensation in US dollars and the remaining 50% in bolivars. Subsequently and based on the collections related to 2005 third quarter production, the portion of the contractual compensation payable in bolivars was reduced to 25%;

(d)

The SENIAT (National Integrated Tax Administration Service) performed several tax inspections on the companies that operate the 32 oil operating contracts and, as a result, challenged prior tax filings. In this regard, as of December 31, 2005, the Company booked a 54 loss; and

(e)

the applicable income tax rate was increased from 34% to 50%.

F-31

As a first instance, on September 29, 2005, Petrobras Energía Venezuela S.A., Coroil S.A. and Inversora Mata S.A. signed provisional agreements with PDVSA, whereby it committed itself to negotiating the terms and conditions related to the conversion of the agreements in the areas of Oritupano Leona, La Concepción, Acema and Mata, and also acquiesced the application of the 66.67% cap over the value paid to contractors. The provisional agreement for the Oritupano Leona area was signed subject to the previous approval of Petrobras Energía S.A.’s General Shareholders’ Meeting and of the Petrobras Energía Participaciones S.A. Extraordinary Shareholders’ Meeting, which issued a favorable opinion in this regard.

Estimated proved oil and gas reserves as of December 31, 2005 attributable to the Company’s operations in Venezuela is calculated on the basis of the contractual structure in force as of that date.

Although the final terms for the conversion of the operating contracts are not defined as of the date of these financial statements, the Company considers, based upon the framework of the provisional agreements and the current status of conversations with PDVSA, that this process will have an adverse effect on the value of its assets and a reduction of its reserves in Venezuela.

Accordingly, as of December 31, 2005, the Company recorded provisions for 424 in order to adjust the book value of its Venezuelan assets to their recoverable value, out of which 255, 110, and 59 relate to Property, Plant and Equipment, deferred income tax assets, and non-current investments, respectively. In order to determine the recoverable value, the Company has made cash flows projections taking into account the current operating agreements during the negotiation period and different assumptions for the mixed-ownership structure thereafter, according to the information available at present under the current state of negotiation in progress with PDVSA. Projections are highly sensitive to any change in the assumptions considered and, as a result, the final result of the contracts conversion process mentioned above could differ materially from the estimate.

Based on the Company’s estimated participation in the mixed companies and the corporate structure established to materialize the migration of operating agreements, and once such migration has been completed, the Company’s reserves in Venezuela will be shown on the Unconsolidated Companies line in the Supplementary information on oil and gas producing activities of SFAS 69 (unaudited information).

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, electrical power generation companies, retail customers, natural gas distributors, large electrical power 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., Glencore AG and Petrobras International Finance Co., and sales to such entities represented about 12%, 7%, 3% and 2%, respectively, of sales for such year, before deducting export duties.

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 AG, and sales to such entities 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.

As a result of the business of the Company and sale locations, the portfolio of receivables is well diversified, and the Company’s Management considers that 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 bad debt losses.

F-32

8. Inventories

The breakdown of current and non-current inventories as of December 31, 2005 and 2004, is as follows:


	12/31/2005				12/31/2004
	Current		Non-current		Current		Non-current
Crude oil stock	105		—		65		—
Materials	200		81		157		73
Work in progress and finished products	435		—		388		—
Advances to suppliers	41		—		13		—
Other	4		—		6		—
Reserve for materials obsolescence (Note 13)	(3	)	(2	)	(2	)	(2	)

	782		79		627		71

9. Investments, equity in earnings of affiliates and dividends collected from affiliates

The breakdown of current and non-current investments as of December 31, 2005 and 2004, and the equity in earnings of affiliates and dividends collected from affiliates for the years ended December 31, 2005, 2004 and 2003, are as follows:

a) Investments


	12/31/2005			12/31/2004
Name and issuer	Cost	Book value		Book value
Current:

Government securities	33	25		5
Certificates of deposit	561	561		569
Mutual funds	126	126		241
Related companies (Note 18)	—	2		119
Citelec S.A. (Note 9.I.c)	298	288		—
Reserve for impairment of investments (Note 13)	—	(145	)	—

	1,018	857		934

Non-current:

Government securities	1	1		24
Advances to joint ventures	138	138		154
Reserve for impairment of advances to joint ventures (Note 13)	—	(33	)	—
Related companies (Note 18)	150	150		156
Equity in affiliates (note 22 b)	688	914		988
Other	—	2		1

	977	1,172		1,323

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b) Equity in earnings of affiliates


	2005		2004	2003
Cia. de Inversiones de Energia S.A.	—		—	(33)	(iii)
Citelec S.A.	27	(ii)	(42)	87	(iv)
Petrobras Bolivia Refinación S.A.	54		18	(5)
Oleoducto de Crudos Pesados Ltd.	2		1	(5)
Inversora Mata S.A.	(7)		4	4
Oleoductos del Valle S.A.	3		7	2
Petrolera Entre Lomas S.A.	26		17	13
Peroquimica Cuyo S.A.	7		16	16
Refineria del Norte S.A.	46		40	28
Transportadora de Gas del Sur S.A. (i)	16		10	52
Yacylec S.A.	3		3	2
Coroil	(11)		2	1
Others	—		—	1

	166		76	163

(i)	Net of adjustments incorporated to adapt TGS’s accounting principles to those of the Company amounted to zero, 1 and 30 for 2005, 2004 and 2003, respectively. (See Section II).

(ii)	Includes an allowance for investments depreciation of 145 (See Section II)

(iii)

Corresponds to non-recognized losses of the year 2002 because the valuation of the equity interest in CIESA amounted to zero, as this interest valued under the equity method would have represented a negative amount.

(iv)	Includes the reversal of the 2002 allowance, which amounted to 66

c) Dividends collected from equity investments


	2005	2004	2003
Yacylec S.A.	3	3	3
Petrobras Bolivia Refinacion S.A.	1	13	—
Petroquimica Cuyo S.A.	7	9	—
Petrolera Entre Lomas S.A.	16	12	9
Oleoductos del Valle S.A.	6	6	7
Refineria del Norte S.A.	39	41	7

	72	84	26

I. Investment in companies over which joint control or significant influence is exercised and which 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.

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 its Class “A” shares representing 51% of CIESA’s capital stock, without the prior authorization of the regulatory agency and the approval of the shareholders of CIESA.

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c) Compañía Inversora en Transmisión Eléctrica Citelec S.A. (“Citelec”):

The Company, through Petrobras Energía S.A., 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.

Upon obtaining approval by CNDC for the acquisition by Petrobras Participaciones SL of a majority shareholding in Petrobras Energía Participaciones S.A., Petrobras Energía assumed the unilateral commitment to divest all its ownership interest in Citelec, without a fixed term, in conformity with Law No. 24,065 of the regulatory framework for the electrical power sector and the concession contract thereof. The commitment was taken into account by the Department of Competition, Deregulation and Consumer Defense when approving the change in the ownership interest. The commitment should be overseen by the Argentine Electrical Power Regulatory Agency and approved by the Argentine Energy Department. On May 26, 2005, through Resolution No. 757, the Argentine Energy Department notified the Company that it established March 31, 2006, as the deadline for Petróleo Brasileiro S.A., through Petrobras Participaciones SL, to meet the irrevocable commitment to divest its interest in Citelec. Afterwards, through Resolution No. 941, the Argentine Energy Department abrogated the deadline and determined that Petrobras Energía had to file a divestment plan for the interest in Citelec, and it will be required to report on the progress made on a quarterly basis. Fulfilling the disposed by the Resolution N° 941, as of August 5, 2005 Petrobras Energía presented to the Argentine Energy Department the plan to divest completely from the equity interest in Citelec. Consequently, as of December 31, 2005 this investment is presented as a current investment.

Citelec is not permitted to modify nor sell its Class “A” shares representing 51% of Compañía de Transporte de Energía en Alta Tensión Transener S.A. (“Transener”) capital stock, without prior approval by the ENRE.

Transener may not modify nor 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.

e) 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.

In July 2005, the DPEC (Provincial Energy Department of Corrientes) decided not to consent to any payment to Enecor S.A. by virtue of the electroduct contract and demanded that contract guarantors abrogate the irrevocable guarantees posted in due time. Consequently, Enecor S.A. went through the suspension of not only the royalty payment but also the guarantees posted in its favor. As a result of this action, Enecor S.A. demanded that the DPEC and the guarantors pay the royalties due and payable and to refrain from amending the electroduct contract and the guarantee system. Furthermore, constitutional actions for the enforcement of rights were filed against the entities involved in view of the apparent unlawfulness of their resolutions. On September 21, 2005, the ENRE was requested to become involved as enforcement authority of the electroduct contract. The ENRE notified the DPEC of the filing.

According to Enecor S.A.’s legal counsel, the behavior of the DPEC and the guarantors is apparently unlawful and arbitrary, and implies a clear noncompliance by these entities with the obligations and commitments assumed in due time. The controversy described generates substantial doubt as to Enecor S.A.’s ability to continue as a going concern. Based on such uncertainty, the Company booked an allowance amounting to 16 with respect to its investment in Enecor S.A.

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II. Situation of the interests in public utility companies

The scenario after enactment of the Law on Public Emergency significantly changed the financial equation of public utility companies. Particularly, the tremendous effect of the devaluation, within a context of remained fixed revenues, 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 agreement clauses.

During 2002, CIESA, TGS and Transener suspended the payment of their financial debts. TGS and Transener restructured their financial debt through their own processes, which were accepted by about 99.8% and 98.8% of the related creditors, respectively. In September 2005, CIESA signed an agreement to restructure its financial debt with all its creditors. The materialization of the restructuring is subject to certain approvals by the regulatory authorities. CIESA has prepared its financial statements assuming that it will continue as a going concern, therefore, those financial statements do not include any adjustment that might result from the outcome of these uncertainties.

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 that Ministry of the Economy renegotiate the agreements executed with public utilities. The Ministry of the Economy should submit a renegotiation proposal or termination recommendation to the Executive Branch of Government and then it should be sent to the applicable Congressional bicameral commissions.

To allow the preservation of the public services provision, and considering the renegotiation process already underway, the Executive Branch of Government issued Decree No. 146/03, authorizing an increase in gas and electrical power rates. The ombudsman and consumer associations objected the increase in rates. 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. This agency reports to the Ministries of Economy and Production, and of Federal Planning, Public Investment and 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, to execute comprehensive or partial agreements, and to submit regulatory projects related to transitory rate adjustments, among other things.

On October 1, 2003, the Argentine Congress passed a bill establishing the extension to December 2004 of the term granted by the Executive Branch of Government by virtue of the Public Emergency Law to renegotiate the agreements executed with privatized public-service companies. This law will also allow the Executive Branch of Government to fix public utility 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.

In July 2004, the UNIREN made a proposal to TGS to adjust the license contractual terms, which stipulates, among other issues, a 10% rate increase effective as from 2005 as well as a comprehensive rate review effective as from 2007 and the waiver by TGS and its shareholders to claims based on the emergency situation under Law No. 25,561 before the agreement effective date, and to hold the Argentine Government harmless against any claim that may proceed based on the same grounds. Considering that it does not reflect the outcome of the meetings held with the UNIREN, TGS requested to continue with the negotiation process so as to reach a comprehensive agreement during the first half of 2005. On April 27, 2005, the public hearing called by the UNIREN was held to analyze the proposal made on July 2004. During such meeting, the UNIREN repeated its 10% increase proposal and proposed to bring forward the comprehensive rate review process so that the new rate charts may take effect during 2006. The Company stated which features of the original proposal should, in its opinion, be improved and that it was willing to continue negotiating its terms. In June and November 2005, TGS received two new proposals from the UNIREN, which were made in conformity with the previous one and incorporating as a new requirement that TGS and its shareholders shall waive any future claim related to the PPI rate (United States Producer Price Index) adjustments that were not applied in 2000 and 2001. TGS answered these proposals and stated that the original 10% increase was not sufficient and, jointly with Petrobras Energía, agreed not to make any claims and file any appeals

F-36

and actions in an arbitration tribunal or an administrative or judicial court in Argentina or abroad, provided that a renegotiation agreement was reached. In addition, the other shareholders in CIESA, which filed a claim against Argentina with the International Centre for Settlement of Investment Disputes (ICSID), reported that they would only consider waiving it should it be fairly compensated.

In May, 2005, Transener and Transba signed memorandum of understanding with the UNIREN, which included the terms and conditions that form the bases for the comprehensive renegotiation agreement regarding both companies’ concession contracts. After fulfilling several steps, the memorandums of understanding were ratified by the Executive Branch in November 2005.

In June 2005, Edesur signed a letter of understanding with the UNIREN as part of the renegotiation process involving the related concession contract. Based on this Letter of Understanding, in August 2005, the parties signed a Memorandum of Understanding that includes, among other matters, the terms and conditions that, once the procedures established by regulations are fulfilled, they shall be the substantive basis for amending the concession agreement. The document establishes that from the execution of the Letter of Understanding through June 30, 2006, a complete rate review will be performed, which will allow fixing a new rate system effective August 1, 2006, and for the following five years. Also, it established a transition period for which the following was agreed upon: (i) a transitional rate system as from November 1, 2005, with an increase in the average service rate not exceeding 15%, applicable to all rate categories, except for residential rates; (ii) a mechanism to monitor costs, which allows for reviewing rate adjustments; (iii) restrictions on dividends distribution and debt interest payment during 2006; (iv) investment commitments for 2006; (v) service provision quality standards; and (vi) restrictions on Distrilec regarding a change in its interest or the sale of its shares in Edesur. As a preliminary condition for the Executive Branch to ratify the Memorandum of Understanding, Edesur and its shareholders shall suspend all pending claims that are based on the measures resolved as from the emergency situation established by Public Emergency Law in connection with the concession agreement. As of the date of issuance of these financial statements, the Memorandum of Understanding was approved by the Argentine Senate. Its approval by the House of Representatives and ratification by the Federal Executive are still pending.

It is not possible to predict the future development of the rates and concession agreements renegotiation processes or their effects on the companies’ results of operations and financial position.

As of December 31, 2005, the book value of the equity interests in CIESA, Distrilec and Citelec amounted to 407, 660 and 143 (net of adjustments made to adapt CIESA’s valuation method to those of the Company of (40) and 83 corresponding to the purchase price allocated to Distrilec’s fixed assets recorded by the Company at the time of the acquisition of a portion of its interest). Additionally the valuation of CIESA includes 166 corresponding to the transfer to Enron of its interest in TGS (See Section III). The book value of the equity interest in Citelec was exposed net of a valuation allowance, at its recoverable value of 145. As of December 31, 2004, the valuation of the equity interests in CIESA, TGS, Distrilec and Citelec amounted to 206, 151, 678 and 116 respectively (net of adjustments made to adapt CIESA and TGS’s valuation method to those of the Company of (43) and (11), respectively, and 87 corresponding to the purchase price allocated to Distrilec’s fixed assets recorded by the Company at the time of the acquisition of a portion of its interest). As of December 31, 2003, the valuation of the equity interests in CIESA, TGS, Distrilec and Citelec amounted to 190, 140, 691 and 158 respectively (net of adjustments incorporated to adapt CIESA and TGS valuation methods to those of the Company amounted to 45 and 12, respectively, and 91 corresponding to the purchase price allocated recorded by the Company at the time of the acquisition of the interest in Distrilec)

The book value of the equity interests does not exceed their recoverable value. To estimate the recoverable value of the investments in CIESA and TGS, the Company’s Management privileges the measure regarding the listed price of TGS’s shares, as it considers that the use of the related values in use is severely subject to the uncertainties of the continuity of the rate renegotiation process with the Federal Government and the CIESA’s financial debt renegotiation. In estimating the respective cash flows, which is necessary for estimating the values in use, this uncertain situation entails structuring and analyzing several possible scenarios for future projections, weighing extremely subjective likelihood of occurrence, which condition the appropriateness and reliability of the resulting values. Such methodology has been consistently applied through June 30, 2005, in estimating the recoverable value of the investment in Citelec, by considering the listed price of the Transener’s shares. As from September 30, 2005, by virtue of the filing of the plan contemplated for the divestiture (see Section I), the shares held in Citelec were valued up to the cap of the recoverable value determined based on the probable net realizable value.

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III. CIESA’s Master Settlement Agreement and Mutual Release Agreement

In April 2004, the shareholders of CIESA celebrated a master settlement 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. The terms of the Master Agreement include the transfer of the technical assistance agreement to Petrobras Energía, which was materialized in July 2004. In addition, to provide the necessary flexibility to make progress in restructuring CIESA’s financial debt, the Master Agreement establishes certain share transfers. On August 29, 2005, after the relevant regulatory authorities’ approvals, Enron transferred 40% of the shares issued by CIESA to a trust and, at the same time, Petrobras Energía and its subsidiary, Petrobras Hispano Argentina S.A. transferred Class B shares of common stock issued by TGS (representing 7.35% of TGS’s capital stock) to Enron. In a second stage, pursuant to the terms of CIESA’s financial debt refinancing agreement, entered into in September 2005, once the appropriate approvals are obtained from Ente Nacional Regulador del Gas (Argentine Gas Regulatory Agency) and Comisión Nacional de Defensa de la Competencia (Anti-trust authorities), CIESA will deliver about 4.3% of the Class B shares of common stock held in TGS to its financial creditors as a partial debt repayment. These shares will be, afterwards, transferred to Enron in exchange for the remaining shares held by the latter in CIESA.

Once the debt restructuring is completed (Note 10.VIII), considering that in addition to the share transfers mentioned above the fiduciary ownership of the shares held in CIESA by the trust will be transferred to Petrobras Energía and Petrobras Hispano Argentina S.A. and new shares will be issued for the benefit of creditors, CIESA’s capital stock structure will be as follows: (i) Class A shares directly and indirectly held by Petrobras Energía S.A., representing 50% of the capital stock and votes in CIESA; and (ii) Class B shares held by the financial creditors of CIESA, representing the remaining 50% of the capital stock and votes in CIESA.

Considering the progress made in renegotiating CIESA’s debt and the favorable expectations regarding its outcome, which would result in an increased value of the equity interest in CIESA, the Company computed the book value of the interest in TGS transferred to Enron as part of the valuation of its equity interest in CIESA, which is presented as non-current investment.

IV. Expansion of TGS’s gas transportation system

In accordance with the establishment by the Argentine Government of a framework for the creation of trust funds for financing expansions to the natural gas transportation system, 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, which entered totally into operations by the end of August 2005. TGS was in charge of managing the project and will be operating and maintaining the new facilities.

The trust fund invested about US$ 311 million, which will be repaid with 20% of the revenues from the firm additional capacity contract, plus an additional tariff to be invoiced to certain customers. In turn, TGS invested US$ 40 million in such expansion, which will be repaid with 80% of the revenues from the additional capacity contracted.

V. Transener S.A.’s financial debt restructuring

On June 30, 2005, Transener S.A. concluded the restructuring process of its financial debt and, as of the offer maturity date, it obtained the acceptance of regular creditors representing 98.8% of the total pending paid debt. The redeemed debt represented a nominal value of about US$ 460 million. As a result of the decisions made by creditors, the prorating and assignment mechanisms and further terms and conditions of the restructuring offer, Transener S.A. issued corporate bonds and made payments in cash pursuant to the following conditions:

(1)

Issuance of corporate bonds at par for a nominal value of about US$ 80 million, with final maturity in December 2016, accruing interest at a 3% annual rate until December 2007, and then increasing by 4% to 7% until the maturity term thereof.

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(2)

Issuance of discount corporate bonds for a nominal value of about US$ 200 million, with final maturity in December 2015, accruing interest at a 9% annual rate until December 2008, and 10% for the remaining period.

(3)

Issuance of 76,017,610 Class “B” shares. At the end of the term for the holders of Transener S.A.’s class “C” shares to exercise the preemptive right and the right to accrue, the Company will make available 8,447,500 class “B” shares for shareholders or will deliver cash in lieu of class “C” shares.

(4)

Payment in cash for an amount of about US$ 70 million.

Pursuant to the financing agreements signed in connection with the debt restructuring, Transener S.A. was required to comply with a series of restrictions including, among others, restrictions on debt issuance, new investments, sale of assets and dividend distribution.

As the result of the issuance of shares described in (3), Citelec’s participation in Transener decrease from 65% to 52.7%.

10. Financing

The detail of debt as of December 31, 2005 and 2004, is as follows:


	12/31/2005			12/31/2004
	Current		Non-current	Current		Non-current
Financial institutions	1,238		887	340		933
Notes	541		4,063	1,292		4,821
Investment agreement with IFC	—		—	67		345
Related companies (Note 18)	26		758	10		149

	1,805	(a)	5,708	1,709	(a)	6,248

(a) Includes 682 and 1,056 corresponding to current portion of long-term debt for the years ended December 31, 2005 and 2004, respectively.

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 starting May 5, 2003, or for 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, Certificate No. 290, dated July 3, 2002 and Certificate No. 296 dated September 16, 2003, of the CNV.

As of December 31, 2005, 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.

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•

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 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 six-month LIBOR plus 1%. As of December 31, 2005, 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, 2005, as they were not completely exchanged, the Company is carrying US$ 170,000 of such issuance in its own portfolio net of the nonconvertible notes.

•

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, 2005, under the medium-term Global Program whose date 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 all the corporate notes under both programs were used to refinance liabilities, and 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 the “Other receivables” account.

II. Cross default covenants

Class 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 Petrobras Energía 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.

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 Petrobras Energía 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.

The remaining outstanding amount of the Sixth Series and Class B notes does not include cross default covenants.

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

F-40

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 the corporate bonds that formed part of the debt refinanced, 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. These loans may be settled in advance at any time, at Petrobras Energía’s discretion, and the remainder may be settled with the use of cash inflows. As of December 31, 2005, the amounts outstanding from the financing of the plant were US$ 20 million, of which US$ 10 million is related to a contract which contains restrictive covenants, including a restriction on selling or leasing more than 40% of the plant during the period 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 composed of tranches A and B of US$ 20 million and US$ 60 million, respectively. The applicable interest rate was LIBOR plus 3.25%. Amortization of the principal has been as from June 2002, in 16 and 12 semiannual installments for tranches A and B, respectively. In December 2005, the Company paid in advance the remaining principal.

The IFC financing was completed by issuing preferred stock of Innova in the amount of US$ 5 million.

The funds provided by the IFC were used to construct styrene and polystyrene plants in the Brazilian State of Rio Grande do Sul. The loan was secured by a mortgage on certain real property owned by Innova.

VI. 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, which were cancelled in advance during 2005.

The loan was primarily composed of a Tranche A for US$ 80 million, maturing in a term of eight and a half years, 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 nine and a half years, at an annual LIBO nominal rate + 1.50%.

The funds obtained from this loan were used in developing the Acema, Mata, La Concepción and Oritupano Leona areas, in Venezuela.

VII. Edesur Indebtedness

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 year. As of December 31, 2005 Edesur paid 8 in advance, leaving 32 at the end of the year.

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The Class 6 notes were 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 year, plus a differential margin of 3% per year.

Edesur applied the net proceeds from this issuance to refinancing its financial liabilities.

In addition, Edesur has signed loan agreements with banks. Some of Edesur’s loan agreements contain cross-default clauses, whereby lending banks may declare all owed amounts as due and payable in the event that any debt was not settled in due time, provided that such amounts due and payable exceeded those stipulated in the agreements. Some of these agreements also contain cross-acceleration clauses, whereby lending banks may declare all owed amounts as due and payable in the event that Edesur was required to pre-settle any other debt stipulated in the agreements.

VIII. CIESA and TGS indebtedness

In the wake of the new Argentine macroeconomic situation, starting with the enactment of the Public Emergency Law (see Note 9.II), CIESA did not pay at maturity, in April 2002, 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.

In September 2005, CIESA signed an agreement to restructure its financial debt with all its financial creditors. The debt to be restructured, in default as from April 2002, amounted to about US$ 270 million.

In view of the agreement reached, CIESA refinanced the debt for an amount of about US$ 23 million at a 10-year term and, once approvals are obtained from the Argentine Gas Regulatory Agency and the Argentine Committee for Competition Defense, it will provide its financial creditors with about 4.3% of TGS’s Class “B” common shares and will capitalize the remaining debt by issuing shares in favor of creditors.

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. As TGS could not meet the majority required by regulation, on May 14, 2003, 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 December 12, 2004. By that 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 (i) a cash payment equivalent to 11% of the outstanding principal amount, (ii) new debt securities for the remaining 89% of the outstanding principal amount, structured into two tranches, A and B, with quarterly amortization terms of 6 and 9 years respectively and a grace period of six years for tranche B, accruing interest rates ranging from 5.3% to 10 %, and (iii) 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.

The new debt has an early amortization clause, the application and amount of which, as the case may be, depends on the consolidated debt coefficient, the liquidity level and certain payments to be made subsequently by TGS.

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IX. Detail of long-term debt

Long-term debt as of December 31, 2005, is made up as follows:


Type	Amount	Currency	Annual interest rate
	(In millions of pesos)
Financial institutions	15	US$	Libo+0.125
	10	US$	Libo+0.75
	45	US$	Libo+4.65
	107	US$	Libo+1.35
	46	US$	Libo+3.1
	28	US$	7.75%
	11	US$	8.09%
	22	US$	8.35%
	61	US$	6.15%
	3	US$	7.23%
	16	US$	9.13%
	2	US$	7.65% to 9.00%
	222	US$	5.30% to 7.50%
	299	US$	7.00% to 10.00%

Related companies (See Note 19)	152	US$	7.50%
	606	US$	7.22%

Notes
Serie Sixth	99	US$	8.125%
Class G	758	US$	9.00%
Class H	550	US$	9.00%
Class I	1,058	US$	8.125%
Class N	241	US$	Libo+1
Class Q	11	US$	5.625%
Class R	608	US$	9.375%
Class 6 (Edesur)	29	$	7.50%
Serie A (TGS)	317	US$	5.30% to 7.50%
Serie B-A and B-B (TGS)	392	US$	7.00% to 10.00%

	5,708

The maturities of long-term debt as of December 31, 2005, are as follows:


From 1 to 2 years		1,138
From 2 to 3 years		403
From 3 to 4 years		763
From 4 to 5 years		1,268
Thereafter		2,136

		5,708

11. Fund for investments required to increase the electric power supply in the electronic wholesale market (FONINVEMEM)

Through Resolution No. 712/04, the Energy Department created the FONINVEMEM for the purpose of increasing the supply of electrical power generation in Argentina.

Petrobras Energía contributes to this fund through 65% of 2004-2006 revenues with respect to the margin between the energy sale price and the variable generation cost. The total nominal value of the revenues contributed as of December 31, 2005, amounted to 54, out of which 41 is related to the year then ended. The final amount will depend, among other factors, on water conditions, the Company’s generation units delivered by CAMMESA and the resulting energy prices.

F-43

On October 17, 2005, by virtue of Resolution No. 1,193 of the Energy Department, Petrobras Energía, jointly with other creditors of the electronic wholesale market, formally stated its decision to manage the construction, operation and maintenance of two plants of at least 800 MW each, expecting to start operating gas turbines in December 2007 and the complete combined cycles in June 2008. Petrobras Energía will hold an estimated interest of about 10% in the Combined Cycles, which will be determined accurately when the construction of the power plants is concluded. After the start up of such plants, the amounts contributed to the FONINVEMEN, converted into US$ and accruing interest at through LIBOR plus 1% per year, shall be reimbursed in 120 monthly installments.

Two trusts will be created within CAMMESA’s sphere to purchase, acquire and operate the plants. These plants will be subject to a 10-year contract for the supply of electrical power with CAMMESA, with a price covering all their costs and the payments to the FONINVEMEM.

12. Income tax and deferred tax

The Company’s provision for income tax was comprised of the following:


	12/31/2005		12/31/2004		12/31/2003
Income tax for the year
Current	(144	)	(124	)	(82	)
Deferred tax gain - (loss)	(237	)	335		53

Total income tax	(381	)	211		(29	)


	12/31/2005		12/31/2004
Deferred tax
Deferred tax assets
Tax loss carryforwards and other tax losses	1,658		1,785
Reserve for contingencies	74		74
Pension plan obligations	4		3
Derivatives	6		191
Allowance on receivables	9		8
Other	54		78
Deferred tax allowance (Note 13 and Note 17)	(1,359	)(3)	(1,380	)

Deferred tax liability
Revenue recognition	(34	)	(44	)
Property, plant and equipment	(78	)	(145	)
Prepaid expenses	(8	)	(15	)
Timber	—		—
Non-current investments	(77	)	(70	)
Other	(3	)	(2	)

	246	(1)	483	(2)

(1)	400 are presented in the non-current “Other receivables” line and 154 are presented in the non-current “Taxes payable” line.

(2)	600 are presented in the non-current “Other receivables” line and 117 are presented in the non-current “Taxes payable” line.

(3)	Including 110 related to the deferred income tax assets allowance for Venezuelan operations.

As of December 31, 2005, the Company keeps recorded a 1,164 allowance on tax loss carryforwards because, as of that date, it is not possible to guarantee that future taxable income will be sufficient to absorb net temporary differences and accumulated tax loss carryforwards.

Upon the issuance of the annual financial statements, the Company’s Management evaluates the recovery of tax loss carryforwards taking into consideration, among other elements, the projected business profits, tax planning strategies, temporariness of future taxable income, considering the term of expiration of the tax loss carryforwards, the future reversions of the existing temporary differences and the recent-year tax history. All the evidence available both positive and negative is duly weighted and considered in the analysis.

F-44

At the time of issuance of the financial statements for the fiscal years ended on December 31, 2005, and 2004, the Company’s Management partially reversed the tax loss carryforwards allowance recorded in prior years recognizing a gain of 197 and 299, respectively. Prospectively, the Company’s Management will continue analyzing the feasibility of recovering the tax loss carryforwards for which the allowance was recognized.

The reconciliation of the 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:


	12/31/2005		12/31/2004		12/31/2003
Income before income tax and minority interests in the subsidiaries, income	1,228		439		430
Statutory tax rate	35	%	35	%	35	%

Statutory tax rate applied to income for the year	430		154		151
Permanent differences at income tax rate
- Equity in losses of non-current investments	(124	)	(176	)	(59	)
- Inflation adjustment	118		144		157
- Changes in allowances for tax loss carryforwards	(21	)	(425	)	(511	)
- Loss (gain) in foreign subsidiaries	(14	)	68		277
- Other	(8	)	24		14

	381		(211	)	29

Tax loss carryforward and deferred losses include the following items and may be used through the dates indicated below:


Items	12/31/2005	12/31/2004	12/31/2003
General tax loss carryforward	1,573	1,615	1,702
Deferred losses	85	170	211

	1,658	1,785	1,913


Use up to	12/31/2005	12/31/2004	12/31/2003
2007	1,631	1,615	1,743
2010	12	85	85
2011 and thereafter	15	85	85

	1,658	1,785	1,913

F-45

13. Contingencies, allowances and environmental matters

The movements of reserves for contingencies and allowances were as follows:


Account	Balances at beginning	Increase	Decrease		Balances at end
Deducted from assets:

Current
For doubtful accounts	128	2	(45	)	85
For other tax credits	—	78	—		78
Inventories’ obsolescence	2	1	—		3
For investments (Note 9)	—	145	—		145

	130	226	(45	)	311

Non-current
For other receivables
Tax loss carryforwards	1,210	85	(21	)	1,274
Deferred tax losses	170	—	(85	)	85
Tax on minimum presumed income	45	—	(45	)	—
For investments (Note 23.b and Note 9)	10	59	—		69
For property, plant and equipment	376	255	(46	)	585
Inventories’ obsolescence	2		—		2

	1,813	399	(197	)	2,015

TOTAL 2005	1,943	625	(242	)	2,326

TOTAL 2004	2,323	31	(411	)	1,943

Included in liabilities:

Current
For contingencies
Labor and commercial contingencies	31	17	—		48

	31	17	—		48

Non-current
For contingencies
Labor and commercial contingencies	76	27	—		103

	76	27	—		103

TOTAL 2005	107	44	—		151

TOTAL 2004	121	28	(42	)	107

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 requirements are currently interpreted and enforced, including sanitation commitments assumed. The Company and its subsidiaries have not incurred any material pollution liabilities 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 these new projects have not had any 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. That is why its strategic and business plans include excellence in management and performance as a goal in Quality Assurance, Safety, Health and Environmental Protection (designated by the Spanish initials CSMS).

With its CSMS 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 policies of CSMS take into account advanced concepts, such as: eco-efficiency, life cycle, continuous improvement and operations sustainability.

F-46

The Company has been a pioneer in environmental practices certification (ISO 14001) both in Argentina and in the oil industry worldwide. The Company has 23 assets certified, including ISO 14001 (Environment), ISO 9001 (Quality) and OHSAS 18001/IRAM 3800 (Security and Occupational Health) with regular external audit procedures held by third parties audit firms.

Through external audits by licensed environmental certification agencies and internal audits performed periodically, the Company monitors its operations to meet the CSMS policies mentioned above within the framework of ongoing improvement with the challenge of consolidating its performance in CSMS guaranteeing the sustainability of results. Consistently, the Company will continue making investments aimed, among other things, at implementing improvements in prevention systems and production installations.

b) TGS stamp tax

As of the date of issuance of these financial statements, TGS is party to a claim by the Tax Bureau of the Province of Río Negro for stamp tax purportedly due on the contracts transferred by GdE and service provision offers between TGS and its customers. The total amount claimed is 438 (including fines and interest calculated as of the date of each claim). Additionally, the Tax Bureau of the Province of Neuquén maintains a claim against TGS for stamp tax due on service provision offers between TGS and its customers. The total amount claimed is 219 (not including fines and interest). In each case, TGS filed adminstrative appeals before the respective Provincial Tax Bureau. Subsequently, TGS petitioned the Supreme Court of Justice of the Nation (“SCJN”) for declaratory judgments on the legitimacy of the provincial claims. The SCJN granted the precautionary measure requested and ordered the provinces’ Tax Bureaus to abstain from any acts aimed at collecting the stamp tax until the court had ruled on the basic issue.

In November 2005, the Argentine Supreme Court dismissed the Province of Rio Negro’s right to levy taxes on the transportation offers and contracts. In addition, the Neuquén DGR (Provincial Tax Authorities) dismissed its claim through Resolution No. 705/05.

c) Value-added tax on operations in Ecuador

As of December 31, 2005, the Company -as is the case of many other companies producing and exporting oil in Ecuador- has a tax credit from Ecuadorian 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 the reimbursement because it considers that such item had already been considered when determining the parties respective shares of the oil produced. The 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 this same dispute with the Ecuadorian Government. The international arbitration award established that the VAT in question should be reimbursed. The Ecuadorian Government has objected to the arbitration and considered it void. On August 11, 2004, the Ecuadorian National Congress passed a VAT interpretation law, which provides that the reimbursement of the tax is not applicable to the oil industry. As of December 31, 2005 the credits mentioned amounted to 78.

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. Notwithstanding, and without constituting a waiver of its legitimate rights, as of December 31, 2005, the Company recorded a 78 allowance related to these receivables (included in Note 13).

d) Tax issues

The AFIP filed a claim to collect the tax on the transfer of fuels, which, according to tax authorities, would be levied on the import of benzene without considering that it will be used for petrochemical purposes. The total amount claimed, including interest, is 150. Company’s Management and its legal counsel consider that there are legal reasons to assert that such a claim is not valid, and it filed a brief challenging the validity. Company’s Management based its position on the law regulating the tax, which sets forth exemptions for transfers made for a valuable consideration or gratuitously for the chemical and petrochemical industries, notwithstanding whether it is purchased locally, imported or manufactured by the Company itself.

F-47

The Company holds interpretative differences with the AFIP (Argentine Federal Public Revenues Administration), provincial tax authorities and foreign tax authorities about taxes applicable on oil and gas activity. Company’s Management and its legal advisors estimate that the outcome of these differences will not have significant adverse effects on the Company’s financial position or results of operations.

14. Contractual commitments, warranty bond, suretyships and guarantees granted

The warranty bonds, suretyships and guarantees as of December 31, 2005, which are not disclosed in the remaining notes, amount to 45.

In addition, as of December 31, 2005, the Company had the following contractual commitments:


	Total (Units)	Total (Millions of Pesos)	Until
Purchase Commitments
Transportation agreement with OCP (in millions of bbls.) (1)	356	2,512	2018
Long-term service agreement	—	68	2007
Bolivian gas transportation agreement (in MMm3)	6,352	219	2019
Petroleum services and materials	—	509	2009
Ethylene (in thousands of tons)	453	1,427	2015
Benzene (in thousands of tons)	1,283	3,688	2015
Transportation capacity with TGs (in M dam3)	10,791	559	2014
Gas purchase agreement for Genelba (in M dam3)	460	105	2008

Sales commitments
Natural gas (in MMm3)	18,415	2,819	2018
Styrene (in thousands of tons)	14	54	2007
Electric power (in MWh)	1,707	111	2006
LPG (in thousands of tons)	32	31	2006

(1)	Net of transportation capacity sold to third parties (see Note 6)

15. Contribution, benefit pension and stock option plans of Petrobras Energía

a) Retirees and Pensioners Fund

Supplementary Pension Plan for Personnel

In November 2005, the Board of Directors of Petrobras Energía approved the implementation of a defined voluntary contributions plan for all of the Company’s employees. Through this plan, Petrobras Energía will make contributions to a trust to be constituted. Such contributions will be related to amounts equivalent to the contributions made by the participating employees to a mutual fund or AFJP, at their choice, in conformity with a scheme defined for each salary level. The participating employees may make voluntary contributions exceeding those established in the mentioned scheme, which will not be considered for purposes of the contributions to be made by the Company. The employees adhering to the plan upon the launch thereof will be entitled to choose, one time only, to make retroactive contributions as of January 1, 2004, or as of the date they started working at Petrobras Energía, which ever is most recent. As of December 31, 2005, Petrobras Energía recognized a liability and a loss of 7, related to the estimated obligation for this plan.

F-48

In addition to the plan described above, the Company will implement a benefit policy for all its employees, which will consist of granting, upon retirement, a one-month salary per year of service at the Company, in conformity with a decreasing scale considering the years of effectiveness of the Supplementary Pension Plan for Personnel.

Compensatory Fund

All employees of the Petrobras Energía who take part without interruption in the defined contribution plan effective at each opportunity, that have joined the Company prior to May 31, 1995, and who have reached a certain number of years of service, are participants in this defined benefit plan. The employee benefit is based on the last computable salary and years of service of each employee included in the fund.

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 equals the one stipulated in this plan.

The plan calls for a contribution to a fund exclusively by Petrobras Energía and without any contribution by the employees, provided that they should make contributions to the retirement system for their whole salary. The Company determines the liability related to this plan by applying actuarial calculation methods. The assets of the fund were contributed to a trust. The goals with respect to asset investment are: (i) the preservation of capital in US dollars, (ii) the maintenance of high levels of liquidity, and (iii) the attainment of the highest yields possible on a 30-days basis. For this reason, the assets 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. As of December 31, 2005, the most relevant actuarial information on the defined-benefits pension plan is as follows:


Plan assets	40
Projected benefit obligations	(94	)

Net underfounding	(54	)
Unrecognized actuarial loss	41

Net liability recognized	(13	)

According to its by-laws, Petrobras Energía 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.

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, Petrobras Energía will be entitled to make a choice and use it, in which case it would have to notify the trustee thereof.

Petrobras Energía admitted the advanced collection of this plan by beneficiaries should they expressly state so. All the individuals who exercised the abovementioned option before February 13, 2003, have lost their rights to collect their retirement supplement, thus they are no longer plan beneficiaries.

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:

F-49

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 the same 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, 2005 the exercised options amounted to 4,644,196, almost entirely 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”). As of December 31, 2005 the exercised options amounted to 461,177, almost entirely in cash.

Beneficiaries of this plan will be entitled to exercise their rights from the dates mentioned above, until March 5, 2007.

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, 2005 the exercised options amount 2,854,465, almost entirely in cash.

ii.

352,347 options to receive the same number of shares at no cost to the beneficiary. These options may be exercised as from May 29, 2004 (“full value”). As of December 31, 2005 the exercised options amounted to 324,982, almost entirely in cash.

Beneficiaries of this plan will be entitled to exercise their rights from the dates mentioned above, until May 29, 2006.

The cost of this 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 3, 6 and 8 were charged to operating expenses for the years ended December 31, 2005, 2004 and 2003, respectively.

The following table presents a summary of the status of the Company’s stock option plans as of December 31, 2005, 2004 and 2003.


	2005			2004			2003
	Options (a)		Weighted- Average Exercise Price	Options (a)		Weighted- Average Exercise Price	Options (a)		Weighted- Average Exercise Price
Outstanding at the beginning of the year	3,195,192		1,60	7,557,205		1,59	9,339,012		1,58
Exercised	(1,996,389	)	1,60	(4,362,013	)	1,58	(1,781,807	)	1,56

Outstanding at the end of the year	1,198,803		1,59	3,195,192		1,60	7,557,205		1,59

Exercisable at the end of the year	1,198,803		1,59	2,599,178		1,59	4,463,194		1,56

(a)	Includes both options to receive an “appreciation right” and “full value”.

As of December 31, 2005 the weighted average remaining contractual life is 1 year and 1,198,803 of these options are exercisable.

F-50

16. Capital stock and restrictions on unappropriated retained earnings

As of December 31, 2005 the Company’s capital stock totaled $2,132,043,387 fully subscribed, issued, paid-in and registered. Changes in capital stock in the last three fiscal years:


	December, 31
	2005	2004	2003
Common stock – face value $	1	1	1

Class B: 1 vote per share	2,132	2,132	2,132

Since January 26, 2000, the Company Class B shares are listed on the Buenos Aires Stock Exchange and on the New York Stock Exchange.

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 (See Note 25).

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 thirty-five percent income tax withholding, 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.

17. Other receivables, other liabilities, other operating income, other expenses, net and supplemental cash flow information.


	12/31/2005			12/31/2004
	Current	Non-current		Current	Non-current
a) Other receivables
Joint ventures	60	—		33	—
Related companies (Note 18)	56	3		18	4
Tax credits	298	220		310	163
Deferred tax assets	—	1,759		—	1,980
Advisory services to other companies	6	—		13	—
Receivables from the sale of companies	—	—		—	9
Letters of credit advances	—	—		121	—
Prepaid expenses and interest	35	28		44	34
Other collaterals	35	—		64	—
Minimum presumed income tax allowance (Note 13)	—	—		—	(45	)
Deferred tax allowance (Note 12)	—	(1,359	)	—	(1,380	)
Other	136	21		153	19

	626	672		756	784

F-51


	12/31/2005		12/31/2004
	Current	Non-current	Current	Non-current
b) Other liabilities
Debt for investments in companies	6	—	11	—
Derivatives	50	—	385	—
Unified Fund - Basic Price of Electric Power (a)	1	3	1	4
Related companies (Note 18)	2	—	2	—
Receivables in advance	8	55	55	12
Accrual for expenses
- Environmental remediation	29	56	43	44
- Other	—	42	41	—
Joint ventures	—	—	5	—
Innova preferred stock	—	15	—	15
Litigation reserves and fines	22	30	52	—
Abandonment costs in oil & gas areas	—	126	—	91
Other	50	12	62	12

	168	339	657	178

(a)

To ensure completion of works in Pichi Picún Leufú Hydroelectrical Complex within the term of the concession and a profitability to make the investment viable, the Energy Department granted the Company the amount of 25. For the purpose of determining whether or not this 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. This 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 this system, an Annual Monomial Support Price (AMSP) was set in the amounts of US$/Kwh 0.021 and US$/Kwh 0.023 for the first and second period, respectively. In order to determine the amount to be reimbursed, each 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 that year will be determined. Owing to the selling prices set for the energy generated by the Complex, and the future prices estimated, considering that it implies profitability reinsurance, as of December 31, 2005 the Company accrued a profit of 22.


	12/31/2005		12/31/2004		12/31/2003
c) Other operating expenses
Advisory services to other companies	37		35		36
Idle capacity	—		—		(7	)
Environmental remediation expenses	(29	)	(51	)	(58	)
Taxes on bank transactions	(90	)	(84	)	(45	)
Contingencies	(3	)	(28	)	(57	)
Oil transportation agreement with OCP	(184	)	(184	)	—
Fundopem (a)	42		27		—
Tax credit allowance	(78	)	—
Others	(24	)	(39	)	8

	(329	)	(324	)	(123	)

(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.

F-52


	12/31/2005		12/31/2004		12/31/2003
d) Other income (expense), net
Impairment of assets
- Areas in Venezuela (Note 6)	(255	)	(12	)	—
- Debt to exploitation partners in Venezuela	(55	)	(15	)	(27	)
- Gas areas in Argentina (Note 6)	44		—		(37	)
- Operations in Ecuador	—		—		(309	)
- Enecor S.A.	(16	)	—		—
- Other assets	—		(20	)	(38	)
Seniat claim - Venezuela	(54	)	—		—
Gain from AE (out-of-court composition with creditors) - Edesur S.A.	—		18		—
Financial debt refinancing	—		(12	)	—
Sale price adjustment - Conuar S.A.	23		—		—
Disposal of property, plant and equipment	(24	)	(11	)	(27	)
Losses from settled financial debt in advance	(9	)	—		—
Other, net	14		12		(9	)

	(332	)	(40	)	(447	)


	2005		2004		2003
e) Supplemental cash flow information
Cash	111		141		167
Time deposits and Mutual Funds	679		926		921
Others	—		—		3

Cash and cash equivalent	790		1,067		1,091

As of December 31, 2005, 2004 and 2003, the accounts payable increased for the acquisition of property, plant and equipment in the amount of 56, 176 and 115, respectively.

18. Balances and transactions with related companies

The outstanding balances from transactions with related companies as of December 31, 2005 and 2004, are as follows:


	2005
	Current						Non-currrent
Company	Investments	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Loans	Other receivables	Investments	Loans
Petroquímica Cuyo S.A.	—	8	4	—	—	6	—	—	—
Oleoducto de Crudos Pesados Ltd.	—	—	—	—	—	—	—	142	—
Transportadora de Gas del Sur S.A.	—	9	—	6	—	—	—	—	—
Refinería del Norte S.A.	—	17	5	40	—	—	—	—	—
Petrobras International Finance Co.	—	95	—	5	—	—	—	—	—
Petróleo Brasileiro S.A. - Petrobras	—	3	15	17	—	—	3	—	—
Petrolera Entre Lomas S.A.	2	—	—	69	—	—	—	—	—
PROPyME	—	—	—	—	—	—	—	6	—
Petrobras Intemacional - Braspetro B.V.	—	—	25	—	—	20	—	—	758
Others	—	2	7	2	2	—	—	2	—

Total	2	134	56	139	2	26	3	150	758

F-53


	2004
	Current						Noncurrent
Company	Investments	Trade Receivables	Other Receivables	Accounts Payable	Other Liabilities	Loans	Trade Receivables	Investments	Other Liabilities	Loans
Petroquímica Cuyo S.A.	—	—	1	—	—	6	—	—	—	—
Oleoductos de Crudos Pesados Ltd.	—	—	—	—	—	—	—	156	—	—
Petrolera Entre Lomas S.A.	—	—	—	46	—	—	—	—	—	—
Transportadora De Gas del Sur S.A.	—	1	—	3	1	—	—	—	—	—
Refineria delNorte S.A.	—	9	6	17	—	—	—	—	—	—
Petrobras International Finance Co.	119	23	—	5	—	—	—	—	—	—
Petroleo Brasileiro S.A. - Petrobras	—	11	9	—	—	—	—	—	—	—
Petrobras Internacional - Braspetro BV.	—	—	—	—	—	4	—	—	4	149
Others	—	4	2	7	1	—	3	—	—	—

Total	119	48	18	78	2	10	3	156	4	149

The main transactions with affiliates for the years ended December 31, 2005, 2004 and 2003, are as follows:


	2005		2004		2003
Company	Purchases	Sales	Purchases	Sales	Purchases	Sales
Oleoductos del Valle S.A.	15	—	20	—	17	—
Transportadora de Gas del Sur S.A.	30	—	35	—	13	—
Refineria del Norte S.A.	122	82	77	46	57	43
Petrobras International Finance Co.	118	977	121	488	47	209
Petrolera Entre Lomas S.A.	344	1	198	—	118	—
Petroleo Brasileiro S.A.	—	10	—	240	6	155
Petrobras Bolivia Refinacion. S.A.	3	34	—	36	—	—

Total	632	1,104	451	810	258	407

19. 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, refining and distribution, petrochemicals and gas and energy.

In keeping with management’s evaluation, during 2005, the Company’s management implemented certain minor changes to the segment information. The Company’s management grouped electricity and sale and transport of gas under the Gas and Energy segment. The sale and transport of gas formerly comprised, along with sale and transport of petroleum, the Hydrocarbon Marketing and Transportation business segment. In addition, the Company’s management grouped sale and transport of petroleum with the Oil and Gas Exploration and Production segment. The information contained in these financial statements for all periods presented is in accordance with the current management’s evaluation. According to this, the identified business segments are as follows:

The Oil and Gas Exploration and Production segment is composed of the Company’s participation in oil and gas blocks and its interest in Oleoductos del Valle S.A. and Oleoducto de Crudos Pesados Ltd.

The Refining and Distribution segment includes the Company’s operations in Refinería San Lorenzo and Bahía Blanca, its own gas station network and the Company’s interests in Refinería del Norte S.A. and Empresa Boliviana de Refinación S.A.

The Petrochemical segment includes the Company’s petrochemical operations, and its interests in Innova S.A. and Petroquímica Cuyo S.A.

Gas and Energy segment comprises operations in Marketing and Transportation of Gas and Electricity. The Marketing and Transportation of Gas operations includes the sale of gas and the liquefied petroleum gas brokerage and trading, and its interest in Transportadora de Gas del Sur S.A. The Electricity operations includes Company’s operations in the Genelba plant and in the 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 Corporate 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-segments transaction prices are made at market value.

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The following information shows total assets, total liabilities and net income (loss) for each of the business segments identified by the Company’s management:


	2005
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Gas and Energy		Corporate and Eliminations	Total
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Marketing and Transportation of Gas	Electricity	Corporate and Eliminations	Total
Total Assets	9,364	2,165	1,486	2,897	2,289	660	18,861
Total Liabilities	4,881	687	593	1,933	512	1,671	10,277


	2004
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Gas and Energy		Corporate and Eliminations	Total
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Marketing and Transportation of Gas	Electricity	Corporate and Eliminations	Total
Total Assets	8,913	2,129	1,380	2,748	2,414	691	18,275
Total Liabilities	4,323	847	619	1,922	467	2,395	10,573


	2005
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Gas and Energy				Corporate and Eliminations		Total
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Marketing and Transportation of Gas		Electricity		Corporate and Eliminations		Total
Statement of income
Net sales
To third parties	2,935		3,572		2,140		1,009		999		—		10,655
Inter-segment	1,722		284		38		110		18		(2,172	)	—

	4,657		3,856		2,178		1,119		1,017		(2,172	)	10,655
Cost of sales	(2,034	)	(3,749	)	(1,801	)	(849	)	(757	)	2,132		(7,058	)

Gross profit	2,623		107		377		270		260		(40	)	3,597

Administrative and selling expenses	(248	)	(251	)	(143	)	(22	)	(86	)	(191	)	(941	)

Exploration expenses	(34	)	—		—		—		—		—		(34	)

Other operating (expenses) income, net	(314	)	(5	)	33		32		(4	)	(71	)	(329	)

Operating income(loss)	2,027		(149	)	267		280		170		(302	)	2,293

Equity earnings of affiliates	13		100		7		16		30		—		166

Other (expenses) income	(1,447	)	73		(87	)	(215	)	(89	)	(81	)	(1,846	)

Net income (loss)	593		24		187		81		111		(383	)	613

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	2004
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Gas and Energy				Corporate and Eliminations		Total
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Marketing and Transportation of Gas		Electricity		Corporate and Eliminations		Total
Statement of income
Net sales
To third parties	2,080		3,085		1,857		930		811		—		8,763
Inter-segment	1,567		274		20		49		14		(1,924	)	—

	3,647		3,359		1,877		979		825		(1,924	)	8,763
Cost of sales	(1,747	)	(3,102	)	(1,503	)	(711	)	(628	)	1,900		(5,971	)

Gross profit	1,900		257		374		268		197		(24	)	2,972

Administrative and selling expenses	(221	)	(244	)	(123	)	(22	)	(75	)	(162	)	(847	)

Exploration expenses	(133	)	—		—		—		—		—		(133	)

Other operating (expenses) income, net	(286	)	(3	)	27		(1	)	11		(72	)	(324	)


Operating income (loss)	1,260		10		278		245		133		(258	)	1,668

Equity earnings of affiliates	31		58		16		10		(39	)	—		76

Other expenses	(1,043	)	(7	)	(66	)	214		(55	)	319		(1,066	)


Net income (loss)	248		61		228		41		39		61		678


	2003
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Gas and Energy				Corporate and Eliminations		Total
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Marketing and Transportation of Gas		Electricity		Corporate and Eliminations		Total
Statement of income
Net sales
To third parties	2,045		2,590		1,294		502		680		2		7,113
Inter-segment	944		112		—		19		11		(1,086	)	—

	2,989		2,702		1,294		521		691		(1,084	)	7,113
Cost of sales	(1,600	)	(2,441	)	(982	)	(281	)	(523	)	1,068		(4,759	)

Gross profit	1,389		261		312		240		168		(16	)	2,354

Administrative and selling expenses	(195	)	(251	)	(110	)	(34	)	(73	)	(107	)	(770	)

Exploration expenses	(360	)	—		—		—		—		—		(360	)

Other operating (expenses) income, net	(48	)	(12	)	(17	)	(1	)	17		(62	)	(123	)


Operating income (loss)	786		(2	)	185		205		112		(185	)	1,101

Equity earnings of affiliates	16		22		19		16		90		—		163

Other expenses	(947	)	7		(39	)	26		(19	)	89		(883	)


Net income (loss)	(145	)	27		165		247		183		(96	)	381

The following information shows total assets and net sales by geographic area.

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	2005
	Argentina	Venezuela	Bolivia	Peru	Brazil	Ecuador	Other	Eliminations		Total
Total Assets	12,318	3,588	389	957	706	791	112	—		18,861
Net sales	7,378	1,175	136	705	972	449	12	(172	)	10,655


	2004
	Argentina	Venezuela	Bolivia	Peru	Brazil	Ecuador	Other	Eliminations		Total
Total Assets	12,270	3,638	327	830	680	444	86	—		18,275
Net sales	6,429	811	108	458	774	211	11	(39	)	8,763


	2003
	Argentina	Venezuela	Bolivia	Peru	Brazil	Ecuador	Other	Eliminations		Total
Net sales	5,423	594	108	374	502	115	2	(5	)	7,113

20. Controlling Group

Petróleo Brasileiro S.A. – PETROBRAS, through Petrobras Participaciones, S.L., a wholly-owned subsidiary, is the controlling shareholder. As of December 31, 2005 Petrobras Participaciones S.L. owns 58.6% of Petrobras Energía Participaciones’s capital stock.

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.

21. Summary of significant differences between accounting principles followed by the Company 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 22 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

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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.

Under US GAAP, general price level adjusted financial statements are not required. However, pursuant to the instructions to Item 17 of Form 20-F, these adjustments are not removed when performing the reconciliation to US GAAP included in Note 22.

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 of December 31, 2005 and 2004, 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) 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.

Notwithstanding the above-mentioned criteria, and effective for fiscal years beginning as from January 1, 2006, according to changes introduced to Argentine GAAP, the Company decided to book the difference between the Property, Plant and Equipment carrying value adjusted for inflation (and other non-monetary assets) and their tax value as a temporary difference for deferred income tax purposes that would result in the recognition of a deferred tax liability, therefore unifying the treatment thereof with US GAAP accounting standards. (See Note 2.g and 25)

d) Deferred charges

Under Argentine GAAP, costs such as organization and pre-operating 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.

e) 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.

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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.

f) 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 proportional 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 (see US GAAP Summarized Consolidated Data in Note 22). The proportional consolidation of CIESA for fiscal years 2005, 2004 and 2003 under Argentina GAAP has been reversed for purposes of the US GAAP reconciliation.

g) Accounting for business combinations

Under Statement of Financial Accounting Standards (SFAS) No. 141, “Business Combinations” and SFAS No. 142 “Goodwill and Other Intangible Assets”, 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, are no longer amortized. Goodwill and indefinite lived intangible assets are assessed for impairment using fair value measurement techniques. The Company has completed the annual impairment test of goodwill under the standard and no additional adjustment was required.

The following summarizes the application of the business combination standards to certain transactions:

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 non-monetary 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

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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 2005, the Company recorded impairment charges under US GAAP for 975 in order to adjust the book value of its Venezuelan assets to their recoverable value related to Property, Plant and Equipment as described in Note 6 – Operations in Venezuela. Such impairment charges were not reflected under Argentine GAAP due to the fact that the carrying value of Property, Plant and Equipment was higher under US GAAP, due to the purchase price allocation described above.

As of December 31, 2005 under US GAAP the book value of the Company’s interest in Citelec and CIESA accounted for under the equity method is 28 and nil. As of December 31, 2004 the book value of the interest in CIESA, TGS and Citelec is nil, 92 and nil, under US GAAP.

Under US GAAP, once an impairment loss is allocated to the carrying values of the long-lived assets, the reduced carrying amount represents the new cost basis of the long-lived assets. As a result, SFAS 144 prohibits entities from reversing the impairment loss should facts and circumstances change in the future. Under Argentine GAAP, impairment charges can be reversed in future years due to changes in the above-mentioned facts and circumstances. As of December 31, 2005, the company recorded a 44 gain related to an impairment reversal of gas areas in Argentina. In the reconciliation to US GAAP included in Note 22, such gain was reversed.

3) 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.

h) 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 gain or loss is recognized currently in earnings in the “Financial income (expense) and holding gain (losses) account.

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.

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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 2005 and 2004), 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.

i) 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.

j) 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.

k) Minority interest

An adjustment to record the portion of all US GAAP adjustments attributable to minority interests in consolidated subsidiaries has been recorded.

l) 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.

m) 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.

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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.

n) 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.

o) 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 are no differences in the reported net income and earning per share for the years 2005, 2004 and 2003 based on SFAS No. 123, “Accounting for stock –based compensation”, amended by SFAS No. 148.

p) 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 22.

q) 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 22.

r) 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. (See Note 21.w)

In connection with the adoption of SFAS 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 22 reflects the difference described above in recognizing such change in accounting principle.

s) 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.

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t) 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.

u) 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. As of December 31, 2005, this additional liability is reported as an intangible asset and as other comprehensive income, taking into account the conditions mentioned above.

v) Troubled debt restructuring of TGS and Transener.

On December 15, 2004, and on June 30, 2005, TGS and Transener respectively concluded their debt restructuring process.

Under Argentine GAAP the Companies followed the provisions contained in RT No. 17 and accordingly, recorded gain on restructuring during the years ended December 31, 2005 and December 31, 2004 for Transener and TGS respectively.

Under US GAAP, following 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 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.

w) New accounting standards and developments under US GAAP

Compensation costs relating to Share-Based Payments

The FASB issued FASB Statement No. 123R, “Share-Based Payment” (“SFAS 123R”) in December 2004 which requires that compensation cost relating to the fair value of share-based payments be recognized 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.

In March 2005, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin No. 107 (SAB 107) which provides guidance regarding the application of SFAS 123(R). SAB 107 expresses views of the SEC regarding the interaction between SFAS No. 123(R), Share-Based Payment, and certain SEC rules and regulations and provides the SEC’s views regarding the valuation of share-based payment arrangements for public companies. In particular, SAB 107 provides guidance related to share-based

F-63

payment transactions with non-employees, the transition from nonpublic to public entity status, valuation methods (including assumptions such as expected volatility and expected term), the accounting for certain redeemable financial instruments issued under share-based payment arrangements, the classification of compensation expense, non-GAAP financial measures, first-time adoption of SFAS No. 123(R) in an interim period, capitalization of compensation cost related to share-based payment arrangements, the accounting for income tax effects of share-based payment arrangements upon adoption of SFAS No. 123(R), the modification of employee share options prior to adoption of SFAS No. 123(R) and disclosures in Management’s Discussion and Analysis (MDandA) subsequent to adoption of SFAS 123(R).

On April 14, 2005, the SEC approved a new rule that delays the effective date for SFAS No. 123(R) to annual periods beginning after June 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.

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 applications of the interpretation did not result in a material effect on the Company’s consolidated financial statements upon adoption of the new standard.

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 does not expect there to be any material effect on the Company’s consolidated financial statements upon adoption of the new standard.

Accounting Changes and Error Corrections

In May 2005, the FASB issued FASB Statement No. 154, Accounting Changes and Error Corrections. This new standard replaces APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, and represents another step in the FASB’s goal to converge its standards with those issued by the IASB. Among other changes, Statement 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. Statement 154 also provides that (1) a change in method of depreciating or amortizing a long-lived non-financial asset be accounted for as a change in estimate (prospectively) that was effected by a change in accounting principle, and (2) correction of errors in previously issued financial statements should be termed a “restatement.” The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Early adoption of this standard is permitted for accounting changes and correction of errors made in fiscal years beginning after June 1, 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.

The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments

On November 3, 2005, the FASB issued Financial Staff Position (“FSP”) FAS 115-1 and FAS 124-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments,” which nullifies certain requirements of Emerging Issues Task Force (“EITF”) Issue No. 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” and supersedes EITF Abstracts Topic No. D-44, “Recognition of Other-Than-Temporary Impairment Upon the Planned Sale of a Security Whose Cost Exceeds Fair Value.” The guidance in this FSP will be applied to reporting periods beginning after December 15, 2005. Early application is permitted. The Company is analyzing the effects of this Statement.

F-64

Accounting for Certain Hybrid Financial Instruments

In February 2006, the FASB issued SFAS 155, “Accounting for Certain Hybrid Financial Instrument—an amendment of FASB Statements No. 133 and 140.” The new statement: a) permits fair value remeasurement for any hybrid financial instrument that contains an embedded derivative that otherwise would require bifurcation; b) clarifies which interest-only strips and principal-only strips are not subject to the requirements of SFAS 133. “Accounting for Derivative Instruments and Hedging Activities”; c) establishes a requirement to evaluate interests in securitized financial assets to identify interests that are freestanding derivatives or that are hybrid financial instruments that contain an embedded derivative requiring bifurcation; d) clarifies that concentrations of credit risk in the form of subordination are not embedded derivatives; and e) amends SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities” to eliminate the prohibition on a qualifying special purpose entity from holding a derivative financial instrument that pertains to a beneficial interest other than another derivative financial instrument. The Company is analyzing the effects of this Statement.

Accounting for Servicing of Financial Assets

In March 2006, the FASB has issued SFAS 156 “Accounting for Servicing of Financial Assets”, which amends SFAS 140 “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities”. SFAS 156 permits an entity to choose between two measurement methods (amortization method and fair value measurement method) for each class of separately recognized servicing assets and servicing liabilities. SFAS 156 is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. However, earlier adoption is permitted as of the beginning of an entity’s fiscal year, provided the entity has not yet issued financial statements for any interim period of that fiscal year. The Company is analyzing the effects of this Statement.

Accounting for Purchases and Sales of Inventory with the Same Counterparty

At its September 2005 meeting, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterpart that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. EITF No. 04-13 is effective for new arrangements that a company enters into in periods beginning after March 15, 2006. We reviewed our buy and sell contracts and have estimated that, if those contracts were required to be reported net, sales of products and services, and cost of sales would be reduced by Ps. 171 million for 2005 with no impact on net income.

F-65

22. 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, 2005, 2004 and 2003, and the shareholders’ equity as of December 31, 2005 and 2004, 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


	2005		2004 (b)		2003 (b)

Net income (loss) in accordance with Argentine GAAP	613		678		381

US GAAP adjustments:

Foreign currency translation adjustment	(11	)	16		(108	)
Amortization of deferred charges	9		8		3
Debt refinancing costs	14		18		24
Deferred income taxes	10		167		38
Derivatives	—		—		88
Depreciation of PP&E	(171	)	(141	)	(136	)
Impairment of PP&E	(1,019	)	—		133
Fair value of liabilities	(49	)	(36	)	(36	)
Discounted value of assets and liabilities	21		9		17
Difference in accounting basis for assets sold	—		—		(29	)
Asset retirement obligations	—		—		45
Minority Interest	216		(23	)	(114	)
Other	(55	)	2		58
Deferred income taxes on US GAAP adjustments	488		42		53
US GAAP adjustments applicable to equity in earnings of affiliates
Deferred income taxes	118		40		(130	)
Depreciation of PP&E	(13	)	(10	)	(8	)
Capitalized exchange difference	13		2		50
Minority Interest	154		(6	)	6
Reversal of equity in earnings of CIESA and Citelec (a)	(162	)	15		(242	)
Debt restructuring	(256	)	(48	)	—
Other	3		27		7

Total US GAAP adjustments	(690	)	82		(281	)

Reclasification of discontinued operations and cumulative effect of changes in accounting principles, net of income tax	—		—		9

Income (loss) from continuing operations	(77	)	760		109

Discontinued operations:
Income (loss) from operations	—		—		7
Income (loss) from disposal (1)	—		—		(46	)

Income (loss) before cumulative effect of changes in accounting principles	(77	)	760		70

Cumulative effect of changes in accounting principles, net of tax (2)	—		—		30

Net income (loss) under US GAAP	(77	)	760		100

This amount corresponds to the adjustment to reverse equity in earnings accounted for under Argentine GAAP and the effects of other US GAAP adjustments recognized in items listed above respect to CIESA (2005, 2004 and 2003) and CITELEC (2004 and 2003). As of December 31, 2005, 2004 and 2003, CIESA had negative shareholders equity under US GAAP, and therefore it was valued at zero. CITELEC, in turn, had negative shareholders equity, as of December 31, 2004 and 2003, and was valued at zero. As of December 31, 2005, CITELEC was valued at 28 under US GAAP, which represents its book value as of such date (See Note 9.1).

Information presented for the years ended December 31, 2004 and 2003 have been restated for comparative purposes due to the merger described in Note 2.f) to these financial statements. The net effects of additions, both at the shareholders equity and net income reconciliation to US GAAP for those years, are included in the line “Minority interest”.

F-66


	2005		2004	2003
Basic net income (loss) per share under US GAAP	(0.036	)	0.356	0.047
Diluted net income (loss) per share under US GAAP	(0.036	)	0.356	0.047

Basic net income (loss) per share under US GAAP
Continuing operations	(0.036	)	0.356	0.051
Discontinued operations	—		—	(0.018	)
Cumulative effect of changes in accounting principles	—		—	0.014
Diluted net income (loss) per share under US GAAP
Continuing operations	(0.036	)	0.356	0.051
Discontinued operations	—		—	(0.018	)
Cumulative effect of changes in accounting principles	—		—	0.014
Basic net income (loss) per share under Argentine GAAP
Class B	0.289		0.319	0.179
Diluted net income (loss) per share under Argentine GAAP	0.289		0.319	0.179
Number of shares -in millions (3)	2,132		2,132	2,132

(1)	Including applicable income tax benefit of 10 for the year ended December 31, 2003.

(2)	Net of applicable income tax expense of 15 for the year ended December 31, 2003.

(3)	Earnings per share are calculated based on the weighted average number of shares outstanding during the year.

Consolidated statement of comprehensive income


	2005		2004		2003
Net income (loss) under US GAAP	(77	)	760		100
Foreign currency translation adjustment:
Net change during period, net of tax	38		3		(78	)
Deferred Pension Plan Obligations
(Increase) decrease in additional minimum liability, net of tax	(16	)	(10	)	—
Deferred hedge gains and losses, net of tax:
Reclassification to net income	2		16		(15	)
Deferred hedge (loss) gains	—		(6	)	17

Total Comprehensive Income (Loss)	(53	)	763		24

Cumulative Other Comprehensive Loss:
Amounts not recognized as net periodic pension costs, net of tax	(26	)	(10	)	—
Foreign currency translation adjustment, net of tax	(7	)	(45	)	(48	)
Deferred hedge gains and losses, net of tax	—		(2	)	(12	)

Total Cumulative Other Comprehensive Loss	(33	)	(57	)	(60	)

F-67

Reconciliation of shareholders’ equity to US GAAP


	2005		2004 (b)
Shareholders’ equity in accordance with Argentine GAAP	6,124		5,511

US GAAP adjustments:

Deferred charges	(12	)	(21	)
Debt refinancing costs	(9	)	(23	)
Pension plan obligations	(40	)	(15	)
Deferred income taxes	(1,131	)	(1,141	)
Minority interest	391		186
Derivatives	—		(2	)
Foreign currency translation adjustment	(132	)	(154	)
PP&E	261		1,426
Goodwill	155		155
Fair value of liabilities	1		50
Discounted value of assets and liabilities	47		26
Other	(19	)	35
Deferred income taxes on U.S. GAAP adjustments	94		(392	)
US GAAP adjustments applicable to equity in affiliates
Deferred income taxes	(523	)	(641	)
PP&E	(128	)	(116	)
Capitalized exchange difference	(33	)	(46	)
Minority interest	394		240
Reversal of equity in affiliates of CIESA and Citelec (a)	136		298
Debt restructuring	(304	)	(48	)
Other	(39	)	(42	)

Total US GAAP adjustments	(891	)	(225	)

Shareholders’ equity in accordance with US GAAP	5,233		5,286

This amount corresponds to the adjustment to reverse equity in earnings accounted for under Argentine GAAP and the effects of other US GAAP adjustments recognized in items listed above respect to CIESA (2005, 2004 and 2003) and CITELEC (2004 and 2003). As of December 31, 2005, 2004 and 2003, CIESA had negative shareholders equity under US GAAP, and was valued at zero. CITELEC, in turn, had negative shareholders equity, as of December 31, 2004 and 2003, and was valued at zero. As of December 31, 2005, CITELEC was valued at 28, which represents its book value as of such date (See Note 9.1).

Description of changes in shareholders’ equity under US GAAP


	2005		2004 (a)	2003 (a)
Shareholders’ equity under US GAAP as of beginning of the year	5,286		4,523	4,499

Other comprehensive income	24		3	(76	)
Net (loss) income under US GAAP	(77	)	760	100

Shareholders’ equity under US GAAP as of the end of the year	5,233		5,286	4,523

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US GAAP Summarized Consolidated Data

The consolidated income data and the consolidated cash flow data for the years ended December 31, 2005, 2004 and 2003, and the consolidated balance sheets data as of December 31, 2005 and 2004, presented below have been adjusted to reflect the differences between US GAAP and Argentine GAAP discussed above:


	Year ended December 31,
US GAAP consolidated income and loss data	2005		2004 (c)		2003 (c)
Sales	10,287		8,351		6,811
Less - taxes on sales and services	(158	)	(119	)	(114	)

Net sales	10,129		8,232		6,697
Cost of sales	(6,874	)	(5,588	)	(4,623	)

Gross profit	3,255		2,644		2,074
Administrative and selling expenses	(923	)	(830	)	(740	)
Exploration expenses	(34	)	(133	)	(360	)
Other operating income (expense), net	(1,685	)	(333	)	(327	)

Operating income	613		1,348		647
Equity in earnings of affiliates	57		110		65
Financial income (expense) and holding gains (losses)	(906	)	(1,161	)	(633	)
income (loss) before income taxes, minority interest, discontinued operations and cumulative effect of changes in accounting principles	(236	)	297		79
Income tax (expenses) benefit	126		424		9
Minority interest in subsidiaries	33		39		21
Discontinued operations					—
Income (loss) from discontinued operations, net of					—
income taxes	—		—		7
Income (loss) from disposal, net of income taxes (a)	—		—		(46	)
Cumulative effect of changes in accounting principles (b)	—		—		30

Net income (loss) for the year	(77	)	760		100

a)	Net of income tax benefit of 10 for the year ended December 31, 2003.

b)	Net of income tax expense of 15 for the year ended December 31, 2003.

F-69


	Year ended December 31,
	2005	2004 (b)
US GAAP condensed consolidated balance sheet data
Current assets	3,592	3,406

Investments	1,004	1,143
Property, plant and equipment	10,955	11,598
Other non current assets	607	604

Total non current assets	12,566	13,345

Total assets	16,158	16,751

Short-term debt (a)	1,358	1,225
Other liabilities	1,993	2,079

Total current liabilities	3,351	3,304

Long-term debt	4,475	4,931
Other non current liabilities	1,517	1,635

Total non current liabilities	5,992	6,566

Total liabilities	9,343	9,870

Minority interest in subsidiaries	1,582	1,595
Shareholders’ equity	5,233	5,286

	16,158	16,751

a)	Includes 438 and 924 corresponding to current portion of Long Term Debt for the years ended December 31, 2005 and 2004. In addition, the weighted average annual interest rates for outstanding short-term borrowings were 3.37% and 3.13% at December 31, 2005 and 2004, respectively.


	Year ended December 31,
	2005		2004 (a)		2003 (a)
US GAAP condensed consolidated cash flow data
Net cash provided by operations	1,701		1,688		1,388
Net cash used in investing activities	(1,599	)	(1,150	)	(929	)
Net cash used in financing activities	(477	)	(388	)	(527	)

(Decrease) Increase in cash	(375	)	150		(68	)
Effect of the exchange rate on cash	9		(6	)	(88	)
Cash and cash equivalent at beginning	899		755		911

Cash and cash equivalent at end under US GAAP	533		899		755

Cash and cash equivalent from proportional interest in CIESA	257		168		336

Cash and cash equivalent at end under Argentine GAAP	790		1,067		1,091

F-70

23. Additional financial statements disclosures required by US GAAP and the SEC

Information presented for the years ended December 31, 2004 and 2003 have been restated for comparative purposes due to the merger described in Note 2.f) to these financial statements.

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:


	2005		2004
Deferred tax assets
Tax loss carryforwards	1,328		1,345
Other tax losses	71		141
Property, plant and equipment	263		164
Reserve for contingencies	74		74
Non-current investments	209		77
Pension plan obligations	18		8
Derivatives	6		191
Receivables	9		8
Other deferred tax assets, not significant individually	60		73
Less-Valuation allowance	(1,386	)	(1,239	)

Deferred tax liabilities
Revenue recognition	(34	)	(44	)
Fair value of liabilities	(1	)	(18	)
Prepaid expenses	(14	)	(20	)
Property, plant and equipment	(1,150	)	(1,591	)
Non-current investments	(265	)	(258	)
Other deferred tax liabilities, not significant individually	(26	)	(17	)

Net deferred tax liabilities	(838	)	(1,106	)

The reconciliation of tax provision at the statutory rate to the tax provision for the years ended December 31, 2005, 2004 and 2003, computed in accordance with US GAAP, is as follows:


	2005		2004		2003
Income tax reconciliation
Pre-tax income in accordance with U.S. GAAP	(236	)	297		61

Statutory tax rate	35	%	35	%	35	%

Statutory tax rate applied to pre-tax income (loss)	(83	)	104		21

Equity in earnings and dividends from affiliates	(227	)	(238	)	(56	)
Inflation adjustment on nonmonetary assets and liabilities	—		—		13
Inflation adjustment, remeasurement and foreign earnings	(2	)	(67	)	373
Increase (decrease) in valuation allowances	147		(253	)	(408	)
Tax on minimum presumed income	—		—		11
Impairment, amortization and other decreases of goodwill	—		—		13
Tax adjustments and other, net	39		30		29

Tax (benefit) expense	(126	)	(424	)	(4	)

F-71

The Company’s provision for income taxes under US GAAP was comprised of the following:


	2005		2004		2003
Current
Argentina	15		—		—
Foreign	129		64		48

	144	(3)	64	(2)	48	(1)

Deferred
Argentina	(444	)	(432	)	10
Foreign	174		(56	)	(62	)

	(270	)	(488	)	(52	)

Total tax (benefit) expense	(126	)	(424	)	(4	)

(1)	Net of 483 for loss tax carryforward utilization in 2003.

(2)	Net of 299 for loss tax carryforward utilization in 2004.

(3)	Net of 197 for loss tax carryforward utilization in 2005.

b) 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 their 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-72

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:


	2005				2004
	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	4,475		4,605		4,931		4,994
Derivative financial instruments:
Energy commodities price swaps and options:
Accounted for as non-hedge:
Unfavorable	(76	)	(76	)	(606	)	(606	)
Foreign currency and interest rate:
Accounted for as a hedge:
Unfavorable	—		—		(4	)	(4	)

c) 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, 2005, 2004 and 2003.

Oil and Gas Exploration and Production: Petrolera Entre Lomas S.A., Inversora Mata S.A. and Coroil S.A., Oleoductos del Valle S.A. and Oleoducto de Crudos Pesados Ltd.

Refining and Distribution: Refinería del Norte S.A. and Petrobras Bolivia Refinación S.A.

Petrochemical: Petroquímica Cuyo S.A.

Gas and Energy: a) Marketing and Transportation of Gas: TGS S.A. (for 2004 and 2003), and b) Electricity: Citelec S.A., Yacylec S.A. and Uruguaí—S.A.


	2005
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Gas and Energy
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Marketing and Transportation of Gas	Electricity
Current Assets	598	1,144	136	—	177
Noncurrent Assets	4,687	653	105	—	2,049
Current Liabilities	369	948	90	—	139
Noncurrent Liabilities	3,720	118	19	—	877
Shareholders’ Equity	1,195	732	131	—	663
Minority interest	—	—	—	—	547
Sales	1,384	2,931	337	—	431
Gross profit	784	491	64	—	126
Income (loss) from continuing operations before extraordinary items and Cumulative effect of changes in accounting principles	158	275	18	—	359
Net income	158	275	19	—	359

F-73


	2004
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Gas and Energy
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Marketing and Transportation of Gas	Electricity
Current Assets	584	944	106	611	342
Noncurrent Assets	4,791	599	108	4,381	2,124
Current Liabilities	425	847	55	355	1,799
Noncurrent Liabilities	3,780	105	17	2,584	141
Shareholders’ Equity	1,171	591	142	2,053	352
Minority interest	—	—	—	—	174
Sales	1,247	2,425	293	994	356
Gross profit	695	388	91	528	89
Income (loss) from continuing operations before extraordinary items and Cumulative
effect of changes in accounting principles	140	178	40	155	(68	)
Net income	140	178	40	155	(68	)

	2003
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Gas and Energy
	Oil and Gas Exploration and Production	Refining and Distribution	Petrochemical	Marketing and Transportation of Gas	Electricity
Sales	582	1,988	225	893	324
Gross profit	267	350	68	466	96
Income (loss) from continuing operations before extraordinary items and Cumulative effect of changes in accounting principles	27	87	21	286	50
Net income	27	87	21	286	50

d) 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:


	2005						2004						2003
	CIESA (a)		Distrilec		Total		CIESA (a)		Distrilec		Total		CIESA (a)		Distrilec		Total
Current Assets	361		175		536		306		145		451
Noncurrent Assets	2,263		1,292		3,555		2,293		1,326		3,619
Current Liabilities	556		260		816		564		241		805
Noncurrent Liabilities	1,245		195		1,440		1,293		195		1,488
Shareholders Equity	281		577		858		250		591		841
Minority interest	542		435		977		492		444		936

Sales (b)	492		651		1,143		472		535		1,007		432		447		879
Gross Profit	243		97		340		253		86		339		236		74		310
Income (loss) from continuing operations before extraordinary items and cumulative effect of changes in accounting principles	31		(13	)	18		14		(9	)	5		110		(6	)	104
Net Income (loss)	31		(13	)	18		14		(9	)	5		110		(6	)	104

Cash provided by (used in):
Operating activities	299		73		372		62		132		194		263		87		350
Investing activities	(84	)	(54	)	(138	)	(49	)	(78	)	(127	)	(31	)	(27	)	(58	)
Financing activities	(126	)	(13	)	(139	)	(181	)	(47	)	(228	)	1		(46	)	(45	)

(a)	For U.S. reporting purposes, CIESA was not proportionally consolidated, as explained in Note 21 f).

(b)	Net of 21, 13 and 14 in inter-company sales as of December 2005, 2004 and 2003, respectively.

F-74

e) Pension plan:

Defined contribution plan:

During 2005, 2004 and 2003 fiscal years, no contributions were made under this plan (see Note 15.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:


	2005		2004
Change in benefit obligation
Benefit obligation at beginning	68		51

Service cost	1		1
Interest cost	6		4
Actuarial gain	25		17
Effect of remeasurement in constant money	—		—
Benefits paid	(6	)	(4	)
Curtailment effect	—		(1	)
Unrecognized prior service cost	5		—

Benefit obligation at end of year	99		68

Change in plan assets
Fair value of plan assets at beginning	45		47
Actual return on plan assets	1		2
Effect of remeasurement in constant money	—		—
Benefits paid	(6	)	(4	)
Settlement payments	—		—

Fair value of plan assets at end of year	40		45

F-75


Reconciliation of funded (unfunded) shares
Unfunded status, end of year	(59	)	(23	)
Unrecognized prior service cost	5		—
Unrecognized net actuarial(gain)/loss	41		15

Net amount recognized	(13	)	(8	)

Amounts recognized in the statement of financial position consist of:
Accrued benefit liability	(59	)	(23	)
Intangible asset	5		—
Accumulated other comprehensive income	41		15

Net amount recognized	(13	)	(8	)

Projected benefit obligation	99		68
Accumulated benefit obligation	99		68
Fair value of plan assets	40		45

Components of net periodic benefit cost
Service cost	1		1
Interest cost	6		4
Expected return on plan assets	(2	)	(2	)
Amortization of unrecognized gains	—		—
Gains from settlements	—		(1	)
Effect of remeasurement in constant money	—		—

Net periodic benefit(gain) cost	5		1


Weighted-average assumptions
Discount rate	4	%	4	%
Expected return on plan assets	4	%	4	%
Rate of compensation increase	2	%	2	%

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, 2005 and 2004, 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 2006.

Benefit obligations are expected to be paid as follows:


		Pension Benefits
2006		7
2007		8
2008		9
2009		10
2010		12
2011-2015		82

F-76

f) 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. Inter-segment 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.


	2005
							Gas and Energy
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Marketing and Transportation of Gas		Electricity		Corporate and Eliminations		Total
Unaffiliated revenues	2,935		3,572		2,140		1,009		999		—		10,655
Intersegment revenues	1,772		284		38		110		18		(2,172	)	—

Total revenues	4,657		3,856		2,178		1,119		1,017		(2,172	)	10,655

Depreciation, depletion and amortization	(832	)	(65	)	(69	)	(90	)	(137	)	(28	)	(1,221	)
Equity in earnings of unconsolidated affiliates	13		100		7		16		30		—		166
Interest expense	(303	)	(5	)	(26	)	(106	)	(1	)	(145	)	(586	)
Interest revenue	33		1		9		7		11		27		88
Dividends received from unconsolidated affiliates	22		40		7		—		3		—		72
Additions to property, plant and equipment	1,179		177		95		72		60		70		1,653
Identifiable asset	9,017		1,873		1,437		2,706		2,254		660		17,947
Investments in and advances to unconsolidated affiliates	347		292		49		191		35		—		914

Total assets	9,364		2,165		1,486		2,897		2,289		660		18,861

F-77


	2004
							Gas and Energy
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Marketing and Transportation of Gas		Electricity		Corporate and Eliminations		Total
Unaffiliated revenues	2,080		3,085		1,857		930		811		—		8,763
Intersegment revenues	1,567		274		20		49		14		(1,924	)	—

Total revenues	3,647		3,359		1,877		979		825		(1,924	)	8,763

Depreciation, depletion and amortization	(772	)	(68	)	(71	)	(87	)	(138	)	(30	)	(1,166	)
Equity in earnings of unconsolidated affiliates	31		58		16		10		(39	)	—		76
Interest expense	(261	)	(1	)	(17	)	(117	)	(22	)	(191	)	(609	)
Interest revenue	20		1		5		2		9		16		53
Dividends received from unconsolidated affiliates	18		54		9		—		3		—		84
Additions to property, plant and equipment	864		72		86		50		62		14		1,148
Identifiable assets	8,542		1,900		1,327		2,571		2,256		691		17,287
Investments in and advances to unconsolidated affiliates	371		229		53		177		158		—		988

Total assets	8,913		2,129		1,380		2,748		2,414		691		18,275


	2003
							Gas and Energy
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Marketing and Transportation of Gas		Electricity		Corporate and Eliminations		Total
Unaffiliated revenues	2,045		2,590		1,294		502		680		2		7,113
Intersegment revenues	944		112		—		19		11		(1,086	)	—

Total revenues	2,989		2,702		1,294		521		691		(1,084	)	7,113

Depreciation, depletion and amortization	(714	)	(64	)	(77	)	(86	)	(147	)	(33	)	(1,121	)
Equity in earnings of unconsolidated affiliates	16		22		19		16		90		—		163
Interest expense	(267	)	(1	)	(30	)	(134	)	(23	)	(171	)	(626	)
Interest revenue	32		1		5		9		12		13		72
Dividends received from unconsolidated affiliates	16		7		—		—		3		—		26
Additions to property, plant and equipment	92		63		37		12		40		33		277

g) Derivative financial instruments

As described in Note 5, the Company used 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 account for the years ended December 31, 2005, 2004 and 2003:

F-78

Commodity Price Risk

As of December 31, 2005, 2004 and 2003, there are no unrealized gains or losses in the accumulated other comprehensive income.

Interest rate risk

As of December 31, 2005 there are no unrealized gains or losses in accumulated Other Comprehensive Income.

As of December 31, 2004 and 2003, the Company has an after taxes net unrealized loss of 2 and 12 respectively, on a derivative instrument entered into to hedge interest rate recorded in accumulated other comprehensive income.

24. 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 Argentina and other countries of Latin America; the respective detail is disclosed in Exhibit J to the financial statements.

For comparative purposes the Company modified retroactively the Supplementary information on oil and gas producing activities, including the information of Petrolera Santa Fe S.R.L. and Petrobras Argentina S.A. for the years ended as of December 31, 2004 and 2003 (See note 1.c. to our financial statements).

Amounts in millions of pesos are stated as mentioned in Note 2.II to the financial statements.

Operations in Venezuela

Supplementary information on oil and gas producing activities as of December 31, 2005 attributable to the Company’s operations in Venezuela is calculated on the basis of the contractual structure in force as of such date. As described in note 6 to the financial statements, the Company has undertook a migration process as to its operations in Venezuela implying conversion of operating agreements in force into partially state-owned companies that will be majority-owned by the Venezuelan Government, through Petróleos de Venezuela S.A. As of December 31, 2005, estimated proved oil and gas reserves attributable to operations in Venezuela amount to 269 millions of barrels of oil equivalent, accounting for 35.4% of the Company’s total reserves; estimated future net cash flows attributable to Venezuela amount to P$5,385 million, accounting for 30.9% of estimated net cash flows.

Based on the corporate structure established to materialize the migration of operating agreements, and once such migration has been completed, the Company’s interest in operations in Venezuela will be shown on the Unconsolidated Companies line.

Operations in Bolivia

Supplementary information on oil and gas producing activities as of December 31, 2005 attributable to the Company’s operations in Bolivia is calculated on the basis of the regulatory framework in force as of such date (See Note 6). However, as provided by the Supreme Decree No. 28,701, issued in May 2006, as from May 1, 2006 oil companies will have to deliver to YPFB the property of all hydrocarbons for sale. We are currently in the process of evaluating the effects of this decree on our reserves in Bolivia. (See Note 25)

F-79

Capitalized costs

The following table presents the capitalized costs as of December 31, 2005, 2004 and 2003, for proved and unproved oil and gas properties, and the related accumulated depreciation and allowances, which reduce the value of assets.


	2005				2004
	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	3,642		3,532		3,032		2,922
Mining properties and wells	9,311		10,095		8,299		8,995
Unproved properties	276		276		395		395

Total capitalized costs	13,229		13,903		11,726		12,312

Accumulated depreciation and allowances which reduce the value of assets	(6,126	)	(6,841	)	(5,032	)	(4,551	)

Subtotal of consolidated companies	7,103		7,062		6,694		7,761

Company’s share in capitalized costs by unconsolidated affiliates	126		151		185		264

Total net capitalized costs	7,229		7,213		6,879		8,025

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, 2005 2004 and 2003. 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.

F-80


	2005			2004
	Argentine and US GAAP			Argentine and US GAAP
	Argentine	Rest of Latin- America	Total	Argentine	Rest of Latin- America	Total
Consolidated companies:
Acquisition of properties:
- Proved	—	—	—	—	—	—
- Unproved	—	—	—	—	—	—
Exploration costs	90	2	92	19	9	28
Development costs	583	835	1,418	477	556	1,033

Subtotal costs incurred by consolidated companies	673	837	1,510	496	565	1,061
Company’s share in costs incurred by unconsolidated affiliates	10	3	13	9	5	14

Total costs incurred	683	840	1,523	505	570	1,075


	2003
	Argentine and US GAAP
	Argentine	Rest of Latin- America	Total
Consolidated companies:
Acquisition of properties:
- Proved	—	—	—
- Unproved	—	—	—
Exploration costs	21	103	124
Development costs	407	346	753

Subtotal costs incurred by consolidated companies	428	449	877
Company’s share in costs incurred by unconsolidated affiliates	9	5	14

Total costs incurred	437	454	891

F-81

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, 2005, 2004 and 2003. 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


	2005
	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	458		2,477		2,935		458		2,477		2,935
- transfers to other operations	1,722		—		1,722		1,722		—		1,722

Total net sales	2,180		2,477		4,657		2,180		2,477		4,657
Production costs:
- Operating costs	(378	)	(328	)	(706	)	(378	)	(328	)	(706	)
- Royalties and other	(306	)	(635	)	(941	)	(306	)	(635	)	(941	)

Total production costs	(684	)	(963	)	(1,647	)	(684	)	(963	)	(1,647	)
Exploration costs	(32	)	(2	)	(34	)	(32	)	(2	)	(34	)
Depreciation, depletion, amortization and allowances which reduce the value of assets	(386	)	(650	)	(1,036	)	(448	)	(1,720	)	(2,168	)

Results of operations before income tax	1,078		862		1,940		1,016		(208	)	808
Income tax	(426	)	(612	)	(1,038	)	(357	)	(238	)	(595	)

Results of operations - consolidated companies	652		250		902		659		(446	)	213
Company’s share in results of operations by unconsolidated affiliates	26		(11	)	15		22		(43	)	(21	)

Total Results of oil and gas operations	678		239		917		681		(489	)	192

F-82


	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	480		1,600		2,080		480		1,600		2,080
- transfers to other operations	1,567		—		1,567		1,567				1,567

Total net sales	2,047		1,600		3,647		2,047		1,600		3,647
Production costs:
- Operating costs	(318	)	(290	)	(608	)	(318	)	(290	)	(608	)
- Royalties and other	(339	)	(398	)	(737	)	(339	)	(398	)	(737	)

Total production costs	(657	)	(688	)	(1,345	)	(657	)	(688	)	(1,345	)
Exploration costs	(50	)	(83	)	(133	)	(50	)	(83	)	(133	)
Depreciation, depletion, amortization and allowances which reduce the value of assets	(424	)	(336	)	(760	)	(430	)	(447	)	(877	)

Results of operations before income tax	916		493		1,409		909		382		1,291
Income tax	(382	)	(155	)	(537	)	(367	)	(117	)	(484	)

Results of operations - consolidated companies	534		338		872		542		265		807
Company’s share in results of operations by unconsolidated affiliates	17		6		23		14		4		18

Total Results of oil and gas operations	551		344		895		557		269		826

F-83


	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	854		1,191		2,045		941		1,191		2,132
- transfers to other operations	944		—		944		944		—		944

Total net sales	1,798		1,191		2,989		1,885		1,191		3,076
Production costs:
- Operating costs	(310	)	(247	)	(557	)	(310	)	(247	)	(557	)
- Royalties and other	(279	)	(161	)	(440	)	(279	)	(161	)	(440	)

Total production costs	(589	)	(408	)	(997	)	(589	)	(408	)	(997	)
Exploration costs	(175	)	(185	)	(360	)	(175	)	(185	)	(360	)
Depreciation, depletion, amortization and allowances which reduce the value of assets	(429	)	(593	)	(1,022	)	(274	)	(726	)	(1,000	)

Results of operations before income tax	605		5		610		847		(128	)	719
Income tax	(243	)	(1	)	(244	)	(266	)	46		(220	)

Results of operations - consolidated companies	362		4		366		581		(82	)	499
Company’s share in results of operations by unconsolidated affiliates	13		5		18		9		2		11

Total Results of oil and gas operations	375		9		384		590		(80	)	510

F-84

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, 2005, 2004 and 2003, were audited by Gaffney, Cline & Associates Inc., international technical advisors. The technical revision covered the 95%, 95% y 92% for the years 2005, 2004 and 2003 of the estimated reserves of the Company. Reserves which have not been certified are attributable to estimated reserves related to areas where the Company does not act as operator. 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 that are ultimately recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.

F-85

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, 2005, 2004 and 2003:


	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
Proved reserves (developed and undeveloped)	ARGENTINA		REST OF LATIN- AMERICA		ARGENTINA		REST OF LATIN- AMERICA		TOTAL		ARGENTINA		REST OF LATIN- AMERICA		ARGENTINA		REST OF LATIN- AMERICA	TOTAL
Reserves as of December 31, 2002*	236,840		369,658		6,241		10,878		623,617		1,275,413		369,456		17,924		—	1,662,793

Increase (Decrease) originated in:
Revisions of previous estimates	(8,252	)	(3215	)	(39	)	(63	)	(11,569	)	(257,559	)	23,110		(4,549	)	—	(238,998	)
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	(23,689	)	(20,367	)	(559	)	(376	)	(44,991	)	(95,834	)	(22,517	)	(1,006	)	—	(119,357	)

Reserves as of December 31, 2003*(2)	209,658		379,424		6,517		10,786		606,385		932,986		384,881		13,323		—	1,331,190

Increase (Decrease) originated in:
Revisions of previous estimates	(25,158	)	(4,468	)	(108	)	(1,285	)	(31,019	)	229,305		(1,749	)	611		—	228,167
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	(21,898	)	(24,147	)	(583	)	(365	)	(46,993	)	(95,053	)	(23,643	)	(1,003	)	—	(119,699	)

Reserves as of December 31, 2004*(1)	170,173		397,330		6,117		9,136		582,756		1,085,885		365,987		13,630		—	1,465,502

Increase (Decrease) originated in:
Revisions of previous estimates	(7,066	)	4,807		(99	)	(624	)	(2,982	)	(88,102	)	22,612		238		—	(65,252	)
Improved recovery	(9,505	)	—		20		—		(9,485	)	12		—		44		—	56
Extensions and discoveries	3,850		8,762		232		—		12,844		23,541		13,787		233		—	37,561
Purchase of proved reserves in place	—		—		—		—		—		—		—		—		—	—
Sale of proved reserves in place	—		—		—		—		—		—		—		—		—	—
Year’s production	(19,272	)	(24,553	)	(617	)	(261	)	(44,703	)	(83,393	)	(22,577	)	(1,225	)	—	(107,195	)

Reserves as of December 31, 2005(*)	138,180		386,346		5,653		8,251		538,430		937,943		379,809		12,920		—	1,330,672

(*) Includes proved developed reserves:
As of December 31, 2002	158,226		173,820		4,428		4,056		340,530		799,647		209,854		14,373		—	1,023,874
As of December 31, 2003	138,607		166,349		4,320		3,576		312,852		641,341		207,144		10,514		—	858,999
As of December 31, 2004	114,654		165,634		3,999		2,485		286,773		544,353		208,440		9,785		—	762,578
As of December 31, 2005	93,980		174,227		4,113		2,000		274,320		447,161		203,255		10,217		—	660,633
(1) Effect of the merger on December 31, 2004	30,243		—		—		—		30,243		388,542		—		—		—	388,542
(2) Effects of the merger on December 31, 2003	37,323		—		—		—		37,323		196,390		—		—		—	196,390

The amounts of proved reserves disclosed herein as of December 31, 2005 include 130,203 thousand of barrels of crude oil condensate and natural gas liquids and 321,783 million of cubic feet of natural gas correspond to the minority interest in Petrobras Energía which include 66,336 thousand of barrels of crude oil condensate and natural gas liquids and 159,754 million of cubic feet of natural gas correspond to the minority interest in Petrobras Energía of proved developed reserves.

F-86

Estimated proved oil and gas reserves attributable to the Company’s operations in Venezuela and Bolivia are calculated on the basis of the contractual structure in force as of December 31, 2005. (See Note 6 and Note 25)

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, an operational 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.

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 27.5%, 26.8% and 22.9%, 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 44.0%, 40.4% and 37.3% as of December 31, 2005, 2004 and 2003, respectively. The 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 and abandonment costs include estimated drilling costs, development and 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.

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.

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	2005						2004						2003
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of pesos - note 2.II.)
Consolidated companies:
Future cash flows	24,589		41,868		66,457		20,124		30,131		50,255		18,408		22,513		40,921
Future production costs	(6,020	)	(10,133	)	(16,153	)	(5,025	)	(7,228	)	(12,253	)	(4,566	)	(6,653	)	(11,219	)
Future development and abandonment costs	(2,030	)	(4,068	)	(6,098	)	(1,898	)	(3,695	)	(5,593	)	(1,629	)	(2,875	)	(4,504	)
Future income tax	(5,298	)	(10,294	)	(15,592	)	(4,099	)	(5,518	)	(9,617	)	(3,743	)	(3,308	)	(7,051	)

Undiscounted future net cash flows	11,241		17,373		28,614		9,102		13,690		22,792		8,470		9,677		18,147
10% annual discount	(4,006	)	(7,656	)	(11,662	)	(3,511	)	(6,099	)	(9,610	)	(3,375	)	(4,466	)	(7,841	)

Subtotal of consolidated companies	7,235		9,717		16,952		5,591		7,591		13,182		5,095		5,211		10,306
Company’s share in standardized measure by unconsolidated affiliates	287		183		470		198		162		360		150		117		267

Standardized measure of discounted future net cash flows	7,522		9,900		17,422		5,789		7,753		13,542		5,245		5,328		10,573

Effect of the Menager	—		—		—		767		—		767		780		—		780

The amounts of the standardized measure of discounted future net cash flows herein for the year ended December 31, 2005 include 4,213 that corresponds to the minority interest in Petrobras Energía.

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, 2005, 2004 and 2003:

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	CONSOLIDATED AND UNCONSOLIDATED COMPANIES
	2005						2004						2003
	Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total		Argentina		Rest of Latin- America		Total
	(in millions of pesos - note 2.II.)
Standardized measure at beginning of year	5,789		7,753		13,542		5,245		5,328		10,573		6,548		6,139		12,687

Changes related to oil & gas activities

Hydrocarbons sales net of production costs	(1,548	)	(1,825	)	(3,373	)	(1,494	)	(1,147	)	(2,641	)	(1,319	)	(805	)	(2,124	)
Net change in sales prices, net of future production costs	4,168		4,985		9,153		1,999		2,813		4,812		(1,435	)	(2,015	)	(3,450	)
Changes in future development costs	(571	)	(879	)	(1,450	)	(521	)	(997	)	(1,518	)	(285	)	(111	)	(396	)
Extensions, discoveries and improved recovery, net of future production and associated costs	(518	)	282		(236	)	442		1,570		2,012		444		800		1,244
Development costs incurred	593		838		1,431		486		561		1,047		416		351		767
Revisions of quantity estimates	(579	)	486		(93	)	(827	)	(40	)	(867	)	(761	)	(56	)	(817	)
Purchase of reserves in place	—		—		—		—		—		—		—		—		—
Sale of reserves in place	—		—		—		—		—		—		(164	)	—		(164	)
Net change in income taxes	(921	)	(2,944	)	(3,865	)	(271	)	(1,248	)	(1,519	)	803		230		1,033
Accretion of discount	868		1,119		1,987		777		741		1,518		980		835		1,815
Changes in production rates	31		(218	)	(187	)	(34	)	188		154		(20	)	(181	)	(201	)
Other changes	210		303		513		(13	)	(16	)	(29	)	38		141		179

Standardized measure at end of year	7,522		9,900		17,422		5,789		7,753		13,542		5,245		5,328		10,573

Effect of the Menager	—		—		—		767		—		767		780		—		780

The amounts of the standardized measure of discounted future net cash flows herein for the year ended December 31, 2005 include 4,213 that corresponds to the minority interest in Petrobras Energía.

25. Subsequent events

Agreement to exploit the Argentine Sea

In May 2006, we and Energía Argentina S.A. (Enarsa) signed an association agreement whereby a consortium was created for the exploration, development, production and commercialization of hydrocarbons in two offshore areas located on the Argentine continental shelf, approximately 250 km east of the city of Mar del Plata (Province of Buenos Aires), at depths ranging from 150-200 meters to 3,000 meters. We will have a 25% working interest in the consortium that will explore a combined area of 8,664,000 acres.

Oil and gas areas and participation in joint ventures

Argentina

The Neuquén Provincial Government, through Provincial Decrees Nos. 225/06 and 226/06 issued in February 2006 and effective March 1, 2006, provided that oil royalties are to be calculated and paid considering as reference the international price of crude oil (WTI), while gas royalties are to be calculated and paid on the basis of the average price at the border of natural gas imported into Argentina. In April 2006, the Company requested declarative judgment and precautionary measures from Federal Court No. 1 in the Province of Neuquén, specifically requesting that the court

F-89

declare that the royalties for oil and gas concessions awarded by the Federal Government should be calculated and paid as provided by Federal Law No. 17,139 and the regulations issued by the Argentine Department of Energy in its capacity of enforcement agency and, hence, that the Company is not subject to Neuquén Provincial Executive Decrees Nos. 225/2006 and 226/2006 or to any other provincial regulation issued or to be issued in the future that departs from, alters or amends the provisions of Law No. 17,319 and the related Department of Energy regulations.

Venezuela

In March 31, 2006, Petrobras Energía Venezuela, Coroil S.A., Corod S.A. and Inversora Mata S.A., PDVSA and CVP, entered into Memorandums of Understanding (MOUs) in order to effect the migration of the Oritupano Leona, La Concepción, Acema and Mata’s operating agreemets into mixed companies. Pursuant to these MOUs, the equity interest of private investors in the mixed companies will be 40%, with the Venezuelan Government holding a 60% interest. Petrobras Energía’s indirect interest in the Oritupano Leona, La Concepción, Acema and Mata areas will be 22%, 36%, 34.5% and 34.5%, respectively. The MOUs establish that CVP will recognize a divisible and transferable credit in favor of Petrobras Energía of U.S.$88.5 million. The credit will not bear interest and may be used for the payment of mineral rights offered by the Venezuelan government in the future.

In the future, the mixed companies will be subject to royalty payments based on production of 33.33%. In addition, they will be required to pay to the government an amount equivalent to any difference between (1) 50% of the value of oil and gas sales during each calendar year and (2) the sum total of royalty payments made during such year plus income tax and any other tax or duty calculated on the basis of the sales revenues of the mixed companies paid during such year. Any remaining net profits of the mixed companies, after payment of expenses and capital expenditures, are distributed among its shareholders pro rata on the basis of their ownership interests. Each mixed company shall be the operator of the areas, and the crude oil produced by the mixed companies is required to be sold and delivered to PDVSA at market prices.

In view of the new contractual framework, as of December 31, 2005, the Company booked allowances in the amount of 424 to adjust the book value of its assets in Venezuela to their recoverable value, out of which 255 relate to property, plant & equipment, 110 to deferred tax assets, and 59 to non-current investments. The terms of the MOU signed in March 2006 did not result in any changes to the allowance booked.

Due to the ownership structure and governance system defined for the mixed companies, as from their respective organization dates the Company will discontinue the line-by-line consolidation of the assets, liabilities, results of operations and cash flows of those investments.

As of December 31, 2005, the assets and liabilities related to the operations in Venezuela included in these financial statements are as follows:


Current assets		703
Non-current assets		2,885

Total assets		3,588

Current liabilities		484
Non-current liabilities		146

Total liabilities		630

Certain information from the income statement related to the operations in Venezuela for the twelve-month period ended December 31, 2005, is disclosed below.

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Net sales	1,175
Gross profit	684
Operating income	639
Net loss	(170	)

Bolivia

In May 2006, the Bolivian Government enacted the Supreme Decree No. 28,701, which provides that as from May 1, 2006 oil companies will have to deliver to YPFB the property of all hydrocarbon production for sale. Oil companies will have a 180-day transition term to subscribe the new agreements which will be individually authorized and approved by the Bolivian Legislature. The Ministry of Hydrocarbons and Mines will determine, on a case-by-case basis, the interest corresponding to oil companies by means of investment audits, operational costs and profitability indicators. The current distribution of the oil and gas production value will be maintained during the transition period, in the case of fields which certified average production of natural gas for 2005 was lower than 100 million cubic feet per day. The Colpa Caranda area is in this situation. In addition, the abovementioned decree provides, among other things, that the Bolivian Government shall recover full participation in the entire oil and gas production chain, and for this purpose provides for the nationalization of the shares of stock necessary for YPFB to have at least 50% plus one of the shares in a number of companies, among which is Petrobras Bolivia Refinación. Due to the fact that the abovementioned decree has recently been issued and that there will be needed several instrumentation and application procedures, including the YPFB full restructuring, we are analyzing its effects of the above mentioned decree. As of December 31, 2005 the assets in Bolivia represent about 2% of the Company’s total assets.

Ecuador

In April 2006, the Ecuadorian Government approved the Oil and Gas Reform Law, which assigns to the government an equity interest of at least 50% in the extraordinary revenues resulting from the increase in the price of Ecuadorian crude (effective monthly average price of FOB price) with respect to the average monthly sales price of such oil at the respective contracts’ execution date, expressed in constant values as of the calculation date. As of the date of issuance of these financial statements the administrative order for such law remains to be issued; therefore, the impact of such legislation and regulations cannot be predicted.

In relation with the development works in Block 31, in May 2006, a new work proposal was presented to the Ministry of the Environment and is currently under evaluation by the Ministry of Energy and Mines and the Ministry of the Environment. The new proposal minimizes activities within the Yasuní National Park and employs advanced oil production technologies for environmental protection.

Decisions of the Ordinary General Shareholders’ Meeting

The Ordinary General Shareholders Meeting held on April 28, 2006, in accordance with the proposal made by the Board of Directors, appropriated retained earnings as of December 31, 2005, as follows: 68 to the Legal Reserve and 545 carried over to unappropiated retained earnings of the new fiscal year. The amount appropriated to the Legal Reserve includes 37 related to the pending reimbursement of the decrease in such reserve that had been approved by the Regular General Shareholders’ Meeting held on April 4, 2003.

F-91

Changes in professional accounting standards

As mentioned in Note 2.g, and with regards to the recognition of a deferred tax liability related to the difference between Property, Plant and Equipment carrying value adjusted for inflation (and other non-monetary assets) and their tax value, at the Meeting held on March 10, 2006, the Company’s Board of Directors decided to book the deferred tax liability that results from the above-mentioned difference between carrying value of PP&E and its tax value.

Changes in Professional Accounting Standards in Argentina are effective for fiscal years beginning as from January 1, 2006.

26. Other consolidated information

The following tables present additional consolidated financial statement disclosures required under Argentine GAAP.

Property, plant and equipment.

Equity in affiliates

Costs of sales.

Foreign currency assets and liabilities.

Consolidated detail of expenses incurred and depreciation.

Information about ownership in subsidiaries and affiliates.

Oil and gas areas and participation in joint ventures.

Combined joint ventures and consortium assets, liabilities and results.

F-92

a) Property, plant and equipment as of December 31, 2005, 2004 and 2003

(Stated in millions of Argentine Pesos - See Note 2.c)


	2005
	Exploration and Production		Refining and Distribution		Petrochemical		Gas and Energy				Other Discontinued Investments and Eliminations		Total
	Exploration and Production		Refining and Distribution		Petrochemical		Electricity		Marketing and Transportation of Gas		Other Discontinued Investments and Eliminations		Total
Net book value at beginning of the year	6,694		835		670		1,940		2,087		121		12,347
Effect of translation	62		—		6		—		—		—		68
Net increase	1,179		177		95		60		72		70		1,653
Depreciation	(832	)	(65	)	(69	)	(137	)	(90	)	(28	)	(1,221	)

Net book value at the end of the period	7,103		947		702		1,863		2,069		163		12,847


	2004
	Exploration and Production		Refining and Distribution		Petrochemical		Gas and Energy				Other Discontinued Investments and Eliminations		Total
	Exploration and Production		Refining and Distribution		Petrochemical		Electricity		Marketing and Transportation of Gas		Other Discontinued Investments and Eliminations		Total
Net book value at beginning of the year	6,552		831		652		2,016		2,124		137		12,312
Effect of translation	50		—		3		—		—		—		53
Net increase	864		72		86		62		50		14		1,148
Depreciation	(772	)	(68	)	(71	)	(138	)	(87	)	(30	)	(1,166	)

Net book value at the end of the period	6,694		835		670		1,940		2,087		121		12,347


	2003
	Exploration and Production		Refining and Distribution		Petrochemical		Gas and Energy				Other Discontinued Investments and Eliminations		Total
	Exploration and Production		Refining and Distribution		Petrochemical		Electricity		Marketing and Transportation of Gas		Other Discontinued Investments and Eliminations		Total
Net book value at beginning of the year	7,805		832		770		2,123		—		137		11,667
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	92		63		37		40		12		33		277
Depreciation	(714	)	(64	)	(77	)	(147	)	(86	)	(33	)	(1,121	)

Net book value at end of the period	6,552		831		652		2,016		2,124		137		12,312

F-93

b) Equity in affiliates as of December 31, 2005 and 2004

(Stated in millions of Argentine Pesos - See Note 2.c)


	12/31/2005						12/31/2004
	Description of securities
Name and issuer	Face value		Amount	Cost	Book value		Book value
Citelec S.A. (Note 9.I.c)	$	1	73,154,437	—	—		116
Coroil S.A.	Bs	1,000	490	43	46		49
Petrobras Bolivia Refinacion S.A.	$B	l1,000	178,752	103	177		121
Hidroneuquén S.A.	$	10	25,744,097	26	26		26
Inversora Mata S.A.	Bs	1,000	490	55	95		100
Oleoducto de Crudos Pesados Ltd.	US$	0.01	31,500	98	95		91
Oleoductos del Valle S.A.	$	10	2,542,716	61	78		81
Petrolera Entre Lomas S.A.	$	1	96,050	2	59		50
Petroquimica Cuyo S.A.	$	0.083	240,000,000	43	49		53
Refineria del Norte S.A.	$	10	2,610,809	63	115		108
Transportadora de Gas del Sur S.A.	$	1	58,408,751	—	—		151
Cost related with CIESA S.A. reestructuring ( Note 9.II)				169	166		—
TGS S.A. goodwill in CIESA S.A. (1)				—	25		26
Yacylec S.A.	$	0.1	100,000,000	25	19		26
Reserve for impairment of investments				—	(36	)	(10	)

				688	914		988

(1)	As of December 31, 2005, 2004 and 2003, it includes Ciesa capitalized exchange differences of 25, 26 and 29, respectively.

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c) Costs of sales for the years ended December 31, 2005, 2004 and 2003

(Stated in millions of Argentine Pesos - See Note 2.c)


	2005
							Gas Energy
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Electricity		Marketing and Transportation of Gas		Corporate, Other Discontinued Investments and Eliminations		Total
Inventories at beginning	130		331		278		33		3		(77	)	698
Effect of translation	1		—		—		—		—		—		1
Costs (Section e)	1,896		151		171		275		507		—		3,000
Holding gain (losses)	(6	)	88		(6	)	(10	)	—		(26	)	40
Purchases, consumption and other	178		3,706		1,621		501		349		(2,175	)	4,180
Inventories at end	(165	)	(527	)	(263	)	(42	)	(10	)	146		(861	)

Costs of sales	2,034		3,749		1,801		757		849		(2,132	)	7,058


	2004
							Gas Energy
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Electricity		Marketing and Transportation of Gas		Corporate, Other Discontinued Investments and Eliminations		Total
Inventories at beginning	114		255		155		35		8		(57	)	510
Effect of translation	(1	)	—		—		—		—		—		(1	)
Costs (Section e)	1,677		136		163		296		319		—		2,591
Holding gain (losses)	(9	)	23		37		(17	)	—		4		38
Purchases, consumption and other	94		3,020		1,426		347		387		(1,923	)	3,351
Inventories at end	(130	)	(331	)	(278	)	(33	)	(3	)	77		(698	)

Costs of sales	1,745		3,103		1,503		628		711		(1,899	)	5,791


	2003
							Gas Energy
	Oil and Gas Exploration and Production		Refining and Distribution		Petrochemical		Electricity		Marketing and Transportation of Gas		Corporate, Other Discontinued Investments and Eliminations		Total
Inventories at beginning	132		223		169		38		—		(38	)	524
Inventories at beginning from proportional interest in CIESA	—		—		—		—		3		—		3
Effect of translation	(10	)	—		(6	)	—		—		—		(16	)
Costs (Section e)	1,535		165		149		283		156		1		2,289
Holding gain (losses)	2		12		—		1		—		(6	)	9
Purchases, consumption and other	55		2,554		824		236		133		(1,342	)	2,460
Inventories at end	(114	)	(255	)	(155	)	(35	)	(8	)	57		(510	)

Costs of sales	1,600		2,699		981		523		284		(1,328	)	4,759

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d) Foreign currency assets and liabilities as of December 31, 2005 and 2004

(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$	9	3.0300	28
	Rs	2	1.2900	2
	BS	19,286	0.0014	27

				57

Investments	US$	195	3.0300	591
	Rs	27	1.2900	35

				626

Trade receivables	US$	298	3.0300	904
	Rs	82	1.2900	106
	BS	74,286	0.0014	104

				1,114

Other receivables	US$	58	3.0300	177
	BS	78,571	0.0014	110
	Rs	17	1.2900	22

				309

TOTAL 2005				2,106

TOTAL 2004				2,171

NON-CURRENT ASSETS
Trade receivables	US$	4	3.0300	11

Other receivables	US$	2	3.0300	7
	Rs	1	1.29	1

				8

Investments	US$	48	3.0300	144

TOTAL 2005				163

TOTAL 2006				434

TOTAL ASSETS
2005				2,269

2004				2,605


	Foreign currency and amount		Exchange rate	Book amount in local currency
CURRENT LIABILITIES
Accounts payable	US$	299	3.0300	907
	Rs	36	1.2900	46
	BS	19,286	0.0014	27
	Sol	1	0.8836	1

				981

Short-term debt	BS	101,429	0.0014	142
	US$	503	3.0300	1,524

				1,666

Payroll and social security taxes	Sol	10	0.8836	9
	BS	2,143	0.0014	3
	Rs	5	1.2900	7
	US$	4	3.0300	12

				31

Taxes payable	US$	20	3.0300	60
	Rs	10	1.2900	13
	BS	85,714	0.0014	120

				193

Other liabilities	Rs	2	1.2900	3
	US$	48	3.0300	145

				148

TOTAL 2005				3,019

TOTAL 2004				3,150

NON-CURRENT LIABILITIES
Accounts payable	US$	3	3.0300	9

Long-term debt	US$	1,874	3.0300	5,679

Taxes payable	Rs	23	1.2900	30
	Bs	70,714	0.0014	99

				129

Other liabilities	US$	76	3.0300	230

TOTAL 2005				6,047

TOTAL 2004				6,433

TOTAL LIABILITIES
2005				9,066

2004				9,583


US$		Millions of American Dollars
BS		Millions of Bolivares
RS		Millions of Reales
Sol		Millions of Peruvian Soles

F-96

e) Consolidated detail of expenses incurred and depreciation for the years ended December 31, 2005, 2004 and 2003

(Stated in millions of Argentine Pesos - See Note 2.c)


	2003		2004		2005
Accounts	Total		Total		Total		Costs		Administrative and selling expenses		Exploration expenses
Salaries and wages	332		354		435		192		243		—
Social security taxes	37		47		72		32		40		—
Other benefits to personnel	108		111		128		42		86		—
Taxes, charges and contributions	96		84		42		33		9		—
Fees and professional advisory	118		116		100		26		74		—
Depreciation of property, plant and equipment	1,121		1,166		1,221		1,132		89		—
Amortization of other assets	20		14		14		5		9		—
Oil and gas royalties	366		390		507		507		—		—
Spares and repairs	111		138		129		119		10		—
Geological and geophysical expenses	6		7		34		—		—		34
Transportation and freights	213		252		293		36		257		—
Construction contracts and other services	356		446		466		351		115		—
Impairment of unproved oil and gas properties	343		119		16		16		—		—
Fuel, gas, energy and other	69		51		68		59		9		—
Other operating costs and consumption	222		361		557		479		78		—
Recovery of expenses	(99	)	(85	)	(107	)	(29	)	(78	)	—

Total 2005					3,975		3,000		941		34

Total 2004			3,571				2,591		847		133

Total 2003	3,419						2,289		770		360

F-97

f) Information about ownership in subsidiaries and affiliates as of December 31, 2005


	% OF OWNERSHIP AND VOTES		BUSINESS SEGMENT
	DIRECT	INDIRECT	BUSINESS SEGMENT
Subsidiaries
Corod Producción S.A. (Venezuela)	—	75.82	Oil and Gas Exploration and Production
ECUADORTLC S.A. (Ecuador)	—	75.82	Oil and Gas Exploration and Production
Enecor S.A.	—	53.07	Gas and Energy
EG3 Asfalto S.A.	—	75.17	Refining and Distribution
EG3 Red S.A.	—	75.82	Refining and Distribution
Innova S.A. (Brasil)	—	75.82	Petrochemical
Petrobras Energía de México S.A. de C.V. (México)	—	75.82	Oil and Gas Exploration and Production
Petrobras Finance Bermuda (Islas Bermudas)	—	75.82	Corporate
Petrobras Holding Austria AG (Austria)	—	75.82	Corporate
Petrobras de Valores Internacional de España S.A. (España)	—	75.82	Corporate
Petrobras Energta S.A.	75.82	—	Corporate
Petrobras Energta Internacional S.A.	—	75.82	Corporate
Petrobras Energta Operaciones S.A. (Ecuador)	—	75.82	Oil and Gas Exploration and Production
Petrobras Financial Services Austria GMBH (Austria)	—	75.82	Corporate
Petrobras Hispano Argentina S.A. (España)	—	75.82	Corporate
Petrobras Bolivia Internacional S.A. (Bolivia)	—	75.82	Corporate
Petrobras Energta Ecuador (Gran Cayman)	—	75.82	Oil and Gas Exploration and Production
Petrobras Energta Perú S.A. (Perú)	—	75.82	Oil and Gas Exploration and Production
Petrobras Energta Venezuela S.A. (Venezuela)	—	75.82	Oil and Gas Exploration and Production
Petrolera San Carlos S.A. (Venezuela)	—	75.82	Oil and Gas Exploration and Production
Transporte y Servicios de Gas en Uruguay S.A. (Uruguay)	—	51.67	Gas and Energy
World Energy Business S.A.	—	75.82	Gas and Energy
Electricidade Com S.A. (Brasil)	—	75.82	Gas and Energy
World Fund Financial Services (Gran Cayman)	—	75.82	Corporate

Main affiliates - join control
Cía. de Inversiones de Energía S.A.	—	37.91	Gas and Energy
Citelec S.A.	—	37.91	Gas and Energy
Distrilec Inversora S.A.	—	36.77	Gas and Energy
Edesur S.A.	—	20.72	Gas and Energy
Transba S.A.	—	18.31	Gas and Energy
Transener S.A.	—	20.35	Gas and Energy
Transportadora de Gas del Sur S.A.	—	20.96	Gas and Energy

Main affiliates - significance influence
Coroil S.A. (Venezuela)	—	37.15	Oil and Gas Exploration and Production
Petrobras Bolivia Refinación S.A. (Bolivia)	—	37.15	Refining and Distribution
Hidroneuquén S.A.	—	6.97	Gas and Energy
Inversora Mata S.A. (Venezuela)	—	37.15	Oil and Gas Exploration and Production
Oleoducto de Crudos Pesados Ltd. (Gran Cayman)	—	8.66	Gas and Energy
Oleoducto de Crudos Pesados S.A. (Ecuador)	—	8.66	Gas and Energy
Oleoductos del Valle S.A.	—	17.51	Gas and Energy
Propyme S.G.R.	—	37.91	Corporate
Petrolera Entre Lomas S.A.	—	14.56	Oil and Gas Exploration and Production
Petroquímica Cuyo S.A.	—	30.33	Petrochemical
Refineria del Norte S.A.	—	21.61	Refining and Distribution
Uruguaí S.A.	—	22.24	Gas and Energy
Yacylec S.A.	—	16.85	Gas and Energy

F-98

g) Oil and gas areas and participations in joint ventures as of December 31, 2005


NAME	LOCATION	WORKING INTEREST(2)		OPERATOR	DURATION THROUGH
Production
Argentina
25 de Mayo - Medanito S.E.	La Pampa and Río Negro	100.00	%	Petrobras Energia	2016
Jaguel de los Machos	La Pampa and Río Negro	100.00	%	Petrobras Energia	2015
Puesto Hemández- U.T.E.	Mendoza and Neuquén	38.45	%	Petrobras Energia	2016
Bajada del Palo - La Amarga Chica - U.T.E.	Neuquén	80.00	%	Petrobras Energia	2015
Santa Cruz II	Santa Cruz	100.00	%	Petrobras Energia	2017 / 2024
Río Neuquén	Neuquén and Río Negro	100.00	%	Petrobras Energia	2019
Entre Lomas	Neuquén and Río Negro	17.90	%	Petrolera Entre Lomas S.A.	2016
Aguada de la Arena	Neuquén	80.00	%	Petrobras Energia	2022
Veta Escondida y Rincón de Aranda - U.T.E.	Neuquén	55.00	%	Petrobras Energia	2016
Santa Cruz I - U.T.E	Santa Cruz	71.00	%	Petrobras Energia	2016 / 2023
Sierra Chata	Neuquén	19.89	%	Petrobras Energia	2022
Atamisqui	Mendoza	100.00	%	Petrobras Energia	2016
Refugio Tupungato	Mendoza	100.00	%	Petrobras Energia	2016
Atuel Norte	Mendoza	50.00	%	Tecpetrol S.A.	2016
EI Mangrullo	Neuquén	100.00	%	Petrobras Energia	2025
La Tapera - Puesto Quiroga	Chubut	21.95	%	Tecpetrol S.A.	2016
El Tordillo	Chubut	21.95	%	Tecpetrol S.A.	2016
Aguarague	Salta	15.00	%	Tecpetrol S.A.	2017

Foreign
Colpa - Caranda	Bolivia	100.00	%	Petrobras Energia	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	%	Petolera Mata	2017
Lote X	Perú	100.00	%	PE Perú	2024
Bloque 18(3)	Ecuador	70.00	%	Ecuadortlc	2022
Bloque 31(3)	Ecuador	100.00	%	Petrobras Energía	2024

Exploration
Argentina
Glencross (1)	Santa Cruz	96.68	%	Petrobras Energia	1999
Santa Cruz I - Oeste	Santa Cruz	50.00	%	Petrobras Energia	2006
Cerro Hamaca (4)	Mendoza	39.64	%	Petrobras Energia	2004
Gobemardor Ayala (4)	La Pampa	22.51	%	Petrobras Energia	2004
Puesto Zúñiga	Río Negro	100.00	%	Petrobras Energia	2006
Coiron Amargo	Neuquén	100.00	%	Petrobras Energia	2006
Cañadón del Puma	Neuquén	50.00	%	Chevron San Jorge S.R.L.	2006
Parva Negra (5)	Neuquén	47.63	%	Petrobras Energia	2001
Cerro Mantique (6)	Río Negro	50.00	%	Petrobras Energia
Estancia Chiripa (1)	Santa Cruz	100.00	%	Petrobras Energia	2001

Foreign
San Carlos	Venezuela	50.00	%	Pet San Carlos	2005
Tinaco	Venezuela	50.00	%	PE Venezuela	2006
Lote 57	Peru	35.15	%	PE Perú	2008
Lote 58	Peru	100.00	%	PE Perú	2007
Lote 110	Peru	100.00	%	PE Perú	2007
Lote 112	Peru	100.00	%	PE Perú	2007

(1)	Petrobras Energia has requested that the lot be declared operational with commercial operation held in suspense.

(2)	Indirect interest through Petrobras Energia and its subsidiaries.

(3)	See note 6.

(4)	The granting of the lots explotation concession is under progress.

(5)	The request to extend the explotation with commercial operation held in suspense was rejected. The granting of the concession is under progress.

(6)	The granting of the exploration permit is under progress.

F-99

h) Combined joint-ventures and consortium assets and liabilities as of December 31, 2005 and 2004 and results for the years ended December 31, 2005, 2004 and 2003.

(Stated in millions of Argentine Pesos - See Note 2.c)


Assets and liabilities	2005	2004
Current assets	708	928
Non-current assets	3,722	3,811

Total assets	4,430	4,739

Current liabilities	909	409
Non-current liabilities	84	74

Total liabilities	993	483


Statement of income	2005		2004		2003
Net sales	2,105		1,437		1,071
Costs of sales	(878	)	(746	)	(581	)

Gross profit	1,227		691		490

Administrative and selling expenses	(92	)	(93	)	(46	)
Exploration expenses	(20	)	(9	)	(8	)
Other operating (expenses) income	(219	)	(111	)	18
Financial income and holding gains	(160	)	91		2
Income tax provision	(98	)	(22	)	13

Net income	638		547		469

F-100

REFINERÍA DEL NORTE S.A.

STATEMENTS OF INCOME

FOR THE FISCAL YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(Figures stated in thousands of Argentine pesos – Note 2.II.)


			Unaudited
	2005		2004		2003
NET SALES (Note 3.h)	1,429,111		1,090,540		881,680
COST OF SALES (Note 3.i)	(1,068,411	)	(766,726	)	(617,883	)

Gross profit	360,700		323,814		263,797
ADMINISTRATIVE EXPENSES (Exhibit II)	(35,984	)	(31,364	)	(28,202	)
SELLING EXPENSES (Exhibit II)	(78,911	)	(72,816	)	(65,057	)
OTHER EXPENSES	(1,152	)	(3,464	)	(3,215	)
FINANCIAL INCOME (EXPENSE) AND HOLDING GAINS (LOSSES) (Note 3.j)	6,694		4,739		(9,803	)
OTHER INCOME, NET (Note 3.k)	4,094		2,828		3,019

Income before income tax	255,441		223,737		160,539
INCOME TAX (Note 3.l)	(95,201	)	(83,035	)	(62,612	)

Net income for the year	160,240		140,702		97,927

The accompanying notes 1 through 8 and supplementary statements (Exhibits I through V) are an integral part of these statements.

F-101

REFINERÍA DEL NORTE S.A.

BALANCE SHEETS AS OF DECEMBER 31, 2005 AND 2004

(Figures stated in thousands of Argentine pesos – Note 2.II.)


		Unaudited
	2005	2004
ASSETS
CURRENT ASSETS
Cash	2,301	1,438
Investments (Note 3.a)	4,444	55,696
Trade receivables (Note 3.b)	175,509	131,640
Other receivables (Note 3.c)	65,983	29,014
Inventories (Note 3.d)	105,037	94,826

Total current assets	353,274	312,614

NONCURRENT ASSETS
Investments (Note 2.III.a)	3	—
Trade receivables	3,292	3,438
Other receivables (Note 3.c)	9,876	8,847
Materials and spare parts	18,574	13,725
Property, plant and equipment (Exhibit I)	371,323	362,624
Intangible assets	2,392	2,215

Total non-current assets	405,460	390,849

Total assets	758,734	703,463

LIABILITIES CURRENT LIABILITIES
Accounts payable (Note 3.e)	224,904	190,674
Loans (Note 3.f)	79,568	77,291
Payroll and social security taxes	6,584	4,604
Taxes payable (Note 3.g)	31,518	40,820

Total current liabilities	342,574	313,389

NONCURRENT LIABILITIES
Other liabilities (Exhibit V)	11,652	10,429

Total non-current liabilities	11,652	10,429

Total liabilities	354,226	323,818
SHAREHOLDERS’ EQUITY (as per related statements)	404,508	379,645

	758,734	703,463

The accompanying notes 1 through 8 and supplementary statements (Exhibits I through V) are an integral part of these statements.

F-102

REFINERÍA DEL NORTE S.A.

STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

FOR THE FISCAL YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(Figures stated in thousands of Argentine pesos – Note 2.II.)


	2005									Unaudited
	2005									2004		2003
	Shareholders’ contributions		Retained earnings
	Capital stock	Adjustment to capital stock	Legal reserve	Voluntary reserve		Unappropriated retained earnings		Total		Total		Total
Balances at beginning of the year	91,607	130,190	15,436	44,937		97,475		379,645		354,324		311,410

Decisions of the Regular Shareholders’ Meetings of March 24, 2003, December 15, 2003, April 1, 2004, April 15, 2005, and December 15, 2005:
- Earnings distribution:
to cash dividends	—	—	—	(44,937	)	(90,440	)	(135,377	)	(115,381	)	(55,013	)
to legal reserve	—	—	7,035	—		(7,035	)	—		—		—
Net income for the year	—	—	—	—		160,240		160,240		140,702		97,927

Balances at end of the year	91,607	130,190	22,471	—		160,240		404,508		379,645		354,324

The accompanying notes 1 through 8 and supplementary statements (Exhibits I through V) are an integral part of these statements.

F-103

REFINERÍA DEL NORTE S.A.

STATEMENTS OF CASH FLOWS (1)

FOR THE FISCAL YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(Figures stated in thousands of Argentine pesos – Note 2.II.)


			Unaudited
	2005		2004		2003
Cash provided by operations:
Net income for the year	160,240		140,702		97,927
Adjustments to reconcile the net income for the year to the cash provided by operations:
Income tax accrued	95,201		83,035		62,612
Income tax paid	(89,151	)	(95,486	)	(15,549	)
Depreciation of property, plant and equipment	33,978		32,878		28,192
Property, plant and equipment retirements	190		2,781		1,190
Intangible assets amortization	922		872		890
Reestimation of provisions and reserves	3,954		(3,222	)	(1,847	)
Interest accrued	4,436		4,743		9,237
Interest paid	(2,388	)	(5,135	)	(12,389	)
Inventory holding (gains) losses	(14,388	)	(11,060	)	5,706
Consumption of materials and spare parts	6,189		6,465		4,843
Compensation for contractual breach	(8,519	)	—		—
Other financial income, net	1,243		2,021		13,824

Changes in assets and liabilities
Trade receivables	(43,735	)	(35,040	)	12,182
Other receivables	(29,479	)	(13,300	)	8,289
Inventories	(6,861	)	12,739		(31,781	)
Accounts payable	34,230		67,615		(24,683	)
Payroll and social security taxes and taxes payable	(16,478	)	3,690		(9,338	)
Other liabilities	(1,655	)	992		7,749

Cash provided by operations	127,929		195,290		157,054

Cash used in investing activities:
Acquisition of property, plant and equipment	(43,153	)	(46,750	)	(44,338	)
Investments other than cash	(191	)	—		—
Sale of property, plant and equipment	286		—		—
Increase in intangible assets	(1,099	)	(1,048	)	(254	)

Cash used in investing activities	(44,157	)	(47,798	)	(44,592	)

Cash used in financing activities:
Net short-term loans obtained (paid)	1,410		(26,762	)	(66,978	)
Dividends paid	(135,377	)	(144,031	)	(31,100	)

Cash used in financing activities	(133,967	)	(170,793	)	(98,078	)

Effect of inflation and devaluation on cash	—		(1,047	)	(8,270	)
(Decrease) increase in cash	(50,195	)	(24,348	)	6,114

Cash and cash equivalents at beginning of the year (1)	56,940		81,288		75,174

Cash and cash equivalents at end of the year (1)	6,745		56,940		81,288

(1)	Cash plus current investments with original maturities of three months or less.

The accompanying notes 1 through 8 and supplementary statements (Exhibits I through V) are an integral part of these statements.

F-104

REFINERÍA DEL NORTE S.A.

NOTES TO THE FINANCIAL STATEMENTS

AS OF DECEMBER 31, 2005

(Figures stated in thousands of Argentine pesos – Note 2.II.)

1. COMPANY INCORPORATION AND ACTIVITY

Refinería del Norte S.A. (“the Company” or “Refinor”) was organized to engage in the industrialization of liquid and/or gas hydrocarbons and the direct and indirect by-products thereof through the commercial exploitation of the Campo Durán business unit, which includes the Campo Durán distillery, the Campo Durán-Montecristo multiple pipeline, the Güemes and Tucumán storage plants, as well as the retail distribution of its products through a service center network.

According to the by-laws, the holders of class “A” shares, owning 50% of the capital stock, are in charge of the operation of the Company’s assets through 2018, being jointly and severally liable for the related obligations.

2. SIGNIFICANT ACCOUNTING POLICIES

I. Generally accepted accounting principles

These financial statements were prepared in accordance with generally accepted accounting principles effective in Argentina, as approved by the Professional Council in Economic Sciences of the City of Buenos Aires (CPCECABA).

On August 10, 2005, the Board of the CPCECABA approved Resolution CD No. 93/2005, which introduced a series of changes to professional accounting standards, effective for the fiscal years beginning as from January 1, 2006. In addition, it contemplated transition standards that defer the obligatory effectiveness of certain changes for fiscal years beginning as from January 1, 2008.

The changes that could be of relevance to the Company’s financial statements are described below:

(i) It is established that the difference between the Property, Plant and Equipment carrying value adjusted for inflation (and other nonmonetary assets) and their tax value is a temporary difference for deferred income tax purposes that would result in the recognition of a deferred tax liability. Notwithstanding this, it is acceptable to continue to consider such difference as permanent. In this case, the disclosure of certain supplementary information is required.

(ii) In the performance of impairment tests of Property, Plant and Equipment and certain intangible assets, the comparison of their carrying value against the sum of the undiscounted cash flows expected to result from the use and eventual disposition of those assets, is eliminated. An impairment allowance is now required to be booked whenever the estimated present value of net cash flows (and the net realizable value) is lower than the carrying value.

(iii) An amendment was introduced in the measurement of the deferred tax assets and liabilities, which shall not be discounted.

The Company’s Management is currently evaluating the future impact of the application of such standards in its financial statements.

F-105

II. Restatement into constant currency

Generally accepted accounting principles in Argentina establish that the financial statements should be stated in constant currency. Within a monetary stability context, the nominal currency is used as constant currency; however, during inflationary or deflationary periods, financial statements are required to be restated into constant currency recognizing the variations in the domestic wholesale price index, in conformity with the restatement method established by the Argentine Federation of Professional Councils in Economic Sciences Technical Resolution No 6.

These financial statements recognize the effects of the changes in Argentine peso purchasing power through February 28, 2003, as required by Presidential Decree No. 664/2003 and IGJ (Argentine regulatory agency of business associations) General Resolution No. 4/2003.

III. Valuation methods

The main valuation methods used to prepare these financial statements are:

Cash and investments:

•

Cash and certificates of deposit in local currency: at nominal value.

•

Cash and certificates of deposit in foreign currency: at nominal value, converted at the prevailing exchange rates at each year-end. Foreign exchange differences were charged to the statement of income for each year.

•

Mutual funds: at market prices as of each year-end.

•

Noncurrent investment in subsidiary: it includes the 100% interest in the capital stock of Refinor Internacional S.A., a company organized in Bolivia and acquired by Refinor in October, 2005, by the holding of 6 registered shares of common stock, face value USD 166 per share. This company closes its fiscal year on December 31 and it has not been engaged in any transactions during the 2005 fiscal year. As of December 31, 2005, its shareholders’ equity amounted to 3. This investment was valued by the equity method using Management information available as of year-end. The Company’s Management decided not to file consolidated financial statements considering the scarce significance of the amounts involved.

Current investments include financial income (expense) accrued as of each year-end.

Trade receivables and accounts payable:

Trade receivables and accounts payable were valued at the estimated price used in spot transactions upon each transaction plus the relevant portion of accrued financial income (expense).

Receivables and payables in foreign currency were converted into Argentine pesos at the prevailing exchange rates at each year-end for the settlement of these transactions.

Trade receivables were valued net of an allowance for doubtful accounts. Upon estimating the amounts the Company’s Management considered the likelihood of occurrence based on the judgment elements available and the legal counsel’s opinion.

Loans:

Loans were valued according to the amount of money received, including the relevant portion of financial expense accrued. Payables in foreign currency were converted into Argentine pesos at the prevailing exchange rates at each year-end for the settlement of these transactions.

F-106

Other receivables and payables (except contingencies):

Receivables from and payables to third parties, except for those indicated in sections (b) and (c) above, were valued on the basis of the amount to be collected and paid, respectively, discounted in the relevant cases. Receivables from and payables to related companies were valued at nominal value plus accrued financial income (expense).

Inventories:

Crude oil and refined products: at replacement or reproduction cost, as applicable.

Materials and spare parts: of high turnover, at replacement cost; of low turnover, at the last purchase price restated as indicated in note 2.II.

Advances to suppliers: valued on the basis of the amounts of money delivered. The amounts in foreign currency were converted at the prevailing exchange rates at each year-end for the settlement of these transactions.

The value of inventories, thus obtained, does not exceed its recoverable value.

Property, plant and equipment:

Transferred assets: The total value was assessed on the basis of the price effectively paid for the majority shareholding under competitive bidding (70% of capital stock), restated as indicated in note 2.II. Such value was pro-rated among the different assets obtained on the basis of the technical residual value thereof estimated by independent experts. The amounts thus assessed are net of the related accumulated depreciation calculated by the straight-line method on the basis of the remaining useful life estimated by the experts mentioned above.

Additions subsequent to the transfer date: valued at acquisition cost restated as indicated in note 2.II including, if applicable, the cost related to the financing thereof less the related accumulated depreciation calculated by the straight-line method on the basis of the estimated useful life.

Advances to suppliers: valued on the basis of the amounts of money delivered.

The valuation of property, plant and equipment does not exceed the related recoverable value.

Intangible assets:

Related to disbursements made to gas station’s owners in connection with agreements of branding of gas stations. They were valued on the basis of the amount of money delivered restated as mentioned in note 2.II less the related accumulated amortization, calculated considering a five-year useful life, which is the term of the agreements.

The valuation of intangible assets does not exceed the related recoverable value.

Income tax, minimum presumed income tax and VAT:

The Company recognized the income tax charge based on the deferred tax method, thus recognizing the temporary differences between the book- and tax-purposes measurements of assets and liabilities. The tax rate expected to be effective upon the reversal or use of deferred assets and liabilities was applied on the temporary differences identified in order to determine such assets and liabilities, considering current legal regulations issued as of the date of issuance of these financial statements.

F-107

As of December 31, 2005, the Company recognized deferred tax assets since the future recoverability thereof has been evaluated as probable.

In addition, the Company determines minimum presumed income tax by applying the effective 1% rate to the computable assets at year-end. This tax is supplementary to income tax. The Company’s tax obligation for each tax year shall be the higher of these two taxes. However, should minimum presumed income tax exceed income tax in a given tax year, such excess may be computed as payment on account of any income tax excess over minimum presumed income tax that could occur in any of the ten subsequent years.

As of December 31, 2005, the income tax amount calculated exceeded minimum presumed income tax. Note 3.I to these financial statements discloses the changes and breakdown of income tax and deferred tax accounts.

The Company’s sales on the domestic market are subject to valued added tax (VAT) at the general 21% rate. However, as provided for in Law No. 26,020, effective April 17, 2005, propane, butane, and LPG sales on the domestic market were subject to a differential 10.5% rate.

Contingencies:

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 “Other liabilities” 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.

Shareholders’ equity accounts:

These accounts have been restated as mentioned in Note 2.II, except for the “Capital stock” account, which has been kept at original value. The adjustment resulting from such restatement is disclosed under the caption “Adjustment to capital stock”.

Statement of income accounts:

Restated into constant currency according to Note 2.ll, considering the following:

•

The charges for consumption of non-monetary assets were determined based on the restated values of such assets.

•

Financial income (expense) and holding gains (losses) are broken down between those generated by assets and those generated by liabilities and they include nominal financial income and expense, foreign exchange differences, the effects of inflation on monetary assets and liabilities and other holding gains (losses).

F-108

3. BREAKDOWN OF MAIN ACCOUNTS

The main accounts breakdown is as follows:


			Unaudited
	2005		2004
a) Investments:
Current:
Certificates of deposit	3,094		3,293
Mutual funds	1,350		52,082
Government securities	—		321

	4,444		55,696

b) Trade receivables:
Current:
Common receivables	27,329		24,831
Receivables under litigation	7,331		7,823
Shareholder companies:
• Petrobras Energía S.A.	40,760		17,291
• YPF S.A.	26,343		29,996
• Pluspetrol S.A.	13,851		4,525
Related companies:
• Repsol YPF Trading y Transporte S.A.	44,908		37,542
• Petrobras Bolivia Distribución S.A.	21,400		16,027
• Pluspetrol Energy S.A.	43		49

	181,965		138,084
Less: Allowance for doubtful accounts (Exhibit V)	(6,456	)	(6,444	)

	175,509		131,640

c) Other receivables:
Current:
VAT credit	54,171		17,931
Tax on diesel oil transfer or import credit	2,292		—
Prepaid insurance	1,799		2,761
Advances to suppliers	760		2,125
Court deposit	660		3,594
Loans and advances to personnel	335		417
Turnover tax credit	296		383
Prepaid expenses	88		314
Notes receivable	899		447
Less: Allowance for doubtful accounts (Exhibit V)	(404	)	(442	)
Shareholder company – Pluspetrol S.A. (Note 3.k.2)	2,981		—
Other	2,106		1,484

	65,983		29,014

F-109


			Unaudited
	2005		2004
Noncurrent:
Deferred tax assets (Note 3.I)	2,956		5,157
Turnover tax credit	2,739		897
Notes receivable	1,111		2,284
Shareholder company – Pluspetrol S.A. (Note 3.k.2)	2,629		—
Other	441		509

	9,876		8,847

d) Inventories:
Refined products	63,627		60,818
Materials and spare parts	20,961		22,175
Allowance for materials’ impairment (Exhibit V)	(4,218	)	(4,218	)
Crude oil	23,611		14,901
Advances to suppliers	138		248
Other	918		902

	105,037		94,826

e) Accounts payable:
Common suppliers	120,822		96,861
Shareholder companies:
• YPF S.A.	74,983		74,218
• Petrobras Energía S.A.	22,944		15,164
• Pluspetrol S.A.	4,496		3,341
Related companies:
• Pluspetrol Energy S.A.	1,633		1,076
• Pluspetrol Bolivia Corporation S.A.	26		14

	224,904		190,674

f) Loans:
Short-term bank loans	77,303		75,893
Interest payable	2,265		1,398

	79,568		77,291

g) Taxes payable:
Income tax, net of prepayments and withholdings	25,402		32,080
Tax on fuel transfers	812		2,801
Other withholdings	5,012		4,629
Tax on diesel oil transfer or import	—		776
Other	292		534

	31,518		40,820

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	Income (Loss)
			Unaudited
	2005		2004		2003
h) Net sales:
Gross sales (1)	1,462,820		1,115,978		901,772
Withholdings on exports (2)	(33,709	)	(25,438	)	(20,092	)

	1,429,111		1,090,540		881,680

(1)

Sales for the fiscal year ended December 31, 2005, made mainly to Repsol YPF Trading y Transporte S.A., YPF S.A., Petrobras Energía S.A., Petrobras Bolivia Distribución S.A., and Compañía Petrolera Nacional Ltda. (Bolivia), represented about 37%, 12%, 7%, 9%, and 8%, respectively, of total gross sales.

(2)	The Argentine Government implemented a withholding on exports system amounting to 5% of hydrocarbons by-products and 20% of LPG exports.


			Unaudited
	2005		2004		2003
i) Cost of sales:
Inventories in stock at beginning of year	108,551		120,330		99,098
Purchase of goods and services	993,035		685,218		598,350
Operating expenses (Exhibit II)	76,725		59,352		48,496
Inventory holding gains (losses) (Note 3.j)	14,388		11,060		(5,706	)
Plant idle capacity	(677	)	(683	)	(2,025	)
Less: Inventories in stock at end of year	(123,611	)	(108,551	)	(120,330	)

	1,068,411		766,726		617,883


	Income (Loss)
			Unaudited
	2005		2004		2003
j) Financial income (expense) and holding gains (losses):

From assets:
Due to foreign exchange differences	420		(14,779	)	(33,219	)
Inventory holding gains (losses)	14,388		11,060		(5,706	)
Loss due to inflation exposure	—		—		(1,955	)
Interest accrued	3,118		3,594		1,054
Other	335		(16	)	668

Subtotal from assets	18,261		(141	)	(39,158	)

From liabilities:
Due to foreign exchange differences	(2,918	)	14,883		39,679
Interest accrued	(7,554	)	(8,337	)	(10,291	)
Commissions and other bank expenses	(1,095	)	(1,666	)	(2,824	)
Gain due to inflation exposure	—		—		2,791

Subtotal from liabilities	(11,567	)	4,880		29,355

Total	6,694		4,739		(9,803	)

F-111


	Income (Loss)
			Unaudited
	2005		2004		2003
k) Other income, net:
Reestimation of provisions and reserves	(3,954	)	3,222		1,847
Reversal of insurance – Lavallen claim (1)	—		—		2,377
Reversal of doubtful accounts accrual	—		—		462
Compensation for contractual breach (2)	8,519		—		—
Other	(471	)	(394	)	(1,667	)

Total	4,094		2,828		3,019

(1)	Corresponds to the amount recognized by the assurance company for the remediation made because of a spilling of hydrocarbons.

(2)

The shareholder company Pluspetrol S.A. breached certain contractual commitments related to rich gas supply to the Company. On April 14, 2005, both companies signed an agreement whereby Pluspetrol S.A. recognized that the Company carried a USD 2,950 receivable in this regard, which is settled by offsetting it with the obligations resulting from rich gas purchases by Refinor S.A. to the abovementioned company over a maximum 36-month term. Noncompensated differences, if any, are assessed and paid in cash in the periods established in the agreement.

I)	Income tax and deferred tax:

The breakdown of income tax included in the statement of income and its reconciliation with the one that would result from applying the current 35% rate on book income before income tax are disclosed below:


	Income (Loss)
			Unaudited
	2005		2004		2003
Estimated tax payable	(92,731	)	(80,458	)	(61,871	)
Changes in nominal deferred tax	(2,470	)	(2,577	)	(741	)

Total income tax	(95,201	)	(83,035	)	(62,612	)

Income for the year before income tax	255,441		223,737		160,539
Effective tax rate	35	%	35	%	35	%

	(89,404	)	(78,308	)	(56,189	)
Permanent differences at tax rate:
- Restatement into constant pesos	(4,288	)	(5,350	)	(5,913	)
- Other	(1,509	)	623		510

Total income tax	(95,201	)	(83,035	)	(62,612	)

F-112

Deferred tax net assets as of December 31, 2005 and 2004, break down as follows:


			Unaudited
	2005		2004
Asset differences
- Deferred foreign exchange difference	1,848		6,407
- Non-deductible allowances	3,125		2,651
- Other, not individually significant	2,971		1,512
Liability differences
- Valuation of inventories	(4,988	)	(5,413	)

	2,956		5,157

4. MAIN COMMITMENTS ASSUMED BY THE COMPANY AND CONTINGENCIES

Commitments

The Company assumed different purchase commitments for crude and condensed oil and natural gas by-products at prices adjusted by a variable scale based on the international WTI price (periodically checked according to domestic market changes) for crude and condensed oil, and the basin price published by the Enargas for natural gas by-products. The amounts of purchase obligations, calculated on the basis of future estimated prices and the expected volumes for the coming years are:


	Millions of Argentine pesos
	Condensed and crude oil	Natural gas by-products
2006	241	83
2007	93	82
2008	82	72
2009	80	71
2010 and subsequent years	38	180

	534	488

The Company assumed different sales commitments of virgin gasoline, diesel oil and natural gas by-products. The amounts of sale obligations, calculated on the basis of future estimated prices and the expected volumes for the coming years are:


Millions of Argentine pesos
Year	Virgin gasoline	Diesel oil	Natural gas by- products
2006	418	260	170
2007	134	243	170
2008	—	54	42

	552	557	382

A total amount of 48% and 88% of the purchase and sale commitments, respectively, mentioned above were executed with shareholders and related companies.

On December 24, 2004, the Energy Department issued Resolution No. 1679/2004 which, among other issues, required that market agents report all diesel oil export transactions for prior approval providing evidence that the demand of the whole commercial chain, both retail and wholesale, identified with a

F-113

brand or refinery, or not, is appropriately met or that domestic demand has been granted the possibility of acquiring diesel oil. This evidence should be included in a declaration with minimum contents established by the abovementioned resolution. As of the date of issuance of these financial statements, the Company’s Management obtained the related exports permits and it is currently evaluating the commercial procedures that it will use to meet effective contracts.

Lawsuits

The Company is a party to a criminal lawsuit resulting from its reporting with the ANA (Argentine Customs Administration) in connection with gasoline sales to Paraguay in 1996 and in connection with which two Company customers and a transportation company are being investigated. As of the date of issuance of these financial statements, the lawsuit is at the pre-trial investigation stage and, based on the Company’s participation in good faith and according to its legal counsel, a favorable outcome is expected.

On September 20, 2001, and in connection with the criminal lawsuit related to gasoline sales to Paraguay mentioned above, the DGI (Argentine tax bureau) notified the assessment of the tax on fuel transfers and VAT allegedly omitted in such transactions in the amount of about 1,400 and possible fines and interest. Having the Company filed a brief with the DGI on October 17, 2001, such agency reasserted its collection intention on December 14, 2001.

In 2000, the DGR (provincial tax authorities) of the Province of Tucumán assessed a turnover tax charge larger than the one calculated by the Company by 1,400 and interest in the amount of 1,600, and potential fines from a difference in the tax rate applied to calculate the abovementioned tax. On May 10, 2004, the Company, jointly with other companies operating in the province, executed an agreement with the Government of the Province of Tucumán to conclude the administrative and legal actions existing at present or that could occur in the future, whereby the parties give up the actions filed duly and waive any right to claim or appeal the amounts paid in connection with the collection intention for the fiscal years prior to December 31, 2003, related to such claim.

In addition, during the fiscal year ended December 31, 2003, the Company received an estimation from the AFIP (Federal Public Revenue Agency) claiming the payment of the diesel oil rate for the exports of such fuel for the period beginning July 2001 through February 2003. The amount claimed totaled 21,646 plus potential interest and fines. On June 15, 2005, the AFIP revoked the abovementioned claim.

Also, during fiscal year 2005, the Company received claims from the DGR of the Provinces of Salta and Jujuy in connection with differences in turnover tax calculations in the amounts of about 43,273 and 504, respectively, plus potential interest and fines resulting from differences in the tax category of the Company’s activities. As of the date of issuance of these financial statements, the Company filed briefs with the abovementioned provincial agencies.

Finally, as of the date of issuance of these financial statements certain other lawsuits were in progress in connection with the Company’s operations.

Based on the opinion of its legal counsel and tax advisors, the Company estimated that the final outcome of the lawsuits mentioned above will not have a material adverse effect on the Company’s financial position and results of operations.

F-114

5. TRANSACTIONS WITH SHAREHOLDER COMPANIES AND RELATED COMPANIES

During the fiscal years ended December 31, 2005, 2004 and 2003, the Company engaged in transactions with the shareholder companies and related companies as follows:


		Unaudited
	2005	2004	2003
Sale of products and services:
Shareholder companies:
• YPF S.A.	167,713	152,317	124,870
• Pluspetrol S.A.	40,171	32,156	20,880
• Petrobras Energía S.A.	122,338	77,384	57,339
Related companies:
• Repsol YPF Trading y Transporte S.A.	528,254	380,716	287,265
• Petrobras Bolivia Distribución S.A.	118,834	57,411	49,731
• Pluspetrol Energy S.A.	448	396	413
• Pluspetrol Bolivia Corporation S.A.	24	45	—
• Repsol Gas S.A.	—	111	3,468

	977,782	700,536	543,966

Purchases of products and services:
Shareholder companies:
• YPF S.A.	315,059	286,730	269,838
• Petrobras Energía S.A.	78,838	43,080	39,879
• Pluspetrol S.A.	37,746	35,859	20,595
• Petrobras Energía S.A – Fees to the operator (1)	3,031	2,974	2,933
Related companies:
• Empresa Petrolera Andina S.A.	151,182	30,024	—
• Pluspetrol Bolivia Corporation S.A.	8,681	5,353	1,312
• Pluspetrol Energy S.A.	11,776	11,060	13,638

	606,313	415,080	348,195

(1)	The Company is committed to recognizing technical operation assistance fees equivalent to 5% of gross earnings, up to an accumulated cap of USD 1,000,000 per fiscal year.


		Unaudited
	2005	2004	2003
Other transactions:
Shareholder company – Pluspetrol S.A.:
Compensation for contractual breach	8,519	—	—

	8,519	—	—

6. CAPITAL STOCK BREAKDOWN AND RETAINED EARNINGS RESTRICTION

The capital stock as of December 31, 2005, 2004 and 2003 was fixed at 91,607 represented by 91,607,310 book-entry shares of common stock, with Argentine peso 1 face value each, entitled to one vote per share, and broken down into class “A” and “B” shares, as detailed below:


	Shares
	Class	Number
Petrobras Energía S.A.	A	26,108,078
Pluspetrol S.A.	A	19,695,577
YPF S.A.	B	45,803,655

Total		91,607,310

Under Argentine Business Associations Law No. 19,550, 5% of net income for the year should be appropriated to increase the legal reserve until such reserve is equal to 20% of the capital stock.

Under Law No. 25,063, dividends to be distributed in cash or in kind in excess of taxable income accumulated as of the date of payment or distribution shall be subject to a 35% income tax withholding as single and definitive payment.

F-115

7. AGREEMENT WITH OIL AND GAS COMPANIES

The agreement signed on January 1, 2003, by oil and gas producers and refineries related to the stability of the price of fuels on the domestic market expired on April 30, 2004. The accumulated balance accrued by the Company in favor of oil and gas producers amounting to 69,595 and booked as current accounts payable as of December 31, 2005, will be paid over to them when the WTI value of crude oil is under USD 28.5 per barrel, under the mechanism provided for in such agreement.

As from May 1, 2004, producers and refiners independently executed agreements whereby the price of crude oil purchases paid by local refineries (including the Company) to producers is fixed considering a variable scale of the adjustment factor based on the WTI reviewed periodically on the basis of market changes.

8. SUMMARY OF SIGNIFICANT DIFFERENCES BETWEEN ACCOUNTING PRINCIPLES FOLLOWED BY THE COMPANY AND US GAAP

The financial statements as of December 31, 2005 have been prepared in conformity with generally accepted accounting principles in Argentina (Argentine GAAP) which differ in certain respects from generally accepted accounting principles in the United States of America (US GAAP). The significant differences between Argentine GAAP and US GAAP that affect the Company’s financial statements are principally related to the following items:

a) Restatements of financial statements for general price-level changes

Prior to September 1, 1995, the financial statements were required to recognize the effects of the changes in the purchasing power of the currency, through the restatement of non-monetary assets and liabilities into constant Argentine pesos as of the date of the financial statements. Since September 1, 1995, and until December 31, 2001, following professional accounting standards, the Company interrupted the use of such method. Due to the inflationary environment in Argentina in 2002, the professional accounting standards required the reinstatement of the adjustment-for-inflation method of accounting in financial statements, since January 1, 2002.

As the inflation rate stabilized, the Argentine regulatory agency of business associations (IGJ) rescinded the requirement that financial statements be prepared in constant currency from March 1, 2003. Thus, the Company recognized the effects of the changes in the purchasing power of the Argentine peso until February 28, 2003.

Under US GAAP, general price level adjusted financial statements are not required. However, pursuant to the Security and Exchange Commission (SEC)’s rules, these adjustments are not removed when performing certain filings to the mentioned commission.

b) Income taxes

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-116

The deferred tax assets and liabilities under Argentine GAAP are required to be discounted using an estimated rate at the time of the financial statements, whereas under US GAAP they are accounted for at nominal value.

c) Accounting for inventories

Under Argentine GAAP, inventories must be accounted for at reproduction or replacement cost or, at the price the Company would pay at any given time to replace or reproduce such inventory, whereas under US GAAP, inventories must be accounted for at cost.

d) Discounting of certain receivables and liabilities

e) Financial statements presentation and disclosure

These financial statements have been prepared in conformity with the overall presentation and disclosures provisions required by Argentine GAAP, which differ in certain respects from US GAAP.

F-117

EXHIBIT I

REFINERÍA DEL NORTE S.A.

CHANGES IN PROPERTY, PLANT AND EQUIPMENT AS OF DECEMBER 31, 2005, 2004 AND 2003

(Figures stated in thousands of Argentine pesos – Note 2.II.)


	2005
	Original cost
Main account	At beginning	Additions	Transfers		Decreases		At end
Gas stations	18,077	—	1,380		—		19,457
Buildings and construction	16,429	—	1,750		(506	)	17,673
Compression plant equipment and facilities	2,895	—	23		—		2,918
Pumping stations equipment and facilities	23,748	—	83		—		23,831
Multiple pipeline equipment and facilities	127,552	—	6,926		(309	)	134,169
Refinery equipment and facilities	316,154	—	25,159		—		341,313
Tools	3,922	104	—		(4	)	4,022
Software	14,937	989	—		(42	)	15,884
Furniture and office supplies	5,073	451	—		(7	)	5,517
Vehicles	5,178	—	—		(150	)	5,028
Storage and dispatch units	44,355	—	193		—		44,548
Works in process	20,458	28,063	(22,155	)	—		26,366
Plots of land	3,705	—	—		(56	)	3,649
Advances to suppliers	1,557	4,371	(3,989	)	—		1,939
Materials and spare parts	5,123	9,175	(9,370	)	—		4,928

Total as of 12/31/2005	609,163	43,153	—		(1,074	)	651,242

Total as of 12/31/2004 (Unaudited)	569,695	46,750	—		(7,282	)	609,163

Total as of 12/31/2003 (Unaudited)	538,466	44,338	—		(13,109	)	569,695


	2005							2004 (Unaudited)	2003 (Unaudited)
	Accumulated depreciation
		For the year
Main account	At beginning	Rate %	Amount	Decreases		At end	Net book Value	Net book value	Net book Value
Gas stations	7,930	4 to 7	1,333	—		9,263	10,194	10,147	10,640
Buildings and construction	5,308	2 to 10	828	(206	)	5,930	11,743	11,121	12,912
Compression plant equipment and facilities	52	3 to 7	117	—		169	2,749	2,843	—
Pumping stations equipment and facilities	8,462	4 to 6	1,056	—		9,518	14,313	15,286	16,214
Multiple pipeline equipment and facilities	50,022	2 to 6	4,764	(245	)	54,541	79,628	77,530	74,385
Refinery equipment and facilities	138,409	4 to 10	21,738	—		160,147	181,166	177,745	188,894
Tools	3,474	9 to 20	200	(4	)	3,670	352	448	559
Software	11,316	10 to 33	1,445	(28	)	12,733	3,151	3,621	4,077
Furniture and office supplies	4,741	10 to 20	224	(6	)	4,959	558	332	620
Vehicles	3,976	20	404	(109	)	4,271	757	1,202	1,608
Storage and dispatch units	12,849	4 to 10	1,869	—		14,718	29,830	31,506	29,239
Works in process	—		—	—		—	26,366	20,458	3,943
Plots of land	—		—	—		—	3,649	3,705	3,800
Advances to suppliers	—		—	—		—	1,939	1,557	82
Materials and spare parts	—		—	—		—	4,928	5,123	4,560

Total as of 12/31/2005	246,539		33,978	(598	)	279,919	371,323

Total as of 12/31/2004 (Unaudited)	218,162		32,878	(4,501	)	246,539		362,624

Total as of 12/31/2003 (Unaudited)	195,867		28,192	(5,897	)	218,162			351,533

F-118

EXHIBIT II

REFINERÍA DEL NORTE S.A.

INFORMATION REQUIRED UNDER SECTION 64(1)b OF LAW No. 19,550

FOR THE FISCAL YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(Figures stated in thousands of Argentine pesos – Note 2.II.)


	Unaudited		2005
Accounts	2003	2004	Total	Operating expenses	Administrative expenses	Selling expenses
Payroll and social security taxes	17,264	20,367	27,548	4,604	11,568	11,376
Other employee benefits	3,320	4,051	3,730	479	1,897	1,354
Taxes, charges and contributions	14,179	14,737	15,785	366	8,576	6,843
Depreciation of property, plant and equipment	28,192	32,878	33,978	23,214	925	9,839
Intangible assets amortization	890	872	922	—	—	922
Maintenance expenses	12,834	8,859	12,246	5,753	791	5,702
Transportation and storage expenses	18,457	22,226	25,909	—	—	25,909
Electric power, fuels and lubricants and other	10,767	19,638	30,994	28,945	66	1,983
Consumption of materials and spare parts	4,843	6,465	6,189	3,792	427	1,970
Insurance	7,210	5,142	5,771	4,770	834	167
Works and other services contracted	8,550	11,198	12,778	4,467	3,315	4,996
Communications	2,048	2,148	2,215	135	623	1,457
Traveling and living expenses	901	1,254	1,180	47	641	492
Advertising	2,736	2,904	2,563	—	—	2,563
Professional fees	4,321	4,730	4,802	55	4,507	240
Other	5,243	6,063	5,010	98	1,814	3,098

Total 2005			191,620	76,725	35,984	78,911

Total 2004 (Unaudited)		163,532		59,352	31,364	72,816

Total 2003 (Unaudited)	141,755			48,496	28,202	65,057

F-119

EXHIBIT III

REFINERÍA DEL NORTE S.A.

ASSETS AND LIABILITIES IN FOREIGN CURRENCY

AS OF DECEMBER 31, 2005 AND 2004

(Figures stated in thousands)


	2004 (Unaudited)		2005
Item	Currency and amount		Currency and amount			Effective exchange rate	Booked amount in thousands of Argentine pesos
CURRENT ASSETS
Cash	USD	2	USD	3	(a)	3.0315	9
Investments	USD	16,312	USD	1,021	(a)	3.0315	3,094
Other receivables		—	USD	1,088	(a)	3.0315	3,299
Trade receivables	USD	10,447	USD	28,256	(a)	3.0315	85,657
Inventories – Advances to suppliers	USD	83	USD	45	(a)	3.0315	138

Total current assets							92,197

NONCURRENT ASSETS
Other receivables		—	USD	867	(a)	3.0315	2,629

Total non-current assets							2,629

Total assets							94,826

CURRENT LIABILITIES
Accounts payable	USD	21,528	USD	30,880	(a)	3.0315	93,612
Loans	USD	25,991	USD	26,247	(a)	3.0315	79,568

Total current liabilities							173,180

(a)	Benchmark exchange rate of the BCRA (Central Bank of Argentina).

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EXHIBIT IV

REFINERÍA DEL NORTE S.A.

BREAKDOWN OF CURRENT INVESTMENTS, RECEIVABLES, LOANS AND OTHER LIABILITIES

AS OF DECEMBER 31, 2005

(Figures stated in thousands of Argentine pesos – Note 2.II.)


	Assets				Liabilities
Term	Current investments		Receivables		Loans		Other liabilities
With no maturity	—		5,695	(5)	—		81,247	(6)

With maturity

Matured:
- Up to 3 months	—		65,745		—		19,720
- From 3 to 6 months	—		—		—		418
- From 6 to 9 months	—		1		—		164
- From 9 to 12 months	—		439		—		433
- From 1 to 2 years	—		277		—		349
- Over 2 years	—		12,931		—		760

Total matured	—		79,393		—		21,844

To mature:
- Up to 3 months	4,444		165,891		78,436		143,135
- From 3 to 6 months	—		206		453		28,432
- From 6 to 9 months	—		44		679		—
- From 9 to 12 months	—		2,818		—		—
- From 1 to 2 years	—		3,332		—		—
- Over 2 years	—		4,141		—		—

Total to mature	4,444		176,432		79,568		171,567

Total with maturity	4,444		255,825		79,568		193,411

Total	4,444	(1)	261,520	(2)	79,568	(3)	274,658	(4)

(1)	Accruing interest at a variable rate of about 3.76% per annum.

(2)	Receivables are disclosed excluding the allowance for doubtful accounts. Approximately 94% does not accrue interest, accruing the rest, interest at a fixed rate. The average weighted rate is approximately 6% per annum.

(3)	Loans accrue interest at a variable rate. The average weighted rate, including taxes on interest, is approximately 4.24% per annum.

(4)	Not accruing interest, except for the accrual for purchase of raw material under the agreement with oil & gas producing companies amounting to 69,595, accruing interest at LIBOR.

(5)	Related to the balances of social contributions credit, turnover tax credit, and deferred tax assets.

(6)	Related to reserves for contingencies and accrual for purchase of raw material under the agreement with oil & gas producing companies.

F-121

EXHIBIT V

REFINERÍA DEL NORTE S.A.

CHANGES IN ALLOWANCES AND RESERVES AS OF DECEMBER 31, 2005 AND 2004

(Figures stated in thousands of Argentine pesos – Note 2.II.)


	2005
Item	Balances at beginning of year	Increases		Decreases		Balances at end of year
Deducted from assets:

- Allowance for doubtful accounts	6,886	—		26		6,860
- Allowance for materials’ impairment	4,218	—		—		4,218

Total 2005	11,104	—		26	(1)	11,078

Total 2004 (Unaudited)	8,931	2,173		—		11,104

Total 2003 (Unaudited)	12,243	—		3,312		8,931

Included in liabilities:

- Noncurrent – Reserve for contingencies	10,429	2,878		1,655		11,652

Total 2005	10,429	2,878	(2)	1,655	(3)	11,652

Total 2004 (Unaudited)	13,072	9,625		12,268		10,429

Total 2003 (Unaudited)	5,557	7,796		281		13,072

(1)	Used over the year.

(2)	Charge for the year allocated to “Other income, net” account in the statement of income.

(3)	Used over the year.

F-122