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

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 S.S. Floor
(C1084ABA) Buenos Aires
Argentina
(Address of principal executive offices)

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

		Name of Each Exchange
Title of each Class		On Which Registered
American Depositary Shares, each representing 10 Class B		New York Stock Exchange
shares

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, 2007 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 þ     No o

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 o     No þ

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 þ     No o

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:

U.S. GAAP o     IFRS o     Other þ

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 þ     Accelerated filer o      Non-accelerated filer  o

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

Item 17 o      Item 18 þ

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 o     No þ

 

 

TABLE OF CONTENTS

Items 1-2. Not Applicable			2
Item 3. Key Information			2
Selected Financial Data			2
Exchange Rates			6
Risk Factors			7
Item 4. Information on the Company			18
Our History and Development			18
Business Overview			19
Oil and Gas Exploration and Production			22
Refining And Distribution			40
Petrochemicals			45
Gas and Energy			48
Insurance			57
Patents and Trademarks			57
Quality, Safety, Environment and Health			58
Regulation of our Business			61
Organization Structure			84
Property, Plant and Equipment			86
Item 4A. Unresolved Staff Comments			86
Item 5. Operating and Financial Review and Prospects			87
Overview			88
Factors Affecting our Consolidated Results of Operations			89
Discussion of Results			101
Analysis of Operating Results By Business Segment			106
Analysis of Equity in Earnings of Affiliates			113
Analysis of Operating Results by Business Segment			116
Analysis of Equity in Earnings of Affiliates			123
Critical Accounting Policies			125
Liquidity and Capital Resources			128
Description of Indebtedness			132
Future Capital Requirements			133
Off-Balance Sheet Transactions			135
Contractual Obligations			135
U.S. GAAP Reconciliation			137
Reconciliation Tables			138
Item 6. Directors, Senior Management And Employees			140
Directors and Senior Management			140
Compensation			146
Board Practices			147
Employees			150
Share Ownership			151
Item 7. Major Shareholders and Related Party Transactions			151
Major Shareholders			151
Related Party Transactions			151
Item 8. Financial Information			153
Consolidated Financial Statements			153
Legal Proceedings			153
Dividends			154
Item 9. Offer and Listing			154
Offer and Listing Details			154
Markets			155

Item 10. Additional Information			156
Memorandum and Articles of Association			156
Comparison of New York Stock Exchange Corporate Governance Standards			161
Material Contracts			161
Taxation			162
Documents On Display			166
Item 11. Quantitative and Qualitative Disclosures About Market Risk			166
Items 12-14. Not Applicable			168
Item 15. Controls and Procedures			168
Item 16A. Audit Committee Financial Expert			169
Item 16B. Code of Ethics			169
Item 16C. Principal Accountant Fees and Services			169
Item 16D. Not Applicable			170
Item 16E. Purchase of Equity Securities By the Issuer and Affiliated Purchasers			170
Item 17. Not Applicable			170
Item 18. Financial Statements			170
Item 19. Exhibits			171
Exhibit 4.2
Exhibit 4.4
Exhibit 4.5
Exhibit 4.6
Exhibit 4.7
Exhibit 8.1
Exhibit 12.1
Exhibit 12.2
Exhibit 13.1
Exhibit 13.2

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 on 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,” “US$” or “U.S.$” 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.

PART I

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) (“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.

This annual report also includes financial statements of Refinería del Norte, S.A. (“Refinor”) and Petroritupano, S.A. The financial statements of Refinor have been prepared in accordance with Argentine GAAP and presented in Argentine pesos, and the financial statements of Petroritupano, S.A. have been prepared in accordance with International Financial Reporting Standards (“IFRS”) and presented in US dollars.

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 (“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.

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 on or after January 1, 2006. In addition, it contemplates transition standards that defer the mandatory effectiveness of certain changes until fiscal years beginning on or after January 1, 2008. Through General Resolution Nos. 485 and 487, dated December 29, 2005, and January 26, 2006, respectively, the CNV approved the aforementioned changes.

Figures for the years 2005 and 2004 have been restated to give effect to the aforementioned changes in the professional accounting standards.

The effects of these changes on our income statement and shareholders’ equity as of December 31, 2005 and 2004 are described below:

		Gain (loss)								Increase (decrease)
										Shareholders’ equity as of
		Income for								December 31,
		2005				2004				2005				2004
		(in millions of pesos)
Comparison with recoverable values (i)			(120	)			10				(190	)			(70	)
Deferred tax (ii)			272				118				(1,060	)			(1,332	)
Minority interest			(36	)			(31	)			303				339
Total effect on unappropriated retained earnings											(947	)			(1,063	)
Deferred loss (iii)											(22	)			(49	)
Total effect on Shareholders’ equity			116				97				(969	)			(1,112	)

U.S. GAAP Information

Neither the effects of inflation accounting nor the proportional consolidation of Distrilec or PVIE (only for the year ended December 31, 2007), jointly controlled companies, under Argentine GAAP have been reversed in the reconciliation to U.S. GAAP.

The proportional consolidation of Compañía de Inversiones de Energía S.A. (“CIESA”), another company under joint control, in 2007, 2006, 2005 and 2004 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 each of those four years 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.

Selected financial data for the year ended December 31, 2003 is not presented because we were not able to restate it to reflect the abovementioned changes in professional accounting standards without unreasonable effort or expense.

The following tables set forth selected financial data including data for joint control companies consolidated under the proportional consolidation method, as of and for the years ended December 31, 2007, 2006, 2005 and 2004:

Income Statement Data

		Year Ended December 31,
		2007				2006				2005				2004
		(in millions of pesos, except for per share amounts
		and share capital or as otherwise indicated)
Argentine GAAP:
Net sales			13,458				11,745				10,655				8,763
Cost of sales			(10,132	)			(8,068	)			(6,851	)			(5,661	)
Gross profit			3,326				3,677				3,804				3,102
Administrative and selling expenses			(1,444	)			(1,277	)			(1,136	)			(967	)
Exploration expenses			(172	)			(117	)			(34	)			(133	)
Other operating expense, net			(177	)			(135	)			(329	)			(324	)
Operating income			1,533				2,148				2,305				1,678
Equity in earnings of affiliates			176				219				281				102
Financial income (expenses) and holding gains (losses)			(495	)			(506	)			(899	)			(1,265	)
Other income (expenses), net			130				93				(459	)			(40	)
Income before income tax and minority interest in subsidiaries			1,344				1,954				1,228				475
Income tax			(494	)			(465	)			(211	)			317
Minority interest in subsidiaries			(277	)			(425	)			(288	)			(17	)
Net income			573				1,064				729				775
Basic/diluted Earning per share			0.270				0.501				0.343				0.365
Number of shares outstanding (in millions):
Class B			2,132				2,132				2,132				2,132
U.S. GAAP:
Net sales			12,712				11,085				10,129				8,232
Operating income			678				1,934				613				1,348
Net (loss) income			(23	)			972				(77	)			760
Basic/diluted net (loss) income per share			(0.011	)			0.458				(0.036	)			0.356

Balance Sheet Data

		Year Ended December 31,
		2007				2006				2005				2004
		(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			98				86				104				139
Investments			1,094				1,479				857				934
Trade receivables			1,605				1,438				1,626				1,181
Other receivables			2,473				1,182				627				756
Inventories			1,182				888				782				627
Other assets			—				1				—				1
Total current assets			6,452				5,074				3,996				3,638
Non-current assets
Trade receivables			228				124				78				47
Other receivables			657				691				672				943
Inventories			100				81				79				71
Investments			3,270				3,630				1,072				1,107
Property, plant and equipment			10,609				10,838				12,657				12,277
Other assets			41				41				47				65
Total non-current assets			14,905				15,405				14,605				14,510
Total assets			21,357				20,479				18,601				18,148
Liabilities
Current liabilities
Accounts payable			1,867				1,603				1,483				1,181
Short-term debt			1,922				2,646				1,805				1,709
Payroll and social security taxes			261				276				177				98
Taxes payable			242				331				228				215
Reserves			124				95				48				31
Other current liabilities			305				214				198				657
Total current liabilities			4,721				5,165				3,939				3,891
Non-current liabilities
Accounts payable			78				49				14				26
Long-term debt			5,430				4,716				5,708				6,248
Other liabilities			367				402				356				190
Taxes payable			1,428				1,492				1,404				1,692
Reserves			86				85				103				76
Total non-current liabilities			7,389				6,744				7,585				8,232
Total liabilities			12,110				11,909				11,524				12,123
Minority interest in subsidiaries			2,583				2,350				1,922				1,626
Total Shareholders’ Equity			6,664				6,220				5,155				4,399
Total liabilities and shareholders’ equity			21,357				20,479				18,601				18,148
Capital Stock			2,132				2,132				2,132				2,132
U.S. GAAP:
Total assets			19,316				18,017				16,158				16,751
Shareholders’ equity			6,874				6,195				5,233				5,286

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 the annual high, low, average and period-end exchange rates for the periods indicated, expressed in Argentine pesos per U.S. dollar and not adjusted for inflation. There can be no assurance that the Argentine peso will not depreciate or appreciate again in the future. The Federal Reserve Bank of New York does not report a noon buying rate for pesos.

		Argentine peso per U.S. dollar
		High				Low				Average				Period-end
2008
May			3.18				3.12				3.15				3.11
April			3.18				3.15				3.17				3.17
March			3.17				3.15				3.16				3.16
February			3.17				3.15				3.16				3.16
January			3.16				3.13				3.15				3.16
For the year ended December 31,
2007			3.16				3.08				3.12				3.15
2006			3.08				3.05				3.06				3.07
2005			3.03				2.86				2.92				3.03
2004			2.99				2.94				2.97				2.98
2003			3.37				2.73				2.95				2.94
2002			3.90				1.60				3.14				3.38
2001			1.00				1.00				1.00				1.00

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 such 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, among others, 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, 2007, approximately 72% of our total assets, 75% of our net sales, 65% of our combined crude oil and gas production and 56% of our proved oil and gas reserves were located in Argentina. Fluctuations in the Argentine economy and actions adopted by the Argentine government have had and may continue to have a significant impact on Argentine companies, including us. Specifically, we have been affected and may continue to be affected by inflation, interest rates, the value of the peso against foreign currencies, price controls, regulatory policies, business and tax regulations and in general by the political, social and economic scenario in Argentina and in other countries that may affect Argentina.

The Argentine economy has experienced significant volatility in recent decades, characterized by periods of low or negative growth, 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 “Business Overview—Our Principal Market”.

The crisis had significant and adverse consequences on our company, including (i) losses derived from the effects of the peso devaluation on our affiliates and our affiliates’ net borrowing position, which primarily was denominated in U.S. dollars, (ii) the impairment of the book value of certain gas areas and tax assets due to material changes in the prospects of our operations, (iii) a decrease in U.S. dollar cash flows due to the imposition of export taxes, (iv) limits on the availability in the financial market to renew our short-term lines of credit and the current portion of our medium and long-term financings at maturity and (v) 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 significant net loss and our liquidity resulted adversely affected. Within this context and in order to secure compliance with our financial commitments, we reduced our investment plan and reached an agreement with our financial creditors and holders of notes to extend the maturity profile of a substantial portion of our debt, at face value. 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 Argentine economy has largely recovered from the crisis of 2001 and 2002, uncertainty remains as to whether current growth and relative stability are sustainable. Sustainable economic growth depends 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 recent years, 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.

We cannot provide you with any assurance that future economic, social and political developments in Argentina, over which we have no control, will not adversely affect our financial condition or results of operations, including our ability to pay our debts at maturity or dividends.

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

Since the default on the Argentine sovereign debt at the end of 2001, Argentine companies have had fewer opportunities to access the international credit market. In spite of the renegotiation of a significant portion of the Argentine sovereign debt and the improvement in the financing capacity of Argentine companies, the prospects for all Argentine companies, including us, of accessing financial markets could be limited in terms of amounts, terms and financial costs. If we are unable to gain 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, our financial condition and the results 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 of Argentina (“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 and had a negative impact on businesses whose success depends on domestic market demand, including public utilities.

The significant peso devaluation during 2002 adversely affected our results of operations and financial condition. 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 and Foreign Exchange System Reform Law No. 25,562 (the “Public Emergency Law”) in January 2002, 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 and restrictions on exports), however, limited our ability to hedge 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 since it 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 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 operations.

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

In the past, inflation has 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%.

This inflation reflected both the effect of the peso devaluation on production costs and a significant change in relative prices, which was partially offset by the elimination of rate adjustments and a strong drop in demand as a result of the recession. According to official inflation data published by the National Statistics Institute, in 2003, inflation slowed, with a 3.7% increase in the consumer price index and a 2.0% increase in the wholesale price index. Since 2004, both indexes have shown trends characteristic of an inflationary economy. The consumer price index increased 6.1% in 2004, 12.3% in 2005, 9.8% in 2006 and 8.5% in 2007 and the wholesale price index rose 7.9% in 2004, 10.6 % in 2005, 7.1% in 2006 and 14.4% in 2007.

Uncertainty surrounding future inflation may result in slowed economic activity and reduced growth. A return to a high inflation environment would also undermine Argentina’s foreign competitiveness by diluting the effects of the peso devaluation, with negative effects on the level of economic activity and employment. Sustained inflation in Argentina, without a corresponding increase in the price paid by consumers for our products in the local market, would have a negative effect on our results of operations and financial condition. 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 that may impair our ability to service our foreign currency-denominated debt obligations and 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, the obligation to deposit with the Argentine Central Bank foreign currency from exports, restrictions on the transfers of funds abroad as well as 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 to further tighten restrictions on the transfer of funds, we may be unable to make principal or interest payments on our debt when they become due or to pay dividends.

On June 9, 2005, the Federal Executive Branch issued Executive Order No. 616/05, requiring that any repayment obligation related to proceeds derived from foreign loans to private Argentine entities must have a maturity of at least 365 days from the date of receipt of such proceeds. In addition, 30% of the amount of the relevant proceeds must be deposited with Argentine financial institutions. Such deposit must (i) be registered, (ii) be non-transferable, (iii) be non-interest bearing, (iv) be made in U.S. dollars, (v) have a term of 365 days and (vi) not 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 capacity to finance our operations through new intercompany loans or other kinds of foreign financial loans.

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, which has inhibited our ability to profit from higher prices for these commodities on the international market, hindered us from offsetting sustained increases in costs endemic to the energy industry, and materially affected our competitiveness and results of operations.

On May 23, 2002, the Argentine government enacted Executive Order 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 volumes of crude oil and liquefied petroleum gas (“LPG”) produced in Argentina that should be used to supply the domestic market and be sold in the local market.

In April 2004, in order to facilitate the recovery of natural 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. In 2007, upon the expiration of the aforementioned agreement, the Argentine government and producers signed a new agreement effective until 2011 aimed at securing the domestic supply of gas.

Under these resolutions and agreements, temporary limits on certain natural gas exports have been imposed to avoid a crisis in the local supply of natural gas, depriving us of the higher margins offered by export prices.

During 2005 and 2006, the Secretary of Energy requested producers to redirect gas for export to supply thermal plants and gas distribution companies. This decision limited our total gas export volumes by a daily average of approximately 110 thousand cubic meters and 339 thousand cubic meters, respectively. In 2007, our total gas export volume was limited by a daily average of about 420 thousand cubic meters.

Pursuant to Resolution No. 1679/04, enacted in December 2004, producers must obtain the approval of the Argentine government prior to exporting crude oil or diesel oil. 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 under 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 offered to their own gas station network. Furthermore, in December 2006, pursuant to Resolution No. 1338/06, the Secretary of Energy extended these regulations to the export of gasoline, fuel oil and fuel oil mixtures, diesel oil, aero kerosene, jet fuel, lubricants, asphalts, coke and by-products for use in the petrochemical industry. See “Business Overview—Regulation of Our Businesses—Argentine Regulatory Framework—Petroleum—Refining”.

In response to an increase in fuel prices in the domestic market, in January 2008 the Argentine government temporarily prohibited the exports of gasoline and diesel oil until the domestic market was fully supplied at the prices in force on October 31, 2007.

In the future, the extension of these restrictions could significantly and adversely affect the profitability of our operations, preventing us from capturing the upside of export prices, and negatively impacting the total volume of refined products sold in the domestic market, due to our need to manage crude oil volumes processed in accordance with our storage capacity.

We cannot assure you that the Argentine government will not increase export restrictions on hydrocarbons and related oil products. If it were to do so, our financial condition and 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.

In order to discourage exports, secure domestic supply and fix a reference price for crude between producers and refineries, on March 1, 2002, the Argentine government imposed a withholding tax on exports of hydrocarbons, initially lasting five years. The term of this withholding regime was subsequently extended for five years from January 2007, pursuant to Law No. 26,217. At its inception, this regime imposed a 20% tax on exports of crude oil and LPG and a 5% tax on exports of certain oil related products. In May 2004, taxes on exports of crude oil and LPG were increased to 25% and 20%, respectively, and a 20% tax was levied on exports of natural gas.

From August 2004 through November 2007, a graduated withholding regime was applied to crude oil exports, starting at 25% when the price per barrel was equal to or lower than US$32 and with additional, incremental rates ranging between 3% and 20% when the price per barrel of crude oil ranged between US$32.01 and US$45, with a cap set at 45% when the price exceeded US$45. In 2006, under Resolution 534/2006 issued by the Secretary of Energy, the Argentine government increased taxes on natural gas exports to 45% of the price of gas imported from Bolivia.

Effective November 2007, Resolution No. 394/07 issued by the Ministry of Economy and Production (“Resolution No. 394/07”) provided for a new calculating method for withholdings on exports of crude oil and certain oil by-products. Under this new method, when the international price for crude oil exceeds US$60.90 per barrel, an incremental withholding rate is set on crude oil exports, capping the price the producer receives at US$42 per barrel. When the international price for crude oil ranges between US$45 and US$60.90 per barrel, a 45% withholding tax is applied. If the international price for crude oil decreases below US$45 per barrel, the authorities will set new rates within 90 days. A similar withholding regime applies to exports of oil by-products such as gasoline, fuel oil and lube oils, with different cut-off and reference prices. This new tax regime has had a negative impact on our Refining and Distribution business unit, particularly on exports of paraffins, other heavy products and gasoline.

In April 2008, the Ministry of Economy and Production issued Resolution No.127/08, amending Resolution No. 534/2006, and imposing a 100% withholding tax on natural gas exports, based upon the highest price set for natural gas under any applicable agreement for natural gas imports into Argentina. Under this resolution, taxes on natural gas exports are set equivalent to the cost of natural gas imported into Argentina. We are negotiating new contractual terms with our foreign customers to reflect the economic effect of these increased withholdings.

This tax framework prevented us from benefiting from significant recent increases in international prices for oil, oil related products and natural gas, hindered us from offsetting sustained increases in costs endemic to the energy industry, and materially affected our competitiveness and results of operations.

We cannot assure you that the Argentine government will reduce 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.

The Argentine government has imposed a series of regulations on the energy sector to limit the prices charged of end users in an effort to reduce the inflationary impact of high international commodity prices and to guarantee domestic supply. These regulations have had a material adverse impact on our results of operations. See “Regulation of our Businesses”.

a) Natural Gas and electricity

Pursuant to the Public Emergency Law, we were precluded from increasing the price of 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 and other gas producers, entered into an agreement with the Argentine government that provided for a schedule of gradual increases in gas prices in the domestic market that would culminate in a complete deregulation of the wellhead price of natural gas in 2007. Since September 1, 2005, wellhead prices have been deregulated for sales to electricity generation and gas distribution companies supplying industrial clients directly, with the Gas Electronic Market (Mercado Electrónico del Gas) starting operations for gas surplus spot transactions. This agreement provides for minimum supply requirements that gas producers must supply to the domestic market. In 2007, upon expiration of the aforementioned agreement, the Argentine government and producers signed a New Natural Gas Producers Agreement.

This new agreement modified the prescribed extent of the total deregulation of wellhead prices of gas, adopting a schedule of defined prices, whereby the 2005 price remains unchanged for the residential sector and an annual average increase of approximately 6.5% is established for the Compressed Natural Gas (“CNG”), electricity generation, and industrial sectors, although the price for the latter remains freely negotiable. This new resolution has already come into effect by sector according to schedule; the residential supply commitment is the last one to expire in the year 2011.

With respect to electricity generation, with the enactment of the Public Emergency Law, the Argentine government implemented the pesification of dollar-denominated prices in the Wholesale Electricity Market (“WEM”), and set a price cap on gas supplied for electric power generation. This regulatory change imposed a deviation from the marginal cost system previously in force, and forced generators to set prices based on the price of natural gas, regardless of the fuel actually used in generation activities. In December 2004, the Secretary of Energy agreed to approve successive seasonal electricity price increases to rates that would at least cover total monomic costs by November 2006 (to include compensation for actual output at spot market rates, or energy, plus compensation for capacity placed at the disposal of the spot market, or power capacity). However, these assurances were never carried out.

In addition, the Secretary of Energy committed to pay for energy at the marginal price obtained in the spot market and to pay for power capacity at the U.S. dollar values that were in effect prior to the enactment of the Public Emergency Law, once the new generation capacity is brought into the system under the FONINVEMEM plan. See “Item 5. Operating and Financial Review and Prospects—Analysis of Consolidated Results of Operations—Factors Affecting our Consolidated Results of Operations—Regulation of the Energy Industry in Argentina—Price Controls and Restrictions on Exports—Electricity Generation”.

Through these combined measures, the Argentine government is expected to gradually restore economic and financial balance to the natural gas and electricity sectors. Our results and capital expenditure plans, however, may be adversely affected if (i) the agreed schedule of increases in natural gas prices or the commitments with respect to electricity price increases fail to be fully implemented by the Argentine government or (ii) the government applies its regulatory emergency authority or adopts other regulations to control prices or supply.

b) 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 have had and may continue to have an adverse effect on the results of our operations. Downstream margins in Argentina have significantly declined since the enactment of the Public Emergency Law. Since 2002, the Argentine government has actively intervened in the domestic fuel market to ensure full supply and to limit increases in the price of gasoline and diesel oil at the retail level that would have resulted from: (i) higher costs due to increases in crude oil international prices (ii) the peso devaluation and (iii) domestic inflation. During 2007, there was some flexibility in allowing a gradual increase in fuel prices in the domestic market, which enabled a partial recovery in margins. However, the Argentine government, through measures adopted in late 2007 and early 2008, significantly limited this trend.

In 2007, the fuel market in Argentina grew for the fifth year in a row. To secure domestic supply, in 2006 the Secretary of Domestic Trade promulgated Resolution No. 25/2006, which required refining companies to supply all diesel oil market demand with a baseline equal to the same month of the prior year’s demand, plus an estimated market variation. In order to comply with this resolution, we were required to import 208 thousand cubic meters of diesel oil in 2007, and 85 thousand cubic meters of diesel oil in 2006. Considering the differential between import and retail diesel oil prices, we recognized losses of P$106 million and P$38 million in 2007 and 2006, respectively. In the future, subject to the production capacity of our plants and the real market growth levels, we may be required to continue importing diesel oil pursuant to Resolution No. 25/2006, with a consequent adverse effect upon our results of operations.

We cannot assure you that the Argentine government will not make further regulatory changes that adversely affect our refining margins. See “Factors Affecting Our Consolidated Results of Operations—Regulation of the Energy Industry in Argentina—Price Controls and Restrictions on Exports—Downstream Margins”.

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 condition of utility companies in Argentina. The combined effect of (i) the peso devaluation, (ii) the pesification of rates on a one-to-one basis and (iii) financial debts primarily denominated in foreign currency, adversely affected the utility companies’ financial condition, 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 provisional rate adjustments) is currently in the process of renegotiating contracts with our affiliates Edesur S.A. (“Edesur”) and TGS. These discussions are in different stages, and in some cases UNIREN’s latest proposals were not sufficient to return the regulated business to financial stability and profitability in the near future or on a long-term basis.

See “Business Overview—Gas and Energy—Gas Transportation—TGS—Regulated Energy Segment” and “Regulation of Our Businesses—Argentine Regulatory Framework—Natural Gas”.

We cannot assure you that these discussions will ultimately result in a level of tariff increases sufficient for our affiliated utility companies to return their regulated business to financial stability and profitability in the near future or on a long-term basis.

Factors Relating to the Company

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

A significant amount of our revenue is derived from sales of crude oil and related oil products. We do not and will not have control over factors affecting international prices for crude oil and related oil 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 generally result in changes in prices for related oil products. International oil prices have fluctuated widely over the last ten years. In 2007, oil prices reached a high for the sixth year in a row. The West Texas Intermediate crude reference price (“WTI”) averaged US$72.3 per barrel that year, 9% higher than the average price in 2006 of $66 per barrel. During 2005 and 2004 the average WTI was US$56.6 and US$41.5 per barrel, respectively, compared to an average of US$22.6 per barrel for the 1994-2003 period.

Substantial or extended declines in international prices for crude oil and related oil products 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 prices for crude oil and related oil products 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 account for 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 estimate date). Our proved crude oil and natural gas reserves are those that can be expected to be recovered through existing wells with existing equipment and operating methods.

DeGolyer and MacNaughton, international technical consultants, audited 71% of our total reserves as of December 31, 2007. See “Business Overview—Oil and Gas Exploration and Production—Reserves”.

Crude oil and natural gas reserves are reviewed annually taking into consideration many factors, including:

•   new production or drilling activities;

•   field reviews;

•   the addition of new reserves from discoveries or extensions of existing fields;

•   changes in the international prices of oil and gas;

•   the application of improved recovery techniques; and

•   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 could impact our future results of operations and business plan, including our level of capital expenditures.

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

In recent years, we have experienced a decline in reserves and production. The possibility of replacing our crude oil and gas reserves in the future is dependent on our ability to access new reserves, both through successful exploration and reserve acquisitions. We consider exploration, which carries inherent risks and uncertainties, our main vehicle for future growth and reserve replacement.

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. Without successful 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.

Further decline in reserves and production may limit the integration of our upstream and downstream operations, since maximizing the crude oil processing capacity of our refineries would require us to obtain a greater supply of our crude oil from third parties, including imports.

We cannot guarantee that our exploration, development and acquisition activities will result in significant additional reserves. If we are not able to successfully find, develop or acquire additional reserves, our reserves and therefore our production may continue to decline and, consequently, this may adversely affect our future results of operations and financial condition.

Our operations could be adversely affected by events beyond our control.

Our activities are subject to numerous risks, many of which are beyond our control. Our operations may be curtailed, delayed, interrupted or canceled as a result of weather conditions, mechanical difficulties, shortages or delays in the delivery of equipment, coercive actions and compliance with governmental requirements, events that could adversely impact our costs of production, results of operation and financial condition. For example, from March 9, 2007 to April 10, 2007, operations in Block 18, in Ecuador were curtailed as a result of coercive actions taken by local communities. During this period, cumulative oil production decreased by approximately 305,000 barrels of oil equivalent in our participation.

Our activities may be adversely affected by events in 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, many governments in Latin America have taken steps to assert greater control or increase their share of revenues from the energy sector, spurred by soaring oil and gas prices and nationalistic politics. See “Regulation of our Businesses—Regulatory Framework outside of Argentina—Petroleum and Gas”.

These steps have included:

Venezuela

In April 2005, the Venezuelan Energy and Oil Ministry instructed the Venezuelan national oil company, Petróleos de Venezuela S.A. (“PDVSA”), to review all operating agreements signed with oil companies between 1992 and 1997. The Ministry further instructed PDVSA to take all necessary action to convert those operating agreements into mixed-ownership companies whereby the Venezuelan government, through PDVSA, would be entitled to majority ownership.

In March 2006, we, through Petrobras Energía and its controlled and affiliated companies in Venezuela, signed memoranda of understanding (MOUs) with PDVSA and the Corporación Venezolana del Petróleo S.A. (“CVP”), respectively, in order to effect the migration of our four pre-existing operating agreements.

As a result, the direct and indirect interests of Petrobras Energía in the mixed companies that operate the areas of Oritupano Leona, La Concepción, Acema and Mata were reduced to 22%, 36%, 34.5% and 34.5%, respectively. The economic effect of the migration to mixed-ownership companies was effective as of April 1, 2006. Additionally, the MOUs provided that CVP would recognize a divisible and transferable credit in favor of Petrobras Energía in the amount of US$88.5 million, which would not accrue interest, but could be applied toward the acquisition of bonds for any new mixed-company project for oil exploration and production activities, or licenses for gas exploration and production operations in Venezuela. Once the milestones required for recognition of the credit by PDVSA were reached, as of December 31, 2006, we recorded the credit at its estimated recoverable value of P$180 million.

The conditions imposed under the new operating agreements had an adverse impact on the recoverable value of our assets in Venezuela. The recoverability of these investments is highly sensitive to crude oil price volatility, to economic, social and regulatory changes in Venezuela and, particularly, to the decisions made by management in the mixed-ownership companies. Decreases in crude oil prices, fluctuations in economic conditions, the adoption of more restrictive measures by the Venezuelan government, and decisions by mixed-ownership companies to limit the development of reserves could adversely affect the valuation of the recoverability of our investment in these companies and, consequently, our income. As a result of the aforementioned variables, in the years ended December 31, 2007, 2006 and 2005, we recorded writedowns of P$33 million, P$186 million and P$424 million, respectively, related to our assets in Venezuela. In addition, since (i) to date no projects for which the aforementioned credit is eligible for investment have materialized, (ii) our efforts to transfer the credit to third parties have been unsuccessful, and (iii) alternative uses of the credit cannot be anticipated, as of December 31, 2007 we wrote down the carrying value of the above mentioned credit to zero.

In April 2008, the government of Venezuela published the Law of Special Contribution to Extraordinary Prices at the International Hydrocarbons Market. This law imposes a windfall profits tax on exports of liquid hydrocarbons and related oil products when the average monthly price of Brent crude exceeds US$70.00 per barrel, with 50% of the Brent crude price in excess of US$70.00 payable to the Venezuelan government. Likewise, when the average monthly Brent crude price exceeds US$100.00 per barrel, 60% of the Brent crude price above US$100.00 is payable as tax. As of the date of this annual report, we are evaluating whether this law will have a differential impact on mixed-ownership companies. As a result, we have not incorporated this windfall profits tax into our estimates of the recoverability of our stake in the mixed-ownership companies.

Bolivia

In May 2006, the Bolivian government enacted Supreme Decree No. 28,701, which provided, among other things, for the nationalization of hydrocarbon resources in Bolivia. This decree mandated that as of May 1, 2006, oil companies had to deliver all property related to hydrocarbon production for sale to the national operator, Yacimientos Petrolíferos Fiscales Bolivianos (“YPFB”). In addition, this decree provided that the Bolivian state would recover full participation in the entire oil and gas production chain and to that end provided 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, including our affiliate Petrobras Bolivia Refinación S.A., in which we had a 49% interest, in partnership with Petrobras, which held a 51% interest.

Pursuant to the terms of the contract between Petrobras Energía and YPFB, we, through our branch in Bolivia, agreed to conduct, at our own expense and on our own account, exploration and production activities in the Colpa Caranda area on behalf of YPFB. In addition, in June 2007, we signed an agreement, through our subsidiary Petrobras Energía Internacional S.A., under which we sold our interest in Petrobras Bolivia Refinación S.A. to YPFB.

Ecuador

In April 2006, the Ecuadorian government approved the Law Amending the Hydrocarbon Law (“Law 42”), which assigned the Ecuadorian state a share of at least 50% of the revenues resulting from any increase in the average monthly sales price of Ecuadorian crude oil, based upon the average monthly sales price for such oil as of the execution date of the relevant agreements, stated in constant values as of the month of settlement. In October 2007, the Ecuadorian President issued an amendment to the regulations applying Law 42, further increasing the Ecuadorian government’s share of revenues from increases in the price of crude oil to 99%, reducing the oil companies’ share to 1%.

When the regulations issued pursuant to this amendment were published in July 2006, our subsidiary, EcuadorTLC, and the nationally owned operator, Petroecuador, adopted opposing interpretations of these regulations. Since the promulgation of these regulations, we, Petroecuador and various Ecuadorian government authorities have disagreed on the application of Law 42 to our operations and whether we are required to pay additional withholding taxes. EcuadorTLC paid under protest settlements made by Petroecuador under Law 42 from April 2006 to December 2007, deducting the amounts payable to the government due to price increases under the operating agreement for the Palo Field in Block 18. In January 2008, Petroecuador informed our subsidiary, EcuadorTLC, that under Law 42, EcuadorTLC owed Petroecuador a debt of US$66 million on production between April 2006 and December 2007, due to differing interpretations of withholdings.

In addition, on December 28, 2007, the Constitutional Assembly approved the Tax Equality Law, which became effective as from January 1, 2008. This law introduces a major tax reform and facilitates the creation of new taxes.

The combined effect of these regulatory changes—the scope of which for some has not yet been fully determined—has been a material modification of the conditions set forth at the time of execution of our participation agreements, adversely affecting the valuation of our ongoing projects in Ecuador, and negatively impacting our assessment of recoverability. Accordingly, as of December 31, 2007, we recorded an impairment allowance of P$759 million to write down the book value of our Ecuadorian assets to their probable recoverable value.

Since January 2008, EcuadorTLC has discontinued payments under Law 42. According to its legal counsel, EcuadorTLC S.A. has legal grounds to consider Law 42 inapplicable. EcuadorTLC considers Law 42 to be a confiscatory measure that puts at risk the economic feasibility of its investment, equivalent to an expropriation of its interests. For the January to March 2008 period, settlements made by Petroecuador under Law 42 totaled US$71 million.

In order to protect EcuadorTLC S.A.’s position, a notice was served on Ecuador’s Attorney General under the terms of the Treaty for the Reciprocal Protection of Investments signed by Ecuador and Argentina, which authorizes, once the term for negotiation between the parties has elapsed, the settlement of disputes through mandatory arbitration.

On March 30, 2008, Petroecuador notified EcuadorTLC that Ecuador’s Attorney General submitted a request for termination of the participation agreement relating to Block 18, based, among others arguments, on alleged irregularities in the process involving assignment to Teikoku Oil Ecuador S.A. of its 40% interest in Block 18.

On April 10, 2008 EcuadorTLC filed an answer invoking its rights, and included with its answer all documentary evidence that it believes necessary to prove that there are no grounds for terminating the Block 18 participation agreement, since the assignment had been approved by the respective administrative authorities and a Ministerial Accord had been issued authorizing the assignment and obliging Petroecuador to amend the participation agreement and grant the pertinent deeds. In addition, the explanations necessary to dismiss the other grounds invoked were given.

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

We employ a largely unionized labor force and could be subject to an organized labor action.

As of December 31, 2007, approximately 41% of our workforce consisted of union members. We have been affected by organized labor actions in the past, and could be in the future.

During 2007 unionized employees went on strike over salary increases, adversely affecting our operations. We and the unions representing these workers were successfully able to negotiate an agreement on basic salary changes and other conditions.

Despite the collective bargaining agreements that are in place, we cannot predict what actions our labor force or their unions might take in the future. Strikes, picketing or other types of conflict with the unions or unionized personnel could curtail our operations and cause higher labor costs, having an adverse effect on our results in the long-term.

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 condition. We have not incurred any material pollution liabilities as a result of operations to date. We cannot assure you that we will not incur additional costs related to the environment in the future, which could negatively impact our results of operations.

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 towards more stringent enforcement of 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 condition and results of operations.

Item 4. INFORMATION ON 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 businesses. 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, 22nd 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 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. (“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. (“Eg3”), Petrobras Argentina S.A. (“PAR”) and Petrolera Santa Fe SRL (“PSF”) approved the merger of Eg3, PAR and PSF into Petrobras Energía effective January 1, 2005. Pursuant to the merger, PPSL was incorporated as a new shareholder of Petrobras Energía S.A. with a 22.8% equity interest, and thus our interest in Petrobras Energía decreased to 75.82% from 98.21%. Considering its 58.62% interest in Petrobras Energía Participaciones S.A., Petrobras has an indirect interest in Petrobras Energía of 67.2%.

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, Petrobras Energía has become a vertically integrated energy company.

Capital Expenditures and Divestitures

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

BUSINESS OVERVIEW

Our Strategy

Our long-term strategy is to grow as an integrated energy company with a regional presence, while being a leader in profitability as well as social and environmental responsibility.

The main points of this strategy are:

	•		Increasing oil and gas reserves and production, to secure sustainable growth.
	•		Seeking profitability in downstream business in Argentina, through a balanced crude production – refining – logistics – distribution chain.
	•		Generating energy solutions through the development of businesses in the gas and energy areas that will allow for capitalizing on the synergies with the natural gas reserves of the Petrobras group.
	•		Consolidating our leading position in the South American styrenics markets.
	•		Maintaining our financial solvency, while pursuing operating and management efficiency and the development of human resources.

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

	•		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.
	•		Adoption of, and compliance with, corporate governance practices in line with recognized best practices.
	•		Maintenance of a management style that favors communication and teamwork, fostered by the value of the people that work in our organization.
	•		Developing new business opportunities in order to maximize potential synergies and capitalize on complementary business opportunities with Petrobras.

We currently manage our activities, with the support of a corporate center, in four business segments: (1) Oil and Gas Exploration and Production, (2) Gas and Energy, (3) Refining and Distribution, and (4) Petrochemicals.

Our Principal Market

We are an Argentine corporation and, as of December 31, 2007, 72% of our total assets, 75% of our net sales, 65% of our combined oil and gas production and 56% of our proved oil and gas reserves were located in Argentina. Fluctuations in the Argentine economy and actions adopted by the Argentine government have had and may continue to have a significant effect on Argentine private sector entities, including us. Specifically, we have been affected and may be affected by inflation, interest rates, the value of the peso against foreign currencies, price and export controls on oil and oil by-products, business regulations, tax regulations and in general by the political, social and economic environment affecting Argentina and other countries. See “Risk Factors – Factors Relating to Argentina”.

Historically, the Argentine economy was characterized by its macroeconomic instability and 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. 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 implemented various plans and utilized a number of exchange rate systems and controls.

In the 1990s deep and drastic economic reforms were implemented in terms of State reform, privatization of public companies and utilities and opening of the economy. The pillar of the economic reform was the Convertibility Law enacted in 1991. 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. In the 1991–1997 period, the economy experienced growth, with exchange stability and low inflation rates.

Partly due to the crisis of the convertibility model, as from 1998 the Argentine economy entered into a recession, with a peak in December 2001 that resulted in a massive withdrawal of deposits and capital outflow. In this situation, and with a fall in GDP of approximately 10%, the Argentine government implemented a number of monetary and exchange control measures which proved to be insufficient and caused a sharp rise in social discontent. This triggered a political, social and economic crisis, ultimately resulting in the resignation of the then President De la Rúa.

After a series of interim presidents, on January 1, 2002 Eduardo Duhalde was appointed President and, among other measures, ratified the suspension of the payment of a portion of Argentina’s sovereign debt previously declared by Interim President Rodríguez Saá. In January 2002, the Argentine Congress enacted the Public Emergency Law, whereby monetary, financial and exchange measures were implemented to overcome the economic crisis in the short term. These events resulted in dramatic changes in the economic model and put an end to the US dollar-peso parity, leading to a significant devaluation of the Argentine peso.

The Federal Executive Branch implemented a number of far-reaching initiatives, which included:

	•		Pesification of certain assets and liabilities denominated in foreign currency and held in the country;
	•		Amendment of the charter of the Central Bank authorizing it to issue money in excess of the foreign currency reserves, grant short-term loans to the federal government and provide financial assistance to financial institutions with liquidity or solvency problems;
	•		Pesification and elimination of indexing clauses on utility rates, fixing those rates in pesos at the P$1=US$1 exchange rate; and
	•		Implementation of taxes on hydrocarbon exports and certain related oil products, among others.

In 2002, with an active intervention by the government in the development of the economy, as a consequence of the significant political and economic changes that resulted from the severe crisis at the end of 2001, commercial and financial activities were virtually paralyzed, further aggravating the economic recession which included a 10.9% decline in the GDP. Within this context, the peso devalued 238% against the dollar and wholesale inflation grew 118.2%. 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 the 2003-2007 period, GDP grew at an annual rate of over 8%, especially in terms of investments, consumption and imports, with significant improvements in employment indicators, which caused the unemployment rate to drop below 10% in 2007. During this period the use of installed capacity by industrial sectors gradually increased, and in 2007 several sectors operated at their maximum production capacity.

In 2003 and 2004, official inflation remained at levels below 8% per annum, but since 2005, the increase in consumption, boosted by a sizeable increase in credit and the recovery of wages, has resulted in increased inflationary pressures.

In 2005, the administration was able to restructure 76% of the government debt in default, with a significant nominal reduction in principal, an extension in repayment terms and a reduction in interest coupons. At the beginning of 2006, the Argentine Government made an advance payment of approximately US$10 billion in debt to the IMF with freely available reserves.

In the 2003-2007 period, there was excess supply of foreign currency as a result of the large surplus in the balance of trade, with record exports boosted by the rise in the price of commodities, and with significant capital flows favored by high liquidity worldwide. With a view to maintaining a competitive rate of exchange, the Central Bank bought foreign currency in the market and avoided a nominal appreciation of the peso. This favored the accumulation of international reserves to US$46 billion by December 2007. These factors, together with a favorable international climate, helped to reduce the country risk to approximately 400 basis points by the end of December 2007.

During the first quarter of 2008, the growth rate of the Argentine economy remained high (8.8%, year on year). Exports grew approximately 40%, driven by high international prices for commodities while imports increased in a similar proportion, though due to higher volumes. As a result, the trade balance surplus rose 50% in the first quarter of 2008 compared to the same quarter of previous year, supporting the surplus foreign currency supply. The official inflation data published by the National Statistics Institute (“INDEC”) showed a 2.5% slight increase in retail prices accumulated during the first quarter 2008 (below 9% year on year), though alternative measurements account for significantly higher increases.

OIL AND GAS EXPLORATION AND PRODUCTION

Overview

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

	•		increasing oil and gas production and reserves by capitalizing on our experience and presence in nearly all Latin American oil producing countries;
	•		optimizing our investment portfolio by balancing exploration projects with development projects; and
	•		performing efficient operations under high safety and environmental care standards.

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

As of December 31, 2007, our combined crude oil and natural gas proved reserves, including our share of the reserves of our unconsolidated investees, were estimated at 482.7 million barrels of oil equivalent, approximately 55.4% of which were proved developed reserves and approximately 44.6% of which were proved undeveloped reserves. Crude oil accounted for approximately 54.9% of our combined proved reserves, while natural gas accounted for about 45.1%. As of December 31, 2007, 55.5% of our total combined proved reserves were located in Argentina and 44.5% were located abroad.

During 2007, combined crude oil and natural gas production, including our share in the production of our unconsolidated investees, averaged 138.6 thousand barrels of oil equivalent per day. Crude oil accounted for approximately 85.6 thousand barrels per day, while natural gas accounted for approximately 318.02 million cubic feet per day. Approximately 54.5% of our oil production and 82.2% of our gas production is derived from our operations in Argentina.

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 (“Genelba”), allows us to use approximately 99 million cubic feet of natural gas per day of our own reserves. In addition, we supply gas to our Petrochemical and Refining 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 indirect administrative expenses on a monthly basis by their partners in proportion to their participation in the relevant field.

As of December 31, 2007, we had interests in forty-six blocks: twenty-seven oil and gas production blocks (eighteen in Argentina and nine outside of Argentina) and nineteen exploration blocks located within exploration areas or pending authorization for production (fourteen in Argentina and five outside of Argentina). We are directly or indirectly the contractual operator of twenty-eight of the forty-six blocks in which we have an interest.

As of December 31, 2007, our total gross and net productive wells were as follows:

		Oil				Gas				Total
Gross productive wells (1)			5,836				349				6,185
Net productive wells (2)			3,028				237				3,265

As of December 31, 2007, our total producing and exploration acreage, both gross and net, was as follows:

		Average
		Producing(1)								Exploration(2)
		Gross				Net(3)				Gross				Net(3)
		(in thousands of acres)
Argentina (6)			4,922				3,201				18,129	(4)			6,514	(5)
Peru			116				70				11,548				5,438
Venezuela			485				125				—				—
Ecuador			62				54				714				637
Bolivia			56				56				—				—
Colombia			81				24				—				—
Total			5,722				3,530				30,391				12,589

The following table sets forth the number of total wells we drilled in Argentina and outside of Argentina and the results for the relevant periods. 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 our fractional ownership working interest in wells drilled. This table includes wells drilled by our consolidated subsidiaries, companies under joint control and unconsolidated investees.

		Year ended December 31,
		2007								2006								2005
						Outside of								Outside of								Outside of
		Argentina				Argentina				Argentina				Argentina				Argentina				Argentina
Gross wells drilled:
Production:
Productive wells:
Oil			184				132				218				60				256				85
Gas			13				6				3				2				7				2
Dry wells			2				—				3				—				2				—
Total			199				138				224				62				265				87
Exploration:
Discovery wells:
Oil			5				—				5				—				11				—
Gas			1				1				6				—				—				—
Dry wells			3				—				4				1				—				—
Total			9				1				15				1				11				—
Net wells drilled:
Production:
Productive wells:
Oil			79.0				115.6				100.4				57.4				110.7				75.2
Gas			5.2				5.4				0.6				1.0				2.9				1.0
Dry wells			0.9				—				0.6				—				1.7				—
Total			85.1				121				101.6				58.4				115.3				76.2
Exploration:
Discovery wells:
Oil			1.1				—				1.7				—				8.5				—
Gas			0.5				0.4				3				—				—				—
Dry wells			1.3				—				2				0.5				—				—
Total			2.9				0.4				6.7				0.5				8.5				—

Production

Argentine Production

Our proved reserves in Argentina as of December 31, 2007 were 98.5 million barrels of crude oil and 1,016.7 billion cubic feet of natural gas. For the year 2007, our average daily production was 46.7 thousand barrels of crude oil and 261.5 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.

Oil and natural gas reserves in Argentina have had a downward trend during the last few years. According to official data from the Argentine Oil and Gas Institute, proved oil and gas reserves for the 2002-2006 period dropped approximately 23%.

Oil production in Argentina has declined for ten years in a row. In 2007, oil production totaled 643 thousands barrels per day, a decline of approximately 2.5% compared to 2006.

In 2007 our oil and gas reserves in Argentina declined 4.5%. During the same year, our production of oil equivalent in Argentina decreased 5.8% compared to 2006.

Exploration is our main vehicle for growth and reserve replacement, including exploration of offshore fields. Due to the risks inherent in exploration activities, we cannot assure you that the downward trend in reserves will be reversed in the future.

During the fiscal year ended December 31, 2007, according to the Argentine Oil and Gas Institute, our oil and gas production accounted for approximately 6% and 7% of total oil and gas production in Argentina, respectively, and positioned us as the third largest producer in the country. 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. These royalties are in general 12% of the wellhead price for oil and gas. The wellhead price is calculated by deducting freight and other expenses to make oil and gas available for sale from the sales price obtained in transactions with third parties, or from the product price prevailing in the domestic market if the product is subject to industrialization processes.

We transport our oil and gas production in several ways depending on the infrastructure available and the cost efficiency of the transportation system in a given location. We use the oil pipeline system and oil tankers to transport oil to our customers. Oil is customarily sold through FOB contracts whereby producers are responsible for transporting produced oil 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 all 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 infrastructure. The privatization of the transportation system led to capital investments in these 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.

As of December 31, 2007, we owned 18 concessions in oil and gas production areas in Argentina. Our production is concentrated in four basins, the Neuquén, Austral, San Jorge and Noroeste basins. In the Neuquén basin—the most important basin in Argentina in terms of oil and gas production—we own approximately 573 thousands net acres. Our most important fields in the Neuquén basin are Puesto Hernández, 25 de Mayo-Medanito S.E. and Sierra Chata. In the Austral basin, we own approximately 2,478 thousand net acres, with Santa Cruz I and Santa Cruz II being our main concessions.

As of December 31, 2007, we had 3,091 productive wells.

In February 2007, we agreed to acquire 25.67% and 52.37% interests in the Sierra Chata and Parva Negra areas, respectively, for an acquisition price of US$77.6 million. This transaction, which is subject to approval by regulatory authorities, will increase our interest in Sierra Chata and Parva Negra to 45.55% and 100%, respectively. Sierra Chata is a natural gas producing field in the Neuquén basin, with total proved reserves of 51 million barrels of oil equivalent as of December 31, 2007. Parva Negra is a lot, adjacent to Sierra Chata, that has two drilled wells with natural gas shows.

In December 2007, we acquired a 13.72% interest in El Tordillo and La Tapera — Puesto Quiroga areas, for an acquisition price of US$117.5 million. This transaction became effective in March 2008 after completion of all contractual formalities. As a result, our interest in the aforementioned areas increased to 35.67%. El Tordillo concession produces Escalante crude oil (crude of 24° API gravity), while La Tapera — Puesto Quiroga concession is in the exploration stage. Our increased estimated share of production in El Tordillo area is estimated at approximately 3,500 barrels per day.

Production outside of Argentina

As of December 31, 2007, 44.5% of our combined proved reserves were located outside of Argentina. In addition, approximately 45.5% of our oil production and 17.8% of our gas production came from outside of Argentina in 2007. We have working interests in nine oil and gas production blocks outside of Argentina: Oritupano Leona, La Concepción, Acema and Mata (these four through direct and indirect interest in Petroritupano S.A., Petroven-Bras S.A., Petrowayú S.A. and Petrokariña S.A.) in Venezuela, Lote X in Peru, Block 18 and Block 31 in Ecuador, Colpa Caranda in Bolivia and Tibú in Colombia.

Venezuela

As of December 31, 2007, estimated proved oil and gas reserves attributable to operations in Venezuela amounted to 71.1 million barrels of oil equivalent, accounting for 14.7% of our total reserves. In 2007, oil and gas production from our interest in mixed companies averaged 15.9 thousand barrels of oil equivalent per day, representing 11.5% of our daily production

In 1994, Petróleos de Venezuela S.A. (“PDVSA”) awarded us the contract at the Oritupano-Leona field to provide exploration and production services for a 20-year period. In 1997, PDVSA awarded us three 20-year service contracts for the exploration and production of La Concepción, Acema and Mata blocks.

In April 2005, the Venezuelan Energy and Oil Ministry (“MEP”) ordered PDVSA to review the thirty-two operating agreements signed from 1992 through 1997 by PDVSA’s affiliates with oil companies, including the agreements signed with us, through our subsidiaries and affiliates in Venezuela, to operate the Oritupano Leona, La Concepción, Acema and Mata production areas. The MEP ordered PDVSA to take all necessary measures to convert existing operating agreements effective at that time into mixed companies, in which the Venezuelan government would hold a share of at least 50% through PDVSA.

In March 2006, we, through Petrobras Energía and its related companies in Venezuela, signed memoranda of understanding (“MOU”) with PDVSA and the Corporación Venezolana del Petróleo S.A. (“CVP”) in order to effect the migration of our four pre-existing operating agreements.

These MOUs established that private investors would hold a 40% share in these mixed companies, with the Venezuelan government entitled to a 60% ownership interest. The MOUs established that the economic effects of the migration would become effective on April 1, 2006. As a result, our direct and indirect interests in the mixed companies that operate in the areas of Oritupano Leona, La Concepción, Acema and Mata are 22%, 36%, 33.24% (34.5% prior to the sale of Petrobras de Valores Internacional de España S.L. (“PVIE”)) and 34.5%, respectively. Additionally, the MOUs provided that CVP would recognize a divisible and transferable credit in favor of Petrobras Energía in the amount of US$88.5 million, which would not accrue interest, but could be applied toward acquisition bonds for any new mixed-company project for oil exploration and production activities, or licenses for gas exploration and production operations in Venezuela. Since (i) no projects for which the credit is eligible for investment have materialized, (ii) our efforts to transfer the credit to third parties have been unsuccessful, and (iii) alternative uses of the credit cannot be anticipated, as of December 31, 2007 we wrote down the carrying value of the credit to zero.

In August 2006, the relevant conversion agreements were signed for the Oritupano Leona, La Concepción, Acema and Mata areas, which were consistent with the terms agreed upon in the MOUs. Subsequently, the companies Petroritupano S.A., Petrowayú S.A., Petrovenbras S.A. and Petrokariña S.A. were organized and registered with the Public Registry of Commerce of Venezuela. The Venezuelan government issued the relevant decrees granting the necessary powers to these four companies, and the respective shareholders subsequently made the required capital contributions. Between December 2006 and March 2007, following the transfer of vendor agreements and employees, among others, the transfer of operations to the mixed companies was completed.

Mixed companies are subject to royalty payments of 33.33% based on production. In addition, they are 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 of total royalty payments made during such year plus income tax and any other tax or duty calculated on the basis of the sales revenues paid during such year. Each mixed company is the operator of the areas, and the crude oil produced by the mixed companies has to be sold and delivered to PDVSA at market prices.

As of December 31, 2007, Oritupano Leona, La Concepción, Acema and Mata areas had 363 productive wells.

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 the organization. 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 activities governed by the law. As a result, if OPEC approves production cuts, these cuts will affect PDVSA and the mixed companies. See “Regulation of Our Businesses—Venezuelan Regulatory Framework—Petroleum and Gas—OPEC”.

Peru

In 1996, we, through Petrobras Energía Perú, acquired 30-year oil and 40-year natural gas production rights in Lote X, in which Petrobras Energía Perú holds a 100% interest. Lote X is an area of approximately 116,000 acres in Peru’s Talara Basin, which is operated pursuant to a concession production agreement with free crude oil availability.

In December 2007, we sold 40% of our equity interest in PVIE, the holding company whose main asset is a 99.79% interest in Petrobras Energía Perú S.A.’s capital stock, to Petrobras Internacional — Braspetro B.V., a wholly owned subsidiary of our controlling shareholder, Petrobras, for US$423.3 million, plus a contingent compensation to be defined by the parties in the event a commercially viable discovery is made at the Kinteroni prospect in Block 57. See “Exploration—Exploration Outside of Argentina—Peru”. Following this sale, we continue to hold a 60% interest in PVIE. Pursuant to the terms and conditions of the stock purchase agreement, we and Petrobras Internacional — Braspetro B.V. agreed to share the power and authority to define and direct PVIE’s operating and financial policies.

As of December 31, 2007, estimated proved oil and gas reserves attributable to operations in Peru amounted to 69.3 million barrels of oil equivalent, accounting for 14.4% of our total reserves. In 2007, our net daily production in Peru was 15.1 thousand barrels of oil equivalent or 10.8% of our total production.

As of December 31, 2007, Lote X had 2,518 productive wells. We entered into a long-term sales agreement, whereby Perupetro S.A.’s Talara refinery is the sole customer of our crude oil production.

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 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 US$98 million in Lote X during the 2004-2011 period. By December 31, 2007, our investements in Lote X had exceeded the committed amount by approximately US$74 million. Works covered by this agreement include the drilling of 51 wells, 526 workovers, the reactivation of 177 temporarily abandoned wells, the implementation and expansion of the water injection project and the development of a gas injection project. The Peruvian government, in turn, reduced the royalty rate for crude oil and gas production.

In Peru, 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 a rate of 13% for prices of up to US$23.9 per barrel. The royalty rate applicable for oil at December 2007 was 36.2%. Production of natural gas in Peru is subject to a fixed royalty of 24.5%.

Our activities in Peru during the year included the drilling of 112 productive wells, one injection well, 133 workovers and the reactivation of 44 wells. In September 2007, a second automatic drilling rig was added to the operation in order to increase drilling activity in this area.

Ecuador

In Ecuador we operate Blocks 18 and 31 under participation agreements, in which as of December 31, 2007, we held 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, 2007, estimated proved oil and gas reserves attributable to our operations in Ecuador amounted to 44.8 million barrels of oil equivalent, accounting for 9.3% of our total reserves. In 2007, our oil production in Ecuador totaled 10.3 thousand barrels per day, accounting for 7.4% of our total average daily production in barrels of oil equivalent.

In January 2005, we entered into a letter of intent with Teikoku Oil Co. Ltd. (“Teikoku”), whereby we requested approval from the Ecuadorian Ministry of Energy and Mines to transfer 40% of our working interest in Blocks 18 and 31. On January 11, 2007, the Ecuadorian Ministry of Energy and Mines authorized the assignment. As a result of this authorization, Petroecuador commenced the process of completing the necessary formalities, including obtaining amendments to the participation agreements, in order to incorporate Teikoku as a partner in the agreements for Blocks 18 and 31. Once the amendments are finalized, the terms and economic conditions of the Teikoku transaction would become effective.

On March 30, 2008, Petroecuador notified EcuadorTLC that Ecuador’s Attorney General had submitted a request for termination of the participation agreement relating to Block 18, based on alleged irregularities in the assignment to Teikoku Oil Ecuador, an alleged lack of registration of what the Attorney General understands to be a consortium among the different parties to the participation agreement, and on account of repeated penalties imposed for alleged non-compliance with the Ecuadorian hydrocarbons law (see “New Regulations” below).

On April 10, 2008 EcuadorTLC filed an answer invoking its rights, and included with its answer all documentary evidence that it believes necessary to prove that there are no grounds for terminating the Block 18 participation agreement, including the necessary administrative authorizations, and a Ministerial Accord authorizing the assignment and obligating Petrecuador to amend the participation agreement and grant the pertinent deeds. See “Operating and Financial Review and Prospects—Factors Affecting Our Consolidated Results of Operations—Operations in Ecuador”.

Block 18

In 2001, we acquired a 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 sales price and total proved reserves. If the sales price of crude from Palo Azul is lower than US$15 per barrel, the government receives approximately 30% of the crude produced, while if the sales price of crude is US$24 or higher, the government receives approximately 50% of production. For the intermediate price ranges, an increasing scale of aliquot is applied. The sales price of the Palo Azul crude is calculated considering as reference the WTI net of the standard market discount for Oriente crude. In the Pata field, the government receives a production share ranging from 25.8%, if daily production is lower than 35 thousand barrels per day, to 29% if production exceeds 45 thousand barrels per day, shares which are adjusted depending on the crude oil quality factor. As of December 31, 2007, the government’s share of oil produced at the Pata and Palo Azul fields under the operating agreements was 31.3% and 50.5%, respectively.

As of December 31, 2007, Block 18 had thirty-two productive wells, twenty-nine located at the Palo Azul field and three located at the Pata field. In December 2006, the new oil treatment plant and ducts became operational. This investment increased the plant’s treatment capacity to 40 thousand barrels of oil per day.

During the first quarter of 2007 our operations in Block 18 were interrupted for 30 consecutive days, from March 9, 2007 to April 10, 2007, as a result of protests and demonstrations by local communities. During this period, cumulative oil production decreased by approximately 305 thousand barrels of oil equivalent in our participation.

Block 31

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 that 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. These wells were 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 2003, the Ministry of Energy and Mines approved the development plan for the Apaika Nenke field. 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. Native and environmentalist groups made public statements against the Block 31 development, arguing that oil and gas activities 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 (the boundary of the Parque Nacional Yasuní) and denied us access to Parque Nacional Yasuní. We changed our development plan for Block 31 in order to address the objections posed by the Ecuadorian Ministry of the Environment and finally, after a process involving participation of the affected communities, submitted a new Environmental Impact Assessment (“EIA”), which was approved by the Ministry of the Environment and the Ministry of Energy and Mines.

The Ecuadorian Ministry of the Environment granted an Environmental License in October 2007. In November 2007, the Ministry of Mines and Petroleum approved the First Amendment to the Development Plan of Apaika-Nenke field in Block 31. The new project stands out for its implementation of the best technology available to minimize potential social and environmental impacts on areas as sensitive as the Parque Nacional Yasuní. As of the date of this annual report, Petrobras Energía Ecuador has applied for a forestry license and is in compliance with its obligations under the 2007 environmental license.

New Regulations

In April 2006, the Ecuadorian government approved an amendment to the Hydrocarbons Law, which assigned the government an interest of at least 50% of excess revenues resulting from any increase in the price of Ecuadorian crude (effective monthly average FOB price) over the average monthly sales price for such oil at the execution date of the relevant production agreements, expressed in constant values for the month in which settlement occurs (“extraordinary income”). On October 18, 2007, the Ecuadorian President issued an additional regulation increasing the government’s share in extraordinary income to 99%, and reducing the share of oil companies to 1%.

We, Petroecuador, and the Ecuadorian government have divergent interpretations of the proper application of the amended Hydrocarbon Law. See “Factors Affecting Our Consolidated Results of Operations—Operations in Ecuador—Recoverability of Investments and Amendments to the Hydrocarbons Law” and “Risk Factors—Our activities may be adversely affected by events in countries in which we do business—Ecuador”.

EcuadorTLC has since served notice on Ecuador’s Attorney General that it intends to arbitrate its dispute over the application of Law 42 pursuant to the bilateral investment treaty between Ecuador and Argentina. EcuadorTLC sees Law 42 as a confiscatory measure that threatens the economic feasibility of its investments and is equivalent to an expropriation of its interests. See “Risk Factors— Our activities may be adversely affected by events in countries in which we do business—Ecuador”.

In addition, on December 28, 2007, the Ecuadorian Constitutional Assembly approved the Tax Equality Law, which became effective as from January 1, 2008. This law introduces a major tax reform and makes progress on the creation of new taxes.

The combined effect of these regulatory changes—the scope of which for some has not yet been fully determined—has materially modified the conditions set forth at the time of execution of our participation agreements, adversely affecting the valuation of our ongoing projects in Ecuador, and negatively impacting our assessment of recoverability.

As of the date of this annual report, Petrobras Energía and the Ecuadorian Government are negotiating their relationship under the participation agreements governing exploitation of Blocks 18 and 31.

Ship or Pay Obligations with Oleoducto de Crudos Pesados (“OCP”)

In connection with our operations in Blocks 18 and 31, we executed a transportation agreement with OCP whereby we acquired an oil transportation capacity of 80 thousand barrels per day for a 15-year term, starting November 10, 2003. Under the “Ship or Pay” clause included in the agreement, we, as well as all other producers, must pay a fee covering OCP operating costs and financial services even when no crude oil is transported. As of December 31, 2007, such fee amounted to US$ 2.10 per barrel.

We expect that during the term of the transportation agreement oil production will be lower than the aggregate committed transportation capacity. This assumption is based on our current forecast of reserve potential in Ecuador and on the gradual development estimated for those reserves. In light of this situation, we have sold some of our transportation capacity to other parties. As of December 31, 2007, we sold transportation capacity of approximately 8 thousand barrels per day to Murphy Oil, through January 2012, and transportation capacity of approximately 16 thousand barrels per day to Petroecuador, through December 2008.

Pursuant to the letter of intent signed with Teikoku, and once the terms and economic conditions of the transaction would become effective, Teikoku would assume 40% of our rights and obligations resulting from the crude oil transportation agreement with OCP. Allocation of part of our transportation capacity to Teikoku would enable us to further reduce our current oil production deficit and facilitate compliance with our “Ship or Pay” commitment.

Bolivia

As of December 31, 2007, we held a 100% interest in the Colpa Caranda Block in Bolivia. The Colpa Caranda Block covers approximately 56,000 net acres located in the Sub Andina Central basin and has fifty-four producing wells.

As of December 31, 2007, estimated proved oil and gas reserves attributable to operations in Bolivia amounted to 29.6 million barrels of oil equivalent, accounting for 6.1% of our total reserves. In 2007, our net daily production in Bolivia under the economic method was 7.15 thousands barrels of oil equivalent or 5.2% of our total production. Approximately 87% 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.

We have operated the Colpa Caranda Block in Bolivia since 1989. Under a contract signed with the Bolivian national oil company, YPFB, in October 2006, we now perform exploration and production activities at our own risk and for our own account in the Colpa Caranda Block, but on behalf of and in the name of the YPFB. Under the current agreement, YPFB owns the hydrocarbons and pays royalties, direct interest and direct tax on hydrocarbons, which in the aggregate amount to 50% of the production valued on the basis of sales prices. The 80% of the remaining amounts are used to pay for operating services provided by us, including depreciation. Any remainder is shared between YPFB and us on the basis of an index calculated based on production volumes, depreciation rates, prices and taxes paid, among other items. The agreement was signed on November 28, 2006, approved by the Bolivian Legislature on April 19, 2007 and became effective on May 2, 2007. In previous years, the subsidiary operated the block under a shared risk contract whereby it had free oil production availability.

Colombia

We are involved in the exploitation of the Tibú Field in the Catatumbo basin, Colombia, through our 30% interest in the Tibú Consortium. This consortium signed an agreement with the Colombian state-owned company, Ecopetrol, for the development of the Tibú field. We contribute our expertise in the development and exploitation of mature fields to this project.

During the first two stages of this project, lasting two and a half years from July 2007, the Tibú Consortium will invest US$40 million in studies and projects to determine the potential of the field, which is currently producing 1,800 barrels of oil per day. During the next phase, we expect that the Tibú Consortium will be responsible for 55% of the investments (Ecopetrol for the remaining 45%) and that the Tibú Consortium will be entitled to the 40% of the field’s production after royalties. The Tibú Consortium carries out investment projects to generate additional production, while Ecopetrol operates the field.

Statistical Information Relating to Oil and Gas Production

The following table sets forth our oil and gas production during 2007. Production figures represent our working interest in production (and are therefore net to us). 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, 2007. Although some of these concessions may be extended at their expiration, the expiration dates set forth below do not include any extensions.

														Oil and
						2007 Production								Gas
Production Areas		Location		Basin		Oil (1)				Gas (2)				Wells				Interest (8)				Expiration
Argentina:
25 de Mayo — Medanito S.E.		La Pampa and Río Negro		Neuquén			4,913				3,169				577				100.00	%			2016
El Mangrullo		Neuquén		Neuquén			6				10,260				6				100.00	%			2025
Jagüel de los Machos		Río Negro and La Pampa		Neuquén			1,030				2,769				101				100.00	%			2015
Puesto Hernández		Mendoza and Neuquén		Neuquén			3,460				—				825				38.45	%			2016
Bajada del Palo		Neuquén		Neuquén			60				—				4				17.9	%(3)			2015
Santa Cruz II		Santa Cruz		Austral			1,241				7,855				71				100.00	%			2017/2024
Río Neuquén		Neuquén and Río Negro		Neuquén			503				6,435				131				100.00	%			2017
Entre Lomas		Neuquén and Río Negro		Neuquén			880				1,053				417				17.9	%			2016
Veta Escondida and Rincón de Aranda U.T.E.		Neuquén		Neuquén			—				—				—				55.00	%			2017
Aguada de la Arena		Neuquén		Neuquén			97				6,991				11				80.00	%			2022

														Oil and
						2007 Production								Gas
Production Areas		Location		Basin		Oil (1)				Gas (2)				Wells				Interest (8)				Expiration
Santa Cruz I U.T.E.		Santa Cruz		Austral			2,294				44,421				98				71.00	%			2016/2031
Sierra Chata		Neuquén		Neuquén			180				5,639				41				19.89	%			2020
Atuel Norte		Neuquén		Neuquén			4				—				6				33.33	%			2015
La Tapera — Puesto Quiroga		Chubut		San Jorge							—								21.95	%			2017
El Tordillo		Chubut		San Jorge			2,034				30				756				21.95	%			2016
Aguaragüe		Salta		Noroeste			143				6,761				38				15.00	%			2017/2023
Estancia Agua Fresca		Santa Cruz		Austral			189				75				3				50.00	%				(4)
Gobernador Ayala		Mendoza		Neuquén			12				—				6				22.51	%				(4)
Total Argentina							17,046				95,458				3,091
Outside of Argentina:
Colpa Caranda (9)		Bolivia		Sub Andina			490				12,715				54				100.00	%			2029
Oritupano Leona (5)		Venezuela		Oriental			3,107				—				215				22.00	%			2025
Acema (5)		Venezuela		Oriental			239				831				26				33.24	%			2025
La Concepción (5)		Venezuela		Lago Maracaibo			1,383				1,480				74				36.00	%			2025
Mata (5)		Venezuela		Oriental			361				1,901				48				34.49	%			2025
Lote X		Peru		Talara			4,859				3,691				2,518				60.00	%(6)			2024
Block 31		Ecuador		Oriente			—				—				—				100.00	%			2024
Block 18		Ecuador		Oriente			3,769				—				32				70.00	%			2022
Tibú		Colombia		Catatumbo			—				—				127				30.00	%				(7)
Total Outside of Argentina							14,208				20,618				3,094
Total							31,254				116,076				6,185

The following table sets forth our average daily production of oil, including other liquid hydrocarbons, for the fiscal years ended December 31, 2007, 2006 and 2005. This table includes our net share of production of consolidated subsidiaries, companies under joint control and unconsolidated investees.

		Year ended December 31,
		2007				2006				2005
		(average barrels per day)
Argentina			46,700				54,233				54,516
Outside of Argentina			38,925				49,181				67,962
Total			85,625				103,414				122,478

The following table sets forth our average daily gas production for the fiscal years ended December 31, 2007, 2006 and 2005. This table includes our net share of production of consolidated subsidiaries, companies under joint control and unconsolidated investees.

		Year ended December 31,
		2007				2006				2005
		(average thousand cubic feet per day)
Argentina			261,529				250,030				231,830
Outside of Argentina			56,487				54,677				61,855
Total			318,016				304,707				293,685

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 fiscal years ended December 31, 2007, 2006 and 2005, of our consolidated subsidiaries and companies under joint control.

		Year ended December 31,
		2007				2006				2005
Argentina:
Oil (in pesos per barrel of oil equivalent)			126.3				124.4				99.91
Gas (in pesos per million cubic feet)			4.1				3.54				2.74
Outside of Argentina (1):
Oil (in pesos per barrel of oil equivalent)			202.5				144.3				94.65
Gas (in pesos per million cubic feet)			10.84				10.52				5.21

The following table sets forth our average lifting cost, royalties and depreciation cost of oil and gas fields in each geographic area for the fiscal years ended December 31, 2007, 2006 and 2005. This table includes our net share of production of our consolidated subsidiaries and companies under joint control.

		Year ended December 31,
		2007				2006				2005
		(in pesos per barrel of oil equivalent)
Argentina:
Lifting Cost			17.27				13.50				11.05
Royalties			9.13				9.42				7.73
Depreciation			17.09				13.91				12.95
Total			43.49				36.83				31.73
Outside of Argentina (1):
Lifting Cost			11.55				12.10				10.03
Royalties			37.66				23.72				8.08
Depreciation			12.99				13.91				13.97
Total			62.20				49.73				32.08

Exploration

We consider exploration our main vehicle for future growth and the replacement of reserves. Our strategy is focused on constantly searching for new exploration opportunities aligned with our growth targets. Accordingly, we expect an increase in our exploration investments, including exploration opportunities in Argentina’s offshore areas. In exploring offshore areas, we use the expertise 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, 2007, the location and basin of each area, our net working interest and the expiration date for the exploration authorization.

		Location		Basin		Interest (4)				Expiration
In Argentina:
Glencross		Santa Cruz		Austral			87.00	%			2032
Estancia Chiripá		Santa Cruz		Austral			87.00	%			2032
Cerro Manrique		Rio Negro		Neuquén			50.00	%				(2)
Parva Negra		Neuquén		Neuquén			47.63	%			2001	(1)
Cerro Hamaca		Mendoza		Neuquén			39.64	%			2004	(1)
Cañadón del Puma		Neuquén		Neuquén			50.00	%			2008
Puesto Oliverio		Santa Cruz		Austral			50.00	%			2006	(1)
El Campamento		Santa Cruz		Austral			50.00	%			2006	(1)
El Cerrito Oeste		Santa Cruz		Austral			50.00	%			2006	(1)
Chirete		Salta		Noroeste			100.00	%			2010
Hickman		Salta		Noroeste			50.00	%			2011
Rio Colorado		Salta		Noroeste			30.00	%			2010
Enarsa 1		Continental Shelf		Offshore Argentina			25.00	%			—
Enarsa 3		Continental Shelf		Offshore Argentina			35.00	%			—
Outside of Argentina:
Block 57		Peru		Madre de Dios			21.12	%(3)			2008
Block 58		Peru		Madre de Dios			60.08	%			2009
Block 103		Peru		Huallaga			18.02	%			2008
Block 110		Peru		Madre de Dios			60.08	%			2009
Block 117		Peru		Marañon			60.08	%			2008

Exploration in Argentina

As of December 31, 2007, we held interests in approximately 18,129 thousand gross exploration acres in Argentina. In 2007, Petrobras Energía was awarded three exploration blocks in the province of Salta, one of them, Chirete, as operator, and Hickmann and Río Colorado as non-operator partner.

In 2007, we completed a 1,138 km² 3D seismic survey in El Campamento, Estancia Chiripá and Glencross areas in the Austral basin and an approximately 1,594 km² survey in the Enarsa 1 offshore area. Additionally, during 2007 we completed a 820 km² 3D seismic survey in Parva Negra and Atuel Norte blocks in the Neuquen basin.

In the Neuquén, Austral and Golfo de San Jorge basins, twelve exploratory wells were drilled, six of which were successful and three of which were awaiting completion as of December 2007. In 2007, we added 3.9 million barrels of oil equivalent through exploration activities. Additional investments are required in reservoir demarcation and characterization to determine the possibility of adding proved reserves.

Exploration Outside of Argentina

Peru

In 2004, we, through Petrobras Energía Perú, entered into an agreement with Repsol Exploración Perú S.A. to jointly perform exploration activities in Block 57, located in the Madre de Dios basin. Pursuant to this agreement, Petrobras Energía Perú’s interest in the Block was 35.15%. In 2005, Petrobras Energía Perú pursued an aggressive policy to increase its acreage position, through exploration license applications and farm-ins. During 2005, Petrobras Energía Perú applied for four exploration blocks: Blocks 58 and 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). In 2005, through a farm-in, Petrobras Energía Perú acquired a 30% working interest in Block 103, operated by Occidental, in the Huallaga basin. Early in 2007, Burlington Resources sold their working interest in Block 57 to Petrobras Energía Perú and Repsol. Petrobras Energía Perú’s interest increased from 35.15% to 46.16%. In February 2008 the Peruvian authorities approved the new consortium.

In August 2007, Petrobras Energía Perú decided, based on technical and economic merits, not to proceed with the second exploration period in Block 112, and therefore relinquished this area.

In Peru, exploration licenses are granted for a total of seven years. The first exploration period of 12 to 24 months generally 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.

During 2007, our main exploration activities were carried out in Block 57, operated by Repsol. A total of 283 km out of 296 km of a 2D seismic program was acquired. One of the most important highlights for the year 2007 in Peru was the drilling of the Kinteroni well in Block 57. Production tests carried out on some reservoir levels show potential flow rates of over 35 million cubic feet of gas per day and 1,245 barrels of condensate per day.

As of December 31, 2007, our total gross exploration area in Peru was 11,548 thousand acres.

In addition, on November 16, 2006, Petrobras Energía Perú and Petroperú entered into a two-year Technical Evaluation Agreement over six blocks covering almost 14,579 thousand acres. During 2007, the incorporation of Ecopetrol in the agreement was agreed upon, but is still awaiting official approval.

Venezuela

We had a 50% working interest in the Venezuelan Tinaco area under a license for the exploration and production of gas. In 2006, drilling of La Yaguara well in the Tinaco area yielded disappointing results and in March 2007 the license was relinquished. We do not currently conduct any exploration activities in Venezuela.

Colombia

In 2005, we agreed to acquire a 10% working interest in the Tierra Negra Block from Petrobras Colombia, operator of the block with a 60% working interest. In January 2008, 10% of Tierra Negra exploration area was formally awarded to Petrobras Energía Colombia. Since no positive results were obtained from the works carried out in this area, the block was relinquished in February 2008.

Ecuador

The concession contract for Block 31 allows us to perform additional exploratory works for a period of three years following commencement of the development stage. In November 2007, the Ministry of Mines and Petroleum approved the First Amendment to the Development Plan of Apaika-Nenke field in Block 31, which established the start of the exploration period in 2008. Furthermore, and in accordance with the provisions set forth in the Ministerial approval, we are able to perform exploratory activities in the Block until the end of 2010. In terms of planned exploration activities in the western region of Block 18, local communities have not allowed us to enter the area to carry out fieldwork activities. This event prompted us to invoke force majeure remedies and request an extension of the remaining exploration period until difficulties with the local communities were resolved. In March 2006, the Ministry of Mines and Petroleum issued a Ministerial Accord acknowledging force majeure status.

Reserves

We believe our estimates of remaining proved recoverable oil and gas reserve volumes to be reasonable. Pursuant to Rule 4-10 of Regulation S-X, promulgated by the U.S. Securities and Exchange Commission, proved oil and natural gas reserves are those estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs, under existing economic, operating and regulatory conditions, i.e., prices and cost at the date of estimation.

DeGolyer and MacNaughton audited 71% of our estimated reserves as of December 31, 2007. The majority of the reserves not audited by DeGolyer and MacNaughton are in areas where we do not act as operator. The audit covered approximately 90% of the estimated reserves located in areas operated by us.

DeGolyer and MacNaughton concluded that the proved oil and natural gas reserve volumes covered by the audit are reasonable and that reserve estimates have been prepared in accordance with Rule 4-10 of Regulation S-X and in accordance with oil and gas reserve disclosure provisions of the Financial Accounting Standards Board — FASB Statement of Financial Accounting Standards No. 69 - Disclosures about Oil and Gas Producing Activities. We resolved all questions that arose during the course of the audit process to the auditor’s satisfaction.

As of December 31, 2006 and 2005, 93% and 95% of our estimated reserves, respectively, were audited by Gaffney, Cline & Associates Inc.

The estimates of reserves related to areas in which we act as operator were prepared by our petroleum engineers. Most of the reserve estimates related to areas in which we do not act as operator were prepared by the operators and subsequently reviewed by our petroleum engineers before making the assessment of our proved reserves. The reported hydrocarbon reserves were estimated based on professional, geological and engineering judgment and on information supplied by us prior to January 11, 2008. Thus they are subject to revisions, upward or downward, as a result of future operations or as additional information becomes available. DeGolyer and MacNaughton’s audit examination included those tests and procedures considered necessary by them in view of the circumstances prevailing in each case. These tests and procedures included a review of the appropriateness of the methodologies employed by us in estimating reserves, the adequacy and quality of the data obtained and used by us in estimating reserves, the scope and completeness of the process used by us in estimating reserves and our classification of reserves in accordance with relevant definitions and guidance, as well as an economic test of the proved developed and total proved categories of reserves for each audited property.

An audit of proved reserves is an examination of proved reserves that is conducted by the auditor for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable. The estimation of reserves is an imprecise science due to many unknown geologic and reservoir factors that can only be estimated through sampling techniques. Since reserves are therefore only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by us, engaged in the exploration and production of oil and gas in estimating our reserves so that the auditor may express an opinion as to whether, in the aggregate, the reserve information furnished by us is reasonable.

As of December 31, 2007, liquid hydrocarbon and natural gas proved developed and undeveloped reserves amounted to 482.7 million barrels of oil equivalent (264.9 million barrels of oil and 1,307.1 billion cubic feet of natural gas), representing an 8.4% decline compared to proved reserves as of December 31, 2006 (a decline of 18.2% for liquid hydrocarbons and an increase of 7.2% for natural gas). This reflects principally a decline in proved reserves in Peru as a result of the sale of a 40% interest in PVIE, partially offset by an increase in reserves due to extensions and revisions of previous estimates, principally in Peru and Argentina.

Liquid hydrocarbons and natural gas accounted for 54.9% and 45.1%, respectively, of our total proved reserves as of December 31, 2007. Approximately, 44.5% of our total proved reserves as of December 31, 2007 were located outside of Argentina, as compared to 46.8% as of December 31, 2006.

As of December 31, 2007, proved developed reserves of crude oil equivalent represented 55.4% of our total proved reserves of crude oil equivalent.

During 2007, an increase of net reserves of approximately 54 million barrels of oil equivalent was recorded principally as detailed below:

•   An addition of 18 million barrels of oil equivalent in Argentina by exploration and extensions of known accumulations net of revisions in gas fields.

•   An addition of 33 million barrels of oil equivalent in Peru principally by extension of drilling and secondary oil recovery projects, which allowed us to make revisions to previous estimates.

As a result of the sale of a 40% interest in PVIE, there was a reduction of 46 million barrels of oil equivalent in Peru. In addition, due to the reduction of our interest in Bajada del Palo, our reserves decreased 1 million barrels of oil equivalent in the Neuquen basin in Argentina.

As of December 2007, we had proved reserves equal to 9.5 years of production at 2007 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 reserves of natural gas at the indicated dates. This table includes our net share of the proved reserves of our consolidated subsidiaries, companies under joint control and unconsolidated investees. Our net share of the proved reserves of our unconsolidated investees represented 16% of our total proved reserves as of December 31, 2007.

		Crude oil, condensate and natural gas
		liquids												Natural gas
						Outside of												Outside of
		Argentina				Argentina				Total				Argentina				Argentina				Total				Combined
																										(in millions
																										of barrels
																										of oil
		(in thousands of barrels)												(in millions of cubic feet)												equivalent)
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
Increase (decrease) originated in:
Revisions of previous estimates			(2,636	)			(186,724	)			(189,360	)			25,264				(96,042	)			(70,778	)			(201.2	)
Improved recovery			38				4.705				4,743				724				6,830				7,554				6.0
Extensions and discoveries			5,510				6,900				12,410				63,595				—				63,595				23.0
Purchase of proved reserves in place			—				—				—				—				—				—				—
Sale of proved reserves in place			(4,541	)			—				(4,541	)			—				—				—				(4.5	)
Year’s production			(19,795	)			(17,951	)			(37,746	)			(91,261	)			(19,957	)			(111,218	)			(56.3	)
Total proved developed and undeveloped reserves as of December 31, 2006			122,409				201,527				323,936				949,185				270,640				1,219,825				527.2
Proved developed reserves as of December 31, 2006			81,845				102,735				184,580				497,680				179,884				677,564				297.5
Increase (decrease) originated in:
Revisions of previous estimates			(8,766	)			9,380				614				(5,348	)			79,904				74,556				13.0
Improved recovery			—				8,864				8,864				—				2,027				2,027				9.2
Extensions and discoveries			3,113				299				3,412				168,326				—				168,326				31.5
Purchase of proved reserves in place			—				—				—				—				—				—				—
Sale of proved reserves in place			(1,231	)			(39,439	)			(40,670	)			—				(41,595	)			(41,595	)			(47.6	)
Year’s production			(17,046	)			(14,208	)			(31,254	)			(95,458	)			(20,618	)			(116,076	)			(50.6	)
Total proved developed and undeveloped reserves as of December 31, 2007			98,479				166,423				264,902				1,016,705				290,358				1,307,063				482.7
Proved developed reserves as of December 31, 2007			71,927				79,530				151,457				507,140				188,542				695,682				267.4