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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 20-F ANNUAL REPORT PURSUANT TO SECTION 13
OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended: December 31, 2003 Commission file number 333-11130 PETROBRAS ENERGÍA PARTICIPACIONES S.A.  N/A
    
    REPUBLIC OF ARGENTINA(Translation of Registrants name into English)
    
    (Jurisdiction of incorporation of organization)
 Maipú 1, 22nd Floor
(C1084ABA) Buenos Aires
Argentina
(Address of principal executive offices) Securities registered or to be registered pursuant to Section 12(b) of the Act: Name of Each ExchangeTitle of each Class
    
    On Which RegisteredAmerican Depositary Shares, each representing 10 Class B shares
    
    New York Stock Exchange
 Securities registered or to be registered pursuant to Section 12(g) of the Act:  None Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act:  None The number of outstanding shares of each of the issuers classes of capital or
common stock as of December 31, 2003 was: Class B Ordinary Shares, par value Ps.1.00 per share
    
    
    2,132,043,387
 Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days: Yes x
    
    No o
 Indicate by check mark which financial statement item the Registrant has elected to follow: Item 17 o
    
    Item 18 x
 The following disclosure item
is omitted from Item 18 in this annual report: the financial
statements for Compañia de Inversiones de Energía
S.A., a company of which we held 50% of the share capital as of
December 31, 2003 and over which we exercised joint control.




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TABLE OF CONTENTS PageINTRODUCTION
    
    
    1FORWARD-LOOKING STATEMENTS
    
    
    1Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
    
    
    2Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE
    
    
    2Item 3. KEY INFORMATION
    
    
    2Item 4. INFORMATION ABOUT US
    
    
    20Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
    
    
    86Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
    
    
    139Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
    
    
    149Item 8. FINANCIAL INFORMATION
    
    
    152Item 9. OFFER AND LISTING
    
    
    154Item 10. ADDITIONAL INFORMATION
    
    
    156Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
    
    
    171Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
    
    
    174Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
    
    
    174Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITYHOLDERS AND USE OF PROCEEDS
    
    
    174Item 15. CONTROLS AND PROCEDURES
    
    
    175Item 16.
    
    
    176Item 17. FINANCIAL STATEMENTS
    
    
    178Item 18. FINANCIAL STATEMENTS
    
    
    178Item 19. EXHIBITS
    
    
    179BYLAWSMASTER SETTLEMENT AND MUTUAL RELEASE AGREEMENTLIST OF SIGNIFICANT SUBSIDIARIESCERTIFICATIONCERTIFICATIONCERTIFICATIONS
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INTRODUCTION All references in this annual report to: Petrobras Energía Participaciones, we, us, our, and similar terms
refer to Petrobras Energía Participaciones S.A. and its subsidiaries, but
excludes affiliates and companies under joint control. Prior to July 2003, our
corporate name was Perez Companc S.A. Petrobras Energía refers to Petrobras Energía S.A., a 98.21% owned
subsidiary of Petrobras Energía Participaciones together with its controlled
subsidiaries, but excludes affiliates and companies under joint control. Prior
to July 2003, the corporate name of Petrobras Energía was Pecom Energía S.A. Argentine pesos, pesos or P$ refer to the currency of the Republic
of Argentina. U.S. dollars or U.S.$ refer to the currency of the United States of
America. 
 FORWARD-LOOKING STATEMENTS Some of the information included in this annual report contains
information that is forward looking, including statements regarding, among
other items, future earnings and operating results, capital expenditures,
competition and sales, oil and gas reserves and prospects and trends in the oil
and gas, refining and petrochemicals and electricity industries. Certain statements contained in this annual report are forward-looking
statements and are not based on historical fact, such as statements containing
the words believe, may, will, estimate, continue, anticipate,
intend, expect and similar words. These forward-looking statements are
subject to risks, uncertainties and assumptions, including those discussed in
Item 4. Information About Us, Item 5. Operating and Financial Review and
Prospects and elsewhere in this annual report. Factors that could cause
actual results to differ materially and adversely include, but are not limited
to:  
    
    changes in general economic,
business, political or other conditions in Argentina or
changes in general economic or business conditions in
Latin America;
    
    the availability of financing at
reasonable terms to Argentine companies, such as us;
    
    changes in the price of hydrocarbons;
    
    changes to our capital expenditure plans;
    
    changes in laws or regulations affecting our operations;
    
    increased costs; and
    
    other factors discussed under Risk Factors in Item 3 of this annual report. We believe that our estimates are reasonable, but you should not unduly
rely on these estimates, which are based on our current expectations. We
undertake no obligation to update any forward-looking statement or statements
to reflect events or circumstances after the date on which the statement is
made or to reflect the occurrence of unanticipated events. New factors emerge
from time to time, and it is not possible for us to predict all of these
factors. Further, we cannot assess the impact of each factor on our business
or the extent to which any factor, or combination of factors, may cause actual
results to be materially different from those contained in any forward-looking
statements. 1




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Item 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS Not applicable. 
 Item 2. OFFER STATISTICS AND EXPECTED TIMETABLE Not applicable. 
 Item 3. KEY INFORMATION SELECTED FINANCIAL DATA The financial information set forth below may not contain all of the
financial information that you should consider when making an investment
decision. This information should be read in conjunction with, and is
qualified in its entirety by reference to, the Risk Factors included in this
annual report. See Risk Factors. You should also carefully read our
financial statements and Item 5. Operating and Financial Review and
Prospects included in this annual report for additional financial information
about us. Our financial statements are prepared in accordance with Argentine GAAP
which differs in certain significant respects from U.S. GAAP. Note 22 to our
financial statements provides a description of the principal differences
between Argentine GAAP and U.S. GAAP as they relate to us, and note 23 provides
a reconciliation to U.S. GAAP of net income, shareholders equity and certain
other selected financial data. Neither the effects of inflation accounting nor
the proportional consolidation of Distrilec Inversora S.A., a company under
joint control which we refer to as Distrilec, under Argentine GAAP have been
reversed in the reconciliation to U.S. GAAP. The proporational consolidation
of Compañía de Inversiones de Energía S.A., another company under joint control
which we refer to as CIESA, in 2001 and 2003 under Argentine GAAP has been
reversed in the reconciliation to U.S. GAAP. We are a holding company whose only asset is our 98.21% equity interest in
Petrobras Energía. We were organized as a result of a spinoff of Petrobras
Energía shares by Sudacia S.A., effective July 1, 1998. We acquired control of
Petrobras Energía on January 25, 2000 as a result of the completion of an
exchange offer of our Class B shares for 69.29% of Petrobras Energías
outstanding common stock. Prior to January 25, 2000, our only asset was a
minority interest in Petrobras Energía. Our financial data relating to the fiscal years ended December 31, 2003,
2002 and 2001 set forth below have been derived from our financial statements
included in this annual report. Our financial statements as of and for the
years ended December 31, 2002 and December 31, 2001 have been restated to
reflect changes in generally accepted accounting principles in Argentina, which
we refer to as Argentine GAAP. See Item 5. Operating and Financial Review
and ProspectsCritical Accounting Policies. Our balance sheet as of December
31, 2003 and 2002 and the related consolidated statements of income, changes in
shareholders equity and cash flows for each of the three fiscal years ended
December 31, 2003, 2002, 2001 included in this annual report have been audited
by Pistrelli, Henry Martin y Asociados S.R.L., a member firm of Ernst & Young
Global. Selected financial data for the fiscal years ended December 31, 2000
and 1999 has not been restated to reflect the changes in Argentine GAAP, and
accordingly are not comparable to the financial data for the fiscal years ended
December 31, 2003, 2002 and 2001. Argentine law does not require that we
restate these financial statements and any such restatement cannot be prepared
without unreasonable effort or expense. Due to the inflationary environment in Argentina in 2002, and the
conditions created by the Public Emergency Law, the Professional Council of
Economic Sciences of the City of Buenos Aires, or CPCECABA, approved on March
6, 2002 Resolution MD No. 3/02 applicable to financial statements for fiscal
years or interim periods ending on or after March 31, 2002. Resolution MD No.
3/02 required the reinstatement of the adjustment-for-inflation method of
accounting in financial statements, which provides that all recorded amounts
arising between August 31, 1995 and December 31, 2001 be stated in constant
currency as of December 31, 2001. On July 16, 2002, the Argentine government issued Decree No. 1,269/02,
instructing the National Securities Commission (Comisión Nacional de Valores),
which we refer to as CNV, and other regulatory authorities 2




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to issue the necessary regulations for the delivery to such authorities of
balance sheets or financial statements prepared in constant currency. On July
25, 2002, under Resolution No. 415/02, the CNV reinstated the requirement to
submit financial statements in constant currency. As the inflation rate
stabilized, on March 25, 2003, Decree No. 664/03 rescinded the requirement that
financial statements be prepared in constant currency. On April 8, 2003, the
CNV issued Resolution No. 441/03 discontinuing inflation accounting as of March
1, 2003. In accordance with the above, for comparative purposes, our financial
statements for the fiscal years ended December 31, 2001 and 2002, were restated
in constant pesos as of February 28, 2003, based on changes in the Argentine
wholesale price index published by the National Institute of Statistics and
Census (Instituto Nacional de Estadísticas y Censas), which we refer to as the
INDEC. This price index does not reflect any specific variation in the price
of products and services sold by us, and, therefore, variations in gains
(losses) for both periods include positive or negative price variations that
may be higher or lower than the price variations for the products or services
sold by us. The selected financial data for the fiscal years ended December
31, 2000 and 1999 has also been restated in constant pesos as of February 28,
2003. In accordance with the procedure set forth in Technical Resolutions Nos. 4
and 19 of the Argentine Federation of Professional Councils in Economic
Science, or FACPCE, we have consolidated line by line on a proportional basis
our financial statements with the companies in which we exercise joint control.
See Item 5. Operating and Financial Review and ProspectsOverview. In the
consolidation of companies over which we exercise joint control, the amount of
the investment in the subsidiaries under joint control and the interest in
their income (loss) and cash flows are replaced by our proportional interest in
the subsidiarys assets, liabilities and income (loss) and cash flows. Petrobras Energía Participacioness net income per share under Argentine
and U.S. GAAP was calculated as follows:  
    
    diluted net income per share was calculated by dividing
net income by the average number of shares outstanding during each
year (assuming all Class A shares are converted into Class B
Shares);
    
    for 2003 and 2002, net income per share was calculated by
dividing net income by the average number of shares outstanding
during each year. As of October 2002, all outstanding
Class A shares were converted into Class B shares;
    
    for 2001 and 2000, basic net income per Class A share was
calculated by dividing net income by the sum of (1) the average
number of Class A shares outstanding during 2001 and 2000,
respectively, and (2) the average number of Class B shares
outstanding during 2001 and 2000, respectively, multiplied by 1.5;
and
    
    for 2001 and 2000, basic net income per Class B share has
been calculated by multiplying (A) the quotient attained by
dividing net income by the sum of (1) the average number of Class
A shares outstanding during 2001 and 2000, respectively, and (2)
the average number of Class B shares outstanding during 2001 and
2000, respectively, multiplied by 1.5(B) by 1.5. Our basic net income per share for the fiscal years 2001 and 2000 was
calculated in the manner described above because Class B shares were entitled
to dividends equal to 150% of dividends that were paid with respect to Class A
shares. 3




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Income Statement Data Year Ended December 31,2003
    
    2002(1)
    
    2001(1)
    
    2000(1) (2)
    
    1999(1) (2)(in millions of pesos, except for per share amounts, share capital and operating information oras otherwise indicated)Income Statement DataArgentine GAAP:Net sales
    
    
    5,494
    
    
    
    5,106
    
    
    
    5,170
    
    
    
    3,185
    
    
    
    Cost of sales
    
    
    (3,386
    )
    
    
    (3,284
    )
    
    
    (3,347
    )
    
    
    (2,161
    )
    
    
    Gross profit
    
    
    2,108
    
    
    
    1,822
    
    
    
    1,823
    
    
    
    1,024
    
    
    
    Administrative and selling expenses
    
    
    (559
    )
    
    
    (609
    )
    
    
    (665
    )
    
    
    (385
    )
    
    
    Exploration expenses
    
    
    (196
    )
    
    
    (58
    )
    
    
    (41
    )
    
    
    (13
    )
    
    
    Other exploitation (expense) income, net
    
    
    (121
    )
    
    
    (28
    )
    
    
    23
    
    
    
    22
    
    
    
    Exploitation income
    
    
    1,232
    
    
    
    1,127
    
    
    
    1,140
    
    
    
    648
    
    
    
    Equity in earnings of affiliates
    
    
    163
    
    
    
    (638
    )
    
    
    119
    
    
    
    189
    
    
    
    143Financial income (expense) and holding
gains (losses)
    
    
    (417
    )
    
    
    (1,827
    )
    
    
    (573
    )
    
    
    (325
    )
    
    
    Other (expense) income, net
    
    
    (421
    )
    
    
    (187
    )
    
    
    (88
    )
    
    
    132
    
    
    
    Income (loss) before income tax and
minority interest in subsidiaries
    
    
    557
    
    
    
    (1,525
    )
    
    
    598
    
    
    
    644
    
    
    
    143Income tax provision
    
    
    (18
    )
    
    
    (82
    )
    
    
    (385
    )
    
    
    (41
    )
    
    
    Minority interest in subsidiaries
    
    
    (158
    )
    
    
    28
    
    
    
    (112
    )
    
    
    (15
    )
    
    
    Net income (loss)
    
    
    381
    
    
    
    (1,579
    )
    
    
    101
    
    
    
    588
    
    
    
    143Basic net (loss) income per share:Class A (3)
    
    
    
    
    
    
    
    
    
    
    0.035
    
    
    
    0.215
    
    
    
    0.323Class B
    
    
    0.179
    
    
    
    (0.744
    )
    
    
    0.053
    
    
    
    0.322
    
    
    
    Diluted net (loss) income per share
    
    
    0.179
    
    
    
    (0.744
    )
    
    
    0.047
    
    
    
    0.288
    
    
    
    Number of shares outstanding (millions):Class A(3)
    
    
    
    
    
    
    
    
    
    
    628
    
    
    
    628
    
    
    
    628Class B
    
    
    2,132
    
    
    
    2,132
    
    
    
    1,504
    
    
    
    1,504
    
    
    
    U.S. GAAP:Net sales
    
    
    5,078
    
    
    
    5,182
    
    
    
    4,630
    
    
    
    3,343
    
    
    
    Operating income
    
    
    622
    
    
    
    830
    
    
    
    853
    
    
    
    864
    
    
    
    Income (loss) from continuing
operations(5)
    
    
    109
    
    
    
    (1,868
    )
    
    
    (2,254
    )
    
    
    286
    
    
    
    242Income (loss) from discontinued operations
    
    
    (39
    )
    
    
    135
    
    
    
    12
    
    
    
    38
    
    
    
    0.547Cumulative effect of changes in
accounting principles
    
    
    30
    
    
    
    179
    
    
    
    
    
    
    
    
    
    
    
    Net income (loss)(4)
    
    
    100
    
    
    
    (1,554
    )
    
    
    (2,266
    )
    
    
    324
    
    
    
    242Basic net (loss) income per shareClass A:(3)
    
    
    
    
    
    
    
    
    
    
    (0.786
    )
    
    
    0.119
    
    
    
    0.547Class B:
    
    
    0.047
    
    
    
    (0.729
    )
    
    
    (1.179
    )
    
    
    0.178
    
    
    
    Diluted net (loss) income per share
    
    
    0.047
    
    
    
    (0.729
    )
    
    
    (1.063
    )
    
    
    0.157
    
    
    
    Basic net (loss) income per share:Class A:(3)Continuing Operations
    
    
    
    
    
    
    
    
    
    
    (0.782
    )
    
    
    0.105
    
    
    
    0.323Discontinued Operations
    
    
    
    
    
    
    
    
    
    
    (0.004
    )
    
    
    0.014
    
    
    
    Class B:Continuing Operations
    
    
    0.051
    
    
    
    (0.876
    )
    
    
    (1.172
    )
    
    
    0.157
    
    
    
    Discontinued Operations
    
    
    (0.018
    )
    
    
    0.063
    
    
    
    (0.006
    )
    
    
    0.021
    
    
    
    Cumulative effect of changes
in accounting principles
    
    
    0.014
    
    
    
    0.084
    
    
    
    
    
    
    
    
    
    
    
    
   (1)
    
    Expressed in constant pesos as of
February 28, 2003, except share capital
and operating information.(2)
    
    Selected financial data for the fiscal years ended December 31, 2000 and
1999 has not been restated to reflect recent changes in Argentine GAAP,
and accordingly are not comparable to the financial data for the fiscal
years ended December 31, 2003, 2002 and 2001. See Item 5. Operating and
Financial Review and ProspectsCritical Accounting Policies.(3)
    
    As of October 2002, there are no Class A shares outstanding.(4)
    
    As of January 1, 2002, we have applied SFAS No. 142, Goodwill and Other
Intangible Assets, effective as of January 1, 2002, and SFAS No. 143, Accounting for Asset Retirement
Obligations, effective as of January 1, 2003. If the new standards had been effective and applied before
January 1, 2001, net income (loss) for the years ended December 31, 2003,
2002 and 2001, would have been 70; (1,723) and (2,265), respectively.(5)
    
    After minority interest in subsidiaries and income tax (expense)
benefit. 4




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Balance Sheet Data Year Ended December 31,2003
    
    2002(1)
    
    2001(1)
    
    2000(1) (2)
    
    1999(1) (2)(in millions of pesos, except for per shareamounts, share capital and operating information or asotherwise indicated)Argentine GAAPConsolidated Balance SheetAssetsCurrent AssetsCash
    
    
    153
    
    
    
    93
    
    
    
    98
    
    
    
    59
    
    
    
    Investments
    
    
    802
    
    
    
    664
    
    
    
    1,254
    
    
    
    543
    
    
    
    Trade receivables
    
    
    886
    
    
    
    784
    
    
    
    1,108
    
    
    
    908
    
    
    
    Other receivables
    
    
    861
    
    
    
    734
    
    
    
    397
    
    
    
    470
    
    
    
    Inventories
    
    
    319
    
    
    
    356
    
    
    
    346
    
    
    
    374
    
    
    
    Other assets
    
    
    3
    
    
    
    178
    
    
    
    
    
    
    
    
    
    
    
    Total current assets
    
    
    3,024
    
    
    
    2,809
    
    
    
    3,203
    
    
    
    2,354
    
    
    
    Non-current AssetsTrade receivables
    
    
    36
    
    
    
    21
    
    
    
    21
    
    
    
    7
    
    
    
    Other receivables
    
    
    131
    
    
    
    220
    
    
    
    370
    
    
    
    162
    
    
    
    Inventories
    
    
    61
    
    
    
    39
    
    
    
    240
    
    
    
    205
    
    
    
    Investments
    
    
    1,284
    
    
    
    1,103
    
    
    
    1,341
    
    
    
    2,750
    
    
    
    1,627Property, plant and equipment
    
    
    11,559
    
    
    
    10,433
    
    
    
    11,633
    
    
    
    6,572
    
    
    
    Other assets
    
    
    43
    
    
    
    24
    
    
    
    63
    
    
    
    11
    
    
    
    Total non-current assets
    
    
    13,114
    
    
    
    11,840
    
    
    
    13,668
    
    
    
    9,707
    
    
    
    1,627Total assets
    
    
    16,138
    
    
    
    14,649
    
    
    
    16,871
    
    
    
    12,061
    
    
    
    1,627LiabilitiesCurrent liabilitiesAccounts payable
    
    
    860
    
    
    
    651
    
    
    
    852
    
    
    
    547
    
    
    
    Short-term debt
    
    
    3,204
    
    
    
    1,543
    
    
    
    3,501
    
    
    
    1,625
    
    
    
    Payroll and social security taxes
    
    
    93
    
    
    
    76
    
    
    
    99
    
    
    
    75
    
    
    
    Taxes payable
    
    
    172
    
    
    
    133
    
    
    
    145
    
    
    
    138
    
    
    
    Other current liabilities
    
    
    423
    
    
    
    372
    
    
    
    563
    
    
    
    97
    
    
    
    Total current liabilities
    
    
    4,752
    
    
    
    2,775
    
    
    
    5,160
    
    
    
    2,482
    
    
    
    Non-current liabilitiesAccounts payable
    
    
    7
    
    
    
    9
    
    
    
    4
    
    
    
    20
    
    
    
    Long-term debt
    
    
    5,098
    
    
    
    6,130
    
    
    
    4,114
    
    
    
    3,100
    
    
    
    Other liabilities
    
    
    279
    
    
    
    641
    
    
    
    368
    
    
    
    303
    
    
    
    Reserves
    
    
    277
    
    
    
    86
    
    
    
    61
    
    
    
    55
    
    
    
    Total non-current liabilities.
    
    
    5,661
    
    
    
    6,866
    
    
    
    4,547
    
    
    
    3,478
    
    
    
    Total liabilities
    
    
    10,413
    
    
    
    9,641
    
    
    
    9,707
    
    
    
    5,960
    
    
    
    Transitory DifferencesMeasurement of derivative
financial instruments designated
as effective hedge
    
    
    (18
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Foreign currency translation
    
    
    (56
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total transitory differences
    
    
    (74
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Minority interest in subsidiaries
    
    
    966
    
    
    
    556
    
    
    
    1,133
    
    
    
    149
    
    
    
    Total Shareholders Equity
    
    
    4,833
    
    
    
    4,452
    
    
    
    6,031
    
    
    
    5,953
    
    
    
    1,627Total liabilities and
shareholders equity
    
    
    16,138
    
    
    
    14,649
    
    
    
    16,871
    
    
    
    12,062
    
    
    
    1,627Capital Stock
    
    
    2,132
    
    
    
    2,132
    
    
    
    2,132
    
    
    
    2,132
    
    
    
    628Dividends(3)per Class A share
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.0208
    
    
    
    0.0238per Class B share
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.0317
    
    
    
    U.S. GAAP
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total assets
    
    
    14,508
    
    
    
    16,108
    
    
    
    20,264
    
    
    
    15,794
    
    
    
    Shareholders equity
    
    
    4,523
    
    
    
    4,499
    
    
    
    6,403
    
    
    
    8,406
    
    
    
    1,508
   (1)
    
    Expressed in constant pesos as of
February 28, 2003, except share capital
and operating information.(2)
    
    Selected financial data for the fiscal years ended December 31, 2000 and
1999 has not been restated to reflect recent changes in Argentine GAAP,
and accordingly are not comparable to the financial data for the fiscal
years ended December 31, 2003, 2002 and 2001. See Item 5. Operating and
Financial Review and ProspectsFactors Affecting our Consolidated Results
of OperationsCritical Accounting PoliciesChange in Accounting
Standards.(3)
    
    Dividends declared in 2000 and 1999 as expressed in U.S. dollars would
equal amounts in historical pesos since the exchange rate between the peso
and the U.S. dollar was fixed at a one-to-one ratio during those years in
accordance with the Convertibility Law. 5




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EXCHANGE RATES Prior to December 1989, the Argentine foreign exchange market was subject
to exchange controls. Between April 1, 1991, when Law No. 23,928 and Decree
No. 529/91 (together referred to as the Convertibility Law) became effective,
and January 5, 2002, the peso was freely convertible into U.S. dollars at a
fixed one-to-one exchange rate. Pursuant to the Convertibility Law, the Central
Bank of Argentina, which we refer to as the Central Bank, had to (i) maintain a
reserve in foreign currencies, gold and certain public bonds denominated in
foreign currency equal to the amount of outstanding Argentine currency and (ii)
sell U.S. dollars to any requesting person at a fixed U.S.$1.00 to P$1.00
exchange rate. In addition, on January 12, 1995, the Central Bank issued
Communication A 2298 which provided that all exchange transactions made with
the Central Bank also had to be made at a fixed U.S.$1.00 to P$1.00 exchange
rate. On January 6, 2002, the Argentine Congress passed the Public Emergency and
Foreign Exchange System Reform Law No. 25,561, which superseded certain
provisions of the Convertibility Law, including the fixed one-to-one exchange
rate. This law granted the federal executive branch the power to set the
exchange rate between the peso and foreign currencies and to issue regulations
related to the foreign exchange market. On January 6, 2002, the executive
branch established a temporary dual exchange rate system. As of February 11,
2002, a single and free exchange market has been established for all exchange
transactions. Within this new exchange regime and for the purpose of
supporting the peso exchange rate, the Central Bank has intervened several
times in the exchange market by selling U.S. dollars. In light of a growing demand for U.S. dollars during the six months ended
June 30, 2002 and the shortage of U.S. dollars available to satisfy this
demand, the Argentine government adopted a series of measures to mitigate the
demand for U.S. dollars and increase its U.S. dollar reserve base. As a
result, (i) the export sector has had to exchange on a daily basis its
non-Argentine currency into Argentine pesos through the Central Bank, (ii) new
restrictions on the transfer of funds abroad were implemented, (iii) the
purchase of foreign exchange was limited and (iv) requirements relating to the
purchase of foreign currency from banks and exchange agencies became more
stringent. Under these guidelines, the demand from private parties for U.S.
dollars significantly declined and the Central Bank gradually started to
accumulate U.S. dollar reserves. In 2003, the balance of trade yielded a strong surplus, which, together
with the continuing default in partial foreign debt payments by the government,
caused an excess supply of foreign currency. As a result, the peso appreciated
significantly against the U.S. dollar during 2003, notwithstanding the Central
Banks efforts to curtail these effects on the exchange rate through numerous
currency purchases. The following table sets forth, for the periods indicated, the high, low,
average and period end exchange rates for the purchase of U.S. dollars,
expressed in nominal pesos per U.S. dollar. The Federal Reserve Bank of New
York does not report a noon buying rate for pesos. Exchange RateHigh
    
    Low
    
    Average(1)
    
    Period End(in pesos)Year Ended December 31,1999
    
    
    1.00
    
    
    
    1.00
    
    
    
    1.00
    
    
    
    1.002000
    
    
    1.00
    
    
    
    1.00
    
    
    
    1.00
    
    
    
    1.002001
    
    
    1.00
    
    
    
    1.00
    
    
    
    1.00
    
    
    
    1.002002
    
    
    3.90
    
    
    
    1.60
    
    
    
    3.14
    
    
    
    3.382003
    
    
    3.37
    
    
    
    2.73
    
    
    
    2.95
    
    
    
    2.94Three months ended March 31, 2004
    
    
    2.96
    
    
    
    2.85
    
    
    
    2.90
    
    
    
    2.86Latest Six MonthsDecember, 2003(2)
    
    
    2.99
    
    
    
    2.94
    
    
    
    2.96
    
    
    
    2.94January, 2004(2)
    
    
    2.93
    
    
    
    2.85
    
    
    
    2.89
    
    
    
    2.89February, 2004(2)
    
    
    2.96
    
    
    
    2.92
    
    
    
    2.93
    
    
    
    2.92March, 2004(2)
    
    
    2.93
    
    
    
    2.86
    
    
    
    2.90
    
    
    
    2.86April, 2004(2)
    
    
    2.87
    
    
    
    2.80
    
    
    
    2.83
    
    
    
    2.86May, 2004(2)
    
    
    2.97
    
    
    
    2.84
    
    
    
    2.92
    
    
    
    2.97
   (1)
    
    Based on monthly average exchange rates.(2)
    
    Source: Banco de la Nación Argentina. On June 11, 2004, the exchange rate for the purchase of U.S. dollars
published by Banco de la Nación Argentina was P$2.97 per U.S. dollar. 6




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RISK FACTORS Factors Relating to Argentina Overview We are an Argentine corporation. As of December 31, 2003, approximately
64% of our total assets, 69% of our net sales, 58% of our combined crude oil
and gas production and 40% of our proved oil and gas reserves were located in
Argentina. Fluctuations in the Argentine economy and government actions
adopted by the Argentine government have had and will continue to have a
significant effect on Argentine private sector entities, including us.
Specifically, we have been affected and might be affected by inflation,
interest rates, the value of the peso against foreign currencies, price
controls, regulatory policies, business regulations, tax regulations and in
general by the political, social and economic scenario in and affecting
Argentina. The Argentine economy has experienced significant volatility. The Argentine economy has experienced significant volatility in recent
decades, characterized by periods of low or negative growth and high and
variable levels of inflation and currency devaluation. In 1988, 1989 and 1990,
the annual inflation rates were approximately 388%, 4,924% and 1,344%,
respectively, based on the Argentine consumer price index and approximately
422%, 5,386% and 798%, respectively, based on the Argentine wholesale price
index. As a result of inflationary pressures, the Argentine currency was
devalued repeatedly during the 1960s, 1970s and 1980s, and macroeconomic
instability led to broad fluctuations in the real exchange rate of the
Argentine currency relative to the U.S. dollar. To address these pressures,
the Argentine government during this period implemented various plans and
utilized a number of exchange rate systems and controls. In April 1991, the Argentine government launched a plan aimed at
controlling inflation and restructuring the economy, enacting the
Convertibility Law. The Convertibility Law fixed the exchange rate at one peso
per U.S. dollar and required that the Central Bank maintain reserves in gold
and foreign currency at least equivalent to the monetary base. Following the
enactment of the Convertibility Law, inflation declined steadily and the
economy experienced growth through most of the period from 1991 to 1997. In
the fourth quarter of 1998, however, the Argentine economy entered into a
recession that caused the gross domestic product to decrease by 3.4% in 1999,
0.8% in 2000, 4.4% in 2001 and 10.9% in 2002. As discussed below, in 2003, the
Argentine economy began to recover with GDP growing 8.7%. Argentina experienced a severe recession and significant political and social
instability during 2001 and 2002, and economic turmoil and recession may occur
again in the future. Beginning in the second half of 2001, Argentinas recession worsened
significantly. As the public sectors creditworthiness deteriorated, interest
rates reached record highs, bringing the economy to a virtual standstill. The
lack of confidence in the countrys economic future and its ability to sustain
the pesos parity with the U.S. dollar led to a massive withdrawal of deposits
from banks and capital outflows. To prevent further capital outflows, on December 1, 2001, the Argentine
government implemented a number of monetary and exchange control measures that
mainly included restrictions on the free disposition of funds deposited with
banks and the practical impossibility of making transfers of foreign currency
abroad, with the exception of certain transactions subject, in some cases, to
the previous authorization of the Central Bank. Foreign currency resulting
from export sales was required to be deposited with Argentine Banks, to the
extent no prior exemption mechanisms were in place. The measures were perceived as further paralyzing the economy for the
benefit of the financial system, and caused a sharp rise in social discontent,
ultimately triggering public protests, outbreaks of violence and the looting of
stores throughout Argentina. On December 20, 2001, after declaring a state of
emergency and suspending civil liberties, President Fernando de la Rúa tendered
his resignation to Congress. After a series of interim presidents, on January
1, 2002, Eduardo Duhalde was appointed by Congress at a joint session to
complete the remaining term of former President de la Rúa. 7




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The new President, among other measures, ratified the suspension of
payment of a portion of Argentinas sovereign debt declared by Interim
President Rodríguez Saá. On January 6, 2002, the Argentine Congress enacted the Public Emergency
Law, which introduced dramatic changes to Argentinas economic model and put an
end to the U.S. dollar-peso parity established since the enactment of the
Convertibility Law in 1991, leading to a significant devaluation of the
Argentine peso. The Public Emergency Law also empowered the federal executive branch of
Argentina to implement, among other things, additional monetary, financial and
exchange measures to overcome the economic crisis in the short term, such as
determining the rate at which the peso was to be exchanged into foreign
currencies. The federal executive branch implemented a number of far-reaching initiatives, which included:  
    
    pesification of certain assets and liabilities denominated in foreign currency and held in the country;
    
    rescheduling of bank deposits, with the subsequent ability
for owners of such deposits to receive certain dollar-denominated
government bonds maturing in ten years or peso-denominated
government bonds maturing in three or five years or bills with
specific terms in lieu of payment of such deposits;
    
    amendment of the charter of the Central Bank authorizing it
to issue money in excess of the foreign currency reserves, to grant
short-term loans to the federal government and to provide financial
assistance to financial institutions with liquidity or solvency
problems;
    
    issuance by the federal government of bonds to compensate
banks for losses resulting from the different pesification rates
applicable to deposits and U.S. dollar obligations assumed in
Argentina;
    
    pesification of all private agreements entered into as of
January 6, 2002 at the P$1=U.S.$1 exchange rate and subsequent
adjustment thereof by the Benchmark Stabilization Coefficient,
published by the Central Bank;
    
    pesification and elimination of indexing clauses on utility
rates, fixing those rates in pesos at the P$1=U.S.$1 exchange rate;
and
    
    implementation of taxes on hydrocarbon exports and certain
oil by-products, among others. Commercial and financial activities were virtually paralyzed in 2002,
further aggravating the economic recession, which included a 10.9% decline in
GDP in 2002. The crisis and the governments reactions to the crisis severely weakened
the Argentine banking system. A few small banks went into liquidation, and
credit became scarce for the public and private sectors. Towards the end of 2002, the Argentine government implemented different
measures aimed at unblocking the economy and abrogating certain restrictions to
gradually normalize the foreign exchange market and the commercial and
financial flow of foreign currency. On April 27, 2003, presidential elections took place. Since none of the
presidential candidates captured either 45% of the votes or a 10% margin of
victory, the former-President Carlos Menem and Néstor Kirchner, the two
candidates with the most votes in the first round, entered a run-off election
that was scheduled to have taken place on May 18, 2003. However, Carlos Menem
dropped out of the Argentine presidential election, and, thus, Nestor Kirchner
automatically became the countrys newly elected president. On May 25, 2003,
Mr. Kirchner took office as Argentinas president. In September 2003, Argentina and the International Monetary Fund, or IMF,
reached a three-year stand-by credit agreement, which set specific fiscal
targets for 2004. This new agreement guaranteed the refinancing of all
principal maturities of credit facilities granted by multilateral agencies. 8




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In 2003, the Argentine economy began to recover with GDP growing 8.7%.
This recovery, at first based almost exclusively on import substitution,
broadened as the level of consumption and investment increased. Reflecting the
economic recovery, Argentine stock exchange indices displayed great dynamism in
2003, and both labor indicators and salary purchasing power registered
consistent improvements during this year. The balance of trade exhibited a
strong surplus, favored by an increase in commodity prices, which, together
with the continuity of the partial foreign debt payment default, caused an
excess supply of foreign currency. The peso appreciated significantly against
the U.S. dollar during 2003, even as the Central Bank made numerous currency
purchases to attempt to maintain a high rate of exchange. Inflation was below
4% during 2003. Although the social and economic situation has improved, important issues
remain unresolved, such as renegotiating the external public debt and public
utility contracts, restructuring the financial system and redesigning the
federal fiscal regime. Argentine government actions concerning the economy,
including with respect to inflation, interest rates, price controls, foreign
exchange controls and taxes, have had, and may continue to have, a material
adverse effect on private sector entities, including us. We cannot provide any
assurance that future economic, social and political developments in Argentina,
over which we have no control, will not further impair our business, financial
condition, or results of operations or impair our ability to make payments of
principal and/or interest on our outstanding indebtedness. Argentinas insolvency and default on its public debt could limit or impair
Argentinas economic recovery. Because Argentina failed to meet fiscal targets, including those for the
fourth quarter of 2001, on December 5, 2001, the IMF suspended further
disbursements. This decision deepened the economic and financial crisis. On December 23, 2001, interim President Rodríguez Saá declared the
suspension of debt payments on approximately U.S.$63 billion of Argentinas
sovereign debt, which amounted to approximately U.S.$144.5 billion as of
December 31, 2001. On January 2, 2002, President Duhalde ratified this
decision. On September 22, 2003, the Argentine government presented bondholders with
a proposal for restructuring the countrys defaulted bonds at the IMF/World
Bank annual meeting in Dubai, United Arab Emirates. Under the proposal,
sovereign bonds issued before December 31, 2001 would be eligible for the
proposed bond exchange, which we refer to as Eligible Debt, maintaining a
strict equitable principle among all kinds and classes of creditors. The
Eligible Debt would comprise approximately U.S.$100 billion, issued under 152
different series of bonds, seven different currencies and eight different
governing laws. Past due interest payments since the early 2002 default would
not be paid, and principal would be reduced by 75%. The stated main objective
of the governments proposal is to restore solvency through improvements in the
Debt/GDP and Debt Service/Fiscal Revenues ratios, reaching a new debt profile
that would be consistent with Argentinas payment capacity. The proposal was
not well received by bondholders. In March 2004, within the framework of a second review of the three-year
agreement subscribed with the IMF, the government committed itself to taking
decisive steps towards the restructuring of the public debt. In this regard,
the federal executive branch issued a decree appointing the syndicate of banks
that will assist the government in the restructuring. On June 1, 2004, the Argentine government announced a new proposal to
restructure the countrys defaulted debt. This new proposal includes a plan to
pay accrued interest on the defaulted bonds for the period commencing on the
date the country defaulted on its sovereign debt until either December 31, 2003
or June 30, 2004 depending on the level of acceptance of the proposal, and an
option for existing bondholders to exchange their bonds for one of three types
of bonds, namely par, quasi-par and discount bonds, which have coupons pegged
to the countrys growth in GDP and with terms ranging from 20 to 32 years.
This offer has not been launched, and we cannot predict whether bondholders
will adhere to the offer, when and if launched. The government expects to
complete the exchange process before the end of the year. The Argentine governments current insolvency, its inability to obtain
financing and the uncertainties surrounding the restructuring process, which is
described as one of the most complex in history and has led and may continue to
lead to a growing number of lawsuits by creditors until a final agreement is
reached, may affect significantly the governments ability to implement reforms
and restore sustainable economic growth. This could further undermine the
maintenance of the economic recovery experienced during 2003 and may result in
recession, 9




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##### Table of Contents



higher inflation, greater unemployment and social unrest. If this
happens, our financial condition and results of operations would be adversely
affected. The devaluation of the peso creates greater uncertainty as to Argentinas
economic future. The peso has been subject to large devaluations in the past and may be
subject to significant fluctuations in the future. The Public Emergency Law put an end to ten years of U.S. dollar-peso
parity and authorized the Argentine government to set the exchange rate between
the peso and foreign currencies, and issue regulations related to foreign
exchange markets. After devaluing the peso, the Argentine government initially
established a dual exchange rate of P$1.40 per U.S. dollar for certain
transactions and a free-floating rate for all other transactions. This dual
system was later eliminated in favor of a single free-floating exchange rate
for all transactions. Since the end of the U.S. dollar-peso parity, the peso has fluctuated
significantly. As a result, the Central Bank has taken several measures to
stabilize the exchange rate and preserve its reserves. See Exchange Rates. The marked peso devaluation during 2002 adversely affected our results and
financial position. All of our financial debt and a significant portion of our
affiliates debt are denominated in U.S. dollars. Before the enactment of the
Public Emergency Law, our cash flow, usually denominated in U.S. dollars or
dollar-adjusted, provided a natural hedge against exchange rate risks. The new
Argentine regulatory framework, however, limited our ability to mitigate the
impact of the peso devaluation. Pesification of utility rates, regulatory
issues related to the renegotiation of pesified utility rates, new taxes on
hydrocarbon exports and the implementation of regulations to prevent an
increase in prices to final users in the domestic market had a significant
impact in such respect. As from the second half of 2002, domestic prices of the main commodities
have significantly recovered in line with export prices. In addition, we
aggressively pursued a trade policy of opening and consolidation of export
markets to capitalize on domestic and export price asymmetries. In light of
the above strategies and the strength of our foreign operations with a cash
flow primarily denominated in U.S. dollars, our exposure to peso fluctuations
has dropped, and we have substantially recovered our ability to naturally hedge
our cash exposure to U.S. dollar liabilities. We cannot assure you, however, that the Argentine government will not
adopt new regulations or make regulatory changes that prevent or limit us from
offsetting the risk derived from our exposure to the U.S. dollar. Inflation may escalate and undermine any hope for continued economic growth in
Argentina. On January 24, 2002, the Argentine government amended the charter of the
Central Bank to allow the Central Bank to print currency without having to
maintain a fixed and direct relationship to foreign currency and gold reserves.
This change allows the Central Bank to make short-term advances to the federal
government to cover its anticipated budget deficits and to provide assistance
to financial institutions with liquidity or solvency problems. There is considerable concern that, if the Central Bank prints currency to
finance public sector spending, to assist financial institutions in distress or
to prevent a further appreciation of the peso, significant inflation could
result. During 2002, the Argentine consumer price index increased 40.98%, and
the wholesale price index increased 118.2%. During 2003, within a
substantially different economic scenario, such indices increased only 3.7% and
2.0%, respectively. In the past, inflation has materially undermined the Argentine economy and
the governments ability to stimulate economic growth. The variability of
inflation in Argentina makes it impossible to estimate how our activities and
results of operations will be affected in the future. Sustained inflation in
Argentina, without a corresponding increase in the price of our products in the
local market, would have a negative effect on our results of operations and
financial position. 10




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Exchange controls may further impair our ability to service our foreign
currency-denominated debt obligations. After December 2001, the Argentine authorities implemented a number of
monetary and currency exchange control measures that included restrictions on
the withdrawal of funds deposited with banks and tight restrictions on foreign
transfers, including restrictions relating to the servicing of foreign debt,
with the exception of those related to foreign trade and other authorized
transactions. Although these control measures have been relaxed and, during
2003, the Central Bank issued a number of regulations aimed at gradually
normalizing the domestic exchange market, we cannot assure you as to how long
these more flexible regulations will be in effect or whether they will become
more restrictive again in the future. Pursuant to Decree No. 1589/89 relating to the deregulation of the
upstream oil industry, companies engaged in oil and gas production in Argentina
are free to sell and dispose of the hydrocarbons they produce, and are entitled
to maintain outside Argentina up to 70% of the foreign currency proceeds from
crude oil and gas exports. These companies are required to repatriate the
remaining 30% through the Argentine exchange markets. During 2002,
controversies arose among producers and the authorities regarding the
enforceability of the right to freely dispose of up to 70% of the proceeds from
foreign currency export sales. These controversies were the subject of legal
challenges, and many federal judges have pronounced on and recognized the prima
facie validity of producers rights. In December 2002, we filed with a federal
court of the Province of Santa Cruz, a temporary injunction against the federal
executive branch, requesting the maintenance of the status quo that allows us
to freely dispose of up to 70% of our export proceeds. This right was prima
facie admitted by the court. On December 31, 2002, Decree No. 2703/02,
effective as of January 1, 2003, was enacted. This decree recognized the right
of oil and gas producers to dispose of 70% of the proceeds from foreign
currency export sales, but had no provisions related to such right during 2002.
In order to avoid any uncertainty regarding the application of this right in
2002, in February 2003, we filed a civil action of certainty, requesting that
the court recognize our right to freely dispose up to 70% of our export
proceeds in 2002, based on the effectiveness of Decree No. 1589/89. This was
admitted prima facie by the court. If the Argentine government decides further to tighten its transfer
restrictions by, among other things, eliminating Decree No. 1589/89 or
otherwise, we may be unable to make principal or interest payments when they
become due. Limits on exports of hydrocarbons could lower our anticipated
dollar-denominated cash receipts. On May 23, 2002, the Argentine government enacted Decree No. 867/02
declaring a state of emergency in the supply of hydrocarbons in Argentina until
September 30, 2002 and empowering the Secretary of Energy to determine the
volume of crude oil and liquefied petroleum gas, which we refer to as LPG,
produced in Argentina that should be sold in the local market. In addition, by
Resolution No. 140/02, temporary limits were established for hydrocarbon
exports during the months of June, July, August and September of 2002.
Resolution No. 140/02 was repealed on July 26, 2002 by Resolution No. 341/02. Argentina is suffering an energy crisis. In light of this situation, the
Secretary of Energy issued Resolution No. 265/2004 on March 26, 2004, pursuant
to which limits on natural gas exports may be imposed and, in fact, some limits
have already been imposed. This resolution instructs the Undersecretary of
Fuels to create a program for the rationing of gas exports and for the
regulation of the use of transportation capacity. In compliance with this
instruction, the Undersecretary of Fuels issued Disposition No. 27/04
implementing this program. Both regulations were issued as temporary measures
in order to avoid a crisis in the local supply of natural gas and,
consequently, in the supply of electricity to the wholesale electricity market.
We do not believe that these measures will have a material adverse effect on
our results or financial condition, but we cannot assure you that this will be
the case. Additionally, in April of 2004, in order to facilitate the recovery of gas
prices, the Secretary of Energy entered into an agreement with natural gas
producers requiring them to sell a specified amount of gas in the local
regulated market for prices determined in accordance with a roadmap that
culminates with the expected complete deregulation of wellhead prices for
natural gas by January of 2007. See Item 4. Information About UsRegulation
of Our BusinessesThe Argentine Gas Industry and Regulatory
FrameworkAdjustment of the Price of National Gas in Wellhead. 11




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We cannot assure you that the Argentine government will not impose
additional export restrictions on hydrocarbons. If it were to do so, we would
receive lower dollar-denominated cash receipts, which might limit our ability
to service our U.S. dollar-denominated debt. Export taxes on our products have negatively affected, and may continue to
negatively affect, the profitability of our operations. Effective as of March 2002, the Argentine government adopted a 20% export
tax on crude oil exports and a 5% tax on exports of certain oil by products.
Diesel oils effective export tax from June until July 31, 2002 was 20%. In
May 2004, the Argentine government increased to 25% the export tax on crude oil
exports, increased the export tax on LPG oil exports to 20% and imposed a 20%
tax on all gas exports. We cannot assure you that the Argentine government will reduce the current
export tax rates or will not increase them further. We do not know the
governments future intentions in regard to export taxes. Price controls have affected, and may continue to affect, our results of
operations and capital expenditures. For the purposes of reducing inflationary pressures generated by the sharp
Argentine peso devaluation, the Argentine government issued a set of
regulations aimed at controlling the increase in prices to end users. These
regulations were particularly focused on the energy sector. Under the Public Emergency Law, our ability to increase the price of
energy and gas sold in the domestic market is limited, especially in connection
with sales agreements entered into with utility companies and energy sales in
the spot market. This limitation, within the context of the peso devaluation
and subsequent inflation, resulted in a substantial change in the economic and
financial balance of our energy and gas related businesses, significantly
affecting our operating results and prospects. As a result, gas investments,
especially at the Neuquén basin, were postponed. With respect to crude oil prices, in January 2003, at the federal
executive branchs request, hydrocarbon producers and refineries executed a
temporary agreement in connection with crude oil, gasoline and diesel oil price
stability in the domestic market. After successive renewals, the term of this
agreement was extended until May 2004. This agreement provided for crude oil
deliveries to be invoiced and paid based on the West Texas Intermediate Crude
reference price, or WTI, of U.S.$28.5 per barrel instead of the actual relevant
WTI. Any positive or negative difference between the actual relevant WTI, not
exceeding U.S.$36 per barrel, and the reference price would be paid out of any
balance generated in periods where the actual WTI is below U.S.$28.5 per
barrel. Refineries, in turn, would reflect the crude oil reference price in
domestic market prices. In February 2004, a new agreement
corresponding to the period beginning on March 1, 2004 and
ending on April 30, 2004 was reached between producers and
refineries, but the Secretary of Energy has not yet approved this
agreement because it contains a difference concerning the interest
rate to be used to calculate the debt between producers and refiners.
If the situation continues in the future, producers shall be forced
to reinvoice refiners in order to adjust prices. Notwithstanding this
situation, beginning in May 2004, hydrocarbon producers and refineries
have informally agreed that while
the WTI per barrel ranges between U.S.$32 and U.S.$42, crude oil deliveries
will be invoiced and paid based on a reference price equal to (i) 86% of the
WTI as long as this price does not exceed U.S.$ 36 per barrel, or (ii) 80% of
the WTI, in cases where this price exceeds U.S.$36 per barrel. With respect to electricity generation, the Argentine government
implemented the pesification of dollar-denominated prices in the wholesale
electricity market, and through Resolution No. 08/02 of the Secretary of
Energy, set a price cap for the energy sold in the spot market of P$120/MWh.
This is the maximum price for an efficient generation company, regardless of
the actual marginal cost of electricity generation. Resolution No. 240/03
effective since August 15, 2003, established that the cost of liquid fuels in
thermal power plants and water in hydroelectric plants was excluded from the
determination of electricity prices. This resolution was temporarily suspended
on October 9, 2003, and then put into effect again by the Secretary of Energy
on January 30, 2004. These measures represent deviations from the marginal cost
system implemented in 1992 and from the provisions in Electricity Law No.
24,065, which allow for an adequate return on investment in a competitive
environment based on a marginal price system. Thermal power generating
companies, however, may cover variable operating costs through certain
mechanisms. See Item 4. Information About UsRegulation of Our BusinessesThe
Argentine Electricity Industry and Regulatory FrameworkDispatch. In addition, due to the governments decision to suspend the seasonal
increases in electricity prices, electricity prices have not reflected
production costs. As a result, the Stabilization Fund (Fondo de
Estabilización) was exhausted and Compañia
Administradora del Mercado Eléctrico
S.A., or CAMMESA, which we refer to as the 12




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Wholesale Market Manager, could not settle accounts with market agents.
As a palliative measure, in December 2003 the Argentine government made a P$150
million contribution to the Stabilization Fund under Decree No. 1181/03 and on
March 2004, under Decree No. 365/04, made a further contribution of P$200
million. In February 2004, in an effort to restore the Stabilization Fund, the
government reinstated the seasonal adjustment in electricity prices for the
February-April 2004 period, but on May 2004, the government suspended seasonal
adjustments again. As of May 2004, the Stabilization Fund has a deficit of
P$650 million. In light of the uncertainties prevailing in Argentina, we have made
progress in renegotiating the terms and conditions of gas and electricity sale
agreements entered into with industrial clients in order to adjust prices to
reflect the new economic conditions. In this regard, we have reached
commercial agreements that gradually increase sale prices to reflect the
effects of the peso devaluation. We, as well as others, have attempted to
maximize export opportunities in an effort to capitalize on variations between
domestic and export prices, by effectively encouraging the opening and
consolidation of new markets. During 2003, we started to export gas to Chile
from the Austral basin. The Argentine government is expected to gradually restore the economic and
financial balance in the natural gas and electricity sectors, in compliance
with the respective regulatory frameworks. However, our results and capital
expenditure plans may be negatively affected if the Argentine government
continues issuing additional decrees or exerting political pressure to curb
price increases or control exports or if it applies its regulatory emergency
authority to fix prices or adopts other laws to stabilize prices or supply. The pesification of utility rates has affected and may continue to affect the
operations of our affiliated utility companies. The Public Emergency Law pesified tariffs for public utility services and
prohibited the increase of such tariffs based on indexation factors. Tariffs
were converted into pesos at a P$1=U.S.$1 parity. Pursuant to this law, the
Argentine federal executive branch is authorized to renegotiate the terms of
contracts relating to the provision of public utility services. The criteria
for such renegotiation must take into account: (i) the impact of tariffs on
economic competitiveness and on income distribution, (ii) the quality of the
service and capital expenditure programs, in cases where they were required in
the contracts, (iii) the interest of the customers and accessibility to the
services, (iv) the safety of the systems and (v) the companies profitability. On February 12, 2002, the federal executive branch issued Decree No.
293/02 under which the Ministry of Economy was empowered to renegotiate utility
contracts and a Public Works and Services Contract Renegotiation Committee,
which we refer to as the Renegotiation Committee, was created, the members of
which, among them a representative of customers, were appointed through Decree
No. 370/02. The Renegotiation Committees mission is to provide advice to and
assist the Ministry of Economy, which must submit a renegotiation proposal to
the federal executive branch or otherwise recommend the termination of
concession contracts. Such proposal or recommendation is subsequently
submitted to the relevant congressional commissions for analysis. The
Renegotiation Committee, however, failed to achieve its intended goal due to
successive actions to protect constitutional rights (acciones de amparo)
brought by the Argentine National Ombudsman (Defensor del Pueblo de la Nación). In order to secure the supply of utilities, and in line with the
renegotiation process, the federal executive branch authorized an increase in
gas and electricity rates under Decree No. 146/03. Such increase was 10% for
Transportadora Gas del Sur S.A., or TGS, 9% for Edesur S.A., or Edesur, and 22%
for Compañía de Transporte de Energía Eléctra en Alta Tensión Transener S.A.,
or Transener and 18% for Empresa de Transporte de Energía Eléctrica por
Distribución Troncal Sociedad Anónima Transba S.A. or Transba The Argentine
National Ombudsman and consumer organizations challenged the increase. On
February 25, 2003, a Court of First Instance issued a provisional remedy and
suspended the rate increase authorized under Decree No. 146/03. In July 2003, the Utilities Contract Renegotiation and Analysis Committee,
or UNIREN, was created within the scope of the Ministries of Economy and
Production and Federal Planning, Public Investment and Services. UNIREN, as
successor of the Renegotiation Committee, was created to, among other things,
assist in the contract renegotiation process for public works and services,
subscribe comprehensive or partial agreements and submit regulatory projects
concerning temporary price and rate adjustments. To date, no substantial
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On October 1, 2003, the Argentine Congress enacted a law whereby the term
granted to the federal executive branch under the Public Emergency Law to
renegotiate contracts with privatized utility companies was extended until
December 2004. In addition, under such law the federal executive branch may
fix temporary utility rates until completion of the renegotiation process. We cannot anticipate the outcome of the current renegotiation process. If
utility companies contracts are renegotiated, the new terms could be less
favorable than the current terms. If so, the results of operations and
financial position of utility companies could be severely affected. Even if
these contracts are renegotiated with more favorable terms, such terms could be
insufficient to prevent a material adverse effect on the results of operations
and financial position of utility companies. The problems faced by our
affiliated utilities have adversely impacted our net income and our ability to
receive dividends from these companies. Whereas we received dividends from
these companies in 2000 and 2001, we did not receive dividends from them in
2002 or 2003. See Item 5. Operations and Financial Review and
ProspectsOverview. The devaluation and pesification of utility rates have resulted in payment
defaults by some of our affiliates. The new macroeconomic scenario after enactment of the Public Emergency Law
deeply changed the economic and financial balance of utility companies. The
tremendous effect of devaluation, within a context where revenues remained
unchanged as a consequence of the pesification of rates and financial debts
with foreign creditors were primarily denominated in foreign currency, affected
the financial position, results of operations and cash generation ability of
utility companies. CIESA and Transener have defaulted on their debt and are attempting to
restructure it. On February 24, 2003, TGS started an overall restructuring
process for substantially all its financial debt. This process mainly aims at
extending short-term maturities, modifying certain financial restrictions
contemplated in financial agreements and adjusting interest rate and repayment
terms to align cash flows required to repay the debt with its expected cash
flows, with no principal reductions. TGS first attempted to reach an agreement with creditors through a
pre-packaged out-of-court reorganization agreement (Acuerdo Preventivo
Extrajudicial), or APE, which is a new structure permitted by Argentine law.
An APE essentially permits a company to restructure its debt pursuant to an
agreement approved by two-thirds of its creditors, which we refer to as the
Requisite Majority, and which is then endorsed by an Argentine Court. Since
TGS could not achieve this Requisite Majority, on May 14, 2003, it withdrew the
restructuring proposal and simultaneously announced the postponement of the
payment of interest on its financial debt. TGS is currently conducting
negotiations with its main creditors. Transener has been notified of a request by one of its creditors for the
commencement of involuntary bankruptcy proceedings against it and of requests
for attachment of approximately U.S.$11.5 million in accounts receivable from
CAMMESA. Transener is pursuing all reasonable defenses to protect its rights. The management of our different affiliated utility companies have
formulated and implemented an action plan aimed at offsetting the negative
impact of the current conditions. We cannot assure you that these plans will
prove to be successful or that these plans will help meet the companies
established goals. We could lose some or all of our ownership in these companies if any
necessary debt restructuring is unsuccessful and creditors proceed against the
assets of the defaulting affiliates, although the outcome of such procedure is
uncertain due to the procedural difficulties of Argentine bankruptcy courts and
laws relating to the ownership of Argentine utilities. In addition, as part of
a debt restructuring, creditors may require an equity stake in these companies,
thereby reducing our equity interest. If our equity interest were reduced, our
share of any future cash dividends and equity in earnings from affiliates from
these companies would decrease in line with the decrease in our ownership
interest. 14




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Factors Relating to Venezuela Political and social events in Venezuela may negatively affect our Venezuelan
operations. Operations in Venezuela have become an important part of our businesses.
In 2003, production in Venezuela accounted for 27.3% of the total average
production in barrels of oil equivalent. As of December 31, 2003, a
significant share of our total combined proved reserves was located in
Venezuela. Accordingly, our operations are affected by political developments
in Venezuela. Effective January 2002, the Venezuelan government adopted a new law
whereby royalty payments increased from 16.67% to 30%. This had a significant
adverse impact on the results of certain of our fields. In February 2002, as a result of the capital drain that had started a few
years before and the fall in economic activity caused by production cuts
mandated by the Organization of Petroleum Exporting Countries, or OPEC,
Venezuela was forced to abandon the exchange rate system that it had maintained
for some time. Venezuelas currency, the Bolivar, was allowed to float against
the U.S. dollar, leading to a significant devaluation. In April 2002, the President of Venezuela, Hugo Chávez, was removed from
power but subsequently returned to the presidency after a few days. He was
removed by the military after heavy political backlash over the implementation
of his social programs and decision to change management at Petróleos de
Venezuela S.A., or PDVSA, the state-owned oil company. The political crisis deepened in the last months of 2002, with less
support for President Chávez and increased violence. In December 2002, in the
face of Chávezs refusal to permit a referendum that would determine whether to
accelerate elections, a general strike organized by the Coordinadora
Democrática was initiated. A number of sectors, including PDVSA workers,
joined the strike; as a result, oil production plummeted. The strike was
accompanied by increased capital drains, loss of bank deposits and a material
deterioration of the countrys tax situation as a result of reduced tax
revenues. Credit rating agencies downgraded Venezuelas debt ratings. Taking
into account the economic deterioration brought by the strike, opposition
forces decided to lift the strike in February 2003. The government, in turn,
was able to resume control over PDVSA and to partially reinstate production,
after dismissing a large number of PDVSA employees. After discussions between the government and the opposition resumed, an
agreement was reached to hold a referendum on President Chávezs future tenure.
In June 2004, the Venezuelan Justicia Electoral determined that the opposition
to Hugo Chávez had gathered the necessary support to force a referendum on
Chávezs mandate, which is scheduled to occur in August of 2004. New riots and
social protests are expected. Amid this continuing struggle, the economy has suffered. A significant
loss in reserves and capital flight was recorded. In addition, the country was
plunged into in an unprecedented recession, which significantly increased
inflation, unemployment and violence rates. For the reasons mentioned above, the government adopted emergency measures including:  
    
    closing the foreign exchange market and implementing strict exchange controls;
    
    implementing price controls over basic goods;
    
    importing fuel; and
    
    increasing governmental control over PDVSA. While these measures enabled a gradual recovery of reserves as oil
production returned to normal levels, with high crude oil prices, the
restrictions resulted in a sharp decline in overall imports and affected the
general level of activity, particularly in the non-oil sector. Venezuela
experienced both shortage problems and the emergence of a black market. The
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By the end of 2003, Venezuela experienced:  
    
    the establishment of a foreign exchange parallel market with
a U.S. dollar exchange rate close to 3,000 Bolivars per U.S. dollar
as compared to an official rate of 1,600 Bolivars per U.S. dollar,
which was reflected in the price level;
    
    an 11% decline in GDP, resulting in a decline of over 20% in the last two years;
    
    an unemployment rate close to 20%; and
    
    inflation of approximately 27%. We are required to deliver all of our oil equivalent production in
Venezuela to PDVSA, and accordingly PDVSA has become one of our most important
customers. Since oil production activities in Venezuela are closely monitored by the
government through PDVSA, our operations in Venezuela could be affected by
political and social riots, including strikes and other forms of political
protest, similar to those experienced during the first quarter of 2003. Due in
part to the oil strike at PDVSA in 2002, our daily sales volume of oil
equivalent decreased 12.5% during 2003. In addition to these effects,
Venezuelas complex crisis could have other unforeseen effects, which may have
an adverse impact on our results of operations. The Venezuelan government may, at its own discretion, decide to enact
additional laws to modify the terms and conditions of our operating agreements
that could negatively impact our operations. Such changes may include
increased royalty payments or production cuts. In addition, since Venezuela is
an OPEC member country, we are subject to any decision related to production
cuts that OPEC may adopt. Factors Relating to Us Decline in oil prices affect our operating results and capital expenditures. Oil prices in Argentina and other Latin American countries reflect world
market prices. World oil prices are determined by global supply and demand
factors over which we have no control. Oil prices have fluctuated widely over
the last ten years. During 2003, 2002 and 2001, the average WTI was U.S.$31,
U.S.$26 and U.S.$26 per barrel, respectively. Because a substantial amount of our revenue is derived from sales of oil,
any decline in the price of oil may affect our operating results and the amount
and timing of our projected capital expenditures. Although we regularly
evaluate the opportunity to enter into derivative transactions to mitigate our
exposure to changes in the price of crude oil and crude oil by-products, if oil
prices decline significantly, we may have to dramatically cut capital
expenditures, and this could adversely affect our production forecasts in the
medium term and our hydrocarbon reserve estimates. The lack of financing alternatives may impact the execution of our strategic
business plan. After the default on the Argentine sovereign debt, Argentine companies
have had significantly fewer opportunities to access international credit
markets. Non-Argentine financial markets and institutions are reluctant to
lend additional capital and grant loans to Argentine entities and companies.
In addition, as a result of the default in payment of loans and other financial
liabilities in Argentina on the part of the government and private entities and
the massive withdrawal of money from accounts opened with financial
institutions in Argentina and from the Argentine financial market in general,
the opportunities to obtain financing at attractive rates in Argentina continue
to be very limited. Although we have thus far been able to fulfill our financings needs
throughout the Argentine crisis (we were the first Argentine company to place a
new issuance of debt which was not associated or part of a debt restructuring
in the international capital markets since the Argentine governement defaulted
on its debt), the prospects for all Argentine companies, including us, of
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continue to be challenging. If we are unable to access the financial
markets, we may have to reduce our projected capital expenditures in order to
meet our contractual obligations. This may in turn affect the implementation
of our business plan for 2004 and our long-term prospects. Production of oil in Block 31 in Ecuador
is significantly delayed, and this delay has and will continue to
affect our results. Further delays could result in an increase in our
operating losses related to our group of assets in Ecuador. Our oil fields in an area referred to as Block 31 in Ecuador are located
in the Amazon jungle in the northeastern part of the country where no
significant infrastructure currently exists for the production of hydrocarbons. Investments of approximately U.S.$800 million are estimated to be required
for Block 31s development in full. Initial investments in the amount of
approximately U.S.$150 million must be effectively made before the start of the
production phase, which is currently scheduled for 2006. The decline in our
capital expenditures following the Argentine crisis resulted in significant
delays with respect to our original plan for Block 31s development. Our
investments are dependent upon our ability to increase capital expenditures in
future periods and to access the financial markets. Future oil production in Block 31 will be shipped through a heavy crude
oil pipeline known as Oleoducto de Crudos Pesados. We entered into a contract
with Oleoducto de Crudos Pesados Ltd., or OCP, whereby 80,000 barrels per day
of oil transportation capacity was committed on a ship or pay basis for a
15-year term as from the date OCP starts operations. Our annual cost
associated with this oil transportation capacity is approximately P$220
million. Transportation capacity costs are billed by OCP on a monthly
basis and charged to expensed by us as incurred. OCP started commercial operations on November 10, 2003. As of that date,
we have had to comply with our contractual obligations with respect to our
committed acquired capacity by paying a fee which as of December 31, 2003 was
estimated to be P$7.53 per barrel. We currently estimate that, during the contracts term, oil production
will be lower than our committed transportation capacity. We have reached this
belief based on, among other reasons, the delays involved in the development of
Block 31, the new schedule of investments required for the joint development of
Blocks 18 and 31 and a revised outlook on the potential of Block 31.
As of December 31, 2003, we have recorded an impairment allowance of P$321 million
to adjust the book value of a group of assets in Ecuador to its
recoverable value. If we cannot increase capital expenditures in future periods, production
from Block 31 will be delayed further. In addition, once development projects
are commenced, unforeseen delays in our drilling activities may occur, which
could result in significant additional delays in production. See Our
drilling activities may be adversely affected by events beyond our control.
Furthermore, we cannot assure you that, if required investments were made,
future production levels would reach estimated production levels. As a result
of these scenarios, we may have future operating losses to the extent
that our revenues do not compensate our operating expenses and such
losses shall be recognized when incurred. Our oil and gas proved reserve estimates are not 100% accurate and may be
subject to revision. We estimate our proved developed crude oil and natural gas reserves by
using geological and engineering data to demonstrate with reasonable certainty
whether they are recoverable in future years from known reservoirs under
existing economic and operating conditions. These estimates are audited by
Gaffney, Cline & Associates, an international technical consulting firm for the
oil and gas industry. Nonetheless, reserve estimates are based, in part, on
subjective judgments and as a consequence are not 100% accurate, and, thus, may
be subject to revision. Crude oil and natural gas reserves are reviewed
annually to take into account production levels, field reviews, the addition of
new reserves from discoveries, new economic conditions and other factors.
Although we believe our proved reserve estimates fairly present the amount of
reserves available to us, proved reserve estimates could be materially
different from the quantities of crude oil and natural gas that are ultimately
recovered. 17




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We may not be able to replace our oil and gas reserves. The rate of production from oil and gas properties generally declines, and
the cost of such production generally increases, as reserves are depleted.
Without successful exploration and development activities or reserve
acquisitions, our proved reserves will decline as oil and gas are produced from
our existing proved developed reserves. We cannot guarantee that our
exploration, development and acquisition activities will result in significant
additional reserves or that we will continue to be able to drill productive
wells at acceptable costs. Our ability to replace our reserves is also
dependent upon our capital expenditures. In 2002, we reformulated our
investment plan and adopted a restrictive expense and investment policy. This
has significantly limited our reserve replacement ratio. Looking towards the future, we have limited capital resources to implement
an ambitious capital expenditure program. In addition, as long as the
financial debt remains unpaid, we must comply with a series of restrictions and
covenants, including restrictions on capital expenditure levels. Our drilling activities may be adversely affected by events beyond our control. Oil and gas drilling activities are subject to numerous risks, many of
which are beyond our control. Our operations may be curtailed, delayed or
canceled as a result of weather conditions, mechanical difficulties, shortages
or delays in the delivery of equipment and compliance with governmental
requirements. Drilling may involve unprofitable efforts, not only with respect
to dry wells, but also with respect to wells that are productive but do not
produce sufficient net revenues to return a profit after drilling, operating
and other costs. Completion of a well does not assure a return on the
investment or a recovery of drilling, completion and operating costs. Our oil and gas operations may be affected by standard industry operating
risks. Our operations are subject to all of the risks normally incident to the
operation and development of oil and gas properties and the drilling of oil and
gas wells, including the risk of fire, explosions, blow outs, pipe failure,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures or discharges of toxic gases. The occurrence of these
industry operating risks could cause us to suffer substantial losses, including
losses due to injury or loss of life, severe damage to or destruction of
property, natural resources and equipment, pollution or other environmental
damages and clean up responsibilities, and penalties and suspension of
operations. Our activities may be adversely affected by events in other countries in which
we do business. As we expand our operations in other countries, we may be increasingly
affected by the following factors and developments: political and economic
uncertainties; expropriation of property and cancellation or modification of
contract rights; regulatory changes; currency exchange fluctuations and other
risks arising out of the imposition of foreign investment or capital controls,
and risks of loss in countries due to civil strife, acts of war, guerilla
activities and insurrection. Our operations run the risk of causing environmental damage, and any changes in
environmental laws may increase our operational costs. The nature of some of our operations forces us to undertake risks that may
cause environmental as well as other types of damage. In 2003, we hired an international consulting firm to perform an
environmental and safety audit on our operations. The report ratified the high
environmental standards under which our operations are performed and also
identified a series of actions necessary for our operations to be in full
compliance with current laws and regulations, to satisfy future requirements
and, in the absence of local laws, to comply with applicable international
standards. We have decided to implement the actions recommended by the audit.
Consequently, over the next several years we will make investments to improve
prevention systems and production facilities, among other things, in the amount
of approximately U.S.$23 million, and we will implement several corrective and
remediation actions, some of which are already underway. 18




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Notwithstanding our decision to implement actions recommended by the
environmental audit and our commitment to our environmental, health and safety
efforts, we cannot assure you that our operations will not cause environmental
or other damages or that any such damages will not result in legal liabilities
to us. We are subject to extensive environmental regulation both in Argentina and
in the other countries in which we operate. Additionally, local, provincial and
national authorities in Argentina are moving toward more stringent enforcement
of applicable environmental laws, which may require us to incur higher
compliance costs. We cannot predict what additional environmental legislation
or regulations will be enacted in the future or the potential effects on our
financial position and results of operations. We operate some of our businesses pursuant to concessions and licenses that are
subject to termination. The terms of the concessions under which some of our businesses operate
typically require the operator to meet specified requirements and to maintain
minimum quality and service standards. Failure to comply with these criteria
could result in the imposition of fines or other government actions. In
addition, in extreme cases our license or concession may be terminated or
revoked. Although we have materially complied with the terms and conditions of
our licenses and concessions in the past and expect to do so in the future, we
cannot assure you that our businesses will be able to comply fully with the
terms and conditions of their licenses. Regarding utility companies, the freezing of rates, in addition to
increased operating and financing costs, had a significant adverse impact on
the utilities cash flow and capital expenditure plans. Although these
companies have continued to maintain acceptable service quality levels, their
ability to continue meeting these levels will be seriously affected if the
Argentine government does not adopt structural measures allowing for a recovery
of these companies economic-financial balance. Our activities may be adversely affected by competition. Activities in the energy business are highly competitive and are expected
to remain competitive in the future. We compete with other companies, including leading international oil and
gas companies in Argentina and the rest of Latin America. Some of these
companies may have greater financial and other resources than us and, as a
result, may be in a better position to compete for future business
opportunities. In addition, other alternative sources of energy are expected
to come into operation in the future. We cannot assure you that we will maintain our current competitive
position in the regional energy markets. In addition, we cannot predict with
reasonable certainty the magnitude and speed of evolution of such potential
competitive threats or their effect on our operations. 19




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Item 4. INFORMATION ABOUT US OUR HISTORY AND DEVELOPMENT Our History We are an Argentine based holding company and operate exclusively through
our subsidiary Petrobras Energia and its subsidiaries which are engaged in oil
and gas exploration and production, refining, petrochemicals, electricity
generation, transmission and distribution and hydrocarbons marketing and
transportation. We conduct operations in Argentina, Bolivia, Brazil, Ecuador,
Peru and Venezuela. We are a corporation organized and existing under the laws
of the Republic of Argentina with a duration of 99 years from the date of our
incorporation, September 25, 1998. Our legal name is Petrobras Energía
Participaciones S.A. and we are known commercially as Petrobras Energía
Participaciones. Our principal executive offices are located at Maipú 1, 22nd
Floor, C1084ABA Buenos Aires, Argentina, Telephone: 54 11 4344-6000. Our original name was PC Holdings S.A. We were formed in 1998 as a result
of a spinoff by Sudacia S.A. of its equity interest in Petrobras Energía. At
the time of the spinoff, we and Sudacia S.A. were wholly owned by members of
the Perez Companc family. In addition, Petrobras Energía was also controlled
at the time by members of the Perez Companc family. We were formed for the
sole purpose of owning shares of Petrobras Energía. As of December 31, 1998
and 1999, we owned 16.15% and 28.92%, respectively, of Petrobras Energías
common stock. We acquired control of Petrobras Energía on January 25, 2000 as a result
of the consummation of an exchange offer pursuant to which we issued
1,504,197,988 Class B shares, with one vote per share, in exchange for 69.29%
of Petrobras Energías outstanding capital stock, thereby increasing our
ownership interest in Petrobras Energía to 98.21%. Since January 26, 2000, our
Class B shares have been listed on the Buenos Aires Stock Exchange and our
American Depositary Shares, each representing ten Class B shares, have been
listed on the New York Stock Exchange. At the time, we were controlled by
members of the Perez Companc family, who owned all of our Class A shares.
Those Class A shares had five votes per share until October 17, 2002, when all
Class A shares converted into Class B shares upon their purchase by Petrobras. In July 2000, we completed the change in our corporate name from PC
Holdings S.A. to Perez Companc S.A. On October 17, 2002, Petrobras Participacões, S.L., a wholly owned
subsidiary of Petróleo Brasileiro S.A.  PETROBRAS, or Petrobras, acquired from
the Perez Companc family and Fundación Perez Companc their entire ownership
interest, or 58.6%, of Petrobras Energía Participacioness capital stock.
Petrobras is the largest integrated oil, gas and energy company in Brazil. It
is engaged in a broad range of oil and gas activities, including crude oil and
natural gas exploration and production, refining, transportation, marketing and
distribution of oil products, petrochemicals, natural gas and power. Petrobas
is a mixed-capital company with a majority of its voting capital owned by the
Brazilian federal government. Prior to that date, the Perez Companc family,
together with Fundación Perez Companc, had owned at least half of the share
capital issued by Petrobras Energía Participaciones. On April 4, 2003, at a regular and special shareholders meeting,
shareholders approved the change of our corporate name to Petrobras Energía
Participaciones S.A. from Perez Companc S.A. On the same date, shareholders of
Pecom Energía S.A., or Pecom, approved the change of its name to Petrobras
Energía S.A. Both changes were registered with the National Corporate
Registrant (Inspección General de Justicia) on July 17, 2003. On May 13, 2003, the CNDC approved the purchase of 58.62% of Petrobras
Energía Participaciones S.As capital stock. History of Petrobras Energía Petrobras Energía was founded in 1946 as a shipping company by the Perez
Companc family. In the mid-1950s Petrobras Energía began its forestry
operations when it acquired an important forestry area in northeastern
Argentina. In 1960, Petrobras Energía began servicing oil wells, and, over
time, its maritime operations were gradually discontinued and replaced by
oil-related activities. The development of Petrobras Energías oil and gas
business is marked by two significant events. The first occurred in the early
1990s, when Petrobras Energía was 20




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awarded concessions to operate Puesto Hernandez, the second most important
oilfield in Argentina, and the Faro Virgenes and Santa Cruz II areas in the
Austral basin, Argentinas most important area of oil and gas production. As a
result of this and other concessions, Petrobras Energía has become one of the
largest oil and gas producers in Argentina. The second milestone in Petrobras Energías oil and gas operations
occurred in 1994 when Petrobras Energía bid on and was awarded an exploration
and production service contract for the Oritupano Leona area in Venezuela.
Over the last few years Petrobras Energía has expanded its operations rapidly
in Venezuela, Peru, Ecuador, Brazil and Bolivia as part of its strategy to
become a leading integrated energy company in Latin America. Petrobras Energía developed its other energy businesses primarily through
the acquisition of interests in state-owned companies that were privatized by
the Argentine government between 1990 and 1994. Petrobras Energía acquired
interests in companies operating in refining and petrochemicals, hydrocarbon
transportation and distribution and power generation, transmission and
distribution. These companies have formed the core of Petrobras Energías
energy businesses. In addition to the energy sector, Petrobras Energía has in the past
conducted operations in other industries, including construction,
telecommunications and mining. Petrobras Energía entered the construction
business in the 1970s when it acquired Sade S.A. Petrobras Energía entered the
telecommunications business when it acquired an interest in Nortel Inversora
S.A., the controlling shareholder of Telecom Argentina, an Argentine telephone
services provider, in the early 1990s when the Argentine government privatized
the telecommunications industry. These businesses were sold by Petrobras
Energía during the late 1990s as part of Petrobras Energías strategy to focus
its operations on the energy sector. As a result of these divestitures and the
development of Petrobras Energías energy businesses over the last decade,
Petrobras Energía has become a vertically integrated energy company. Capital Expenditures and Divestitures For a description of our most significant divestitures see Item 5.
Operating and Financial Review and ProspectsFactors Affecting Our Consolidated
Results of Operations and Business OverviewDivestments of non-core assets.
For a description of our capital expenditures see Item 5. Operating and
Financial Review and ProspectsLiquidity and Capital Resources. BUSINESS OVERVIEW Our Strategy Our long-term strategy is to grow as an integrated energy company with a
leading presence in Latin America as part of the Petrobras group, while
focusing on profitability as well as social responsibility. We will continue to integrate our business in order to take full advantage
of our significant hydrocarbon reserves. We consider the following objectives essential in our efforts to meet
these goals:  
    
    a disciplined use of capital, with a view to optimizing our
debt to capital ratio. Our level of investment will be guided
primarily by funds generated internally, with priority given to
projects with better potential of generating profits on an
accelerated basis and financial solvency as the starting point for
our growth strategy;
    
    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;
    
    the adoption of corporate governance practices in line with
international best practices;
    
    a style of management that favors communication and teamwork,
fostered by the value of the people that work in our organization;
and 21




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
    
    the development of new business opportunities, by maximizing
potential synergies and capitalizing on complementary business
opportunities with Petrobras. We currently manage our activities, with the support of the corporate
staff, in five business segments: Oil and Gas Exploration and Production,
Hydrocarbon Marketing and Transportation, Refining, Petrochemicals, and
Electricity. OIL AND GAS EXPLORATION AND PRODUCTION Overview The core of our operations is the oil and gas exploration and production
business segment. In line with our profitability and cash generation goals,
this business segments strategy is based on the following: (1) sustained
growth of operations by capitalizing on our experience and presence in almost
all Latin American oil producing countries, (2) aggressive field exploration as
a significant vehicle for growth, (3) monetization of our oil and gas reserves,
(4) low lifting costs, and (5) investment portfolio optimization. We currently conduct oil and gas exploration and production operations in
Argentina, Venezuela, Peru, Bolivia and Ecuador. As of December 31, 2003, our combined crude oil and natural gas proved
reserves, including our shares of the reserves of our unconsolidated investees,
were estimated at 758.1 million barrels of oil equivalent, approximately 53% of
which were proved developed reserves and approximately 47% of which were proved
undeveloped reserves. Crude oil accounted for approximately 75.1% of our
combined proved reserves, while natural gas accounted for about 24.9%. As of
December 31, 2003, 40.1% of our total combined proved reserves were located in
Argentina and 59.9% were located abroad. Over the last few years, total
reserves located abroad have become an increasing component of our assets
portfolio, consistent with our strategy aimed at growing as an integrated
energy company throughout Latin America. Pursuant to this strategy, between
2001 and 2003, total investments outside of Argentina accounted for 65% of our
total investments. For the year ended December 31, 2003, our combined crude oil and natural
gas production, including our share of the production of our unconsolidated
investees, averaged 158.6 thousand barrels of oil equivalent per day (114.6
thousand oil barrels and 264 million cubic feet of natural gas per day).
Approximately 49.6% of our oil production and 23.4% of our gas production were
outside of Argentina. In particular, in 2003, Venezuelan production became a
main component of our total production, accounting for 27.3% of our total
average production in barrels of oil equivalent. Deliveries of oil equivalent, including those relating to unconsolidated
investees, totaled 161.3 thousand barrels of oil equivalent per day. As of December 2003, we had total proved reserves equal to 13.1 years of
production at 2003 oil and gas production levels. Our integrated business vision places our refining, petrochemicals and
electricity businesses as primary links in our business value chain, through
which the potential of our significant hydrocarbon reserves may be maximized.
Integration with our refining business segment enables us to process a large
part of our crude oil production in Argentina. The Genelba Power Plant allows
us to use approximately 2.8 millions cubic meters of natural gas per day of our
own reserves. In addition, we supply gas to our petrochemical operations in
Argentina. Investments Significant investments made by us in the past have laid a foundation for
the expansion and growth of our oil and gas exploration and production segment.
During 1999-2001, investments totaled P$3,165 million. The 2002 fiscal year marked a change in our investment history. The
magnitude and complexity of the crisis that broke out in Argentina late in 2001
and the limited opportunities to access the capital markets forced us to
reformulate our growth strategy. Given this new environment, we developed a
new strategy that prioritizes cash 22




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generation and the maintenance of adequate liquidity levels. This has
resulted in more restrictive expense and investment policies. As a result,
capital expenditures in 2002 totaled only P$596 million, a relatively low
amount compared to our historical average investment levels. The reduced pace of investments influenced our growth objectives in the
short term, mainly affecting our future production volumes of oil and gas. In
addition, reduced investments delayed the development of new exploitation areas
and related production. In 2003, as the Argentine economy began to improve, our operating cash
flow recovered and our liquidity approached our target levels, which allowed
our investment levels to partially recover. In 2003, capital expenditures
totaled P$696 million, accounting for a 17% increase compared to 2002. Capital
expenditures in 2003 focused on maintaining production and increasing cash flow
generation, while prioritizing investments in countries and in products with
higher profit margins. Our Oil and Gas Exploration and Production Interests We generally participate in exploration and production activities in
conjunction with joint venture partners, as is commonplace in the oil and gas
exploration and production business. Contractual arrangements among
participants in a joint venture are usually governed by an operating agreement,
which provides that costs, entitlements to production, and liabilities are to
be shared according to each partys percentage interest in the joint venture.
One party to the joint venture is usually appointed as operator and is
responsible for conducting the operations under the overall supervision and
control of an operating committee that consists of representatives of each
party to the joint venture. While operating agreements generally provide for
liabilities to be borne by the participants according to their respective
percentage interest, licenses issued by the relevant governmental authority
generally provide that participants in joint ventures are jointly and severally
liable for their obligations to that governmental authority pursuant to the
applicable license. In addition to their interest in field production,
contractual operators are generally paid their production costs on a monthly
basis by their partners in proportion to their participation in the relevant
field. Our joint venture partners are oil companies that are active in
Argentina and subsidiaries of overseas oil companies. As of December 31, 2003, we had interests in 24 oil fields, 17 of which
are oil and gas producing fields and seven of which are located in exploration
areas, four in Argentina and three outside of Argentina. We are, directly or
indirectly, the contractual operator of 21 of the 24 fields in which we have an
interest. As of December 31, 2003, our total gross and net productive wells were as
follows: Oil
    
    Gas
    
    TotalGross productive wells
    
    
    4,373
    
    
    
    227
    
    
    
    4,600Net productive wells
    
    
    3,609
    
    
    
    200
    
    
    
    3,809
 23




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As of December 31, 2003, our total producing and exploration acreage, both
gross and net, is shown in the following table: Average(thousands of acres)Producing(1)
    
    Exploration(1)Gross
    
    Net(2)
    
    Gross
    
    Net(2)Argentina
    
    
    4,027
    
    
    
    3,211
    
    
    
    911
    
    
    
    887Peru
    
    
    116
    
    
    
    116
    
    
    
    
    
    
    
    Venezuela
    
    
    585
    
    
    
    379
    
    
    
    363
    
    
    
    181Ecuador
    
    
    281
    
    
    
    197
    
    
    
    494
    
    
    
    494Bolivia
    
    
    56
    
    
    
    56
    
    
    
    
    
    
    
    Total
    
    
    5,065
    
    
    
    3,959
    
    
    
    1,768
    
    
    
    1,562
   (1)
    
    Producing acreage includes all areas in which we produce commercial
quantities of oil and gas. Exploration acreage includes all areas in
which we are allowed to perform exploration activities but where
commercial quantities of oil and gas are not produced.(2)
    
    Net interests represent our fractional ownership working interest in the
gross acreage. Production Argentine Production Argentina is currently the fourth largest oil producer in Latin America
after Mexico, Venezuela and Brazil. In 2003, Argentinas daily production was
approximately 720 thousand barrels, accounting for approximately 8.1% of the
regions total production. Production from Mexico, Venezuela and Brazil
accounts for about 37.7%, 22.6% and 17.2%, respectively, of total oil
production in Latin America. According to statistical data for 2002, Argentina has the second largest
amount of natural gas proved reserves in Latin America. Reserve volumes in
Argentina coupled with its highly developed gas infrastructure, both for the
domestic and export markets, has enabled the country to position itself as an
energy leader in the region. Considering its significant gas reserves, as well
as the tremendous growth in electric power generation supplied by natural gas
in the southern part of South America, Argentina is expected to consolidate its
position as a large gas exporter to Chile, Brazil and Uruguay. Since the privatization of natural gas utilities in 1992, the natural gas
industry in Argentina has grown significantly as a result of a number of
factors, including: (i) an increase in gas availability, (ii) increased and
improved transportation and distribution, (iii) environmental efficiency, (iv)
low prices as compared to international levels and (v) alternative fuels in the
domestic market. As a result of natural gass competitiveness, demand for gas
significantly increased from 17,800 million cubic meters in 1990 to 43,466
million cubic meters in 2003, and natural gas became the preferred fuel for
both residential and industrial users as well as electricity generation
companies. In response to this increased demand for natural gas, we made significant
investments in each step of the natural gas chain during the last decade.
Transportation and distribution licensees, in turn, also made sizable
investments. As a result, our gas transportation capacity doubled from 67
million cubic meters per day to 115 million cubic meters per day and
distribution networks increased in size by 53%. These investments allowed for
exports to bordering countries and led to a suspension of imports. The higher
gas availability resulting from the expansion of gas pipelines and distribution
networks caused the tripling of the number of compressed natural gas, or CNG,
stations. CNG is the least expensive and least polluting motor fuel. As a
result, Argentina currently has the largest CNG-fueled vehicle fleet in the
world. Notwithstanding this segments potential, the Public Emergency Law has
significantly changed the applicable regulatory framework and has adversely
affected the economic attractiveness of the gas business. Following enactment
of this law, there has been an abrupt reduction of investment in exploration
activities in Argentina. This reduction, combined with the increase in demand,
has significantly reduced Argentinas horizon of reserves, which decreased from
approximately 25 years of production in the beginning of the 1990s to a 14-year 24




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reserve by the end of 2002. Without a clear path to price recovery, there
may be structural uncertainties as to the future potential of the gas industry
and the consequent integral use of reserves. In the fiscal year ended December 31, 2003, our oil and gas production
accounted for 4.6% and 3.9% of total oil and gas production in Argentina,
respectively. As of December 31, 2003, we had interests in ten Argentine oil
and gas production fields, with production rights in 3,211 thousand net acres. Our production is concentrated in two basins, the Neuquén and the Austral
basins. This positioning helps to optimize our operating efficiency and
capitalize on the operating synergies of our own assets. The Neuquén basin is
the most important area in Argentina in terms of oil and gas production. We
own 579 thousand net acres under production concessions. Our most important
fields in the Neuquén basin are 25 de Mayo-Medanito S.E., Puesto Hernández and
Río Neuquén. In the Austral basin we own 2,632 thousand net acres under
production concessions, with Santa Cruz I and Santa Cruz II being our most
important fields in that basin. In line with our current strategy, we have implemented the following
initiatives during the last three years:  
    
    In February 2001, we completed an asset swap with Repsol-YPF
S.A. having an economic impact as from January 1, 2001, whereby: (i)
we added a 30% and 62.2% interest in Santa Cruz I and Santa Cruz II
areas, respectively, and (ii) assigned our 50% interest in
Manantiales Behr and Restinga Alí joint ventures and our 40.5%
equity interest in Andina Corporation, a company controlling 50% of
Empresa Petrolera Andina S.A. of Bolivia. This transaction enabled
us to monetize our oil and gas reserves and optimize our assets
portfolio, strengthening our position in the Austral basin by
divesting non-core assets located in Bolivia and in the San Jorge
basin in Argentina.
    
    In October 2001, we sold our exploitation rights in the Pampa
del Castillo-La Guitarra area and our 13.79% equity interest in
Terminales Marítimas Patagónicas. As a strategic milestone, this
transaction represented the end of our oil operations at the Golfo
San Jorge basin.
    
    In June 2003, we sold our 50% equity interest in the Faro
Vírgenes concession area to Geodyne Energy Inc.s Argentine branch.
The Faro Vírgenes area was a low production asset with little
potential and high operating costs.
    
    In August 2003, we sold our 85% interest in the Catriel Oeste
area to Central International Corporations Argentine branch. The
Catriel Oeste was a low production asset with little potential and
high operating costs. Rights to develop oil and gas fields in Argentina are granted through
concessions and exploration permits. Concessions are generally granted for
periods of 25 years and are typically renewable for a maximum term of ten
years, and permits are generally granted for initial periods of three years.
The concessions for all production areas in Argentina typically provide for the
free availability of oil. All permanent fixtures, materials and equipment are
under the control of the concessionaire, although they revert to the Argentine
government at the end of the concession. Royalties are paid to the respective
Argentine provinces for the production of crude oil and the volumes of natural
gas produced for sale. These royalties are 12% of the wellhead price for oil
and gas. The wellhead price used to determine the royalty cost is similar to
the final sales price less treatment, storage and transportation costs. Production outside of Argentina As a result of the substantial investments we have made in the rest of
Latin America in recent years, as of December 31, 2003, 59.9% of our combined
proved reserves were located outside of Argentina. In addition, approximately
49.6% of our oil production and 23.4% of our gas production came from outside
Argentina in 2003. We have interest in seven oil and gas production fields
outside of Argentina: Oritupano-Leona, Acema, La Concepción and Mata in
Venezuela, Lote X in Peru, Block 18 in Ecuador and Colpa Caranda in Bolivia. 25




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Venezuela Venezuela is an important country in the international oil market. With
proven reserves of approximately 77.8 billion barrels of crude oil in 2003,
Venezuela possesses the largest proven reserves in the Western Hemisphere and
has 7% of the total reserves on earth. Its commercial production is
concentrated in the basins of Zulia and Barinas-Apure in the western part of
the country and in the basins of the Estados Monagas and Anzoátegui in the
eastern part of the country. Venezuela also has billions of barrels of heavy
duty crude and bitumenes, the great majority of which is situated in the Faja
Petrolífera of Orinoco. In 2002, Venezuela produced approximately 2.6 million barrels of crude oil
a day, of which close to 407,000 barrels were consumed in the local market and
the rest were exported. It is worth noting that production levels were
affected by a general strike that took place in the beginning of December of
2002 and lasted until February of 2003. See Item 3. Key InformationRisk
FactorsFactors Related to Venezuela. Production from Venezuela has become an important part of our total
production, accounting for 27.3% of the total average production in barrels of
oil equivalent in 2003. In Venezuela, our rights are held under operating service contracts. In 1994, during the second round of operating agreements, we were awarded
the first service contract by PDVSA at the Oritupano-Leona field to provide
production services for a 20-year period, which may be extended for an
additional ten-year period. Oritupano-Leona is a 215 thousand net acre block
located in the Oriental basin that includes 263 producing wells. The Oritupano Leona joint ventures sole customer for the sale of oil
production is PDVSA. Per our operating service agreement, PDVSA is the sole
owner of the facilities, assets and/or operating equipment used by the joint
venture to conduct the activities provided for in this agreement. For the
provision of production services, we receive a variable fee based on production
volumes plus an additional fee for reimbursement of capital expenditures, on a
quarterly basis during the first ten-year term of the agreement. Expenses
related to investments made thereafter will be recovered over the rest of the
term. Any of these unpaid expenses will bear interest of up to 1% over the
London Interbank Offered Rate, or LIBOR, annual rate. The contract has a cap
(maximum total fee) on the amount which we can collect, which is reset
quarterly based on the market price of oil. As of December 2003, this cap was
approximately U.S.$28.72 per barrel. In 1997, PDVSA awarded us three 20-year service contracts for the
exploration and production of Acema, La Concepción and Mata blocks in the
so-called Third Round bids. The bids were initially made through joint
ventures. Currently, we have a 90% interest in the La Concepción block and a
86.23% interest in the Acema and Mata oil blocks, which, together with the La
Concepción, block we refer to as the Third Round Blocks. La Concepción is a 55
thousand net acre block located in the Maracaibo basin, with 92 producing
wells. Acema and Mata, located in the Oriental basin, are 64 thousand and 45
thousand acre blocks with 22 and 53 producing wells, respectively. According
to the concession contracts, PDVSA will be the sole owner of the facilities,
assets, and operating equipment. We receive a fee for each barrel delivered
which has a fixed component related to contractual baseline production and a
variable component related to the incremental production that covers
investments and production costs, plus a gross profit up to a maximum that is
tied to a basket of international oil prices. Effective January 2002, the Venezuelan government adopted a new law
whereby royalty payments increased from 16.67% to 30%. This law had a
significant adverse impact on the operating results of our Third Round Blocks.
We are taking every necessary step to partially reverse this increase, since
under a new hydrocarbons law the federal executive may reduce such royalties by
up to 20%. The government of Venezuela may set a limit on our oil production under
the terms of the service agreements. Venezuela is a member of OPEC and has set
forth a policy of strict compliance with the production quotas decided within
OPEC. According to the Venezuelan Hydrocarbon Law, any decisions made by the
federal administration in connection with agreements or international treaties
involving hydrocarbons are applicable to any party that carries out the
activities governed by the law. As a result of this, if there are production
cuts approved by OPEC, these cuts affect private producers as well as PDVSA.
See Regulation of Our BusinessesThe 26




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Venezuela Petroleum and Gas Industry and Regulatory Framework.
Production cuts were only contemplated by the third round operating agreements,
which we refer to as the Third Round Agreements, but not by the second round
operating agreements, which we refer to as the Second Round Agreements, which
apply to the Oritupano-Leona field. Although no production cuts have been
ordered under the Second Round Agreements to date, it is not completely clear
whether the constitutional principle that prohibits retroactive application of
the law will protect Second Round Agreements against future production cuts. Peru In 1996, we acquired 30-year oil and 40-year natural gas production rights
in Lote X, a 116 thousand acre block in Perus Talara basin, through a public
bidding process. The purchase included all of the then existing assets on the
site. The concession agreement provides for the free availability of
hydrocarbons. As of December 31, 2003, Lote X had 2,366 productive wells. We
have entered into a long-term sales contract under which Perupetro S.A., the
Peruvian state-owned company which we refer to as Perupetro, is obligated to
purchase all of our production at market prices. Hydrocarbon sales are subject
to royalty payments of 24% of the sales price. The sales contract is set to
expire in July 2006. In June 2003, the Peruvian government approved the National Law for the
Promotion of Investment in the Exploitation of Resources and Marginal Reserves
of Hydrocarbons (Ley para la Promoción de la Inversión en la Explotación de
Recursos y Reservas Marginales de Hidrocarburos a Nivel Nacional) through which
Perupetro is authorized to reduce the level of royalty payments. This
reduction would be contingent on the concessionairés agreeing to minimum
production levels and work programs. Under this scheme, we entered into an
agreement with Perupetro, modifying the original terms of our concession, in
which we promised to invest U.S.$65 million during the first five years and
U.S.$33 million in the following two years, in exchange for a reduction in
royalty payments, which, under current conditions, we estimate would decline to
16.5%. This agreement becomes valid simultaneously with the promulgation of
the Supreme Decree (Decreto Supremo) approving the modification of our
concession. Peru production accounted for 8.1% of our total average production in
barrels of oil equivalent in 2003. Bolivia Petrobras Energía has a 100% interest in the oil and gas fields of Colpa
Caranda and has operated them since 1989. Colpa Caranda is a 56 thousand net
acre block located in the Sub Andina Central basin that has 55 producing wells.
Approximately 88.6% of our proved developed reserves in Bolivia are gas.
These fields, which originally supplied Bolivian gas exports to Argentina,
currently have priority in the dispatch of gas to the Santa Cruz-São Paulo
pipeline that transports gas to Brazil. Bolivia production accounted for 3.8%
of our total average production in barrels of oil equivalent in 2003. Ecuador In 2001, we acquired a 70% interest in Block 18, located in the Oriente
basin of Ecuador. Block 18 is a field covering 197 thousand acres and having a
significant potential of 28o to 33° API light crude oil reserves. The
concession for production activities in Block 18 will be for an initial 20-year
term as from October 2002. Once this term expires, the Ecuadorian hydrocarbons
law provides for the possibility of an additional five-year extension period. In October 2002, the Hydrocarbons National Directorate approved the
development plan for the Pata field in Block 18, thereby initiating its
production phase until October 2022. The Government has the right to take 35%
of production, in kind. Exploratory activities will continue for an additional
three-year period ending October 2005. In August 2002, Petroecuador, the Ecuadorian state-owned oil company,
subscribed to a joint exploitation agreement for the Palo Azul field in Block
18. In December of 2002, the Palo Azul development plan was approved and has
been extended until December 2022. The general terms of the agreement include
differential production sharing percentages according to a formula that takes
into account the final selling price of Palo Azuls crude oil and the level of
total proved reserves. Specifically, if Palo Azuls crude oil sells at a price
less than U.S.$15 per barrel, the States share of crude oil equals 30%. If
crude oil sells at a price greater or equal to U.S.$24 per barrel, the 27




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States share of crude oil equals about 50%. For all other price ranges,
a scale was agreed with Petroecuador. Palo Azuls selling price is computed by
considering the WTI crude oil benchmark minus the market discount for the
Oriente crude oil. The agreement provides for the free availability of crude
oil. Block 18 has eight productive wells, two of which are located at the Pata
field and six of which are located at the Palo Azul field. In addition, the
area has early production facilities which can handle a daily gross production
of 20 thousand barrels. Mexico In 2003, as part of the bidding launched by Petróleos Mexicanos, or PEMEX,
for the operation of areas under multiple service contracts, contracts for the
Cuervito and Fronterizo blocks were awarded to a joint venture composed of
Petrobras, Teikoku and Diavaz. Under an operating agreement, we will act as
contractor and provide the joint venture with the technical and operating
support required for the operation of the Cuervito and Fronterizo blocks. 28




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Statistical Information Relating to Oil and Gas Production The following table sets forth our oil and gas fields production as of
December 31, 2003. In addition, the table includes our percentage interest in
the oil and gas production of each field, the number of producing wells and the
expiration date of the concessions. Although some of these concessions may be
extended at their expiration, the expiration dates set forth below do not
include any such extensions. Oil2003 Production
    
    andGasProduction Areas
    
    Location
    
    Basin
    
    Oil(1)
    
    Gas(2)
    
    Wells
    
    Interest
    
    ExpirationArgentina25 de Mayo  Medanito
    
    La Pampa and Rìo
    
    Neuquén
    
    
    4,982
    
    
    
    1,314
    
    
    
    461
    
    
    
    100.00
    %
    
    
    2016S.E.
    
    NegroCatriel Oeste(3)
    
    Rìo Negro
    
    Neuquén
    
    
    258
    
    
    
    240
    
    
    
    
    
    
    
    85.00
    %
    
    
    2016Jagüel de los Machos
    
    Rìo Negro and La
    
    Neuquén
    
    
    1,296
    
    
    
    3,630
    
    
    
    73
    
    
    
    100.00
    %
    
    
    2015PampaFaro Vírgenes U.T.E.(4)
    
    Santa Cruz
    
    Austral
    
    
    
    
    
    
    127
    
    
    
    
    
    
    
    50.00
    %
    
    
    2016Puesto Hernández
    
    Mendoza and Neuquén
    
    Neuquén
    
    
    5,661
    
    
    
    
    
    
    
    580
    
    
    
    38.45
    %
    
    
    2016Bajada del Palo  La
    
    Neuquén
    
    Neuquén
    
    
    101
    
    
    
    
    
    
    
    4
    
    
    
    80.00
    %
    
    
    2015Amarga ChicaSanta Cruz II
    
    Santa Cruz
    
    Austral
    
    
    4,705
    
    
    
    24,307
    
    
    
    76
    
    
    
    100.00
    %
    
    
    2017Río Neuquén
    
    Neuquén and Rìo
    
    Neuquén
    
    
    843
    
    
    
    12,060
    
    
    
    134
    
    
    
    100.00
    %
    
    
    2019NegroEntre Lomas
    
    Neuquén and Rìo
    
    Neuquén
    
    
    711
    
    
    
    1,282
    
    
    
    327
    
    
    
    17.90
    %
    
    
    2016NegroVeta Escondida and
    
    Neuquén
    
    Neuquén
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    55.00
    %
    
    
    2016Rincón de Aranda
U.T.E.Aguada de la Arena
    
    Neuquén
    
    Neuquén
    
    
    75
    
    
    
    5,626
    
    
    
    9
    
    
    
    80.00
    %
    
    
    2022Santa Cruz I U.T.E.
    
    Santa Cruz
    
    Austral
    
    
    2,466
    
    
    
    25,243
    
    
    
    77
    
    
    
    71.00
    %
    
    
    2016Outside of ArgentinaColpa Caranda
    
    Bolivia
    
    
    
    
    491
    
    
    
    13,095
    
    
    
    55
    
    
    
    100.00
    %
    
    
    2029Oritupano Leona
    
    Venezuela
    
    Oriental Maturin
    
    
    8,221
    
    
    
    
    
    
    
    263
    
    
    
    55.00
    %
    
    
    2014Acema
    
    Venezuela
    
    Oriental Maturin
    
    
    943
    
    
    
    
    
    
    
    22
    
    
    
    86.23
    %
    
    
    2017La Concepción
    
    Venezuela
    
    Lago Maracaibo
    
    
    3,994
    
    
    
    6,848
    
    
    
    92
    
    
    
    90.00
    %
    
    
    2017Mata
    
    Venezuela
    
    Oriental Maturìn
    
    
    1,510
    
    
    
    
    
    
    
    53
    
    
    
    86.23
    %
    
    
    2017Lote X
    
    Peru
    
    Talara
    
    
    4,239
    
    
    
    2,570
    
    
    
    2,366
    
    
    
    100.00
    %
    
    
    2024Block 18
    
    Ecuador
    
    Oriente
    
    
    1,344
    
    
    
    
    
    
    
    8
    
    
    
    70.00
    %
    
    
    2022Total
    
    
    
    
    
    
    41,840
    
    
    
    96,342
    
    
    
    4,600
   (1)
    
    in millions of barrels(2)
    
    in billions of cubic feet(3)
    
    In August of 2003, we sold our 85% interest in Catriel Oeste
concession area to Central International Corporation, Argentine Branch.(4)
    
    On June 26, 2003, we sold our 50% interest in Faro Vírgenes
concession area to Geodyne Energy Inc.s Argentine Branch. In 2003, our annual production from producing oil fields, including our
oil fields in Bolivia, Venezuela, Peru and Ecuador, was 41.8 million barrels of
oil, 21.1 million of which were produced in Argentina. Our annual production
of gas amounted to 96.3 million cubic feet, 73.8 million cubic feet of which
were produced in Argentina. 29




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##### Table of Contents



The following table sets forth our average daily production of oil,
including other liquid hydrocarbons, for the three fiscal years ended December
31, 2003, 2002 and 2001. This table includes our proportionate share of the
production of both our consolidated subsidiaries and our unconsolidated
investees. Year ended December 31,2003
    
    2002
    
    2001(average barrels per day)Argentina
    
    
    57,803
    
    
    
    56,746
    
    
    
    67,671Outside of Argentina
    
    
    56,827
    
    
    
    58,917
    
    
    
    60,484Total
    
    
    114,630
    
    
    
    115,663
    
    
    
    128,155
 The following table sets forth our average daily gas production for the
three fiscal years ended December 31, 2003, 2002 and 2001. This table includes
our proportionate share of the production of both our consolidated subsidiaries
and our unconsolidated investees. Year ended December 31,2003
    
    2002
    
    2001(average Mcf per day)Argentina
    
    
    202,272
    
    
    
    252,559
    
    
    
    273,414Outside of Argentina
    
    
    61,679
    
    
    
    61,238
    
    
    
    65,912Total
    
    
    263,951
    
    
    
    313,797
    
    
    
    339,326
 The following table sets forth the average sales price per barrel of oil
and per thousand cubic feet of gas for each geographic area for the three
fiscal years ended December 31, 2003, 2002 and 2001, of our consolidated
subsidiaries. Year ended December 31,2003
    
    2002
    
    2001ArgentinaOil (in pesos per BOE)
    
    
    69.80
    
    
    
    65.88
    
    
    
    40.56Gas (in pesos per 1,000 cubic feet)
    
    
    1.76
    
    
    
    1.97
    
    
    
    2.40Outside of ArgentinaOil (in pesos per BOE)
    
    
    52.70
    
    
    
    50.70
    
    
    
    30.84Gas (in pesos per 1,000 cubic feet)
    
    
    4.37
    
    
    
    4.52
    
    
    
    3.34
 30




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##### Table of Contents



The following table sets forth our average lifting cost, royalties and
depreciation cost of oil and gas fields in each geographic area for the three
fiscal years ended December 31, 2003, 2002 and 2001. This table includes our
proportionate share of the production of our consolidated subsidiaries. Year ended December 31,2003
    
    2002
    
    2001(in pesos per BOE)ArgentinaLifting Cost
    
    
    6.45
    
    
    
    5.77
    
    
    
    5.98Royalties
    
    
    5.37
    
    
    
    5.28
    
    
    
    3.94Depreciation
    
    
    10.02
    
    
    
    9.61
    
    
    
    8.09Total
    
    
    21.84
    
    
    
    20.66
    
    
    
    18.01Outside of ArgentinaLifting Cost
    
    
    9.42
    
    
    
    10.41
    
    
    
    5.87Royalties
    
    
    5.52
    
    
    
    5.45
    
    
    
    3.38Depreciation
    
    
    12.78
    
    
    
    15.41
    
    
    
    6.92Total
    
    
    27.72
    
    
    
    31.27
    
    
    
    16.17
 The following table sets forth the average reserve replacement cost and
the finding and development costs of oil and gas from all fields for the three
fiscal years ended December 31, 2003, 2002 and 2001. This table includes our
proportionate share of the production of both our consolidated subsidiaries and
our unconsolidated investees. Year ended December 31,2003
    
    2002
    
    2001(in pesos per BOE)Reserve replacement cost
    
    
    41.85
    
    
    
    
    (1)
    
    
    26.80Finding and development costs
    
    
    13.51
    
    
    
    10.63
    
    
    
    14.99
   (1)
    
    In 2002, there was no net increase in reserves. Exploration Overview We believe that an increase in exploration is essential to maintain and
grow our reserve base. Exploration is a key activity to sustain a high reserve
replacement ratio. We use 3-D seismic technology to ensure a technologically sound prospect
portfolio and a high success rate. The integration of well and 3-D seismic
data into subsurface models is critical for exploration drilling, field
delineation and optimization of the appraisal of well locations. 31




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##### Table of Contents



The following table lists our oil and gas fields in exploration areas as
of December 31, 2003, the location of the basin in each area, our ownership
interest and the expiration date of the exploration permits for each field. Location
    
    Basin
    
    Interest
    
    ExpirationArgentinaGlencross
    
    Santa Cruz
    
    Austral
    
    
    96.68
    %
    
    
    1999
    (1)Estancia El Chiripá
    
    Santa Cruz
    
    Austral
    
    
    100.00
    %
    
    
    2006
    (1)Santa Cruz I  Oeste
    
    Santa Cruz
    
    Austral
    
    
    50.00
    %
    
    
    2006
    (1)CAM-2A  Norte
    
    Santa Cruz
    
    Austral
    
    
    50.00
    %
    
    
    2004Outside of ArgentinaSan Carlos
    
    Venezuela
    
    Guarico
    
    
    50.00
    %
    
    
    2005Tinaco
    
    Venezuela
    
    Guarico
    
    
    50.00
    %
    
    
    2005Block 31
    
    Ecuador
    
    Oriente
    
    
    100.00
    %
    
    
    2024
   (1)
    
    We have requested that the lot be declared operational and are awaiting a
response from the relevant authorities. Exploration in Argentina As of December 31, 2003, we hold interest in 911 thousand gross acres (887
thousand net acres) of basin area in Argentina available for exploration.
Under exploration licenses we hold interests in Glencross, Santa Cruz I  Oeste
and CAM-2A exploratory areas. We may continue to acquire acreage positions in
the future as the Argentine government offers additional exploration permits
through license bidding rounds. We compete with other oil and gas producers in Argentina for the
acquisition of new properties. The following table sets forth the number of wells we drilled in
Argentina, and the results thereof, for the periods indicated. A well is
considered productive for purposes of the following table if it justifies the
installation of permanent equipment for the production of oil and gas. A well
is deemed to be a dry hole if it is determined to be incapable of commercial
production. Gross wells drilled in the tables below refers to the number of
wells completed during each fiscal year, regardless of the spud date, and net
wells drilled relates to the fractional ownership working interest in wells
drilled. This table includes wells drilled by both our consolidated
subsidiaries and unconsolidated investees. Year ended December 31,2003
    
    2002
    
    2001Gross wells drilledExploratoryProductive wellsOil
    
    
    
    
    
    
    
    
    
    
    Gas
    
    
    
    
    
    
    
    
    
    
    Dry
    
    
    
    
    
    
    1
    
    
    
    1Total
    
    
    
    
    
    
    1
    
    
    
    1DevelopmentProductive wellsOil
    
    
    169
    
    
    
    109
    
    
    
    137Gas
    
    
    8
    
    
    
    7
    
    
    
    20Dry
    
    
    8
    
    
    
    4
    
    
    
    3Total
    
    
    185
    
    
    
    120
    
    
    
    160
 32




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##### Table of Contents



Year ended December 31,2003
    
    2002
    
    2001Net wells drilledExploratoryProductive wellsOil
    
    
    
    
    
    
    
    
    
    
    Gas
    
    
    
    
    
    
    
    
    
    
    Dry
    
    
    
    
    
    
    1
    
    
    
    1Total
    
    
    
    
    
    
    1
    
    
    
    1DevelopmentProductive wellsOil
    
    
    105.2
    
    
    
    78.7
    
    
    
    110.6Gas
    
    
    6.6
    
    
    
    5.8
    
    
    
    14.6Dry
    
    
    6.2
    
    
    
    2.8
    
    
    
    3.0Total
    
    
    118.0
    
    
    
    87.3
    
    
    
    128.2
 During 2002, we farmed out a 50% interest in Santa Cruz I exploratory
block. The buyer committed to make all the investments necessary to acquire
and process 500 km2 of 3-D seismic lines and to drill five wells. However, we
remain responsible for conducting operations in this block. Exploration Outside of Argentina As of December 31, 2003, we hold interests in 857 thousand gross acres
(675 thousand net acres) outside of Argentina available for exploration. We
hold interests in three oil and gas exploration fields outside of Argentina:
San Carlos and Tinaco in Venezuela and Block 31 in Ecuador. We continue to
seek new business opportunities in Peru, Bolivia, Ecuador and Venezuela. 33




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##### Table of Contents



The following table sets forth our drilling activities outside of
Argentina for the three years ended December 31, 2003, 2002 and 2001. A well
is considered productive for purposes of the following table if it justifies
the installation of permanent equipment for the production of oil and gas. A
well is considered to be a dry hole if it is determined to be incapable of
commercial production. This table includes both our consolidated subsidiaries
and unconsolidated investees. Year ended December 31,2003
    
    2002
    
    2001Gross wells drilledExploratoryProductive wellsOil
    
    
    2
    
    
    
    
    
    
    
    Gas
    
    
    
    
    
    
    
    
    
    
    Dry
    
    
    1
    
    
    
    2
    
    
    
    Total
    
    
    3
    
    
    
    2
    
    
    
    DevelopmentProductive wellsOil
    
    
    20
    
    
    
    2
    
    
    
    35Gas
    
    
    1
    
    
    
    
    
    
    
    3Dry
    
    
    
    
    
    
    
    
    
    
    1Total
    
    
    21
    
    
    
    2
    
    
    
    39Net wells drilledExploratoryProductive wellsOil
    
    
    1.4
    
    
    
    
    
    
    
    Gas
    
    
    
    
    
    
    
    
    
    
    Dry
    
    
    1.0
    
    
    
    1.1
    
    
    
    Total
    
    
    2.4
    
    
    
    1.1
    
    
    
    DevelopmentProductive wellsOil
    
    
    17.7
    
    
    
    1.1
    
    
    
    19.5Gas
    
    
    0.6
    
    
    
    
    
    
    
    3.0Dry
    
    
    
    
    
    
    
    
    
    
    1.0Total
    
    
    18.3
    
    
    
    1.1
    
    
    
    23.5
 Venezuela We began exploration activities in the San Carlos region of western
Venezuela under a contract entered into with PDVSA through its subsidiary,
Corporación Venezolana de Petróleo S.A., in July 1996. The block is located in
the areas of Cojedes and Portuguesa and extends across 125 thousand acres. We
are required to pay all exploration costs in the block. The exploration
activities in this block started late in 1996 and the work commitments for the
first stage of the exploration process were fulfilled with the acquisition of
2-D seismic data and the drilling of 2 exploratory wells. Total expenditures
required for initial exploration in the block were U.S.$32 million. Our
exploration activities in this block yielded gas findings. In June 2001, upon the opening of free gas exploration areas, we were
awarded a license for the exploration and production of gas in the Tinaco area,
a field adjacent to the San Carlos field, with an area of 238 thousand acres.
This event is an important step in the development of the San Carlos block,
since it would enable us to confirm related natural gas reserves. The
contractual work commitments included the acquisition of 200 km of 2-D seismic
data. 34




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##### Table of Contents



During 2003, the conditions prevailing in the political, economic and
social arena in Venezuela prevented the performance of the 2-D seismic works in
the Tinaco area. These works will be completed throughout the first half of
2004. Depending on the seismic results obtained, an exploratory well may be
drilled in 2005. If gas reserves are commercialized in the future, we will be required to
pay 23.21% in royalties. In connection with the joint future gas production of both blocks, we
negotiated the conversion of the San Carlos contract into a contract with
similar conditions as those appearing in the Tinaco contract. In October 2002, we subscribed to an association agreement, which we refer
to as the Transfer of Interest Agreements, with Teikoku Oil Co. Ltd., or
Teikoku, whereby we transferred 50% of our rights and obligations in and to gas
production in San Carlos and Tinaco exploratory areas. The Transfer of Interest Agreement, which is subject to approval by the
Venezuelan Ministry of Energy and Mines, provides for an initial cash payment
of U.S.$1 million and a subsequent payment of U.S.$2 million for the financing
of the exploratory investment program in the Tinaco area in relation to
geological studies, 2-D seismic shooting and 2-D seismic evaluation and
interpretation. Furthermore, in the event a joint commercial development in
this area is agreed upon, we will receive a supplementary payment in the amount
of U.S.$3 million. Ecuador In Ecuador, we hold a 100% interest in Block 31. In 1996, Petroecuador
called the Eighth Round of International Bids for the performance of
exploration and production activities in the Amazon Region, and we were awarded
Block 31. This block is located in a highly sensitive ecological area of the
Amazon jungle in the central part of the eastern border of the upper Amazon
basin and covers an area of 494 thousand net acres. For the full development of the block, we estimate that approximately
U.S.$800 million in investments will be required. Initial investments in the
amount of approximately U.S.$150 million are necessary prior to the production
phase. Changes in our investment scenario following the Argentine crisis have
resulted in significant delays to our original investment plan for the areas
development. Under the concession contract, the exploration program is divided into two
phases, with the first phase having expired in July 2001 and the second in June
2003. To fulfill the committed work program, 1,200 km of 2-D seismic lines
were acquired and three exploratory wells were drilled. We have conducted the following works in Block 31: 1,382 km of 2-D
seismic, 167 km 2 of 3-D seismic, and the drilling of four exploratory wells in
Apaika, Nenke, Obe and Minta. All the wells were successful and led to the
discovery of the Apaika/Nenke, Obe, and Minta fields. Interpretation of 600 km
of 2-D seismic acquired in the eastern and northeastern areas of the block was
also performed. The 3-D seismic cube (167 km2) was reprocessed to ensure
better adjustment to 2-D seismic. In March 2004, the Minister of Energy of
Ecuador approved an environmental impact study, completing all of the required
steps for the approval of the development plan. Following approval of the
environmental study, a twenty-year exploitation period has begun, during which,
in the initial three-year period, the plan contemplates investments of U.S.$75
million. We are obligated to give Petroecuador a guaranty of 20% of this
amount. According to the blocks production sharing agreement, Petroecuador is
entitled to a crude oil production take of about 15% to 17%, depending on the
fields daily crude oil production and crude oil gravity. The Block 31
concession provides for the free availability of crude oil. Future oil production in Block 31 will be shipped through a heavy crude
oil pipeline known as Oleoducto de Crudo Pesados in which we currently have an
11.42% interest. We have entered into a 15-year ship or pay transportation
contract under which OCP has committed to provide us with a shipping capacity
of 80,000 barrels per day. OCP started commercial operations on November 10,
2003 and since that date, we have had to comply with our contractual
obligations with respect to our committed acquired capacity by paying a
transportation capacity fee. We currently estimate that during the contracts
term, oil production will be lower than our committed transportation
capacity.
Accordingly, as of December 31, 2003, we have recorded an
impairment allowance of P$321 to adjust the book value of our group
of assets in Ecuador to its recoverable value. See Item 3. Key InformationRisk
FactorsFactor Relating to UsProduction of oil in Block 31 in 35




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##### Table of Contents



Ecuador is significantly
delayed, and this delay has and will continue to affect our results.
Further delays could result in an increase in our operating losses
related to our group of assets in Ecuador. As a way of maximizing the value of this asset and enhancing its
potential, we are considering a number of alternatives, including the addition
of a new partner who could speed up the development of the block or a potential
sale of all or a portion of our interest in Block 31. A transaction involving
a sale of all or part of our interest in Block 31 may likely involve a sale or
other disposition of all or a portion of our interests in Block 18 and in OCP. Peru In 1998, Petrobras Energía entered into exploration agreements for Lote
XVI, in which it has a 100% interest. Exploratory investments were first made
in this block in 1999, with the shooting of 50 km2 of 3-D seismic lines.
During 2002, interpretation of the block geology was concluded and a location
was selected for the drilling of an exploration well in 2003. Due to the
disappointing results of the exploration, in May 2003, we decided not to
proceed to the next phase. In the Ucayali basin, two blocks were awarded to a consortium formed by
Petrobras Energía and Repsol-YPF S.A., the latter being the operator of both
blocks. Seven-year exploration contracts were signed in September 1998 for
Lote 34 and in November 1998 for Lote 35. We had a 40% interest in Lote 34 and
a 35.15% interest in Lote 35. Both contracts provide for an initial two-year
exploration phase, each with a commitment of 500 km 2-D seismic line
acquisition and the reprocessing of 1,000 km of existing 2-D seismic data. The
subsequent five one-year exploration periods are optional, and each period
requires the drilling of an exploration well or compensatory exploratory
seismic. The wildcat Mashansha 35-13-IX in the Lote 35 was drilled in 2002.
The well resulted in a dry hole with sparse oil shows. In 2003, after a
thorough evaluation of the well results and the impact on the additional
exploration objectives, it was decided not to continue in both blocks due to
the limited remaining exploration potential. In 2001, we executed a concession contract for hydrocarbon exploration and
production in Lote 99, a block located in the Ucayali basin. We hold a 100%
interest in Lote 99. The concession program requires a minimum exploration
program of seven years divided into five periods. Exploration during the first
18-month period included geological surveys and the reprocessing and
reinterpretation of 900 km2 of seismic data. In 2003, after evaluating the
exploration results, we decided not to proceed to the next stage. In May 2004, we entered into a contract with Repsol Exploración Perú S.A.
to perform certain exploration activities jointly in Lot 57. Petrobras Energía
has an option to participate in Lot 57 by acquiring a 35.15% interest from
Repsol, which currently holds a 76.15% interest in Lot 57. Burlington Resources
Perú Ltd. is Repsols partner in the shared risk agreement with Perupetro for
the exploration and exploitation of hydrocarbons in Lot 57. In the Lote 63 area, the survey period has concluded and an exploration
contract will be negotiated with Perupetro. Reserves We believe our estimates of remaining proved recoverable oil and gas
reserve volumes to be reasonable. These estimates have been prepared in
accordance with Rule 4-10 of Regulation S-X under the U.S. Securities Act.
Gaffney, Cline & Associates, Inc., an international technical and management
advisory firm for the oil and gas industry, audited our oil and gas reserves as
of December 31, 2003, 2002 and 2001. The estimated reserves were subjected to economic tests to determine
economic limits. These estimated reserves in Argentina, Peru and Bolivia are
stated prior to the payment of any royalties, as they have the same attributes
as taxes on production and, therefore, are treated as operating costs. In
Ecuador, due to the type of contract in which the government has the right to a
percentage of production and takes it in kind, reserves are stated after such
percentage. In Venezuela, the government maintains full ownership of all
hydrocarbons in such areas. Reserve volumes in Venezuela are computed by
multiplying our percentage interest by the gross proved recoverable volumes for
the contract area. In Venezuela, for the Acema, Mata and La Concepción areas,
30% royalties are paid, calculated based on the crude wellhead estimated price.
Under contractual terms the Third Round Blocks royalties 36




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##### Table of Contents



are deducted from the sales price. Pursuant to operating agreements in
force, we are exempt from production royalty payments in the Oritupano Leona
field. As of December 31, 2003, liquid hydrocarbon and natural gas proved
reserves, audited by Gaffney, Cline & Associates, Inc., amounted to 758.1
million barrels of oil equivalent (569.1 million barrels of oil and 1,134.8
billion cubic feet of natural gas, representing a 6.7% decline compared to the
reserves certified as of December 31, 2002 (a decline of 4.2% for liquid
hydrocarbons and 13.6% for natural gas)). As of December 2003, total proved reserves represented, at 2003 oil and
gas production levels, a 13.1-year production. During the 2002-2003 period, after the change in the investment scenario
for our businesses following the Argentine crisis, we focused on maintaining
adequate liquidity levels and cash generation, and this focus affected our
reserve replacement strategy. Production of proved undeveloped reserves was
prioritized relative to prior years, with a reduced emphasis on exploration and
acquisition activities, which had historically been a major source of reserve
replacement. This had a negative impact on the addition of reserves. Therefore, during 2003 the reserve replacement ratio was 33%, reflecting
production of 57.9 million barrels of oil equivalent which was partially offset
by a net addition of 19.3 million barrels of oil equivalent, as reflected
below:  
    
    Secondary recovery projects that added 26.7 million barrels
of oil equivalent.
    
    Extensions of known accumulations and discoveries that added
33 million barrels of oil equivalent reflecting good results from
drilling and recovery.
    
    Technical reviews, based on the performance of the different
fields and the projects implemented during 2003, resulted in
reductions of previous estimates by 40.4 million barrels of oil
equivalent at fields where secondary recovery operations were
performed. In addition, in 2003, the sale of the Catriel Oeste and Faro Vírgenes
areas in Argentina reduced our reserves by 15.9 million barrels of oil
equivalent. Liquid hydrocarbons and natural gas account for 75.1% and 24.9%,
respectively, of total proved reserves, and 59.9% are located outside of
Argentina. Proved reserves outside Argentina increased as a percentage of
proved reserves. This increase reflects principally lower investments in gas
projects in Argentina, which were scaled back in light of low domestic prices,
with a consequent reduction in additions from recoveries, extensions and
discoveries. 37




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##### Table of Contents



The table below sets forth, by geographic area, total proved reserves and
proved developed reserves of crude oil, condensate and natural gas liquids and
natural gas reserves at the indicated dates. Crude oil, condensate and natural gasliquids in thousands of barrels
    
    Natural gas in millions of cubic feetOutside of
    
    
    
    
    
    
    
    
    
    Outside of
    
    
    
    
    
    CombinedArgentina
    
    Argentina
    
    Total
    
    Argentina
    
    Argentina
    
    Total
    
    MMBOE(1)Total proved reserves as of
December 31, 2001
    
    
    237,280
    
    
    
    501,892
    
    
    
    739,172
    
    
    
    1,129,486
    
    
    
    495,053
    
    
    
    1,624,539
    
    
    
    1,009.9Proved developed reserves as of
December 31, 2001
    
    
    151,924
    
    
    
    203,808
    
    
    
    355,732
    
    
    
    561,834
    
    
    
    290,638
    
    
    
    852,472
    
    
    
    497.8Increase (decrease) originated in:Revisions of previous estimates
    
    
    (14,868
    )
    
    
    (113,425
    )
    
    
    (128,293
    )
    
    
    (258,150
    )
    
    
    (123,594
    )
    
    
    (381,744
    )
    
    
    (191.9
    )Improved recovery
    
    
    4,195
    
    
    
    3,510
    
    
    
    7,705
    
    
    
    76,371
    
    
    
    9,687
    
    
    
    86,058
    
    
    
    22.0Extensions and discoveries
    
    
    6,938
    
    
    
    10,057
    
    
    
    16,995
    
    
    
    88,265
    
    
    
    10,662
    
    
    
    98,927
    
    
    
    33.5Purchase of proved reserves in
place
    
    
    516
    
    
    
    
    
    
    
    516
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0.5Sale of proved reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Years production
    
    
    (20,719
    )
    
    
    (21,498
    )
    
    
    (42,217
    )
    
    
    (92,184
    )
    
    
    (22,352
    )
    
    
    (114,536
    )
    
    
    (61.3
    )Total proved reserves as of
December 31, 2002
    
    
    213,342
    
    
    
    380,536
    
    
    
    593,878
    
    
    
    943,788
    
    
    
    369,456
    
    
    
    1,313,244
    
    
    
    812.7Proved developed reserves as of
December 31, 2002
    
    
    146,319
    
    
    
    177,876
    
    
    
    324,195
    
    
    
    554,104
    
    
    
    209,854
    
    
    
    763,958
    
    
    
    451.5Increase (decrease) originated in:Revisions of previous estimates
    
    
    (19,026
    )
    
    
    (3,278
    )
    
    
    (22,304
    )
    
    
    (131,964
    )
    
    
    23,110
    
    
    
    (108,854
    )
    
    
    (40.4
    )Improved recovery
    
    
    10,082
    
    
    
    15,392
    
    
    
    25,474
    
    
    
    
    
    
    
    7,261
    
    
    
    7,261
    
    
    
    26.7Extensions and discoveries
    
    
    3,258
    
    
    
    18,303
    
    
    
    21,561
    
    
    
    61,370
    
    
    
    7,571
    
    
    
    68,941
    
    
    
    33.0Purchase of proved reserves in
place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Sale of proved reserves in place
    
    
    (7,707
    )
    
    
    
    
    
    
    (7,707
    )
    
    
    (49,450
    )
    
    
    
    
    
    
    (49,450
    )
    
    
    (15.9
    )Years production
    
    
    (21,097
    )
    
    
    (20,743
    )
    
    
    (41,840
    )
    
    
    (73,825
    )
    
    
    (22,517
    )
    
    
    (96,342
    )
    
    
    (57.9
    )Total proved reserves as of
December 31, 2003
    
    
    178,852
    
    
    
    390,210
    
    
    
    569,062
    
    
    
    749,919
    
    
    
    384,881
    
    
    
    1,134,800
    
    
    
    758.2Proved developed reserves as of
December 31, 2003
    
    
    122,085
    
    
    
    169,925
    
    
    
    292,010
    
    
    
    455,465
    
    
    
    207,144
    
    
    
    662,609
    
    
    
    402.4
   (1)
    
    Millions of barrels of oil equivalent. There are many uncertainties in estimating quantities of proved reserves
and in projecting future rates of production and the timing of development
expenditures, including certain factors that are beyond our control. The
reserve data set forth in this annual report solely represents estimates of our
proved oil and gas reserves. Reserve engineering is a subjective process of
estimating underground accumulations of crude oil and natural gas that cannot
be precisely measured. The accuracy of a reserve estimate stems from available
data, engineering and geological interpretation and judgment of reserves and
reservoir engineering. As a result, different engineers often obtain different
estimates. In addition, results of drilling, testing and production subsequent
to the date of an estimate may justify revision of such estimate, so the
reserve estimates at a specific time are often different from the quantities of
oil and gas that are ultimately recovered. Furthermore, estimates of future
net revenues from our proved reserves and the present value thereof are based
upon assumptions about future production levels, prices and costs that may not
prove to be correct over time. Forecasts of future prices, costs and
production levels are subject to great uncertainty and may not prove to be
correct over time. The meaningfulness of such estimates is highly dependent
upon the accuracy of the assumptions upon which they are based. Accordingly,
we cannot assure that any specified production levels will be reached or that
any cash flow arising therefrom will be produced. The actual quantity of our
reserves and future net cash flows therefrom may be materially different from
the estimates set forth in this annual report. We replace our reserves through the acquisition of new producing fields,
new exploration of our existing fields, the exploration of new fields, and by
proving up reserves in existing fields. Proving up is the process by which
additional reserves classified as probable and possible reserves in a
producing field are accessed and reclassified as proved reserves. We prove up
reserves with reservoir management techniques by implementing waterflood and
enhanced oil recovery projects. Reservoir management techniques currently used
include water injection and drilling of horizontal wells, including producing
and injection wells. In addition, technologies such as 3-D seismic process,
horizontal and step out wells, underbalance drilling and reservoir numerical
stimulation are also used. 38




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Transportation and Sales In Argentina, we transport our oil and gas production in several ways
depending on the infrastructure availability and the cost efficiency of the
transportation system in a given location. We use the Argentine oil pipeline
system and oil tankers to transport oil to customers. Oil is customarily sold
through FOB contracts, and therefore, producers are responsible for
transporting oil produced from the field to a port for shipping, with all costs
and risks associated with transportation borne by the producer. Gas, however,
is sold at the delivery point of the gas pipeline system near the field, and,
therefore, the customer bears the total transportation costs and all risks
associated therewith. Oil and gas transportation in Argentina operates in an
open access non-discriminatory environment under which producers have equal
and open access to the transportation pipelines. The privatization of the
pipeline system has led to capital investments in the systems, which have
increased their capacity. For the foreseeable future, our oil and gas
production is not expected to require increased capacity. In addition, we
maintain limited storage capacity at each oil site and at the terminals from
which oil is shipped. In the past, these capacities have been sufficient to
store oil without reducing current production during temporary unavailability
of the pipeline systems, due, for example, to maintenance requirements or
temporary emergencies. With respect to production from Block 18 in Ecuador, oil is transported by
a system which has a current transportation capacity of 17,000 barrels per day.
This capacity will be increased to 40,000 barrels per day. Once the Palo Azul
field has been completely developed, a 12-inch diameter and 35 km long oil
pipeline will be constructed from the oil treatment plant to Lago Agrio to
transport production through the OCP or the Sistema de Oleoducto
Transecuatoriano in accordance with the commercial circumstances prevailing at
that time. Future oil production from Block 31 will be transported through the OCP.
With respect to future oil production from Blocks 18 and 31, we have entered
into an agreement with OCP to ensure an 80,000 barrels per day oil
transportation capacity. See Business OverviewHydrocarbon Marketing and
TransportationOCP. During the fiscal year ended December 31, 2003, our main customers were
PDVSA, Perupetro, Repsol-YPF S.A., Trading y Transporte S.A., and Glencore AG,
which accounted for approximately 11%, 7%, 5% and 4%, respectively, of total
consolidated oil and gas sales, calculated on an unhedged basis. Intercompany
sales, mainly to the refining business segment, accounted for 34%. We sell a significant volume of our oil production to export markets. In
the current Argentine scenario, we, as well as other Argentine energy
companies, have sought to optimize export opportunities with a view to
capitalizing on domestic and export price asymmetries by effectively
encouraging the opening and consolidation of new markets. In such respect,
during the first quarter of 2003, we started exporting gas to Chile from the
Austral basin. During 2003, oil and gas exports totaled approximately P$474 million or
16% of total consolidated oil and gas sales (calculated on an unhedged basis).
In 2003, exports sales were made principally to Chile. Competition Our oil and gas related businesses are subject to oil price fluctuations
determined by international market conditions. In executing our strategy to
expand our oil and gas operations both in and outside of Argentina, we face
competition from oil and gas producers throughout the world. 39




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HYDROCARBON MARKETING AND TRANSPORTATION The hydrocarbon marketing and transportation segment serves to link our
energy businesses. In the marketing business, we provide oil, gas and LPG brokerage services
to producing companies who prefer outsourcing oil, gas and LPG sales. This
business enables us to position ourselves as a major commercial service
provider since it assists clients not only in sales but also in logistics,
foreign trade and market knowledge. We are engaged in the hydrocarbon transportation business through our
interest in TGS, Oleoductos del Valle S.A., or Oldelval, and OCP. Gas Transportation  TGS We hold, directly or indirectly, a 35% interest in TGS. TGS is controlled
by CIESA, which, together with other companies of the Petrobras Energía group
and the Enron group, own 70% of TGS capital stock. CIESA, in turn, is owned
on a 50/50 basis by Enron Corporation, or Enron, and us. An ownership committee composed of an equal number of our representatives
and those of Enron manages the activities of TGS and CIESA. We appoint the
chairman of the board and the chief executive officer of both TGS and CIESA.
TGS and Enron have entered into a technical services agreement under which TGS
pays Enron an annual fee equal to the greater of (i) P$3 million or (ii) 7% of
the amount obtained after subtracting P$3 million from the net income before
financial income (expense) and income taxes. We share in these management fees
through an agreement with Enron in which we are reimbursed for any costs
associated with any service provided by TGS on behalf of Enron and a percentage
of the exploitation income. In June 2004, the Federal Entity of Gas
Regulation, or ENARGAS, authorized the assignment by Enron of its duties under
this agreement to us. Both Enron and we have a right of first refusal on the
transfer of CIESAs shares, and preferential rights to any shares issued by
CIESA. Pursuant to the regulatory framework, gas transportation and distribution
rates were established under the Natural Gas Law and the Concession Contract,
which provide the methodology of calculation and adjustment frequency of
natural gas rates charged to end users by distribution companies. As a result
of the reforms implemented under the Public Emergency Law, which, among other
things, provided for the conversion into pesos of utility rates and the
elimination of indexation of such rates, the gas transportation business
currently operates in an uncertain environment. See Regulation of Our
Businesses. As a result of this abrupt change in rules, CIESA failed to repay
corporate notes with a principal amount of U.S.$220 million and derivative
instruments of approximately U.S.$2 million. In addition, TGS is seeking to
restructure substantially all of its financial debt and is currently in
discussions with its principal creditors. See Item 3. Key InformationRisk
FactorsThe devaluation and pesification of utility rates have resulted in
payment defaults by some of our affiliates. In April 2004, CIESAs shareholders reached a mutual settlement agreement
by which Petrobras Energía and Enron agreed to release each other from all
claims related to their investments in CIESA and TGS. In addition, in order to
facilitate a future restructuring of CIESAs financial debt, both parties
agreed to a two-stage transfer involving their equity interests in TGS and
CIESA. In stage one, we will transfer our 7.35% direct interest in TGS to
Enron, and, in stage two, CIESA will transfer a 4.3% interest in TGS to Enron.
In exchange, Enron will place its shares of CIESA in trust, 40% in stage one
and the remaining 10% in stage two. We will not hold directly or indirectly
more than our current 50% shareholding in CIESA. These transfers are subject
to several conditions, one of which is approval by ENARGAS. In May 2004, the
bankruptcy court with jurisdiction over Enron also approved the terms of this
settlement agreement. CIESA initiated discussions with its creditors regarding
a possible restructuring. As far as the regulated segment is concerned, TGS is the gas
transportation licensee in the south of Argentina. TGS has an exclusive license
due to expire in 2027 with an option to extend for ten additional years if
certain conditions are met, and as such is the largest transporter of natural
gas in Argentina and all of Latin America. TGS currently delivers
approximately 60% of the countrys total gas consumption through more than
7,400 km of gas pipelines with a transportation capacity of approximately 62.5
million cubic meters per day, substantially all of 40




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which is committed under firm transportation contracts. Under these firm
transportation contracts, the capacity is reserved and paid for irrespective of
the actual use by the customer. Almost all capacity of the gas transportation
pipelines in Argentina is currently apportioned among gas distribution
companies, large industrial customers and gas-fired power plants under firm
long-term contracts. In 2003, TGS renewed firm transportation agreements
covering approximately 12.9 million cubic meters per day. This enabled it to
extend the total average life of its firm transportation contracts to
approximately nine years. In addition, TGS provides interruptible
transportation services under which gas transportation is dependent on the
availability of capacity. The TGS pipeline system connects major gas fields in southern and western
Argentina with distributors of gas in those areas and in the city of Buenos
Aires and the greater Buenos Aires area. The service area includes
approximately 4.6 million end users (approximately 3.2 million of which belong
to the greater Buenos Aires area), which are directly served by distribution
companies. In addition, TGS provides transportation services on a direct basis
to major industries located in TGSs operating area. The firm transportation
capacity committed to industrial clients represents approximately 20% of TGSs
total capacity. Since the start of operations in 1992, TGS has made investments of about
U.S.$1.2 billion, doubling the value of its assets. As a result of such
investment 850 km of gas pipelines were laid in addition to the existing
pipelines, and compression power was increased by 58.8% from 339,000 HP in 1992
to 538,220 HP in 2003. Therefore, transportation capacity increased from 42.8
million cubic meters per day to 62.5 million cubic meters per day at the end of
2003. Gas transportation companies in Argentina operate in an open access
non-discriminatory environment under which producers, distributors and certain
third parties have equal and open access to the transportation pipelines and
distribution system. See Regulation of Our BusinessesThe Argentine Gas
Industry and Regulatory Framework. As a consequence of the enactment of the Public Emergency Law, revenues
from the regulated segment strongly decreased compared to TGSs total revenues.
In 2003, the gas transportation segment accounted for 47% of TGSs total
revenues compared to 57% in 2002 and to approximately 80% since the start of
the service supply until 2001. TGS continues seeking new alternatives aimed at
growing its business and mitigating the effects derived from such law. Along
these lines, in 2003, TGS entered into an agreement with a consortium producing
gas at the Austral basin, formed by Total Austral S.A., Panamerican Sur S.R.L.
and Wintershall Energía S.A., for the purpose of providing Argentine natural
gas to Methanex, a leading company in the production of methanol located in
Chile. In view of the set of measures taken by the Argentine government aiming to
lessen the impact of the energy crisis emerging in 2004, TGS is currently
analyzing several alternatives along with the government, with the object to
implement the expansion of the San Martín gas pipeline. In furtherance of this
goal, TGS launched an Open Season, which offers 2.9 MMm3/d of firm
transportation capacity in service as from the middle of 2005. In connection
with this additional capacity, TGS would not only render the service of
transportation but the operation and maintenance of the facilities as well. In addition to the natural gas transportation regulated service, TGS is
one of the leading processors of natural gas and one of the largest marketers
of natural gas liquids, or NGL, and provides other unregulated services in the
gas industry, through the General Cerri Complex located near Bahía Blanca, in
the Province of Buenos Aires. TGS has two gas processing plants at the General
Cerri Complex: (i) an ethane, propane, butane and natural gasoline
turboexponder separating plant and (ii) an absorption plant which separates
propane, butane and gasoline from the gas transported through the TGS pipeline
system, with a gas processing capacity of 43 million cubic meters per day and a
storage capacity of 54,840 tons. From 2001 to 2002, as a result of the
agreements entered into with natural gas producers in the Neuquén basin, TGS
managed to restructure the business and became the owner of a portion of the
Cerri Complex production. TGS was able to increase, through these agreements,
the richness of the gas reaching the complex for processing, and thus minimized
the impact of competitive projects. The economic crisis during 2002 presented an opportunity for TGS, as 33%
of its total NGL production is exported, enabling TGS to benefit from
devaluation of the peso. In addition, local market prices increased in order
to maintain parity with export prices. The combination of these factors led to
an increase in TGS revenues. 41




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Revenues from unregulated services compared to TGSs total revenues
increased from 37% in 2002 to 48% in 2003. This evidences the growing relative
significance of this business. This improvement substantially reflects the
deterioration of the regulated gas transportation business and favorable
domestic market prices in line with international prices. TGS is an important midstream service provider in Argentina offering
commercial and financial structuring, turnkey construction and the operation
and maintenance of surface facilities (gathering, conditioning and
transportation). Through the provision of midstream services, TGS provides integral
solutions for natural gas supply from the wellhead to transportation, including
conditioning, gathering and gas compression, which services are generally
provided to producers at the wellhead. Such services also include those
related to the construction, operation and maintenance of gas pipelines and
treatment plants provided by TGS itself or through its related companies, Gas
Link S.A., or LINK, and Transporte y Servicios de Gas en Uruguay S.A., or TSGU.
TGS is developing a strategy geared towards becoming one of the main service
providers in Argentina. During 2003, TGS completed the renegotiation with this
segments clients of the outstanding midstream services agreements that were
still pesified. As a result of this renegotiation, TGS improved the
profitability associated with such agreements while its clients secured a
long-term supply of services. TGS has a 49% interest in LINK, a company engaged in the construction,
operation and maintenance of the gas pipeline connecting the TGS system and the
Cruz del Sur gas pipeline that links Argentina to Uruguay and is likely to be
extended to Brazil. This pipeline is approximately 40 km long, has a current
transportation capacity of 1 million cubic meters per day and started
operations in October 2002. Under the agreement for the supply of Argentine natural gas to Methanex in
Chile, TGS will install a 12,700 HP compressor plant on the General San Martín
pipeline, and, through its affiliated company Emprendimientos de Gas del Sur
S.A., or EGS, will construct a 6 km long gas pipeline with an initial capacity
of 1 million cubic meters per day (with a 1.2 million cubic meters per day
extension scheduled for 2009) which will link TGSs main system to the Chilean
border. TGS, through its interest in EGS, connects its gas transportation
system to the Chilean market. TGS and TSGU have a 49% and a 51% interest in
EGS, respectively. In turn, 49% of TSGUs capital stock is owned by TGS. The following chart shows statistical information relating to TGSs
business segments for fiscal years ended December 31, 2003, 2002 and 2001. 2003
    
    2002
    
    2001Regulated SegmentTotal available capacity at year end (in MMm3/d)
    
    
    62.5
    
    
    
    62.5
    
    
    
    62.5Average firm committed capacity (in MMm3/d)
    
    
    61.7
    
    
    
    61.4
    
    
    
    60.7Average daily deliveries (in MMm3/d)
    
    
    52.6
    
    
    
    49.4
    
    
    
    46.7Annual load factor
    
    
    85%
    
    
    
    80%
    
    
    
    77%Unregulated SegmentLiquids total production (in thousand tons)
    
    
    929.1
    
    
    
    908.5
    
    
    
    822.3Processing capacity at year end (in MMm3/d)
    
    
    43.0
    
    
    
    43.0
    
    
    
    43.0
 Oldelval Oldelval, a company in which we have a 23.1% interest, holds the
concession for the transportation of crude oil through 888 km-long oil
pipelines with 1,706 km of installed piping, between the Neuquén basin and
Puerto Rosales (located in the Province of Buenos Aires) for a 35-year period
starting in 1993 with an option to renew for ten years. Oldelvals other
shareholders are Repsol-YPF, Petrolera San Jorge, Pluspetrol, Pan American and
Tecpetrol. The Allen/Puerto Rosales section transportation capacity is of
approximately 265,000 barrels per day, with a 173,000 m3 storage capacity. In
2003 and 2002, Oldelval transported approximately 65 million and 66 million of
oil barrels, respectively, from the Neuquén basin to the Atlantic coast. 42




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The applicable laws governing the transportation of hydrocarbons through
oil pipelines, which are based on the free access notion, assign loading
preference quotas to pipeline owners based on their shareholdings. Oil
transportation rates are set by the Argentine Secretary of Energy. OCP The Government of Ecuador awarded OCP with the construction and operation
for a 20-year term of the 503 km long pipeline that runs from the northeastern
region of Ecuador to the Balao distribution terminal on the Pacific Ocean
coast. As of December 31, 2003, we held an 8.96% interest in OCP. In May
2004, Techint International Construction Corporation, or Tenco, exercised an
option to sell to us its shares and subordinated debt in OCP, comprising a
2.46% ownership interest. In accordance with the terms of the option, we paid
U.S.$14 million for Tencos ownership interests in OCP. Consequently, our
interest in OCP increased to 11.42%. OCPs other shareholders are Encana,
Perenco, Occidental and Repsol-YPF. The oil pipeline has a 450,000 barrels per day transportation capacity of
which at least 390,000 barrels per day have been committed to OCP shareholders
under a ship or pay contract for transportation of their production. Since
the oil pipeline runs across ecologically sensitive areas, the pipeline was
construed under stringent environmental protection and technical standards. The construction of the oil pipeline was performed by Techint
International Construction Corporation and was completed during 2003. After
testing the system at its maximum capacity and the approval by the Ministry of
Energy and Mines of Ecuador, the oil pipeline officially started operations on
November 10, 2003. OCPs original budget amounted to U.S.$1,210 million, U.S.$900 million of
which was funded by banking institutions, U.S.$250 million of which was funded
by subordinated loans from shareholders and U.S.$60 million through capital
contributions. We made contributions in the amount of U.S.$9 million and were
granted a 15% shareholding interest. The total construction cost of the oil
pipeline amounted to U.S.$1.4 billion, which was U.S.$190 million in excess of
the original budget. The need for additional financing was satisfied through
loans and capital contributions by shareholders in the amount of U.S.$150
million and U.S.$40 million, respectively. We did not make any such
contributions and our equity interest was diluted from 15% to 8.96%. Regarding future production from Blocks 18 and 31 in Ecuador, we, through
Petrobras Energía Ecuador, entered into the ship or pay contract with OCP,
whereby OCP has committed to transport 80,000 barrels per day for a 15-year
term, as from the start of its operations. We, as well as the remaining
producers, must pay transporation capacity fee. Competition TGSs gas transportation business, which provides an essential service in
Argentina, faces only limited direct competition. In view of the
characteristics of the markets in which TGS operates, it would be very
difficult for a new entrant in the transportation market to pose a significant
competitive threat to TGS, at least in the short to medium term. In the longer
term, the ability of new entrants to successfully penetrate TGSs market would
depend upon a favorable regulatory environment, an increasing and unsatisfied
demand for gas by end users, and sufficient investment in gas transportation to
accommodate increased delivery capacity from the transportation systems. On a day-to-day basis, TGS competes, to a limited extent, with
Transportadora de Gas del Norte S.A. for interruptible transportation services
and for new firm transportation services made available as a result of
expansion projects from the Neuquén basin to the greater Buenos Aires area.
Interruptible transportation services accounted for only 4.5% of TGSs
regulated net revenues for 2003. The relative volumes of such services will
depend principally upon the specific arrangements between buyers and sellers of
gas in such areas, the perceived quality of services offered by the competing
companies, and the applicable rate for each company. With respect to NGL processing activities, TGS competes with MEGA S.A.,
which owns a gas processing plant at the Neuquén basin and has a processing
capacity of approximately 36 million cubic meters per day. Early in 2001,
operations at this processing complex began and the gas from this basin reached
TGS Cerri Complex with a low liquid content. In order to mitigate this effect,
TGS increased the rich gas contribution to the system under agreements
subscribed with gas producers at the Neuquén Basin and was able to restore NGL
production levels at 43




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Cerri Complex to levels similar to those recorded prior to the start of
MEGA S.A. operations. In addition, a third of this production is marketed
abroad and domestic market prices were increased to reach, in terms of U.S.
dollars, parity with dollar-based export prices. Our controlling company,
Petrobras, has a 34% interest in MEGA S.A. MEGA S.A.s other shareholders are
Repsol-YPF (38%) and Dow Chemical (28%). REFINING Our presence in the refining business moves us toward vertical integration
of our operations. The refining business is a tool that enables us to
capitalize on our significant hydrocarbon reserves. Refining operations are a
necessary link in the business value chain, which starts with crude oil
exploration and ends with customer service. Our refining segment offers the
most immediate prospects of further developing and taking advantage of business
opportunities jointly with Petrobras, and some opportunities have already begun
to materialize for us. Our refining operations are located in Argentina and Bolivia. In
Argentina, we operate our own refinery in San Lorenzo and have a 28.5% interest
in Refinería del Norte S.A., which we refer to as Refinor. In Bolivia, as of
December 31, 2003, we had a 49% interest in Empresa Boliviana de Refinación,
which we refer to as EBR. The Refining Business in Argentina During recent years, the Argentine liquid fuel market was adversely
affected by the growth of CNG as substitute fuel. The high taxes imposed on
gasoline and, to a lesser extent, on diesel consumption, still affect the
market, encouraging the use of CNG to the detriment of liquid fuels. Thus, the
gasoline domestic market shrank 10% in 2003 in line with the downward trend of
the previous eight years. The drop in the demand for gasoline totaled
approximately 48% in the 1995-2003 period. Our share of the gasoline market
has climbed to 3.1% from 2.9%. Demand for diesel grew 4% in 2003, the first a recovery after a four-year
decline, halting a prolonged downward trend in the market which had resulted in
a 14% drop from 1999-2002. Refining Division We operate a refinery in San Lorenzo, Province of Santa Fé, strategically
located along the central product distribution systems. The refinery capacity
is approximately 37,700 barrels of oil per day, enabling us to process a large
part of our crude oil production in Argentina. The refinery has three atmospheric distillation units, two vacuum
distillation units, a heavy diesel oil thermal cracking unit and an aircraft
fuel production unit, which produce the following products: premium and regular
gasoline, jet fuel, diesel oil, fuel oil, kerosene, solvents, aromatics and
asphalts. The refinery has two fuel storage and dispatch plants located in the
Provinces of Santa Fe and Buenos Aires, respectively. At our Dock Sud
facilities, in the Province of Buenos Aires, crude oil is received, stored and
dispatched. The Dock Sud facility has a total storage capacity of 60,000m3.
Crude oil is received from the oil pipeline connecting Bahía Blanca with Dock
Sud and is dispatched to tankers transporting the oil to the San Lorenzo
refinery. In addition, the San Lorenzo refinery located on the right bank of
the Paraná River, with access from the so-called hydroway forming part of the
Océano-Santa Fé trunk navigation route, has three docks for 250 meter-long
vessels having 70,000 ton displacement. As of December 31, 2003, we had a commercial network of 119 retail
outlets, including 84 gas stations (eight directly operated by us), 20 diesel
centers, six mobile diesel centers and nine agro-service centers, located in
the Provinces of Santa Fé, Buenos Aires, Entre Ríos, Corrientes, Santiago del
Estero, Tucumán, San Juan, San Luis, Catamarca, Chaco, Formosa, Salta, Mendoza
and Córdoba. In line with our business integration strategy, we continue to
expand our own retail network following a medium-term plan aimed at selling the
largest volume of fuels produced by us. In order to reposition the gas station
network and to leverage the synergies with our controlling shareholder, during
2003 we agreed to use the Petrobras brand name in seven gas stations that we
own. Over the last few years, Petrobras has built an excellent image for its
brands, products, and services in Argentina, currently competing with the image
of the leading companies in the country. Negotiations continue over a
long-term agreement for the use of the Petrobras brand in all our retail
network. 44




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In addition, we subscribed to an agreement to market Lubrax lubricants in
our gas station network. These lubricants manufactured by Petrobras attained a
8.5% share of the domestic market in a relatively short period of time and
experienced the highest growth rate among lubricants in 2003. The technical,
commercial and advertising efforts Petrobras is making for the development of
the Lubrax brand give considerable support to our sales growth in this
business. The following table shows production and sales figures for the Refining
Division for the fiscal years ended December 31, 2003, 2002 and 2001: Year Ended December 31,2003
    
    2002
    
    2001Production (thousands of tons)Virgin naphtha
    
    
    417
    
    
    
    325
    
    
    
    324Diesel oil
    
    
    613
    
    
    
    499
    
    
    
    522Other products
    
    
    619
    
    
    
    507
    
    
    
    527Sales (thousands of tons/m3)Aromatics (thousands of tons)
    
    
    56
    
    
    
    67
    
    
    
    65Benzene (thousands of tons)
    
    
    50
    
    
    
    44
    
    
    
    45Gasoline (thousand m3)
    
    
    119
    
    
    
    123
    
    
    
    126Diesel oil (thousand m3)
    
    
    883
    
    
    
    622
    
    
    
    743Other medium distillates (thousand m3)
    
    
    11
    
    
    
    13
    
    
    
    24Asphalts (thousands of tons)
    
    
    86
    
    
    
    43
    
    
    
    79Reformer plant products (thousands of tons)
    
    
    79
    
    
    
    65
    
    
    
    69Other heavy products (thousands of tons)
    
    
    418
    
    
    
    374
    
    
    
    266Paraffins (thousands of tons)
    
    
    151
    
    
    
    138
    
    
    
    97Sales (in millions of pesos)Argentina
    
    
    956
    
    
    
    636
    
    
    
    702Outside of Argentina
    
    
    346
    
    
    
    372
    
    
    
    86Total
    
    
    1,302
    
    
    
    1,008
    
    
    
    788
 During 2003 our refinery processed an average of 32.6 thousand barrels per
day. Crude oil volumes processed accounted for about 86% of the refining
capacity. During 2003, 210,000 cubic meters of diesel oil were sold to EG3 S.A.,
which we refer to as EG3, a company controlled by Petrobras, which caused an
increase in crude oil processing at our San Lorenzo refinery to levels much
higher than those recorded over the last few years and on profitable terms for
us. This was possible because EG3 had been forced to import diesel oil since
its production capacity at the Bahía Blanca Refinery is insufficient to supply
its extensive retail outlet network. Since our diesel oil production at San
Lorenzo exceeds the demand from our gas station network, significant volumes
were exported to other countries in the region. Therefore, attractive
long-term business opportunities may exist for both companies. As of December 31, 2003, considering statistical data for the last month,
we had a market share of approximately 3.1% in the gasoline market, 4.6% in the
diesel oil market, 23.6% in the asphalt market and 15.1% in the fuel oil
market. In addition, our share in the gas oil bunker (intermediate fuel oil)
market totaled 23.2%. Refinor We have a 28.5% interest in Refinor. Refinors other two shareholders are
Repsol-YPF (50%) and Pluspetrol Exploración y Producción S.A. (21.5%). Refinor owns the only refinery located in Campo Durán, Province of Salta,
in the northern region of Argentina. Refinors refining capacity is 26,000
barrels of oil per day and its natural gas processing capacity is 19 million
cubic meters per day. Refinor receives crude oil and natural gas from the oil
and gas fields located at the northwestern region of Argentina and Bolivia. It
has an atmospheric distillation unit, a vacuum distillation unit, a catalytic
reformer plant, two turboexpander plants and a compressor plant. Refinor
produces diesel oil, fuel oil, 45




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motor gasoline, virgin naphtha, propane, butane, raw gasoline and LPG. It
is the leaching LPG producer based on volume produced in the northern region of
Argentina and the third largest producer in the country. In May 2003, a
gathering and compression system that takes enriched gas from the Chango Norte
field began operations. This system required an investment of approximately
U.S.$13 million. As of December 31, 2003, Refinor had a commercial network comprising 65
gas stations (14 owned by Refinor) located in the Provinces of Salta, Tucumán,
Jujuy, Córdoba, Santiago del Estero, Catamarca and Chaco and started developing
the commercial network in Bolivia, where it has five gas stations under its
brand and two more under development. For logistics and distribution purposes,
Refinor operates a 1,112 km poliduct that extends from our compression station
in Campo Durán (Salta) to Montecristo (Córdoba). Along the pipeline, layout
product recompression stations are located at Urundel (Salta), Lavallén
(Jujuy), Cobos and Piedras (Salta) and Quilino (Córdoba). The pipeline
supplies the following dispatch plants:  
    
    General Mosconi (Salta), with a 9,908 m3 storage capacity
(fuels);
    
    General Güemes (Salta), with a 1,800 m3 storage capacity
(liquefied gas), and which started operations in 2003 replacing the
old Tres Cerritos dispatch plant;
    
    Banda del Río Salí (Tucumán), with a 57,508 m3 storage capacity (fuels); and
    
    Leales (Tucumán), with a 5,054 m3 storage capacity (liquefied gas). In addition, the poliduct discharges a large volume of product,
petrochemical gasoline and liquefied gas at the Terminal Station located at
Montecristo (Córdoba), and such products are then dispatched in the area or
sent to San Lorenzo, Province of Santa Fé. In 2003, Refinor commenced the commercialization of LPG in bulk, with
1,150 tons/year. The following table sets forth Refinors sales and production for the fiscal
years ended December 31, 2003, 2002 and 2001: Year ended December 31,2003
    
    2002
    
    2001Production (thousands of tons/m3)Gasoline (thousand m3)
    
    
    122
    
    
    
    121
    
    
    
    125Virgin naphtha (thousand m3)
    
    
    420
    
    
    
    473
    
    
    
    514Diesel oil (thousand m3)
    
    
    330
    
    
    
    335
    
    
    
    368Natural gasoline (thousand m3)
    
    
    129
    
    
    
    134
    
    
    
    137Propane/butane (thousand tons)
    
    
    313
    
    
    
    287
    
    
    
    241Other products (thousand m3)
    
    
    138
    
    
    
    100
    
    
    
    75Sales (thousands of tons/m3)Gasoline (thousand m3)
    
    
    121
    
    
    
    122
    
    
    
    139Virgin naphtha (thousand m3)
    
    
    550
    
    
    
    611
    
    
    
    619Diesel oil (thousand m3)
    
    
    378
    
    
    
    374
    
    
    
    368Propane/butane (thousand tons)
    
    
    297
    
    
    
    274
    
    
    
    239Other products (thousand m3)
    
    
    97
    
    
    
    103
    
    
    
    75Sales (in millions of pesos)Argentina
    
    
    490
    
    
    
    428
    
    
    
    350Outside of Argentina
    
    
    373
    
    
    
    412
    
    
    
    241Total
    
    
    863
    
    
    
    840
    
    
    
    591
 In 2003, Refinors sales through its service centers had a share in the
motor gasoline and diesel oil markets in the northwest of Argentina of 25% and
18.2%, respectively. In addition, Refinor reached a 55% share in the diesel
oil import market in Bolivia. 46




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Empresa Boliviana de Refinación We have a 49% interest in Empressa Boliviana de Refinanción, or EBR.
Petrobras is its strategic partner, with a 51% interest. EBR owns two Bolivian refineries located in Cochabamba and Santa Cruz de
la Sierra, with an estimated maximum production capacity of 48,000 barrels of
oil per day, accounting for 95% of Bolivias total refining capacity. In 2003,
an average of 32,600 barrels per day were processed. EBR wholly owns Empresa Boliviana de Distribución, or EBD, a company
having a commercial network of 81 gas stations, six of which were incorporated
during the last fiscal year. In 2003, EBD continued implementing the
Integrated Gas Stations concept in Bolivia, by offering supplemental products,
while focusing on first-class customer services, product quality and quantity. Competition We compete in Argentina with Repsol-YPF, Shell and Esso, who combined have
a predominant share in this market. 47




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PETROCHEMICALS Overview Our strategy in this segment is to optimize the oil-refined
products-polymer chain. The petrochemicals business is an integral part in our
strategy of vertically integrating our operations by taking advantage of
operating synergies and positioning us as a low-cost producer of hydrocarbons,
thereby allowing us to reap the benefits of our significant hydrocarbon
reserves. Our petrochemical operations are performed in Argentina and Brazil,
through the production of a wide array of products, such as styrene,
polystyrene, synthetic rubber, fertilizers and polypropylene, both for the
domestic and export markets. We are the only producer of styrene monomer, polystyrene and elastomers in
Argentina and the only integrated producer from oil and natural gas to plastic
products (such as bioriented polystyrene sheets) or the production of
fertilizers. Through Innova, our wholly owned subsidiary in Brazil, we have the
regions largest installed capacity for the production of styrene and
polystyrene, with the benefit of providing service to clients from both
locations. In Argentina, we supply more than one-third of the Argentine fertilizer
market with a wide array of specific solutions and are the only liquid
fertilizer producer in the region. We also have a 40% interest in Petroquímica Cuyo S.A., which accounts for
a portion of our petrochemical operations. Argentine Operations Argentine Styrenics Division The Styrenics Division has a plant at Puerto General San Martín, Province
of Santa Fé, with a production capacity of 110,000 tons of styrene per year and
55,000 tons of synthetic rubber per year, and a plant at Zárate, Province of
Buenos Aires, with a production capacity of 66,000 tons of polystyrene per year
and 14,000 tons of bioriented polystyrene per year. This state-of-the-art
plant in Zárate is the only one of its type in Latin America. As part of our efforts to achieve full integration, we use a large amount
of styrene for the production of polystyrene and synthetic rubber. In March of 2004, we acquired from Imperial Chemical Industries an
ethylene plant which is located in San Lorenzo and has a production capacity of
18,000 tons per year. The increased production capacity of ethylene will allow
us to increase our production of ethylbenzene and to take advantage of the
spare capacity of the plant. This, in turn, will allow Innova to increase
production of styrene and operate at full capacity. Our greater production of styrene monomers will enable us to meet the
growing demand in the region. As of December 31, 2003, our estimated share in the domestic market was:
styrene 100%, polystyrene 70%, styrene butadiene rubber, or SBR, combined with
the market for nitrite butadiene rubber, or NBR, approximately 90%. Exports are a significant part of our business. Recent changes in trade
policy have helped us to consolidate our position in foreign markets,
especially in Mercosur and in Chile. In 2003, we exported 47%, 61% and 45% of
our total sales volumes of styrene, rubber and polystyrene, respectively. With
respect to styrene, our position in the Chilean market was further
consolidated, and we were able to maintain a leading position in the Mercosur
region, considering market shares both in Argentina and Brazil through Innova.
In addition, a record was set for the export of bioriented polystyrene (8
thousand tons), the main destinations being the European and United States
markets. SBR export volumes were in line with 2002 volumes, consolidating our
presence in the Brazilian market. 48




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Fertilizers Division We are pioneers in the production and distribution of fertilizers in
Argentina. As leader in the market, we developed a new liquid product line
during recent years with wide acceptance among agricultural producers. The Fertilizers Division has a plant located at Campana, Province of
Buenos Aires, with a production capacity of 190,000 tons/year of urea. In
2003, we doubled the installed production capacity of UAN, our liquid
fertilizer (a composition of urea and amonium nitrate) to 475,000 ton/year. We
are the only producer of liquid fertilizer in Latin America. Liquid storage
capacity has been increased to 40,000 tons, which together with an automatic
and computerized loading facility, has allowed us to manage the growth in
liquids production. During 2003, we started the construction of a 130,000 ton/year thiosulfate
fertilizer plant, which required investments of approximately U.S.$8 million.
Thiosulfate fertilizer has been designed to incorporate nitrogen for wheat and
corn and sulfur for soybean, with great success in pre-marketing. We have 700 customers throughout Argentina, and 130 are distributors with
their own storage facility centers, complementing our warehouses and assistance
centers in Buenos Aires, Santa Fé, Mendoza and Tucumán provinces. The following table sets forth production and sales by major product for
both the Styrenics and Fertilizers Divisions for the fiscal years ended
December 31, 2003, 2002 and 2001: Year ended December 31,2003
    
    2002
    
    2001Production (thousands of tons)Styrene (1)
    
    
    106
    
    
    
    98
    
    
    
    95Synthetic rubber (2)
    
    
    56
    
    
    
    51
    
    
    
    47Urea
    
    
    193
    
    
    
    190
    
    
    
    180UAN
    
    
    184
    
    
    
    145
    
    
    
    110Polystyrene
    
    
    57
    
    
    
    61
    
    
    
    62Bops
    
    
    11
    
    
    
    6
    
    
    
    6Sales (in millions of pesos)Styrene (1)
    
    
    124
    
    
    
    100
    
    
    
    63Synthetic rubber (2)
    
    
    161
    
    
    
    138
    
    
    
    94Fertilizers
    
    
    304
    
    
    
    259
    
    
    
    228Polystyrene and Bops (3)
    
    
    180
    
    
    
    170
    
    
    
    120Other products and services
    
    
    23
    
    
    
    26
    
    
    
    16Total
    
    
    792
    
    
    
    693
    
    
    
    521Export Sales (in millions of pesos)
    
    
    260
    
    
    
    223
    
    
    
    106
   (1)
    
    Including styrene monomer and by-products.(2)
    
    Including SBR, NBR and butadiene.(3)
    
    Net of 5, 25 and 9 intercompany eliminations. Petroquímica Cuyo Petroquímica Cuyo S.A., which we refer to as Cuyo, is primarily involved
in the production and marketing of polypropylene. We and Admire Trading
Company are Cuyos main shareholders, with a 40% and 50.5% interest,
respectively. Cuyos industrial plant, located at Luján de Cuyo, Province of
Mendoza, has a production capacity of approximately 100,000 tons/year. The
quality and specialization of products have enabled Cuyo to enter international
markets and export to several countries in the world, especially to Mercosur
member countries and Chile. Approximately 87% of the propylene feedstock required for Cuyos
operations is supplied by Repsol-YPF from its Luján de Cuyo refinery under a
long-term contract set to expire in 2014. 49




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Cuyo is a licensee of the Novolen Technology Holding company, a member of
the ABB Lumus Group, engaged in the production and marketing of polypropylene.
In addition, it maintains transfer, assistance and technology upgrade
agreements, allowing it to be a leading company in product applications and to
serve the market with world-class processes and products. The following table sets forth Cuyos production and sales for the fiscal
years ended December 31, 2003, 2002 and 2001. Year ended December 31,2003
    
    2002
    
    2001Production (thousand of tons)
    
    
    87
    
    
    
    84
    
    
    
    80Sales (in millions of pesos)
    
    
    225
    
    
    
    200
    
    
    
    132
 Brazilian Operations Our petrochemical operations in Brazil are conducted through Innova, our
wholly owned subsidiary. Innova is the first integrated plant in Latin America
for the production of ethylbenzene, styrene and polystyrene in one site,
located at Triunfo Petrochemical Pole, Rio Grande do Sul, in the south of
Brazil. The styrene plant has a production capacity of 250,000 tons per year
and the polystyrene plant has a production capacity of 120,000 tons per year.
Our styrene and polystyrene plants began commercial operations in January and
October 2000, respectively. Copesul, a Brazilian company, supplies the benzene
and ethylene feedstock necessary for the production of styrene pursuant to a
long-term contract. The polystyrene plant uses approximately 110,000 tons of styrene monomer
as the feedstock to produce two grades of polystyrene (Crystal and High
Impact). The remainder is sold mainly in the Brazilian market for the
production of synthetic rubber, expanded polystyrene, polyester and acrylic
resins. As of December 31, 2003, Innova was Brazils largest styrene producer and
merchant (not including styrene used in the production of polystyrene), and one
of Brazils largest polystyrene producers and merchants, with an estimated 47%
and 26% market share, respectively. Sony Corporation recognized Innova as Green Partner, which is only
awarded by Sony after a thorough examination of suppliers. Innova is the only
polystyrene supplier in Brazil to receive this recognition. In addition,
Yakult approved a polystyrene grade developed by Innova, making Innova the
third supplier in the world recognized by this client. The following table sets forth Innovas production and sales of styrene
and polystyrene for the fiscal years ended December 31, 2003, 2002 and 2001. 2003
    
    2002
    
    2001Production (in thousands of tons)Styrene
    
    
    175
    
    
    
    179
    
    
    
    165Polystyrene
    
    
    86
    
    
    
    96
    
    
    
    92Sales (in millions of pesos)Styrene
    
    
    216
    
    
    
    234
    
    
    
    100Polystyrene
    
    
    255
    
    
    
    298
    
    
    
    183Other
    
    
    31
    
    
    
    29
    
    
    
    14Total sales
    
    
    502
    
    
    
    561
    
    
    
    297
 50




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Competition The petrochemical markets in which we compete are highly cyclical, and our
results in these businesses are heavily influenced by world market conditions.
We are the only producer of styrene and synthetic rubber in Argentina, but
compete with other foreign producers, especially those in Brazil. In the
fertilizers market, we compete with Profertil S.A., a local urea and ammonia
producer with a production capacity of one million tons per year and other
players who import and mix fertilizers such as Cargill, Nidera and Hidro Agri
Arg. Profertil is owned by Repsol-YPF and Agrium S.A. In the polypropylene
business, Petroken S.A is Cuyos main competitor with a production capacity of
180,000 tons per year. In Brazil, we mainly compete with Dow Chemical and BASF, who, after
expansion of their San Paulo plants in 2001, have a polystyrene production
capacity of 190 and 180 thousand tons per year, respectively. In addition,
Videolar, a Brazilian producer, operates a 120 thousand ton capacity plant in
Manaos. Nevertheless, we do not believe our revenues will be adversely
affected, considering the strategic geographical location of our plants and
their target markets, in addition to Innovas low cost producer nature. Based
on the above, we believe we will maintain our current market position in the
future. 51




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ELECTRICITY In the electricity business, we are involved in all three industry
segments: generation, transmission and distribution. Thus, we are positioned
as a major player in the Argentine electricity market. We believe that electricity generation allows us to accelerate
monetization of our significant gas reserves. Electricity transmission and
distribution provides us with new growth opportunities, adding value through
the sale of power and energy services to end users, as well as, through the
development of cutting-edge technology. We conduct electricity generation activities through our Genelba Power
Plant in the Province of Buenos Aires and Pichi Picún Leufú hydroelectric
complex, or HPPL, in the Comahue region, on the Limay River, Province of
Neuquén. In addition, we have a 9.19% interest in Hidroneuquén S.A., a company
controlling 59% of Hidroeléctrica Piedra del Aguila S.A., a hydroelectric
complex located on the Limay River, in the Comahue region, in the dividing line
between the Provinces of Neuquén and Río Negro. We are engaged in the
transmission business through our interests in Transener (through Compañía
Inversora en Transmisión Eléctrica Citelec S.A., or Citelec), Enecor S.A. and
Yacylec S.A, and the electricity distribution business through our interest in
Edesur (through Distrilec). The enactment of the Public Emergency Law deeply changed the economic and
financial balance of utility companies. The tremendous effect of the
devaluation, within a context where revenues remained unchanged as a
consequence of the pesification of rates and where financial debts were
primarily denominated in foreign currency, affected the utilities financial
position, results of operations and the cash generation ability required to
comply with financial obligations. The Argentine Electricity Market In Argentina, in the early 1990s, within the state-reform general
framework, the Argentine government carried out a deep restructuring of the
electricity sector transforming it into a more decentralized model with greater
private sector participation. Up to then, the electricity system was
characterized by the inability to meet the requirements of short- and long-term
demand and a low service quality standard, all within a framework of a limited
financing capacity on the part of the state to make necessary investments. Electricity demand in Argentina has strongly increased over the last few
years. Over the last 11 years, electricity demand increased at an average rate
of 5%, exceeding the GDP growth for the same period. In 2003, electricity
demand grew approximately 7.8% to 77,738 GWH from 72,107 GWH in 2002. This
improvement is mainly due to the recovery following the economic crisis in
2002. As of December 2003, installed generation capacity reached 22,500 MW,
which accounted for a growth of approximately 70% from the time of the
privatization of electricity services. Within this context, it is worth noting
the growth in the installed capacity of non-nuclear thermal power plants and
hydroelectric plants. As of December 31, 2003, thermal and hydroelectric power
accounted for 46.7% and 44.7%, respectively, of total supply. In the case of
non-nuclear thermal units, the new plants have substantially increased their
operating efficiency by incorporating cutting-edge technology, such as combined
cycles, which allowed the reduction of the average unavailability of thermal
units from 50% to approximately 20%. Serving as an integrating link, the
systems transportation capacity increased by 20% between 1994 and 2003. These
improvements in the installed capacity enabled plants to meet the growth in
demand in Argentina and also allowed for the start of exports to neighboring
countries. Electricity Generation Genelba Power Plant and Pichi Picún Leufú Hydroelectric Complex Our Genelba Power Plant is a 660MW combined cycle gas-fired generating
unit located at the central node in the Argentine electricity network, at
Marcos Paz, about 50 km from the city of Buenos Aires. As part of our strategy
to increase vertical integration, the Genelba Power Plant allows us to use
approximately 2.8 million cubic meters per day of our own gas reserves. 52




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The Genelba Power Plant, which commenced
commercial operations in February 1999, has two gas-fired turbines that receive
gas through an 8 km duct connected to the transportation system operated by
TGS. The electricity produced at the Genelba Power Plant is distributed via
the national grid through a connection to the Ezeiza transformer station (owned
by Transener) and is located only 1 km away from the Genelba Power Plant. The allocation of electricity dispatch to the Wholesale Electricity
Market, or WEM, whether the electricity is produced for firm contracts or for
the spot market, is subject to market rules based on the lowest variable cost
of electricity generation. See Regulation of Our BusinessesThe Argentine
Electricity Industry and Regulatory Framework. Since the Genelba Power Plant
uses combined cycle technology for a natural gas-fired power plant, our
short-run variable cost is expected to be lower than the cost of other
thermoelectric power plants, granting significant competitive advantages for
the Genelba Power Plant. Therefore, CAMMESA is expected to dispatch the
Genelba Power Plants generating capacity before that of most other
thermoelectric plants, and the Genelba Power Plant is estimated to operate at
an approximately 76% capacity on a month-to-month basis. The development and implementation of the Primary Frequency Response, or
PFR, operation mode along with the full combined cycle represents a milestone
in the Genelba Power Plant operation. The associated system was designed by
the plant engineers and the Genelba Power Plant was the first of its type
worldwide to provide this service to the interconnected system. In 2003, the
U.S. Patent Office granted us patent rights on this system, and currently steps
are being taken to obtain patents in Europe and Argentina. We were awarded a 30-year concession beginning in August 1999 for
hydroelectric power generation at Pichi Picún Leutú hydroelectric complex, or
at HPPL. Our total investment in the construction of the complex was P$291
million. The complex has three generating units with an installed capacity of
285MW. Units 1 and 2 began commercial operations during the third quarter of
1999, and Unit 3 started commercial operations in December 1999. Pursuant to our concession contract and under Section 43 of Law 15,336, as
amended by Law 23,164, since August 2003 we have paid 1% in hydroelectric
royalties, which will be increased by 1% annually until reaching a 12% maximum
tax rate, on the amount resulting from applying to the energy sold the tariff
corresponding to block sales. In addition, we pay the Argentine government a
monthly fee for the use of the water source amounting to 0.5% of the amount
used in the calculation of the hydroelectric royalties mentioned above. In order to secure completion of the works within the term of the
concession and to ensure certain minimum profitability levels needed to make
the investment viable, the Secretary of Energy granted us P$25 million from the
Unified Fund, section 37, Law 24,065. For the purposes of determining whether
this amount should be reimbursed or not, a system fixing a support price for
the electric power generated by the hydroelectric complex and sold at the WEM
was implemented. This support price system will be implemented during a
ten-year period divided into two five-year consecutive periods as of December
1999. For implementation purposes, an Annual Monomic Support Price, or AMSP,
of P$0.021 per Kwh and P$0.023 per Kwh was fixed for the first and second
periods, respectively. In order to determine the amount to be reimbursed,
annually and during the term mentioned above, the difference between the annual
average monomic price for generation at the complex node and the
above-mentioned AMSP, valued by the energy generated by the complex during such
year, will be considered. Taking into account the hydroelectric complexs
energy sales prices and price estimates for the remaining period of the first
five-year term, and considering that the price support system described above
guarantees the viability of our project by providing us with a minimum return
on investment, as of December 31, 2003, we recognized P$15 million in income
from the fund. The Genelba Power Plant and HPPL, together, account for approximately 6.7%
of the power used by, and approximately 6.6% of the power generated for, the
Argentine electricity system. The joint operation of the generating units
minimizes income volatility, capitalizing on the natural barriers existing
among the different energy resources used for power generation. The following chart details energy generation and sales figures for the
Genelba Power Plant and HPPL for the fiscal years ended December 31, 2003, 2002
and 2001. 53




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For the year endedDecember 31,2003
    
    2002
    
    2001Generation(Gwh)
    
    
    5,400
    
    
    
    5,278
    
    
    
    4,732Sales(Gwh):Contracted sales
    
    
    1,588
    
    
    
    1,569
    
    
    
    1,140Spot market
    
    
    4,450
    
    
    
    4,402
    
    
    
    4,152Total sales
    
    
    6,038
    
    
    
    5,971
    
    
    
    5,292Sales(in millions of pesos)
    
    
    235
    
    
    
    196
    
    
    
    266
 Piedra del Aguila We, through our 9.19% interest in Hidroneuquén S.A., have an indirect 5.4%
interest in Hidroeléctrica Piedra del Aguila S.A., or HPDA. Piedra del Aguila hydroelectric complex has 1,400 MW of installed capacity
and four vertical axis turbosets. During 2003, HPDA sold 5,333 GWh in the WEM,
5,170 GWh of which were supplied by its own generation (close to its historical
average) and 163 GWh were purchased in the spot market. On June 30, 2002, Piedra del Aguila announced the suspension of principal
and interest payments on its financial debt; since then, HPDA has been involved
in a restructuring process. Electricity Transmission: Transener, Yacylec and Enecor Transener We currently own an indirect participation of 32.5% in Transener. We have
committed ourselves to divesting our aggregate equity interest in Transener
(under Law No. 24,065 which provides for the Electricity Regulatory framework)
based on the Argentine Antitrust Commissions resolution under which the
transaction involving the purchase of Petrobras Energía Participaciones
majority stock by Petrobras Participacoes S.L. was approved. Such transaction
will be subject to supervision by the Argentine regulatory entity for
electricity, Ente Nacional Regulador de la Electricidad, or ENRE, and must be
approved by the Argentine Secretary of Energy. No time limits have been set to
effect this divestment. Transener is controlled by Citelec, who owns 65% of the capital of
Transener. Citelec, in turn, is owned 49.993% by us,
42.493% by National Grid Finance B.V. and 7.514% by Dolphin Fund
Management, or Dolphin. In March 2004, subject to the approval
from the Argentine Antitrust Commission, Dolphin acquired a 42.493% interest in
Citelec from National Grid Finance B.V. If this transaction is
approved, we have already notified both Dolphin and National Grid
Finance B.V. of our intention to exercise our preemptive right to
acquire 0.007% of Citelecs share capital from National Grid
Finance B.V., increasing
our shareholding in  Citelec to 50.00%. Transener is the leading power transmission company in Argentina. Under a 95-year concession, which is due to expire in 2088, Transener
operates approximately 7,500 km of extra high and high voltage power lines
(most of them 500 Kv lines) and 32 transformer stations. This network is the
core of the power transmission system in Argentina. Transener was awarded an exclusive license for the rest of the term of the
original concession to construct, maintain and operate the fourth line of the
Comahue-Buenos Aires electricity transmission system, which began operations
late in 1999, and consists of 1,292 km of 500 Kv electricity lines. Transener operates approximately 90% of the Argentine extra high voltage
power transmission system. 54




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In July 1997, Transener was awarded the exclusive 95-year concession to
operate Empresa de Transporte de Energía Eléctrica por Distribución Troncal de
la Provincia de Buenos Aires S.A., or Transba S.A., or Transba, which expires
in 2091. Transba operates approximately 5,991 km of electricity transmission
lines (most of them 132 KV lines) and 82 transformer stations. Transener and Transba jointly operate approximately 75% of the Argentine
high-voltage power transmission system. We have agreed with the National Grid to jointly manage Transener and
Transba and to share equally in the management fees received under a management
agreement with Transener. In addition, shareholders have a right of first
refusal in any transfer of Transeners shares. Under the concession agreement
with the government, certain shares of Transener are pledged in favor of the
grantor as guarantee for the execution of obligations under such agreement. Transener generates additional income related to its power transmission
services, from the supervision of the construction and operation of certain
assets connected with the networks and other external services provided to
third parties. In this respect, efforts are being made by Transener to expand
its activities abroad, supported by its quality engineering and experienced
technical personnel. In order to meet the commitments arising from two contracts with foreign
joint ventures in Brazil, the company Transener Internacional Limitada, with
offices in Brasilia, was organized. During 2003, Transener Internacional
Limitada consolidated its operation and maintenance activities in Brazil,
reaching a high operating efficiency level. During 2003, in line with Transeners strategy to expand its operations at
a regional level, the development of the brand insertion policy continued in
Latin America, allowing for the dissemination of Transeners capabilities. The following chart details the evolution of Transeners failure rate for
the fiscal years ended December 31, 2003, 2002 and 2001. The failure rate
represents the service quality provided by the company to users. The maximum
admissible failure rate under the concession contract is 2.50 failures per year
per every 100 km. For the year ended December 31,2003
    
    2002
    
    2001Transener failure rate
    
    
    0.51
    
    
    
    0.57
    
    
    
    0.60
 Maintenance of this low failure rate resulted from operating improvements,
acquisition of special equipment and agreements with public safety agencies. The provisions of the Public Emergency Law have severely affected the
economic and financial balance of Transeners business. Within this framework,
Transener publicly announced the suspension of principal and interest payments
on all its financial debts. Transener retained an international financial
advisor to assist it in developing a restructuring plan for all its banking and
financial liabilities. Transener has been notified of a request by one of its
creditors for the commencement of involuntary bankruptcy proceedings against it
and of requests for attachment of approximately U.S.$11.5 million in accounts
receivable from CAMMESA. Transener is pursuing all reasonable defenses to
protect its rights. Yacylec Yacylec S.A., which we refer to as Yacylec, is an independent transmission
company formed by a consortium of construction and engineering companies of
Argentina and Europe, including Empresa Nacional de Electricidad S.A. of Spain,
or Endesa, Impregilo International Infraestructures N.V. of The Netherlands and
Dumez S.A. of France, which currently hold 22.2%, 18.67% and 1.78% of Yacylec,
respectively. We have a 22.22% direct interest in this consortium. The
consortium operates and maintains the 500 Kv and 280 km-long electric power
transmission line from Yacyretá hydroelectric complex to the Argentine national
grid under a 95-year concession that expires in 2091. Under the concession
agreement, ENREs approval is necessary to transfer or sell shares 55




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representing up to 49% of the capital stock. If that percentage is
higher, a public tender must be called in order to award such shares to the
best bidder. Under the shareholders agreement, shareholders have a right of first
refusal in any transfer of shares. Enecor Enecor is an electricity transmission company. We own a 69.99% interest
and Impregilo International Infrastructures N.V. of The Netherlands owns the
remaining interest in the company. Enecor has a 95-year concession, expiring
in 2088, to construct, operate and maintain approximately 22 km of electricity
lines and a 500 Kv/132 Kv transformer station in the Province of Corrientes.
Under the concession contract, certain shares of Enecor are pledged in favor of
the Province of Corrientes. As collateral for the amounts owed by the
Dirección Provincial de Energía de Corrientes, or DPEC, to Enecor, the province
of Corrientes has assigned to Enecor (i) all royalty credits it has against the
Comisión Técnica Mixta de Salto Grande for the sales of electricity generated
by the Salto Grande Hydroelectric Power Complex, and (ii) the funds that belong
to the Province under the Fondo de Desarrollo Eléctrico del Interior, or FEDEI. Enecor is collecting such guarantees because the DPEC has failed to pay
tariffs to Enecor since September 1999. However, as a result of lower
hydropower generation and the issuance of Resolution SE 406/03, which affected
all generators by establishing a priority for canceling existing debts subject
to the Stabilization Fund having sufficient monies (coming from either the
adjustment of the seasonal price or the Federal Government), Enecors revenues
have been seriously affected. Enecor is taking appropriate administrative and
legal actions with respect to these matters, but we cannot assure that these
actions will result in a favorable outcome to Enecor. Electricity Distribution: Edesur In 1992, Edesur, was awarded an exclusive license by the Argentine
government to distribute electricity in the southern area of the Federal
Capital and 12 districts of the Province of Buenos Aires, serving a residential
population of approximately six million inhabitants and a client portfolio of
approximately 2.1 million. The license will expire in 2087 and is extendable
for an additional 10-year period. Edesur was created as part of the
privatization of the Buenos Aires electricity distribution network. We own
48.5% of Distrilec which, in turn, owns 56.35% of Edesur. We and the Enersis/Chilectra group, owned by Endesa, are the only
shareholders in Distrilec and, under a shareholders agreement, each have the
right to elect an equal number of directors. The Enersis/Chilectra group had
challenged the validity of the shareholders agreement in an arbitration
proceeding, and in September 2002, the International Chamber of Commerce issued
a final award which was fully in our favor and determined that each group has
the right to appoint five directors of Distrilec. The unanimous approval of the board of directors is necessary for any lien
on Edesurs shares or any merger, reorganization, dissolution or spin-off of
Distrilec. Shareholders also have a right of first refusal on any transfer of
shares and preferential rights on any new issue of shares. Chilectra entered into a 15-year management agreement with Edesur that
expires in 2007. Under the agreement, Chilectra receives management fees of
U.S.$1 million plus 10% of exploitation income per year. We are reimbursed for
costs incurred by it in connection with the management agreement. Under the concession contract, Edesur has a fixed cap on what it may
charge each customer for the distribution of electricity to that customer.
However, Edesur may pass through to the customer the cost of the electricity
purchased, limited only by the pre-adjusted seasonal WEM price. Customers are
divided into tariff categories based on the type of consumption required.
Under the current regulations, large users may purchase energy and power
directly from the WEM. Edesur charges these large users a wheeling fee for the
provision of distribution services. Residential consumers purchase power only
from distributors. These customers are generally daylight and weather
sensitive and their consumption of electricity is different in summer and
winter. Peak demand occurs in July, when there is the least amount of
sunlight, and in January, which is usually the hottest summer month. 56




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The enactment of the Public Emergency Law significantly affected Edesurs
economic and financial balance and its ability to comply with its contractual
commitments. For this reason, Edesurs efforts were focused on refinancing
financial liabilities, reducing risks and optimizing working capital. Based on
these guidelines, Edesur has managed to refinance all of its financial debt,
achieving a better maturity profile and lower average costs. The chart below sets forth Edesurs annual power sales for each type of
customer for the fiscal years ended December 31, 2003, 2002 and 2001. Annual sales in GwhType of customer
    
    2003
    
    2002
    
    2001Residential
    
    
    4,304
    
    
    
    4,597
    
    
    
    4,632General
    
    
    2,785
    
    
    
    2,439
    
    
    
    2,844Large users
    
    
    5,569
    
    
    
    5,123
    
    
    
    5,433Total
    
    
    12,658
    
    
    
    12,159
    
    
    
    12,909
 During the period since privatization, Edesur has made investments of over
U.S.$1.2 billion and increased the equipments average useful life from 17 to
24 years by incorporating new facilities and revamping the existing ones. As a
result of such investments, Edesur was able to provide over a 35% rise in
demand and maximum output compared to the first years of the concession of
operation. In addition, investments enabled Edesur to reduce total energy loss
through the system. This loss had accounted for 26% of total electricity
received in 1992 but currently accounts only for 11.8%. Quality of service
supplied to customers improved and the number and duration of interruptions
declined by more than 70%. Edesur has added more than 200,000 new customers to
its system since 1992, with a 12% increase in the number of customers last year
alone. Some of these customers were added as a result of new electricity
lines, and others who had been receiving electricity outside the system are now
fully connected and accurately billed. Edesur has also substantially reduced
overdue payments from customers and is implementing more efficient billing and
collection practices. Based on a functional organization and a prevention approach in the
development of its activities, Edesur made significant efforts to consolidate
the electricity system structure and incorporate new technologies with a view
to meeting the new challenges of an increasingly demanding and competitive
market. In order to meet its clients new requirements, Edesur took actions
geared towards the development of new products and services, while it
redesigned existing ones. Competition We compete with other generators in the WEM, both in the spot market and
for contracts (mainly short-term contracts). The price received by us for
energy generation is determined by the WEM dispatch marginal cost rules and by
rules and regulations enacted following the Argentine crisis and the adoption
of the Public Energy Law. See Regulation of our BusinessesThe Argentine
Electricity Industry and Regulatory Framework. Divestments of non-core assets The sale of a controlling interest in the company that directly controlled
us to Petrobras represents a major milestone in the development of our strategy
to focus and concentrate on our core businesses. The agreements executed in connection with the transfer of our control
granted Petrobras an option whereby, if within 30 days after closing of the
stock purchase transaction, we did not consummate the sale of assets related to
the farming, forestry and mining businesses, Petrobras would be entitled, but
not obligated, to cause the seller to acquire such assets in the amount of
U.S.$190 million. In line with the provisions of the agreements mentioned above, during 2002
we sold the asset portfolio associated with our mining, farming and forestry
businesses. As a part of these divestments, we are involved in the following
transactions: 57




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
    
    In July 2002, we sold to Anglogold our 46.25% indirect equity
interest in Cerro Vanguardia S.A., and certain related assets. The
transaction price amounted to U.S.$90 million, and the transaction
resulted in a P$123 million gain for us.
    
    In September 2002, we sold to Argentina Farmland Investors
LLC our 100% equity interest in Pecom Agropecuaria S.A. The
transaction price amounted to U.S.$53 million, resulting in a P$27
million gain for us.
    
    In December 2002, we sold our forestry business assets,
including a total area of about 169,000 hectares of forestry land
located in the Province of Misiones, Corrientes and Buenos Aires and
a sawmill with a 90,000 m3/year capacity. The sales price was
U.S.$53.16 million, resulting in a P$153 million loss for us.  In addition, the following transactions were performed:
    
    In April 2002, under an asset swap, we transferred to IRHE
(Argentine Branch) and GENTISUR S.A. (a company wholly owned by
IRHE) our 50% interest in Pecom Agra with a value of U.S.$30
million, resulting in a P$81 million gain. These parties, in turn,
transferred to us a 0.75% interest in Puesto Hernández UTE, with a
value of U.S.$4.5 million, a 7.5% interest in Citelec, with a value
of U.S.$15 million and a 9.19% interest in Hidroneuquén S.A, with a
value of U.S.$5.5 million.
    
    In October 2002, we sold to Sudacia S.A., a company
controlled by the Perez Companc family, our 66.67% equity interest
in Conuar, including a 68% interest in Fabricación de Aleaciones
Especiales S.A., for U.S.$8 million. No gain or loss was recorded
in connection with the sale.
    
    In April 2000, we sold our interest in Servicios Especiales
San Antonio S.A., a company engaged in the business of providing
production well services to the oil industry in Argentina, Bolivia,
Peru and Venezuela, for P$133 million, resulting in a gain of P$103
million. All these transactions helped to (i) enhance our asset portfolio, (ii) move
forward with the strategy focused on energy operations to become an integrated
energy company, and (iii) consolidate a high potential and profitable business
portfolio. Insurance We carry insurance covering all operating risk damages, with assets
valued at current market replacement cost. The coverage limit for each and
every loss in our oil and gas exploration and production businesses is the
total value at risk for each location: U.S.$370 million for each and every
loss in our styrenics petrochemical businesses; U.S.$150 million for each and
every loss in our fertilizers business; U.S.$80 million for each and every loss
in our refining business; U.S.$180 million with respect to our thermoelectric
generation businesses; and U.S.$217 million for each and every loss in the
hydroelectric generation power plant. In addition, we carry insurance of up to
U.S.$100 million for ocean marine and non-ocean marine third-party liability,
U.S.$7.5 million for well control costs in Argentine fields, U.S.$40 million
for wells in Bolivia, U.S.$40 million for wells in Ecuador, U.S.$25 million for
fields in Venezuela and U.S.$10.5 million for cargo transportation by sea or
river. In addition, we carry insurance for workmens compensation and
automobile liabilities. Our coverage include the following different types of deductibles: (1)
U.S.$10,000,000 for combined claims for property damage and business
interruption for all our businesses, except for the oil and gas exploration and
production businesses, (2) U.S.$ 10,000,000 for claims for each property of our
oil and gas exploration and production businesses, (3) U.S.$5,000,000 for in
well control costs, and (4) U.S.$5,000,000 in non-ocean marine third-party
liability, and (5) U.S.$5,000,000 in ocean-marine third-party liability. Our
insurance decisions are based on our requirements and available commercial and
market opportunities. Pursuant to the resolutions adopted by the ordinary shareholders meeting
held on April 4, 2003, the Board of Directors was authorized to determine the
most economically appropriate coverage, including a program of self-insurance
covering directors and senior officers liabilities. 58




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Patents and Trademarks Minor portions of our commercial activities are conducted under licenses
granted by third parties, including Petrobras. Royalties related to sales
associated with such commercial activities are paid under the relevant
licenses. We use the name Petrobras with the permission of Petrobras. Environmental Environment, Quality, Occupational Health and Safety (EQOHS) In 1993, we started to implement our environmental strategy. Since then,
environmental protection, employee health and safety and the continuous
improvement of our management quality have been an integral part of our
business. Policies and Directives We have issued policies, goals and plans emphasizing environmental care
and control. Through these policies and standardized management systems
designed to implement these policies, we have undertaken the commitment to
ensure the quality of our products and services, to preserve the overall
environment in which we operate, and the safety and health of our personnel,
contractors and neighboring communities. The consolidation of our management system for quality, safety,
environment and occupational health has been reinforced by the implementation
of the same directives used by Petrobras in Brazil, which we now apply to each
of our business units in order to create and improve our systems. Each
business unit is focused on complying with these goals and closely monitors its
progress, thereby continuously seeking improvement. We call this process
Programa de Seguridad de los Procesos, or PSP. Performance Assessment The possible environmental, safety and occupational health impacts that
are directly or indirectly related to our operations are measured through risk
analysis to ensure their treatment and solution. In that respect, each
business unit has set up adequate procedures which are regularly reviewed and
which are based on standards and directives that we have established. The performance of our environmental management system is evaluated every
month. We verify compliance by our different business units with goals with
respect to reduced atmospheric gas emissions, reduced discharges of liquid
effluents and the treatment or reduction of waste. We also monitor safety
indicators such as the frequency of lost time due to injury, lost work days,
and the total recordable incident rate. We will take and have taken corrective
and preventive measures in order to improve our results with respect to each of
these indicators and the overall safety of our personnel. We have more than 90 certifications in environment (ISO 14001), quality,
(ISO 9001) and safety and occupational health (OHSAS 18001/IRAM 3800), which
are maintained through regular third-party audits. Many of our achievements in this continuous process to achieve excellence
have been enhanced through our integration with Petrobras. Since July 2003, we
have put into operation the project Inventory System of Atmospheric Emissions
initiated in September 2002 by Petrobras. The main goal of this project is the
creation of a tool to be applied to the management of atmospheric emissions.
The work consists of the creation of a collection, utilization and
communication data system that permits the systematic environmental evaluation
of our emissions, the identification of critical issues and the technological
analysis of improvements that can be put into place to reduce these emissions. Environmental Audit Following the change of our controlling shareholder and pursuant to our
goal of continuously improving our environmental, health and safety management,
in 2003 we hired an international consulting firm to conduct an environmental
and safety audit of all our operations. 59




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The final audit report issued by this consulting firm confirmed the high
environmental standards of our operations and identified a series of actions
necessary for our operations to be in full compliance with current laws and
regulations, to satisfy future requirements and, in the absence of local laws,
to comply with applicable international standards. We have decided to implement
these actions. Consequently, over the next several years we plan on making
investments to improve, among other things, our prevention systems and
production facilities at a cost of approximately U.S.$23 million, and we plan
to also implement several corrective and remediation actions several
of which are already underway. 60




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REGULATION OF OUR BUSINESSES The Argentine Petroleum Industry and Regulatory Framework Overview The Argentine oil and gas industry operates under Law No. 17,319 which we
refer to as the Hydrocarbons Law, enacted in 1967, and the Natural Gas Law No.
24,076, enacted in 1992. The Hydrocarbons Law allows the federal executive
branch of the Argentine government to establish a national policy for the
development of Argentinas hydrocarbon reserves, with the principal purpose of
satisfying domestic demand. A new regulatory framework was required in order to respond to several
changes in the Argentine oil and gas industry after the privatization of
Yacimientos Petrolíferos Fiscales Sociedad del Estado, or YPF, and Gas del
Estado, or GdE. Pursuant to Law No. 24,145, the Argentine government
transferred to the provinces ownership of oil and gas reserves located within
their territories. The transfers will be implemented once (i) the Hydrocarbons
Law is modified for the purpose stated in Law No. 24,145, which is referred to
as the Privatization Law, and (ii) the rights of holders of existing
exploration permits and production concessions, as applicable, have expired.
In connection with this legislation, certain issues remain unresolved with
respect to the relevant regulatory authority of the federal executive branch
and the provinces, regarding oil and gas exploration, production, and
transportation activities. Exploration and Production The Hydrocarbons Law sets forth the basic legal framework for the current
regulation of oil and gas exploration and production in Argentina. The
Hydrocarbons Law permits surface reconnaissance of territory not covered by
exploration permits or production concessions upon authorization of the
Secretary of Energy and with permission of the property owner. Information
gained as a result of surface reconnaissance must be provided to the Secretary
of Energy, who is prohibited from disclosing such information for a period of
two years, without the permission of the party that conducted the
reconnaissance, except in connection with the grant of exploration permits or
production concessions. The Hydrocarbons Law provides for the grant of exploration permits by the
federal executive branch following submissions of competitive bids. Permits
granted to third parties in connection with the deregulation and
demonopolization process were granted in accordance with procedures specified
in certain decrees, known as the Oil Deregulation Decrees, issued by the
federal executive branch. In 1991, the federal executive branch established a
program under the Hydrocarbons Law, known as the Argentina Exploration Plan,
pursuant to which exploration permits may be auctioned. The holder of an
exploration permit has the exclusive right to perform the operations necessary
or appropriate for the exploration of oil and gas within the area specified by
the permit. Each exploration permit may cover only unexplored areas up to
10,000 km2 (15,000 km2 offshore), and may have a term of up to 14 years (17
years for offshore exploration). In the event that the holder of an exploration permit discovers
commercially exploitable quantities of oil or gas, the holder may apply for,
and is entitled to receive, an exclusive concession for the production and
development of such oil and gas. A production concession vests in the holder
the exclusive right to produce oil and gas from the area covered by the
concession for a term of 25 years (plus, in certain cases, a part of the
unexpired portion of the underlying exploration permit), which may be extended
for an additional ten-year term by application to the federal executive branch.
A production concession also entitles the holder to obtain a transportation
concession for the transport of the oil and gas produced. Holders of exploration permits and production concessions are required to
carry out all necessary works to find or extract hydrocarbons, using
appropriate techniques, and to make the investments specified in such holders
permits or concessions. In addition, these holders are required to avoid
damage to oil fields and waste of hydrocarbons, to adopt adequate measures to
avoid accidents and damage to agricultural activities, the fishing industry,
communications networks and the water table, and to comply with all applicable
federal, provincial and municipal laws and regulations. 61




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Holders of production concessions are also required to pay a 12% royalty
to the government of the province in which production occurs, calculated on the
wellhead price (equal to the FOB price less transportation costs and certain
other reductions) of crude oil and natural gas produced. The Hydrocarbons Law
authorizes the government to reduce royalties up to 5% based on the
productivity and location of a well and other special conditions. Any oil and
gas produced by the holder of an exploration permit prior to the grant of a
production concession is subject to the payment of a 15% royalty. Exploration permits and production or transportation concessions are
subject to termination in the event of certain breaches or defaults of laws or
regulations or upon the bankruptcy of the concessionaire. Upon the expiration
or termination of a production concession, all oil and gas wells, operating and
maintenance equipment and facilities ancillary thereto automatically revert to
the Argentine government, without payment to the concessionaire. Net Worth Requirements Resolution No. 193/03 of the Secretary of Energy implements mandatory
minimum net worth requirements for companies that wish to acquire or maintain
exploration permits, exploration concessions, and hydrocarbon transportation
concessions in Argentina. The Secretary of Energy has historically required companies that wish to
obtain these permits or concessions to comply with certain minimum net worth
and economic and financial solvency requirements. Along these lines, the
Hydrocarbons Law and subsequent regulations provide for certain economic and
financial solvency requirements for carrying out these activities. However,
prior to the issuance of Resolution No. 193/03, there were no resolutions that
established specific required amounts, but rather, the Secretary of Energy
determined the amount that would be required to comply with the solvency
requirement on a case by case basis. Resolution No. 193/03 sets forth minimum
net worth requirements, as well as, alternative economic and financial
guarantees that can be complied with to obtain permits or concessions. This resolution also provides that, in order to be a holder of a permit or
concession, the company or group of companies (for example, companies
associated through a joint operating or joint venture agreement) shall have a
minimum net worth of P$2,000,000 for land-based areas and U.S.$20,000,000 for
off-shore areas. This minimum net worth amount must be maintained during the
whole term of the permit or concession. The breach of this obligation may
result in sanctions, including fines, or even the revocation of a companys
registry with the Secretary of Energy as a petroleum company. To comply with
these requirements other local Argentine companies or foreign companies may
grant financial support or guarantees of up to 70% of the minimum net worth
requirements in favor of the entity requesting a permit or concession. Security Zones Legislation Pursuant to provisions of Argentine law that restrict the ability of
non-Argentine companies to own real estate, oil concessions or mineral rights
located within, or with respect to, areas defined as security zones
(principally areas located on the border of Argentinas national geographic
limits), prior approval by the Argentine government for any additional
acquisition of real estate, mineral rights, oil or other Argentine government
concessions located within, or with respect to, the security zones may be
required if (i) non-Argentine shareholders acquire control of us or (ii) the
majority of our shares become owned by non-Argentine shareholders. Transportation The Hydrocarbons Law grants hydrocarbon producers the right to obtain from
the federal executive branch a 35-year transportation concession for the
transportation of oil, gas and their by-products through public tenders.
Producers granted a transportation concession remain subject to the provisions
of the Natural Gas Law, and in order to transport their hydrocarbons do not
need to participate in public tenders. The term of a transportation concession
may be extended for an additional ten years upon application to the federal
executive branch. Transporters of hydrocarbons must comply with the provisions established
by Decree No. 44/91, which implements and regulates the Hydrocarbons Law as it
relates to the transportation of hydrocarbons through oil pipelines, gas
pipelines, multiple purpose pipelines and/or any other services provided by
means of permanent and 62




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fixed installations for transportation, loading, dispatching, tapping,
compression, conditioning infrastructure, and hydrocarbon processing. This
decree is applicable currently and primarily to oil pipelines and not to gas
pipelines. (Gas pipelines are subject to ENARGAS regulations.) The transportation concessionaire has the right to transport oil, gas, and
petroleum products and to construct and operate oil pipelines and gas
pipelines, storage facilities, pumping stations, compressor plants, roads,
railways, and other facilities and equipment necessary for the efficient
operation of an oil, gas and petroleum product pipeline system. While the
transportation concessionaire is obligated to transport hydrocarbons on a
non-discriminatory basis on behalf of third parties for a fee, this obligation
applies only if such producer has surplus capacity available, and after such
producers own transportation requirements are satisfied. Depending on whether it is gas or crude oil that is transported,
transportation tariffs are subject, respectively, to approval by ENARGAS or the
Secretary of Energy. Resolution No. 5/04 of the Secretary of Energy sets
forth:  (i)
    
    maximum amounts for tariffs on hydrocarbon transportation
through oil pipelines, and multiple purpose pipelines, as well as
the tariffs on storage, use of buoys, and the handling of liquid
hydrocarbons; and(ii)
    
    maximum deduction amounts that may be applied in connection
with crude oil transportation by producers that, as of the date of
the regulation, transport their production through their own
unregulated pipelines, for the purpose of assessing royalties. Upon expiration of a transportation concession, ownership of the pipelines
and related facilities is granted to the Argentine government at no cost. Refining Hydrocarbon refining activities by oil producers and other third parties
are subject to Law 13,660 and Oil Deregulation Decrees, which provide the basic
regulatory framework for these activities in Argentina. The Secretary of
Energy is the authority that enforces Law 13,660 and its regulations. Hydrocarbon refining activities are subject to registration requirements
established by the Secretary of Energy, such as the requirement to register
with the registry of oil companies, which is granted on the basis of general,
financial, and technical standards. Furthermore, liquid fuel retail outlets,
points of sale for fuel fractioning, resale to large users, as well as, supply
contracts entered into between service stations and each oil company are
required to be registered in registers created by the Secretary of Energy. Refiners are authorized to freely market their products in the national
and export markets (subject, in the case of exports of diesel and liquefied
petroleum gas, to prior regulation) and to freely install gas stations
identified with their own or third parties representative flag, provided that
their own gas stations or those directly operated by oil companies do not
exceed 40% of their distribution network (subject, in the case of exports of
diesel and liquefied petroleum gas, to prior registration). This regulatory empowerment of the Secretary of Energy is also delegated
to the provinces and municipal districts, and, therefore, refining activities
must also comply with provincial and municipal safety and technical
regulations. The installation and operation of gas stations must not only
comply with technical, safety, and quality standards set by the Secretary of
Energy, but their authorization also requires compliance with municipal
regulations. Market Regulation Under the Hydrocarbons Law and the Oil Deregulation Decrees, the holders
of exploitation concessions have the right to freely dispose of their
production either through sales in the domestic market or abroad. Pursuant to Decree No. 1589/89, relating to the deregulation of the
upstream oil industry, companies engaged in oil and gas production in Argentina
are free to sell and dispose of the hydrocarbons they produce and are 63




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entitled to keep out of Argentina up to 70% of the foreign currency
proceeds they receive from crude oil and gas sales, while being required to
repatriate the remaining 30% through Argentine exchange markets. During 2002,
as a result of the reestablishment of a system that requires exporters of
domestic products to repatriate foreign currency amounts generated by their
exports, many controversies arose among producers and the authorities regarding
the enforceability of the right to freely dispose of up to 70% of their foreign
currency. These controversies were even subject to legal suit, and many
federal judges have pronounced on and recognized the prima facie validity of
producers rights. In December 2002, we filed before a federal court of the
Province of Santa Cruz, a temporary injunction against the federal executive
branch, requesting the maintenance of the status quo which allows us to freely
dispose of up to 70% of our export proceeds. This right was prima facie
admitted by the court. On December 31, 2002, Decree No. 2703/02, effective as
of January 1, 2003, was enacted. This decree declared the right to dispose of
70% of foreign currency but had no provisions related to this right during
2002. Therefore, in order to avoid any uncertainty regarding the application
of this right during 2002, in February 2003, we filed a civil action of
certainty, requesting that the court recognize our right to freely dispose of
up to 70% of our foreign proceeds in 2002, based on the effectiveness of Decree

No. 1589/89. The Hydrocarbons Law authorizes the federal executive branch to regulate
the Argentine oil and gas markets and prohibits the export of crude oil during
any period in which the federal executive branch finds domestic production to
be insufficient to satisfy domestic demand. In the event the federal executive
branch restricts the export of oil and petroleum products or the free disposal
of natural gas, the Oil Deregulation Decrees provide that producers, refiners
and exporters shall receive a price, in the case of crude oil and petroleum
products, not lower than that of similar imported crude oil and petroleum
products and, in the case of natural gas, not less than 35% of the
international price per cubic meter of Arabian light oil, at 34 degrees. On May 23, 2002, the Argentine government issued decree No. 867/02
declaring an emergency in the supply of hydrocarbons in Argentina through
October 1, 2002. This decree authorized the Secretary of Energy to determine
quotas on the minimum volumes of petroleum and LPG produced in Argentina that
must be sold on the domestic market. By means of Resolution No. 140/02, the
Secretary of Energy established that in June, July, August and September of
2002, only 36% of the oil produced in each preceding month could be exported.
In addition, during this emergency period, no producer or exporter of oil was
permitted to export a volume of oil higher than the volume it exported during
the equivalent months of 2001. The emergency resolution was amended and
finally repealed on July 26, 2002. Argentina is currently suffering an energy crisis, and there is an
agreement in principle, subject to the approval of the federal executive
branch, for gas producers to sell a minimum specified amount in the local
market in exchange for price increases. This proposal may change during the
approval process. See Item 3. Key InformationRisk FactorsFactors Relating
to ArgentinaLimits on exports of hydrocarbons could lower our anticipated
dollar-denominated cash receipts. Taxation Holders of exploration permits and production concessions are subject to
federal, provincial, and municipal taxes and regular customs duties on imports.
The Hydrocarbon Law grants such holders a legal guarantee against new taxes
and certain tax increases at the provincial and municipal levels. Permit
holders and concessionaires must pay an annual surface tax based on the area
held. On January 6, 2002, the Argentine Congress enacted the Public Emergency
Law. Pursuant to the Public Emergency Law, all foreign-denominated bank
deposits were converted into peso-denominated bank deposits at a rate of P$1.4
per U.S. dollar, and all dollar-denominated debts with Argentine financial
institutions were converted into peso-denominated debts at a rate of
one-to-one. Under the Public Emergency Law, the Argentine Congress delegated
the right to issue secured government bonds to the federal executive branch in
order to compensate it for the effect of pesification and to ameliorate the
situation of financial institutions. The Public Emergency Law established a five-year export tax on hydrocarbon
exports as security for these bonds, and empowered the federal executive branch
to establish the applicable tax rate. By virtue of Decree No. 310/02, the
federal executive branch determined that the applicable tax rate would be 20%
on crude oil and 5% on petrochemical and oil by-products. On May 13, 2002, by
Decree No. 809/02, the federal executive branch 64




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temporarily extended the 20% export tax to other hydrocarbon exports, such
as petrochemical and oil by-products, stating that the 20% export tax
applicable to hydrocarbon exports would be reduced to 5% on October 1, 2002. Through Resolution No. 77, the Secretary of Energy regulates the payment
of tolls by persons and companies that are subject to audit and control under
technical and security regulations for the fractionation and sale of liquid gas
and the transportation of liquid hydrocarbons and its derivatives through
pipelines. It provides the methods and terms and conditions for payment of the
tolls. Stability of Diesel Prices  Supply to the Domestic Market Decrees No. 645/02 and 652/02 and Resolution No. 38/02 of the Secretary of
Energy were published in the Official Gazetteon April 22, 2002 and were aimed
at overcoming the diesel fuel supply shortage. Decree No. 645/02 provides that diesel exports must be registered and
empowers the Secretary of Energy to expand the list of hydrocarbons subject to
registration, depending on the condition of the domestic market. The Secretary
of Energy has also been authorized to discontinue the registration system if
the situation in the domestic market so warrants. Resolution No. 202/02 of the Secretary of Energy, dated December 19, 2002,
modified Decree No. 645/02 by canceling the registration system established by
that decree for crude oil export transactions. This resolution also provides
for the automatic registration and approval of diesel oil and liquefied
petroleum gas exports such that simple evidence of a receipt of the form signed
by an attorney of the export company is considered sufficient evidence of the
registration and approval of the transaction. By means of Decree No. 652/02, the federal executive branch ratified the
diesel supply stability agreement for public transportation services, dated
April 19, 2002, among the national government and hydrocarbon producing and
refining companies. Under the agreement:  (i)
    
    refining companies agreed to supply the domestic market with
diesel for the public transportation service at a set maximum price
until July 31, 2002;(ii)
    
    hydrocarbon manufacturers agreed to supply local refineries
with the same amount of crude oil that they had supplied in the
first quarter of 2002, plus an additional amount (with a fixed price
and exchange rate), until July 31, 2002; and, in turn,(iii)
    
    the national government agreed to allow manufacturing
companies to offset against export duties:  
    
    the amount of any costs, penalties and
indemnities incurred due to the total or partial cancellation
of supply to third parties, which were incurred for purposes
of complying with the stability agreement; and
    
    any differences between the fixed price and
exchange rate set by the agreement and market prices and
rates. The parties also agreed that, if the fixed price and exchange rate at
which manufacturers have agreed to sell their products exceeds a certain limit,
either party may request that the agreement be renegotiated. If no agreement
is reached in this respect, then the agreement may be terminated. Decree No. 652/02 has been extended by means of Decree Nos. 1,912/02,
704/03, 447/03 and 301/04 until December 31, 2003. Subsequently, Decree No. 1,912/02 ratified the agreement on extension of
the stability agreement and the first quarterly agreement. Under the extension
to the stability agreement, the national government agreed to issue a
resolution that would provide for the reduction of export duties imposed on
diesel, from a 20% rate to a 5% rate, retroactive as of August 1, 2002. 65




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The first quarterly agreement aimed at limiting diesel volumes that must
be provided to public transportation companies at contractually discounted
prices, by establishing an information and verification system. The refining
companies were entitled to compensation for any differences between the net
income that refining companies obtained from the sale of diesel at the market
price compared to that obtained from sales at agreed upon prices. The amount
of that economic compensation is verified by the Secretary of Energy, who
issues a certificate permitting the refining companies to obtain from producers
a rebate on the unit price of crude oil equal to the value of the compensation.
Producers, in turn, may discount the amount of such rebate from export duties. Since ratification of the first quarterly agreement, a series of extension
agreements has been executed and ratified through Decrees No. 704/03 and No.
447/03. In turn, Decree No. 576/03 empowered the Cabinet of Ministers until
December 31, 2003 to execute new agreements with the companies, as well as to
enter into amendments to these agreements, in order to secure a continued
supply of diesel at a discounted price. Stability of Fuel Prices With
respect to crude oil prices, in January 2003, at the federal
executive branchs request, hydrocarbon producers and refineries
executed a temporary agreement in connection with crude oil, gasoline
and diesel oil price stability in the domestic market. After
successive renewals, the term of this agreement was extended until
May 2004. This agreement provided for crude oil deliveries to be
invoiced and paid based on the West Texas Intermediate Crude
reference price, or WTI, of U.S.$28.5 per barrel instead of the
actual relevant WTI. Any positive or negative difference between the
actual relevant WTI, not exceeding U.S.$36 per barrel, and the
reference price would be paid out of any balance generated in periods where the actual WTI is below
 U.S.$28.5 per barrel. Refineries,
in turn, would reflect the crude oil reference price in domestic
market prices. In February 2004, a new agreement corresponding to the
period beginning on March 1, 2004 and ending on April 30, 2004 was
reached between producers and refineries, but the Secretary of Energy
has not yet approved this agreement because it contains a difference
concerning the interest rate to be used to calculate the debt between
producers and refiners. If the situation continues in the future,
producers shall be forced to reinvoice refiners in order to adjust
prices. Notwithstanding this situation, beginning in May 2004,
hydrocarbon producers and refineries have informally agreed that
while the WTI per barrel ranges between U.S.$32 and U.S.$42, crude
oil deliveries will be invoiced and paid based on a reference price
equal to (i) 86% of the WTI as long as this price does not exceed
U.S.$36 per barrel, or (ii) 80% of the WTI, in cases where this price
exceeds U.S.$36 per barrel. Royalties The national government has provided that the Central Bank will be
responsible for issuing the regulations that may be required to apply the
provisions of Section 5 of Decree No. 1,589/89, which will permit producing
companies to dispose of their proceeds from sales in the domestic market, and
the national government has described the manner in which these regulations
shall apply during the course of the Argentine economic crisis. Under Resolution No. 76/02 of the Ministry of Economy, royalties on oil
exports must be fixed taking into account the seller exchange rate of Banco de
la Nación Argentina on the day before the royalty is paid. However,
from December 2001 until May 2002, producers and refiners agreed to
negotiate a reduced exchange rate in order to moderate the impact of
the devaluation in product prices. Producers calculated and paid
royalties according to this reduced exchange rate. These calculations
have been rejected by Argentine Provinces, which have presented
claims for any shortfall arising from this agreement. The Argentine Gas Industry and Regulatory Framework Background In 1992, the Natural Gas Act and related decrees of the federal executive
branch were passed providing for the privatization of GdE. The Natural Gas Act
and the related decrees provided for, among other things, the transfer of
substantially all the assets of GdE to two transportation companies and eight
distribution companies. The transportation assets were divided into two
systems on a geographical basis, the northern and southern area pipeline
systems, designed to give both systems access to gas sources and to main
centers of demand, including the greater Buenos Aires region. The distribution
assets were also divided on a geographical basis. A majority stake in each of the ten companies was sold to private bidders
through a public tender process. Each consortium of bidders was required to be
qualified on the basis of technical merit, including having a consortium
participant with previous experience as an operator of gas transportation or
distribution facilities. Accordingly, each consortium included one or more
significant international operators. 66




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The Natural Gas Act and related decrees granted each privatized company a
license to operate the transferred assets, established a regulatory framework
for the privatized industry based on open, non-discriminatory access, and
created ENARGAS to regulate the transportation, distribution, marketing and
storage of natural gas. The Natural Gas Act also provided for the regulation
of wellhead gas prices in Argentina for a period of between one and two years
beginning in June 1992 with prices to be deregulated no later than June 1994.
Pursuant to a subsequent decree, gas prices were deregulated as of January 1,
1994. Since the deregulation, prices have risen with variances based on the
basin and the season of the year. As part of the privatizations, the concessionaires assumed a series of
obligations aimed at correcting the previous situation. In particular,
concessionaires agreed to incorporate modern technology and make greater
investments in equipment, thereby improving quality and safety levels to comply
more closely with international standards and ensuring a supply necessary to
meet a growing demand. In addition, operating efficiencies were sought, with a
view to sharing these benefits with the consumers through tariff rebates. In exchange, the companies were entitled to tariff levels that ensured a
reasonable and fair profit, comparable with profits at the domestic and
international levels. In line with that objective, tariffs were to be
denominated in U.S. dollars, in order to permit companies to better match their
income with their expenses and investments, which in large part were tied to
foreign markets, both through the import of specialized equipment and foreign
financing. Regulatory Framework Natural gas transportation and distribution companies operate in an open
access, non-discriminatory environment under which producers, large users and
certain third parties, including distributors, are entitled to equal and open
access to the transportation pipelines and distribution system in accordance
with the Natural Gas Act, applicable regulations and the licenses for
privatized companies. In addition, a regime of concessions under the
Hydrocarbons Law is available to exploitation concessionaires to transport
their own gas production. The Natural Gas Act prohibits gas transportation companies from buying and
selling natural gas. Additionally, gas producers, storage companies,
distributors and consumers who contract directly with producers may not own a
controlling interest (as defined in the Natural Gas Act) in a transportation
company. Furthermore, gas producers, storage companies and transporters may
not own a controlling interest in a distribution company, and no seller of
natural gas may own a controlling interest in a transportation or distribution
company (unless such seller neither receives nor supplies more than 20% of the
gas received or transported, on a monthly basis, by the relevant distribution
or transportation company). Contracts between affiliated companies engaged in different stages in the
natural gas industry must be reported to ENARGAS. ENARGAS may disapprove such
contracts only if it determines that they were not entered into on an
arms-length basis. ENARGAS ENARGAS is an autonomous entity which functions under the Ministry of
Economy and Public Works and Services of Argentina and is responsible for a
wide variety of regulatory matters, including the approval of rates and rate
adjustments and transfers of controlling interests in the distribution and
transportation companies. ENARGAS is governed by a Board of Directors composed
of five full-time directors who are appointed by the federal executive branch
subject to confirmation by the Argentine Congress. ENARGAS has its own budget which must be included in the Argentine
national budget and submitted to Congress for approval. ENARGAS is funded
principally by annual control and inspection fees that are levied on regulated
entities in an amount equal to the approved budget, net of collected penalties,
and allocated proportionately to each regulated entity. Conflicts between two regulated entities or between a regulated entity and
a third-party arising from the distribution, storage, transportation or
marketing of natural gas must first be submitted to ENARGAS for its decision.
ENARGASs decisions may be appealed through an administrative proceeding to the
Ministry of Economy or directly to the federal courts. 67




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Rate Regulation Overview Since the adoption of the Public Emergency Law and the other emergency
measures taken by the Argentine government in early 2002, the regulation of
public utility tariffs including those for gas transportation and distribution
has changed dramatically. The rapid implementation of these rate changes has
resulted in a complex and often conflicting legal framework. Although the rate
regulations described below are still in effect, in practice, they have for the
most part been superseded by new regulations which we summarize later in this
annual report. See Public Emergency Law. We cannot provide assurance on
which regulatory scheme will ultimately be implemented by the Argentine
government once it acts to conform the conflicting regulations. The Natural Gas Act regulates the rates for gas transportation and
distribution services, including those of TGS. Under the TGS license, TGS is
permitted to adjust rates (i) semi-annually to reflect changes in the U.S.
Producer Price Index, and (ii) every five years in accordance with efficiency
and investment factors to be determined by ENARGAS. In addition, subject to
ENARGASs approval, rates may be adjusted from time to time to reflect cost
variations resulting from changes in the tax regulations (other than income
tax) applicable to TGS, and for objective, justifiable and non-recurring
circumstances. The Natural Gas Act provides that the tariffs for natural gas charged to
end users by distribution companies shall consist of the sum of three
components: (i) the price of gas purchased; (ii) the transportation tariff for
transporting gas from the production area through the distribution system; and
(iii) the distribution tariff. The rates of TGS are expressed in U.S. dollars
and are adjusted every five years in accordance with efficiency and investment
factors determined by ENARGAS. The ratemaking methodology contemplated by the
Natural Gas Act and the TGS license is the price-cap with periodic review
methodology, a type of incentive regulation which allows regulated companies to
retain a portion of the economic benefits arising from efficiency gains. Under the terms of the TGS gas transportation license, TGS could increase
rates semi-annually based on the U.S. producer price index. In January 2000,
ENARGAS, TGS and the other gas transportation and distribution companies agreed
to postpone the Producers Price Index, or PPI, adjustment scheduled for January
2000. In August 2000, Decree No. 669/00 was issued which (i) allowed TGS to
bill its customers retroactively for the January 2000 PPI rate adjustment over
a 12-month period, and (ii) postponed any further PPI rate adjustments until
July 2002. Decree No. 669/00 allows TGS to bill its customers retroactively
for these postponed PPI rate adjustments beginning in July 2002. Decree No.
669/00 also allows TGS to add an interest charge to its bills in order to
compensate it for the delay in billing these PPI rate adjustments. In late August 2000, a court proceeding was commenced, which challenged
the legality of Decree No. 669/00, claiming that the PPI rate adjustments
contradict the Convertibility Law. The court suspended the application of
Decree No. 669/00 and, subsequently, ENARGAS notified TGS that it should not
apply any PPI rate adjustments until the court proceeding is resolved. As a
result of the enactment of the Public Emergency Law, ENARGAS notified TGS of
the suspension of the second five-year review of its tariffs. This review had
begun in 2000. Because of certain provisions of the Public Emergency Law and
our contract renegotiation efforts, we do not expect that Decree No. 669/00
will be upheld nor do we expect that TGS will ultimately be able to
retroactively bill its clients for PPI rate adjustments. Notwithstanding the foregoing, through Decree No. 689/02, the federal
executive branch exempted the following from the pesification required by the
Public Emergency Law and Decree No. 214/02: (i) tariffs for the regulated
transportation of natural gas destined for export; (ii) agreements for the
transportation of natural gas destined for export; and (iii) purchase and sale
contracts for natural gas destined for export whose terms had been originally
fixed in a currency other than the Argentine peso (these contracts are to be
invoiced and paid in U.S. dollars at an exchange rate of P$1/U.S.$1). Decrees No. 689/02 and 704/02 excluded from pesification the obligations
to pay in foreign currency incurred by individuals or companies residing or
located outside Argentina, payable with funds coming from abroad, to
individuals or companies residing or located in the country. Under Resolution
No. 2,774/02, which was based on these decrees, ENARGAS reinstated the PPI
index as an adjustment coefficient for transportation tariffs in respect of gas
destined for exportation, and consequently, with respect to natural gas
destined for exportation, approved the 68




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tariff schedules presented by TGS effective as of July 1, 2002, and
permitted the denomination of the charges related to each type of service to be
in U.S. dollars. Public Emergency Law The Public Emergency Law established that in contracts related to public
works and services, clauses setting forth the price of such works and services
in foreign currencies and indexation clauses based on foreign price indices or
any other indexation mechanisms are no longer valid. Prices and tariffs
resulting from those clauses had to be converted into pesos at a conversion
rate of P$1=U.S.$1. Pursuant to this law, the Argentine federal executive
branch is authorized to renegotiate the terms of these contracts. The criteria
for these renegotiations include:  
    
    the impact of tariffs on economic competitiveness and income
distribution;
    
    the quality of the services to be provided and/or the capital
expenditure programs provided for in the contracts;
    
    the interests of customers and accessibility to the services;
    
    the safety of the systems; and
    
    the providers profitability. On February 12, 2002, the federal executive branch issued Decree No.
293/02, putting the Ministry of Economy in charge of the renegotiation of
contracts related to public works and in charge of selecting a Renegotiation
Committee, which committee includes a representative of customers and assists
the Ministry in the renegotiations. Since July 2003, by means of Decree No.
311/03, the renegotiation process has been conducted by the Union of the
Renegotiation and Analysis of Public Service Contracts (Unidad de Renegociación
y Análisis de Contratos de Servicios Públicos), which is comprised of the
relevant secretaries of state with jurisdiction over the specific utility
sector undergoing the renegotiation process. The Ministry of Economy was
required to submit a renegotiation proposal or a rescission recommendation to
the federal executive branch within 120 days of February 15, 2002. This
proposal or recommendation would then be submitted to Argentine Congress for
their review. On March 21, 2002, the Renegotiation Committee delivered to the licensed
companies guidelines on the renegotiation process approved by the Ministry of
Economy. In April 2002, these licensed companies submitted to the
Renegotiation Committee the information required by the guidelines and agreed
to cooperate in finding realistic and possible solutions within a serious
economic and social crisis of the country. Early in August 2002, the Renegotiation Committee asked the licensees to
set forth the tariff increases requested by each, and they, in turn, requested
a public hearing for a discussion on this issue. The process of contract renegotiation unilaterally imposed by the
government did not show any significant progress in the year following its
enactment. In the course of 2002, the public hearings convened for the tariff
review were suspended by the Argentine courts. Within this framework,
Resolution No. 38/02 of the Ministry of Economy ordered the regulatory agencies
to suspend their five-year reviews on gas and electricity tariffs. This
suspension does not cover the seasonal adjustments for producers, which is
defined by the Secretary of Energy. Resolution No. 75/02 has approved the
seasonal adjustment for the electricity market from May to October 31, 2002. The national government tried to grant a tariff increase through Decree
No. 2,437/02, which was also invalidated by the courts. In light thereof, the
federal executive branch issued Decree No. 120/03, which tried to cast the
Public Emergency Law in a manner that would permit an immediate grant of tariff
increases to the licensed companies on account of future renegotiation of the
contracts. In January 2003, the federal executive branch issued Decree No.
146/03, which establishes tariff increases as of January 30, 2003. Thereafter,
a number of organizations representing consumers filed amparo proceedings to
revoke those tariff increases and obtained judgments favorable to their claims. 69




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On December 4, 2003, Law 25,820 was promulgated, which extended up to
December 31, 2004 the public emergency declared by Law 25,561 on social,
economic, administrative, financial and foreign exchange matters, and the
delegation of powers provided to the federal executive branch to renegotiate
the tariffs of the public services and license contracts. This law empowers
the federal executive branch to negotiate tariffs without being constrained by
the applicable regulatory frameworks. Any legally permitted revisions of any
current tariff must be authorized by the applicable regulatory agency to the
extent these revisions fall within the scope of the renegotiation process led
by the executive branch. Also, any agreed transitory changes to the utility
service agreements and/or licenses must be considered in the definitive
agreements. Modifications to the Regulatory Framework  On February 16, 2004, Decree No. 180/04 was published in the Official
Gazette providing for:(i)
    
    the creation of a trust fund (the trust will be funded by
tariffs payable by users of the service, special credit programs and
contributions from direct beneficiaries);(ii)
    
    the creation of an electronic market to coordinate spot
transactions of the sale of natural gas and secondary market
transactions for transportation and distribution of natural gas;(iii)
    
    the expansion of section 34 of Decree No. 1738 that
regulates Gas Law 24,076 to prohibit distributors or their
shareholders from having a controlling participation in more than
one dealing company; and(iv)
    
    an authorization by the Secretary of Energy to take all
necessary measures to maintain an adequate level of services in the
event that it verifies that the system could face a supply crisis. Adjustment of the Price of Natural Gas in Wellhead On February 16, 2004, Decree No. 181/04 was published in the Official
Gazette that instructed the Secretary of Energy to design a framework for the
normalization of prices of natural gas at the wellhead. This framework is to
be applicable to both distributors and major consumers. The decree authorizes
the Secretary of Energy to negotiate with gas producers on a price framework
for the adjustment of prices in sale contracts to distributors. It also
authorizes the Secretary of Energy to determine a category of users who will
not be able to buy gas from distributors but, rather, must buy directly from
producers. A new mechanism for protection of this new category of consumers
must be established to guaranty supply and price, and must be extended to July
31, 2005. The decree further states that prices resulting from sales pursuant to the
agreement with producers shall be the prices used as a reference for
calculating and paying royalties. These prices will also be used by ENARGAS in
calculating any necessary adjustments in tariffs that result from variations in
the price of purchased gas. The decree also states that the framework shall
adjust tariffs corresponding to form R for Residential Services and P for
General Services. In addition, the decree states that all agreements for the
sale of natural gas shall be filed with the gas electronic market, and the
Secretary of Energy has the authority to regulate the sale of gas (i) between
producers, and (ii) between producers and the dealers who they either control
or are affiliated with. On April 2, 2004, the Secretary of Energy entered into an agreement with
natural gas producers, in which the following was agreed to:  
    
    the minimum volumes that natural gas producers must supply to
the local market, including specified amounts for: (i) distributors
who supply industrial users, (ii) clients of distributors (the New
Direct Consumers) who are prohibited from buying directly from
distributors and must buy directly from producers, and (iii) power
stations that generate electricity for the local market;
    
    the authorization of the producers to increase the prices of
natural gas according to a price roadmap which differs for each
basin and that culminates in complete deregulation of the wellhead
price of natural gas by January 1, 2007; 70




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
    
    the obligation of the distribution and generation companies
to renegotiate the price and volumes of their supply contracts with
producers who are also a party to the agreement. If an agreement is
not reached after a 45-day period, producers are released from their
obligation to supply natural gas to these distribution and
generation companies;
    
    the New Direct Customers have regulated prices through June
31, 2005; and
    
    notice of all new supply agreements must be given to the
Secretary of Energy and will be published in the electronic gas
market once this market starts functioning. This agreement has already been approved by Resolution No. 208 of the
Ministry of Federal Planning, Public Investment and Utilities. The public
hearings at ENARGAS took place on May 6, 2004. In addition, on March 24, 2004, under Resolution No. 265 the Secretary of
Energy imposed certain restrictions in order to avoid a crisis in the supply of
gas to the domestic market. Specifically, export authorizations and exports of
natural gas surplus volumes were suspended and the Undersecretary of Fuels was
instructed to create a program for the rationalization of gas exports and the
use of the countrys transportation capacity. Under Resolution No. 27/04, which was issued by the Undersecretary of
Fuels, a Program for the Rationalization of Natural Gas Exports was approved
and is in effect as long as natural gas volumes in the Argentine system fail to
satisfy the domestic demand. In addition, an order of priority for the
selection of companies that will be subject to export suspension restrictions
was established taking into account the following factors: (i) the degree of
compliance with the producers commitment of gas supply to the domestic market
(these commitments were established by each producer at the time the
corresponding gas export authorization was granted), (ii) the history of sales
to the domestic market, and as divided between sales to distributors and sales
to direct consumers, and (iii) the impact that this suspension would have on
the domestic market supply. Except as expressly authorized by the Undersecretary of Fuels, no export
authorizations will be granted if such authorizations would result in export
volumes (not including surplus volumes) higher than those exported in 2003.
For calculation purposes, volumes for each month will be compared with figures
from the corresponding month of the previous year. In addition, excess
volumes, if any, already exported by a producer will be offset until the end of
the third quarter of 2004. Producers that have not maintained the level of sales to the domestic
market committed at the time of requesting their export authorizations will
receive the average basin price for the domestic market as published by
ENARGAS. On the other hand, producers who have complied with their obligations
with respect to the supply of the domestic market will receive a value for
their natural gas equal only to the value actually received under their
respective export agreement. On June 18, 2004 the Secretary of Energy passed Resolution 659/2004 by
which the Complementary Program to Supply the Domestic Market of Natural Gas,
which we refer to as the Complementary Program, was approved. The
Complementary Program replaces the Program of Natural Gas Exportations and
Transportation Capacity Rationing, which had been approved by Disposition
27/2004 issued by the Undersecretary of Fuels. The Complementary Program
commenced on June 24, 2004 and partially eliminates the monthly and quarterly
limits on the export of natural gas which was applicable under Disposition
27/2004. On April 21, 2004, the Argentine government reached a six-month agreement
with the Bolivian government. This agreement allowed Argentina to import up to
4 million cubic meters of natural gas from Bolivia per day. Also in April 2004,
Resolution 185/04 of the Ministry of Federal Planning, Public Investment and
Utilities was issued creating trust funds with the objective of financing
infrastructure works in gas transportation. On May 26, 2004, under Resolution 503/04 the Secretary of Energy approved
a method for priority use of transportation for the supply by distributors of
uninterruptible natural gas. This resolution is effective through August 31,
2004. 71




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Also in May 2004, under Executive Order 645/04, the government imposed a
20% export tax on all natural gas exports. The Argentine Electricity Industry and Regulatory Framework Background Prior to 1991, virtually all of the electricity supply industry in
Argentina was controlled by the public sector. Inefficient management and
inadequate capital expenditures under that regime resulted in the deterioration
of quality in service and physical equipment, poor financial condition and high
rates for poor service. Accordingly, the Argentine government enacted Decree No. 634/02 in March
1991, and the Argentine Congress enacted Law 24,065, known as the Regulatory
Framework Law, in January 1992, establishing guidelines for the restructuring
and privatization of the electricity sector within the framework of Law 23,696.
The new regulatory framework of the sector established, as separate areas, the
generation, transportation and distribution of electricity, and adopted
separate regulatory regimes for each, thereby moving to a decentralized model
with an increased participation in the private sector. The privatization process began in February 1992 with the sale of several
large thermal generation facilities, previously operated by Servicios
Eléctricos del Gran Buenos Aires and has continued with the sale to the private
sector of transmission and distribution facilities, as well as additional
thermoelectric and hydroelectric generation facilities. The companies that
have received concessions have also assumed a series of commitments to improve
the quality and safety of the industry. They also plan to ensure supply by
incorporating modern technologies and by making large investments in equipment
and works. Due to privatization, a higher level of quality has been achieved, with
fewer losses of grid capacity during peak times. Wholesale prices have also
been reduced as a direct result of new generation equipment in place of less
cost-efficient power plants. In order for the flow of revenues to be more closely associated with
expenses and investments, the operations of the sector were denominated in U.S.
dollars. This was because private operators often funded their large works
through foreign lending institutions due to difficulty in obtaining significant
amounts of financing at adequate rates in the domestic market. Regulatory Framework Overview The Secretary of Energy regulates electric power supply and grants and
controls electricity sector concessions at the national level through the
National Directorates for Coordination and Regulation of Prices and Rates and
for Electricity Planning. The Federal Board of Electric Power, made up of
representatives from each province, is an advisory body to the Secretary of
Energy, which coordinates policies for the electricity sector. The Federal
Entity of Electricity Regulation, or ENRE, is an autonomous body which reports
to the Secretary of Energy and has overall supervisory power in the electricity
industry. It is managed by a board of five members selected by the federal
executive branch, two of whom are individuals from a list proposed by the
Federal Board of Electric Power. The members of the board of directors of ENRE
are not allowed to have any economic interest in the areas under their
jurisdiction. ENREs purpose is to pursue the objectives set out in the Regulatory
Framework Law and provide regulations regarding security, the standard quality
of service, and procedures for technical areas such as metering and
interpretation. Accordingly, ENREs specific duties, among others, include:
(i) establishing a tariff collection mechanism; (ii) establishing the criteria
and conditions for awarding concessions; and (iii) safeguarding public safety,
environmental protection and property rights relating to the construction and
operation of generation, transmission, and distribution facilities. ENRE has mandatory jurisdiction over all disputes between generators,
transmitters and distributors in matters relating to the public supply,
distribution and transportation of electricity. If ENRE becomes aware of 72




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practices that are inconsistent with the Regulatory Framework Law and
other regulations, it is empowered to notify the interested parties, hold
hearings and take the appropriate authorized action. In particular, ENRE can
apply penalties for noncompliance with the Regulatory Framework Law and
initiate and pursue legal actions to ensure compliance therewith. Appeals to
ENREs decisions may be filed directly before the Secretary of Energy and the
courts. ENRE is required to prepare an annual budget and to submit it to the
regulated entities for approval. These regulated entities are required to pay
a fee to ENRE on the basis of the approved budget and their respective share in
the total gross profit of all regulated entities. In addition to revenues from
regulated entities from this fee, ENRE is entitled to retain cash from fines
and seizures. Structure Under the current regulatory structure, generation of electricity in
Argentina is organized as a competitive market, the Wholesale Electricity
Market in which independent generators sell the power they produce to other
generators, distribution companies, large scale users and into the spot market.
The generation of electricity is characterized under the law as a public
utility and as such is not highly regulated. In contrast, the transmission and
distribution of electricity are considered public services and as such are
licensed by the national and/or the provincial government. Transporters are
obliged to permit third parties to have access to any available transmission
capacity, but are not themselves authorized to buy or sell electricity, and are
entitled to charge a toll for the provision of transmission services.
Distributors are also regulated through the establishment of rates and
specifications for quality of service. They are required to satisfy demand in
their markets and, as long as they have any distribution capacity available,
they have to permit large scale users, who have purchased electricity from a
different source, to transmit such electricity through their network. Large
scale users include (i) major large users, meaning consumers with a demand of
at least 1.0 MW of electricity who are willing to execute contracts with a
duration of at least one year and who purchase electricity through contracts
that require that the suppliers meet at least 50% of their demand, and (ii)
minor large users, meaning consumers with a demand between 0.1 MW and 2.0 MW of
electricity who are willing to execute contracts with a duration of at least
two years and who purchase electricity through contracts that require that the
suppliers meet 100% of their demand. Management and Operations of the WEM The activities of participants in the WEM are governed by the terms of the
Regulatory Framework Law. Additionally, CAMMESA was specifically created by
the federal government to perform the necessary administrative functions of the
WEM. CAMMESAs capital stock is distributed equally among the entities
representing generation companies, transmission companies, distribution
companies, large scale users and the Secretary of Energy, each of which has the
right to nominate two of CAMMESAs directors. The Secretary of Energy has a
veto right over the decisions taken by CAMMESA. CAMMESAs operating costs are
covered by mandatory contributions made by all the members of the WEM. CAMMESA
does not itself buy or sell electricity, but it manages the physical
transactions of the system and commercial transactions on the spot market. In addition to the national structure of the WEM, medium-voltage
transmission and distribution of electricity (except in the city of Buenos
Aires, the greater Buenos Aires area and the city of La Plata) are also subject
to provincial regulation. In particular, provincial governments may, in
certain cases, forbid the direct sale of electricity to large scale users
within their own jurisdiction. Large scale users connected to the national
interconnected system (described below), however, cannot be prevented from
purchasing electricity directly from generators. Dispatch The dispatch of generating units into the WEM is managed by CAMMESA based
on the short-run marginal cost of each unit on the system. CAMMESA defines the
marginal cost of thermoelectric generating units for dispatching purposes as
the cost of fuel delivered (natural gas, fuel oil, diesel oil or coal) for such
unit to produce 1kWh. The marginal cost of hydroelectric plants with
reservoirs that are overflowing is determined by a model that takes into
account existing reservoir levels and projected hydroelectrical conditions for
the subsequent six months. The marginal cost associated with flow-through
hydroelectric generating units is zero, meaning that such units are the first
to be dispatched. 73




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Generation companies advise CAMMESA on a weekly basis of their anticipated
available energy and other relevant information such as fuel type, price and
anticipated consumption. CAMMESA then ranks each generating unit according to
that units marginal costs, taking into consideration the minimum operating
load needed to keep generating units on line and expenses incurred in shutting
down and restarting generating units. Based on this ranking, and in order for
CAMMESA to obtain the lowest overall system cost, generating units are
dispatched to the network successively from the lowest cost generating unit to
the highest cost generating unit until the demand for electricity is met.
CAMMESA is responsible for administering all transactions through the WEM, but
is not involved in the actual settlement of transactions between generators,
distributors and large users that have entered into either long-term or
medium-term contracts. CAMMESA makes optimum dispatch arrangements without taking into account
the existence of long-term and medium-term agreements between generators,
distributors and large scale users. CAMMESA also administers an option market
in which generators may enter into option contracts known as cold reserve
contracts. Finally, CAMMESA coordinates the dispatching of generators in the
spot market. As a consequence of the crisis in Argentina, the Secretary of Energy
issued Resolution 2/02, which pesified the prices of power and the reference
prices of fuels at an exchange rate of P$1=U.S.$1. This placed a limit on the
generators stated prices. Resolution No. 8/02 established market prices that
accounted for part of the variable costs in production declared by the
generators, and it also established a maximum price of $120/MWh. Resolution
No. 82/03 suspended the last seasonal increase of prices. Under Resolution No.
240/03, in connection with the spot market, generators are able to set a market
price without considering potential restrictions in the supply of gas, and
those generators, with costs higher than the established price, are
individually paid their variable costs of production. By means of Resolution
No.406/03 the Secretary of Energy established that all credits pending of
payment by CAMMESA as a consequence of the deficit of the Stabilization Fund
(due to the suspension of the seasonal increase of prices) should be
consolidated and paid once this fund has sufficient monies. Resolution SE No. 984/03 authorized the WEM to call for bids for reserve
of available capacity fuel for the Argentine winter period from May through
October 2004. We participated with a bid of 550 MW from the Genelba Power
Plant and were awarded in advance U.S.$29,072,736. Resolution SE No. 93/04 authorized summer quarterly rescheduling for the
WEM, for the period from February up to April 30, 2004, establishing new
reference seasonal prices for power and electricity. Generation Power plants in Argentina are classified by the type of energy source
usedhydroelectric, nuclear and thermoelectric (gas, fuel oil, diesel oil or
coal). Power plants are also classified by capacity, defined as the net output
the station is capable of sustaining for an indefinite period without causing
damage to the station, which is referred to as declared net capacity. Transmission In Argentina, bulk transfer of electricity is achieved by means of a
national interconnected system, or NIS, which consists mainly of overhead lines
and substations and covers approximately 90% of the territory of Argentina.
Practically all of the NIS 500 kV transmission lines have been privatized and
are owned by Transener. Apart from Transener, there are five other regional
subtransmission companies in charge of transmitting energy at 132 kV and 330 kV
voltages, and almost all large power plants use the NIS. Supply points connect
the NIS to distribution systems and large users. In addition, there are two
international connections: one between the Argentine transmission system and
the Uruguayan transmission system, and the other between Argentina and Brazil,
which permit the import or export of electricity between these systems. The
cost of transmission is charged to generators, distributors and large users.
The transportation cost is made up of a variable charge corresponding to the
energy transmitted across the system, and a fixed charge for (1) connection to
the system, (2) transformation and (3) transmission capacity. Transmission
companies operate as common carriers and must provide open access to all
generation companies. Transeners rates are set by the concession contract and
are to be subject to revision by ENRE. The law provides that services provided
by transmission companies must be offered at fair and reasonable rates which
yield sufficient income to meet reasonable operating costs applicable to
service, taxes, depreciation and a reasonable rate of return. The rate of
return should bear a relationship to (i) the energy costs, (ii) the use of 74




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transmission lines and (iii) the degree of operating efficiency of the
business, and should be similar, as an industry average, to that of other
domestic or international activities of similar or comparable risk. The rates
that Transener may charge have been modified by the Public Emergency Law. See
"The Argentine Gas Industry and Regulatory FrameworkPublic Emergency Law. Pursuant to Resolution No. 1650/98, ENRE approved an 8% overall reduction
of Transeners tariffs for the second tariff period, July 1998  June 2003,
retroactive to July 17, 1998. In addition, a bonus subject to compliance with
certain quality parameters was approved, and currently, Transeners quality
levels entitle it to a bonus of approximately P$2.5 million. Since the beginning of the second tariff period, Transeners income from
transportation capacity and connection has been reduced annually through the
application of an efficiency ratio established by ENRE. Pursuant to Resolution
No. 1319/98, the efficiency ratio applicable to the second tariff period is
approximately 0.5% per annum. Distribution Electricity is transferred from the NIS supply points to consumers by
means of distribution systems consisting of a widespread network of overhead
lines, underground cables and substations having successively lower voltages
(220 kV and below). In general, electricity users in Argentina are the users
of the distributor within whose area of distribution the premises of such
consumer are located. Each user is charged in accordance with the applicable
tariff. Distributors charges seek to recover the various costs associated
with supply, including the electricity purchase costs and transmission and
distribution charges, in addition to, the added value of distribution. In
accordance with Law 24,065, and in the case of transmission companies, services
provided by electricity distributors must be offered at fair and reasonable
rates which yield sufficient income to meet reasonable operating costs
applicable to service, taxes, depreciation and a reasonable rate of return.
The rate of return should bear a relationship to the degree of operating
efficiency of the business, and should be similar, as an industry average, to
that of other domestic or international activities of similar or comparable
risk. Similarly, distributors are required to include a representative figure
for the acquisition cost of electricity from the WEM in the electricity sales
price to end-users. Each distributor operates in accordance with a concession agreement
executed between itself and the Argentine government or provincial government,
depending on whether the distributor is under federal or provincial
jurisdiction, which provides for, among other things, the area of its
concession, the quality of service that it is required to provide, the tariffs
it is permitted to charge and its obligation to satisfy demand. ENRE, in the
case of distributors under the federal jurisdiction (Edenor, Edesur and
Edelap), and the provincial regulatory agencies in each of the provinces,
monitor compliance by the distributor with the provisions of the concession
agreement and the regulatory framework and provide a mechanism for public
hearings at which complaints against the distributor can be heard and resolved. Rate Adjustment Method Under the terms of the concession contract, the rate adjustment structure
applicable by Edesur is calculated in U.S. dollars but stated in Argentine
pesos, taking into account the rate for conversion into Argentine pesos
provided for in section 3, Decree No. 2128/91, containing the regulations under
Law 23,928. Distribution costs are adjusted on an annual basis and, among
other things, are subject to the application of the U.S. wholesale price index
for industrial products. Since the adoption of the Public Emergency Law and other emergency
measures taken by the Argentine government in early 2002, the regulation of
public utility tariffs, including those related to transportation and
distribution of electricity, has changed dramatically. The rapid
implementation of these rate changes has resulted in a complex and oftentimes
conflicting legal framework. Although the rate regulations described below are
still in effect, in practice they have been superseded by the new regulations
described under The Argentine Gas Industry and Regulatory FrameworkPublic
Emergency Law. We cannot assure which regulatory scheme will ultimately be
implemented by the Argentine government once it acts to conform the conflicting
regulations. 75




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On December 2, 2003, Law 25,820 was promulgated, which extended until
December 31, 2004 the public emergency declared by Law 25,561 on social,
economic, administrative, financial and foreign exchange matters, and the
delegation of powers therein provided to the federal executive branch to
renegotiate the tariffs of the public services and license contracts. This
authorization empowers the national executive branch to negotiate such tariffs
without being constrained by the applicable regulatory frameworks. The legally
permitted revisions of any current tariff should be decided by the applicable
regulatory agency to the extent that these revisions fall within the scope of
the renegotiation process led by the federal executive branch. In addition,
the transitory changes made to the utility service agreements and/or licenses
should be considered in the definitive agreements that may be reached with
respect thereto. The Venezuelan Petroleum and Gas Industry and Regulatory Framework Overview The Venezuelan state is owner of all hydrocarbon fields and as such has
established methods different from Argentina for the regulation of the
exploitation of hydrocarbon located in Venezuelan fields. The Gas Hydrocarbons Organic Law published on September 23, 1999 in
Official Gazette No. 36,793, was issued to regulate the exploitation of free
gas and the transportation, distribution, collection, storage,
industrialization, handling and internal and external commerce of associated
gas and free gas, permitting the private sectors participation in these
activities. This was later regulated by Decree No. 840 of May 31, 2000. In December 1999, the new Venezuelan Constitution became effective, which
contains provisions related to petroleum activity. Article 12 of the
Constitution states that oil fields are the property of the Venezuelan state.
Article 302 of the Constitution reserves petroleum activity to the Venezuelan
state. Article 303 of the Constitution states that, PDVSA or the entity
created for the management of petroleum activity (except for affiliates,
strategic associations, companies or any other company set up to develop
PDVSAs business) is owned by Venezuelan state. The new Hydrocarbons Organic Law published on November 13, 2001 in
Official Gazette No. 37,323 was issued, effectively reversing most prior
related legislation, except for the Gas Hydrocarbons Organic Law, and granted
ample opportunity for the private sector to participate in the industry,
limiting the activities reserved by the Venezuelan state to primary activities,
and to the sale of crude oil and specific products. The purpose of the Hydrocarbons Organic Law is to regulate everything
related to the exploration, exploitation, refinery, industrialization,
transportation, storage, commercialization and conservation of hydrocarbons,
and everything related to refined products and works that the performance of
these activities require. The law sets forth the following principles: (i)
hydrocarbon fields are public property, (ii) hydrocarbon activities are
activities of public utility and of social interest, and (iii) activities
described in the law are subject to decisions of the Venezuelan state adopted
in connection with international treaties and agreements on hydrocarbons. The Performance of Hydrocarbon Related Activities The primary activities expressly reserved by law to the Venezuelan state
can only be performed by: (i) the executive branch, (ii) wholly owned state
entities, or (iii) companies in which the Venezuelan state owns at least 50% of
the capital stock. Activities related to the internal and external sale of
natural hydrocarbons and the derivatives, specifically mentioned by the
executive branch, can only be performed by wholly owned state entities.
Installations and existing facilities dedicated to the refining of natural
hydrocarbons in the country and to the transportation of products and gas are
reserved to the Venezuelan state. Hydrocarbon refining activities may be carried out by the Venezuelan state
and private entities, in a joint effort or separately. Those activities
relating to the internal and external sale of derivative products, which have
not been reserved by the executive branch to be carried out by wholly owned
state entities, may be carried out directly by (i) the Venezuelan state, (ii)
by wholly owned state entities, (iii) by entities with public and private
capital in any proportion, or (iv) by private entities. Pursuant to Decree No.
1,648 dated January 15, 2002, activities related to the exportation and
importation of products derived from hydrocarbons that have been carried out in
the past by wholly owned state entities shall continue to be carried out in
such manner until those products are specifically excluded in order to create
an international market for them. Internal commercial activities regarding
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may be performed by anyone who obtains a permit. The sale of refined
hydrocarbons may be performed by (i) the Venezuelan state, (ii) its wholly
owned state entities, (iii) entities with public and private capital in any
proportion, and (iv) private entities. In order for the Venezuelan state to carry out its activities, the
executive branch is authorized to create, through a Council of Ministers,
wholly owned state entities of any kind, including corporations. These
entities may also create other entities, with the approval of their
shareholders, or modify their corporate purpose, merge, enter into joint
ventures, liquidate, and create affiliates. These wholly owned state entities
are regulated by (i) Decree No. 1,648 and its regulations, (ii) their by-laws,
(iii) dispositions of the executive branch and certain entities connected with
the Ministry of Energy and Mines, and (iv) applicable law. They are also
subject to local and international inspection and audit and must comply with
guidelines and policies of the executive branch administered through the
Ministry of Energy and Mines. The private sector may participate in primary hydrocarbon related
activities only through entities in which the Venezuelan state holds the
majority of the capital. The creation of these entities and the conditions
under which they will carry out their activities must be previously approved by
the National Assembly, which may modify the conditions proposed or set forth
conditions that it, itself, considers suitable. These entities must meet the
following minimum conditions: (i) must have a maximum duration of 25 years
(which may be extended for 15 years), (ii) must provide information regarding
location, orientation and extension of the area, (iii) all of their assets must
be reserved and turned over to the Venezuelan state once the activity ends, and
(iv) any dispute among its shareholders must be resolved through private
negotiations or arbitration and shall be subject to the Venezuelan legal
system. Licenses and permits Entities that wish to carry out activities related to the refining of
natural hydrocarbons must obtain a license from the Ministry of Energy and
Mines. This license is subject to certain conditions. Entities that wish to
carry out activities related to the processing of refined hydrocarbons must
obtain a permit from the Ministry of Energy and Mines. This permit is also
subject to certain conditions. Entities that wish to carry out activities
related to the domestic sale of refined hydrocarbons must obtain a permit from
the Ministry of Energy and Mines. Relevant tax features Income Tax Venezuelan income tax law imposes a tax at a rate of 50% on the net
taxable income of persons involved in hydrocarbon related activities, or
activities related to the purchase or acquisition of hydrocarbons and
derivatives for exportation. These persons may be authorized to deduct from
their income tax 8% of the value of new investments in fixed assets up to a
maximum amount equal to 2% of their annual income for the relevant fiscal year.
Any excess may be used in the following three fiscal years. Four percent of
certain investments in high waters may also be deducted. Accelerated
amortization and depreciation of fixed assets and direct or indirect expenses
necessary for the drilling of oil wells is permitted. Activities related to the exportation of extra-heavy hydrocarbons through
vertically integrated projects or the exploration or exportation of natural
non-associated gas are subject to a 34% rate. Contractors dedicated to exploration and production activities under
operative agreements with state companies are subject to a 34% rate. Value Added Tax Subject to certain exceptions, in particular for exporting companies,
imports and local purchases of goods and services are subject to a value added
tax, or VAT, at a rate of 16%, with a limited number of goods and services
subject to a VAT at a rate of 8%. In operative contracts for the rehabilitation of marginal fields, the VAT
on goods and services acquired by the contractor in the name of the state
company shall be considered directly charged, under the Third Round Agreements,
to that entity and, therefore, will have no economic effect on the contractor. 77




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Municipal Taxes Hydrocarbon activity is not subject to municipal taxes, as taxes on this
activity are exclusively reserved for the national executive branch. Income from contractors that have entered into operative contracts with
state companies for the rehabilitation of marginal fields is subject to a tax
on gross income. The municipality in which the contractors perform their
activities sets this rate. Under the Second Round Agreements, municipal taxes
paid by a contractor can be recovered from the state. However, under the Third
Round Agreements, only municipal taxes in excess of 41% of gross income may be
recovered from the state, subject to certain conditions. Additional Matters OPEC Venezuela is a founding member of the Organization of Petroleum Exporting
Countries. In the past, PDVSA, under instructions from the Ministry of Energy
and Mines, has adjusted its own production to assure that Venezuela as a whole
complies with the production ceilings set forth by OPEC. The Venezuelan government has created a policy of strict compliance with
the production quotas decided within OPEC. Article 6 of the new Hydrocarbons
Law extends reductions such as those that may be set forth by OPEC to all
persons that perform activities regulated by the Hydrocarbons law. As a result
of this, if there are productions cuts, these cuts may directly affect private
producers and contractors as well as PDVSA. Under agreements that specifically contemplate production costs (e.g., the
Third Round Agreements), the reductions that may be imposed on the contractor
may not exceed the percentage of reduction in production requested from
petroleum companies that operate in Venezuela as a whole, including Petróleos
Venezuela, S.A. and its affiliates. These reductions must be determined in
each case with respect to available production capacity. If the contractor
cannot recuperate losses resulting from these production cuts by increasing
production to an adequate level, it has the right to extend the original 20
year term of its operating agreement in order to produce the same quantity that
it would have produced without the production cut. Exchange Control System On February 5, 2003, the Venezuelan government set forth an exchange
control system (Exchange System Agreement No. 1 of February 5, 2003, as amended
on March 19, 2003). These regulations state that companies set up for the
purpose of developing any of the activities described in the Hydrocarbons
Organic Law may maintain outside of Venezuela accounts in currency other than
the currency of Venezuela in banking or similar institutions only for purposes
of meeting their obligations outside Venezuela, which obligations must be
verified by the Central Bank of Venezuela. Any other foreign currency
generated by such companies must be sold to the Central Bank of Venezuela.
These companies do not have the right to acquire foreign currency from the
Central Bank of Venezuela to make foreign currency payments. These limitations
do not apply to contractors who have entered into operative agreements, and,
thus, act on account of the PDVSA. These companies are only obligated to sell
to the Central Bank of Venezuela any foreign currency that they voluntarily
bring into Venezuela. The Bolivian Petroleum and Gas Industry and Regulatory Framework Overview In Bolivia, the System of Regulation by Sectors, or SRS, has the
responsibility to regulate, control and supervise telecommunications,
electricity, hydrocarbons, transportation and water activities, to assure that
they operate efficiently, protecting the interest of users, service providers
and the Bolivian state by contributing to the development of the country. The SRS Law of October 1994 created the SRS and defined the functions of
the General Superintendent and the general attributes of the Sectors
Superintendent. The SRS Law and its regulations include provisions related to
antitrust and competition, appeal mechanisms, and procedures to address claims
from users. 78




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Subsequently, laws were enacted that regulate different public services,
including hydrocarbons. In particular, these laws create rules related to the
granting of rights, prices and tariffs, quality of services, coverage,
technological innovation, entry and exit control, use of natural recourses,
users claims, and they regulate issues related to industrial organization,
identifying the different market structures of each industry. Hydrocarbons Law 1689 Pursuant to the Hydrocarbons Law 1689 of April 30, 1996, the right to
explore and exploit hydrocarbons fields and to commercialize their products is
exercised by the Bolivian state through Yacimientos Petrolíferos Fiscales
Bolivianos, or YPFB, which enters into shared risk agreements that may not
exceed 40 years for the exploration, exploitation and commercialization of
hydrocarbons. YPFB also administers and audits the shared risk agreements.
All controversies arising between YPFB and the contractors under shared risk
agreements must be resolved through arbitration with application of Bolivian
law. The holders of shared risk agreements shall have the right to explore,
exploit, extract, transport and commercialize production. Volumes needed to
satisfy internal demand for natural gas and to comply with the exportation
agreement entered into by YPFB are not freely disposable, and the Hydrocarbons
Superintendent periodically sets these volumes. Producers of hydrocarbons have the right to construct and operate
pipelines for transportation of their own or third parties production. The refining and industrialization of hydrocarbons and the
commercialization of hydrocarbon products is not restricted and may be carried
out by any entity with due registration from the Hydrocarbons Superintendent,
as long as that entity complies with specific legal requirements. The Ecuadorian Petroleum and Gas Industry and Regulatory Framework Legal and Regulatory Framework Petroleum activity in Ecuador is regulated by (i) the Hydrocarbons Law (of
Ecuador) and its regulations, (ii) certain Ministry of Energy and Mines
regulations, and (iii) the specific terms of a tender for public auction. Regulatory Authorities The executive branch, led by the President of the Republic, regulates
hydrocarbon policies. The Ministry of Energy and Mines sends hydrocarbon
policies to the President for his consideration. Audit Authorities The National Directorate of Hydrocarbons, who is under the authority of
the Ministry of Energy and Mines, is the technical and administrative entity in
charge of controlling and auditing hydrocarbon operations. The National
Directorate for Environmental Protection, who is also under the authority of
the Ministry of Energy and Mines, is in charge of approving environmental
impact studies and environmental management plans. Exploration and Exploitation of Hydrocarbons Hydrocarbons and related products are the property of the Ecuadorian
state. Hydrocarbon activities are performed by the Empresa Estatal de
Petroleos Ecuador, which we refer to as Petroecuador, by and through third
parties. The award of exploration and exploitation agreements is performed through
a special tender mechanism implemented by relevant authorities. In order to
reach the exploitation phase, the contractor may only retain those areas with
commercially exploitable hydrocarbons. If the contractor fails to comply with
this requirement, it will be forced to return those areas to the state. The
exploration and exploitation agreements for crude oil in Ecuador are generally
divided into two stages. The first stage, or the exploration period, lasts
four years and is renewable for 79




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another two years. The second stage, or the exploitation period, may be
up to twenty years in duration and is renewable. Both exploration and
exploitation agreements require an exploratory program agreeable to all
parties. A minimum average investment of U.S.$120 to U.S.$180 per hectare,
either on land and/or in seawater, shall be made during each of the first three
years of the exploration period. Royalties are paid as follows: (i) 12.5% for
daily gross production levels less than 30,000 barrels, (ii) 14% when these
daily levels are between 30,000 and 60,000 barrels, and (iii) 18.5% when gross
production exceeds 60,000 barrels per day. With respect to contracts for
specified services or for marginal or participation fields, the contractor is
not obliged to pay royalties. The contractor may not sell any of the assets
related to the agreement without authorization from the Ministry of Energy and
Mines. At the end of the term of the agreement, the contractor shall deliver
to Petroecuador, at no cost, all these assets. The contractor assumes at its own risk and expense all investments, costs
and expenses required to perform these hydrocarbon related activities, and, in
turn, it has the right to receive a portion of the production of the area
covered by the agreement, with Petroecuador having the right to the other
portion. Petroecuador may enter into joint venture agreements by contributing
rights over areas, fields, hydrocarbons or other rights. Petroecuadors joint
venture party, in turn, acquires these rights and is obligated to make the
investments agreed to by the parties. In services agreements, the contractor
shall provide exploration and exploitation services in the agreed area at its
own risk and expense. If the contractor finds commercially exploitable fields,
it shall have the right to be reimbursed for its investments, costs and
expenses and will also have the right to be paid for its services. Prior to initiating any work, an environmental impact study and an
environmental management plan must be prepared. Consultation and participation
procedures, referred to in the National Constitution, must be complied with
while taking into consideration local rules of the citizens in the affected
area, as well as the rules applicable to all other citizens. The Brazilian Petrochemical Industry and Regulatory Framework Overview The petrochemical industry in Brazil transforms crude oil by-products or
natural gas into widely used consumer and industrial goods. The Brazilian
petrochemical industry is generally organized into three sectors, each
characterized by the stage of transformation of various petrochemical
feedstocks: first generation companies, second generation companies and third
generation companies. First Generation Companies Brazils first generation companies, which are referred to as crackers,
break down or crack naphtha, their principal feedstock, into basic
petrochemicals. The crackers currently purchase their naphtha, which is a
by-product of the oil refining process, from Petrobras. The basic
petrochemicals produced by the crackers include olefins, primarily ethylene,
propylene and butadiene and aromatics, such as benzene, toluene and xylenes.
Companhia Petroquímica do Nordeste, or Copene, Companhia Petroquímica do Sul,
or Copesul, and Petroquímica União S.A., or PQU  Brazils three crackers 
sell these basic petrochemicals to second generation companies. The basic
petrochemicals, which are in the form of either gases or liquids, are
transported to the second generation companies nearby plants through pipelines
for further processing. Second Generation Companies Second generation companies process the basic petrochemicals purchased
from the crackers to produce intermediate petrochemicals. These intermediate
petrochemicals include:  
    
    polyethylene, ethylene oxide, polystyrene and
polyvinylchloride, or PVC, each produced from ethylene;
    
    polypropylene, oxo-alcohols and acrylonitrile, each produced from propylene;
    
    caprolactam, produced from benzene; 80




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
    
    purified terephtalic acid, or PTA, produced from p-xylene; and
    
    styrene butadiene rubber and polybutadiene, each produced from butadiene. There are approximately 48 second generation companies operating in
Brazil, including Innova. The intermediate petrochemicals are produced in
solid form as plastic pellets or powders and in liquid form and are transported
by truck to third generation companies, which generally are not located near
the second generation production facilities. Third Generation Companies Third generation companies, known as transformers, purchase the
intermediate petrochemicals from the second generation companies and transform
them into final products. These final products include:  
    
    plastics produced from polyethylene, polypropylene and PVC;
    
    acrylic fibers produced from acrylonitrile;
    
    polyester produced from PTA and ethylene glycol;
    
    nylon produced from caprolactam; and
    
    elastomers produced from butadiene. The third generation companies produce a variety of consumer and
industrial goods, including containers and packaging materials, such as bags,
film and bottles, textiles, detergents and paints as well as automobile parts,
toys and consumer electronic goods. There are over 6,000 third generation
companies operating in Brazil. Petrochemical Complexes The production of first and second generation petrochemicals in Brazil
centers around three major complexes. These are the Northeast Complex, the São
Paulo Petrochemical Complex, which we refer to as the São Paulo Complex, and
the Southern Petrochemical Complex, which we refer to as the Southern Complex.
Each complex has a single first generation producer or cracker, and several
second generation companies which purchase feedstock from the crackers. The Northeast Complex, located in the municipality of Camaçari in the
State of Bahia, began operations in 1978. The Northeast Complex consists of
approximately 25 second generation companies, situated around Copene as the raw
materials center. Copene has at present an ethylene capacity of 1.2 million
metric tons per annum. The São Paulo Complex, at Capuava in the State of São Paulo, was created
in 1972 and is the oldest petrochemical complex in Brazil. Its raw material
center, PQU, supplies first generation petrochemicals to 15 second generation
companies. PQU has an ethylene production capacity of 500,000 metric tons per
annum. The Southern Complex, located in the municipality of Triunfo (where Innova
is located) in the Southern State of Rio Grande do Sul, is based around the raw
materials center, Copesul, and includes eight second generation companies,
including Innova. In July 1999, Copesul finalized an expansion project which
increased ethylene production capacity to 1,135,000 metric tons per annum from
680,000 metric tons per annum. Environmental, Health and Safety Standards Innova is subject to Brazilian federal, state and local laws and
regulations governing the protection of the environment. Innova is regulated
at the federal level primarily by the Brazilian Institute of the Environment
and Renewable Natural Resources (Instituto Brasileiro de Meio Ambiente e
Recursos Naturais Renováveis) and by National Council of the Environment
(Conselho Nacional do Meio Ambiente), or CONAMA. 81




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Pursuant to federal and state environmental laws and regulations, Innova
is required to obtain permits for its manufacturing facilities. Authorities in
the state where a plant is located may regulate its operations by prescribing
specific environmental standards in its operating permits. These environmental
standards are prescribed and updated by governmental regulations. In addition,
Innova must satisfy regulatory authorities that the operation, maintenance,
termination and reclaiming of facilities are in compliance with regulations and
are not prejudicial to the environment. Environmental regulations apply to all operations of Innova, and in
particular to the discharge, handling and disposal of gaseous, liquid and solid
products and by-products of Innovas manufacturing activities. Rules issued by
CONAMA and by state authorities also prescribe preventive measures relating to
environmental pollution and waste treatment requirements. In addition, the
transportation and storage of Innovas products and supplies are subject to
specific standards designed to prevent spills, leakages and other accidents. Environmental regulations have imposed increasingly strict standards,
higher fines, greater exposure to liability and increased operating costs and
capital expenditures. In addition, civil, administrative and criminal
sanctions, including fines and the revocation of licenses may apply to
violations of environmental regulations. Under applicable law, Innova is
strictly liable for environmental damages. Innova actively participates in the
responsible care program, which establishes international standards for
environmental and occupational health and safety practices for chemical
manufacturers. Innova is also subject to federal, state and local laws and regulations
that prescribe occupational health and safety standards. In accordance with
such laws and regulations, Innova is required to report on its occupational,
health and safety records on a yearly basis to the local office of the Ministry
of Labor in each of the states in which it operates. In addition, Innova is
subject to all federal, state and local government regulation and supervision
generally applicable to companies engaged in business in Brazil, including
labor laws, social security laws, public health, consumer protection,
securities laws and antitrust laws. 82




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ORGANIZATION STRUCTURE (ORGANIZATION CHART) 83




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The following is a summary diagram of our material subsidiaries and
affiliates as of the date of this annual report, including information about
ownership, business segment and location: (PETROBRAS ENERGIA CHART) 84




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PROPERTY, PLANTS AND EQUIPMENT We have freehold and leasehold interests in various countries in South
America, but there is no specific one that is individually material to our
company. The majority of our property, consisting of oil and gas reserves,
service stations, refineries, petrochemical plants, power plants, manufacturing
facilities, power distribution systems, stock storage facilities, gas
pipelines, oil and gas wells, pipelines and corporate office buildings, is
located in Argentina. We also have significant interests in crude oil and
natural gas operations outside Argentina in Venezuela, Ecuador, Bolivia and
Peru, two refineries in Bolivia, and a petrochemical plant in Brazil. For a
more detailed description of our property, plants and equipment, including
information on our oil and gas reserves and production see Business
Overview. 85




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Item 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS In addition to the management discussion below, you should carefully read
Petrobras Energía Participacioness consolidated financial statements and
selected financial data included elsewhere in this annual report for additional
financial information about us. Our consolidated financial statements were
prepared in accordance with Argentine GAAP, which differs in certain
significant respects from U.S. GAAP. Note 22 to our consolidated financial
statements provides a description of the principal differences between
Argentine GAAP and U.S. GAAP as they relate to us, and note 23 provides the
reconciliation to U.S. GAAP of net income, shareholders equity and certain
other selected financial data. OVERVIEW We are a holding company whose only asset is our 98.21% equity interest in
Petrobras Energía common stock. We acquired control of Petrobras Energía on
January 25, 2000 as a result of the completion of an exchange offer of our
Class B shares for 69.29% of Petrobras Energías common stock. See note 12 to
our financial statements for further information relating to our exchange
offer. Prior to January 25, 2000, our only asset was our minority interest in
Petrobras Energía. As of December 31, 1999, we owned 28.92% of Petrobras
Energías capital stock. We are an integrated energy company engaged in oil and gas exploration and
production, refining, petrochemicals, electricity generation, transmission and
distribution and hydrocarbons marketing and transportation. We conduct
operations in Argentina, Bolivia, Brazil, Ecuador, Peru and Venezuela. Our
long-term strategy is to grow as an integrated energy company with a leading
presence in Latin America as part of the Petrobras group, while focusing on

profitability as well as social responsibility. In accordance with the procedures set forth in Technical Resolutions Nos.
4 and 19 of the FACPCE beginning in 2003, we were required to consolidate on a
proportional basis the financial statements of companies over which we exercise
joint control. We have restated our financial statements as of and for the
years ended December 31, 2001 and 2002 to reflect this change as well as recent
changes in Argentine GAAP. See note 3 to our consolidated
financial statements. The tables below present selected consolidated
financial data of Petrobras Energía and its subsidiaries including the
proportional consolidation of certain companies under joint control, as
compared to such data excluding the proportional consolidation of such
companies under joint control, in each case for the fiscal years indicated. 86




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With Proportional Consolidation
    
    Without Proportional ConsolidationFor the Year Ended
    
    For the Year EndedDecember 31,
    
    December 31,2003
    
    2002
    
    2001
    
    2003(1)
    
    2002(1)
    
    2001(1)Net sales
    
    
    5,494
    
    
    
    5,106
    
    
    
    5,170
    
    
    
    4,615
    
    
    
    4,587
    
    
    
    3,614Costs of sales
    
    
    (3,386
    )
    
    
    (3,284
    )
    
    
    (3,347
    )
    
    
    (2,813
    )
    
    
    (2,878
    )
    
    
    (2,459
    )Gross profit
    
    
    2,108
    
    
    
    1,822
    
    
    
    1,823
    
    
    
    1,802
    
    
    
    1,709
    
    
    
    1,155Administrative and selling expenses
    
    
    (559
    )
    
    
    (609
    )
    
    
    (665
    )
    
    
    (464
    )
    
    
    (532
    )
    
    
    (510
    )Exploration expenses
    
    
    (196
    )
    
    
    (58
    )
    
    
    (41
    )
    
    
    (196
    )
    
    
    (58
    )
    
    
    (41
    )Other exploitation income (loss) net
    
    
    (121
    )
    
    
    (28
    )
    
    
    23
    
    
    
    (104
    )
    
    
    (28
    )
    
    
    20Exploitation income(2)
    
    
    1,232
    
    
    
    1,127
    
    
    
    1,140
    
    
    
    1,038
    
    
    
    1,091
    
    
    
    624Equity in earnings of affiliates
    
    
    163
    
    
    
    (638
    )
    
    
    119
    
    
    
    373
    
    
    
    (647
    )
    
    
    204Financial income (expense) and
holding gains (losses)
    
    
    (417
    )
    
    
    (1,827
    )
    
    
    (573
    )
    
    
    (569
    )
    
    
    (1,659
    )
    
    
    (451
    )Other expenses, net(3)
    
    
    (421
    )
    
    
    (187
    )
    
    
    (88
    )
    
    
    (407
    )
    
    
    (178
    )
    
    
    (14
    )Income (loss) before income tax and
minority interest in subsidiaries
    
    
    557
    
    
    
    (1,525
    )
    
    
    598
    
    
    
    435
    
    
    
    (1,393
    )
    
    
    363Income tax provision
    
    
    (18
    )
    
    
    (82
    )
    
    
    (385
    )
    
    
    (47
    )
    
    
    (209
    )
    
    
    (249
    )Minority interest in subsidiaries
    
    
    (158
    )
    
    
    28
    
    
    
    (112
    )
    
    
    (7
    )
    
    
    23
    
    
    
    (13
    )Net income (loss)
    
    
    381
    
    
    
    (1,579
    )
    
    
    101
    
    
    
    381
    
    
    
    (1,579
    )
    
    
    101
   (1)
    
    For a reconciliation of our results to our
results as adjusted to reflect the elimination of proportional
consolidation see Reconciliation Tables at the end
of this Item 5.(2)
    
    As used in this annual report, exploitation income means gross profit
plus or minus administrative and selling expenses, exploration expenses
and other exploitation income (expense), net. We present exploitation
income as an indicator of our income from operations. Other jurisdictions
define operating income to include certain expenses that we do not present
as part of our operating income.(3)
    
    Includes impairment charges for some of our
assets including our assets in Ecuador. In the columns above showing our results without proportional
consolidation, the results of companies under joint control are shown under
equity in earnings of affiliates. The companies over which we exercise joint control are Distrilec, CIESA
and Citelec. Joint control exists where all the shareholders have resolved, on
the basis of written agreements, to share the power to define and establish a
companys operating and financial policies. In the consolidation of companies over which we exercise joint control,
the amount of our investment in the subsidiary under joint control and our
interest in its income (loss) and cash flows are replaced by our proportional
interest in the subsidiarys assets, liabilities, income (loss) and cash flows.
Related party receivables, payables and transactions within the consolidated
group and companies under joint control have been eliminated in the
consolidation pro rata to the shareholding of the controlling company. We consolidated proportionally line by line the assets, liabilities,
income (loss) and cash flows of Distrilec for all periods covered by the
financial statements included in this annual report. We consolidated proportionally line by line the assets, liabilities,
income (loss) and cash flow of CIESA for the 2003 and 2001 fiscal years. For
the 2002 fiscal year, however, we did not proportionately consolidate on a line
by line basis the assets, liabilities, earnings and cash flow of CIESA, since,
as of December 31, 2002 our equity interest in such company had a P$33 million
negative value. Since we have not assumed any commitments to make capital
contributions or provide financial assistance to CIESA, such shareholding was
valued at zero and CIESAs results were not consolidated. In accordance with Argentine GAAP, we did not consolidate proportionally
line by line our financial statements with the financial statements of Citelec
because we have committed to sell our interest in Citelec to comply with the
restrictions imposed by the Argentine authorities in connection with the
transfer of our control to Petrobras. 87




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The discussion of our results and financial condition below is presented
both on the basis of our consolidated financial data with the proportional
consolidation of such joint controlled companies as described above and without
proportional consolidation. The financial data discussed below excluding
proportional consolidation is not directly comparable to the corresponding
financial data set forth in our financial statements included in this annual
report. Both CIESA and Distrilec are primarily engaged in regulated energy
businesses in Argentina, through TGS and Edesur, respectively. Both have been
significantly affected by the Argentine crisis and the Public Emergency Law.
CIESA and TGS have defaulted on their debt and are in restructuring discussions
with their creditors. See Factors Affecting Our Consolidated Results of
OperationsEconomic and Political Developments in ArgentinaImpact on our
Investments in Utility Companies. There are significant uncertainties
regarding the ability of CIESA and TGS to continue operating as going concern.
We are not committed, and do not expect, to make any further capital
contributions or financial assistance to CIESA, TGS and Distrilec, and we have
not received dividends from these companies since 2001. Accordingly, our
management analyzes our results and financial condition separately from the
results and financial conditions of these companies and we believe financial
information without proportional consolidation is useful to investors in
evaluating our financial condition and results of operations. FACTORS AFFECTING OUR CONSOLIDATED RESULTS OF OPERATIONS Economic and Political Developments in Argentina We are an Argentine corporation with 63.6% of our total assets, 69.2% of
our net sales, 58% of our combined crude oil and gas production and 40% of our
proved oil and gas reserves located in Argentina as of December 31, 2003.
Fluctuations in the Argentine economy and actions adopted by the Argentine
government have had and will continue to have a significant effect on Argentine
private sector entities, including us. Specifically, we have been affected and
might be affected by inflation, interest rates, the value of the peso against
foreign currencies, price controls, regulatory policies, business regulations,
tax regulations and in general by the political, social and economic
environment in and affecting Argentina. Starting in the second half of 1998 and through 2002, the Argentine
economy was mired in a severe economic recession, with GDP declining 3.4% in
1999, 0.8% in 2000, 4.4% in 2001 and 10.9% in 2002. In 2002, the peso was
devalued by 237.0% (having reached 290% as of June 25, 2002), and Argentina
experienced a rise in the wholesale price index of 118.2% and in the consumer
price index of 41%. Our financial results were negatively impacted by drastic political and
economic changes that took place in Argentina in 2002. The decrease in
industrial output led to decreased demand for energy products in Argentina,
particularly for petrochemical and refined products. In late 2002, as the
foreign exchange and capital flows began to stabilize, the Argentine government
gradually began to lift some of the monetary and exchange control measures it
had implemented to prevent a collapse of the banking system. The lifting of
these measures served to boost economic activity. In 2003, the Argentine economy began to recover, with GDP growing 8.7%.
This recovery, at first based almost exclusively on import substitution,
broadened as the level of consumption and investment increased. Reflecting the
economic recovery, Argentine stock exchange indices displayed great dynamism in
2003, and both labor indicators and salary purchasing power registered
consistent improvements during the year. The long-term evolution of the Argentine economy, however, remains
uncertain. While economic, political and social conditions have improved, the
country still faces significant challenges, including the restructuring of
Argentinas sovereign debt, the renegotiation of utility contracts, the
restructuring of the financial system and reforms to Argentinas tax regime.
In light of this uncertain situation, the following discussion may not be
indicative of our current or future results of operations, liquidity or capital
resources. The recent volatility of the Argentine economy has affected the
comparability of our results in the last three years. The following discussion
should be read in conjunction with, and is qualified in its entirety by, the
risk factors contained in this annual report. See Item 3. Key
InformationRisk FactorsFactors Relating to Argentina. 88




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The most important factors arising from Argentinas economic crisis that
have affected our results of operations are the following:  
    
    Argentine Peso Devaluation During 2002, following the governments termination of the pesos
one-to-one exchange rate parity with the U.S. dollar, the peso registered
a significant devaluation against foreign currencies, losing 238% of its
value against the U.S. dollar. As of December 31, 2002, the pesos
nominal exchange rate was P$3.38 to U.S.$1, up from a P$1 to U.S.$1 rate
as of December 31, 2001. In 2003, however, in part as a result of the
measures adopted by the Argentine government to stabilize the exchange
rate, the peso began to recover its value. As of December 31, 2003, the
peso exchange rate stood at P$2.94 to U.S.$1. Since all of our financial debt and a significant portion of our
affiliates debt is denominated in U.S. dollars, the marked devaluation
of the peso in 2002 adversely affected our financial position. Our exposure to the pesos devaluation was also aggravated by the
pesification of utility rates and other measures implemented by the
Public Emergency Law. Prior to the enactment of this law in January
2002, our cash flows were usually denominated in U.S. dollars or U.S.
dollar-adjusted, which provided hedging against exchange rate risks. The
new Argentine regulatory framework, however, limited our ability to
mitigate the impact of the peso devaluation and prevented us from
increasing the prices of our products in the domestic market to offset
the devaluation of the peso. Despite these restrictions, starting in the second half of 2002,
domestic prices for the main commodities recovered in line with export
prices. In addition, in 2002 we aggressively pursued a trade policy of
opening and consolidating export markets to capitalize on domestic and
export price asymmetries. Based on the above strategies and the solid
positioning of our foreign operations, which have cash flows primarily
denominated in U.S. dollars, our exposure to peso fluctuations has
dropped and we have recovered our ability to naturally hedge our cash
exposure to U.S. dollar liabilities.  
    
    Effects of Inflation In 2002, in light of the peso devaluation and the economic
instability that the country suffered during this year, Argentina
experienced a significant increase in inflation (40.98% and 118.2%
measured in terms of the consumer price index and the wholesale price
index, respectively). This was in sharp contrast with 2001, when
Argentina actually experienced deflationary conditions (negative 1.5% and
negative 5.3% measured in terms of the consumer price index and the
wholesale price index, respectively) due to the constraints of the
Convertibility Law. In 2003, as the peso exchange rate and economic
conditions stabilized, the inflation rate declined significantly, to 3.7%
and 2.0%, measured in terms of the consumer price index and the wholesale
price index, respectively. As a result of the high inflation in 2002, Argentine GAAP
reintroduced inflation accounting. The most important impact of
inflation on results was the incorporation into our financial statements
of the effect of exposure of our monetary assets and liabilities to
inflation and the restatement in constant currency of the rest of our
income statement accounts. See Critical Accounting PoliciesInflation
accounting. In March 2003, in response to the economic stabilization, the
Argentine government issued Decree No. 664, which provided that financial
statements for fiscal years ended after such date must be stated in
nominal currency. Accordingly, starting on March 1, 2003, we
discontinued inflation accounting and the corresponding restatement of
our financial statements. See Critical Accounting PoliciesInflation
accounting. 89




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
    
    Impact on our Investments in Utility Companies The new macroeconomic scenario after enactment of the Public
Emergency Law deeply changed the economic and financial balance of
utility companies. The tremendous effect of the devaluation, within a
context where revenues remained unchanged as a consequence of the
pesification of rates and financial debts primarily denominated in
foreign currency materially and adversely affected the utility companies
financial position, results of operations and the cash generation ability
required to comply with financial obligations. The Public Emergency Law ordered the pesification of utility rates
payable in U.S. dollars, fixing them at the exchange rate of P$1= U.S.$1,
and the elimination in utility contracts of certain indexation clauses.
In addition, the Public Emergency Law granted the Argentine government
broad authority to renegotiate utility contracts. This authority has
been extended to December 2004. See Item 3. Key InformationRisk
FactorsFactors Relating to ArgentinaThe pesification of utility rates
has negatively affected and may continue to affect the operations of our
affiliated utility companies and Item 4. Information about
UsRegulation of Our Businesses. Congress has also authorized the
government to fix utility rates until completion of the renegotiation
process. We cannot predict the outcome of this rate renegotiation
process.  
    
    Inability to Pay Debts In light of the adverse conditions faced by utility companies, TGS,
CIESA and Transener have defaulted on their debt and are trying to
restructure it. Although we do not currently consider it very likely in light of
procedural difficulties related to bankruptcy laws and actions in
Argentina concerning utility companies, there is a risk that we may lose,
in whole or in part, our equity interest in these companies in the event
the restructuring process fails and creditors bring legal actions to
collect against the assets of these affiliates. As part of the debt
restructuring, creditors might demand an interest in these companies
capital stock, thus resulting in the subsequent reduction of our equity
interest in such utility companies.  
    
    Valuation of our Interests in Utility Companies The impact of the measures adopted by the Argentine government on
the financial statements of our affiliate utility companies was
recognized according to the assessments and estimates conducted by their
respective managements. Actual future results may differ from the
assessments and estimates so conducted, and the differences may be
significant. Therefore, the financial statements of such companies may
not report all adjustments that could arise from such a situation. It is
not possible to predict the future evolution of the Argentine economy or
its impact on the economic and financial situation of these companies. As of December 31, 2003, the value of our net investments in CIESA,
TGS and Citelec was P$190 million, P$167 million and P$158 million,
respectively. In our view, the book value of these investments is below
their recoverable value as determined by the market price. Estimates on
the recoverable value of these interests, however, is subject to
significant uncertainties. Accordingly, in the current situation, the
market value of listed shares of these companies is the most objective
method of estimating the net realizable value of such holdings. We note
that as time goes by and the regulatory problems faced by these companies
continue unresolved, the reliability and applicability of any values that
might be used to assess the recoverable value of these interests are
likely to diminish. As of December 31, 2002, the value of our net investments in CIESA,
TGS and Citelec was P$0, P$88 million and P$71 million, respectively. As
of December 31, 2002, our equity interest in CIESA would have accounted
for a P$33 million negative shareholders equity. However, since we did
not assume commitments to making capital contributions or providing
financial assistance to CIESA, such shareholding was valued at zero,
limiting the recognition of related losses to such book value. Our
equity 90




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interest in Citelec was recorded net of a P$66 million impairment
charge to write off the book value of Citelec. As of December 31, 2001, the value of our net investments in CIESA,
TGS and Citelec was P$398 million, P$172 million and P$243 million. For a description of the evolution of our equity interests in the
earnings of our affiliated utility companies see Year Ended December
31, 2003 Compared to Year Ended December 31, 2002Equity in Earnings of
Affiliates and Year Ended December 31, 2002 Compared to Year Ended
December 31, 2001Equity in Earnings of Affiliates. As from 2003, we are required by Argentine GAAP to account for CIESA
on the basis of the proportional consolidation method.  
    
    Taxes on Exports On March 1, 2002, the Argentine government imposed a 20% tax on
exports of crude oil and a 5% tax on exports of certain oil by-products,
which are due to expire in five years. Our export products became
subject to these taxes starting on April 1, 2002. These new taxes forced
us to redesign our business strategies, giving priority to crude oil
refining and the subsequent sale of refined products, both in the
domestic and foreign markets. As a result, sales volume of crude oil
among our business segments increased to 31.7 thousand barrels per day or
21.6% in 2003, while exports of crude oil declined approximately 50%.
Our relationship with Petrobras is a key component of this strategy. In
our refining business in 2003, 210 thousand cubic meters of diesel oil
were sold to EG3, a company controlled by Petrobras. This allowed us to
increase crude oil volumes processed at the San Lorenzo refinery to
levels significantly higher than those recorded over the last few years,
at a profit. In May 2004, the Argentine government increased to 25% the export
tax on crude oil exports, increased the export tax on LPG oil exports to
20% and imposed a 20% export tax on all gas exports.  
    
    Commodities Prices Although the implementation of our risk management strategy
(described below) reduces our exposure to fluctuations in the prices of
hydrocarbons, our results of operations are exposed to changes in the
international prices of crude oil, petrochemical and refined products. In addition, while our reporting currency is the Argentine peso, a
significant portion of our revenues are denominated in or indexed to the
U.S. dollar, reflecting in part the important contribution of exports and
foreign operations to our business. Accordingly, changes in the peso
exchange rate may have a considerable impact on the prices of the
commodities we sell as reported in pesos, thereby affecting our revenues. In 2003, the price of crude oil, gasoline, diesel oil and
electricity increased 4.8%, 16.5%, 7.3% and 20.4%, respectively, while
the price of styrene recorded a 9% decline. In 2002, the price of crude
oil, styrene and polystyrene recorded increases of 62%, 72% and 37%,
respectively.  
    
    Price Stabilization and Supply For the purpose of lessening inflationary pressures caused by the
sharp devaluation of the peso in 2002, the Argentine government issued a
set of regulations aimed at controlling the increase in prices payable by
the final customer. These regulations focused particularly on the energy
sector. Pursuant to the Public Emergency Law, we were precluded from
increasing the price of the gas and energy we sold in the domestic
market, especially for energy sales pursuant to agreements with utility 91




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companies and sales in the spot market. This has changed our
outlook for the gas business, and, as a consequence, we have postponed
some investments in the gas sector, particularly in the Neuquén basin. In January 2003, at the request of the Argentine government,
hydrocarbon producers and refineries (including us) entered into a
temporary agreement to maintain price stability for crude oil, gasoline
and diesel oil in the domestic market. This agreement requires crude oil
deliveries to be invoiced and paid based on a WTI of U.S.$28.5 per
barrel. Any differences between the actual WTI price and this price will
be recorded and will accrue interest. Producers will be compensated by
selling at the agreed price while the actual WTI falls below the agreed
price. Refineries, in turn, will reflect the crude oil reference price
in domestic market prices. This agreement has had no considerable effect
on our results, given the strong integration of our upstream and
downstream operations in Argentina. After successive renewals, this
agreement expired in May 2004. Thereafter, hydrocarbon producers and
refineries executed a new agreement effective until June of 2004, which
provided that, while the WTI per barrel ranges between U.S.$32 and
U.S.$42, crude oil deliveries will be invoiced and paid considering a
reference price equal to (i) 86% of the WTI as long as such price does
not exceed U.S.$36 per barrel, or (ii) 80% of the WTI, in cases when this
price exceeds U.S.$36 per barrel. In 2002, the Argentine government also ordered the pesification of
dollar-denominated prices in the WEM and established a cap on the price
of energy sold in the spot market. The government established a maximum
price of P$120/MWh, regardless of the actual marginal cost of electricity
generation. This diverged from the marginal cost system implemented in
1992 and from the provisions in Electricity Law No. 24,065, which permit
an adequate return on investment in a competitive environment based on a
marginal price system. We note, however, that thermoelectric generators
may cover variable operating costs through certain mechanisms. As a result of the governments decision to maintain seasonal prices
for electricity unchanged following the adoption of the Public Emergency
Law, these prices have not adequately reflected generating costs. As a
result, the funds in the Stabilization Fund were depleted, which
prevented CAMMESA (the administrator of the WEM) from settling its
accounts with market agents. This has resulted in a delay in the payment
of our receivables from CAMMESA. To address this situation, the Ministry
of Energy issued Resolution No. 240/03 (effective August 15, 2003), which
prevented the cost of liquid fuels in power plants and of water in
hydroelectric plants from being included in the determination of
electricity prices. Implementation of this resolution was temporarily
suspended on October 9, 2003.
In addition, due to the governments decision to suspend the
seasonal increases in electricity prices, electricity prices have not
reflected production costs. As a result, the Stabilization Fund was
exhausted and CAMMESA could not settle accounts with market agents.
In December 2003, the Argentine
government made a P$150 million contribution to the Stabilization Fund
and in March 2004 made a further contribution of P$200 million. In
February 2004, with a view to restoring the Stabilization Fund, the
government reinstated the seasonal adjustments for the February-April
2004 period, but on May 2004, the government suspended once again, the
seasonal increases in electricity prices. As of May 2004, the
Stabilization Fund had a deficit of P$650 million. In light of the uncertainties prevailing in Argentina, we have made
progress in renegotiating the terms and conditions of gas and electricity
sale agreements entered into with our industrial clients in order to
adjust prices to reflect the new economic conditions. In this regard, we
have reached commercial agreements that gradually increase sale prices to
reflect the effects of the peso devaluation. We, as well as others, have
attempted to maximize export opportunities in an effort to capitalize on
variations between domestic and export prices, by effectively encouraging
the opening and consolidation of new markets. During 2003, we started to
export gas to Chile from the Austral basin.  
    
    Impairment of assets The peso devaluation and the enactment of the Public Emergency Law,
in addition to all subsequent events, resulted in a dramatic change in
the estimation of the future evolution of results and cash flow of
certain of our businesses and assets. Considering the prevailing
uncertainty of Argentinas economic recovery and the recoverability of
certain assets and businesses, we adjusted the book value of certain
investments and assets to the respective recoverable value. 92




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(i) Gas areas in Argentina: Due to the strong deterioration
of domestic prices of gas and energy produced and to the limited
possibilities of negotiating price increases within the context of
the Public Emergency Law, we adjusted the book value of certain
investments in gas areas in Argentina to their recoverable value,
accounting for impairment charges in the amount of P$37 million in
2003 and P$44 million in 2002. (ii) Argentine government bonds: Following the default by
Argentina on its sovereign debt and related uncertainty, we have
created a provision for the decrease in value of our investments in
dollar-denominated Argentine government bonds. This provision
amounted to P$23 million at December 31, 2003, as compared to P$30
million at December 31, 2002. We are authorized to apply the
nominal value of these bonds toward the payment of our Argentine
federal tax liabilities. As a matter of prudence, we reduce the
provision only when we use the bonds to reduce our tax liabilities. (iii) Tax loss carry forwards: In view of the uncertainty
surrounding our ability to apply these tax losses, we recorded a
charge of P$134 million corresponding to the allowance of tax loss
carried forward accumulated as of December 31, 2001. (iv) Minimum presumed income tax credit: Considering
prospects for the evolution of the results of our operations and
the uncertainty regarding our ability to use amounts paid under
alternative minimum tax rules for the reduction of our future
income taxes, we recorded P$19 million and P$103 million charges in
2002 and 2001, respectively, in respect of the amounts paid as
minimum taxes. Operations in Ecuador In connection with the future exploitation of Blocks 18 and 31, in
Ecuador, we entered into a contract with OCP whereby an 80,000 barrels per day
oil transportation capacity was committed to for a 15-year term as from the
date that OCP starts operations. OCPs commercial operations began on November 10, 2003. From this date,
we are required to comply with our ship or pay contractual obligations for
the aggregate oil volume committed and, by paying a fee, which as of
December 31, 2003 was estimated to be P$7.53 per barrel. Our
annual cost associated with this oil transportation capacity is
approximately P$220 million. Transportation capacity costs are billed
on a monthly basis and charged to expenses by us as incurred. We estimate that oil production from Blocks 18 and 31 will be lower than
our transportation capacity commitment. We have generally based this
estimate on the delays involved in the development of Block 31,
the new Schedule of investments required for the joint development of
Blocks 18 and 31 and a revised outlook of the potential of
Block 31. Notwithstanding this, we will
still be required to comply with our payment obligations with respect to the
aggregate oil volume to which we have committed. Accordingly, as of December 31, 2003, we recorded a P$321 million
impairment allowance in connection with our group of assets in Ecuador. During 2002, we recorded a P$63 million
loss in connection with our investments in Ecuador. Block 31 Block 31 is an exploratory area with a significant reserve potential.
Under the concession contract, the exploration program is divided into two
phases, which expired on July 2001 and June 2003, respectively. The committed
investment demands the acquisition of 1,200 km of 2-D seismic and the drilling
of three exploration wells. Petrobras Energía performed the following works at Block 31: 1,382 km of
2-D seismic, 167 km 2 of 3-D seismic and drilling of four exploration wells at
Apaika, Nenke, Obe and Minta. All wells proved to be successful 93




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and permitted the discovery of the Apaika-Nenke, Obe and Minta fields. For the development of the whole block, we estimate that total investments
will amount approximately U.S.$800 million, U.S.$150 million of which must be
invested before the start of the production phase, which is scheduled for 2006.
The significant drop in the level of our capital expenditures, however, has
caused significant delays when compared to the original plan we designed for
the areas development. See Decline in Historical Capital Expenditures. Following the successful efforts method of accounting (see Critical
Accounting PoliciesSuccessful efforts method of accounting) that we have
implemented in our oil and gas production and exploration activities, and
considering both the current development stage for Block 31 and the schedule of
future investments in line with the currently expected cash flow, during 2003
we charged to expense P$141 million in capitalized exploratory
wells investments in connection with Block 31 and we expect to charge to expense
additional amounts in 2004. We are currently evaluating several alternatives for Block 31, including
recruiting a new partner to accelerate investment execution and the potential
sale of part or all of our interest in our Block 31 asset. Decline in Historical Capital Expenditures As a result of the size and complex nature of the crisis that broke out in
Argentina late in 2001 and the few opportunities to access the capital markets,
we had to take a new approach to our growth strategy and consequently made
radical changes in our short- and medium-term outlook. In this new scenario,
throughout 2002, we reformulated the investment program dynamics, prioritizing
cash generation and the maintenance of adequate liquidity levels. This
resulted in more conservative expense and investment policies. In addition, pursuant to the agreements we subscribed to in 2002 in
connection with the refinancing of our financial debt, and as long as the
refinanced debt remains unpaid, we must comply with a number of restrictions
and commitments, including, among others, restrictions on capital expenditure
levels. Pursuant to these agreements, we are not permitted to make capital
expenditures exceeding U.S.$450 million in 2004, U.S.$425 million in 2005 and
U.S.$475 million in each of 2006 and 2007. These limits may be increased
through: (i) revenues from the sale of capital assets, (ii) 50% of excess cash
from the preceding fiscal year, (iii) cash provided by capital increases,
subordinated debt and the financing of investment projects, and (iv) 50% of
cash provided by new debt. Conversely, the aggregate amount of our dividends
will reduce the limit on capital expenditures. In 2002, our capital expenditures (which includes the sum of (a) the
acquisition of (i) property, plant and equipment, (ii) interest in companies
and (iii) oil and gas areas and (b) contributions and advances to
unconsolidated affiliates) totaled P$732 million (excluding capital
expenditures of companies under our joint control), significantly lower than
our capital expenditures in 2001, which were P$1,756 million, and 2000, which
were P$1,272 million. In the past, our significant investments have laid the
foundations for our operations expansion and growth. During 2002, we made
important divestments of non-core assets amounting to P$593 million, which
helped us to finance our capital expenditures during that year. The reduced pace of investments during 2002 changed our growth objectives
in the short-term, mainly affecting oil and gas future production volumes. In
addition, reduced investments will delay development of new exploitation areas
and related production. In 2003, the recovery of the Argentine economy triggered the recovery of
operating cash flow and liquidity levels. This allowed us to increase our
capital expenditures (excluding capital expenditures of companies under our
joint control) by P$46 million, to P$778 million. This level of capital
expenditures, however, remains low by historical standards. As long as the Argentine economic recovery continues, we expect to
gradually return to the level of capital investment from previous years,
subject to covenant restrictions in our outstanding debt. See Liquidity and 94




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Capital ResourcesDescription of Indebtedness. Our capital investment
strategy will focus on disciplined growth based on a solid financial
foundation, with priority given to profitable projects with faster returns. Divestment of Non-Core Assets The change in Petrobras Energía Participaciones controlling shareholder
represents a major milestone in our strategy and business focus. The agreements executed in connection with the transfer of control to
Petrobras granted Petrobras an option whereby, if, within 30 days after closing
of the sale, we did not consummate the sale of assets related to the farming,
forestry and mining businesses, Petrobras would be entitled but not obliged to
cause the seller to acquire such assets in the amount of U.S.$190 million. In line with the provisions of the agreements mentioned above, during 2002
we sold the asset portfolio associated with our mining, farming and forestry
businesses.  
    
    In July 2002, we sold to Anglogold our 46.25% indirect equity
interest in Cerro Vanguardia S.A. in addition to related assets.
The transaction price amounted to U.S.$90 million, and the operation
accounted for a P$123 million gain.
    
    In September 2002, we sold to Argentina Farmland Investors
LLC our 100% equity interest in Pecom Agropecuaria S.A.s capital
stock. The transaction amounted to U.S.$53 million, accounting for
a P$27 million gain.
    
    In December 2002, we sold our forestry business assets,
including a total area of about 169,000 hectares of forestry land
located in the Provinces of Misiones, Corrientes and Buenos Aires
and a sawmill with a 90,000 m3/year capacity. Considering the sale
price (U.S.$53 million), we recorded a P$153 million loss.  In addition, the following divestitures were made:  
    
    In April 2002, under an asset swap, we sold to IRHE
(Argentine Branch) and GENTISUR S.A. (a company wholly owned by
IRHE) our 50% interest in Pecom Agra with a value of U.S.$30
million, accounting for a P$81 million gain. In return, the parties
transferred to us a 0.75% interest in Puesto Hernández UTE, with a
value of U.S.$4.5 million, a 7.5% interest in Citelec, with a value
of U.S.$15 million, and a 9.187% interest in Hidroneuquén S.A, with
a value of U.S.$5.5 million.
    
    In October 2002, we sold to Sudacia S.A., a company
controlled by the Perez Companc Family, a 66.67% equity interest in
Conuar, including a 68% interest in Fabricación de Aleaciones
Especiales S.A., for U.S.$8 million. No gain or loss was recorded
for the sale. In 2003, we sold our interest in the Catriel Oeste and Faro Vírgenes
areas. These assets had low production levels, no significant potential and
high operating costs. In June 2003, we sold to Geodyne Energy Inc., Argentina Branch, a 50%
interest in the Faro Vírgenes area concession, accounting for a P$11 million
loss. Payments in connection with this transaction will be made during a ten
year term, in quarterly installments, with a value in U.S. dollars calculated
based on 8.8% of the total quarterly gas production from the Faro Vírgenes
area. We have the option of receiving directly such gas production. In August 2003, we sold to Central International Corporation, Argentine
Branch, an 85% interest in the Catriel Oeste area concession. Considering the
transfer price (U.S.$7 million), we recorded a P$28 million loss. These transactions have helped us to enhance the quality of our assets
portfolio and move forward with a strategy focused on becoming an integrated
energy company, and consolidate a business portfolio with a high potential for
growth and profitability. 95




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Management of Crude Oil Price Risk In line with the business integration goal, our risk management policy
focuses on measuring our net risk exposure and monitoring the risks that affect
our overall portfolio of assets. By focusing on our overall asset portfolio,
we are able to naturally hedge some of our risks. This has helped us to
integrate our businesses and grow more efficiently. Additionally, the
knowledge acquired from this process enables us to better allocate capital. We use hedging derivative instruments, such as futures, swaps, options and
other instruments, to mitigate risks related to results and cash flow
volatility as a result of fluctuations in the price of crude oil. Since 2002,
we have intensified the use of options, which provide increased flexibility by
protecting us from decreases in commodity prices, while allowing us to benefit
from future increases in prices. On January 1, 2003, Technical Resolutions Nos. 16, 17, 18, 19 and 20 of
the FACPCE became effective and introduced material changes in the guidelines
regarding the recognition, measurement and disclosure of derivatives and
hedging transactions. See Critical Accounting PoliciesChange in Accounting
Standards. These new regulations, whose principles are consistent with the
international accounting standards issued by the International Accounting
Standards Committee, or IASC, provide that financial derivatives are recorded
at their fair value and that changes in the accounting measurement of such
derivatives are recognized: (i) if the derivative financial instrument is
designated as an effective hedge, under Transitory differencesMeasurement of
derivative financial instruments designated as effective hedge and are
subsequently reclassified to income (loss) for the year or years in which the
hedged item affects such results, or (ii) if the financial derivative
instrument is not designated as an effective hedge, in the income statement
under Financial Income (Expense) and Holding Gains (losses). The new
regulations thus permit recognition of accounting measurements under clause (i)
above on a very restrictive basis, since a hedge is deemed effective if at its
inception and during its life, its changes offset between 80% and 125% of the
changes in the hedged item. Based on the information above and in view of the high crude oil prices
recorded during 2003, 2002 and 2001, we recognized: (i) for instruments that
qualify for hedge accounting, reduced sales in the amount of P$81 million in
2003, P$373 million in 2002 and P$341 million in 2001, and (ii) for instruments
that do not qualify for hedge accounting, financial losses of P$298 million in
2003, P$470 million in 2002 and a P$8 million gain in 2001. Political and Economic Situation in Venezuela As a result of the events that took place in 2002 and early in 2003,
Venezuela was plunged into an unprecedented recession that significantly
increased the level of inflation, unemployment and violence. On December 2, 2002, opposing political parties, together with the labor
union and business confederations, called a national civic strike, involving
the countrys main production areas, including PDVSA. This strike extended to
February 2, 2003, when it was partially lifted. Some of the political and
economic effects of the strike are listed below:  
    
    a significant reduction in oil production to below 1 million
barrels per day (from 3.2 million barrels per day prior to the
crisis), and a heavily weakened PDVSA, with more than 18,000
laid-off workers and a large portion of its facilities out of
operation. This prevented Venezuelas compliance with OPEC
production quotas;
    
    a significant reduction in the level of Venezuelas
international reserves to below U.S.$10 billion, which prevented the
country from meeting its minimum imports needs;
    
    high levels of unemployment, inflation and credit risk, with
an unemployment rate in excess of 20% and difficulties in meeting
domestic demand for fuel; and
    
    difficulties in supplying fuel to the domestic Venezuelan
market. 96




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The deteriorating conditions forced the Venezuelan government to adopt
several emergency measures, including: (i) closure of the foreign exchange
market and adoption of strict foreign exchange controls, (ii) implementation of
price control over the basic basket of goods, (iii) fuel imports and (iv)
greater governmental control over PDVSA. Notwithstanding these measures,
Venezuelas problems continued. By year end 2003, a foreign exchange market
parallel to the official market had developed, where the Bolivar reached rates
as high as Bs.3,000 per U.S.$1, compared to the official rate of Bs.1,600 per
U.S.$1. The crisis at PDVSA and the national strike that ended on February 2003,
affected operations at our oil fields located in the eastern region of
Venezuela. In the fields of Oritupano-Leona, Mata and Acema production
declined 40.2% in the first quarter of 2003 (to 30.4 thousand barrels per day),
compared with the first quarter of 2002. The situation improved after the
strike was lifted. Currently production from these fields is at full capacity. We designed and implemented a number of strategies to address the
challenges raised by the Venezuelan crisis. Accordingly, after the end of the
strike, five wells were drilled ahead of schedule at Oritupano-Leona. These
measures enabled us to lessen the adverse effects of the crisis. In 2003 and 2002, we registered a P$27 million and a P$42 million
allowance, respectively, for the book value of loans granted to our joint
venture partners in Venezuela. These allowances were recorded to reflect our
estimate of the recoverable value of these loans. Since the Venezuelan government, through PDVSA, closely monitors oil
production activities in Venezuela, operations in this country could be
affected if political and social riots, including strikes and other forms of
political protest, affect our operating capacity in Venezuela. In addition,
since Venezuela is an OPEC member country, we are subject to any decision
related to production cuts OPEC may adopt, as was the case in 2002. In
addition to these effects, Venezuelas complex crisis could have other
unforeseen effects that may have an adverse impact on our results of
operations. Association Agreement in San Carlos and Tinaco In October 2002, we subscribed to an association agreement with the oil
company Teikoku whereby we transferred 50% of our rights and obligations
involved in gas production in the San Carlos and Tinaco exploratory areas
located in Cojedes, Venezuela. The transfer of interest agreement (which is subject to approval by the
Venezuelan Ministry of Energy) provides for an initial cash payment of U.S.$1
million and a subsequent disbursement of U.S.$2 million for the financing of
the exploratory investments program in the Tinaco area in relation with
geological studies, 2-D seismic shooting and 2-D seismic evaluation and
interpretation. Furthermore, in the event a joint commercial development in
such area is agreed upon, we will receive a supplementary payment in the amount
of U.S.$3 million. In light of the transfer of 50% of our interests in the San
Carlos and Tinaco areas, as of December 31, 2002, we recorded a P$37 million
loss reflecting the write off of the exploration investments we made prior to
that date. During 2003, the political, economic and social conditions in Venezuela
prevented us from performing our minimum 2-D seismic work commitments in the
Tinaco area. We currently expect to complete this work in the first half of
2004. Depending on the seismic results, we may drill an exploratory well in
2005. Following the successful efforts method of accounting (see Critical
Accounting PoliciesSuccessful efforts method of accounting) that we have
implemented to record oil and gas exploration and production activities, as of
December 31, 2003, we charged to exploration expenses the remaining capitalized
investments in the San Carlos area in the amount of P$29 million. Environmental Matters Quality control, health and safety and environmental protection are
integral components of our business. See Item 4. Information About
UsBusiness OverviewEnvironmental. 97




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In 2003 we retained an international consulting company to conduct an
environmental audit of our operations in light of applicable laws, future
requirements and, in the absence of local applicable guidelines, international
standards. The final audit report ratified the high environmental standards
under which our operations are conducted and set forth an action plan to
enforce our Safety, Environmental and Occupational Health Policy. To execute
this action plan, over the next few years we will make investments of
approximately U.S.$23 million to improve, among other things, our prevention
systems and production facilities. In addition, we will implement several
corrective and remediation actions, for which a P$45 million loss was
recorded during 2003. Including this figure, in 2003 we recorded expenses of
P$58 million for environmental remediation activities. In 2002, our
environmental remediation loss expense was P$15 million. DISCUSSION OF RESULTS The following tables set out net sales, gross profit and exploitation
income for each of our business segments for the years ended December 31, 2003,
2002 and 2001, both excluding the proportional consolidation of the companies
under common control required by recent changes to Argentine general accounting
standards and including proportional consolidation. Net sales eliminations
relate to intersegment sales. Gross profit eliminations relate to adjustments
related to intersegment sales and costs associated with such sales. Substantially all of our intersegment sales are related to sales of oil
and gas to our refining, petrochemicals and electricity businesses. The
business segment year-to-year comparisons that follow the table do not exclude
intersegment sales. 98




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Without Proportional Consolidation For the year ended,December 31,2003
    
    2002
    
    2001(in millions of pesos)Net Sales(1)Oil and Gas Exploration and Production
    
    P$
    2,729
    
    
    P$
    2,806
    
    
    P$
    1,975Hydrocarbon Marketing and Transportation
    
    
    75
    
    
    
    16
    
    
    
    85Refining
    
    
    1,302
    
    
    
    1,008
    
    
    
    788Petrochemicals
    
    
    1,294
    
    
    
    1,254
    
    
    
    818Electricity
    
    
    244
    
    
    
    248
    
    
    
    364Other Investments and Eliminations
    
    
    (1,029
    )
    
    
    (745
    )
    
    
    (416
    )Total
    
    P$
    4,615
    
    
    P$
    4,587
    
    
    P$
    3,614Gross Profit(2)Oil and Gas Exploration and Production
    
    P$
    1,281
    
    
    P$
    1,206
    
    
    P$
    787Hydrocarbon Marketing and Transportation
    
    
    4
    
    
    
    5
    
    
    
    23Refining
    
    
    123
    
    
    
    64
    
    
    
    77Petrochemicals
    
    
    312
    
    
    
    362
    
    
    
    152Electricity
    
    
    94
    
    
    
    50
    
    
    
    112Other Investments and Eliminations
    
    
    (12
    )
    
    
    22
    
    
    
    4Total
    
    P$
    1,802
    
    
    P$
    1,709
    
    
    P$
    1,155Exploitation income(3)Oil and Gas Exploration and Production
    
    P$
    861
    
    
    P$
    902
    
    
    P$
    575Hydrocarbon Marketing and Transportation
    
    
    11
    
    
    
    16
    
    
    
    36Refining
    
    
    54
    
    
    
    
    
    
    
    5Petrochemicals
    
    
    185
    
    
    
    251
    
    
    
    59Electricity
    
    
    108
    
    
    
    57
    
    
    
    138Other Investments
    
    
    
    
    
    
    
    
    
    
    Corporate and Other Discontinued Investments
    
    
    (180
    )
    
    
    (135
    )
    
    
    (189
    )Total
    
    P$
    1,039
    
    
    P$
    1,091
    
    
    P$
    624
   (1)
    
    Royalties with respect to the oil and gas business are accounted for as a
cost or production and are not deducted in determining net sales.
Eliminations correspond to sales between our business units.(2)
    
    Net sales less cost of sales. Eliminations correspond to sales between
our business units and their associated costs.(3)
    
    As used in this annual report, exploitation income means gross profit
plus or minus administrative and selling expenses and other exploitation
income (expense), net. We present exploitation income as an indicator of
our income from operations. Other jurisdictions define operations income
to include certain expenses that we do not present as part of our
operating income. 99




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With Proportional Consolidation For the year ended,December 31,2003
    
    2002
    
    2001(in millions of pesos)Net Sales (1)Oil and Gas Exploration and Production
    
    P$
    2,729
    
    
    P$
    2,806
    
    
    P$
    1,975Hydrocarbon Marketing and Transportation
    
    
    521
    
    
    
    16
    
    
    
    695Refining
    
    
    1,302
    
    
    
    1,008
    
    
    
    788Petrochemicals
    
    
    1,294
    
    
    
    1,254
    
    
    
    818Electricity
    
    
    691
    
    
    
    766
    
    
    
    1,286Corporate and Other Discontinued
Investments and Eliminations
    
    
    (1,043
    )
    
    
    (744
    )
    
    
    (392
    )Total
    
    P$
    5,494
    
    
    P$
    5,106
    
    
    P$
    5,170Gross Profit(2)Oil and Gas Exploration and Production
    
    P$
    1,281
    
    
    P$
    1,206
    
    
    P$
    787Hydrocarbon Marketing and Transportation
    
    
    240
    
    
    
    5
    
    
    
    398Refining
    
    
    123
    
    
    
    64
    
    
    
    77Petrochemicals
    
    
    312
    
    
    
    362
    
    
    
    152Electricity
    
    
    168
    
    
    
    158
    
    
    
    380Corporate and Discontinued Other
Investments and Eliminations
    
    
    (16
    )
    
    
    27
    
    
    
    29Total
    
    P$
    2,108
    
    
    P$
    1,822
    
    
    P$
    1,823Exploitation Income(3)Oil and Gas Exploration and Production
    
    P$
    861
    
    
    P$
    902
    
    
    P$
    575Hydrocarbon Marketing and Transportation
    
    
    205
    
    
    
    16
    
    
    
    378Refining
    
    
    54
    
    
    
    
    
    
    
    5Petrochemicals
    
    
    185
    
    
    
    251
    
    
    
    59Electricity
    
    
    112
    
    
    
    89
    
    
    
    287Corporate and Other Discontinued
Investments and Eliminations
    
    
    (185
    )
    
    
    (131
    )
    
    
    (164
    )Total
    
    P$
    1,232
    
    
    P$
    1,127
    
    
    P$
    1,140
   (1)
    
    Royalties with respect to the oil and gas business are accounted for as a
cost or production and are not deducted in determining net sales.
Elimination corresponds to sales between our business units.(2)
    
    Net sales less cost of sales. Eliminations correspond to sales between
our business units and their associated costs.(3)
    
    As used in this annual report, exploitation income means gross profit
plus or minus administrative and selling expenses and other exploitation
income (expense), net. We present exploitation income as an indicator of
our income from operations. Other jurisdictions define operations income
to include certain expenses that we do not present as part of our
operating income. 100




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Year Ended December 31, 2003 Compared to Year Ended December 31, 2002 Net income: In 2003, we reported net income of P$381 million, compared to
a net loss of P$1,579 million in 2002. This shift principally reflects
improvements in Argentinas economic conditions during 2003, including an 8.7%
increase in GDP, as compared to the 11% contraction in 2002, the impact of the
appreciation of the peso against the U.S. dollar on the income from our utility
affiliates and a reduction in interest expense. Notwithstanding this
improvement in the Argentine economy, significant obstacles to a sustained
recovery remain, including the refinancing of Argentinas sovereign debt and
the renegotiation of utility contracts. These ongoing obstacles could
undermine the recovery of our operations. Net sales: In 2003, our net sales increased by P$388 million or 7.6% to
P$5,494 million, from P$5,106 million in 2002. Our net sales for 2003 reflect
P$432 million and P$447 million corresponding to our share of the net sales of
CIESA and Distrilec, respectively, for that year (net of P$4 million in
intercompany sales). Our net sales for 2002 reflect P$519 million
corresponding to our share of Distrilecs net sales for that year. In 2003, without proportional consolidation, our net sales increased P$28
million or 0.6% to P$4,615 million from P$4,587 million in 2002, due to an
increase in sales from each of our Refining, Hydrocarbon Marketing and
Transportation, and Petrochemicals business segments. Refining registered the
highest increase in net sales to P$1,302 million from P$1,008 million, boosted
by a 24.4% increase in sales volumes and, to a lesser extent, higher prices.
Sales from our Hydrocarbon Marketing and Transportation segment grew by P$59
million, while sales from our Petrochemicals segment grew by P$40 million.
These increases were partly offset by a 2.7% reduction in sales from our Oil
and Gas Exploration and Production business, to P$2,729 million (including
intercompany sales in the amount of P$944 million) from P$2,806 million in 2002
(including intercompany sales in the amount of P$773 million). This reduction
resulted from a 7.7% drop in sales volumes of oil equivalent, which was partly
offset by a 5.8% increase in sales prices. Gross Profit: In 2003, our gross profit increased by P$286 million or
15.7% to P$2,108 million, from P$1,822 million in 2002. Our gross profit for
2003 reflects P$232 million and P$74 million corresponding to our share of the
gross profits of CIESA and Distrilec, respectively, for that year. Our gross
profit for 2002 reflects P$113 million corresponding to our share of
Distrilecs gross profit for that year. In 2003, without proportional consolidation, our gross profit increased by
P$93 million or 5.4% to P$1,802 million, from P$1,709 million in 2002,
primarily due to higher margins for crude oil, refined products and generation
activity. Reflecting these higher margins, our gross profit from Oil and Gas
Exploration and Production increased by P$75 million, our gross profit from
Refining activity increased by P$59 million and our gross profit from our
Electricity business increased by P$44 million. In contrast, the gross profit
from our Petrochemicals business declined by P$50 million, commensurate with
the decline experienced in the industry internationally. Administrative and selling expenses: In 2003, our administrative and
selling expenses decreased by P$50 million or 8.2% to P$559 million, from P$609
million in 2002. Our administrative and selling expenses for 2003 reflect P$30
million and P$65 million corresponding to our share of the administrative and
selling expenses of CIESA and Distrilec, respectively, for that year. Our
administrative and selling expenses for 2002 reflect P$77 million corresponding
to our share of Distrilecs administrative and selling expenses for that year. In 2003, without proportional consolidation, our administrative and
selling expenses declined by P$68 million or 12.8% to P$464 million, from P$532
million in 2002. This drop is primarily due to the impact of the peso
appreciation on expenses incurred outside Argentina. Exploration expenses: In 2003, exploration expenses increased P$138
million or 237.9% to P$196 million, from P$58 million in 2002, mainly as a
result of the charge to income of P$141 million in capitalized exploratory
wells investments in Block 31. See Oil and Gas Exploration and Production. Other exploitation income (expense), net: In 2003, our other operating
expenses increased on a net basis by P$93 million or 332.1% to P$121 million,
from P$28 million in 2002. Our net other exploitation expenses for 2003 101




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reflect P$12 million and P$5 million corresponding to our share of the net
other exploitation expenses of CIESA and Distrilec, respectively, for that
year. Distrilec (which was subject to proportional consolidation in 2002) did
not register, on a net basis, any other exploitation expenses in 2002. In 2003, without proportional consolidation, our other exploitation
expenses increased on a net basis by P$76 or 271.4%, to P$104 million from P$28
million in 2002. This increase is mainly attributable to environmental
remediation expenses (P$58 million in 2003) and other allowances (P$32 million
in 2003). Exploitation income: In 2003, our exploitation income increased by P$105
million or 9.31% to P$1,232 million, from P$1,127 million in 2002. Our
exploitation income for 2003 reflects P$194 million and P$4 million
corresponding to our share of the exploitation income of CIESA and Distrilec,
respectively, for that year (net of P$4 million in intercompany operations).
Our exploitation income for 2002 reflects P$36 million corresponding to our
share of Distrilecs exploitation income for that year (net of intercompany
operations). In 2003, without proportional consolidation, our exploitation income
declined P$53 million or 4.9% to P$1,038 million, from P$1,091 million in 2002.
This decline resulted primarily from the significant increase in exploration
expenses and environmental remediation expenses and contingencies. Equity in earnings of affiliates: In 2003, our equity interest in the
earnings of affiliates accounted for a P$163 million gain, compared to a P$638
million loss in 2002, mainly as a result of improved earnings from Citelec, our
affiliate utility companies. In 2003, but not in 2002 CIESAs results were
consolidated into our financial statements pursuant to the proportional
consolidation method. In 2002, CIESA reported a significant loss. See Overview. Without applying proportional consolidation, our equity in earnings of
affiliates would have been a P$373 million gain in 2003, compared to a P$647
million loss in 2002, which includes a P$59 million gain from Cerro Vanguardia,
which was sold in 2002. As a result of the appreciation of the peso and
reduction of the inflation rate in 2003, our equity share in the earnings of
our affiliate utility companies (CIESA, TGS, Distrilec and Citelec) accounted
for a P$316 million gain in 2003, compared to a P$732 million loss in 2002.
The increased equity gains also resulted from increased earnings of P$19
million, P$26 million and P$13 million at Refinor, Cuyo and Inversora Mata
S.A., respectively. These increased earnings were partly offset by P$17
million and P$9 million reductions in the earnings of Empresa Boliviana de
Refinación and Oldelval, respectively. For a discussion of our equity in the earnings of companies over which we
exercise joint control in 2003 and the factors that affected these companies
results during that year, see Equity in Earnings of Affiliates and Companies
under Joint Control. Financial income (expense) and holding gains (losses): In 2003, our
financial expenses and holding losses decreased by P$1,410 million or 77.2% to
P$417 million, from P$1,827 million in 2002. Our financial expenses and
holding losses for 2003 reflect P$124 million corresponding to our share of
CIESAs financial and holding gains for 2003, and P$28 million corresponding to
our share of Distrilecs financial and holding gains for 2003. Our financial
expenses and holding losses for 2002 reflect P$168 million corresponding to our
share of Distrilecs financial expenses and holding losses for that year. In 2003, without proportional consolidation, our financial expenses and
holding losses declined to P$569 million from P$1,659 in 2002. This reduction
is mainly attributable to the following factors:  
    
    Gains from foreign exchange and exposure to inflation of
P$136 million in 2003 on our net borrowing position, as compared to
a loss of P$370 million in 2002, principally reflect the effects of
the peso appreciation and inflation on our net borrowing position.
    
    A P$349 million drop in net interest expense, to P$423
million in 2003 from P$772 million in 2002, resulting from the
appreciation of the peso and an 8% reduction in the average amount
of our dollar-denominated indebtedness. 102




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
    
    A 37.4% reduction in losses attributable to derivative
instruments that do not qualify for hedge accounting, to P$294
million in 2003 from P$470 million in 2002. In nominal terms, the
loss for 2003 was actually higher than the loss in 2002, mainly due
to the increase in the future curve of reference crude oil prices.
In constant currency, however, the loss for 2002 is higher than for
2003 due to the effects of the adjustment for inflation. This
increase was partially offset by the peso appreciation during 2003. Other expenses, net: In 2003, our other expenses increased on a net basis
by P$234 million or 125% to P$421 million, from P$187 million in 2002. Our net
other expenses for 2003 reflect P$1 million and P$13 million corresponding to
our share of the net other expenses of CIESA and Distrilec, respectively, for
that year. Our net other expenses for 2002 reflect P$9 million corresponding
to our share of Distrilecs net other expenses for that year. In 2003, without proportional consolidation, our other expenses, net
increased by P$229 million or 128.6% to P$407 million, from P$178 million in
2002. These increased expenses reflected:  
    
    an impairment allowance for our operations in Ecuador (See
Factors Affecting Our Consolidated Results of OperationOperations
in Ecuador) of P$309 million;
    
    a P$39 million loss attributable to the sale of oil and gas
areas;
    
    a P$37 million impairment charge for oil production areas
(see Factors Affecting Our Consolidated Results of
OperationsAssociation Agreement in San Carlos and Tinaco); and
    
    a P$27 million allowance for the book value of loans granted to joint-venture partners in Venezuela.These expenses for 2003 compare to the following other expenses for 2002:
    
    a P$63 million allowance for operations in Ecuador;
    
    a P$44 million impairment charge for gas production areas;
    
    a P$37 million loss attributable to the assignment of a 50% interest in San Carlos area;
    
    a P$42 million allowance for the book value of loans granted to joint venture partners in Venezuela;
    
    a P$17 million charge for the accelerated amortization of financial debt issuance costs;
    
    a P$10 million impairment charge for an interest in Hidroneuquén; and
    
    P$78 million income from divestment of non-core assets. Income tax: In 2003, our income tax charge decreased by P$64 million or
78.1% to P$18 million, from P$82 million in 2002. Our income tax charge for
2003 reflects a P$58 million gain corresponding to our share of CIESAs income
tax for that year, and a P$29 million loss corresponding to our share of
Distrilecs income tax for that year. Our income tax provision for 2002
reflects a P$127 million gain corresponding to our share of Distrilecs income
tax for that year. In 2003, without proportional consolidation, our income tax provision
declined P$162 million or 77.5% to P$47 million, from P$209 million in 2002.
This decline reflects the inclusion of the following items in 2002: (i) an
allowance for tax losses and a minimum presumed income tax of P$134 million and
P$19 million, respectively, in line with the uncertain economic context
prevailing in Argentina, and (ii) a P$19 million provision attributable to
Conuar, an asset we sold in 2002. 103




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Oil and Gas Exploration and Production Exploitation income: Exploitation income for this segment decreased 4.5%
in 2003, to P$861 million from P$902 million in 2002. This drop was due
primarily to a significant increase in exploration expenses and a decline in
sales volumes, which were partially offset by a rise in sales prices resulting
from changes in our price hedging strategies and a 19% increase in the WTI. Net sales: Net sales for 2003 declined P$77 million or 2.7% to P$2,729
million (including intercompany sales in the amount of P$944 million), from
P$2,806 million in 2002 (including intercompany sales in the amount of P$773
million). This drop is attributable to a 7.7% decline in sales volumes of oil
equivalent, which was partially offset by a 5.8% increase in sales prices. Combined oil and gas sales volumes declined 7.7% in 2003 to 157.9 thousand
barrels of oil equivalent per day, from 171.1 thousand barrels of oil
equivalent per day in 2002. Oil sales volumes decreased 5% in 2003 to 111.2
thousand barrels per day, from 117.1 thousand barrels per day in 2002, while
gas sales volumes declined 13.5% to 280.0 million cubic feet per day, from
323.6 million cubic feet per day in 2002. This significant drop in sales
volumes is primarily attributable to the decline in the level of activity of
our operations in Venezuela, which was affected by the oil strike that took
place at the beginning of 2003, and to the restrictive investment policy
implemented by us in 2002 in light of the Argentine crisis. While this policy
protected our operating cash flow in 2002, it delayed the development of
hydrocarbon projects. The decline of our operation in Venezuela, however, was
offset by the start of commercial operations in Ecuador, with production
reaching a total of 3.9 thousand barrels per day. In addition, gas sales
volumes declined due to price restrictions in the Argentine market, which
discouraged production. During 2003, the average crude oil sales price per barrel, including the
effects of hedging transactions and taxes on exports (as discussed below),
increased 4.8% to P$61.2, from P$58.4 in 2002. This increase reflected a 19%
increase in the average WTI to U.S.$31.1 per barrel, and changes in our hedging
policy. This increase was partially offset by the effect of the peso
appreciation against the U.S. dollar during 2003, which had a negative impact
on dollar-denominated flows from foreign operations and exports. In 2003, our crude oil price hedging policy accounted for P$85 million in
reduced net sales, compared with P$373 million in 2002. These reduced losses
mainly reflect a change in our hedging strategy. During 2003, we relied on
option contracts that allowed us more flexibility to benefit from price
increases. Conversely, in 2002 hedging instruments consisted primarily of swap
agreements, with fixed sales prices. In 2003, Argentine taxes on exports resulted in a reduction in net sales
of P$60 million, compared to P$84 million in 2002, reflecting a 50% drop in
export volumes. Net Sales in Argentina: In 2003, overall sales in Argentina decreased by
P$69 million or 4.3% to P$1,538 million, from P$1,607 million in 2002, due to a
10.9% decrease in combined oil and gas daily sales volumes, to 90.4 thousand
barrels of oil equivalent from 101.5 thousand barrels of oil equivalent in
2002. Crude oil sales in Argentine declined P$22 million or 1.5% to P$1,401
million, from P$1,423 million in 2002. This reduction in crude oil sales is
mainly attributable to a 7.1% decline in sales volumes to 55.0 thousand barrels
per day, which was partially offset by a 6.1% increase in average sales prices.
Gas sales in Argentina dropped by P$46 million or 25.1% to P$137 million, from
P$183 million in 2002. This drop in gas sales resulted from the combined
effect of reduced sales volumes and reduced prices. Daily gas sales volumes
declined 16.2% to 212.8 million cubic feet, from 253.9 million cubic feet in
2002, while gas sales price dropped 11.1% to P$1.76 per thousand cubic feet,
from P$1.98 per thousand cubic feet in 2002. The Public Emergency Law has
prevented nominal sales prices from changing significantly. In 2003, the volume of intercompany sales in Argentina, particularly to
the Refining business, increased 21.6% to 31.7 thousand barrels per day. 104




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Net Sales Outside of Argentina: In 2003, combined oil and gas sales
outside of Argentina decreased 0.7% to P$1,191 million, from P$1,199 million in
2002. Oil and gas total sales volumes declined to 67.4 thousand barrels of oil
equivalent per day or 3.0% with respect to 2002. The average sales price for
oil per barrel rose to P$52.7 or 3.9% from P$50.7 in 2002, mainly due to the
rise in the international reference price and the change in our hedging policy
(as discussed above). Below is an overview of 2003 sales figures for each country in which we
have oil and gas operations: Venezuela: Oil and gas sales decreased P$106 million or 15.1% to
P$594 million, from P$700 million in 2002, due to the following factors: 
    
    the average price of oil per barrel decreased
3.6% to P$40.4, from P$41.9 in 2002. This decline was
attributable to the effect of the appreciation of the peso,
which was partially offset by the change in the hedging policy
(as discussed above) and the increase in the WTI; and
    
    daily sales volume of oil equivalent decreased
12.5% to 42.8 thousand barrels of oil equivalent, from 48.9
thousand barrels of oil equivalent in 2002, primarily as a
result of the oil strike that took place at the beginning of
2003, and the natural field decline resulting from our
restrictive investment policy in 2002.
 Bolivia: Oil and gas sales decreased P$4 million or 3.6% to P$108
million, from P$112 million in 2002, due primarily to a 7.4% reduction in
the sale price of gas to P$5.24 per thousand cubic feet, from P$5.66 per
thousand cubic feet in 2002. This decline in the gas sales price was
partially offset by the combined oil and gas daily sales volumes, which
increased 5.5% to 7.7 thousand barrels of oil equivalent, from 7.3
thousand barrels of oil equivalent in 2002. Peru: Oil and gas sales increased 4.2% to P$374 million, from P$359
million in 2002, due to the following factors: 
    
    sales price increased 1.3% to P$78.5 per barrel,
from P$77.5 per barrel in 2002, as a result of the change in
our hedging policy (as discussed above) and the increase in
international prices, which were partially offset by peso
appreciation; and
    
    oil and gas daily deliveries increased 2.4% to
13.0 thousand barrels of oil equivalent per day, from 12.7
thousand barrels of oil equivalent per day in 2002, as a
consequence of improved well productivity resulting from
workover tasks.
 Ecuador: Oil sales increased 310.7% to P$115 million, from P$28
million in 2002, due to the approval of the development plan for Block
18, which was obtained in the fourth quarter of 2002. After obtaining
this approval, we were able to start drilling activities, particularly at
the Palo Azul field, where we currently operate five wells which yielded
a production of 17 thousand barrels per day in December (before deduction
on account of the Ecuadorian governments interest and before deducting
royalties). Daily crude oil sales volumes (net of the Ecuadorian
governments interest), increased to 3.9 thousand barrels per day, at a
price of P$79.2 per barrel. Gross profit: In 2003, gross profit for the Oil and Gas Exploration and
Production segment increased 6.2% to P$1,281 million, from P$1,206 million in
2002. The gross margin on sales rose to 46.9% from 43% in 2002. This increase
in margins is primarily attributable to the rise in sale prices. Administrative and selling expenses: In 2003, administrative and selling
expenses for this segment totaled P$178 million, compared to P$224 million in
2002. This drop is attributable to the appreciation of the peso in 2003, which
reduced the peso equivalent of expenses incurred abroad. 105




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Exploration expenses: In 2003, exploration expenses increased by P$138
million or 237.9% to P$196 million, from P$58 million in 2002. Exploration
expenses during 2003 reflected the charge to income of P$141 million
exploration investments in Block 31 (in Ecuador), and P$30 million exploration
investments in the San Carlos area (in Venezuela). In addition, expenses were
recorded for non-producing exploration wells in the Santa Cruz II Oeste area in
Argentina and Lote XVI in Peru and the investment in seismic testing related to
such wells. In 2002, the Chontayacu well in Block 18 (Ecuador) was drilled and did not
prove to be successful. In addition, 238 km of 2-D seismic were shot in Block
31. In Argentina and Peru, expenses in connection with the Chiripá well in the
Santa Cruz II Oeste area and the Mashansha well in Lote 35, respectively, were
charged to income. Other exploitation income (loss), net: In 2003, other exploitation
expenses for this segment increased on a net basis by P$24 million or 109.1% to
P$46 million, from P$22 million in 2002. This increase was primarily a result
of environmental remediation expenses in the amount of P$26 million, and other
allowances in the amount of P$32 million. These effects are offset by the
favorable settlement of certain commercial claims in Venezuela. Hydrocarbon Marketing and Transportation Our results for this segment in 2003 reflect the proportional
consolidation of CIESA. In 2002, CIESAs results were not proportionally
consolidated. See Overview. Exploitation income: In 2003, our exploitation income for this segment
increased by P$189 million or 1181.3% to P$205 million, from P$16 million in
2002. Our exploitation income for this segment in 2003 reflects P$194 million
corresponding to our share of CIESAs exploitation income for that year. In 2003, without proportional consolidation, our exploitation income for
this segment decreased 31.3% to P$11 million, from P$16 million in 2002. Net Sales: Our operations in this segment include oil, gas and LPG
brokerage services, with significantly different margins subject to the
specific characteristics of each operation. In 2003, our net sales for this segment increased by P$505 million or
3156.3% to P$521 million, from P$16 million in 2002. Our net sales for this
segment in 2003 reflect P$446 million corresponding to our share of CIESAs net
sales for that year. In 2003, without proportional consolidation, our aggregate net sales
significantly increased, to P$75 million from P$16 million in 2002, principally
as a result of increased volume in our oil brokerage operations. Gross profit: In 2003, our gross profit for this segment increased by
P$235 million to P$240 million, from P$5 million in 2002. Our gross profit for
this segment in 2003 reflects P$236 million corresponding to our share of
CIESAs gross profit for that year. In 2003, without proportional consolidation, our gross profit decreased to
P$4 million from P$5 million in 2002, as a result of a reduction in margins in
the brokerage business. Other exploitation income, net: In 2003, we registered other net
exploitation expenses for this segment in the amount of P$1 million, compared
to other net exploitation income in the amount of P$13 million in 2002. The
other net exploitation expenses for this segment in 2003 reflect P$12 million
corresponding to our share of the other net exploitation expense of CIESA for
that year. In 2003, excluding proportional consolidation, we registered other net

exploitation income in the amount of P$11 million, a 15.4% decrease from the
P$13 million in other net exploitation that we registered in 2002. In 2003, the income from the advisory services we provided to TGSs
technical operator was P$12 million, as compared to P$13 million in 2002. 106




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Refining Exploitation income: In 2003, exploitation income for this segment totaled
P$54 million, while no significant results were recorded in this segment in
2002. The improvement resulted from a significant increase in sales volumes
and margins. Net sales: In 2003, net sales of refined products increased P$294 million
or 29.2% to P$1,302 million, from P$1,008 million, due to a 24.4% increase in
sales volumes and higher prices, particularly in the domestic market. Below we
highlight certain significant trends in sale prices and volumes for refined
products in 2003:  
    
    In an effort to optimize our margins in this segment, we
adopted changes in the mix of the refined products we sell and of
our distribution channels. Domestic sales of refined products
increased 41%, mainly due to increased diesel oil sales to other oil
companies operating in Argentina. Exports of refined products, on
the other hand, dropped 2%.
    
    In 2003, average sales prices of diesel oil, gasoline,
aromatics and reformer plant by-products increased 7%, 16%, 14% and
9%, respectively. Taxes on exports of refined products imposed by
the Argentine government starting on April 2002 totaled P$9 million
in 2003 and P$14 million in 2002, decreasing revenues.
    
    Crude oil volumes processed in 2003 averaged 32.6 thousand
barrels per day, a 19.9% increase from 2002. During 2003, in order
to maximize our overall results in light of the applicable tax
regime, integration of our refining and exploration and production
operations increased. Accordingly, we prioritized the refining of
crude oil over crude oil exports given the 20% export tax on crude
oil imposed in Argentina in March 2002.
    
    Sales volumes of diesel oil grew 41.9% in 2003, to 882.6
thousand cubic meters, reflecting a 62.3% increase in sales volumes
for diesel oil in the domestic market. This increase resulted
primarily from increased sales to oil companies operating in
Argentina, particularly EG3 (a company controlled by Petrobras) and,
to a lesser extent, a 4.2% recovery of the domestic demand for this
product, which was driven by demand from the farming sector. The
increase in domestic sales of diesel oil in 2003 was partly offset
by an 18.3% drop in exports to bordering countries, particularly to
Paraguay.
    
    Total gasoline sales volumes declined 2.9% in 2003, to 119.2
thousand cubic meters, reflecting a 4.6% drop in our sales volumes
in Argentina. This decline in domestic gasoline sales resulted
primarily from a 10% reduction in total domestic demand for
gasoline, due to increased use of CNG as a substitute fuel.
    
    Sales volumes of reformer plant by-products grew 21.8% in
2003, to 79 thousand tons, as a result of a 14% increase in domestic
sales and a 54% rise in exports.
    
    Sales volumes for heavy distillates grew 12% in 2003, to 438
thousand tons, due primarily to a 63% increase in domestic sales as
a result of increased demand for fuel oil and the increase in crude
oil volumes processed. The increase in domestic sales was partially
offset by a 1% drop in export volumes.
    
    Asphalt sales volumes grew 102.4% in 2003, to 86 thousand
tons, as a result of our active trade policy, and a 110% increase in
domestic sales, due to a rise in road construction and specific
public works (such as the construction of the Rosario-Victoria
Bridge). In addition, 2003 was a record year for asphalt exports,
with exports to Bolivia and Paraguay increased 90% compared to 2002,
reflecting increased demand in these countries.
    
    Sales volumes of paraffins increased 9.4% in 2003, to 151
thousand tons, due to a 32% rise in domestic sales, resulting from
increased demand. This increase was offset by a 4% drop in exports,
particularly to the United States and countries bordering Argentina. 107




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
    
    Sales volumes of aromatic products decreased 16.1%, to 56
thousand tons, as a result of a 27.5% drop in domestic sales, which
was offset by a 41.6% increase in exports, particularly to countries
bordering Argentina. Gross profit: In 2003, gross profit for this segment increased P$59
million or 92.2% to P$123 million, from P$64 million in 2002, due to higher
sales volumes and improved gross margins. The gross margin on sales of refined
products increased to 9.5% from 6.3%. This increase is attributable to a 4.5%
rise in average sales prices, that was only partially offset by a 2.3% increase
in the cost of crude (from 78.9 P$  per barrel in 2002 to 80.7 P$  per barrel in
2003). While the average WTI increased by 19% in 2003, the appreciation of the
peso during this year helped to contain the rise in our crude acquisition costs
(which are dollar-based). Administrative and selling expenses: In 2003, administrative and selling
expenses for the Refining segment increased P$9 million or 18.8% to P$57
million, from P$48 million. This increase resulted primarily from increased
commercial expenses associated with the expansion of our gas station network. Other exploitation expenses, net: In 2003, other exploitation expenses for
the refining segment decreased on a net basis to P$12 million, from P$16
million in 2002. Idle-facility costs accounted for a P$6 million loss in 2003,
compared to a P$10 million loss in 2002. In addition, P$8 million
environmental remediation expenses were recorded for this segment in 2003. Petrochemicals International and Regional Overview: In 2003, the styrenics business was
marked by a strong increase in the international prices for its primary raw
materials. In line with the upward trend of oil prices, prices for benzene and
ethylene increased approximately 27% and 25%, respectively, in 2003.
International prices of styrene and polystyrene increased approximately 15%.
As a result of the increase in the costs of raw materials, spreads (i.e., the
difference between the sales price and the cost of raw materials) for styrenics
decreased in 2003, particularly the spread for styrene, which decreased 21%
and, to a lesser extent, the spread for polystyrene, which decreased 4%. The demand for styrenics in Argentina increased considerably in 2003, due
to the strong recovery in the countrys economic activity. The demand for
styrene increased 38%, for polysterene 14% and for rubber 19%. In Brazil, the
demand for styrene rose 8% in 2003, while the demand for polystyrene dropped
10%. The Mercosur region and Chile continued to record a shortage of styrene.
The excess supply of polystyrene, on the other hand, continued to increase, due
to increased production and lower demand for this product in the Brazilian
market. In the fertilizers business, international prices for urea significantly
increased in 2003 to an average of U.S.$139 per ton, from an average of U.S.$94
per ton in 2002. This increase resulted primarily from increased demand in the
southeastern region of Asia, as well as a lower global supply resulting from
the high cost of natural gas in the major manufacturing centers of urea around
the world. Our fertilizers business also benefited from improved conditions in the
Argentine farming sector, resulting from favorable international prices for
grains, significant growth in sown areas, record soybean harvest and an
increased use of nutrient mixes. Droughts in the Provinces of Córdoba, La
Pampa and Buenos Aires did not affect this general positive trend. Total
demand for fertilizers in Argentina recorded a 31% increase in 2003. Exploitation income: In 2003, exploitation income for the Petrochemicals
segment decreased P$66 million or 26.3% to P$185 million, from P$251 million in
2002, mainly as a result of the decrease in the spreads. Net sales: In 2003, net sales for the Petrochemical segment increased
P$40 million or 3.2% to P$1,294 million, from P$1,254 million in 2002, mainly
as a result of increased sales volumes in Argentina. We highlight below
certain sales figures and trends for this segment: 108




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
    
    StyrenicsArgentina: In 2003, total sales of styrenics from
our Argentine operations increased P$34 million or 7.5% to P$485
million (including exports to Innova in the amount of P$5 million),
from P$451 million in 2002 (including exports to Innova in the
amount of P$26 million). In 2003, total sales volumes for styrenics
increased to 104 thousand tons from 84 thousand tons in 2002.
Average sales prices for styrenics did not register significant
changes compared to 2002, as the alignment with international
reference prices was offset by the appreciation of the peso.  
    
    Sales volumes for styrene increased approximately 38%
in 2003, due to increased domestic demand for this products and
export growth. The greater level of exports is attributable to
increased shipments to Chile reflecting the consolidation of our
presence in this countrys styrene market.
    
    Sales volumes for polystyrene decreased approximately
11.7% in 2003, due to a 43% drop in exports resulting from lower
shipments to Brazil and Europe. These lower shipments in part
reflect our efforts to increase exports of styrene to certain
regional markets from which we can extract greater profit
margins. A 6% increase in sales volume of polystyrene to the
domestic Argentine market, resulting from the countrys economic
recovery, partly offset the decline in the volume of exports of
this product.
    
    Sales volumes for Bioriented Polystyrene, or BOPS,
increased approximately 56% in 2003, due primarily to a 74%
increase in exports, which resulted from increased shipments to
the U.S.A. and Europe. In addition, BOPS sales volumes to the
domestic Argentine market increased 11% due to the countrys
economic recovery.
    
    Sales volumes for rubber increased approximately 11%,
as a result of the recovery of the Argentine economy and an
increase in our market share.  
    
    StyrenicsBrazil: In 2003, sales of styrenics from Innova
(our Brazilian petrochemical subsidiary) decreased P$59 million or
11% to P$502 million, from P$561 million in 2002, as a result of the
decline in sales volumes and prices. Total sales volumes of
styrenics from Innova declined 7% in 2003, reflecting a 3.9%
reduction in sales volumes to the Brazilian domestic market (from
176 thousand tons in 2002 to 169 thousand tons in 2003). This
reduction in domestic sales volumes was mainly the result of a 13%
decline in local sales of polystyrene, due to a drop in demand for
this product in Brazil. Local sales of styrene, on the other hand,
did not reflect significant changes from the levels recorded in
2002. Export volumes of styrenics from our Brazilian operation
declined 17% in 2003, as the decline in international margins for
polystyrene limited the opportunities to export polystyrene to
markets outside of the region. The average sales price of styrenics
from our Brazilian operations dropped 4%, as the appreciation of the
peso offset the increase in the international prices of polymers.
    
    Fertilizers: In 2003, sales of fertilizer increased 16.4% to
P$312 million, from P$268 million in 2002, due primarily to a 32%
increase in sales volumes that was caused by increased demand for
nutrient mixes in Argentina. A 38% increase in sales of liquid
fertilizers in 2003 also improved overall fertilizer sales. This
improvement in sales of liquid fertilizers reflected the
consolidation of our leading position in the Argentine fertilizer
market, particularly in the liquid fertilizers segment. Average
sales prices for fertilizers dropped 11% in 2003, due to the effects
of the peso appreciation that offset the increase in
dollar-denominated prices, and the strong growth in sales of liquid
fertilizer, which have lower unit prices than solid fertilizers. Gross profit: In 2003, gross profit for the Petrochemicals segment
decreased P$50 million or 13.8% to P$312 million, from P$362 million in 2002.
Gross margin for this segment decreased to 24.1% in 2003 from 28.9% in 2002,
due to an increase in the international prices for raw materials. We highlight
below certain significant trends in this segment:  
    
    StyrenicsArgentina: In 2003, gross profit for styrenics from
our Argentine operations increased 2.4% to P$129 million, from $126
million in 2002, reflecting increased volumes. Gross margin on
sales in 109




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these products, on the other hand, declined to 26.6% in 2003 from
27.8% in 2002, mainly as a result of the increased cost of raw
materials.
    
    StyrenicsBrazil: In 2003, gross profit for styrenics from
our Brazilian operations declined 13.6% to P$89 million, from P$103
million in 2002. Gross margin for these products declined to 17.8%
in 2003 from 18.4% in 2002, mainly as a result of the increased cost
of raw materials.
    
    Fertilizers: In 2003, gross profit for our fertilizers
business declined 29.3% to P$94 million, from P$133 million in 2002.
Gross margins for fertilizers declined to 30.1% in 2003 from 49.6%
in 2002, mainly due to a reduction in the average sales price of
fertilizer products as explained above and a change in the product
mix. Our margins in this segment were adversely affected by the
increase in resales by us of fertilizer volumes with a unit cost
higher than that of our own fertilizer products. Administrative and selling expenses: In 2003, administrative and selling
expenses for the Petrochemical segment declined P$12 million or 10% to P$110
million, from P$122 million in 2002, mainly as a result of the impact of the
significant appreciation of the peso on our costs incurred in Brazil. Other exploitation expenses, net: In 2003, other exploitation expenses for
this segment, accounted on a net basis for a P$17 million loss, attributable to
future environmental remediation expenses. This compared to a P$11 million
gain in 2002, attributable to the collection of insurance compensation for a
loss occurred at Innovas ethylbenzene plant and certain tax credits from our
operations in Brazil. Electricity Our results for this segment in 2003 and 2002 reflect the proportional
consolidation of Distrilec. See Overview. Exploitation income: In 2003, our exploitation income for this segment
increased by P$23 million or 25.9% to P$112 million, from P$89 million in 2002.
Our exploitation income for this segment in 2003 and 2002 reflects P$4 million
and P$32 million, respectively, corresponding to our share of Distrilecs
exploitation income for these years. In 2003, without proportional consolidation, our exploitation income for
this segment increased P$51 million or 89.5% to P$108 million, from P$57
million in 2002 (which includes P$10 million from the exploitation income of
Conuar Fae, a company that was divested in the fourth quarter of 2002), due
primarily to an increase in the price of electricity and lower production
costs. Net sales: In 2003, our net sales for this segment decreased by P$75
million or 9.8% to P$691 million, from P$766 million in 2002. Our net sales
for this segment in 2003 and 2002 reflect P$447 million and P$518 million,
respectively, corresponding to our share of Distrilecs net sales for these
years. In 2003, without proportional consolidation, our net sales for this
segment increased P$38 million or 18.4% to P$244 million, from P$206 million in
2002 (excluding P$42 million in net sales of Conuar/Fae in 2002, which we sold
in that year). Net sales from generation: In 2003, net sales for our electricity
generation business increased P$39 million or 19.9% to P$235 million, from
P$196 million in 2002. This increase resulted from a 20.4% increase in average
sales prices, which is attributable primarily to the following factors:  
    
    as a result of changes in the regulatory framework, payments
of additional compensation from the Argentine Stabilization Fund
were received between March and October of 2003 for guaranteed
supply to the electricity market during the winter season. These
additional payments accounted for a P$17 million increase in sales; 110




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
    
    an increase of approximately 7% in the demand for
electricity, which, as a result of the limited availability of
natural gas during the winter season (due to lower temperatures and
increased consumption by industries), required energy dispatch from
less efficient machines, which resulted in higher market prices.
The reduction in the availability of gas did not affect the activity
of the Genelba Power Plant due to the gas supply contract it had in
effect during 2003); and
    
    reduced flows from incoming rivers during the second half of
the year, which shifted generation away from low-cost hydroelectric
plants. This reduction in river flows was caused by a mild summer,
which resulted in less snow water supplying the river basins. In 2003, net sales from the Genelba Power Plant increased P$34 million or
21% to P$196 million, from P$162 million in 2002, due to increased prices and
sales volume. The average monomic price of energy and power delivered
increased 16.7% in 2003, to P$39.9 per MWh from P$34.2 per MWh in 2002. Energy
deliveries from this plant increased 4% to 4,918 GWh, from 4,731 GWh in 2002,
with a plant factor of 79.1% in 2003 and 73.6% in 2002. The increased sales
volume in 2003 was primarily attributable to higher dispatch to the network,
due to changes in 2002 to the regulations regarding cost declaration, that
benefit the plants relative competitiveness and permit a more timely and
flexible operation. In 2003, the availability factor of the Genelba Power
Plant was 96.5%, 1.1% higher than in 2002, as a result of the optimization of
starting processes, inspections, maintenance works and the plants general
performance. In 2003, net sales attributable to HPPL increased P$7 million or 24% to
P$36.2 million, from P$29.2 million in 2002. The average monomic sale price of
energy and power increased 37.4% to P$32.3 per MWh, from P$23.5 per MWh in
2002, reflecting the overall increase in energy prices discussed above. Energy
delivered by HPPL dropped 9.7% to 1,120 GWh, from 1,240 GWh in 2002, due to a
lower contribution from incoming river flows, as compared to historic average
values. As a result of the application of the Energy Support Price Method and
by virtue of the prices recorded in 2003 and 2002, and their future estimates,
we recorded P$3 million and P$5 million gains in 2003 and 2002, respectively. Gross profit: In 2003, our gross profit for this segment increased by
P$10 million or 6.3% to P$168 million, from P$158 million in 2002. Our gross
profit for this segment in 2003 and 2002 reflects P$74 million and P$108
million, respectively, corresponding to our share of Distrilecs gross profit
for these years. In 2003, without proportional consolidation, our gross profits increased
P$59 million or 168.6% to P$94 million, from P$35 million in 2002 (excluding
P$15 million corresponding to the gross profits of Conuar/Fae, which we sold in
2002). Gross profit from generation: In 2003, gross profit for the
electricity-generation business increased P$60 million or 193.5% to P$91
million, from P$31 million in 2002. This significant increase is mainly
attributable to higher sales prices and lower sales costs as measured in
constant pesos given that the nominal cost of gas remained unchanged. Administrative and selling expenses: In 2003, our administrative and
selling expenses for this segment decreased by P$19 million or 20.7% to P$73
million, from P$92 million in 2002. Our administrative and selling expenses
for this segment in 2003 and 2002 reflects P$65 million and P$76 million,
respectively, corresponding to our share of Distrilecs administrative and
selling expenses for these years. In 2003, without proportional consolidation, our administrative and
selling expenses for the generation business dropped P$4 million or 33.3% to
P$8 million, from P$12 million in 2002 (excluding P$4 million corresponding to
administrative and selling expenses of Conuar/Fae, which we sold in 2002). In
nominal terms, these expenses remained unchanged. Other exploitation income (expense), net: In 2003, our other exploitation
income for this segment decreased on a net basis P$6 million or 26% to P$17
million, from P$23 million in 2002. Our net other exploitation income for this
segment in 2003 reflects P$5 million corresponding to our share of Distrilecs
exploitation income for that year. In 2002 Distrilec did not register
significant net other exploitation income. 111




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In 2003, excluding proportional consolidation, our other exploitation
income decreased on a net basis by P$1 million or 4.3% to P$22 million, from
P$23 million in 2002. Equity in Earnings of Affiliates and Companies under Joint Control CIESA/TGS: In 2003, our equity share in the earnings of CIESA (which owns
55.3% of TGS), together with our 7.35% direct interest in TGS, accounted for a
P$240 million gain, compared to a P$482 million loss in 2002. Given the
significant financial indebtedness of both TGS and CIESA that is denominated in
U.S. dollars, the appreciation of the peso in 2003, compared to the
depreciation it registered in 2002, had a significant impact on their net
results. Additionally, CIESAs exploitation income declined 6.7% in 2003, to
P$407 million, as a result of lower revenues for the regulated gas
transportation market as a consequence of the pesification of rates. Our
results in 2003 include a P$33 million gain in respect of our investment in
CIESA, representing the reversal of the P$33 million negative value of our equity in this
company as of December 31, 2002. Sales revenues from the gas transportation segment dropped 20.7% in 2003,
to P$422 million. While the committed transportation capacity slightly
increased from 61.3 MMm3/d to 61.4 MMm3/d, the drop in revenues results from
failure to adjust gas transportation rates due to the delayed start of the
tariff negotiation process with the Argentine government and the restatement of
income for 2002. Both effects were partially offset by increased revenues from
interruptible transportation services, as a result of a rise in the demand for
natural gas. Income from the NGL production and marketing segment increased 23.3% in
2003 to P$428.4 million, as a result of: (i) an increase in domestic sale
prices caused by a significant increase in international sale prices, (ii) the
renegotiation of certain NGL processing and marketing agreements which had been
pesified and were re-indexed to the dollar, and (iii) a 6% increase in sales
volumes. These positive factors were partially offset by the effect of the
restatement of income for 2002, reflecting the fact that the increase in prices
and margins exceeded domestic inflation. CIESA is presented under the proportional consolidation method in our
financial statements as of and for the years ended December 31, 2003 and
December 31, 2001 included in this annual report, but not in the financial
statements as of and for the year ended December 31, 2002. See Overview.
As a result, the financial data discussed above is not directly comparable to
the corresponding data appearing in our financial statements. Distrilec/Edesur: In 2003, our equity interest in the earnings of
Distrilec (through which we hold our interest in Edesur) accounted for an P$11
million loss, compared to an P$8 million loss in 2002. In 2003, Distrilec
registered a P$17.2 million operating loss, compared to a P$46.8 million
operating gain in 2002. This shift reflects the impact of the Public Emergency
Law and the pesification of rates. Net sales declined 13.9% in 2003, to
P$920.2 million. This decline was mainly attributable to a decrease of
approximately 17% (in constant currency) in the average sale price for energy,
which was partially offset by a 4.4% increase in the demand for energy.
Distrilecs operating loss in 2003 was positively affected by the appreciation
of the peso during this year on this companys financial debt. Distrilec is presented under the proportional consolidation method in our
financial statements included in this annual report. See Overview. As a
result, the financial data discussed above is not directly comparable to the
corresponding data appearing in our financial statements. Citelec/Transener: In 2003, our equity interest in the earnings of
Citelec (through which we hold our interest in Transener) accounted for an P$87
million gain, compared to a P$241 million loss in 2002. This shift resulted
primarily from appreciation of the peso in 2003 and its impact on Transeners
financial indebtedness. The equity gain from Citelec in 2003 also reflects the
reversal of a P$66 million allowance recorded in 2002. In 2003, Citelecs
exploitation income declined 39.1% to P$42 million, from P$69 million in 2002,
primarily as a result of the pesification of regulated rates. Sales revenues
declined 3.7% in 2003, to P$276 million, mainly as a result of the Argentine
governments failure to adjust regulated rates in 2002 and 2003. This effect
was offset by the increase in unregulated revenues, primarily attributable to
revenues derived from construction of the Yacyretá  Ayolas 500 kV High Voltage
Transmission Line and other projects in Paraguay. 112




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Refinor S.A.: In 2003, our equity interest in the earnings of Refinor
accounted for a gain of P$28 million, compared to a gain of P$9 million in
2002. This increase resulted primarily from a 19% rise in fuel marketing
margins and, to a lesser extent, the losses attributable to the devaluation of
the peso, which had reduced Refinors earnings for 2002. Refinors sales
increased to P$858 million in 2003, from P$836 million in 2002, reflecting a
10% increase in the volume of gas it processed (to an average of 16.7 million
cubic meters per day). This increase in gas volume processed resulted from the
launch of operations of the Chango Norte field, which supplied gas to Refinors
gathering and compression system. This increase in gas production was offset
by a 6% decrease in the level of oil processed (to 17.6 thousand barrels per
day), resulting from reduced availability of crude oil. Cuyo: In 2003, our equity interest in the earnings of Cuyo accounted for
a P$16 million gain, compared to a P$10 million loss in 2002 (which reflects
the impact of the peso devaluation in 2002 on Cuyos U.S. dollar-denominated
debt). Cuyos sales in 2003 totaled P$225 million, compared to P$200 million
in 2002, as a result of a 5.9% increase in average sale prices of its products,
mainly reflecting the 25% rise in the international prices of polypropylene. Empresa Boliviana de Refinación (EBR): In 2003, our equity interest in
the earnings of EBR accounted for a P$5 million loss, compared to a P$12
million gain in 2002. This drop is mainly attributable to changes introduced
in this companys regulatory framework, which resulted in a significant drop in
refining margins. Oleoductos del Valle S.A. (Oldelval): In 2003, our equity interest in the
earnings of Oldelval accounted for a P$2 million gain, compared to a P$11
million gain in 2002, mainly due to a 16% decline in sales revenues (to P$102
million) resulting from an increase in the U.S. dollar-denominated rate that
Oldelval charges to its customers. Oldelvals operating costs increased due to
maintenance work performed to secure reliability of the pumping system. During
2003, oil volumes transported by Oldelval from Allen to Puerto Rosales
registered a slight 1.2% drop (to 60 million barrels), reflecting the natural
decline of the oil field at the Neuquén basin, and sustained growth of exports
to Chile through the Trans-andino Oil Pipeline. 113




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Year Ended December 31, 2002 Compared to Year Ended December 31, 2001 Net
income: In 2002, we reported a net loss of P$1,579 million, compared
to income of P$101 million in 2001. The enactment of the Public Emergency Law,
the peso devaluation, the worsening of the current economic and financial
crisis in Argentina, in addition to growing uncertainty over its evolution,
adversely affected 2002 operations and resulted in significant losses. This
resulted in a significant change in the historical evolution of our results.
Net income in 2002, without proportional consolidation, was significantly
affected by the following factors:  (i)
    
    Argentine peso devaluation: The 238% devaluation of the peso
in 2002 affected our results in two respects: it caused (i) P$8,030
million in negative exchange differences derived principally from
the net borrowing position primarily denominated in U.S. dollars,
and (ii) a P$356 million increase in interest related to foreign
currency financial debt (from P$477 million in 2001 to P$833 million
in 2002). Conversely, remeasurement and translation into Argentine
currency of foreign non-monetary assets accounted for a P$1,500
million gain. See Factors Affecting Our Consolidated Results of
OperationsEconomic and Political Developments in
ArgentinaArgentina Peso Devaluation.(ii)
    
    Valuation of our interests in utility companies: Due
primarily to the peso devaluation and the pesification of rates,
equity in earnings of utility companies dropped P$851 million in
2002. In addition, we recorded a P$66 million impairment charge to
write off the book value of Citelec. In 2001, we recorded a P$202
million impairment charge to write off CIESAs acquisition value in
excess of the relevant book value. See Factors Affecting Our
Consolidated Results of OperationsEconomic and Political
Developments in ArgentinaValuation of Our Interests in Utility
Companies.(iii)
    
    Impairment of assets: We have recorded a P$63 million
impairment allowance for our operations in Ecuador. See
Factors Affecting our Consolidated Results of
OperationsOperations in Ecuador. We also adjusted the book value of assets
of certain gas areas in Argentina and equity interest in
Hidroneuquén, accounting for P$44 million and P$10 million losses,
respectively, in 2002. See Factors Affecting Our Consolidated
Results of OperationsEconomic and Political Developments in
ArgentinaImpairment of Assets. In addition, considering prospects
for the evolution of results of operations, we recorded P$19 million
and P$103 million impairment charges in 2002 and 2001, respectively,
to write off the minimum presumed income tax credit.(iv)
    
    Impairment of Argentine government bonds: Since the
Argentine government declared the default on most of its sovereign
debt, following a conservative accounting practice, we recorded an
impairment charge to write off the book value of our holdings of
Argentine External Bills in U.S. dollars, survey rate series 74,
accounting for a P$30 million loss in 2002.(v)
    
    Association Agreement in San Carlos and Tinaco: P$37 million
impairment charge to write off the value of the investments made in
such areas. See Factors Affecting Our Consolidated Results of
OperationsPolitical and Economic Situation in VenezuelaAssociation
Agreement in San Carlos and Tinaco.(vi)
    
    Political and economic crisis in Venezuela: Political and
economic unrest, especially the prolonged strike in which PVDSAs
workers joined, accounted for a drop in sales from our Venezuelan
operations of approximately U.S.$10 million. Considering the
uncertainty posed by the prevailing situation in Venezuela, we
deemed it prudent to record a P$42 million impairment charge in 2002
to write off the book value of loans granted to partners in
Venezuelan joint ventures. Under such loan agreements, we from time
to time provide our joint venture partners any cash required to
comply with the obligations related to the joint ventures cash
flows. The 114




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impairment charge was recorded to adjust loan quality to probable
recoverable value taking into account that such loans are secured
by a pledge as fiduciary bond.These effects were partially mitigated by:(i)
    
    Effect of inflation: The significant net borrowing position
resulted in the recognition of a P$6,210 million gain for exposure
to inflation. See Factors Affecting Our Consolidated Results of
OperationsEconomic and Political Developments in ArgentinaEffects
of Inflation.(ii)
    
    Income from divestment of non-core assets: Divestment of
non-core assets accounted for a P$78 million net gain in 2002. See
Factors Affecting Our Consolidated Results of
OperationsDivestment of Non-Core Assets. During the 2001 fiscal
year, divestment of operations accounted for a P$186 million net
gain. Net
sales: In 2002, our net sales decreased by P$64 million or
1.2% to
P$5,106 million, from P$5,170 million in 2001. Our net sales for 2002 reflect
P$519 million corresponding to our share of Distrilecs net sales for that
year. Our net sales for 2001 reflect P$610 million and P$946 million
corresponding to our share of the net sales of CIESA and Distrilec,
respectively, for that year. Without proportional consolidation, net sales increased P$973 million or
26.9% to P$4,587 million in 2002, from P$3,614 million in 2001, primarily due
to the significant rise in the price of the main commodities that we sell. In
the prevailing inflationary scenario in 2002, the price of the main products
significantly increased reflecting increased contribution from foreign
operations, increased exports and the alignment of domestic prices with export
reference prices. In such respect, in 2002 the prices of crude oil, styrene
and polystyrene increased 52%, 72% and 37%, respectively. In 2002, sales for
the Oil and Gas Exploration and Production business segment increased P$831
million (including a P$300 increase in intercompany sales), and sales for the
Petrochemicals and Refining business segments increased P$436 million and P$220
million, respectively. In contrast, sales revenues from the Electricity
segment decreased P$116 million. Gross profit: In 2002, our gross profit decreased by P$1 million or 0.1%
to P$1,822 million, from P$1,823 million in 2001. Our gross profit for 2002
reflects P$113 million corresponding to our share of Distrilecs gross profits
for that year. Our gross profit for 2001 reflects P$376 million and P$292
million corresponding to our share of the gross profits of CIESA and Distrilec,
respectively, for that year. Without proportional consolidation, gross profit for 2002 increased P$554
million or 48% to P$1,709 million from P$1,155 million in 2001, mainly as a
result of increased marketing margins of the main commodities. Oil and Gas
Exploration and Production and Petrochemical business segments gross profits
increased P$419 million and P$210 million, respectively. Conversely, as a
result of restrictions on the increase of energy sales prices in the prevailing
inflationary scenario, gross profit for the Electricity business segment
dropped by P$62 million. Administrative and selling expenses: In 2002, our administrative and
selling expenses decreased by P$56 million or 8.4% to P$609 million, from P$665
million in 2001. Our administrative and selling expenses for 2002 reflect P$77
million corresponding to our share of Distrilecs administrative and selling
expenses for that year. Our administrative and selling expenses for 2001
reflect P$33 million and P$122 million corresponding to our share of the
administrative and selling expenses of CIESA and Distrilec, respectively, for
that year. Without proportional consolidation, administrative and selling expenses
for 2002 increased P$22 million or 4.3% to P$532 million, mainly as a result of
the effect of devaluation on expenses incurred abroad. This impact, however,
was mitigated by the implementation of a stringent cost optimization policy. Exploration expenses: Exploration expenses increased P$17 million or
41.5% to P$58 million in 2002 from P$41 million in 2001. Other exploitation income (expense), net: In 2002, we recorded other
exploitation expenses, net, in the amount of P$28 million, compared to other
exploitation income, net, in the amount of P$23 in 2001. Distrilec 115




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(which was subject to proportional consolidation in 2002) did not
register, on a net basis, any other exploitation expenses in 2002. Our net
other exploitation income for 2001 reflects P$3 million corresponding to our
share of the net other exploitation income of Distrilec for that year. In 2002, excluding proportional consolidation, we recorded other
exploitation expenses, net, in the amount of P$28 million, compared to other
exploitation income, net, in the amount of P$20 million in 2001. Our net other
exploitation expenses for 2002 resulted primarily from a P$20 million reduction
in income from advisory services related, either directly or indirectly, to
utility companies operation, in line with the special situation of these
companies, and P$15 million in liabilities for environmental remediation work. Exploitation income: In 2002, our exploitation income decreased by P$13
million or 1.1% to P$1,127 million, from P$1,140 million in 2001. Our
exploitation income for 2002 reflects P$36 million corresponding to our share
of Distrilecs exploitation income for that year. Our exploitation income for
2001 reflects P$343 million and P$173 million corresponding to our share of the
exploitation income of CIESA and Distrilec, respectively, for that year. Without proportional consolidation, exploitation income increased P$468
million or 75% to P$1,092 million in 2002 from P$624 million in 2001, mainly as
a result of the significant increase in gross profit. Equity in earnings of affiliates: Equity in earnings of affiliates
accounted for a P$638 million loss in 2002 compared to a P$119 million gain in
2001. This significantly increased loss mainly resulted from the decline in
earnings of our affiliate utility companies. Without applying proportional consolidation in 2002, our equity interest
in the earnings of affiliates would have registered a net loss of P$647
million, as compared to a net gain of P$204 million in 2001. This shift
resulted primarily from a significant reduction in the earnings of our
affiliate utility companies. In 2002, these companies registered a loss of
P$732 million, compared to a P$119 million gain in 2001. In 2002, our equity
interest in the earnings of affiliates was also adversely affected by the
following factors:  
    
    the loss of earnings resulting from the sale of our interests
in Pecom Agra, from which we had derived a P$17 million gain in
2001; and
    
    a P$10 million loss from our equity interest in the earnings
of Cuyo, compared to a gain of P$4 million in 2001, resulting from
the impact of the peso devaluation on Cuyos dollar-denominated
debt. Conversely, we derived a P$59 million gain from our equity share in the
earnings of Cerro Vanguardia, compared to a P$16 million gain in 2001,
reflecting the inflow of U.S. dollar-denominated cash flows from this companys
operations. For a discussion of our equity in the earnings of companies over which we
exercise joint control in 2002 and the factors that affected these companies
results during that year, see Equity in Earnings of Affiliates and Companies
under Joint Control. Financial income (expense) and holding gains (losses): In 2002, our
financial expenses and holding losses increased by P$1,254 million or 218.8% to
P$1,827 million, from P$573 million in 2001. Our financial expenses and
holding losses for 2002 reflect P$168 million corresponding to our share of
Distrilecs financial expenses and holding losses for that year. Our financial
expenses and holding losses for 2001 reflect P$124 million corresponding to our
share of CIESAs financial and holding losses for 2001, and P$2 million
corresponding to our share of Distrilecs financial and holding gains for 2001. Without proportional consolidation, net financial expenses increased
P$1,208 million or 267.8% to an expense of P$1,659 million in 2002 from an
expense of P$451 million in 2001. Such increased loss is primarily
attributable to: (i) a P$8,030 million net exchange loss in 2002, (ii) an
increase in net financial costs from P$414 million in 2001 to P$770 million in
2002, (iii) adjustment of liabilities on account of pesification and subsequent
application of indexation in the amount of P$54 million, (iv) impairment charge
to write off book value of holding 116




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of Argentine External Bills in U.S. dollars, survey rate series 74,
accounting for a P$30 million loss and (v) a P$470 million loss in 2002
compared to a P$8 million loss in 2001 from derivatives that do not qualify for
hedge accounting, reflecting the increase in the future price curve of
reference crude oil and the impact of the devaluation of the peso. Such
effects were mitigated by a P$1,500 million gain resulting from conversion and
translation of foreign non-monetary assets and by a P$6,209 million gain due to
exposure to inflation. Other expenses, net: In 2002, our other expenses increased on a net basis
by P$99 million or 112.5% to P$187 million, from P$88 million in 2002. Our net
other expenses for 2002 reflect P$9 million corresponding to our share of
Distrilecs net other expenses for that year. Our net other expenses for 2001
reflect P$63 million and P$11 million corresponding to our share of the net
other expenses of CIESA and Distrilec, respectively, for that year. Without proportional consolidation, other expenses, net recorded P$178
million and P$14 million losses in 2002 and 2001, respectively. In 2002,
losses were primarily attributable to the following: (i) impairment of gas
production blocks in the amount of P$44 million, (ii) P$63 million for
impairment allowance from our group of assets in Ecuador, (iii) impairment
of exploratory investments in the San Carlos areas in the amount of P$37
million, (iv) impairment charge to write off book value of interest in
Hidroneuquén in the amount of P$10 million, (v) P$42 million allowance for bad
debts related to loans granted to joint venture partners in Venezuela, and (vi)
accelerated amortization of financial debt issuance costs in the amount of P$17
million, in the context of the debt refinancing process. Such effects were
partially offset by gain from divestment of non-core assets of P$78 million.
Losses recorded in the previous fiscal year were mainly attributable to the
P$202 million impairment charge to write off the acquisition value of CIESA in
excess of the relevant book value and to the P$65 million loss from the sale of
Pampa del Castillo-La Guitarra area and of the shareholding in Terminales
Marítimas Patagónicas, partially offset by a P$251 million gain derived from a
hydrocarbon assets exchange. Income tax: In 2002, our income tax charge decreased by P$303 million or
78.7% to P$82 million, from P$385 million in 2001. Our income tax charge for
2002 reflects a P$127 million gain corresponding to our share of Distrilecs
income tax for that year. Our income tax charge for 2001 reflects P$66 million
and P$70 million, corresponding to our share of the income tax of CIESA and
Distrilec, respectively, for that year. Without proportional consolidation, the income tax provision accounted for
a P$209 million expense in 2002 compared to a P$249 million expense in 2001.
Both years include an impairment charge to write off the minimum presumed
income tax credit in the amount of P$19 million and P$104 million,
respectively. Oil and Gas Exploration and Production Exploitation income: Exploitation income for this segment increased P$327
million or 56.9% to P$902 million in 2002 from P$575 million in 2001. This
increase was primarily due to increased sale prices and an increase in margins,
as explained below. Net sales: Net sales for this business segment increased P$831 million or
42.1% to P$2,806 million in 2002 from P$1,975 million in 2001. Excluding
intercompany sales, net sales for this segment increased to P$2,033 million or
35.4% from P$1,502 million. This significant rise was attributable to
increased sale prices mainly as a result of the peso devaluation during 2002.
Crude oil international price slightly increased to U.S.$26.3 per barrel or
1.5% in 2002. As a consequence of the combined effect of such factors, the
average price per barrel of oil equivalent increased 52.5% to P$45/per barrel
of oil equivalent from P$29.5/per barrel of oil equivalent. Crude oil hedging
policy in 2002 and 2001 accounted for an opportunity cost of P$373 million and
P$341 million, respectively. Combined oil and gas sales declined 6.8% to 171.1 thousand barrels of oil
equivalent per day in 2002 from 183.6 thousand barrels of oil equivalent per
day in 2001. The previous year includes sales attributable to the Pampa del
Castillo  La Guitarra area, which was sold in October 2001 and contributed an
average production of 7.3 thousand barrels of oil equivalent per day in 2001.
Excluding such divestment, the daily sales volume dropped only 2.9%. The
significant reduction in the investment plan severely limited operations during
2002. Along these lines, our investments were focused on countries and
products with greater possibilities of accelerated cash generation. Our
proactive management of operations enabled us to mitigate the effects of the
reduction in the investment plan. 117




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Net Sales in Argentina: Net sales of oil and gas in Argentina increased
P$383 million or 31.3% to P$1,607 million in the 2002 fiscal year from P$1,224
million in the 2001 fiscal year. Combined oil and gas sales volumes in 2002
decreased 10.1%, to 101.5 thousand barrels of oil equivalent per day in 2002
from 112.9 thousand barrels of oil equivalent per day in 2001. Sales of crude oil in Argentina increased P$447 million or 45.8% to
P$1,423 million from P$976 million as a consequence of the peso devaluation.
Average crude oil prices, net of discounts per barrel, increased 62.3% to
P$65.4 in 2002 from P$40.3 in 2001. Tax on crude oil exports applied since
April 2002 accounted for a P$84 million lower revenue in 2002. Daily oil sales
volumes dropped 10% to 59.2 thousand barrels from 65.8 thousand barrels, mainly
as a result of the sale of Pampa del Castillo  La Guitarra area. Sales of natural gas in Argentina dropped P$65 million or 26% to P$183
million in 2002 from P$248 million in 2001. In 2002, gas daily sales volumes
decreased 10.3% to 253.9 million cubic feet from 282.9 million cubic feet,
primarily as a consequence of reduced sales to gas distributors, especially as
a result of the application of more stringent credit policies and, to a lesser
extent, as a consequence of the reduced demand from thermoelectric generating
plants on account of the high water supply levels recorded in 2002. Average
gas sales prices dropped to P$1.98 per thousand cubic feet in 2002 from P$2.40
per thousand cubic feet in 2001, in line with the Public Emergency Law
provisions that limit the possibility of increasing the price of gas sold in
the domestic market, mainly regarding sales agreements entered into with
utility companies and with the power thermoelectric generating plants.
However, we renegotiated the terms and conditions of certain gas sales
agreements, especially those corresponding to exporting clients, and the prices
of said agreements were adjusted to meet the new economic conditions. Net Sales Outside of Argentina: Net sales of oil and gas outside
Argentina increased P$448 million or 59.7% to P$1,199 million in 2002 from
P$751 million in 2001, mainly as a result of the peso devaluation. In 2002,
combined oil and gas sales decreased 1.7% to an average of 69.5 thousand
barrels of oil equivalent per day from 70.7 thousand barrels of oil equivalent
per day in 2001. In Venezuela, oil and gas sales increased P$220 million or 45.8% to P$700
million in 2002 from P$480 million in 2001 as a consequence of the peso
devaluation. During 2002, average daily oil sales decreased 3.5% to 44.7
thousand barrels compared to 46.3 thousand barrels in 2001 as a result of the
fields natural decline and reduced deliveries due to the oil strike during
December 2002. In 2002, the average oil price per barrel increased 51% to
P$41.9 from P$27.7 in the 2001 fiscal year. In Bolivia, oil and gas sales increased P$29 million or 34.9% to P$112
million in 2002 from P$83 million in 2001, mainly as a result of the peso
devaluation. Combined daily oil and gas sales volumes decreased 6.4% to 7.3
thousand barrels of oil equivalent per day in 2002 from 7.8 thousand barrels of
oil equivalent per day in 2001 as a result of reduced gas demand from Brazil. In Peru, oil and gas sales increased P$174 million or 95.1% to P$359
million in 2002 from P$184 million in 2001. Due to the Argentine peso
devaluation, average oil sales prices rose 101% to P$80.4 from P$40 in 2001.
In 2002, daily oil sales volumes decreased slightly to 11.3 thousand barrels
from 11.6 thousand barrels in 2001, reflecting the field natural decline. In Ecuador, net sales totaled P$28 million in 2002 and there were no
material sales in 2001. Sales in 2002 were attributable to the start-up of
production at the Palo Azul field, in Block 18, upon approval of the
development plan, which added sales of P$16 million. In addition, management
works were performed in the amount of P$12 million. Gross profit and gross margin: Gross profit for this business segment
increased P$419 million or 53.2% to P$1,206 million in 2002 from P$787 million
in 2001 as a result of the Argentine peso devaluation. Gross margin increased
to 43% in 2002 from 39.9% in 2001. During 2002, we continued to reduce costs
by optimizing our operations. 118




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Administrative and selling expenses: Administrative and selling expenses
for this business segment increased P$57 million or 34.1% to P$224 million in
2002 from P$167 million in 2001 as a result of the Argentine peso devaluation
effect on foreign operations expenses. The ratio of administrative and selling
expenses to sales did not suffer significant changes in 2002. Exploration expenses: Exploration expenses increased P$17 million or
41.5% to P$58 million in 2002 from P$41 million in 2001. During 2002, drilling
activities at the Chontayacu well at Block 18 in Ecuador were completed but
proved to be unsuccessful. In addition, 238 km of 2-D seismic lines were shot
at Block 31. In Argentina and Peru, investments attributable to the Chiripá
well in the Santa Cruz II Oeste area and to the Mashansha well at Lot 35 were
charged to income, but no reserves were found. Other exploitation income, net: Other exploitation income recorded a P$22
million loss in 2002 mainly attributable to liabilities for environmental
remediation and the sale of fixed assets. In 2001, net exploitation income
accounted a P$4 million loss, due mainly to discontinued projects. Hydrocarbon Marketing and Transportation Our results for this segment in 2002 do not reflect the proportional
consolidation of CIESA. In 2001, CIESAs results are proportionally
consolidated. See Overview. Exploitation income: In 2002, our exploitation income for this segment
decreased by P$362 million or 95.7% to P$16 million, from P$378 million in
2001. Our exploitation income for this segment in 2001 reflects P$342 million
corresponding to our share of CIESAs exploitation income for that year. Without proportional consolidation, exploitation income for the
hydrocarbon marketing and transportation business segment decreased P$20
million or 55.5% to P$16 million in 2002 compared to P$36 million in 2001. Our own operations: Due to a reformulation of the liquid processing
business, beginning in 2002 the Oil and Gas Exploration and Production business
segment has developed the liquid processing business segment. In 2001, sales
revenues amounted to P$50 million and exploitation income totaled P$14 million.
Excluding the effects from these activities, exploitation income from this
segments operations decreased P$2 million to P$3 million in 2002 from P$5
million in 2001, and sales revenues dropped P$19 million to P$16 million from
P$35 million in 2001, mainly due to the deterioration of the price of gas sold
in the domestic market and the drop in oil operations, partially offset by
improved prices resulting from the Argentine peso devaluation. Other operating expenses: In relation to advisory services provided to
TGSs technical operator, we recorded P$13 million and P$17 million of income
in 2002 and 2001, respectively. Refining Exploitation income: Exploitation income decreased P$5 million. We did
not report exploitation income from this segment in 2002, while in 2001 it
totaled a P$5 million gain. Net sales: Net sales of refinery products, including intersegment sales,
increased P$220 million or 27.9% to P$1,008 million in 2002 from P$788 million
in 2001, boosted by increased prices and higher export volumes, which partially
offset the strong shrinkage in the domestic market. In 2002, the average sales
price of diesel oil, gasolines, heavy products, benzene, paraffins, aromatics
and asphalts increased 23.1%, 7.3%, 58.5%, 108%, 55.4%, 30.5% and 24.0%,
respectively. Total sales volumes remained unchanged compared to 2001. There
was, however, a change in the mix of products sold, aiming to prioritize the
optimization of margins, as well as in marketing channels. Along these lines,
exports increased 171%, capitalizing on the improved competitiveness of
Argentine production after the devaluation, while local sales dropped 30% due
to the domestic market shrinkage and the lack of profitability. Taxes on exports applied in April 2002 accounted for P$14 million lower
income in 2002. 119




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During 2002, gasoline and diesel domestic demand dropped 12.5% and 8.4%,
respectively. The recession in the Argentine market in addition to the strong
tax incidence on final prices of these products had a negative impact on
demand. This, in turn, encouraged a strong growth in alternative products such
as CNG. Total diesel sales volumes decreased 16.3%, with a 35% decline in the
domestic market, offset by a 416% increase in exports to bordering countries,
especially to Paraguay. Total gasoline sales volumes dropped 2.7%, reflecting
the domestic market behavior. Aromatics sales volumes rose 3.4% on account of increased exports that
rose 144%, mainly to bordering countries and the United States, offset by a 15%
drop in the domestic market. Sales volumes of the reformer plant products
decreased 5.6% due to reduced local sales (22%), offset by a 503% increase in
exports. Sales volumes of paraffinic products increased 34.5% due to the 90%
rise in export volumes, mainly to the United States and bordering countries,
offset by reduced local sales (20%). Sales volumes of heavy products increased
46.1% due to the 150% increase in volumes exported to the United States and
bordering countries, offset by reduced local sales (46%). Asphalts sales
volumes dropped 46.4%, with a 60% market shrinkage, and the market share
decreased to 17% from 21% in 2001. Sales to the domestic market influenced by
the interruption of most public works recorded a 65% drop, offset by exports to
Bolivia and Paraguay which increased 194% compared to 2001. We set a new
record on asphalt exports. Gross profit and gross margin: Gross profit for this business segment
dropped P$13 million or 16.9% to P$64 million in 2002 from P$77 million in
2001. Gross margin decreased from 9.8% in 2001 to 6.3% in 2002. In 2002, the refining spread per barrel (average sales price less crude
oil cost) decreased to P$18.1 or 22.3% from P$23.3. The average price of crude
oil increased to P$78.9 per barrel or 36.8% from P$57 per barrel in 2001,
reflecting the impact of the Argentine peso devaluation. The international
reference price remained at an average of U.S.$26 per barrel, equivalent to the
average recorded in 2001. Express Argentine government initiatives and the
gradual drop in the activity level curbed the passing through of increased
crude oil costs to sales prices. Sales prices only increased an average of
28%, thus resulting in the aforementioned deterioration of the spread per
barrel. In line with the strategy designed to maximize product contribution
margins through the optimization of crude oil volumes processed, mainly by
capitalizing on lower refined product export tax rates compared to export tax
rates applicable to crude oil, crude oil volumes processed in 2002 averaged
27.1 thousand barrels per day, 6% higher than in 2001. Administrative and selling expenses: Administrative and selling expenses
for this business segment decreased P$11 million or 18.6% to P$48 million in
2002 from P$59 million in 2001, mainly due to the fact that expenses increased
significantly below inflation levels. Other operating expenses: Other operating expenses recorded P$16 million
and P$13 million losses in 2002 and 2001, respectively. The under-absorption
of fixed costs imposed by the optimization policy of crude oil volumes
processed accounted for P$10 million losses in both fiscal years. In addition,
P$5 million liabilities for environmental remediation costs were recorded in
2002. Petrochemicals Exploitation income: Exploitation income for this business segment
increased P$192 million or 325% to P$251 million in 2002 from P$59 million in
2001, primarily due to the significant recovery of marketing margins,
especially styrenics margins, and to increased styrene, polystyrene and rubber
sales volumes. In addition, the changes in the fertilizers sales mix boosted
exploitation income since the sale of products with a higher added value was
prioritized. Net sales: Net sales for this business segment, including intersegment
sales, increased P$436 million or 53.3% to P$1,254 million in 2002 from P$818
million in 2001. 120




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Styrene and polystyreneArgentina: Sales of styrene and polystyrene from
Argentina increased P$158 million or 54% to P$451 million from P$293 million in
2001 (including exports to Innova in the amount of P$26 million and P$9
million, respectively). Sales prices of styrene, polystyrene and rubber prices
increased 72%, 37% and 36%, respectively. Sales volumes recorded a 5%
increase, boosted by a 41% increase in exports, which offset the 13% drop in
local sales. Styrene sales volumes rose 9%, boosted by a 183% increase of
exports, principally to Brazil and Chile, thus confirming our leading position
in the styrene market in the Mercosur. Local sales dropped 28% due to the
impact of the strong Argentine recession during the year. Polystyrene sales
volumes increased 10% due to a 45% record increase in exports, the main
destinations being neighboring countries, especially Brazil and Chile, and the
United States and Europe, while local sales dropped 12%. Total rubber sales
volumes increased approximately 8% boosted by the 15% increase in exports
(setting another record for us), mainly to Brazil, Chile and Peru, offset by
reduced local sales (6%). Tax on exports applied in April 2002 accounted for a
P$6 million income reduction in 2002. Styrene and polystyreneBrazil: Sales of styrene and polystyrene from
Brazil increased P$264 million or 89.6% to P$561 million from P$297 million in
2001, primarily due to the increase in styrene and polystyrene international
prices which recorded 88% and 61% increases, respectively, compared to 2001.
In addition, Innovas low-cost production, as well as the plants strategic
location and the effective business management, helped extend the client base
in Brazil and generate a 25% increase in styrene volumes sales. With a 2.8%
rise in the local market share, the increased trading activity allowed us to
consolidate our leading position in the Brazilian market. Polystyrene sales
volumes were slightly higher than those in 2001. A 188% increase in exports
compared to 2001, mainly attributable to the consolidation of commercial
relations in South Africa and sales to the United States, favorably offset the
11% drop in local sales. Excluding non-recurrent sales made to co-producers in
2001, the volume sold to our client base registered a 5.7% increase. Overall
performance acquires significance within a market characterized by increasing
competitive pressures as a result of a substantial increase in the total
installed production capacity. Fertilizers: Net sales increased P$31 million or 13.1% to P$268 million
from P$237 million mainly as a result of a 33% price increase on account of the
passing through of increased input costs and of the change in the sales mix.
Total sales volumes fell 15.4% compared to 2001, in line with the Argentine
market shrinkage. In addition, during 2002 we set up a more selective sale
strategy aimed at prioritizing the quality of our client portfolio and
maximizing marketing margins. Along these lines, sales volumes of products
manufactured increased 21%, while resale dropped 58%. Gross profit and gross margin: Gross profit increased P$210 million or
138.2% to P$362 million in 2002 from P$152 million in 2001. Gross margin on
sales increased to 28.9% in 2002 from 18.6% in 2001. In 2002 international and
local margins were significantly higher than in 2001, boosted by an increased
demand from Asia, in addition to operating problems that affected the
performance of plants located in the United States and Europe. Within this
scenario, the differential of international prices between crystal polystyrene
(South East Asia) and the mix of benzene/ethylene raw materials (U.S. Gulf
Coast) increased 64%, and the differential between styrene (U.S. Gulf Coast)
and the mix of benzene/ethylene raw materials (U.S. Gulf Coast) increased 330%.
In line with the international price trend, polystyrene and styrene marketing
spreads increased 27% and 81% in Argentina, and 51% and 129% in Brazil,
respectively. In addition, because of the peso devaluation, Argentinas
elastomers business gained international competitiveness due to the relative
importance of its fixed production costs. Administrative and selling expenses: Administrative and selling expenses
increased P$27 million or 28.7% to P$122 million from P$95 million due to the
Argentine peso devaluation effects on Brazilian operations. Other exploitation income: Other exploitation income recorded P$11
million and P$2 million gains in 2002 and 2001, respectively. Fiscal year 2002
income is attributable to the collection of an insurance compensation for a
loss occurred at the ethyl benzene plant and to certain tax credits from
operations in Brazil. Electricity Our results for this segment in 2002 and 2001 reflect the proportional
consolidation of Distrilec. See Overview. 121




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Exploitation income: In 2002, our exploitation income for this segment
decreased by P$198 million or 69% to P$89 million, from P$287 million in 2001.
Our exploitation income for this segment in 2002 and 2001 reflects P$32 million
and P$149 million, respectively, corresponding to our share of Distrilecs
exploitation income for these years. Without proportional consolidation, income for this business segment
dropped P$81 million or 58.7% to P$57 million in 2002 from P$138 million in
2001. Within the current economic context, the Public Emergency Law provisions
significantly affected the business segments margins. In such respect,
pesification of tariffs and contracts within an inflation and devaluation
scenario adversely affected the business segments operating performance. Net Sales: In 2002, our net sales for this segment decreased by P$520
million or 40.4% to P$766 million, from P$1,286 million in 2001. Our net sales
for this segment in 2002 and 2001 reflect P$518 million and P$922 million,
respectively, corresponding to our share of Distrilecs net sales for these
years. Without proportional consolidation, net sales in the electricity business
generally decreased P$116 million or 31.9% to P$248 million from P$364 million.
Net sales of electricity generation decreased P$70 million or 26.3% to P$196
million from P$266 million in 2001. Net sales of nuclear fuel elements and
other products totaled P$42 million and P$5 million in 2002 and 2001,
respectively. Net Sales from generation: Net sales attributable to the Genelba Power
Plant dropped P$40 million or 19.8% to P$162 million in 2002 from P$202 million
in 2001 reflecting a drop in energy prices, which was partially offset by
increased sales volumes. The average monomic price of energy and power
delivered dropped 32.3% accounting for P$34.2 per MWh and P$49.8 per MWh,
respectively, mainly due to pesification and a 6% demand shrinkage. In 2002,
energy deliveries increased by 18.9% to 4,731 GWh from 3,979 GWh in 2001, with
plant factors of 73.6% and 59.8%, respectively. The increased volume was
mainly attributable to: (i) non-restriction of fuels during 2002; (ii) higher
operating availability; and (iii) higher dispatch to the network, due to a
timely and flexible operation and the effects of regulatory changes that
improved the Genelba Power Plants competitiveness. In 2002, Genelba Power
Plant operating availability was 95.4%, 3.3% higher than in 2001, as a result
of compliance with works scheduled in the technical maintenance program for
equipment. Net sales attributable to HPPL dropped P$19 million or 39.2% to P$29
million in 2002 from P$48 million in 2001 as a consequence of the combined
effect of lower sales prices and a slight drop in sales volumes, to 1,240 GWh
from 1,313 GWh, determined by the high water levels recorded in 2001. The
average monomic price of energy and power delivered dropped 35.6%, accounting
for P$23.5 per MWh and P$36.2 per MWh, respectively, mainly due to pesification
of prices. On account of the application of the Energy Support Price Method
and by virtue of the prices recorded in both fiscal years and their future
estimates, we posted P$5 million and P$17 million gains, respectively, in both
years. Gross profit and gross margin: In 2002, our gross profit for this segment
decreased by P$222 million or 58.4% to P$158 million, from P$380 million in
2001. Our gross profit for this segment in 2002 and 2001 reflects P$108
million and P$268 million, respectively, corresponding to our share of
Distrilecs gross profit for these years. Without proportional consolidation, gross profit for the generation
business dropped P$48 million or 61% to P$31 million in 2002 from P$79 million
in 2001. Gross margin declined to 15.8% from 27.9%, mainly as a result of
reduced prices of electricity generation on account of the aforementioned
provisions of the Public Emergency Law. Gains recorded on account of the
application of the support price method for energy generated at HPPL mitigated
the significant price drop. Administrative and selling expenses: In 2002, our administrative and
selling expenses for this segment decreased by P$45 million or 32.8% to P$92
million, from P$137 million in 2001. Our administrative and selling expenses
for this segment in 2002 and 2001 reflects P$76 million and P$122 million,
respectively, corresponding to our share of Distrilecs exploitation income for
these years. 122




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Without proportional consolidation, administrative and selling expenses
for the electricity generation business increased P$8 million or 100% to P$16
million in 2002 from P$8 million in 2001. This increase mainly derived from
allowances for customers bad debts. Other exploitation income (expense), net: In 2002, our other exploitation
income for this segment decreased on a net basis P$21 million or 47.7% to P$23
million, from P$44 million in 2001. In 2002 Distrilec did not register
significant net other exploitation income. Our net other exploitation income
for this segment in 2001 reflects P$3 million corresponding to our share of
Distrilecs exploitation income for that year. Without proportional consolidation, other exploitation income-net
decreased P$18 million or 43.9% to P$23 million from P$41 million, mainly as a
consequence of lower advisory services fees rendered to Edesurs technical
operator. Equity in Earnings of Affiliates and Companies under Joint Control CIESA/TGS: In 2002, our equity share in the earnings of CIESA (which owns
70% of TGS) accounted for a P$482 million loss, compared to a P$51 million gain
in 2001. This shift resulted primarily from the effects of the peso
devaluation on this companys significant dollar-denominated debt.
Additionally, CIESAs net operating profit fell 6.7% in 2002, to P$4.07
million, as a result of reduced revenues in the regulated segment caused by the
pesification of utility rates. Sales revenue for the gas transportation segment dropped approximately 44%
in 2002 (in constant pesos), primarily as a result of the pesification of
utility rates. These reductions were partially offset by an increase in the
amount of contracted firm transportation capacity, which in 2002 increased from
60.7 million cubic meters per day to 6.14 million cubic meters per day, and by
greater revenue from interruptible gas transportation services. The increased
level of contracted firm transportation capacity is principally the result of a
significant expansion of our gas transportation system starting in June 2001. The revenue derived from the production and sale of NGL in the unregulated
segment increased P$111.5 million in 2002, due to an increase in prices and
sales volume, which resulted from the devaluation of the peso against U.S.
dollar-denominated export prices. Distrilec/Edesur: In 2002, our equity interest in the earnings of
Distrilec (through which we hold our interest in Edesur), accounted for an P$8
million loss, compared to a P$49 million gain in 2001. This reflects the
impact of the Public Emergency Law, which caused significant asymmetry between
Edesurs revenue flow and its operating costs and expenditures, and the
devaluation of the peso on its dollar-denominated debt. In 2002, Edesurs revenue from sales fell approximately 45.2% (in constant
prices) to P$1,068 million, from P$1,950 million in 2001, due to the freezing
of rates and a 6% fall in the demand of energy. In 2002, Edesurs costs and
expenditures fell 36% (in constant prices), since a large portion of these
costs are denominated in pesos. Distrilec is presented under the proportional consolidation method in our
financial statements included in this annual report. See Overview. As a
result, the financial data discussed above is not directly comparable to the
corresponding data appearing in our financial statements. Citelec/Transener: In 2002, our equity interest in the earnings of
Citelec (interest in Transener) accounted for a loss of P$241 million, compared
to a P$19 million gain in 2001. This shift was caused primarily by the effects
of the devaluation of the peso on Citelecs U.S. dollar-denominated debt. Our
equity share of Citelecs earnings also reflects a P$66 million impairment
charge to write off its book value. Cuyo: In 2002, our equity interest in the earnings of Cuyo accounted for
a P$10 million loss, compared to a P$4 million gain in 2001. This shift
reflects the impact of the peso devaluation on Cuyos dollar-denominated debt. 123




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In 2002, Cuyo registered an operating gain of P$16 million, compared to a
P$13 million gain in 2001, as a result of a 59.9% increase in the profit margin
for sales of prolipropoline (which was consistent with the increase in the sale
margins for this product in international markets), as well as a 5.3% increase
in its sales volume (resulting from a 113% increase in Cuyos exports). Empresa Boliviana de Refinación: In 2002, our equity interest in the
earnings of EBR accounted for a P$5 million loss, compared to a $12 million
gain in 2001, due to the significant decline in refining margins caused by
regulatory changes. Refinor: In 2002, our equity interest in the earnings of Refinor
accounted for a P$9 million gain, compared to a P$6 million gain in 2001. This
increase was primarily caused by the growth of export prices, 59% for diesel
oil and 86% for gasoline, which in part mitigated the increased costs of raw
materials that mainly affected local profit margins. In 2002, local prices for
LPG, diesel oil and gasoline increased 8.8%, 13.4% and 9.2%, respectively.
Refinors sales volumes in the local market increased 14.5% for LPG, 2.8% for
diesel oil and 12.6% for gasoline. CRITICAL ACCOUNTING POLICIES This operating financial review and prospects is based upon our financial
statements, which have been prepared in accordance with accounting principles
generally accepted in Argentina. The preparation of financial statements in
accordance with GAAP requires our management to make estimates that affect the
reported amounts of our assets and liabilities. Our actual results could
differ from those estimated if our estimates or assumptions prove to be
incorrect. We believe the following represents our critical accounting policies. Our
accounting policies are more fully described in notes 2 and 4 to our financial
statements. Estimated oil and gas reserves. Estimates of oil and gas reserves have
been prepared in accordance with Rule 4-10 of Regulation S-X. The choice of
method or combination of methods employed in the analysis of each reservoir was
determined by the stage of development, quality and reliability of basic data,
and production history. Reserve engineering is a subjective process of estimation of hydrocarbon
accumulation, which cannot be accurately measured, and the reserve estimation
depends on the quality of available information and the interpretation and
judgment of the engineers and geologists. Therefore, the reserves estimations,
as well as future production profiles, are often different from the quantities
of hydrocarbons which are finally recovered. The accuracy of such estimations
depends, in general, on the assumptions on which they are based. Successful efforts method of accounting. Under this method, exploration
costs, excluding the costs of exploratory wells, are charged to expenses as
incurred. Drilling costs of exploratory wells, including stratigraphic test
wells, are capitalized pending determination of whether proved reserves exist
which justify commercial development. If such reserves are not found, the
drilling costs are charged to exploratory expenses for the period. Drilling
costs of productive wells and of dry holes drilled for development of oil and
gas reserves are capitalized. Hedging and other derivatives. We use various derivative financial
instruments such as options, swaps and others, mainly to mitigate the impact of
changes in crude oil prices and interest rates. Changes in the accounting measurement of derivative financial instruments
designated as cash flow hedge, which have been determined as effective hedge,
are recognized under Transitory differencesMeasurement of derivative
financial instruments determined as effective hedge, and any other change is
recognized under financial income (expense) for the year. Changes in the
accounting measurement of derivative financial instruments recognized under
Transitory differencesMeasurement of derivative financial instruments
determined as effective hedge are subsequently reclassified to income (loss)
for the year or years in which the hedged item affects such results. A hedge is considered to be effective when at its inception, as well as
during its life, its changes offset from eighty to one hundred and twenty five
percent the opposite changes of the hedged item. In this respect, we exclude 124




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the specific component attributable to the time-value of an option when
measuring the effectiveness of instruments that qualify for hedge accounting. Hedge accounting ceases for the future upon occurrence of any of the
following events: (a) the hedge instrument has matured or has been settled;
(b) the hedge transaction is no longer effective; or (c) the projected
transaction does not have a high likelihood of occurrence. Should that be the
case, the income (loss) arising from the hedge instrument that would have been
allocated to Transitory differencesMeasurement of derivative financial
instruments determined as effective hedge should remain there until the
committed or projected transactions occur, in the case of (a) and (b), and are
charged to income in the case of (c). Inflation accounting. Due to the new inflationary environment in
Argentina in 2002, and the conditions created by the Public Emergency Law, the
CPCECABA approved on March 6, 2002 Resolution MD No. 3/2002 applicable to
financial statements for fiscal years or interim periods ending on or after
March 31, 2002. Resolution MD No. 3/2002 required the reinstatement of the
adjustment-for-inflation method of accounting in financial statements, which
provides that all recorded amounts be restated by changes in the general
purchasing power through August 31, 1995, as well as those arising between that
date and December 31, 2001 stated in currency as of December 31, 2001. On July 16, 2002, the Argentine government issued Decree No. 1,269/02,
instructing the CNV and other regulatory authorities to issue the necessary
regulations for the delivery to such authorities of balance sheets or financial
statements prepared in constant currency. On July 25, 2002, under Resolution
No. 415/02, the CNV reinstated the requirement to submit financial statements
in constant currency. As the inflation rate stabilized in 2003, on March 25 of
this year, Decree No. 664/03 rescinded the requirement that financial
statements be prepared in constant currency. On April 8, 2003, the CNV issued
Resolution No. 441/03 discontinuing inflation accounting as of March 1, 2003.
On October 1, 2003, the CPCECABA also discontinued inflation accounting. In accordance with the above, our financial statements for the fiscal
years ended December 31, 2002 and 2001 were restated in constant pesos as of
February 28, 2003 based on changes in the Argentine wholesale price index
published by the INDEC. This price index does not reflect any specific
variation in the price of products and services sold by us, and therefore,
variations in gains (losses) for both periods include positive or negative
price variations that may be higher or lower than the general price variation
or price variations for the products or services sold by us. After March 1,
2003, in accordance with the accounting standards described above, we no longer
apply adjusting-for-inflation accounting. Impairment of long-lived assets. We record impairment losses on
long-lived assets used in operations when events and circumstances indicate
that the assets might be impaired and the undiscounted cash flows estimated to
be generated by those assets are less than the carrying amount of those items.
Our cash flow estimates are based on historical results adjusted to reflect our
best estimate of future market and operating conditions. Our estimates of fair
values used to determine the resulting impairment loss, if any, represent our
best estimate based on forecasted cash flows, industry trends and reference to
market rates and transactions. Contingencies. Certain conditions may exist as of the date of the
financial statements, which may result in a loss to us, but which will only be
resolved when one or more future events occur or fail to occur. We assessed
contingent liabilities based on the opinion of our legal counsel and the
available evidence. If the assessment of a contingency indicates that it is
probable that a loss has been incurred and the amount can be estimated,
liability is accrued. If the assessment indicates that a potential loss
contingency is not probable but is reasonably possible, or is probable but
cannot be estimated, then the nature of the contingent liability, together with
an estimate of the possibility of occurrence, is disclosed in a note to the
financial statements. Loss contingencies considered remote are not disclosed
unless they involve guarantees, in which case the nature of the guarantee is
disclosed. Income tax. We estimate income tax on an individual basis under the
deferred tax method. The deferred tax balance as of the end of each period has
been determined on the basis of the temporary differences generated in certain
items that have a different accounting and tax treatment. To book such differences, we use the liability method, which establishes
the determination of net deferred tax assets and liabilities on the basis of
temporary differences determined between the accounting measurement of 125




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assets and liabilities and the related tax measurement. Temporary
differences determine the balance of tax assets and liabilities where its
future reversal decreases or increases the taxes determined. In the event
there are unused tax loss carry-forwards that may be offset against future
taxable income, we will recognize a deferred tax asset, only to the extent that
recovery of such asset is probable. Deferred tax assets and liabilities have been valued at their nominal
value, as established by CNVs General Resolution No. 434. The professional
accounting standards effective in the city of Buenos Aires require that such
nominal value be discounted at a current rate estimated as of each year-end. Foreign
currency translation. We apply the following method for
the translation of financial statements of foreign subsidiaries, affiliates,
divisions and joint ventures. Foreign currency denominated transactions are first remeasured into U.S.
dollars (functional currency for such transactions) before they are translated
into Argentine pesos. Gain (loss) from remeasurement is charged to income in
the Financial income (expense) and holding gains (losses) account. The
translation effect arising from the translation of the financial
statements into Argentine pesos is
recorded in the Transitory differences  foreign currency translation
account. The above also applies to exchange differences arising from liabilities in
foreign currency assumed to hedge the net investment in the foreign entity. The magnitude of the remeasurement gain (loss) and the translation effect
is dependent upon movements in the exchange rates of the respective foreign
currencies to the U.S. dollar (to remeasure) and upon movements in the exchange
rates from U.S. dollars to Argentine pesos (to translate), respectively. Change in Accounting Standards The FACPCE Technical Resolutions Nos. 16, 17, 18, 19, and 20, approved as
amended by the CPCECABA and adopted by the CNV through its General Resolution
No. 434, became effective on January 1, 2003. These new technical resolutions
are a consequence of the process whereby Argentine professional accounting
standards are being made consistent with the international accounting standards
issued by the International Accounting Standards Committee, or IASC; in
addition, they provide clarification for certain issues which had not been
provided for in past regulations. The primary changes included in the technical resolutions that have
resulted in significant effects on our financial statements, are: (i) the
introduction of guidelines regarding the recognition, measurement, and
disclosure of derivatives and hedging transactions; (ii) the amendment of the
method used to translate the financial statements of foreign subsidiaries
stated in foreign currency; (iii) the mandatory requirement to apply the
deferred tax method to recognize income tax; (iv) measurement of asset and
liability amounts on discounted bases; (v) changes in the frequency and method
of comparison of assets with the recoverable values thereof; (vi) the
incorporation of guidelines to assess whether certain transactions including
financial instruments, irrevocable capital contributions and preferred stock,
among others, should be classified as liabilities or shareholders equity;
(vii) the incorporation of new disclosure requirements including proportional
consolidation of companies under joint control, change in the disclosure of
direct sales revenues, information by segment, earnings (losses) per share, and
the comparative information to be disclosed. In addition, we amended the method used to recognize future estimated
abandonment costs in oil and gas areas. Consistent with U.S. Statement of
Financial Accounting Standards (SFAS) No. 143 guidelines, such costs,
discounted at a rate estimated upon initial measurement, are capitalized
together with the assets from which they originate and are depreciated using
the production units method. In addition, a liability is recognized on such
account at the estimated value of the amounts payable discounted at a rate
estimated in its initial measurement. As established in the new accounting standards, there are certain
transition regulations enabling us to prospectively apply the valuation and
disclosure method incorporated thereto. The transition standards applied by
us, affecting the comparability of the financial statements, are: 126




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(i)
    
    the new methods for translating the financial statements of
foreign subsidiaries stated in foreign currency were not applied
retroactively; and(ii)
    
    the beginning balances resulting from the recognition,
measurement, and booking of financial instruments qualified as
effective hedge were not corrected. LIQUIDITY AND CAPITAL RESOURCES The discussion below regarding our liquidity and capital resources relates
to Petrobras Energía and its consolidated controlled subsidiaries. Beginning
in 2003, in accordance with Argentine GAAP, we are required to consolidate
proportionally the results and financial conditions of companies that we
control jointly with other persons. The discussion below generally excludes
these jointly controlled companies, and as a result may not be directly
comparable to amounts reflected in the financial statements included in this
annual report. CIESA and Distrilec, the two companies that are consolidated
proportionally in our financial statements, are principally engaged, through
TGS and Edesur, respectively, in regulated energy businesses in Argentina and
have been significantly affected by the Argentine crisis and the enactment of
the Public Emergency Law. Of these companies, CIESA and TGS are currently in
default on their financial indebtedness. There are significant uncertainties
regarding the ability of CIESA and TGS to continue operating as going concern.
We are under no obligation to financially support CIESA, TGS and Distrilec and
do not currently intend to do so. We did not receive any dividends from the
companies in 2003 or 2002. Our management analyzes our results and financial
condition separately from the results and financial conditions of these
companies, and we believe presenting our financial information without
proportional consolidation with respect to these companies is useful to
investors in evaluating our financial condition and results of operations. See
"Overview. The ability of Argentine companies to access bank loans and capital
markets over the last few years has been affected by the economic recession and
political instability in Argentina. The size and complexity of the Argentine
crisis by the end of 2001 significantly affected the liquidity,
creditworthiness and profitability of most Argentine companies and severely
limited their ability to access foreign and Argentine financial markets in the
near and medium term. In light of Argentinas default on its sovereign debt,
it is expected that these difficulties will persist for at least the next few
years. Our goal is to consistently maintain high levels of liquidity as a way to
reduce financial risks and provide flexibility to overcome the difficult
conditions and high volatility of Argentine financial markets and of emerging
capital markets as a whole. In 2002, as a consequence of the Argentine governments default on most of
its financial obligations, the restrictions imposed by the government on bank
withdrawals and transfers abroad, the deepening recession and an unprecedented
political instability, our liquidity was materially affected. The crisis
limited our ability to renew short-term lines of credit and the current portion
of medium- and long-term financings at maturity. The difficulties in accessing
medium- and long-term borrowings resulted in a significant shortening of
medium-term maturities of our debt. For further details see Financing
Activities and Description of Indebtedness. In addition, the change in the economic financial equation of the utility
companies (see Economic and Political Developments in ArgentinaValuation of
Our Interests in Utility Companies) also affected our liquidity. In 2001, we
received cash dividends from our related companies in the amount of P$65
million, P$52 million of which we received directly or indirectly from TGS,
Edesur and Citelec. During 2002 and 2003, we received no dividends from any
related utility company. In order to secure compliance with financial commitments and at the same
time support our growth strategy, since 2002 we have implemented a financial
management plan that prioritizes the strict monitoring of liquidity levels.
Along these lines, an action plan was implemented in 2002 which mainly focused
on the refinancing of a substantial portion of our financial debt (see
"Financing Activities and Description of Indebtedness) and the significant
reduction in our investment plan (see Factors Affecting Our Consolidated
Results of OperationsDecline in Historical Capital Expenditures). The
refinancing plan executed during 2002 extended the debt maturity profile of our
debt from 2 to 3.9 years. We believe that the success of our refinancing 127




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plan evidences the confidence in our business prospects that is held by
investors and local and international financial institutions. In the medium-term, we will seek to gradually reduce our level of
indebtedness, in order to optimize our debt to capital ratio. We expect to
accomplish this, in part, by generally limiting the level of our investments to
cash generated internally and funds obtained from project financings, giving
priority to projects with better potential of generating profits on an
accelerated basis. Thus far, we have had success in the implementation of this policy, as
evidenced by the following developments:  
    
    during 2003, we registered an 89% growth in our operating
cash flow (excluding companies under joint control);
    
    Petrobras Energía and its subsidiaries under sole control
have paid all of the financial obligations that have come due, while
registering an 8% decline in their average annual indebtedness in
2003 as compared to 2002; and
    
    during 2003, we increased our capital expenditures as
compared to 2002. Additionally, with the issuance in October 2003 of U.S.$100 million
aggregate principal amount of our Series R notes, we became the first company
to place an issuance, which was not in connection with a debt restructuring, in
the international markets following the Argentine governments default. The
proceeds from this issuance were used to repay short-term liabilities,
resulting in an extension of the average life of our outstanding debt and an
improvement of our debt profile. Cash The table below reflects our cash and cash equivalents at December 31,
2003, 2002 and 2001 and the net cash provided by (used in) operations,
investing activities and financing activities during 2003, 2002 and 2001 under
the proportional consolidation method as is required by Argentine GAAP
beginning in 2003, as compared to such data excluding the proportional
consolidation of the companies under joint control. See Overview. With Proportional
    
    Without ProportionalConsolidation
    
    Consolidation2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Cash and cash equivalents at beginning of
period(1)
    
    
    725
    
    
    
    1,333
    
    
    
    565
    
    
    
    693
    
    
    
    1,256
    
    
    
    565Additions (deductions) of cash and cash
equivalents from proportional interest in CIESA at
beginning of period
    
    
    103
    
    
    
    (64
    )
    
    
    71
    
    
    
    
    
    
    
    
    
    
    
    Net cash provided by operations
    
    
    1,353
    
    
    
    710
    
    
    
    1,725
    
    
    
    1,003
    
    
    
    532
    
    
    
    1,459Net cash used in investing activities
    
    
    (915
    )
    
    
    (182
    )
    
    
    (1,924
    )
    
    
    (857
    )
    
    
    (114
    )
    
    
    (1,592
    )Net cash provided by (used in) financing activities
    
    
    (251
    )
    
    
    (1,827
    )
    
    
    896
    
    
    
    (206
    )
    
    
    (1,754
    )
    
    
    824Devaluation and inflation effects on cash
    
    
    (88
    )
    
    
    755
    
    
    
    
    
    
    
    (88
    )
    
    
    773
    
    
    
    Cash and cash equivalents at end of period
    
    
    927
    
    
    
    725
    
    
    
    1,333
    
    
    
    545
    
    
    
    693
    
    
    
    1,256
   (1)
    
    For 2003 and 2001, this amount does not include cash and cash
equivalents from our proportional interest in CIESA. As of December 31, 2003, cash and cash equivalents, excluding the
proportional consolidation of companies under joint control, totaled P$545
million, compared to P$693 million as of December 31, 2002 and P$1,256 million
as of December 31, 2001. The inability to access capital markets during 2002
resulted in a significant drop in our liquidity level. As explained above, we
have since then instituted a financial plan that strictly monitors liquidity
levels. The reduction in our liquidity level in 2003 is in line with the
increase in our net investment levels during 2003 as compared to 2002. Our goal is to maintain excess cash primarily in U.S. dollars. 128




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Operating Activities Net cash from operations, excluding the proportional consolidation of
companies under joint control, was P$1,003 million, P$532 million and P$1,459
million for 2003, 2002 and 2001, respectively. In 2003, net cash from operations increased P$471 million, mainly due to
the increase in the WTI, which contributed to the increase in margins for the
refining and the oil and gas exploration and production segments, a decrease in
interest expense and a reduction in losses attributable to derivatives
instruments used to hedge the price of crude oil. In 2002, net cash from operations decreased P$927 million mainly due to:
(i) an increase in net financial expenses on account of the Argentine peso
devaluation, (ii) the inclusion in 2001 of a P$244 million inflow from the
assignment to international financial institutions of a portion of the fees we
will receive from PDVSA for the exploitation of the Oritupano Leona area, (iii)
increased cash operating requirements, especially on account of the
regularization of payments to suppliers in Venezuela, and (iv) a significant
drop in dividends received from related companies, in line with the crisis
affecting utility companies. These factors were partially offset by the
dollar-denominated flow from foreign operations and by increased marketing
margins in pesos from Argentine operations, resulting from higher local sales
prices and increasing exports. In 2003 and 2002, we made advanced payments of P$442 million and P$311
million, respectively, to meet the collateral requirements of our hedging
operations, due to increased WTI future prices (see Item 11. Quantitative and
Qualitative Disclosures About Market Risk). In these years, we also made
payments of P$51 million and P$149 million, respectively, as collateral in
connection with letters of credit that guarantee our investment commitments in
Ecuador. Investing Activities Cash used in investing activities, excluding the proportional
consolidation of companies under joint control, was P$857 million in 2003,
P$114 million in 2002 and P$1,592 million in 2001. Capital expenditures totaled P$778 million in 2003, P$732 million in 2002
and P$1,756 million in 2001. Capital expenditures made in the Oil and Gas Exploration and Production
business segments totaled P$696 million in 2003, P$596 million in 2002 and
P$1,580 million in 2001. Investments during these last three years have
generally focused on enhancing production and reservoirs through development
drilling, secondary recovery and workover activities, as well as infrastructure
projects. Capital expenditures in 2002 and 2003 were primarily focused on
maintaining production and maximizing cash flow, giving priority to countries
and products having greater potential to contribute to our business. In
particular, during 2003, we undertook important infrastructure projects,
particularly outside of Argentina, aimed at increasing the yield and operating
capacity of our fields, allowing us to increase production volumes with higher
efficiency. During 2003, 206 wells were drilled (compared to 142 wells in
2002), 185 of which are located in Argentina, and 288 units were repaired
(compared to 231 in 2002), 159 of which were located in Argentina. Capital expenditures in the Refining and Petrochemicals business segments
totaled P$57 million in 2003, P$86 million in 2002 and P$59 million in 2001.
Our capital expenditures in these segments during 2003 were mainly directed at
maintaining efficient operating conditions at the plants. In 2002, we acquired
a 19% additional interest in EBR, for P$60 million. In addition, during 2002
we invested P$26 million, primarily in the development of the commercial
network. In the Hydrocarbon Marketing and Transportation business segment, during
2003 we made capital contributions to OCP in the amount of P$11 million, while
in 2002, we were required to disburse P$39 million to maintain letters of
credit that secure our investment commitments in connection with OCP. 129




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Capital expenditures made outside of Argentina accounted for approximately
62% of the capital expenditures budget for the 2003-2001 period, totaling
P$2,033 million. These figures reflect our long-term strategy to grow as an
integrated energy company in Latin America. Significant sources of cash were generated by the sale of non-strategic
equity and fixed assets during 2002 and 2001. These sales generated P$593
million in 2002 and P$226 million in 2001. In 2002, we sold our interest in
Cerro Vanguardia and our forestry and agricultural business assets. In 2001,
we sold our interest in the Pampa del CastilloLa Guitarra area and in
Terminales Marítimas Patagónicas. See Item 4. Information About UsBusiness
OverviewDiscontinued Investments for more information on our recent
divestitures. During 2003, we received approximately P$20 million from the
sale of oil blocks. In 2003, our net investments increased P$619 million, or 445%, reflecting
Argentinas economic recovery during this year and the improvements to our
operating cash flows and liquidity levels. Our capital expenditure program has
been concentrated in the Oil and Gas Exploration and Production business
segment. Financing Activities Net cash provided by (used in) financing activities, excluding the
proportional consolidation of companies under joint control, totaled P$(206)
million in 2003, P$(1,754) million in 2002 and P$824 million in 2001. In 2003, we paid off long-term liabilities in the amount of P$629 million.
These included Series E, J and L notes, which were repaid at maturity, for an
aggregate amount of P$421 million (U.S.$166 million). In addition, during
2003, we repaid bank loans and long-term lines of credit in an aggregate amount
of P$208 million. In 2002, long-term liabilities in the amount of P$1,724 million were paid
or cancelled, including:  
    
    Fifth Series of notes in an aggregate amount of P$841 million
(U.S.$177 million), issued under the U.S.$1.2 billion global note
program, which were paid in March 2002;
    
    financial debt with an aggregate principal amount of
approximately P$553 million (U.S.$144 million), which was cancelled
pursuant to the terms and conditions of the exchange offers launched
to refinance our overall debt; and
    
    outstanding notes in aggregate principal amount of P$86
million (U.S.$22 million) issued under PASA S.A.s global note
program (later absorbed by us), which were repaid at maturity. In 2001, we paid P$1,047 million in principal amount of financial debt,
P$659 million of which was applied to pay off a U.S.$300 million syndicated
loan due December 2001 and P$357 million to pay off, principally, lines of
credit for foreign trade operations. During 2002 we designed and completed an overall refinancing of a
substantial portion of our financial debt. The main purpose of refinancing was
to align principal payments in line with expectations regarding cash flow to be
provided by operations, and to establish a manageable debt maturity schedule.
In August 2002 we issued corporate notes with a face value of U.S.$845 million
in connection with an exchange offer. Simultaneously, and in line with the
conditions of the offer, we repaid U.S.$70 million of notes. In October 2002,
we refinanced financial liabilities in an aggregate amount of approximately
U.S.$849 million, through the issue of new corporate notes in an amount of
approximately U.S.$600 million and other medium-term credit instruments in the
amount of approximately U.S.$249 million. We simultaneously paid off debt in
the amount of U.S.$74 million. The credit instruments issued under this
refinancing plan replaced short-term letters of credit, previously used as
performance bonds. These new credit instruments comply with our financial
obligations related to (i) our hedge agreements of crude oil prices at U.S.$50
million, and (ii) our capital contribution commitments to OCP (including our
commercial obligations under the ship or pay agreement with OCP and OCPs
financial obligations of U.S.$199 million). Long-term letters of credit issued
under these credit facilities are due on an annual basis, but may be
automatically extended for successive annual terms until (i) December 2005 for
the letters of credit related to the crude oil derivative agreements, or (ii)
October 2007 for obligations related to OCP. If these letters of credit are
not renewed 130




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on their respective maturity dates, they must be disbursed, and
thereafter, they will constitute new loans for us. These refinancings
significantly improved our debt maturity profile, extending debt life from 2 to
3.9 years. Cash provided by long-term financing totaled P$591 million in 2003, P$124
million in 2002 and P$1,011 million in 2001, as described below: Our long-term financing in 2003 included the following:  
    
    In October 2003, we issued Class R medium-term notes for an
aggregate principal amount of P$286 million (U.S.$100 million).
    
    In December 2003, our subsidiary Petrobras Energía Venezuela
S.A., or PEV S.A., received P$206 million corresponding to the first
disbursement of U.S.$76 million under a U.S.$105 million loan
agreement between PEV S.A. and International Finance Corporation.
The financing facility consists of loans with terms of up to nine
years to be used in the investment plan for developing our oil
reserves in Venezuela. As of the date of this annual report, we
have received the whole outstanding amount.
    
    In August 2003, our wholly-owned subsidiary Petrobras Energía
del Perú S.A. received a first disbursement of P$87 million (U.S.$30
million) under a U.S.$40 million loan entered into with Banco de
Crédito del Perú and Interbank to finance its investment plan for
developing our oil reserves in Peru. As of the date of this annual
report, we have received the whole outstanding amount. In 2002, we issued Class E notes in the amount of P$124 million (U.S.$35
million), which were repaid at maturity in March 2003. In 2001, we issued Class C notes in the amount of P$483 million (U.S.$220
million), due 2005. The Class C notes accrued interest at LIBOR plus 2.5% in
the first year, 2.75% in the second year and will accrue interest at LIBOR plus
3% for the third and fourth years. Under this particular financing
arrangement, in the event that currency transferability restrictions are
imposed by the government of Argentina and we are unable to make debt service
payments in cash offshore, we will make debt service payments in crude oil. If
payment is made in kind, the volume delivered to the holders of the Class C
notes will be priced at the WTI spot price at the time, with the guaranteed
minimum price for such oil set at U.S.$15 per barrel. In connection with the
contingent requirement to deliver crude oil, we entered into an Oil Marketing
and Delivery Agreement dated July 17, 2001 between Petrobras Energía as Issuer
and Deutsche Bank AG, London Branch, as Oil Purchaser; and a Crude Oil Purchase
and Delivery Contract dated July 17, 2001 among Petrobras Energía, as Issuer,
Deutsche Bank AG, London Branch, as Oil Purchaser and Bankers Trust Company as
Oil Agent and Administrative Agent. These agreements provide that, in the
event of a payment being made in oil, the crude oil would be purchased by the
Oil Purchaser from the Oil Agent on the terms and conditions and at a
market-related price set out in those agreements. In addition, in 2001, cash provided by foreign lines of credit amounted to
P$287 million; cash provided by foreign trade financing totaled P$163 million,
and cash from the last tranche of the loan granted by the IFC to Innova
amounted to P$78 million. Net cash used to pay short-term financing totaled P$168 million in 2003
and P$94 million in 2002. The combination of the Argentine and Venezuelan
crises limited our ability to renew short-term lines of credit at maturity.
Conversely, during 2001, cash provided by short-term financing amounted to
P$1,025 million, mainly attributable to short-term notes issued in November
2001 in the amount of P$344 million (U.S.$156.5 million) and short-term bank
loans, including loans related to trade financing. Description of Indebtedness All of our financial debt and a significant portion of the debt of our
principal affiliates is denominated in U.S. dollars. 131




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As of December 31, 2003, our total indebtedness, excluding the
proportional consolidation of companies under joint control, was P$6,063
million, P$5,009 million of which was long-term indebtedness. As of such date,
our short-term indebtedness totaled P$1,054 million, P$919 million of which
represents the current portion of long-term obligations and P$135 million of
which is short-term indebtedness with financial institutions under loan
agreements or promissory notes. In addition, our consolidated financial
statements include debt of P$2,239, principally debt that is in default, owed
by our affiliates under joint control. See Factors Affecting Our
Consolidated Results of OperationsImpact on our Investments in Utility
Companies. The following is our debt maturity profile, excluding the proportional
consolidation of companies under joint control, expressed both in millions of
pesos and millions of U.S. dollars as of December 31, 2003: Maturity
    
    1 year
    
    2 years
    
    3 years
    
    4 years
    
    5 years
    
    6 or more yearsMillions of Pesos
    
    P$1,054
    
    P$971
    
    P$480
    
    P$1,284
    
    P$48
    
    P$2,226Millions of U.S. dollars
    
    U.S.$358
    
    U.S.$330
    
    U.S.$163
    
    U.S.$437
    
    U.S.$16
    
    U.S.$757
 Our long-term debt primarily consists of corporate notes. Our remaining
long-term debt is mainly related to bank loans obtained by foreign subsidiaries
and import credit lines used to finance the construction of the Genelba Power
Plant and Innova plant. Petrobras Energía maintains a five-year corporate global note program, or
the Global Program, for a principal amount at any time outstanding of U.S.$2.5
billion or its equivalent in any currency, which was due to expire in May 2003,
but was extended for five additional years. As of May 31, 2004, notes in an
aggregate principal amount of U.S.$1,724 million were outstanding under this
program. Notes under the program are not subject to acceleration in the event
our credit ratings are downgraded. As of May 31, 2004, notes outstanding under the Global Program were:  
    
    Class B, in an aggregate principal amount of U.S.$5 million
notes, payable in a single installment in May 2006, at a 9% fixed
annual rate;
    
    Class C, for U.S.$220 million, with the final maturity in
July 2005, to be amortized in quarterly installments beginning in
2004. Class C notes accrue interest at LIBOR plus 2.50% for the
first year, 2.75% for the second year, and 3% for the third and
fourth years. As of May 31, 2004, the total amount outstanding was
U.S.$157 million; Petrobras Energía has called a
bondholders meeting to be held on July 30, 2004 in order
to ratify Petrobras Energías interpretation of the prepayment
provisions of these notes, so that partial prepayment may be applied
to one or more installments of principal as determined by Petrobras
Energía;
    
    Class F, in an aggregate principal amount of U.S.$64.4
million maturing in August 2005, at a 7.875% annual rate;
    
    Class G, in an aggregate principal amount of U.S.$250 million
maturing in January 2007, at a 9% annual rate;
    
    Class H, in an aggregate principal amount of U.S.$181.5
million maturing in May 2009, at a 9% annual rate;
    
    Class I, in an aggregate principal amount of U.S.$349.2
million maturing in July 2010, at an 8.125% annual rate;
    
    Class K, in an aggregate principal amount of U.S.$286.3
million, amortized in quarterly installments from January 2004 and
with final maturity date in October 2007, accruing interest at three
month LIBOR plus 4% per annum. As of May 31, 2004, the total amount
outstanding was U.S.$260 million;
    
    Class M, in an aggregate principal amount of U.S.$181.8
million, amortized in quarterly installments from January 2004 and
with final maturity date in October 2007, accruing interest at three
month LIBOR plus 4.75% per annum. As of May 31, 2004, the total
amount outstanding was U.S.$165 million; 132




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
    
    Class N, in an aggregate principal amount of U.S.$97 million,
with principal amortized in two installments, the firstequivalent
to 9.9099% of face valuesettled on the day of issuance and the
remainder due in June 2011, accruing interest at six-month LIBOR
plus 1% (issued in January 2003). As of May 31, 2004, the total
amount outstanding was U.S.$ 87 million;
    
    Class Q, in an aggregate principal amount of U.S.$4.0
million, with principal amortized in two installments, the
firstequivalent to 10% of face valueon the date of issuance, April
25, 2003; and the balance in April 2008. These bonds accrue
interest at 5.625%. As of May 31, 2004, the total amount outstanding
was U.S.$3.6 million; and
    
    Class R, in an aggregate principal amount of U.S.$200
million, with final maturity in October 2013, accruing interest at a
9.375% annual rate (issued in U.S.$100 million tranches in October
2003 and in April 2004). In addition, Petrobras Energía has a U.S.$1.2 billion global medium-term
note program. In June 1998, the right to issue new notes under this program
expired. On December 31, 2003, two series of notes remained outstanding under
this program. One of the series was paid in January 2004, and the other, with
an aggregate principal amount of U.S.$32.6 million, matures in July 2007,
accruing interest at 8.125%. Covenants Class F, G, H, I, N, Q and R notes include cross default covenants,
whereby the trustee, as instructed by the noteholders representing at least 25%
of the related outstanding capital, shall declare all the amounts owed due and
payable, if any debt of ours or our significant subsidiaries is not paid at
maturity, provided that those due and unpaid amounts exceed the higher of
U.S.$25 million or 1% of our shareholders equity at that time, and that the
default has not been cured within 30 days after we have been served notice of
the default. Class K and M notes include cross default covenants, whereby the trustee,
as instructed by the noteholders representing at least the majority of the
respective outstanding capital, shall declare all of the amounts owed due and
payable, if any debt of ours or our significant subsidiaries is not paid at the
maturity date, provided that those due and unpaid amounts exceed the higher of
U.S.$15 million or 1% of our shareholders equity at the time. Class C notes, as well as certain loan agreements, include cross default
covenants, whereby the trustee or the creditor bank, as appropriate, shall
declare all the amounts owed as due and payable, if any of our debt is not paid
at maturity, provided that those due and unpaid amounts exceed U.S.$10 million
or 1% of our shareholders equity at the time. For so long as the Class K and M notes and medium-term credit instruments
remain outstanding, we will be subject to certain restrictions and must comply
with certain covenants as described below:  (i)
    
    Restrictions on capital expenditures: We shall not make any
capital expenditure, including the amount of debt incurred in
relation thereto, in excess of U.S.$450 million in 2004, U.S.$425
million in 2005 and U.S.$475 million in 2006 and 2007, which limits
shall be increased under certain circumstances.(ii)
    
    Restrictions on the incurrence of additional debt: We shall
not incur any financial debt as long as, after giving effect to the
issuance and application of the proceeds thereof, the ratio of: (A)
consolidated financial debt, to (B) consolidated EBITDA (defined as
gross profit less administrative, selling and exploration expenses,
plus depreciation and amortization, dividends and advisory services
collected) exceeds 3.5. This restriction is not applicable to
subordinated debt, project financings and refinancings.(iii)
    
    Compliance with certain ratio tests: We must comply with
certain financial ratio tests including (A) consolidated financial
debt (excluding subordinated debt) to consolidated EBITDA, which 133




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shall not be greater than 3.5 to 1.0 in 2004 and 3.0 to 1.0 from
2005 through 2007, and (B) EBITDA to interest expense, which shall
not be lower than 3.0 to 1.0 from 2004 through 2007.(iv)
    
    Restrictions on the amount of short-term debt: At any time,
our short-term financial debt shall not exceed an amount equal to
U.S.$650 million.(v)
    
    Mandatory prepayments: Within 120 days from the end of each
fiscal year, we must use up to 50% of our excess cash to redeem on a
pro rata basis the Series K and M notes and the medium-term credit
instruments. In addition, proceeds from sales of assets (other than
those that constitute the business purpose) not reinvested within
approximately one year, and 50% of the proceeds from new debt, must
be used to make mandatory prepayments.(vi)
    
    Limitation on liens.(vii)
    
    Restrictions on the payment of dividends. These restrictions and covenants may have a negative effect on our ability
to implement our investment plan or obtain additional financing and may
negatively affect our results of operations. Future Capital Requirements Our 2004 budget provides for a continued recovery in the level of our
investments, as we expect to continue moving beyond the economic crisis that
gripped Argentina in 2002. We expect the level of our investment to gradually
increase to our historical levels. Increased investments are crucial to our
future growth objectives. Our 2004 budget contemplates investments totaling approximately U.S.$350
million, which will be directed primarily towards the Oil and Gas Production
and Exploration segment, with a strong emphasis on our operations in Argentina
and Venezuela. We currently expect to conduct significant well-drilling
campaigns in 2004, particularly at mature fields in Argentina, with the goal of
maintaining production levels. In addition, we currently expect to make
investments in infrastructure projects, with the goal of increasing the yield
of our reserves, improving oil treatment quality and increasing secondary
recovery. Our investments in the Refining and Petrochemicals segments will focus on
optimizing efficiency levels. Moreover, we expect to continue expanding the
retail commercial network, while taking advantage of the synergies provided by
the Petrobras brand. With respect to our fertilizers business, we currently
expect to launch construction works of a new thiosulphate plant. We currently expect that our investment requirements, financial debt
payment obligations and working capital will be financed by cash from
operations, and, to a lesser extent, new debt financings. We can offer no assurance that we will be able to make the level of
investments discussed above, since our level of investments will depend on a
variety of factors, many of which are beyond our control. These include the
future price evolution of the commodities we sell, the outcome of the
renegotiation of utility rates, the renegotiation of concession contracts of
the privatized companies, the behavior of energy demand in Argentina and in
regional markets, the existence and competitive impact of alternative projects,
government regulation, the economic situation prevailing in Argentina and the
Mercosur region, the availability of financing and the evolution of the peso
exchange rate. OFF-BALANCE SHEET TRANSACTIONS Other than the transactions described below, we do not have any
off-balance sheet arrangements required to be disclosed by Item 5 of Form 20-F. 134




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OCP Investments Letters of Credit To secure our commercial obligations under the ship or pay contract with
OCP and OCPs financial obligations, we have obtained letters of credit for a
total amount of approximately U.S.$224 million. Of this amount, U.S.$199
million must be secured by cash collateral. As of December 31, 2003 we had
deposited U.S.$55 million of this cash collateral. We must deposit the balance
of this cash collateral on a yearly basis according to the following schedule: (in millions of U.S.$)
    
    2004
    
    2005
    
    2006
    
    2007
    
    Total32
    
    
    
    38
    
    
    
    37
    
    
    
    37
    
    
    
    144
 These letters of credit must remain in place until our OCP investment
obligations and commitments expire or are terminated. We are required to renew
or replace these letters of credit as they mature. Otherwise, we will be
required to repay the amounts due in cash at maturity, which will have a
material adverse effect on our cash flows. Derivative Financial Instruments We have commitments under derivative financial instruments. For a
discussion of these additional commitments see Item 11. Quantitative and
Qualitative Disclosure About Market Risk. As of December 31, 2003 the fair
value of our outstanding oil derivative financial instruments represented
accounts payable to counterparties in the amount of U.S.$185 million. In
connection therewith, as of that date we had standby letters of credit in place
in favor of these counterparties with total commitments of U.S.$31 million and
cash collaterals amounting to U.S.$136 million. Oritupano Leona Revenues Assignment In December 2001, we assigned to an international lending institution
U.S.$120 million in future capital fees to be collected from PDVSA under our
operating agreement for the Oritupano Leona area. Capital fees assigned are
payable by PDVSA in twelve quarterly, equal and consecutive installments
starting February 2002. This transaction, net of the discount calculated at
LIBOR plus 2.75%, provided us cash in the amount of U.S.$110 million. In order
to guarantee to the lending institution that PDVSA will meet its obligations
under this operating agreement, we assigned an additional U.S.$10 million of
future capital fees to such institution. Should PDVSA not settle any amount
payable on this account by the due date and such noncompliance stems from any
commercial challenge or claim that PDVSA may have with respect to our billings
for investments made, we are required to either assign to the lending
institution additional capital fees in an amount equivalent to the amount being
challenged, or pay amounts due in cash. This assignment does not release the
members of the consortium from the obligations under the operating agreement
for the area. 135




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##### Table of Contents



CONTRACTUAL OBLIGATIONS The following table summarizes certain contractual obligations as of December
31, 2003. The table does not include accounts payable or pension liabilities. Payments due by period(in millions of pesos)Less than 1
    
    
    
    
    
    
    
    
    
    More thanTotal
    
    Year
    
    1 - 3 years
    
    3 - 5 years
    
    5 yearsDebt Obligations
    
    
    6,063
    
    
    
    1,054
    
    
    
    1,451
    
    
    
    1,332
    
    
    
    2,226Significant Operating Lease Obligations
    
    
    2
    
    
    
    1
    
    
    
    1
    
    
    
    
    
    
    
    Purchase Obligations:Ship or pay agreement with OCP (1)
    
    
    3,298
    
    
    
    220
    
    
    
    440
    
    
    
    440
    
    
    
    2,198Longterm service agreement
    
    
    141
    
    
    
    25
    
    
    
    54
    
    
    
    62
    
    
    
    Gas transportation agreement with TGS (2)
    
    
    300
    
    
    
    30
    
    
    
    60
    
    
    
    60
    
    
    
    150Ethylene (3)
    
    
    550
    
    
    
    50
    
    
    
    100
    
    
    
    100
    
    
    
    300Benzene (4)
    
    
    1,233
    
    
    
    112
    
    
    
    224
    
    
    
    224
    
    
    
    673Total
    
    
    11,587
    
    
    
    1,492
    
    
    
    2,330
    
    
    
    2,218
    
    
    
    5,547
   (1)
    
    Estimated price P$7.53 per bbl.(5)(2)
    
    Estimated price P$0.025 million per MMm3.(5)(3)
    
    Estimated price U.S.$555 per ton.(5)
Contractual prices are in dollars. Peso amounts translated using
exchange rate as of December 31, 2003.(4)
    
    Estimated price U.S.$451 per ton.(5) Contractual prices are in dollars. Peso amounts translated using
exchange rate as of December 31, 2003.(5)
    
    Our obligations under these agreements are determined by volume, and
prices are generally determined by formula based on future market prices of the
goods or services under each contract. In addition, the estimated prices used
to calculate the monetary equivalent of these purchase obligations are based on
current market prices as of December 31, 2003 and may not reflect actual future
prices of these commodities. Accordingly, the peso amounts provided in this
table with respect to these obligations are provided for illustrative purposes
only. The following table sets forth volume information with regard to our
commitments under commercial contracts for which a fixed price has been agreed,
for the years indicated below, as of December 31, 2003. Obligations by periodLess
    
    
    
    
    
    
    
    
    
    Morethan 1
    
    1 - 3
    
    3 - 5
    
    than 5Total
    
    Year
    
    years
    
    years
    
    yearsPurchase ObligationsShip or pay agreement with OCP (in millions of bbls)
    
    
    438
    
    
    
    29
    
    
    
    58
    
    
    
    58
    
    
    
    293Gas transportation agreement with TGS (in MMm3)
    
    
    11,873
    
    
    
    1,199
    
    
    
    2,398
    
    
    
    2,398
    
    
    
    5,878Ethylene (in thousands of tons)
    
    
    337
    
    
    
    31
    
    
    
    61
    
    
    
    61
    
    
    
    184Benzene (in thousands of tons)
    
    
    930
    
    
    
    85
    
    
    
    169
    
    
    
    169
    
    
    
    507Sales ObligationsNatural gas (in MMm3)
    
    
    18,854
    
    
    
    2,609
    
    
    
    3,451
    
    
    
    2,730
    
    
    
    10,064Styrene (in thousands of tons)
    
    
    56
    
    
    
    39
    
    
    
    16
    
    
    
    1
    
    
    
    Electric power (in MWh)
    
    
    329,115
    
    
    
    329,115
    
    
    
    
    
    
    
    
    
    
    
    
 Long Term Service Agreement. We have entered into a long term service
agreement for the maintenance and repair of the Genelba Power Plant. OCP Oil Transportation Agreement. Regarding the future exploitation of
Blocks 18 and 31, we have executed an agreement with OCP whereby it has
obtained an oil transportation capacity of 80,000 bbls/d for a term of 15 years
as from commencement of OCP operations. We, as well as the remaining
producers, shall pay a ship or pay fee that will cover, among other items,
OCPs operating costs and financial services. Innova Supply Agreements. Benzene and ethylene feedstock, necessary for
Innova operations, are supplied by Copesul, a Brazilian company, pursuant to a
long-term contract that expires in 2014. 136




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##### Table of Contents



Gas Transportation Agreements. We have entered into various gas firm
transportation agreements with TGS to provide gas transportation services to
our Genelba Power Plant. Exploration Commitments. Regarding the exploration and development of our
oil and gas fields, we have minimum investment commitments amounting to U.S.$7
million through 2005. U.S. GAAP RECONCILIATION We had net income under U.S. GAAP of P$100 million in 2003, as compared to
net losses of P$1,554 million in 2002 and P$2,266 million in 2001. Under
Argentine GAAP, we reported net income of P$381 million in 2003 and P$101
million in 2001, as compared to a net loss of P$1,579 million in 2002. There are several differences between Argentine GAAP and U.S. GAAP that
significantly affect our net income and stockholders equity. The most
significant differences in their effect on 2003 net income related to foreign
currency translation adjustments, the depreciation of property, plant and
equipment, the accounting for derivative instruments and deferred income taxes.
See note 23 to our financial statements. Neither the effects of inflation
accounting nor the proportional consolidation of Distrilec, a company under
joint control, under Argentine GAAP have been reversed in the reconciliation to
U.S. GAAP. The proporational consolidation of CIESA, another company under
joint control, in 2001 and 2003 under Argentine GAAP has been reversed in the
reconciliation to U.S. GAAP. RECONCILIATION TABLES The following tables reconciliate our results for the years ended December
31, 2001, 2002 and 2003 with proportional consolidation as required by new
changes to Argentine GAAP to our results as adjusted to reflect the
elimination of proportional consolidation: For the Year EndedDecember 31, 2003With
    
    
    
    
    
    
    
    
    
    WithoutProportional
    
    
    
    
    
    
    
    
    
    ProportionalConsolidation
    
    CIESA(1)
    
    Distrilec(2)
    
    ConsolidationNet sales
    
    
    5,494
    
    
    
    (432
    )
    
    
    (447
    )
    
    
    4,615Costs of sales
    
    
    (3,386
    )
    
    
    200
    
    
    
    373
    
    
    
    (2,813
    )Gross profit
    
    
    2,108
    
    
    
    (232
    )
    
    
    (74
    )
    
    
    1,802Administrative and selling
expenses
    
    
    (559
    )
    
    
    30
    
    
    
    65
    
    
    
    (464
    )Exploration expenses
    
    
    (196
    )
    
    
    
    
    
    
    
    
    
    
    (196
    )Other exploitation income (loss)
net
    
    
    (121
    )
    
    
    12
    
    
    
    5
    
    
    
    (104
    )Exploitation income
    
    
    1,232
    
    
    
    (190
    )
    
    
    (4
    )
    
    
    1,038Equity in earnings of affiliates
    
    
    163
    
    
    
    221
    
    
    
    (11
    )
    
    
    373Financial income (expense) and
holding gains (losses)
    
    
    (417
    )
    
    
    (124
    )
    
    
    (28
    )
    
    
    (569
    )Other expenses, net
    
    
    (421
    )
    
    
    1
    
    
    
    13
    
    
    
    (407
    )Income (loss) before income tax
and minority interest in
subsidiaries
    
    
    557
    
    
    
    (92
    )
    
    
    (30
    )
    
    
    435Income tax provision
    
    
    (18
    )
    
    
    (58
    )
    
    
    29
    
    
    
    (47
    )Minority interest in subsidiaries
    
    
    (158
    )
    
    
    150
    
    
    
    1
    
    
    
    (7
    )Net income (loss)
    
    
    381
    
    
    
    
    
    
    
    
    
    
    
    381
   (1)
    
    The results of CIESA are proportionally consolidated in our Hydrocarbon
segment.(2)
    
    The results of Distrilec are proportionally consolidated in our Electricity
segment. 137




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##### Table of Contents



For the Year EndedDecember 31, 2002With
    
    
    
    
    
    
    
    
    
    WithoutProportional
    
    
    
    
    
    
    
    
    
    ProportionalConsolidation
    
    CIESA(1)
    
    Distrilec(2)
    
    ConsolidationNet sales
    
    
    5,106
    
    
    
    
    
    
    
    (519
    )
    
    
    4,587Costs of sales
    
    
    (3,284
    )
    
    
    
    
    
    
    406
    
    
    
    (2,878
    )Gross profit
    
    
    1,822
    
    
    
    
    
    
    
    (113
    )
    
    
    1,709Administrative and selling
expenses
    
    
    (609
    )
    
    
    
    
    
    
    77
    
    
    
    (532
    )Exploration expenses
    
    
    (58
    )
    
    
    
    
    
    
    
    
    
    
    (58
    )Other exploitation income (loss)
net
    
    
    (28
    )
    
    
    
    
    
    
    
    
    
    
    (28
    )Exploitation income
    
    
    1,127
    
    
    
    
    
    
    
    (36
    )
    
    
    1,091Equity in earnings of affiliates
    
    
    (638
    )
    
    
    
    
    
    
    (9
    )
    
    
    (647
    )Financial income (expense) and
holding gains (losses)
    
    
    (1,827
    )
    
    
    
    
    
    
    168
    
    
    
    (1,659
    )Other expenses, net
    
    
    (187
    )
    
    
    
    
    
    
    9
    
    
    
    (178
    )Income (loss) before income tax
and minority interest in
subsidiaries
    
    
    (1,525
    )
    
    
    
    
    
    
    132
    
    
    
    (1,393
    )Income tax provision
    
    
    (82
    )
    
    
    
    
    
    
    (127
    )
    
    
    (209
    )Minority interest in subsidiaries
    
    
    28
    
    
    
    
    
    
    
    (5
    )
    
    
    23Net income (loss)
    
    
    (1,579
    )
    
    
    
    
    
    
    
    
    
    
    (1,579
    )
   (1)
    
    For the 2002 fiscal year we did not proportionately consolidate on a line
by line basis the assets, liabilities, earnings and cash flow of CIESA, since,
as of December 31, 2002 our equity interest in such company had a P$33 million
negative value.(2)
    
    The results of Distrilec are proportionally consolidated in our Electricity
segment. For the Year EndedDecember 31, 2001With
    
    
    
    
    
    
    
    
    
    WithoutProportional
    
    
    
    
    
    
    
    
    
    ProportionalConsolidation
    
    CIESA(1)
    
    Distrilec(2)
    
    ConsolidationNet sales
    
    
    5,170
    
    
    
    (610
    )
    
    
    (946
    )
    
    
    3,614Costs of sales
    
    
    (3,347
    )
    
    
    234
    
    
    
    654
    
    
    
    (2,459
    )Gross profit
    
    
    1,823
    
    
    
    (376
    )
    
    
    (292
    )
    
    
    1,155Administrative and selling
expenses
    
    
    (665
    )
    
    
    33
    
    
    
    122
    
    
    
    (510
    )Exploration expenses
    
    
    (41
    )
    
    
    
    
    
    
    
    
    
    
    (41
    )Other exploitation income (loss)
net
    
    
    23
    
    
    
    
    
    
    
    (3
    )
    
    
    20Exploitation income
    
    
    1,140
    
    
    
    (343
    )
    
    
    (173
    )
    
    
    624Equity in earnings of affiliates
    
    
    119
    
    
    
    36
    
    
    
    49
    
    
    
    204Financial income (expense) and
holding gains (losses)
    
    
    (573
    )
    
    
    124
    
    
    
    (2
    )
    
    
    (451
    )Other expenses, net
    
    
    (88
    )
    
    
    63
    
    
    
    11
    
    
    
    (14
    )Income (loss) before income tax
and minority interest in
subsidiaries
    
    
    598
    
    
    
    (120
    )
    
    
    (115
    )
    
    
    363Income tax provision
    
    
    (385
    )
    
    
    66
    
    
    
    70
    
    
    
    (249
    )Minority interest in subsidiaries
    
    
    (112
    )
    
    
    54
    
    
    
    45
    
    
    
    (13
    )Net income (loss)
    
    
    101
    
    
    
    
    
    
    
    
    
    
    
    101
   (1)
    
    The results of CIESA are proportionally consolidated in our Hydrocarbon
segment.(2)
    
    The results of Distrilec are proportionally consolidated in our Electricity
segment. 138




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Item 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES DIRECTORS AND SENIOR MANAGEMENT Board of Directors In accordance with our by-laws, the Board of Directors, which formally
meets at least once every three months, shall comprise a minimum of three and a
maximum of nineteen members. Shareholders may appoint a number of alternate
directors that may be equal to or lower than the number of regular directors in
order to fill any vacancy, in the order of their appointment. Directors and
alternate directors are appointed by shareholders at their annual shareholders
meeting for the term of one year and may be reelected. The following table sets out the members and alternate members of our
Board of Directors elected by shareholders at the shareholders meeting held on
March 19, 2004. Year firstYear of
    
    joined
    
    Position
    
    TermName
    
    appointment
    
    Petrobras
    
    
    
    ExpiresJosé Eduardo de Barros Dutra
    
    2003
    
    
    
    Chairman
    
    2005Nestor Cuñat Cerveró
    
    2003
    
    
    
    Vice Chairman
    
    2005Ildo Luis Sauer
    
    2003
    
    
    
    Director
    
    2005José Sergio Gabrielli de Azevedo
    
    2003
    
    
    
    Director
    
    2005Guilherme de Oliveira Estrella
    
    2003
    
    
    
    Director
    
    2005Renato de Souza Duque
    
    2003
    
    
    
    Director
    
    2005Rogério Almeida Manso da Costa
Reis
    
    2003
    
    
    
    Director
    
    2005Luiz Augusto Marciano da Fonseca
    
    2004
    
    
    
    Director
    
    2005Rui Antonio Alves da Fonseca
    
    2004
    
    
    
    Director
    
    2005Alberto da Fonseca Guimarães
    
    2003
    
    2002
    
    Director
    
    2005Oscar Anibal Vicente
    
    1981
    
    1970
    
    Director
    
    2005Cedric Bridger
    
    2004
    
    
    
    Director
    
    2005Héctor Daniel Casal
    
    2003
    
    1991
    
    Director
    
    2005Daniel Maggi
    
    2003
    
    1997
    
    Director
    
    2005Carlos Manuel Alvarez(1)
    
    2003
    
    1981
    
    Director
    
    2005Nicolas Perkins
    
    2004
    
    
    
    Director
    
    2005Roberto Alejandro Fortunati
    
    2004
    
    
    
    Director
    
    2005Carlos Alberto Pereira de Oliveira
    
    2004
    
    
    
    Director
    
    2005Rafael Fernandez Morandé
    
    2004
    
    1997
    
    Director
    
    2005Luis Miguel Sas(1)
    
    2003
    
    1984
    
    Alternate Director
    
    2005Pablo Cavallaro
    
    2004
    
    
    
    Alternate Director
    
    2005
  (1)
    
    Carlos M. Alvarez resigned from the position of director on May 7,
2004. On the same day, Luis Miguel Sas was appointed as a director. In compliance with Resolution No. 368 of the CNV, Nicolas Perkins, Roberto
Alejandro Fortunati and Pablo Cavallaro are independent directors, and the
other directors are not independent in accordance with the CNV rules. Resolution No. 368 provides that a member of a corporate body shall not be
considered independent if that member fits one or more of the following
descriptions:  
    
    The member is also a member of management or an employee of
shareholders who hold significant interests in the issuer, or of
other entities in which these shareholders hold either directly or
indirectly significant interests or over which these shareholders
exercise a significant influence.
    
    The member is an employee of the issuer or has been an
employee in the last three years. 139




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
    
    The member has professional relations or is part of a company
or professional association that maintains professional relations
with, or that receives remunerations or fees (other than directors
fees) from, the issuer or from its shareholders that hold either
directly or indirectly significant interests in or exercise a
significant influence over the issuer, or from which such
shareholders hold either directly or indirectly significant
interests or exercise a significant influence.
    
    The member is either directly or indirectly a holder of
significant interests in the issuer or in an entity that has
significant interests in or exercises a significant influence over
the issuer.
    
    The member sells or provides either directly or indirectly
goods or services to the issuer or to shareholders that hold either
directly or indirectly significant interests in or exercise a
significant influence over the issuer and receives compensation for
such services that is substantially higher than that received as a
director.
    
    The member is married or is a family member, up to fourth
degree by blood or up to second degree by affinity, to an individual
who would not qualify as independent. Significant interests shall mean shareholdings that represent at least
35% of the capital stock of the relevant entity, or a smaller percentage when
the person has the right to elect one or more directors by class of shares or
by having entered into agreements with other shareholders relating to the
governance and the management of the relevant entity or of its controlling
shareholders. The following is a brief summary of the principal business and academic
experience of each of our directors listed in the table above: José Eduardo de Barros Dutra (47)graduated in Geology from Universidade
Federal Rural do Rio de Janeiro, Brazil, in 1979. He carried out a geological
mapping of Rio de Janeiro from 1983 to 1990. In 1994 he was elected Senator of
the Federative Republic of Brazil from the State of Sergipe for the 19952003
period and President of the Sindicato dos Mineiros do Estado de Sergipe (State
of Sergipe Miners Union) from 1989 to 1994. He was a member of the following
Federal Senate Committees of Brazil: Constitutional and Justice, Economic
Affairs, Infrastructure, Education, and Supervision and Control. Mr. Dutra
also served as leader of the Workers Party from 1996 to 1997, and as a member
of the Workers Party National Executive Committee. In January 2003 he was
appointed Chairman of Petrobras. He is also Chairman of Petrobras Energía and
is also a member of the boards of directors of Petrobras Distribuidora S.A. 
BR. Nestor Cuñat Cerveró (52)graduated in Chemical Engineering from
Universidade Federal do Rio de Janeiro, and completed post-graduate studies in
Process Engineering while at Petrobras and MBA courses for managers and
executives at Getúlio Vargas School, in Brazil. He has served in the energy
area in Petrobras Industrial Department since 1984. He currently serves as
International Director of Petrobras, Vice Chairman of Petrobras Energía and
Chairman of Petrolera Entre Lomas S.A. He has worked at Petrobras since 1975,
where he held several positions, including: Energy Manager, Programa de
Termelétricas(Thermoelectrical Plants Program); Thermoelectrical Plants
Manager of the Participations Superintendency; assistant to the CEO for the
development of new ventures and partnerships; and Head of the Energy Sector of
the industrial area. He has also represented Petrobras at the Boards of
Directors of several thermoelectrical energy companies and acted as assistant
to the Presidência da Comercializadora Brasileira de Energia Emergencial
(Presidency of the Brazilian Supplier of Emergencial Energy  CBEE) of the
Ministry of Mines and Energy. Ildo Luis Sauer (49)graduated in Civil Engineering from Universidade
Federal do Rio Grande do Sul, Brazil. He holds a Masters degree in Nuclear
Sciences and Engineering and Energy Planning from Universidade Federal do Rio
de Janeiro and a Ph.D. in Nuclear Engineering from the Massachusetts Institute
of Technology in the United States. He also holds a MSc degree from COPPE -
Federal University of Rio de Janeiro in Energy Planning/Nuclear Power. He is
Professor at the Instituto de Eletrotécnica e Energia da Universidade de São
Paulo (Electrotechnical and Energy Institute of the University of São Paulo),
on leave, where he has published more than 100 technical papers and supervised
more than 40 doctoral and master theses in the field. Previously, he worked as
a consultant at TecSauer Consultoria Ltda. and as manager of the nuclear
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José Sérgio Gabrielli de Azevedo (54)graduated in Economics from
Universidade Federal da Bahía, Brazil, and holds a Masters Degree in Fiscal
Incentives and Regional Development. He served as dean of the Economic
Sciences School of the Federal University of Bahia and superintendent of the
Fundação de Apoio a Pesquisa e Extensão(Foundation for Support of Research and
Extension  Fapex). He was also a visiting researcher at the London School of
Economics and Political Science in 2000 and 2001. He holds a Doctorate in
Economics from Boston University. He currently serves as Chief Financial
Officer and Vice President of Investor Relations at Petrobras and as a Director
of Petrobras Energía. Guilherme de Oliveira Estrella (62)graduated in Geology from Universidade
Federal do Rio de Janeiro, Brazil. He served as an Advisory Director and Vice
President of the Brazilian Geology Society. He was a member of the Brazilian
Paleontology Society and the American Association of Petroleum Geologists and a
Director of the Brazilian Oil Institute. He currently serves as Vice President
of Exploration and Production at Petrobras and Director of Petrobras Energía.
Mr. Estrella has been Managing Director of Exploration and Production of
Petrobras since January 31, 2003. Currently, Mr. Estrella is also a member of
the boards of directors and executive boards of Petrobras Energia S.A., and
also serves as Chairman of the Board of the Instituto Brasileiro de Petróleo e
Gás(Brazilian Oil and Gas Institute). He worked at Petrobras from 1965 until
1994, when he retired as a geologist of our Exploration Department. Before his
retirement, he held several other positions of Petrobras, including: General
Superintendent (1989-1993); Superintendent of Research and Development for
exploration, drilling and production (1985-1989); Head of the Exploration
Division (1981-1985); Head of the Organic Geochemistry Sector (1981); Head of
the Brazilian East Coast Basin Interpretation Sector of the Petrobras
Exploration Department  DEPEX/RJ (1978-1981); and Exploration Manager of
Petrobras Internacional S.A.  BRASPETRO for Iraq (1976-1978). Mr. Estrella
has also served as director of the Instituto Brasileiro de Petróleo e Gás. Renato de Souza Duque (48)graduated in Electrical Engineering from
Universidade Federal Fluminense, Brazil, with a specialization degree in Oil
Engineering and completed post-graduate MBA courses. He joined Petrobras in
1978, and served as Manager of Human Resources for all the operational units in
the Exploration and Production area, Manager of Drilling Operations in the
Campos Basin, Manager of owned platforms, Manager of Well Engineering and
Technology, and Manager of Contracts in the Exploration and Production
division. He currently serves as Vice President of Corporate Services at
Petrobras and a Director of Petrobras Energía. Rogério Almeida Manso da Costa Reis (47)graduated in Civil Engineering
from Universidade do Estado do Rio de Janeiro, Brazil, and holds an MBA from
Stern (New York University). He completed post-graduate courses in Management
at Kellogg (Northwestern University), Instead, IFP-Wharton and Oxford Institute
for Energy Studies. He has worked at Petrobras since 1979, and served as
Managing Director of Marketing and Commercialization, General Manager of Supply
and Deputy General Manager of Logistics. He currently serves as Director of
Supply at Petrobras, member of the Board of Copesul and Alberto Pasqualini S.A.
Refinery, a Director of Petrobras International Finance Company and a Director
of Petrobras Energía. Luis Augusto M. da Fonseca (50)graduated in Electronic Engineering from
Escola de Ingeniería Mauá, São Paulo, with a specialization degree in Oil
Engineering, and obtained a degree in Economics from Universidad do Estado de
Rio de Janeiro. At Petrobras he worked as the company representative to the
Latin American Energy Organization, chief assistant to Petrobras International
Executive Vice President, Manager of Operations in Houston, Officer Director &
Engineering Services Manager at BRASOIL, coordinator of International Relations
with international agencies, OLADE Executive Secretary and Business Development
Manager. He participated in official missions together with government
agencies and energy sector entities of Latin American and Caribbean countries,
multilateral and international cooperation agencies. He currently is Vice
President of Communications of Petrobras Energía. Rui Antonio Alves da Fonseca (47)graduated in Mechanical Engineering from
Universidade Federal do Rio de Janeiro and completed MBA courses for managers
and executives at Fundación Getúlio Vargas, Brazil. At Petrobras he worked as
Head of the CENPES Industrial Project Division and as Environment, Safety and
Health General Manager. He currently is Vice President of Quality,
Environmental, Safety and Occupational Health of Petrobras Energía. Alberto da Fonseca Guimarães (54)graduated in Mechanical Engineering from
UNESP, São Paulo State. He holds a MBA degree in Administration from Coppead,
Rio de Janeiro. He has served for three years as 141




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Executive Manager of Commercialization and Marketing at Petrobras. He
served as Executive Manager of Refining at Petrobras, and for a seven-year
term, he served as Commercial Manager of Petrobras in New York and London. He
was Managing Director of Business Development at Petrobras. Currently, he is a
Director and Chief Executive Officer of Petrobras Energía. He is also a
Director of Petrolera Entre Lomas S.A. Oscar Anibal Vicente (65)graduated in Engineering from Universidad
Nacional de La Plata and in Oil Production Engineering from Universidad de
Buenos Aires. He joined Petrobras Energía in 1970 and has since held several
positions, including General Manager (1978-1982) and Chief Executive Officer
(1997-2001). He is the President of the Argentine Hydrocarbon Producing
Companies Chamber. In addition, he is a Director of Petrobras Energía and
Petrolera Entre Lomas S.A. Cedric Bridger (67)graduated in Public Accounting in London, where he
initiated his professional activities. In Buenos Aires (1964) he was Financial
Manager of FADIP S.A. (later Hughes Tool Co. S.A.). He then held the position
of General Manager of the company in Brazil and was finally appointed Vice
President of Operations of the company for Latin America. From 1992 until
1998, he was Vice President of Finance at YPF S.A. In April 1998, he retired
from YPF S.A. and took a position as a Director of Banco Hipotecario. He is
currently attorney-in-fact of the Argentine subsidiary of Técnicas Reunidas
S.A. (Spain) and a Director of Petrobras Energía. Héctor Daniel Casal (48)graduated in Law. He serves as Vice President of
Legal Affairs of Petrobras Energía. He has worked at Petrobras Energía since
1991. He is a Director of Petrobras Energía, Petrobras Energía Internacional
S.A., Petrobras Financial Services Austria Gmbh and Petrobras Holding Austria
AG, and an alternate Director of Corod Produccion S.A., Petrolera Entre Lomas
S.A., Petrobras Energía Venezuela S.A. and Petrobras Finance Bermuda Ltd. He
is a Statutory Syndic of Refinor S.A., TGS, Compania de Inversiones de Energía
S.A. and Telcosur S.A., and alternate Statutory Syndic of Distrilec, Edesur,
Citelec, Transener, Transba. He is also member of counsel of Innova S.A. Daniel Maggi (51)graduated in Law. He completed post-graduate studies in
Business Management at the Universidad del Salvador. He has worked at
Petrobras Energía since 1997 and currently serves as Vice President of Human
Resources. In the past, he has acted as Director of Human Resources of Edesur,
and Manager of Human Resources at Sade Ingeniería y Construcciones S.A. and as
Manager of Legal Affairs and Human Resources at La Plata Cereal S.A. He is
also a Director of Petrobras Energía, Distrilec and Edesur. Nicolas Perkins (30)graduated in Law from Universidad Católica Argentina
in 1995. He obtained a Master of Law degree from New York University in 1998.
From 1996 to 1998, he worked as an associate at the law firm Cárdenas, Cassagne
& Associales, and from 1998 to 1999, he worked as a foreign associate with
Linklaters & Alliance in New York. From 1999 to 2000 he worked as General
Counsel and Human Resources Manager for LatinStocks.com coordinating work with
local counsel in Argentina, Brazil, Mexico and the United States in commercial
and intellectual property law related matters. In 2001 he worked as General
Counsel for Latin America for Schlumberger-Schlumbergersema. He currently
works as an associate with the law firm of Fortunati & Lucero. Roberto Alejandro Fortunati (48)graduated in law from the Universidad de
Buenos Aires in 1979. He is currently a professor in the post-graduate program
of Petroleum and Gas Law and adjunct professor in Public International Law at
the University of Buenos Aires, and a member of the Consulting Board of the
Universidad Torcuato Di Tella Law School. In 1985 he participated in the
Seminar on U.S. and International Law in the International and Comparative Law
Center at the Southwestern Legal Foundation in Dallas, Texas. From 1996 to
2001, he was partner and member of the Executive Committee of the law firm
Estudio Beccar Varela. From 2001 to 2002, he was Vice President and Director
of legal affairs at Citibank, Argentina Branch. Since 2003, he has been a
member of the law firm Estudio Fortunati & Lucero where he is a founding
partner. Carlos Alberto Pereira de Oliveira (46)graduated in Mechanical and
Automotive Engineering from Instituto Militar de Ingenieria, in the city of Rio
de Janeiro, with a specialization in petroleum engineering. He specialized in
Financial Administration in the areas of petroleum and gas at the University of
Texas, U.S.A. In Petrobras, he was Integral Manager of Production and
Development, Production and Development Manager and Reserves and Reservoirs
General Manager. He currently is Vice President of the Oil and Gas Exploration
and Production and Hydrocarbon Transportation Business Units. He is President
of Petrobras Energía Perú S.A. and a Director of Petrolera Entre Lomas S.A. and
Petrobras Energía. 142




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Rafael Fernández Morandé (49)graduated in Civil Engineering. He has a
post-graduate degree in Business Administration. He served as Director of the
business unit of Electricity since 1997, and additionally, since April 2001, as
Vice President of the Energy and Gas Business Units. He was previously
President of the Association of Electric Energy Generators in Argentina, a
Director of the executive committee of CAMMESA and General Manager of Central
Puerto S.A. He is President of Distrilec, World Energy Business S.A.,
Petrobras Finance Bermuda, Telcosur S.A., Citelec, Transba, TGS and Compañia de
Inversiones de Energía S.A. He is also Vice President of Edesur and Transener
and a Director of Petrobras Energía. Luis Miguel Sas (41)has a degree in economics, is a Certified Public
Accountant, a graduate of Universidad de Buenos Aires and holds an MBA from the
Instituto de Altos Estudios Empresariales  Universidad Austral. He joined
Petrobras Energía in 1984 and has since served in the area of finance. In 1990
he was appointed head of the Financial Operations Division when Petrobras
Energía took over Telecom Argentina S.A., one of the first privatized companies
in Argentina. He worked as head of the Petrobras Energía money desk during the
1992-1997 period. In 1997 he was appointed Corporate Finance Manager, in
charge of capital market financing and project financing. In January 2000, he
was appointed Chief Financial Officer of Edesur. He served as Finance Manager
at Petrobras Energía between May 2001 and May 2004. On May 7, 2004 he was
appointed Chief Financial Officer of Petrobras Energía. In addition, he
currently serves as a Director of Petrobras Energía, Distrilec Inversora,
Petrobras Energía Internacional S.A., Petrobras de Valores Internacional de
España S.A., and Petrobras Financial Services Austria Gmbh, and an alternate
Director of TGS. He is also member of Counsel of Petrobras Hispano Argentina
S.A. Pablo Cavallaro (38)graduated in Law from the Universidad de Córdoba in
1988. In 1993 he finished a course specializing in International Economics and
Development from the University of Denver, in which he received the highest
average. Between 1994 and 1997 he was employed as an associate with the law
firm Clifford Chance in London. Afterwards, he was an associate at the law
firm Bruchou, Fernandez, Madero and Lombardi. Between 1999 and 2003, he
advised important business organizations while working at the law firm of
OFarrel. Currently, he is a post-graduate Professor of Capital Markets in the
Faculty of Law at the Universidad de Buenos Aires, and since May 2003, a senior
partner at the law firm Fortunati & Lucero. Administration and Organization Our operations are conducted through Petrobras Energía. Petrobras
Energías operations are divided into five business segments that are in turn
supported by a corporate center. The five business segments are: Oil and Gas
Exploration and Production, Hydrocarbon Marketing and Transportation, Refining,
Petrochemicals and Electricity. Petrobras Energía is managed by an executive committee made up of 10
members: the Chief Executive Officer, the Chief Financial Officer, the Vice
President of each business unit and the Vice President of Legal Affairs, Human
Resources, Corporate Services, Communications and Quality, Environmental,
Safety and Occupational Health. Operations are managed through standardized processes that facilitate and
secure coordination between the different units and groups. Delegation of
authority is encouraged for the purpose of promoting efficiency. In addition,
the scope of the delegation of authority is clearly and expressly determined
through systemized approval limits for risk minimization purposes. Our
internal control system is supported by coordination among the areas
responsible for managing businesses and administering them on a centralized
basis, always within the framework of the policies established by the executive
committee. Operating and administrative processes are jointly supported by
administrative procedures, highly reliable information systems, the production
of periodical management control reports, performance appraisals and fluid
communications that strengthen the internal control system and help to secure
an efficient administration. 143




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Our Executive Officers Because we are a holding company, we do not have any executive officers.
Our operations are conducted by Petrobras Energías team of highly qualified
executive officers. The following table sets forth the names and positions of
Petrobras Energías executive officers. Name
    
    PositionAlberto Guimarães
    
    Chief Executive OfficerLuis Miguel Sas
    
    Chief Financial OfficerCarlos Alberto P. de Oliveira
    
    Vice President of Oil and Gas Exploration and Production
and Hydrocarbon Transportation Business UnitsHaroldo Dahn
    
    Vice President of Refining and Petrochemicals Business UnitsRafael Fernández Morandé
    
    Vice President of Energy and Gas Business UnitsDaniel Maggi
    
    Vice President of Human ResourcesHéctor Daniel Casal
    
    Vice President of Legal AffairsAlberto Bethke
    
    Vice President of Corporate ServicesLuiz Augusto M. da Fonseca
    
    Vice President of CommunicationsRui Antonio Alves da Fonseca
    
    Vice President of Quality, Environmental, Safety and
Occupational HealthRicardo Meira de Vasconcellos
    
    Executive Manager of AuditingAdelson da Silva
    
    Executive Manager of Planning
 The following is a brief summary of the principal business and academic
experience of Petrobras Energías executive officers who are not also directors
of ours (for the summary regarding executive officers who are directors, see
above). Haroldo Dahn (54)graduated in Chemical Engineering with executive
education at the University of Michigan. He is currently Vice President of the
Refining and Petrochemicals business units of Petrobras Energía. He joined us
in 1989 and has since served in different positions, including General Manager
of Cuyo and PASA S.A. He is President of Refineria Norte S.A., Vice President
of Cuyo in Argentina, President of Innova S.A. in Brazil and a Director of
Empresa Boliviana de Refinación S.A. in Bolivia. Alberto Bethke (38)graduated in Public Accounting. He completed a
post-graduate degree in Business Administration at the Instituto de Altos
Estudios Empresariales  Universidad Austral. He currently serves as Vice
President of Corporate Services of Petrobras Energía. He has been with
Petrobras Energía since 1994, first as Corporate Information Manager and then
from 2000-2001 as E-Commerce Manager. He previously served as Administrative
Manager in TGS and prior to that in the audit and consulting division of
Pistrelli, Díaz y Asociados. Ricardo Meira de Vasconcellos (46)graduated in Business Administration
from Santa Úrsula University, Rio de Janeiro, Brazil. He specialized in
Financial Administration in oil and gas at the University of Texas, U.S.A. He
also completed post-graduation studies in Financial Administration and holds an
Executive MBA in Management from the Fundação Getúlio Vargas, Rio de Janeiro,
Brazil. In Petrobras, he has been working in the Internal Audit Department for
17 years and his last position was E&P Audit Manager. He is currently Executive
Manager of Auditing. Adelson Antonio da Silva (47)graduated as an Accountant from the
University Nilton Paiva Ferreira, in the city of Belo Horizonte and as a Lawyer
from University Candido Mendes in Rio de Janeiro. He specialized in Tax Law at
University Estácio de Sá and MBA Executive/Marketing at COPPEAD-UFRJ in Rio de
Janeiro. He worked for 24 years in Petrobras, predominately at the Accounting,
Finance, Commercial, and Development of New Business areas. He participated in
the biggest international acquisitions of Petrobras. He is currently Executive
Manager of Planning at Petrobras Energía, and a Director of Petrobras Argentina
S.A., Transener, Petrolera Entre Lomas S.A., and TGS. 144




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COMPENSATION Compensation of the members of the Board of Directors is determined at the
ordinary shareholders meeting in compliance with the Business Companies Law,
No. 19,550. The maximum amount of compensation that the members of the Board of
Directors may receive, including salaries and any other form of compensation
for the performance of technical, administrative, or permanent functions, may
not exceed 25% of our profits. Such amount will be 5% in the event that no
dividends are distributed to the shareholders. It will be increased pro rata on
the basis of the dividend distribution, up to the 25% cap. In the event that
one or more directors serve as members of a special committee or perform
technical or administrative functions, and profits are reduced or non-existent,
and, consequently, the preset limits are exceeded, compensation in excess of
the limit may only be paid with the prior express approval by shareholders at
the regular shareholders meeting. In Petrobras Energía, the compensation policy for executive officers
includes an annual cash compensation and a benefit program. The annual cash
compensation is determined based on the characteristics and responsibilities of
the relevant position and the executive officers qualifications and experience
and benchmark information. Such compensation consists of a monthly fixed
compensation and an annual variable compensation dependent upon Petrobras
Energías results of operations and the achievement of individual goals and
objectives. Benefits granted to executive officers are similar to those
granted to our staff, such as life insurance, health care plan, meal allowance,
and supplementary pension plan. In addition to cash compensation, we sponsor a long term incentive plan
for Petrobras Energías executive officers and senior managers. The plan
consists of two stock option programs. The Appreciation Rights Program grants
executive officers and senior managers options to purchase shares of Petrobras
Energía Participaciones at a set exercise price or to receive cash equal to the
difference between the average market price of Petrobras Energía
Participaciones shares during the 20 days prior to exercise date and the
exercise price. The Full Value Program grants executive officers and senior
managers options to receive shares of Petrobras Energía Participaciones at no
cost or receive cash equal to the market value of such shares. Each option
grants the holder the right to purchase one share of Petrobras Energía
Participaciones. As part of this program, the Board of Directors of Petrobras Energía
approved the incentive plans for 2001 and 2000. For further information see
our financial statements as of December 31, 2003. In 2002 and 2003, no grants
were made under these plans. No contracts for services were entered into between the directors and our
company or any of our subsidiaries that provide for benefits after termination
of their office, other than as provided by law. In 2003, we paid an aggregate of P$14.8 million to our directors and to
the executive officers of Petrobras Energía. BOARD PRACTICES Audit Committee Pursuant to the provisions of the Regime concerning Transparency in Public
Offerings approved by Decree No. 677/01, Argentine public companies must have
an Audit Committee composed of three or more members of the Board of Directors.
On May 21, 2003, our Board approved the implementation process required under
General Resolution No. 400/02 of the CNV, which sets forth the rules concerning
the implementation and operation of the Audit Committee that must be provided
for either in our internal regulations or in our by-laws. In compliance with the above resolutions, at the shareholders ordinary
meeting held on March 19, 2004, we approved an amendment to our by-laws adding
a provision related to the structure and operation of the Audit Committee. Our
amended by-laws are awaiting formal approval from the CNV prior to becoming
effective. The Audit Committee will be composed of three regular directors and an
equal or lower number of alternate members that will be appointed by the Board
of Directors from among its members. Directors having 145




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sufficient experience and ability in financial, accounting or business
matters are eligible to become members of the Audit Committee. All members of
the Audit Committee or at least the majority of its members, as determined by
the Board of Directors, must be independent, under the standards provided for
in the regulations of the CNV. See Directors and Senior ManagementBoard of
Directors. The Audit Committee may adopt its own internal regulations. At the
Board of Directors meeting on May 7, 2004, Roberto Fortunati, Nicolás Perkins
and Cedric Bridger were appointed as regular members of the Audit Committee and
Pablo Cavallaro was appointed as an alternate member. The Audit Committee has the following powers and responsibilities:  (i)
    
    To make recommendations to the shareholders about the Board
of Directors proposal regarding the appointment of the external
auditors and to monitor the independence of such external auditors.(ii)
    
    To supervise the performance of the internal control systems,
the performance and trustworthiness of the administrative accounting
system, the trustworthiness of all the financial information and
relevant event disclosure submitted to the CNV and to self-regulated
entities pursuant to the applicable disclosure regulations.(iii)
    
    To supervise the application of our disclosure policies with
respect to our risk management practices.(iv)
    
    To provide the market with complete information with respect
to transactions where members of corporate bodies or controlling
shareholders of ours have conflicts of interests.(v)
    
    To opine with respect to the reasonableness of compensation
and option plans proposed by management for directors or managers.(vi)
    
    To opine on the performance of legal requirements and on the
reasonableness of proposals to issue shares or securities
convertible into shares, in the case of capital increases that
exclude or limit preemptive rights.(vii)
    
    To verify the compliance with applicable codes of conduct.(viii)
    
    To issue founded opinions with respect to transactions with
related parties as required by applicable law. To issue founded
opinions whenever a conflict of interest exists or may arise for us
and to communicate this opinion to self-regulated entities as
required by the CNV. Once
a year, the Audit Committee prepares a working plan with respect to the Audit
Committees goals and work schedule for the fiscal year to be submitted to the
Board of Directors and to the Statutory Syndic Committee. The directors,
members of the Statutory Syndic Committee, managers and external auditors
shall, when requested by the Audit Committee, attend its meetings, provide the
Audit Committee with information and otherwise assist the Audit Committee in
the performance of its functions. In order to better perform its functions,
the Audit Committee may seek the advice of legal counsel and other independent
professionals at our expense, pursuant to a budget approved by shareholders.
The Audit Committee shall have access to the information and documents it may
deem necessary to perform its duties. These same policies were implemented by Petrobras Energía for its Audit
Committee. Statutory Syndic Committee We have a Statutory Syndic Committee that is comprised of three members
and three alternate members. The members of Petrobras Energías Statutory
Syndic Committee are the same as those that serve on our Statutory Syndic
Committee. 146




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The table below sets out the name, year of appointment and position of
each person on the Statutory Syndic Committee, approved by Petrobras Energías
Ordinary Shareholders Meeting held on March 19, 2004: Year ofName
    
    Appointment
    
    PositionJuan Carlos Cincotta
    
    
    2004
    
    
    MemberJusto Federico Norman
    
    
    2003
    
    
    MemberRogelio Norberto Maciel
    
    
    2003
    
    
    MemberOlga M. Morrone de Quintana
    
    
    2004
    
    
    AlternateMariana P. Ardizzone
    
    
    2004
    
    
    AlternateMaría Laura Maciel
    
    
    2004
    
    
    Alternate
 The members and alternate members of the Statutory Syndic Committee are
elected by the shareholders at the annual shareholders meeting to serve for a
renewable term of one year. The primary responsibilities of the Statutory
Syndic Committee are to monitor managements compliance with the Companies Law,
our by-laws and the shareholders resolutions. The Statutory Syndic Committee
also performs other functions, including: (i) attending meetings of the Board
of Directors and shareholders, (ii) calling extraordinary shareholders
meetings when deemed necessary or when required by shareholders, in accordance
with the Business Companies Law, No. 19550, (iii) presenting a report on the
reports of the Board of Directors and the annual financial statements at
regular shareholders meetings, and (iv) investigating written complaints of
shareholders representing not less than 2% of the capital stock. The Statutory
Syndic Committee may not engage in any management control and, accordingly, may
not evaluate business judgment and decisions on issues of administration,
financing, selling and production, as these issues fall within the exclusive
responsibility of the Board of Directors. Justo Federico Norman, Rogelio Norberto Maciel, Mariana P. Ardizzone and
Maria Laura Maciel are lawyers and work at Maciel, Norman & Asociados Law
Office, which has professional relations with and charges fees to us, our
controlling companies and other Petrobras Energía companies. Olga Margarita Morrone de Quintana is a public accountant and works at
Estudio Morrone de Quintana, Seoane & Quintana, which has professional
relations with and charges fees to us and other Petrobras Energía companies. In compliance with Technical Resolution No. 15 of the Federación Argentina
de Consejos Profesionales de Ciencias Económicas, Juan Carlos Cincotta and Olga
Margarita Morrone de Quintana are independent. The following is a brief summary of the principal business and academic
experience of the members of the Statutory Syndic Committee listed in the table
above: Juan Carlos Cincotta (59)graduated in Public Accounting from Universidad
de Buenos Aires. He is currently a member of Cincotta Asesores, formerly a
partner at Ernst & Young, Grant Thornton & Bertora Asociados. He specializes
in external audits of major public and private entities, consulting in
accounting issues and auditing of companies. He is a member of the Special
Commission on Accounting and Auditing Regulations (CENCyA) of the Federación
Argentina de Consejos Profesionales de Ciencias Económicas. He is also a
representative at the Instituto Argentino de Ejecutivos de Finanzas in the
Committee on International Accounting Standards of IAFEI and Director of the
Subcommittee of National and International Technical Rules. He is currently a
member of the Statutory Syndic Committee of Petrobras Energía. Justo F. Norman (59)graduated in Law. He is a partner of Maciel, Norman
& Asociados Law Office in Buenos Aires (1991) with extensive experience in the
general practice of law and in the fields of energy, natural resources, taxes
and environmental issues. He is also renowned in the litigation and
international arbitration fields. He is a member of the Association of
International Petroleum Negotiators (AIPN) where he currently serves as
Regional Secretary (2001-2004); the International Bar Association (IBA); and
Rocky Mountain Mineral Law Foundation. He has represented and currently
represents companies such as Anadarko Petroleum Corporation, ANR Pipeline
Company (Coastal), Apache Corporation, BHP Petroleum (Americas) Inc., British
Gas, Devon Energy Corporation, Parker Drilling, and Petroliam Nasional Berhad
(Petronas). He is Vice President of BHP Petroleum 147




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(Argentina) S.A. and Computalog S.A. and a Regular Director of Noranda
Exploración Argentina S.A., Petronas Argentina S.A. and Petrolera Rio Alto
S.A., among others. He is also a member of the Statutory Syndic Committee of
Petrobras Energía and an alternate member of the Statutory Syndic Committee of
Petrolera Entre Lomas S.A. Rogelio N. Maciel (68)is a founding partner of Maciel, Norman & Asociados
Law Office. He is a renowned lawyer in the litigation and international
arbitration fields. He was one of the members of the Argentine Aeronautical
Code Drafting Committee and was a member of the Argentine delegation to the
OACI. He is a member of the Buenos Aires Oil Club, the Association of
International Petroleum Negotiators (AIPN) and the Rocky Mountain Mineral Law
Foundation. He is Vice President of Noranda Exploración Argentina S.A. and
Petronas Argentina S.A., a Regular Director of BHP Petroleum (Argentina) S.A.
and an Alternate Director of Petrolera Rio Alto S.A., among others. He is also
a member of the Statutory Syndic Committee of Petrobras Energía. Olga M. Morrone de Quintana (68)is a partner of Morrone de Quintana,
Seoane & Quintana. She is currently a member of the Statutory Syndic Committee
of Petrolera Entre Lomas S.A., Petrobras Energía Internacional S.A., Enecor
S.A., Yacylec S.A., World Energy Business S.A., Propyme SGR, and an alternate
member of the Statutory Syndic Committee of Petrobras Energía. Mariana P. Ardizzone (31)graduated in Law from Universidad de Buenos
Aires. She holds a Master of Laws from the University of Michigan and is
currently enrolled in a post-graduate degree course in Business Administration
and Electric Energy and Natural Gas Markets at the Instituto Tecnológico de
Buenos Aires (ITBA). Since July 2001, she has been working as a lawyer at
Maciel, Norman & Asociados law office. She is currently an alternate member of
the Statutory Syndic Committee of Petrobras Energía. Maria Laura Maciel (41)graduated in Law from Universidad Catolica
Argentina. She holds a post-graduate degree in Private International Law and
in Aviation Law from American University in Washington D.C. (1986), and a
post-graduate degree in IATA/FIATA in the International Association of Air
Transportation, Montreal, Canada (2004). She is currently working as an
associate at Maciel, Norman & Asociados law office, and is currently an
alternate member of the Statutory Syndic Committee of Petrobras Energía. Total compensation for the members of the Statutory Syndic Committee was
P$0.045 million in 2003. EMPLOYEES The following table sets out the number of our employees by business
segment for the fiscal years ended December 31, 2003, 2002 and 2001. As of December 31,2003
    
    2002
    
    2001Oil and Gas Exploration and Production
    
    
    900
    
    
    
    884
    
    
    
    914Refining and Petrochemical
    
    
    1,551
    
    
    
    1,505
    
    
    
    1,422Electricity
    
    
    73
    
    
    
    74
    
    
    
    272Farming and Forestry
    
    
    209
    (1)
    
    
    212
    
    
    
    408Hydrocarbon Marketing and Transportation
    
    
    25
    
    
    
    22
    
    
    
    20Corporate
    
    
    576
    
    
    
    558
    
    
    
    583Total
    
    
    3,334
    
    
    
    3,255
    
    
    
    3,619
   (1)
    
    In January 2004, we completed the formalities necessary for execution of the transfer of our forestry industrial activities. Currently, 28% of our workforce are members of labor unions and have
entered into collective bargaining agreements with our company or our entities.
We believe we generally have good relations with our employees and the unions,
and expect to continue to enjoy good relations with our employees and the
unions in the future. We can provide no assurance, however, that our employee
compensation arrangements may not be subject to change or modification after
the expiration of the contracts currently in effect. SHARE OWNERSHIP To our knowledge, none of our directors or members of our senior
management owns more than 1% of our outstanding shares. 148




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Item 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS MAJOR SHAREHOLDERS Our share capital consists of 2,132,043,837 Class B shares. Our Class B
shares have a par value of P$1.00. Our Class B shares are entitled to one vote
per share. On October 17, 2002, Petrobras Participacoes, S.L., a wholly owned
subsidiary of Petrobras, acquired 58.6% of Petrobras Energía Participacioness
capital stock from the Perez Companc Family and Fundación Perez Companc.
Petrobras is a public Brazilian company, whose business is concentrated on
exploration, production, refining, sale and transportation of oil and its
by-products in Brazil and abroad. Prior to that date, the Perez Companc
Family, together with Fundación Perez Companc, had owned at least half of the
share capital issued by Petrobras Energía Participaciones. The table below sets forth certain information as of April 30, 2004 with
respect to the ownership of our capital stock by each person who is known to us
to be the owner of more than 5% of our shares. Class B Shares% of theTotalOutstandingShareholder
    
    Number of Shares
    
    SharesPetrobras Participacões S.L
    
    
    1,249,716,746
    
    
    
    58.6
    %
 RELATED PARTY TRANSACTIONS Our strategy to grow as an integrated energy company led us to develop our
business in various levels of the energy industry, and this in turn has led to
an increase in transactions between our affiliates and subsidiaries, in
particular between affiliates and subsidiaries in different business segments.
These transactions are carried out in the ordinary course of our operations on
an arms length basis. The terms of these transactions are comparable to those
offered by or obtained from non-related third parties. In addition, we have sought to capitalize on the synergies of our
businesses with those of Petrobras, by exploiting a number of opportunities and
initiatives that offer benefits to both companies. The Refining segment has
benefited the most from this relationship. During 2003, 210,000 m3 of diesel
oil were sold to EG3. This allowed us to profitably increase the volumes of
crude oil processed in the San Lorenzo Refinery to levels superior to those of
the last few years. EG3 does not have sufficient production capacity in its
refinery in Bahía Blanca to supply its ample network of service stations, and
we produce excess amounts of diesel oil at the San Lorenzo Refinery, which have
been traditionally exported at lower prices to other countries in the region.
This generates attractive long-term business opportunities for both companies. We reached an agreement to sell Lubrax lubricants, a product of
Petrobras, in our network of services stations. This lubricant has rapidly
acquired a significant local market share of almost 9%, and was the fastest
growing lubricant in Argentina in 2003, with sales increasing 40% as compared
to 2002. The technical, commercial and marketing efforts carried out by
Petrobras for the development of the Lubrax trademark in Argentina have
significantly assisted our sales. We also reached agreements to use the Petrobras flag at seven of our
service stations. Over the last few years, Petrobras has built an excellent
image for its brands, products and services in Argentina, currently competing
with the image of the leading competitors. Negotiations continue over a long
term agreement for the use of the Petrobras brand at all our gas stations. 149




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In January 2003, we closed transactions with a subsidiary of Petrobras to
hedge oil price fluctuations during the second semester of 2003, covering a
volume of 18,000 barrels per day. This agreement provides protection based on
the actual WTI, setting a minimum price of U.S.$22.87 per barrel. We paid a
premium of P$12 million for this option. In the first quarter of 2002, Petrobras Energía approved an asset swap
transaction with IRHE (Argentine Branch) and Gentisur S.A., two companies
related to our former controlling group. Pursuant to the terms of the asset
swap, Petrobras Energía sold to IRHE and Gentisur its 50% interest in Pecom
Agra S.A. for U.S.$30 million, resulting in a P$81 million gain and, in turn,
IRHE and Gentisur transferred to Petrobras Energía the following as
consideration for the sale:  
    
    0.75% interest in the Puesto Hernández Hydrocarbon UTE for U.S.$4.5 million;
    
    7.5% equity interest in CITELEC, the parent of Transener, for U.S.$15 million; and
    
    9.19% equity interest in Hidroneuquén S.A., a company holding
a 59% interest in the capital stock of Hidroeléctrica Piedra del
Aguila S.A., for U.S.$5.5 million. The remaining balance of U.S.$5 million was settled through a document
maturing in October 2002, which accrues interest at six-month LIBOR plus an
annual 3% spread. We have requested reports from consulting firms regarding our related
party transactions. These reports state that these transactions can be
reasonably considered in conformity with ordinary market practices and
conditions. Material transactions with our related entities (including companies under
joint control) for the years ended December 31, 2003, 2002 and 2001, are as
follows: 2003
    
    2002
    
    2001Purchases
    
    Sales
    
    Purchases
    
    Sales
    
    Purchases
    
    SalesCompanyOleoductos del Valle S.A.
    
    
    17
    
    
    
    
    
    
    
    14
    
    
    
    
    
    
    
    20
    
    
    
    Transportadora de Gas del Sur S.A.
    
    
    13
    
    
    
    
    
    
    
    48
    
    
    
    
    
    
    
    106
    
    
    
    Petroquímica Cuyo S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    
    
    
    
    9Petrobras Petroleo Brasileiro S.A.
    
    
    
    
    
    
    149
    
    
    
    
    
    
    
    79
    
    
    
    
    
    
    
    EG3 S.A.
    
    
    26
    
    
    
    196
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    Refinería del Norte S.A.
    
    
    55
    
    
    
    1
    
    
    
    60
    
    
    
    
    
    
    
    37
    
    
    
    Petrolera Entre Lomas S.A.
    
    
    
    
    
    
    
    
    
    
    22
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    111
    
    
    
    346
    
    
    
    144
    
    
    
    85
    
    
    
    163
    
    
    
    9
 The outstanding balances as of December 31, 2003, 2002 and 2001 from
transactions with related companies (including companies under joint control)
are as follows: 2003Current
    
    Long-termTrade
    
    Other
    
    Accounts
    
    OtherReceivables
    
    Receivables
    
    Payable
    
    Liabilities
    
    InvestmentsCompanyOleoductos del Valle S.A.
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    Petroquímica Cuyo S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6
    
    
    
    Oleoductos Crudos Pesados Ltd.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    127EG3 S.A.
    
    
    55
    
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    Transportadora de Gas del Sur S.A.
    
    
    9
    
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    Refinería del Norte S.A.
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    Petrobras Petroleo Brasileiro S.A.
    
    
    10
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Petrobras Energía Participaciones S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    74
    
    
    
    3
    
    
    
    7
    
    
    
    6
    
    
    
    127
 150




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2002CurrentTrade
    
    Other
    
    Accounts
    
    OtherInvestments
    
    Receivables
    
    Receivables
    
    Payable
    
    LiabilitiesCompanyEmpresa Boliviana de Refinación S.A.
    
    
    19
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oleoductos del Valle S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    Petroquímica Cuyo S.A.
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    
    
    
    
    Petrobras International Finance Company
    
    
    
    
    
    
    17
    
    
    
    
    
    
    
    
    
    
    
    Transportadora de Gas del Sur S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    Refinería del Norte S.A.
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    4
    
    
    
    Coroil S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    48Total
    
    
    19
    
    
    
    19
    
    
    
    4
    
    
    
    10
    
    
    
    48
 2001Current
    
    Long-termTrade
    
    Other
    
    AccountInvestments
    
    Receivables
    
    Receivables
    
    Payable
    
    InvestmentsCompanyEmpresa Boliviana de Refinación S.A.
    
    
    20
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oleoductos del Valle S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    Cerro Vanguardia S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    69Transportadora de Gas del Sur S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7
    
    
    
    Refinería del Norte S.A.
    
    
    
    
    
    
    2
    
    
    
    2
    
    
    
    4
    
    
    
    Others
    
    
    
    
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    Total
    
    
    20
    
    
    
    2
    
    
    
    4
    
    
    
    13
    
    
    
    69
 We do not have any other material related party transactions. 151




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Item 8. FINANCIAL INFORMATION CONSOLIDATED FINANCIAL STATEMENTS See Item 18. Financial Statements. LEGAL PROCEEDINGS We are involved in various litigation and regulatory proceedings arising
in the ordinary course of our business. We do not believe that any of these
proceedings is material to our operations or financial condition. In addition, as a result of the Argentine crisis and the pesification of
utility rates, some of our affiliates and companies under joint control have
defaulted on their debt and are in discussions with creditors regarding
possible restructurings. If the restructuring efforts are unsuccessful and
creditors proceed against the assets of such affiliates and companies under
joint control, we could lose some or all of our equity in these companies and
our results would be affected accordingly. See Item 3. Key InformationRisk
FactorsFactor Relating to ArgentinaThe devaluation and pesification of
utility rates have resulted in payment defaults by some of our affiliates. DIVIDENDS We may only pay dividends from our retained earnings reflected in our
annual audited financial statements as approved at our annual general ordinary
shareholders meeting. While our Board of Directors may declare interim
dividends, our Board of Directors and our statutory audit committee would be
jointly and severally liable for the repayment of dividends if our retained
earnings at the close of our fiscal year were not sufficient to permit the
payment of the dividend made during the year and interim dividends received in
good faith are not reimbursable. Under our by-laws, our net income is
allocated as follows:  1.
    
    5% is allocated to a legal reserve until the legal reserve
equals 20% of our outstanding capital,2.
    
    to compensation of the members of the Board of Directors and
statutory audit committee, and3.
    
    to dividends on preferred stock, if any, then to dividends on
common stock or to a voluntary reserve or contingency reserve or
other account, or as otherwise decided by the ordinary shareholders
meeting. Holders of our American Depositary Shares, or ADSs, will be entitled to
receive any dividends payable in respect of our underlying Class B shares. We
will pay cash dividends to the depositary in pesos, although we reserve the
right to pay cash dividends in any other currency, including U.S. dollars. The
deposit agreement provides that the depositary will convert cash dividends
received by the depositary in pesos to U.S. dollars and, after a deduction or
upon payment of fees and expenses of the depositary, will make payment to
holders of our ADSs in U.S. dollars. The main source of funds for the payment of cash dividends will be the
dividends received from our controlled company Petrobras Energía. We will
distribute as cash dividends any cash dividends received from Petrobras
Energía, net of taxes, if any, and expenses, and subject to the Argentine laws
and the corporate by-laws. 152




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Payment of cash dividends by Petrobras Energía will be dependent upon its
financial situation, the results of operations, cash requirements (including
capital expenditures and payments of debt service), retained earnings minimum
requirements and other requirements imposed by Argentine law and upon any other
factors deemed relevant by Petrobras Energías Board of Directors for the
purpose of resolving upon the declaration of dividends. On October 4, 2002, Petrobras Energía refinanced financial liabilities in
the amount of U.S.$849 million through the issue of several series of corporate
notes and other medium term credit instruments. From the time of refinancing
and while any part of the refinanced debt is outstanding, Petrobras Energía
shall comply with a series of restrictions and commitments, including, among
others, the following restriction on the payment of dividends: Petrobras Energía shall not distribute cash dividends prior to
December 31, 2004, exceeding U.S.$650,000. As an exception, Petrobras
Energía distributed an extraordinary dividend to its shareholders up to
U.S.$19 million, based on whether Petrobras Energía Participaciones
allocates its share of distributed dividends to settle Petrobras Energía
Participacioness payable to Petrobras Energía. After this date, the
aggregate amount paid shall not exceed 50% of the excess cash (cash
provided by operating activities less aggregate capital expenditures
allowed, up to the amount of actual capital expenditures, less financial
debt repaid) for the immediately preceding fiscal year. We did not pay dividends for 2003, 2002 and 2001, and we cannot assure you
that we will pay dividends in the near future. 153




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Item 9. OFFER AND LISTING OFFER AND LISTING DETAILS Our ADSs, each representing ten Class B shares, are listed on the New York
Stock Exchange under the trading symbol PZE. The ADSs began trading on the
New York Stock Exchange on January 26, 2000 and were issued by Citibank, N.A.,
as depositary. Our Class B shares are listed on the Buenos Aires Stock Market
under the trading symbol PBE. The Class B shares began trading on the Buenos
Aires Stock Market on January 26, 2000. The following table sets forth, for
the periods indicated, the high and low closing sales price of the ADSs on the
New York Stock Exchange and the Class B shares on the Buenos Aires Stock
Market: ADS(1)
    
    Class B share(2)High
    
    Low
    
    High
    
    LowFull Year2000
    
    
    21.19
    
    
    
    12.81
    
    
    
    2.12
    
    
    
    1.282001
    
    
    18.75
    
    
    
    9.18
    
    
    
    1.98
    
    
    
    0.922002
    
    
    12.60
    
    
    
    3.60
    
    
    
    2.83
    
    
    
    1.422003
    
    
    11.25
    
    
    
    6.52
    
    
    
    3.34
    
    
    
    1.99Quarterly2002First Quarter
    
    
    12.60
    
    
    
    7.04
    
    
    
    2.83
    
    
    
    1.88Second Quarter
    
    
    7.40
    
    
    
    3.60
    
    
    
    2.47
    
    
    
    1.42Third Quarter
    
    
    7.10
    
    
    
    4.40
    
    
    
    2.50
    
    
    
    1.65Fourth Quarter
    
    
    6.28
    
    
    
    4.69
    
    
    
    2.27
    
    
    
    1.782003First Quarter
    
    
    7.56
    
    
    
    6.52
    
    
    
    2.46
    
    
    
    2.07Second Quarter
    
    
    8.81
    
    
    
    6.80
    
    
    
    2.49
    
    
    
    1.99Third Quarter
    
    
    8.88
    
    
    
    7.50
    
    
    
    2.64
    
    
    
    2.18Fourth Quarter
    
    
    11.25
    
    
    
    8.83
    
    
    
    3.34
    
    
    
    2.552004First Quarter
    
    
    14.14
    
    
    
    11.31
    
    
    
    4.13
    
    
    
    3.20MonthlyDecember 2003
    
    
    11.25
    
    
    
    9.39
    
    
    
    3.34
    
    
    
    2.75January 2004
    
    
    13.46
    
    
    
    11.31
    
    
    
    3.90
    
    
    
    3.40February 2004
    
    
    13.60
    
    
    
    11.34
    
    
    
    4.10
    
    
    
    3.20March 2004
    
    
    14.14
    
    
    
    13.00
    
    
    
    4.13
    
    
    
    3.83April 2004
    
    
    14.05
    
    
    
    12.09
    
    
    
    4.00
    
    
    
    3.47May 2004
    
    
    12.23
    
    
    
    9.08
    
    
    
    3.48
    
    
    
    2.65June 2004 (through June 11, 2004)
    
    
    10.06
    
    
    
    9.39
    
    
    
    3.03
    
    
    
    2.73
   (1)
    
    Amounts expressed in U.S.$(2)
    
    Amounts expressed in P$ On May 31, 2004, there were approximately 29.2 million ADSs outstanding.
Our ADSs represented approximately 13.6% of the total number of issued and
outstanding Class B shares as of May 31, 2004. MARKETS Buenos Aires Stock Market The Buenos Aires Stock Market, which is affiliated with the Buenos Aires
Stock Exchange, is the largest stock market in Argentina. The Buenos Aires
Stock Market is a corporation whose shareholder members are the only
individuals and entities authorized to trade in the securities listed on the
Buenos Aires Stock Exchange. 154




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Trading on the Buenos Aires Stock Exchange is conducted by continuous open
outcry and a computer-based negotiation system called SINAC from 10:00 a.m. to
6:00 p.m. each business day. The Buenos Aires Stock Exchange also operates an
electronic trading market system from 11:00 a.m. to 5:00 p.m. each business
day. To control price volatility, the Buenos Aires Stock Market operates a
system by which the trading of a security is suspended for 15 minutes whenever
the price of such security changes 15% from its last closing price. Once the
15 minutes have elapsed, trading is resumed. From that point on, trading will
be suspended for 10 minutes whenever the trading price changes 5% from the last
suspended price. Investors in the Argentine securities market are mostly individuals and
companies. Institutional investors, which are responsible for a growing
percentage of trading activity, consist mainly of institutional pension funds
created under the amendments to the social security laws, enacted in late 1993. Certain information regarding the Argentine equities market is set forth
in the table below: 2003
    
    2002
    
    2001
    
    2000
    
    1999Market capitalization
(P$ billions)(1)
    
    
    543.3
    
    
    
    348.1
    
    
    
    192.5
    
    
    
    165.8
    
    
    
    83.9As percent of GDP(1)
    
    
    205%
    
    
    
    111.2%
    
    
    
    70.9%
    
    
    
    58.1%
    
    
    
    29.6%Volume (P$ millions)
    
    
    8,844
    
    
    
    4,117
    
    
    
    7,519
    
    
    
    11,050
    
    
    
    12,051Average daily trading volume
(P$ millions)
    
    
    35,52
    
    
    
    17.5
    
    
    
    30.9
    
    
    
    38.8
    
    
    
    47.2Number of listed companies(1)
    
    
    110
    
    
    
    117
    
    
    
    119
    
    
    
    116
    
    
    
    125
   (1)
    
    End-of-period figures for trading on the Buenos Aires Stock Exchange. Source: Bolsa de Comercio de Buenos Aires, CNV and Instituto Argentino de
Mercado de Capitales. 155




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Item 10. ADDITIONAL INFORMATION MEMORANDUM AND ARTICLES OF ASSOCIATION Register Our by-laws were registered in the General Board of Corporations
(Inspección General de Justicia) on January 6, 1999 under number 265, book 4 of
Corporations, as amended on November 4, 1999 under number 16,283, book 7 of
Corporations, on July 6, 2000 under number 9,534, book 11 of Corporations, on
July 31, 2000 under number 11,102, book 12 of Corporations, and on October 26,
2000 under number 16,086, book 13 of Corporations, on February 14, 2003 under
number 2172, book 20 of Corporations and on August 22, 2003 under number 11893,
book 22 of Corporations. Objects and Purposes Article 3 of our by-laws states that one of the purposes of our company is
to carry on trade as an investment company, either on our own account, or on
account of or in association with third parties, investing money in our own
real estate transactions and/or through capital contributions to firms or
business or industrial companies existing at present or to be organized in the
future, in order to make present or future businesses, acquire and sell shares,
bonds and debentures, grant financial support, provide sureties, guarantees and
bonds in favor of third parties, and make financial transactions granting loans
and payment facilities whether or not secured by a security interest, expressly
excluding the activities that are prohibited by the financial entities law. To
such effect, we have full legal capacity to assume rights and obligations and
perform all acts not prohibited by the law or by these by-laws. Provisions of the By-laws Relating to Directors Article 9 of our by-laws states that the Board of Directors shall
constitute quorum with the presence of a majority of its members and shall
adopt resolutions by a majority of the votes present. Argentine corporate law
requires that directors refrain from voting on matters in which such director
may have a material interest. Our by-laws establish that, should any members
of the board refrain from voting in any matter on account of having an interest
contrary to ours, the board shall adopt resolutions by a majority of the
members who did not refrain from voting for such reason. Capital Stock Set forth below is a brief description of the material provisions of our
by-laws and Argentine law and regulations relating to our capital stock. There
are no longer Class A shares outstanding since they were converted, on October
17, 2002, into Class B shares as explained below. Voting Rights Each Class B share entitles the holder to one vote. Transfers of Class A Shares Class A shares were converted into Class B shares prior to the sale of
Petrobras Energía Participacioness Class A shares from the Perez Companc
Family to Petrobras. See Major Shareholders. Special Class Voting Rights Under Argentine law, any action that would prejudice the rights of holders
of a particular class of shares but not the rights of holders of other classes
or affect the rights of holders of a particular class of shares in a manner
different than holders of other classes of shares must be approved by the
holders of the prejudiced class of shares at 156




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a special meeting. These special rights apply only to classes of shares
as a whole and not to a minority of shares of one class against a majority of
that same class. In addition, special shareholders meetings are governed by
the same rules as ordinary shareholders meetings. In particular, a special
meeting of Class A shareholders will be required in cases of (1) changing of
our corporate legal status, (2) the anticipated dissolution of our company, (3)
mergers, (4) spinoffs and (5) transfer of our domicile outside of Argentina.
Amendments to the terms of issuance of employee profit-sharing certificates
shall also require shareholder approval at a special meeting. Cumulative Voting Under Argentine law, a shareholder is entitled to cumulative voting
procedures for the election of up to one-third of the directors being elected.
If any shareholder notifies us of its decision to exercise its cumulative
voting rights not later than three business days prior to the date of a
meeting, all shareholders are entitled, but not required, to exercise their
cumulative voting rights. Under cumulative voting, the aggregate number of
votes that a shareholder may cast is multiplied by the number of vacancies to
be filled in the election, and each shareholder may allocate the total number
of its votes among a number of candidates not to exceed one-third of the number
of vacancies to be filled. Shareholders not exercising cumulative voting
rights are entitled to cast the number of votes corresponding to their shares
for each candidate. The candidates receiving the most votes are elected to the
number of vacancies filled by cumulative and non-cumulative voting. If no
candidate for a particular vacancy receives an absolute majority of votes, the
two candidates that received the most votes will participate in a run-off
election, and the candidate receiving the most votes in the run-off election
will be deemed elected. Preemptive Rights In the event of a capital increase, a holder of existing common shares of
a given class has a preemptive right to subscribe for a number of shares of the
same class sufficient to maintain the holders existing proportionate holdings
of shares of that class. Preemptive rights also apply to the issuance of certain convertible
securities (obligaciones negociables) but do not apply upon conversion of these
securities. In addition, preemptive rights may apply to the issuance of
preferred shares if so decided at a shareholders meeting. Holders of ADSs may
be restricted in their ability to exercise preemptive rights if a prospectus
under the Securities Act relating to those securities has not been filed or is
not effective or an exemption from registration is not available. You should
note that we are not obligated to file a registration statement with respect to
the shares relating to preemptive or accretion rights. Preemptive rights are
exercisable during the 30 days following the last publication of notice to the
shareholders in the Official Gazette and an Argentine newspaper of wide
circulation. Pursuant to Argentine corporate law, the 30-day period may be
reduced to ten days by a decision of our shareholders adopted at an
extraordinary shareholders meeting. Preemptive rights may be suspended or
limited in extraordinary circumstances with the favorable vote of more than 50%
of all outstanding voting shares at an extraordinary shareholders meeting at
which all shares will be entitled to exercise one vote regardless of whether
there are shares with multiple votes where the purpose of the capital increases
is to issue shares as consideration for a contribution of assets to the company
or to repay outstanding obligations. Shareholders who have exercised their preemptive rights and indicated
their intention to exercise additional preemptive rights are entitled to
accretion rights, pro rata to their respective subscriptions, with respect to
any unsubscribed shares by other shareholders during the preemptive rights
period, in accordance with the terms of Article 194 et seq. of the Argentine
Companies Law. Shares not subscribed by the shareholders by virtue of their
exercise of preemptive rights or accretion rights may be offered to third
parties. Under Argentine law, we cannot issue any more shares with multiple votes,
including more Class A shares. Appraisal Rights Whenever our shareholders approve (i) a spinoff or merger in which we are
not the surviving corporation, (ii) a change in our corporate legal status,
(iii) a fundamental change in our corporate purpose, (iv) a change of our
domicile to a location outside of Argentina, (v) a voluntary withdrawal from a
public offering or delisting, (vi) the 157




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continuation of our company in the case of a mandatory delisting or
cancellation of the authorization for a public offering, (vii) an increase of
capital approved by an extraordinary shareholders meeting which would imply a
disbursement by a shareholder or (viii) a total or partial recapitalization
following a mandatory reduction of capital or liquidation, any shareholder that
voted against this action may withdraw from our company and receive the book
value of his shares, determined on the basis of our latest balance sheet
prepared or that should have been prepared in accordance with Argentine laws
and regulations, provided that this shareholder exercises his appraisal rights
within the period set forth below. However, because of the absence of legal
precedent directly on point, there is doubt as to whether holders of our ADSs
will be able to exercise appraisal rights either directly or through the
depositary with respect to Class B shares represented by our ADSs. Appraisal
rights must be exercised within the five days following the adjournment of the
meeting at which the resolution was adopted, in the event that the dissenting
shareholder voted against such resolution, or within 15 days following such
adjournment if the dissenting shareholder did not attend such meeting and can
prove that he was a shareholder on the date of such meeting. In the case of a
merger or spinoff, appraisal rights may not be exercised if the shares to be
received as a result of such transaction are authorized for public offering or
listed. Appraisal rights are extinguished if the resolution giving rise to
such rights is revoked at another shareholders meeting held within 60 days of
the meeting at which the resolution was adopted. Payment on the appraisal rights must be made within one year of the date
of the shareholders meeting at which the resolution was adopted, except when
the resolution was to delist our stock or to continue our company following our
mandatory delisting, in which case the payment period is reduced to 60 days
from the date of the related resolution. Acquisition of Class B Shares by Class B Shareholders Our by-laws also provide that if any person or group of persons acquires
Class B shares or securities convertible into Class B shares representing at
least three percent of our capital stock, then these persons must, within three
days after the acquisition, give us notice of the acquisition, irrespective of
any additional notice requirements under applicable rules of any stock exchange
or regulatory agency. The notice must state the acquisition dates and prices,
the voting power acquired, the purpose of the acquisition and the intention of
the acquiror (including, without limitation, whether it intends to increase its
holding or to obtain control). This provision also applies to subsequent
acquisitions involving a number of Class B shares or securities convertible
into Class B shares representing at least three percent of our capital stock. Capital Increases and Reductions Our capital stock may be increased by resolution of an ordinary
shareholders meeting. Capital increases do not require an amendment of the
by-laws, but must be approved by the CNV, published in the Official Gazette and
registered with the Public Registry of Commerce. Capital reductions may be
voluntary or mandatory. Voluntary reductions of capital must be approved by an
extraordinary meeting of shareholders and may take place only after notice is
published and creditors are given an opportunity to obtain payment or
collateralization of their claims or attachment. Reductions of capital are
mandatory when losses have exceeded reserves or more than 50% of our stated
capital. Shares issued in connection with any increase in capital must be divided
among the various classes in proportion to the number of shares of each class
outstanding at the date of the issuance, provided that the number of shares of
each class actually issued may vary based on the exercise of preemptive rights
and additional preemptive rights in accordance with the procedure described in
the preceding section. Redemption and Repurchase Our shares are subject to redemption in connection with a reduction in
capital by the vote of a majority of shareholders at an extraordinary
shareholders meeting. Any shares so redeemed must be cancelled by us. We may repurchase fully paid shares of our capital stock with retained
earnings or freely available reserves, upon a determination of the board that
this repurchase is necessary in order to avoid a material adverse effect to us. 158




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The boards determination must be explained to shareholders at the next
annual shareholders meeting. We may also repurchase shares of our capital
stock held by a company acquired by or merged with us. In either case, we are
required to resell the shares purchased within one year and must give
shareholders a preemptive right to purchase these shares. Any shares
repurchased by us will not be considered in the determination of a quorum or a
majority. Preferred Shares We may issue non-voting preferred shares or preferred shares with one vote
per share. The economic preferences and rights of our preferred shares will be
determined at the shareholders meeting authorizing the issue of the preferred
shares. Non-voting preferred shares may vote one vote per share in the
following circumstances: (i) if we are in default with respect to the payment
of preferred share dividends, (ii) if the events described under Meetings of
ShareholdersQuorum and Voting Requirements occur, and (iii) if the preferred
shares have been listed on a stock exchange and that listing is cancelled or
suspended. Liquidation The liquidation of our company may be carried out by our Board of
Directors or by one or more liquidators appointed by the shareholders to wind
up its affairs. In the event of liquidation, our assets will be applied to
satisfy our debts and liabilities including liquidation expenses. Any
remaining amounts will be distributed as follows: (i) the amount of the
preferred shares issued shall be reimbursed at its paid-in, nominal value; (ii)
the amount of common shares shall be reimbursed at their paid-in, nominal
value; (iii) cumulative dividends in arrears on preferred shares shall be paid;
and (iv) the remaining balance shall be distributed pro rata among all holders
of common shares. Changes in Shareholder Rights See Capital StockSpecial Class Voting Rights above and Meetings of
Shareholders below. Meetings of Shareholders General Shareholders meetings may be ordinary or extraordinary. We are required
to hold an ordinary shareholders meeting within four months of the close of
each fiscal year to consider the approval of our financial statements, the
allocation of net income for the fiscal year, the approval of the reports of
the Board of Directors and the statutory audit committee and the election and
remuneration of directors and members of the statutory audit committee. Other
matters which may be considered at an ordinary meeting include the
responsibility of directors and members of the statutory audit committee,
capital increases and the issuance of certain corporate bonds. Extraordinary
shareholders meetings may be called at any time to consider matters beyond the
authority of an ordinary meeting, including amendment of the by-laws, issuance
of debentures, early dissolution, merger, spinoff, reduction of capital stock
and redemption of shares, changing our company from one type of legal entity to
another and limitation of shareholders preemptive rights. Notices Notice of shareholders meetings must be published for five days in the
Official Gazette of the Republic of Argentina, in an Argentine newspaper of
wide circulation and in the publications of Argentine exchanges or securities
markets in which our shares are traded, at least ten but not more than 30 days
prior to the date on which the meeting is to be held. The notice must include
information regarding the type of meeting to be held, the date, time and place
of the meeting and the agenda. If there is no quorum at the meeting, notice
for a meeting on second call must be published for three days, at least eight
days before the date of the second meeting, and must be held within 30 days of
the date for which the first meeting was called. The first call and second
call notices may be effected simultaneously in order for the meeting on second
call to be held on the same day as the meeting on first call, but only in the
case of ordinary shareholders meetings. Shareholders meetings may be validly
held without notice if all shares of our outstanding capital stock are present
and resolutions are adopted by unanimous vote. 159




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The Board of Directors will determine appropriate publications for notice
outside Argentina in accordance with requirements of jurisdictions and
exchanges where our shares are traded. Quorum and Voting Requirements The quorum for ordinary meetings of shareholders on first call is a
majority of the shares entitled to vote, and action may be taken by the
affirmative vote of an absolute majority of the shares present that are
entitled to vote on such action. If a quorum is not available, a second call
meeting may be held at which action may be taken by the holders of an absolute
majority of the shares present, regardless of the number of such shares. The
quorum for extraordinary shareholders meeting on first call is sixty percent
of the shares entitled to vote, and if such quorum is not available, a second
call meeting may be held, for which there are no quorum requirement. Action may be taken at extraordinary shareholders meetings by the
affirmative vote of an absolute majority of shares present that are entitled to
vote on such action, except that the approval of a majority of shares with
voting rights (for these purposes, non-voting preferred shares shall have
voting rights), without application of multiple votes, is required in both
first and second call for: (i) the transfer of our domicile outside Argentina,
(ii) a fundamental change of the corporate purpose set forth in the by-laws,
(iii) our anticipated dissolution, (iv) the total or partial repayment of
capital, (v) a merger of our company, if we are not the surviving entity, (vi)
a spinoff of our company, or (vii) changing our corporate legal status. Shareholders meetings may be called by the Board of Directors or the
members of the statutory audit committee whenever required by law or whenever
they deem it necessary. Also, the board or the members of the statutory audit
committee are required to call shareholders meetings upon the request of
shareholders representing an aggregate of at least five percent of our
outstanding capital stock. If the board or the statutory audit committee fail
to call a meeting following this request, a meeting may be ordered by the CNV
or by the courts. In order to attend a meeting, a shareholder must deposit
with us a certificate of book-entry shares registered in its name and issued by
Caja de Valores at least three business days prior to the date on which the
meeting is to be held. A shareholder may be represented by proxy. Proxies may
not be granted to directors, members of the statutory audit committee or
officers or employees of our company. Conflict of Interest A shareholder who votes on a matter involving our company in which its
interest conflicts with ours may, under Argentine law, be liable for damages to
us resulting from its decision, but only if the transaction would not have been
approved without its vote. Limitations on Foreign Investment in Argentina Under the Argentine Foreign Investment Law, which as amended we refer to
as the FIL, the purchase of stock by an individual or legal entity domiciled
abroad or by a local company of foreign capital (as defined in the FIL)
constitutes a foreign investment subject to the FIL. Foreign investments are
generally unrestricted. However, foreign investments in certain industries are
restricted to a certain percentage. No approval is necessary to purchase Class
B shares. The FIL does not limit the right of non-resident or foreign owners
to hold or vote Class B shares, and there are no restrictions in our by-laws
limiting the rights of non-residents or non-Argentines to hold or vote our
Class B shares. However,
General Resolution No. 7 passed in September 2003 by the
Inspección General de Justicia, or I.G.J., set forth certain
requirements for foreign entities registered with the I.G.J., such as
disclosure information related to their proprietary interests in
assets located outside Argentina are at least equivalent in value to
those located inside Argentina. The entities must comply with these
requirements in order to (i) perform activities on a regular basis
through their Argentine branches (Section 118 Argentine Corporate
Law), or (ii) exercise their ownership rights in Argentine Companies
(Section 123 Argentine Corporate Law). In cases where the I.G.J. has concluded that the entities (a)
do not have assets outside Argentina; or (b) have non-current assets
that are not materially significant compared to those non-current
assets which are owned by them and located in Argentina; or (c) the
entitys address in Argentina becomes the place where this
entity makes a majority of its decisions, corporate or otherwise, the
entities may be required to amend and register their by-laws to
comply with Argentine law, thereby becoming an Argentine entity
subject to Argentine law according to Section 124 of Argentine
Corporate Law. In addition, Argentine companies with shareholders
consisting of such entities that fail to comply with these requirements may be subject to the following
sanctions; (i) the I.G.J. may not register corporate decisions
adopted by the Argentine Company when its off-shore shareholder votes
as a shareholder and when that vote is essential in attaining a
majority and any decisions made pursuant to such vote related to the
approval of its annual balance sheet may be declared null and void
for administrative purposes; (ii) whether or not the vote of the
off-shore entity is necessary for purposes of determining quorum or
majority, the I.G.J.  may register the decision without considering
that vote; and (iii) the directors of the Argentine Company may be
held personally liable for actions taken by the Argentine Company. Change of Control In 2001, Argentina adopted Decree-Law No. 677/2001, which, among others,
establishes an Optional Statutory System for Binding Public Offers which
regulates the change of control of a public company. According to this
decree-law, if a person or entity, either directly or indirectly, acquires a
determined percentage of the voting shares of a public company with the
intention of obtaining control, then that person or entity must publicly tender
to purchase all of the target companys outstanding shares. Nevertheless,
companies are free to opt out of the decree-laws requirements, provided they
do so expressly in their by-laws. Our shareholders had been called for an
extraordinary meeting to be held July 8, 2003 to consider the incorporation an
opt-out provision in our by-laws. The 160




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same proposal was submitted to the shareholders of Petrobras Energía. Both
General Special Shareholders Meetings approved the non-adherence to the
Optional Statutory System. This non-adherence does not restrain the voluntary
exercise of such an offering. COMPARISON OF NEW YORK STOCK EXCHANGE CORPORATE GOVERNANCE STANDARDS AND OUR
CORPORATE GOVERNANCE PRACTICE On November 4, 2003, the NYSE established new corporate governance rules.
Under these rules, foreign private issuers are subject to a more limited set of
corporate governance requirements than U.S. domestic issuers. As a foreign
private issuer, we must comply with three new NYSE rules: (i) we must (no later
than July 31, 2005) satisfy the Audit Committee requirements of Rule 10A-3
under the Securities Exchange Act of 1934; (ii) our Chief Executive Officer
must promptly notify NYSE in writing after an executive officer becomes aware
of any material non-compliance with the applicable NYSE corporate governance
rules; and (iii) we must provide a brief description of any significant
difference between our corporate governance practices and those followed by
U.S. companies under NYSE listing standards. As required by the NYSE, the table
below discloses the significant differences between our corporate governance
practices and the NYSE rules. Our corporate governance practices are described
in further detail elsewhere in this annual report. See Item 6. Directors,
Senior Management and Employees and Memorandum and Articles of Association. Section of theNYSE Listed
    
    New York Stock Exchange CorporateCompany Manual
    
    Governance Rules for Domestic Issuers
    
    Our PracticesDirector Independence303A.01
    
    Listed companies must have a majority of
independent directors. Controlled
companies, which would include our
company if it were a U.S. issuer, are
exempt from this requirement. A
controlled company is one in which more
than 50% of the voting power is held by an
individual, group or another company,
rather than the public.
A director is not independent if such
director is:
    
    Argentine law does not require that the majority of
the board members be independent. Only the majority
of the directors on the Audit Committee must be
independent.
At our annual shareholders meeting, our shareholders
determine in accordance with Resolution No. 368 of
the CNV and Decree No. 677/01 whether or not each of
our directors is independent based on the following
criteria.
A director is not independent if such director is:(i) a person who the board determines has
a material direct or indirect relationship
with the company, its parent or a
consolidated subsidiary;
(ii) an employee, or an immediate family
member of an executive officer, of the
company, its parent or a consolidated
subsidiary, other than employment as
interim chairman or CEO;
    
    (i) a member of management or an employee of
shareholders who hold significant interests in the
issuer, or of other entities in which these
shareholders hold either directly or indirectly
significant interests or over which these
shareholders exercise a significant influence;

(ii) an employee of the issuer or has been an
employee in the last three years;(iii) a person who receives, or whose
immediate family member receives, more
than U.S.$100,000 per year in direct
compensation from the company, its parent
or a consolidated subsidiary, other than
director and committee fees or deferred
    
    (iii) a person who has professional relations or is
part of a company or professional association that
maintains professional relations with, or that
receives remunerations or fees (other than directors
fees) from the issuer or from its shareholders that
hold either directly or indirectly significant
interests in or exercise a significant influence over
the issuer, or
 161




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Section of theNYSE Listed
    
    New York Stock Exchange CorporateCompany Manual
    
    Governance Rules for Domestic Issuers
    
    Our Practicescompensation for prior services only (and
other than compensation for service as
interim chairman or CEO or received by an
immediate family member for service as a
non-executive employee);
(iv) a person who is affiliated with or
employed, or whose immediate family member
is affiliated with or employed in a
professional capacity, by a present or
former internal or external auditor of the
company, its parent or a consolidated
subsidiary;
(v) an executive officer, or an immediate
family member of an executive officer, of
another company whose compensation
committees membership includes an
executive officer of the listed company,
its parent or a consolidated subsidiary; or

(vi) an executive officer or employee of a
company, or an immediate family member of
an executive officer of a company, that
makes payments to, or receives payments
from, the listed company, its parent or a
consolidated subsidiary for property or
services in an amount which, in any single
fiscal year, exceeds the greater of U.S.$1
million or 2% of such other companys
consolidated gross revenues (charities are
not included, but any such payments must
be disclosed in the companys proxy (or,
if no proxy is prepared, its Form 10-K/annual
report)).
There is a three-year cooling off period
before non-independent directors can be
considered independent.
    
    from which such shareholders hold
either directly or indirectly significant interests
or exercise a significant influence;
(iv) a person who is either directly or indirectly a
holder of significant interests in the issuer or in
an entity that has significant interests in or
exercises a significant influence over the issuer;
(v) the member is married or is a family member, up
to fourth degree by blood or up to second degree by
affinity, to an individual who would not qualify as
independent; and
(vi) a person who sells or provides either directly
or indirectly goods or services to the issuer or to
shareholders that hold either directly or indirectly
significant interests in or exercise a significant
influence over the issuer and receives compensation
for such services that is substantially higher than
that received as a director.
Significant interests shall mean shareholdings that
represent at least 35% of the capital stock of the
relevant entity, or a smaller percentage when the
person has the right to elect one or more directors
by class of shares or by having entered into
agreements with other shareholders relating to the
governance and the management of the relevant entity
or of its controlling shareholders.
Nicolas Perkins, Roberto Alejandro Fortunati and
Pablo Cavallaro are currently members of our Board of
Directors who qualify as independent directors
pursuant to the factors listed above.Immediate family member includes a
persons spouse, parents, children,
siblings, mothers and fathers-in-law, sons
and daughters-in-law and anyone (other
than domestic employees) who shares the
persons home. Individuals who are no
longer immediate family members due to
legal separation, divorce or death (or
incapacity) are excluded.
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Section of theNYSE Listed
    
    New York Stock Exchange CorporateCompany Manual
    
    Governance Rules for Domestic Issuers
    
    Our Practices303A.03
    
    The non-management directors of each
listed company must meet at regularly
scheduled executive sessions without
management.
    
    Alberto da Fonseca Guimarães, Carlos Alberto Pereira
de Oliveira, Rafael Fernández Morandé, Daniel Maggi,
Héctor Daniel Casal, Luiz Augusto Marciano da
Fonseca, Rui Antonio Alves da Fonseca and Luis Miguel
Sas each, in addition to serving on our Board, have
management positions. Our other eleven directors are
non-management directors. The non-management
directors do not meet at regularly scheduled
executive sessions without the presence of the
managerial directors. See Item 6. Directors,
Senior Management and EmployeesDirectors and Senior
ManagementBoard of Directors.Nominating/Corporate Governance Committee303A.04
    
    Listed companies must have a
nominating/corporate governance committee
composed entirely of independent
directors, with a written charter that
covers certain minimum specified duties.
Exception for controlled companies,
which would include our company if it were
a U.S. issuer.
    
    Argentine law does not require the establishment of a
nominating committee. We do not have a nominating
committee.
We also do not have a corporate governance
committee. Instead, the entire Board of Directors
develops, evaluates and approves our corporate
governance principles with the assistance of an
advisory corporate governance committee formed by
certain of our officers.Management Resources and Compensation Committee303A.05
    
    Listed companies must have a compensation
committee composed entirely of independent
directors, with a written charter that
covers certain minimum specified duties.
Exception for controlled companies,
which would include our company if it were
a U.S. issuer.
    
    Argentine regulations do not require the
establishment of a compensation committee. We do
not have a compensation committee.Audit Committee303A.06
303A.07
    
    Listed companies must have an Audit
Committee with a minimum of three
independent directors that satisfy the
independence requirements of Rule 10A-3
under the Exchange Act, with a written
charter that covers certain minimum
specified duties.
    
    Our Audit Committee is an advisory committee to the
Board of Directors. Argentine law requires that the
audit committee be composed of three members from the
Board of Directors (with a majority of independent
directors), all of whom are well-versed in business,
financial or accounting matters. We are not required
to satisfy the audit committee requirements of Rule
10A-3 under the Exchange Act until July 31, 2005.
The members of our audit committee will not need to
satisfy the NYSE independence standards that
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Section of theNYSE Listed
    
    New York Stock Exchange CorporateCompany Manual
    
    Governance Rules for Domestic Issuers
    
    Our Practicesare not
required by Rule 10A-3. Nonetheless, our Audit
Committee, established on May 7, 2004, is composed of
three directors who each satisfy the independence
requirements of Rule 10A-3. One member of the Audit
Committee qualifies as a financial expert within
the meaning of Item 16A of the Form 20-F. See Item
16A. Audit Committee Financial Expert.Our Audit Committee is responsible for, among other
things: (i) monitoring and evaluating the activities
of the internal and external auditors, (ii)
supervising the process for preparation of our
financial statements, (iii) ensuring that our
financial statements comply with applicable legal
requirements, (iv) supervising the application of our
disclosure policies with respect to our risk
management practices, (v) providing the market with
complete information with respect to transactions
where members of corporate bodies or controlling
shareholders of ours have conflicts of interest, and
(vi) verifying compliance with applicable codes of
conduct. See Item 6. Directors, Senior Management
and EmployeesBoard PracticesAudit Committee.Under Argentine law, the Board of Directors must
present a proposal regarding the appointment of the
external auditor to the shareholders meeting, and
the shareholders must appoint the external auditor.
The Audit Committee must issue an opinion on the
Board of Directors proposal to the shareholders.We also have an internal audit department.In accordance with Argentine law, we also have
established a Statutory Syndic Committee that is
comprised of three members and three alternate
members, approved by our shareholders. Members of
the Statutory Syndic Committee are not members of our
Board of Directors. The primary responsibilities of
the Statutory Syndic Committee are to monitor
managements compliance with the Companies Law, our
by-laws and the shareholders resolutions. The
Statutory Syndic Committee also performs other
functions, including: (i) attending meetings of the
Board of Directors and shareholders, (ii) calling
extraordinary shareholders meetings when deemed
necessary or when required by shareholders, in
accordance with the Business Companies Law, No.
19550, (iii) presenting a report on the reports of
the Board of Directors and the annual financial
statements at regular shareholders meetings, and
(iv)
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Section of theNYSE Listed
    
    New York Stock Exchange CorporateCompany Manual
    
    Governance Rules for Domestic Issuers
    
    Our Practicesinvestigating written complaints of shareholders
representing not less than 2% of the capital stock.
See Item 6. Directors, Senior Management and
EmployeesBoard PracticesStatutory Syndic Committee.Equity Compensation Plans303A.08
    
    Shareholders must be given the opportunity
to vote on equity-compensation plans and
material revisions thereto, with limited
exemptions set forth in the NYSE rules.
    
    Our Board of Directors approves the equity
compensation plans for our executive officers and
senior management. For a description of our stock
option programs for our executive officers and senior
management see Item 6. Directors, Senior Management
and EmployeesCompensation.The Audit Committee issues an opinion on the
reasonableness of the Board of Directors proposals
regarding fees and executive equity compensation
plans.Corporate Governance Guidelines303A.09
    
    Listed companies must adopt and disclose
corporate governance guidelines.
    
    Corporate governance guidelines are not required by
Argentine law, but the company has nonetheless
adopted the practice of issuing corporate governance
policies.Code of Ethics for Directors, Officers and Employees303A.10
    
    Listed companies must adopt and disclose a
code of business conduct and ethics for
directors, officers and employees, and
promptly disclose any waivers of the code
for directors or executive officers.
    
    We have adopted a Code of Conduct and Business Ethics
applicable to all employees. See Item 16B. Code of
Ethics. Any amendment to the code will be disclosed
on our web site at www.petrobrasenergia.com.
 MATERIAL CONTRACTS We are party to a number of material financing agreements, including the
underlying agreements for our Global Note Program, an assignment to an
international lending institution of fees receivable in connection with the
Oritupano Leona area and a letter of credit and reimbursement agreement entered
into to backstop certain financial commitments related to our investment in
OCP. These agreements and other financing agreements are described under Item
5. Operating and Financial Review and ProspectsLiquidity and Capital
Resources and Contractual Obligations. In April 2004, Petrobras Energía and Enron reached an agreement with
respect to their investments in CIESA and TGS. Pursuant to the agreement,
Petrobras Energía and Enron agreed to release each other from all claims
related to their investments in CIESA and TGS. In addition, in order to
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CIESAs financial debt, both parties agreed to a two-stage transfer involving
their equity interests in TGS and CIESA. In stage one, we will transfer our
7.35% direct interest in TGS to Enron, and, in stage two, CIESA will transfer a
4.3% interest in TGS to Enron. In exchange, Enron will place its shares of
CIESA in trust, 40% in stage one and the remaining 10% in stage two. These
transfers are subject to several conditions, one of which is approval by
ENARGAS. See Item 4. Information About UsHydrocarbon Marketing and
TransportationGas TransportationTGS. Our agreements with related parties are described in Related Party
Transactions under Item 7. We also enter into a number of significant agreements in the ordinary
course of our business, including an oil transportation agreement with OCP.
This agreement is described in Risk FactorsProduction of oil in Block 31 in
Ecuador is significantly delayed, and this delay has and will
continue to affect our results. Further delays could result in an
increase is our operating losses related to our group of assets in
Ecuador under
Item 3 and Oil and Gas Exploration and ProductionExplorationEcuador under
Item 4. EXCHANGE CONTROLS The Argentine foreign exchange market was subject to exchange controls
until December 1989. From 1989 to December 3, 2001, there were no foreign
exchange controls preventing or restricting the conversion of pesos into U.S.
dollars. Since early December 2001, the Argentine authorities implemented a number
of monetary and currency exchange control measures that included restrictions
on the withdrawal of funds deposited with banks and strict restrictions for
making transfers abroad, with the exception of those related to foreign trade
and other authorized transactions. These regulations have been amended on a
number of occasions since they were first promulgated and we cannot assure you
as to how long these current regulations will be in effect or whether they will
be made stricter. Pursuant to resolutions issued by the Central Bank seeking a gradual
normalization of the local foreign exchange market, effective January 8, 2003,
prior authorization from the Central Bank is no longer required to transfer
funds abroad for payment to foreign beneficiaries of corporate profits and
dividends reported as payable under approved financial statements certified by
an independent auditor. In addition, for the remittance abroad of funds required for principal
payments under financial loans, prior Central Bank authorization is no longer
required as of May 6, 2003, provided such debts have been disclosed under the
Informative Regime of External Debts (Régimen Informativo de Pasivos Externos). Interest payments on outstanding financial indebtedness no longer require
Central Bank approval for their remittance abroad, provided that the transfer
abroad in connection with such payments is made not more than 15 days in
advance of their stated maturity date. TAXATION Argentine Taxes General The following discussion describes the material Argentine tax matters
relating to the acquisition, ownership and disposition of our ADSs or Class B
shares. The discussion describes the principal Argentine tax consequences of the
acquisition, ownership and disposition of our ADSs or Class B shares, but it
does not purport to be a comprehensive description of all of the Argentine tax
considerations that may be relevant to your decision to acquire our ADSs or
Class B shares. For purposes of the following discussion of Argentine tax law,
the purchase, sale or disposition of ADSs is treated as a purchase, sale or
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The discussion is based upon tax laws of Argentina, regulations
thereunder, and administrative and judicial interpretations thereof, as in
effect on the date of this annual report and subject to change with possibly
retroactive effect. In addition, the summary is based in part on
representations of the depositary and assumes that each obligation provided for
in, or otherwise contemplated by, the deposit agreement for our ADSs or any
related document will be performed in accordance with its terms. Prospective
purchasers of ADSs or Class B shares should consult their own tax advisors as
to the Argentine or other tax consequences of the acquisition, ownership and
disposition of our ADSs or Class B shares in their particular circumstances. Income Tax Capital Gains Sales or other dispositions of our Class B shares or ADSs by non-residents
of Argentina or Argentine resident individuals or undivided estates located in
Argentina are exempt from paying income tax on capital gains resulting from the
sale. However, capital gains of legal entities domiciled in Argentina
resulting from the sale or other disposition of our Class B shares or ADSs will
be subject to income tax at a 35% rate. Argentine pension funds, investment
funds and some foundations are not subject to income tax. There will be no
withholding by us on account of this tax. Dividends If any dividend is paid to you on our Class B shares and ADSs that is from
corporate earnings that have not already been subject to Argentine corporate
income tax determined in accordance with general income tax regulations, we
will be required to deduct and withhold Argentine income tax at a rate of 35%
on the amount of the dividend paid by us. However, so long as we distribute dividends to you on our Class B shares
and ADSs that are derived from earnings of Petrobras Energía on which Argentine
corporate income tax has been paid, we will not be required to withhold
Argentine income tax on those dividends. Thus, we expect that dividends paid
to you on our Class B shares and ADSs will not be subject to Argentine
withholding tax under current Argentine law. Capital Reductions and other Distributions Capital reductions and redemptions of our Class B shares and ADSs are not
subject to income tax up to an amount equivalent to the adjusted contributed
capital corresponding to the Class B shares and ADSs to be redeemed plus
accumulated taxable earnings after income taxes and dividends received. Any
distribution exceeding this amount will be considered as a dividend for tax
purposes and withholding tax would apply as described above. Tax on Personal Property Corporations, partnerships, establishments, financial trusts and other
legal entities domiciled or located in Argentina are not subject to the
personal assets tax. Shareholdings or interests in companies governed by Law 19,550, that are
held by individuals or undivided estates domiciled or located in Argentina or
abroad, or by companies or other legal persons located abroad are subject to
the personal assets tax. A company is liable for the personal assets tax
payable by its shareholders in respect of their share ownership. A company
liable for this tax payment will be entitled to seek reimbursement of the
amount paid from the shareholders, by way of withholding or by foreclosing
directly on the assets that gave rise to such payment. Consequently, we are
liable to pay the personal assets tax in respect of our Class B shares and ADSs
and we are entitled to seek reimbursement of the amount paid from the
shareholders. The applicable tax rate is 0.50% on the equity value of the
shares, calculated as of December 31 of the year under consideration. For purposes of the above paragraph, shareholdings or interests in
companies governed by Law 19,550, the holders of which are companies or any
other kinds of legal persons domiciled or located abroad, are presumed to 167




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indirectly belong to individuals domiciled abroad or to undivided estates
located abroad. Contrary evidence is not accepted to rebut this presumption. Other Taxes There is no inheritance, gift, succession or value-added taxes applicable
to the ownership, transfer, exchange or disposition of our Class B shares or
ADSs. There are no Argentine stamp, issue, registration or similar taxes or
duties payable by holders of our Class B shares or ADSs. There is no Argentine gross revenue tax applicable on our Class B shares
or ADSs or on income obtained from the disposition of our Class B shares or
ADSs. Our Class B shares or ADSs owned by legal persons (corporations,
partnerships, certain associations and non-financial trusts organized in
Argentina and permanent establishments owned by foreign beneficiaries) are
exempt from tax on minimum presumed income. Commissions paid in brokerage transactions for the sale of our Class B
shares on the Buenos Aires Stock Exchange are subject to a value-added tax at a
rate of 21%. United States Federal Income Taxes General The following discussion summarizes the United States federal income tax
considerations relevant to the acquisition, ownership and disposition of ADSs
or Class B shares by U.S. holders (as defined below). This discussion is based
on the United States Internal Revenue Code of 1986, as amended (referred to as
the Code), Treasury regulations promulgated or proposed under the Code,
published rulings, and administrative and judicial interpretations of the Code
and the Treasury regulations, all as of the date hereof, and all of which are
subject to change, possibly with retroactive effect, and different
interpretations. This summary is based in part on representations of the
depositary and assumes that each obligation provided for in or otherwise
contemplated by the deposit agreement for our ADSs or any related document will
be performed in accordance with its terms. This discussion is addressed only
to U.S. holders and does not address any United States federal income tax
considerations that might be relevant to persons other than U.S. holders.
Further, this discussion deals only with U.S. holders that hold ADSs as capital
assets (generally, property held for investment) within the meaning of Section
1221 of the Code, and does not address the tax treatment of holders that may be
subject to special tax rules, such as banks, insurance companies, tax-exempt
organizations, brokers or dealers in securities or currencies, traders in
securities that elect mark-to-market treatment, persons that hold the ADSs as
part of a hedge, straddle, conversion transaction or other integrated
investment, persons that hold ADSs or Class B shares through a partnership or
other pass-through entity, U.S. holders who have a functional currency other
than the U.S. dollar or U.S. holders that own or are treated as owning 10% or
more of the voting power of our shares. This discussion does not describe all aspects of United States federal
income taxation that may be relevant to a particular investor in light of such
investors particular circumstances. U.S. holders should consult their own tax
advisors as to the specific tax consequences of the acquisition, ownership and
disposition of our ADSs or Class B shares, including the application and effect
of United States federal, state, local, foreign and other tax laws and the
possible effects of changes in United States federal or other tax laws. In general, for United States federal income tax purposes, if you hold our
ADSs, you will be treated as the beneficial owner of our Class B shares
represented by those ADSs. For purposes of this discussion, you are a U.S.
holder if you are a beneficial owner of our Class B shares and you are, for
United States federal income tax purposes, (a) an individual who is a citizen
or resident of the United States, (b) a corporation (or other business entity
created or organized in or under the laws of the United States or of any state
or the District of Columbia treated as a corporation), or (c) otherwise subject
to United States federal income taxation on a net income basis with respect to
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Taxation of our ADSs Distributions Distributions we make on our ADSs and Class B shares will be treated as
taxable dividends to you to the extent of our current and accumulated earnings
and profits as determined under United States federal income tax principles. A
dividend, generally, will be included in the gross income of a U.S. holder when
the dividend is actually or constructively received by the depository. Such
dividends will not be eligible for the dividends received deduction generally
allowed to U.S. corporations in respect to dividends received from other U.S.
corporations. Subject to certain exceptions for short-term and hedged positions, the
U.S. dollar amount of dividends received by an individual U.S. holder prior to
January 1, 2009 with respect to the ADSs will be subject to taxation at a
maximum rate of 15% if the dividends are qualified dividends. Dividends paid
on the ADSs will be treated as qualified dividends if (i) the ADSs are readily
tradable on an established securities market in the United States and (ii) we
were not, in the year prior to the year in which the dividend was paid, and are
not, in the year in which the dividend is paid, a passive foreign investment
company (PFIC), foreign personal holding company (FPHC) or foreign
investment company (FIC). The ADSs are listed on the New York Stock
Exchange, and will qualify as readily tradable on an established securities
market in the United States so long as they are so listed. Based on our
audited financial statements and relevant market and shareholder data, we
believe that we were not treated as a PFIC, FPHC or FIC for United States
federal income tax purposes with respect to the 2003 taxable year. In
addition, based on our audited financial statements and its current
expectations regarding the value and nature of our assets, the sources and
nature of our income, and relevant market and shareholder data, we do not
anticipate becoming a PFIC, FPHC or FIC for the 2004 taxable year. Based on existing guidance, it is not entirely clear whether dividends
received with respect to the Class B shares will be treated as qualified
dividends, because the Class B shares are not themselves listed on a U.S.
exchange. In addition, the U.S. Treasury has announced its intention to
promulgate rules pursuant to which U.S. holders of ADSs or common stock and
intermediaries through whom such securities are held will be permitted to rely
on certifications from issuers to establish that dividends are treated as
qualified dividends. Because such procedures have not yet been issued, it is
not clear whether we will be able to comply with them. U.S. holders of ADSs
and Class B shares should consult their own tax advisors regarding the
availability of the reduced dividend tax rate in the light of their own
particular circumstances. The amount of dividend income taxable to you generally will include the
amount of Argentine taxes, if any, that we withhold (as described under
"Argentine Taxes). Thus, in the event such withholding taxes are imposed,
you most likely will be required to report income in an amount greater than the
cash you receive in respect of payments in respect of the ADSs. Subject to
various limitations, you may be eligible to claim the Argentine income tax
withheld in connection with any distribution on ADSs as a credit or deduction
for purposes of computing your United States federal income tax liability.
Foreign tax credits will not be allowed for withholding taxes imposed with
regard to certain short-term or hedged positions in securities and may not be
allowed with regard to arrangements in which a U.S. holders expected economic
profit is insubstantial. Dividends we pay in respect of our ADSs generally
will be treated as foreign source income and generally will constitute
passive income (or, in the case of certain U.S. holders, financial services
income) for foreign tax credit purposes. Special rules will apply to the
calculation of foreign tax credits in respect of dividend income that is
subject to preferential rates of United States federal income tax pursuant to
recently enacted legislation. U.S. holders should consult with their own tax
advisors with regard to the availability of foreign tax credits and the
application of the foreign tax credit limitations to their particular
situation. If a dividend is paid in pesos, the amount you must include in gross
income will be the U.S. dollar value of the distributed pesos, as determined on
the date of receipt by the depository, regardless of whether the payment is in
fact converted into U.S. dollars at that time. You will have a tax basis in
such pesos for United States federal income tax purposes equal to the U.S.
dollar value on the date of such receipt. Any subsequent gain or loss in
respect of such pesos arising from exchange rate fluctuations will be ordinary
income or loss and will be treated as income from U.S. sources for foreign tax
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It is unlikely that you will be able to claim a foreign tax credit for any
Argentine personal property tax (as described in Argentine Taxes), but you
may be able to deduct such tax in computing your United States federal income
tax liability, subject to applicable limitations. Sale, Exchange or other Disposition Deposits and withdrawals of our Class B shares by U.S. holders in exchange
for our ADSs will not result in the realization of gain or loss for United
States federal income tax purposes. Upon a sale, exchange or other disposition of our ADSs, a U.S. holder
generally will recognize capital gain or loss equal to the difference between
the amount realized on such disposition (which, in the event of a redemption,
will include any amount withheld by us in respect of Argentine taxes imposed on
such redemption) and your adjusted tax basis in our ADSs (which, generally, is
the U.S. dollar cost thereof). Any gain that you recognize generally will be
treated as U.S. source income for United States foreign tax credit purposes.
Consequently, if a withholding tax is imposed on such gain, you will not be
able to use any corresponding tax credit unless you have other foreign source
income of the appropriate type in respect of which the credit may be used.
Your net capital gains may be taxed at reduced rates if you are an individual
and your holding period for our ADSs is more than one year. Backup Withholding The information reporting requirements of the Code generally will apply to
distributions to you. Subject to certain exceptions, backup withholding at a
rate of 28% may apply to payments of dividends on our ADSs and to payments of
the proceeds of a sale or exchange of the ADSs that are made to a non-corporate
U.S. holder if such holder fails to provide a correct taxpayer identification
number or otherwise comply with applicable requirements of the backup
withholding rules. The backup withholding tax is not an additional tax and may
be credited against a U.S. holders United States federal income tax liability,
provided that correct information is provided to the Internal Revenue Service.
U.S. holders should consult their own tax advisors regarding their
qualification for exemption from backup withholding and the procedure for
obtaining such exemption, if applicable. DOCUMENTS ON DISPLAY We file reports, including annual reports on Form 20-F, and other
information with the Securities and Exchange Commission pursuant to the rules
and regulations of the SEC that apply to foreign private issuers. You may read
and copy any materials filed with the SEC at its public reference rooms in
Washington, D.C., at 450 5th Street, N.W., Washington, D.C. 20549. Please call
the SEC at 1-800-SEC-0330 for further information on the public reference room.
As a foreign private issuer, we were not required to make filings with the SEC
by electronic means prior to November 4, 2002, although we were permitted to do
so. Any filings we make electronically will be available to the public over
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Item 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The following qualitative and quantitative information is provided about
our exposure to market risks derived from the ordinary course of business. This analysis comprises statements about future events which may not occur
and may imply risks and uncertainties. Actual results may significantly differ
due to several factors. Qualitative Disclosures Our results of operations and financial condition are exposed to three
principal market risk categories: (i) commodity price risk, (ii) foreign
currency exchange rate risk, and (iii) interest rate risk. We periodically
review the risks associated with our businesses at a senior management level,
based on an approach that has evolved from an independent analysis of each
business unit to a risk management strategy that focuses on measuring and
monitoring the risks that affect our overall portfolio of assets. We believe
our risk management strategy mitigates risks related to the volatility of the
prices of crude oil and crude oil by-products, supports our capital expenditure
plans and protects our return on investment related to certain capital
projects. Financial hedging is a tool that we employ to mitigate the volatility of
our results and cash flow resulting from fluctuations in the price of crude oil
and its by-products. These financial operations expose us to credit risk. We apply strict
requirements for the approval of lines of credit, apply several procedures to
assess such risks and seek to reduce our credit exposure by using certain tools
(such as agreements for collateral advance payment or collection of such
operations and the offset of collections and payments). Such financial
instruments are entered into subject to strict restrictions set by our senior
management. The results of hedging operations are periodically reviewed by
management in order to confirm they remain effective and relevant, consistent
with market conditions. Such instruments are entered into in accordance with
the goals of our market risk management strategy. The boards of directors of our affiliates formulate their relevant risk
management policies. Commodity Price Risk. In the Oil and Gas Exploration and Production,
Refining, and Petrochemicals businesses we are exposed to market risk in
relation to price volatility, mainly of crude oil and by-products. We regularly
evaluate the opportunity to enter into derivative transactions to mitigate our
exposure to changes in the price of crude oil and crude oil by-products. We use several derivative financial instruments to reduce this exposure.
Historically, we have prioritized a risk strategy that, principally through
swaps and producer collars, was designed to set crude oil sale prices at
certain intervals. As a result, the results of hedging derivative instruments
were generally offset by changes in crude oil sale prices. This policy,
although it proved effective to comply with the proposed objectives, especially
in 1998 when oil prices were at all time lows, has prevented us from benefiting
from price increases. Since 2002, we have increased the use of option contracts within our crude
oil prices hedging strategy. These contracts provide greater flexibility,
provide protection against a drop in prices and allow the possibility for us to
benefit from a high price scenario. Simultaneously, this strategy limits the
financial risk associated with the collateral requirements of swaps and
producers collars. The chart below provides information as of December 31, 2003, regarding
derivative contracts entered into by us in connection with our exposure to
commodity price risks. Foreign Exchange Risk.Our results of operations and financial condition
are sensitive to changes in the exchange rate between the Argentine peso and
other foreign currencies. 171




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As of December 31, 2003, all of our financial debt and a significant
portion of our affiliates debt was denominated in U.S. dollars. Historically, exposure of the Argentine peso to the U.S. dollar had not
been hedged since under the Convertibility Law, effective as of 1991, the BCRA
was obliged to sell U.S. dollars at a rate of exchange not exceeding one peso
per U.S. dollar. In the economic, financial and regulatory scenario prevailing
as of December 31, 2001, our cash flow generation provided us with a natural
hedge for our U.S. dollar-exposure, since a significant portion of our and our
subsidiaries income was directly or indirectly denominated in U.S. dollars. On January 6, 2002, the Argentine Government enacted the Public Emergency
Law that changed the convertibility system in force, which severely affected
our U.S. dollar-denominated operating cash flow. Measures such as the
pesification of utility rates previously denominated in U.S. dollars and their
subsequent renegotiation, the implementation of new taxes on hydrocarbon
exports and the enforcement of policies limiting our ability to increase our
peso-denominated prices to maintain our operating cash flows when measured in
U.S. dollars, negatively affected our ability to hedge the impact of the peso
devaluation on the financial cost of our U.S. dollar-denominated debt. As of the second half of 2002, domestic prices of the main commodities
have significantly recovered in line with export prices. In addition, we have
aggressively pursued a trade policy of consolidation and opening of export
markets to capitalize on domestic and export price asymmetries. In the light
of the above and the strength of our foreign operations with a cash flow
primarily denominated in U.S. dollars, our exposure to peso fluctuations has
dropped and we have substantially recovered our ability to naturally hedge our
cash exposure to U.S. dollar liabilities. Interest Rate Risks. Interest rate risk management mainly aims at
reducing overall financial costs and adjusting our exposure to risk. In order to reduce interest rate volatility, we, by means of the
application of mathematical models that incorporate historical volatility and
correlation analyses, permanently evaluate the opportunity to enter into
derivative instruments. As of December 31, 2003, we maintained an interest rate risk hedging
contract aimed at managing the risk related to LIBO rate volatility from our
Class C notes, fixing the respective interest rate at 7.93% per annum. As a
result of this hedging contract, as of December 31, 2003, approximately 63% our
total financial debt was subject to fixed rates and 37% was subject to variable
rates. The variable rate debt is mainly linked to the LIBO rate. This risk,
however, is mitigated by the natural hedge provided by the portion of fees
received for production activities in the Oritupano-Leona area and by certain
financial assets, with cash flows determined by LIBO or a similar rate. Quantitative Disclosure The chart below provides quantitative information about our derivative
financial instruments and other financial instruments as of December 31, 2003,
that are sensitive to changes in commodity prices, interest rates and foreign
exchange rates. 172




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Commodity Price Risk: Collections (Payments)Expected MaturityEstimated2004
    
    2005
    
    Total
    
    Fair ValueSales Price ExposureCrude oil price swaps(2)Contract volumes (million barrels)
    
    
    4.1
    
    
    
    
    
    
    
    4.1Average settlement prices (U.S.$  per barrel)
    
    
    18.64
    
    
    
    
    
    
    
    Notional amount (U.S.$ million)
    
    
    77
    
    
    
    
    
    
    
    77Expected cash flow (U.S.$ million)(1)
    
    
    (52
    )
    
    
    
    
    
    
    (52
    )
    
    
    (52
    )Swap options(3)Contract volumes (million barrels)
    
    
    6.9
    
    
    
    7.3
    
    
    
    14.2Average settlement price (U.S.$  per barrel)
    
    
    19.00
    
    
    
    19.00
    
    
    
    Notional amount (U.S.$ million)
    
    
    131
    
    
    
    139
    
    
    
    270Expected cash flow (U.S.$ million)(1)
    
    
    (75
    )
    
    
    (65
    )
    
    
    (140
    )
    
    
    (135
    )
   (1)
    
    The expected cash flow was calculated based on the closing price of
future contracts of Light Sweet Crude Oil on the New York Mercantile
Exchange as of December 31, 2003.(2)
    
    These transactions are swaps, which were originally issued as options
that have been exercised by the counterparty.(3)
    
    These transactions are sold consumer swaptions. Foreign Currency Exchange Rate Risk and Interest Rate Risk: Expected Maturity(millions of pesos)Estimated2004
    
    2005
    
    2006
    
    2007
    
    2008
    
    Thereafter
    
    Total
    
    Fair ValueShort- and long-term debtU.S. dollars fixed rate
    
    
    635
    
    
    
    471
    
    
    
    15
    
    
    
    831
    
    
    
    11
    
    
    
    1,853
    
    
    
    3,816
    
    
    
    3,887Average interest rate (%)
    
    
    8.0
    
    
    
    7.9
    
    
    
    9.0
    
    
    
    8.9
    
    
    
    5.6
    
    
    
    8.6Variable rate
    
    
    419
    
    
    
    500
    
    
    
    465
    
    
    
    453
    
    
    
    37
    
    
    
    373
    
    
    
    2,247
    
    
    
    2,246Average interest rate (%)
    
    
    5.1
    
    
    
    5.2
    
    
    
    5.2
    
    
    
    5.3
    
    
    
    6.5
    
    
    
    3.2Total
    
    
    1,054
    
    
    
    971
    
    
    
    480
    
    
    
    1,284
    
    
    
    48
    
    
    
    2,226
    
    
    
    6,063
    
    
    
    6,134
 173




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Item 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES Not applicable. 
 Item 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES No events required to be reported have occurred. 
 Item 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITYHOLDERS AND USE OF PROCEEDS None. 174




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Item 15. CONTROLS AND PROCEDURES (a) We carried out an evaluation under the supervision and with the
participation of our management, including our chief executive officer and
chief financial officer, of the effectiveness of the design and operation of
our disclosure controls and procedures, as of December 31, 2003. There are
inherent limitations to the effectiveness of any system of disclosure controls
and procedures, including the possibility of human error and the circumvention
or overriding of the controls and procedures. Accordingly, even effective
disclosure controls and procedures can only provide reasonable assurance of
achieving their control objectives. Based upon our evaluation, our chief
executive officer and chief financial officer concluded that the disclosure
controls and procedures as of December 31, 2003 were effective to provide
reasonable assurance that information required to be disclosed in the reports
we file and submit under the Securities Exchange Act of 1934, as amended, is
recorded, processed, summarized and reported as and when required. (b) There has been no change in our internal control over financial
reporting during 2003 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting. 175




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Item 16A. AUDIT COMMITTEE FINANCIAL EXPERT At the Board of Directors meeting on May 7, 2004, our Directors determined
and designated that Cedric Bridger is an audit committee financial expert
within the meaning of this Item 16A. Item 16B. CODE OF ETHICS We have adopted a code of ethics, as defined in Item 16B of this annual
report on Form 20-F. Our code of ethics applies to our chief executive
officer, chief financial officer, chief accounting officer, and persons
performing similar functions as well as to our directors and other officers and
employees. Our code of ethics is available on our web site at
http://www.petrobrasenergia.com. Item 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES Audit and Non-Audit Fees Fees for professional services provided to us by our independent auditors,
Pistrelli, Henry Martin y Asociados S.R.L., a member firm of Ernst & Young
Global and other member firms of Ernst & Young Global, during the fiscal years
ended December 31, 2002 and 2003 in each of the following categories are: Year ended December 31,2002
    
    2003(in thousands of pesos)Audit fees
    
    
    3,209
    
    
    
    4,333Audit-related fees
    
    
    1,685
    
    
    
    2,323Tax fees
    
    
    68
    
    
    
    238Total fees
    
    
    4,962
    
    
    
    6,894
 Audit fees.Audit fees in the above table are mainly for in connection
with the audit of our annual financial statements and the review of our
quarterly reports, statutory audits of subsidiaries, and comfort letters. Audit-related fees. Audit-related fees in the above table are mainly for
audit reports required by the parent company and reviews of our
(a) internal controls of our application
systems, and (b) security of our technical
infrastructure. Tax fees. Tax fees in the above table are fees mainly for tax compliance
and tax advice. Audit Committee Pre-Approval Policies and Procedures The Audit Committee must pre-approve all services provided by the external
auditors to ensure the auditors independence and compliance with all
applicable legal restrictions. Pre-approval is either general or specific in
nature. All services that are predictable and recurrent in nature, which can
be performed in a reasonably foreseeable time frame and at a cost that can be
reasonably estimated may be approved by the Audit Committee in a general
fashion on an annual basis. Services to be pre-approved on a general basis
must be described in sufficient detail so that their scope is readily apparent.
This description must also include an estimate of the fees payable for such
services. Specific pre-approval is required for any services not subject to
general pre-approval and/or exceeding the estimated cost of those services.
Detailed, written descriptions of any proposed services must be delivered to
the administrative manager, who will determine whether such services have
already been pre-approved and bring to the Audit Committees attention those
services that have not been pre-approved. Any doubts as to the scope of a
pre-approved service must be resolved exclusively by the Audit Committee.
Prior to Audit Committee meetings and at least three times a year, the
administrative manager must provide a report on all services provided by the
external auditor and related fees to the Audit Committee. The Audit Committee
is also required to 176




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periodically discuss with the external auditors the services they provide
to us and our affiliates and the compensation they receive for those services. Item 16D. EXEMPTIONS FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES. Not applicable. Item 16E. PURCHASES OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED PURCHASERS. Not applicable. 177




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Item 17. FINANCIAL STATEMENTS We have responded to Item 18 in lieu of responding to this Item. 
 Item 18. FINANCIAL STATEMENTS Reference
is made to pages F-1 to F-100 of this annual report. 178




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Item 19. EXHIBITS ExhibitNo.
    
    Description1.1
    
    English translation of Estatutos (by-laws) of Petrobras Energía Participaciones S.A.2.1
    
    Reference is made to the following Exhibits on file with the Securities and Exchange Commission
contained in Petrobras Energía Participaciones S.A.s Registration Statement on Form F-4 (333-11130)
filed with the Commission on November 15, 1999: Exhibit No. 4.2, Form of Deposit Agreement among
Petrobras Energía Participaciones S.A. (formerly PC Holdings S.A.), Citibank, N.A., as depositary,
and the Holders and Beneficial Owners of American Depositary Shares evidenced by American Depositary
Receipts issued thereunder, including the form of American Depositary Receipt; Exhibit No. 4.3,
English translations of letters from members of the Perez Companc family to Petrobras Energía
Participaciones S.A. (formerly PC Holdings S.A.) whereby such persons agree not to acquire an
interest in certain entities; and Exhibit No. 4.4, English translation of Assignment Agreement among
Class A shareholders and Petrobras Energía Participaciones S.A. (formerly PC Holdings S.A.)
regarding the partial assignment of dividends to Class B shareholders.2.2
    
    Trust Deed dated June 29, 1993 between Compania Naviera Perez Companc S.A.C.F.I.M.F.A. and Citicorp
Trustee Company Limited.*2.3
    
    Supplemental Trust Deed dated January 13, 1995 among Compania Naviera Perez Companc
S.A.C.F.I.M.F.A., Citicorp Trustee Company Limited and others, Second Supplemental Trust Deed dated
September 11, 1995 among Compania Naviera Perez Companc S.A.C.F.I.M.F.A., Citicorp Trustee Company
Limited and others, Third Supplemental Trust Deed dated January 9, 1996 among Petrobras Energía
Participaciones S.A., Citicorp Trustee Company Limited and others, Fourth Supplemental Trust Deed
dated May 2, 1996 among Petrobras Energía Participaciones S.A., Citicorp Trustee Company Limited and
others, Fifth Supplemental Trust Deed dated January 8, 1997 between Petrobras Energía
Participaciones S.A. and Citicorp Trustee Company Limited, Sixth Supplemental Trust Deed dated May,
1997 between Petrobras Energía Participaciones S.A. and Citicorp Trustee Company Limited, Seventh
Supplemental Trust Deed dated December 21, 1998 between Petrobras Energía Participaciones S.A. and
Citicorp Trustee Company Limited, Eighth Supplemental Trust Deed dated November 28, 2000 between
Petrobras Energía and Citicorp Trustee Company Limited, each relating to the Trust Deed dated June
29, 1993.*2.4
    
    Form of U.S.$193,450,000 Restricted Global Note and Form of U.S.$106,550,000 Unrestricted Global
Note, related to Petrobras Energías 9% notes due 2004.*2.5
    
    Form of U.S.$323,500,000 Restricted Global Note and Form of U.S.$76,500,000 Unrestricted Global
Note, related to Petrobras Energías 8.125% notes due 2007.*2.6
    
    Indenture dated May 1, 1998 between Petrobras Energía Participaciones, S.A. and Citibank, N.A., as
Trustee.*2.7
    
    Form of U.S.$92,200,000 Restricted Global Note and Form of U.S.$107,800,000 Unrestricted Global
Note, related to Petrobras Energías 9% Series B Notes due 2006.*2.8
    
    Third Supplemental Indenture dated July 17, 2001, to the Indenture dated May 1, 1998 and filed
hereto as Exhibit 2(b)(v), among Petrobras Energía, Citibank N.A. as Trustee, Co-Security Registrar,
Authenticating Agent and Transfer Agent in New York, Citibank N.A. acting through its Buenos Aires
branch, as Security Registrar and Transfer Agent in Argentina, Bankers Trust Company as
Administrative Agent, Calculation Agent, Paying Agent and Oil Agent, Deutsche Bank AG, London
 179




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ExhibitNo.
    
    DescriptionBranch, as Oil Purchaser and Deutsche Bank S.A. as Paying Agent in Argentina.*2.9
    
    Sixth Supplemental Indenture dated as of July 26, 2002, to the Indenture dated as of May 1, 1998,
between Petrobras Energía and Citibank, N.A. **2.10
    
    Ninth Supplemental Trust Deed dated July 31, 2002, to the Trust Deed dated June 29, 1993, between
Petrobras Energía S.A and Citicorp Trustee Company Limited. **2.11
    
    Amended and Restated Indenture, dated August 1, 2002, amending and restating the Indenture dated May
1, 1998, between Petrobras Energía and Citibank, N.A. **2.12
    
    First Supplemental Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated
as of August 1, 2002 filed, among Petrobras Energía S.A., as Issuer, The Bank of New York, as
Trustee, Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York,
Banco Rio de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in
Argentina and JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the
Short Term Floating Rate Trade Series J Notes due 2003.**2.13
    
    Second Supplement Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated
as of August 1, 2002, among Petrobras Energía, as Issuer, The Bank of New York, as Trustee,
Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio
de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and
JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Long Term
Floating Rate Trade Series K Notes due 2007. **2.14
    
    Third Supplemental Indenture dated as of October 4, 2002 to the Amended and Restated Indenture dated
as of August 1, 2002, among Petrobras Energía, as Issuer, The Bank of New York, as Trustee,
Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio
de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and
JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Short Term
Floating Rate Working Capital Series L Notes due 2003. **2.15
    
    Fourth Supplemental Indenture dated as of October 4, 2002 to the Amended and Restated Indenture
dated as of August 1, 2002, among Petrobras Energía, as Issuer, The Bank of New York, as Trustee,
Co-Security Registrar, Authenticating Agent, Paying Agent and Transfer Agent in New York, Banco Rio
de la Plata S.A., as Security Registrar, Argentine Paying Agent and Transfer Agent in Argentina and
JPMorgan Chase, as Administrative Agent and Calculation Agent, for the creation of the Long Term
Floating Rate Working Capital Series M Notes due 2007. **4.1
    
    Oil Marketing and Delivery Agreement dated July 17, 2001 between Petrobras Energía as Issuer and
Deutsche Bank AG, London Branch, as Oil Purchaser; and Crude Oil Purchase and Delivery Contract
dated July 17, 2001 among Petrobras Energía, as Issuer, Deutsche Bank AG, London Branch, as Oil
Purchaser and Bankers Trust Company as Oil Agent and as Administrative Agent.*4.2
    
    Contrato de Cesion dated December 14, 2001, among Petrobras Energía de Venezuela, S.A., Corod
Producción, S.A., Petrobras Energía and Banco Latinoamerica de Exportaciones, S.A., with an English
summary.*4.3
    
    Long-Term Incentive Plan for executive officers and senior managers approved in May 2000 together
with an English summary attached thereof, filed with the Commission on June 18, 2001 as Exhibit 4(c)
to our annual report on Form 20-F, and incorporated herein by reference. **4.4
    
    Letter of Credit Issuance and Reimbursement Agreement dated October 2, 2002 among Petrobras Energía
S.A., the Lenders named therein, the Issuing Banks named therein, and JPMorgan Chase Bank,
 180




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ExhibitNo.
    
    Descriptionas Letter of Credit Administrative Agent. **4.5
    
    Master Settlement and Mutual Release Agreement dated as of April 16, 2004 among Petróleo Brasileiro
S.A., Petrobras Energia, Petrobras Hispano Argentina S.A., Enron Corp., Enron Argentina Ciesa
Holding S.A., Enron Pipeline Company Argentina S.A., and Podnerosa Assets, L.P.8.1
    
    List of significant subsidiaries of Petrobras Energía as defined in Rule 1-02(w) of Regulation S-X.12.1
    
    CEO Certification pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, dated June 30, 2004.12.2
    
    CFO Certification pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002, dated June 30, 2004.13.1
    
    CEO and CFO Certification furnished
pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, dated
June 30,
2004.
    ** Incorporated herein by reference to our annual report for the year ended
December 31, 2002 filed on June 30, 2003. Omitted from the exhibits filed with this annual report are certain instruments
and agreements with respect to our long-term debt, none of which authorizes
securities in a total amount that exceeds 10% of our total assets. We hereby
agree to furnish to the SEC copies of any such omitted instruments or
agreements as the SEC requests. 181




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SIGNATURES The registrant hereby certifies that it meets all of the requirements for
filing on Form 20-F and that it has duly caused and authorized the undersigned
to sign this annual report on its behalf. PETROBRAS ENERGÍA PARTICIPACIONES S.A.By:
    
    /s/ Alberto GuimarãesName: Alberto GuimarãesTitle: Chief Executive OfficerBy:
    
    /s/ Luis Miguel SasName: Luis Miguel SasTitle: Chief Financial OfficerDate:
June 30, 2004
 182




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INDEX TO FINANCIAL STATEMENTS PETROBRAS ENERGÍA PARTICIPACIONES S.A. Report of independent registered public accounting firm of Petrobras Energía Participaciones S.A.
    
    
    F-2Report of independent registered public accounting firm of Distrilec Inversora S.A.
    
    
    F-4Report of independent registered public accounting firm of Compañía Inversora
en Transmisión Eléctrica Citelec S.A.
    
    
    F-6Report of independent registered public accounting firm of Compañía de Inversiones de Energía S.A.
    
    
    F-8Report of independent registered public accounting firm of Transportadora de Gas
del Sur S.A.
    
    
    F-10Consolidated statements of income and loss for the years ended December 31,
2003, 2002 and 2001
    
    
    F-12Consolidated balance sheets as of December 31, 2003 and 2002
    
    
    F-13Statements of changes in shareholders equity for the years
ended December 31, 2003, 2002 and 2001
    
    
    F-14Consolidated statements of cash flows for the years ended December 31,
2003, 2002 and 2001
    
    
    F-15Notes to the consolidated financial statements for the years ended
December 31, 2003, 2002 and 2001
    
    
    F-16
 F-1




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors of
Petrobras Energía Participaciones S.A.:  1.
    
    We have audited the accompanying consolidated balance sheets of
Petrobras Energía Participaciones S.A. (an Argentine Corporation) and
its subsidiaries as of December 31, 2003 and 2002, and the related
consolidated statements of income, changes in shareholders equity and
cash flows for each of the three years in the period ended December 31,
2003. Those financial statements are the responsibility of the
Companys management. Our responsibility is to express an opinion on
those financial statements based on our audits.2.
    
    The financial statements of the affiliates Compañía Inversora en
Transmisión Eléctrica Citelec S.A., Compañía de Inversiones de Energía
S.A. and Transportadora de Gas del Sur S.A. as of and for the years ended
December 31, 2003 and 2001 and the financial statements of the
affiliate Distrilec Inversora S.A. as of and for the year ended
December 31, 2003, have been audited by other auditors whose reports
have been furnished to us, and our opinion, insofar as it relates to
the amounts included for those affiliates, is based on the reports of
the other auditors. Those financial statements, for the affiliates
which have been proportionally consolidated, reflect assets
constituting 27% as of December 31, 2003, and net sales constituting
16% for 2003 and 12 % for 2001 of the Companys respective consolidated
totals, and the Companys investment and equity in the net income of
the other affiliates is stated at Argentine pesos 325,000,000 as of
December 31, 2003 and Argentine pesos 139,000,000 for 2003 and
29,000,000 for 2001. Certain reports of other auditors include a
paragraph referring to going concern uncertainties as explained in
paragraph 7.3.
    
    We conducted our audits in accordance with the standards of the
Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatements. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe
that our audits and the reports of other auditors provide a reasonable
basis for our opinion.4.
    
    As described in note 3, in accordance with the regulations of the
National Securities Commission, the Company has not recognized the
effects of the variations in the purchasing power of the Argentine Peso
from March 1, 2003 to September 30, 2003, and has not discounted the
nominal values of its deferred tax assets and liabilities as required
by accounting principles generally accepted in Argentina. The effects
of such matters in the financial position as of December 31, 2003 and
results of operations for the year then ended have not been quantified
by the Company.5.
    
    In our opinion, based on our audits and on the reports of other
auditors referred to in paragraph 2, the consolidated financial
statements referred to above present fairly, in all material respects,
the consolidated financial position of Petrobras Energía
Participaciones S.A. and its subsidiaries as of December 31, 2003 and
2002 and the results of their operations and their cash flows for each
of the three years in the period ended December 31, 2003, in conformity
with the Business Association Law and the pertinent regulations of the
National Securities Commission, and except for the effect of the
matters discussed in paragraph 4, with generally accepted accounting
principles in Argentina, which differ in certain respects from U.S.
generally accepted accounting principles to the extend discussed in
notes 22 through 24. F-2




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6.
    
    As discussed in note 3, effective January 1, 2003 the Company
adopted new accounting pronouncements related to certain valuation and
disclosure matters. As required by accounting principles generally
accepted in Argentina, the Company has restated prior period financial
statements presented for comparative purposes to reflect the changes in
accounting principles.7.
    
    The financial statements and the reports of the other auditors of
the affiliates Compañía Inversora en Transmisión Eléctrica Citelec
S.A., Compañía de Inversiones de Energía S.A. and Transportadora de Gas
del Sur S.A. as of and for the years ended December 31, 2003 and 2001, stated
that they have been prepared assuming that such affiliates will
continue as going concerns. Those statements, for the affiliates which
have been proportionally consolidated, reflect assets constituting 17%
as of December 31, 2003 and net sales constituting 8% for 2003 and 12 %
for 2001 of the Companys respective consolidated totals, and the
Companys investment and equity in the net income of the other
affiliates is stated at Argentine pesos 325,000,000 as of December 31,
2003 and Argentine pesos 139,000,000 for 2003 and 29,000,000 for 2001.
As discussed in note 9, such affiliates have been negatively impacted
by the Argentine Governments adoption of various economic measures
including the de-dollarization of revenue rates, the renegotiation of
License and Concession contracts and the devaluation of the Argentine
peso. In addition, such affiliates have suspended the payment of their
financial debt. These circumstances raise substantial doubt about the
affiliates ability to continue as going concerns. The affiliates
managements plans in regard of these matters are also described in
note 9. The accompanying consolidated financial statements do not
include any adjustments that might result from the outcome of this
uncertainty. Buenos Aires, Argentina
      June 11, 2004 PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
(Member firm of Ernst & Young Global)

/s/ Daniel G. Minenna
DANIEL G. MINENNA
Partner F-3




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
(English translation of the report originally issued in Spanish) To the Chairman and Directors ofDistrilec Inversora S.A. 1. We have audited:  a)
    
    The accompanying balance sheet of Distrilec Inversora S.A. as of
December 31, 2003, and the related statements of income, changes in
shareholders equity and cash flows for the year then ended.b)
    
    The accompanying consolidated balance sheet of Distrilec Inversora
S.A. and its subsidiary Empresa Distribuidora Sur Sociedad Anónima
(EDESUR S.A.) as of December 31, 2003 and the related consolidated
statements of income and cash flows for the year then ended, included
in Chart I as supplementary accounting information. These financial statements are the responsibility of the Companys Board of
Directors. Our responsibility is to express an opinion on these financial
statements based on our audit conducted with the scope described in
paragraph 2.  2.
    
    We conducted our audit in accordance with standards of the Public Company
Accounting Oversight Board (United States of America). Those standards
require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements, taken as a whole, are free of
material misstatements. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles
used and significant estimates made by Companys Management, as well as
evaluating the overall financial statement presentation.  3.
    
    In our opinion:  a)
    
    The financial statements mentioned in paragraph 1.a) present
fairly, in all material respects, the financial position of Distrilec
Inversora S.A. as of December 31, 2003, the results of its operations,
the evolution of its shareholders  ́ equity and its cash flows for the
year then ended, in accordance with accounting principles generally
accepted in Argentina approved by the Professional Council of Economic
Sciences of the City of Buenos Aires. F-4




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2.  b)
    
    The financial statements mentioned in paragraph 1.b) present
fairly, in all material respects, the consolidated financial position
of Distrilec Inversora S.A. and its subsidiary Empresa Distribuidora
Sur Sociedad Anónima (EDESUR S.A.) as of December 31, 2003, the
consolidated results of their operations and their consolidated cash
flows for the year then ended, in accordance with accounting principles
generally accepted in Argentina approved by the Professional Council of
Economic Sciences of the City of Buenos Aires.  4.
    
    The financial statements as of and for the year ended December 31, 2002,
presented for comparative purposes, were audited by other independent
auditors who issued their audit report with an unqualified opinion on
February 7, 2003. The information as of and for the year ended December
31, 2002 has been modified by the Companys Management in order to comply
with the changes in the accounting principles generally accepted in
Argentina mentioned in note 2.II to the stand alone financial statements
and has been restated in constant currency up to February 2003.  5.
    
    Accounting principles generally accepted in Argentina vary in certain
significant respects from accounting principles generally accepted in the
United States of America. Application of accounting principles generally
accepted in the United States of America would have affected the
determination of the shareholders  ́ equity as of December 31, 2003 and the
results of operations for the year then ended to the extent summarized in
note 11 to the consolidated financial statements. Certain additional
information required by the Securities and Exchange Commission (SEC),
prepared in conformity with accounting principles generally accepted in
the United States of America, was included in note 12 to the consolidated
financial statements.


Buenos Aires, February 9, 2004.DELOITTE & Co. S.R.L./s/ Carlos A. LloverasCARLOS A. LLOVERASPartner F-5




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Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of
Compañía Inversora en Transmisión Eléctrica Citelec S.A.: We have audited the accompanying consolidated balance sheets of Compañía
Inversora en Transmisión Eléctrica Citelec S.A. and its subsidiaries as of
December 31, 2003 and 2002, and the related consolidated statements of
operations, of changes in shareholders equity and of cash flows for each of
the three years in the period ended December 31, 2003. These financial
statements are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. As discussed in Note 3.a. to the consolidated financial statements, in order to
comply with regulations of the legal control authorities, the Company
discontinued inflation accounting as from March 1, 2003 as well as recognized
deferred income tax assets and liabilities on a non-discounted basis. The
application of these regulations represent a departure from accounting
principles generally accepted in Argentina, which require inflation accounting
be discontinued as from October 1, 2003 and the recognition of deferred income
tax assets and liabilities on a discounted basis. The Company has not
quantified the impact of such a departure. In our opinion, except for the effects of not recognizing inflation accounting
until September 30, 2003 and not discounting deferred tax assets and
liabilities as discussed in the preceding paragraph, the consolidated financial
statements referred to above present fairly, in all material respects, the
financial position of Compañía Inversora en Transmisión Eléctrica Citelec S.A.
and its subsidiaries at December 31, 2003 and 2002, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2003 in conformity with accounting principles generally accepted
in Argentina. The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 2,
during 2002 the Company was negatively impacted by the devaluation of the
Argentine Peso and the Argentine Government adoption of various economic
measures, including the conversion of dollar-denominated tariffs to Argentine
pesos at an exchange rate of Ps.1 = US$ 1. As a result of these circumstances,
the Company did not comply with certain restrictive covenants contained in its
debt agreements and suspended the payment of its financial debts. These
circumstances raise substantial doubt about the Companys ability to continue
as a going concern. Management plans in regard to these matters are also
described in Note 2. The accompanying consolidated financial statements do not
include any adjustments that might result from the outcome of this uncertainty. F-6




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As discussed in Note 3.d. to the consolidated financial statements, effective
January 1, 2003 the Company adopted new accounting pronouncements related to
valuation and disclosure criteria. As required by accounting principles
generally accepted in Argentina, the Company has restated its prior period
financial statements presented for comparative purposes to reflect the adopted
changes in accounting principles, except for certain valuation and disclosure
criteria that in accordance with the transition provisions have been applied
prospectively. Accounting principles generally accepted in Argentina vary in certain
significant respects from accounting principles generally accepted in the
United States of America and as allowed by Item 17 to Form 20-F. Information
relating to the nature and effect of such differences is presented in Note 15
to the consolidated financial statements. PRICE WATERHOUSE & Co. by  /s/ Miguel A. Urus (Partner)Miguel A. Urus
 Buenos Aires, Argentina.
June 11, 2004 F-7




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of
Compañía de Inversiones de Energía S.A. We have audited the accompanying consolidated balance sheets of Compañía de
Inversiones de Energía S.A. and its subsidiaries at December 31, 2003 and 2002,
and the related consolidated statements of income, of changes in shareholders
equity and of cash flows for each of the three years in the period ended
December 31, 2003. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an opinion on these
financial statements based on our audits. We conducted our audits of these financial statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion. As indicated in Notes 2.c. and 2.h., the Company has discontinued the
restatement of financial statements into constant currency as from March 1,
2003 and has recorded deferred income tax assets and liabilities on a
non-discounted basis as required by resolutions issued by the Comisión Nacional
de Valores(CNV). Since generally accepted accounting principles in Argentina
require companies to prepare price-level restated financial statements through
September 30, 2003 and to recognize deferred taxes on a discounted basis, the
application of the CNV resolutions represent a departure from generally
accepted accounting principles in Argentina. In our opinion, except for the effects of the matters described in the
preceding paragraph, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Compañía de
Inversiones de Energía S.A. and its subsidiaries at December 31, 2003 and 2002,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 2003 in conformity with accounting
principles generally accepted in Argentina. The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As indicated in Notes 5 and
6, the Company has been negatively impacted by the deterioration of the
Argentine economy, the devaluation of the Argentine peso and the Argentine
governments adoption of various economic measures including the violation of
the contractually-agreed License terms. In view of these circumstances, the
Company has not been able to maintain the financial ratios required by its
outstanding debt agreements and in May, 2003 had announced the suspension of
payment on its financial debt. These circumstances raise substantial doubt
about the Companys ability to continue as a going concern. Managements plans
in regard to these matters are also described in Notes 5 and 6. The
accompanying consolidated financial statements do not include any adjustments
that might result from the outcome of this uncertainty. F-8




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Accounting principles generally accepted in Argentina vary in certain
significant respects from the accounting principles generally accepted in the
United States of America and as allowed by Item 18 to Form 20-F. Information
relating to the nature and effect of such differences is presented in Note 11
to the consolidated financial statements. /s/ Héctor A. López
PRICE WATERHOUSE & CO.
Héctor A. López (Partner)
Buenos Aires, Argentina
June 11, 2004 F-9




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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of
Transportadora de Gas del Sur S.A. We have audited the accompanying consolidated balance sheets of Transportadora
de Gas del Sur S.A. and its subsidiary at December 31, 2003 and 2002, and the
related consolidated statements of income, of changes in shareholders equity
and of cash flows for each of the three years in the period ended December 31,
2003. These financial statements are the responsibility of the Companys
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these financial statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion. As indicated in Notes 2.c and 2.h, the Company has discontinued the restatement
of financial statements into constant currency as from March 1, 2003 and has
recorded deferred income tax assets and liabilities on a non-discounted basis
as required by resolutions issued by the Comisión Nacional de Valores (CNV).
Since generally accepted accounting principles in Argentina require companies
to prepare price-level restated financial statements through September 30, 2003
and to recognize deferred taxes on a discounted basis, the application of the
CNV resolutions represent a departure from generally accepted accounting
principles in Argentina. In our opinion, with the exceptions of the matters described in the preceding
paragraph, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Transportadora de
Gas del Sur S.A. and its subsidiary at December 31, 2003 and 2002, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2003 in conformity with accounting principles
generally accepted in Argentina. The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As indicated in Notes 5 and
6, the Company has been negatively impacted by the deterioration of the
Argentine economy, the Argentine governments adoption of various economic
measures including the violation of the contractually-agreed License terms and
the devaluation of the Argentine peso. In view of these circumstances, the
Company has not been able to maintain the financial ratios required by its
outstanding debt agreements and in May, 2003 had announced the suspension of
payment on its financial debt. These circumstances raise substantial doubt
about the Companys ability to continue as a going concern. Managements plans
in regard to these matters are also described in Notes 5 and 6. The
accompanying consolidated financial statements do not include any adjustments
that might result from the outcome of this uncertainty. F-10




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Accounting principles generally accepted in Argentina vary in certain
significant respects from the accounting principles generally accepted in the
United States of America and as allowed by Item 18 to Form 20-F. Information
relating to the nature and effect of such differences is presented in Note 11
to the consolidated financial statements. /s/ Héctor A. López
PRICE WATERHOUSE & CO.
Héctor A. López (Partner)
Buenos Aires, Argentina
June 11, 2004 F-11




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PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001
(Stated in millions of Argentine pesos  See Note 2.c) 2003
    
    2002
    
    2001Net sales
    
    
    5,494
    
    
    
    5,106
    
    
    
    5,170Costs of sales (Note 27.c)
    
    
    (3,386
    )
    
    
    (3,284
    )
    
    
    (3,347
    )Gross profit
    
    
    2,108
    
    
    
    1,822
    
    
    
    1,823Administrative and selling expense (Note 27.e)
    
    
    (559
    )
    
    
    (609
    )
    
    
    (665
    )Exploration expenses (Note 27.e)
    
    
    (196
    )
    
    
    (58
    )
    
    
    (41
    )Other exploitation (expenses) income, net (Note 17.c)
    
    
    (121
    )
    
    
    (28
    )
    
    
    23Exploitation income
    
    
    1,232
    
    
    
    1,127
    
    
    
    1,140Equity in earnings of affiliates (Note 9.b)
    
    
    163
    
    
    
    (638
    )
    
    
    119Financial income (expense) and holding gains (losses)Generated by assets:Interest
    
    
    65
    
    
    
    88
    
    
    
    91Exchange difference
    
    
    (155
    )
    
    
    1,986
    
    
    
    82Gain from remeasurement and translation
    
    
    
    
    
    
    3,742
    
    
    
    Loss due to exposure to inflation
    
    
    (27
    )
    
    
    (2,967
    )
    
    
    Holding gains (losses) and income from sale of shares
    
    
    98
    
    
    
    (15
    )
    
    
    (1
    )Other financial income, net
    
    
    10
    
    
    
    22
    
    
    
    2(9
    )
    
    
    2,856
    
    
    
    174Generated by liabilities:Interest
    
    
    (623
    )
    
    
    (882
    )
    
    
    (612
    )Exchange difference
    
    
    554
    
    
    
    (10,402
    )
    
    
    (89
    )Loss from remeasurement and traslation
    
    
    
    
    
    
    (2,242
    )
    
    
    Gain due to exposure to inflation
    
    
    67
    
    
    
    9,472
    
    
    
    Derivatives
    
    
    (294
    )
    
    
    (524
    )
    
    
    8Other financial expense, net
    
    
    (112
    )
    
    
    (105
    )
    
    
    (54
    )(408
    )
    
    
    (4,683
    )
    
    
    (747
    )Other expenses, net (Note 17.d)
    
    
    (421
    )
    
    
    (187
    )
    
    
    (88
    )Income (loss) before income tax and minority interest in subsidiaries
    
    
    557
    
    
    
    (1,525
    )
    
    
    598Income tax provision
    
    
    (18
    )
    
    
    (82
    )
    
    
    (385
    )Minority interest in subsidiaries
    
    
    (158
    )
    
    
    28
    
    
    
    (112
    )Net income (loss)
    
    
    381
    
    
    
    (1,579
    )
    
    
    101Earnings (losses) per share  Stated in Argentine pesos
    
    
    0.179
    
    
    
    (0.744
    )
    
    
    0.048
 The accompanying notes are an integral part of these consolidated financial statements. F-12




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PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS AS OF DECEMBER 31, 2003 AND 2002
(Stated in millions of Argentine pesos  See Note 2.c) 2003
    
    2002CURRENT ASSETSCash
    
    
    153
    
    
    
    93Investments (Note 9.a)
    
    
    802
    
    
    
    664Trade receivables
    
    
    886
    
    
    
    784Other receivables (Note 17.a)
    
    
    861
    
    
    
    734Inventories (Note 8)
    
    
    319
    
    
    
    356Other assets
    
    
    3
    
    
    
    178Total current assets
    
    
    3,024
    
    
    
    2,809NONCURRENT ASSETSTrade receivables
    
    
    36
    
    
    
    21Other receivables (Note 17.a)
    
    
    131
    
    
    
    220Inventories (Note 8)
    
    
    61
    
    
    
    39Investments (Note 9.a)
    
    
    1,284
    
    
    
    1,103Property, plant and equipment (Note 27.a)
    
    
    11,559
    
    
    
    10,433Other assets
    
    
    43
    
    
    
    24Total noncurrent assets
    
    
    13,114
    
    
    
    11,840Total assets
    
    
    16,138
    
    
    
    14,649CURRENT LIABILITIESAccounts payable
    
    
    860
    
    
    
    651Short-term debt (Note 12)
    
    
    3,204
    
    
    
    1,543Payroll and social security taxes
    
    
    93
    
    
    
    76Taxes payable
    
    
    172
    
    
    
    133Reserves (Note 14.f)
    
    
    44
    
    
    
    28Other liabilities (Note 17.b)
    
    
    379
    
    
    
    344Total current liabilities
    
    
    4,752
    
    
    
    2,775NONCURRENT LIABILITIESAccounts payable
    
    
    7
    
    
    
    9Long-term debt (Note 12)
    
    
    5,098
    
    
    
    6,130Payroll and social security taxes
    
    
    6
    
    
    
    25Taxes payable
    
    
    11
    
    
    
    120Other liabilities (Note 17.b)
    
    
    262
    
    
    
    496Reserves (Note 14.f)
    
    
    277
    
    
    
    86Total noncurrent liabilities
    
    
    5,661
    
    
    
    6,866Total liabilities
    
    
    10,413
    
    
    
    9,641TRANSITORY DIFFERENCESMeasurement of derivative financial instruments
determined as effective hedge
    
    
    (18
    )
    
    
    Foreign currency translation
    
    
    (56
    )
    
    
    Total transitory differences
    
    
    (74
    )
    
    
    MINORITY INTEREST IN SUBSIDIARIES
    
    
    966
    
    
    
    556SHAREHOLDERS EQUITY (Per respective statements)
    
    
    4,833
    
    
    
    4,45216,138
    
    
    
    14,649
 The accompanying notes are an integral part of these consolidated financial statements. F-13




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PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES STATEMENTS OF CHANGES IN SHAREHOLDERS EQUITY FOR THE YEARS ENDED DECEMBER 31, 2003, 2002 AND 2001 (Stated in millions of Argentine pesos  See Note 2.c) 2003
    
    2002
    
    2001Capital stock
    
    Retained earningsCapital
    
    Adjustment to
    
    Additional
    
    Legal
    
    Unappropriated
    
    Treasurystock
    
    capital stock
    
    paid-in capital
    
    reserve
    
    retained earnings
    
    stock (a)
    
    Total
    
    Total
    
    TotalBalances at beginning of the year
    
    
    2,132
    
    
    
    2,554
    
    
    
    664
    
    
    
    37
    
    
    
    (541
    )
    
    
    (33
    )
    
    
    4,813
    
    
    
    6,014
    
    
    
    5,952Change in balances at beginning of the year due to changes
in accounting method (Note 3)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (361
    )
    
    
    
    
    
    
    (361
    )
    
    
    17
    
    
    
    132Adjusted balances at beginning of the year
    
    
    2,132
    
    
    
    2,554
    
    
    
    664
    
    
    
    37
    
    
    
    (902
    )
    
    
    (33
    )
    
    
    4,452
    
    
    
    6,031
    
    
    
    6,084Special Shareholders Meeting decision of April 4, 2003 and
April 9, 2001:Distribution of unappropriated retained earnings- Cash dividends
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (134
    )- Negative retained earnings absortion
    
    
    
    
    
    
    
    
    
    
    (504
    )
    
    
    (37
    )
    
    
    541
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Acquisition of own stock held by subsidiary
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (20
    )Net income (loss)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    381
    
    
    
    
    
    
    
    381
    
    
    
    (1,579
    )
    
    
    101Balances at end of the year
    
    
    2,132
    
    
    
    2,554
    
    
    
    160
    
    
    
    
    
    
    
    20
    
    
    
    (33
    )
    
    
    4,833
    
    
    
    4,452
    
    
    
    6,031
 (a) See Note 4.m). The accompanying notes are an integral part of these consolidated financial statements. F-14




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PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES CONSOLIDATED STATEMENTS
OF CASH FLOW (a)
 FOR THE YEARS ENDED
DECEMBER 31, 2003, 2002 AND 2001
 (Stated in millions of
Argentine pesos - See Note 2.c)
 2003
    
    2002
    
    2001Cash provided by (used in) operations:Net income (loss)
    
    
    381
    
    
    
    (1,579
    )
    
    
    101Reconciliation to net cash provided by (used in) operating activities:Minority interest in subsidiaries
    
    
    158
    
    
    
    (28
    )
    
    
    112Equity in earnings of affiliates
    
    
    (163
    )
    
    
    638
    
    
    
    (119
    )Financial (Income) expense, net
    
    
    (585
    )
    
    
    140
    
    
    
    Dividends collected (Note 9.c)
    
    
    26
    
    
    
    20
    
    
    
    55Depreciation and depletion of property, plant and equipment
    
    
    1,016
    
    
    
    1,051
    
    
    
    877Impairment of Ecuadorian assets
    
    
    309
    
    
    
    63
    
    
    
    Loss (income) from sale of oil and gas areas and
participation in joint ventures
    
    
    27
    
    
    
    (41
    )
    
    
    65Income from assets exchange
    
    
    
    
    
    
    
    
    
    
    (251
    )Impairment of allocated purchased price related to CIESA
    
    
    
    
    
    
    
    
    
    
    202Impairment of assets
    
    
    64
    
    
    
    96
    
    
    
    Impairment of unproved oil and gas properties
    
    
    180
    
    
    
    17
    
    
    
    Debt restructuring
    
    
    
    
    
    
    17
    
    
    
    Income tax provision
    
    
    18
    
    
    
    82
    
    
    
    385Income tax paid
    
    
    (48
    )
    
    
    (27
    )
    
    
    (196
    )Accrued interest
    
    
    598
    
    
    
    878
    
    
    
    520Interest paid
    
    
    (488
    )
    
    
    (814
    )
    
    
    (526
    )Other
    
    
    (7
    )
    
    
    87
    
    
    
    111Changes
in assets and liabilities:Trade receivables
    
    
    (115
    )
    
    
    208
    
    
    
    (13
    )Other receivables
    
    
    411
    
    
    
    44
    
    
    
    59Inventories
    
    
    (12
    )
    
    
    (70
    )
    
    
    (1
    )Other assets
    
    
    73
    
    
    
    
    
    
    
    Accounts payable
    
    
    (66
    )
    
    
    (16
    )
    
    
    150Payroll and social security taxes
    
    
    17
    
    
    
    (34
    )
    
    
    15Taxes payable
    
    
    (9
    )
    
    
    75
    
    
    
    (167
    )Other liabilities
    
    
    61
    
    
    
    362
    
    
    
    3471,846
    
    
    
    1,169
    
    
    
    1,726Payments in advance
    
    
    (493
    )
    
    
    (459
    )
    
    
    Net cash provided by operations
    
    
    1,353
    
    
    
    710
    
    
    
    1,726Cash
provided by (used in ) investing activities:Acquisition of property, plant and equipment and interest in
companies and oil and gas areas
    
    
    (829
    )
    
    
    (674
    )
    
    
    (2,009
    )Net (increase) decrease in investments other than cash and cash equivalents
    
    
    (97
    )
    
    
    32
    
    
    
    (86
    )Contributions and advances to unconsolidated affiliates
    
    
    (12
    )
    
    
    (127
    )
    
    
    (56
    )Sales of investments
    
    
    20
    
    
    
    593
    
    
    
    227Other
    
    
    3
    
    
    
    (6
    )
    
    
    Net cash used in investing activities
    
    
    (915
    )
    
    
    (182
    )
    
    
    (1,924
    )Cash
provided by (used in) financing activites:Net (decrease) increase in short-term debt
    
    
    (196
    )
    
    
    (193
    )
    
    
    1,022Payments of long-term debt
    
    
    (646
    )
    
    
    (1,762
    )
    
    
    (1,290
    )Increase in long-term debt
    
    
    591
    
    
    
    130
    
    
    
    1,408Acquisition of own stock
    
    
    
    
    
    
    
    
    
    
    (21
    )Cash dividends paid
    
    
    
    
    
    
    (2
    )
    
    
    (223
    )Net cash used in financing activities
    
    
    (251
    )
    
    
    (1,827
    )
    
    
    896Devaluation
and inflation effect on cash
    
    
    (88
    )
    
    
    755
    
    
    
    Increase (decrease) in cash
    
    
    99
    
    
    
    (544
    )
    
    
    698Cash and cash equivalents at beginningCash and cash equivalents at beginning
    
    
    725
    
    
    
    1,334
    
    
    
    565Additions (deductions) of cash and cash equivalents at beginning from proportional interest in CIESA
    
    
    103
    
    
    
    (65
    )
    
    
    71Cash and cash equivalents at end
    
    
    927
    
    
    
    725
    
    
    
    1,334
 (a) Cash and cash equivalents include highly liquid, temporary cash investments with
original maturities of three months or less
when purchased. The accompanying notes are an integral part of these consolidated financial statements. F-15




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PETROBRAS ENERGÍA PARTICIPACIONES S.A. AND SUBSIDIARIES
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEAR ENDED DECEMBER 31, 2003, 2002 AND 2001
(Amounts stated in millions of Argentine pesos  see Note 2.c, unless otherwise indicated) 1. Business of the Company and change of corporate name Petrobras Energía Participaciones S.A. (hereinafter Petrobras
Participaciones or The Company) is an integrated energy company, focused on
oil and gas exploration and production, refining, petrochemical activities,
generation, transmission and distribution of electricity and sale and
transmission of hydrocarboons. It has businesses in Argentina, Bolivia, Brazil,
Ecuador, Peru and Venezuela. Petrobras Energía Participaciones has a
significant share of the regional energetic market. The Companys Special and Regular Shareholders Meeting held on April 4,
2003, approved the change of corporate name from Perez Companc S.A. to
Petrobras Energía Participaciones S.A. This change in corporate name remained
subject to the Comisión Nacional de Defensa de la Competencia (CNDC, Argentine
anti-trust authorties) approving the transaction whereby Petrobras
Participacoes SL purchased stock representing a majority interest in the
Company. In addition, the Regular and Special Shareholders Meeting of Petrobras
Energía S.A. held on April 4, 2003, approved the change of corporate name from
Pecom Energia S.A. to Petrobras Energía S.A, also subject to the approval
mentioned above. The CNDC approved the transaction on May 13, 2003. Pursuant to this
resolution, Petrobras Energía undertook to divest of all of its equity interest
in Transener S.A., in accordance with Law No. 24,065 that provides the Electric
Power Regulatory Framework; such process is subject to supervision by the ENRE
and the approval of the Federal Department of Energy. There is no period
established for the divestiture. Effective with the CNDC approval, Petrobras Participaciones became a
majority-owned subsidiary of Petroleo Brasileiro S.A.-Petrobras. On July 4, 2003, the IGJ (regulatory agency of business associations)
granted its approval for and registered both changes of corporate name, which
were also approved by the CNV on June 9, 2003. 2. Basis of presentation The Petrobras Energía Participaciones S.A. consolidated financial
statements have been prepared in accordance with the regulations of the
Argentine Securities Commission (Comisión Nacional de Valores or CNV) and
except for the matters described in Note 3, with Accounting Principles
Generally Accepted in Buenos Aires City, Argentina (Argentine GAAP). Certain disclosures related to formal legal requirements for reporting in
Argentina have been omitted for purposes of these consolidated financial
statements, since they are not required for the United States Securities and
Exchange Commission (SEC) reporting purposes. The preparation of financial statements in conformity with Argentine GAAP
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities as of the date of the financial statements and the reported amounts
of revenues and expenses during the reporting period. While it is believed that
such estimates are reasonable, actual results could differ from those
estimates. a) Basis of consolidation In accordance with the procedure set forth in Technical Resolutions No. 4
and 19 of the FACPCE (Argentine Federation of Professional Councils in Economic
Sciences), Petrobras Participaciones has consolidated line by line its
financial statements with the financial statements of the companies over which
Petrobras Participaciones exercises exclusive or joint control. Joint control
exists where all the shareholders, F-16




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or only the shareholders owning a majority of votes, have resolved, on the
basis of written agreements, to share the power to define and establish a
companys operating and financial policies. In the consolidation of controlled companies, the amount of the investment
in such subsidiaries and the interest in their income (loss) and cash flows are
replaced by the aggregate assets, liabilities, income (loss) and cash flow of
such subsidiaries, reflecting separately all minority interests in the
subsidiaries. Related party receivables, payables and transactions within the
consolidated group are eliminated. The unrealized intercompany gains (losses)
from transactions within the consolidated group have been completely
eliminated. In the consolidation of companies over which the Company exercises joint
control, the amount of the investment in the company under joint control and
the interest in its income (loss) and cash flows are replaced by the Companys
proportional interest in the companys assets, liabilities, income (loss) and
cash flows. Related party receivables, payables and transactions within the
consolidated group and companies under joint control have been eliminated in
the consolidation pro rata to the shareholding of the controlling company. The data about the companies over which the Company exercises control,
joint control or significant influence are disclosed in Note 27.f). Companies under joint control includes the interests in Distrilec
Inversora S.A., Compañía de Inversiones de Energía S.A. and Compañía Inversora
en Transmisión Eléctrica S.A. (Citelec S.A). As of December 31, 2003, 2002
and 2001, the Company has not consolidated proportionally the interests in
Citelec S.A. taking into account the commitment to divest of such equity
interest as described in Note 1. In order to preserve the informations
comparability, the Company did not proportionally consolidate line by line, in
its comparative financial statements, the assets, liabilities, income (loss)
and cash flows of Citelec S.A. As of December 31, 2002, the Company did not
proportionally consolidate on a line-by-line basis the assets, liabilities,
income (loss) and cash flows of CIESA since, as of that date, such equity
interest was stated at zero value. b) Foreign Currency translation The Company applies the translation method established by Technical Resolution
no. 18 of the FACPCE for the translation of financial statements of foreign
subsidiaries, affiliates, branches and joint ventures. In the opinion of the Companys Management, the transactions carried out abroad
have been classified as not integrated to the Companys transactions in
Argentina. Such transactions are not an extension of the Companys
transactions due to, among others, the following reasons:  a)
    
    transactions with the Company are not a high proportion of the
entitys activities abroad;b)
    
    activities of foreign businesses are partially financed with funds
from their own transactions and with local loans;c)
    
    sales, workforce, materials and other costs of goods and services
related to transactions abroad are settled mainly in a currency other
than the currency of the investors financial statements; andd)
    
    Companys cash flows are independent from the day-to-day activities
of the foreign business and are not directly affected by the size or
frequency of the activities of foreign business. Upon applying the translation method, first the foreign operations are
remeasured into US dollars (functional currency for such operations), as
follows:  
    
    Assets and liabilities stated at current value are converted at the
closing exchange rates.  
    
    Assets and liabilities measured at historical values and the income
(loss) are converted at historical exchange rates. After the operations are remeasured into US dollars, they are translated
into Argentine pesos as follows:  
    
    Assets and liabilities are translated by using the closing exchange rate.  
    
    Income (loss) is translated at the historical exchange rates. The translation effect arising from the translation of the financial statements
is disclosed in the Transitory differences -foreign currency translation
account. F-17




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The above also applies to exchange differences arising from liabilities in
foreign currency that are designated as a hedge the net investment in the
foreign entity. c) Restatement in constant money The Company presents its consolidated financial statements in constant
money following the restatement method established by Technical Resolution No.
6 of the FACPCE and in accordance with CNV General Resolutions No. 415 and 441. Under such method, the consolidated financial statements integrally
recognize the effects of the changes in the purchasing power of Argentine peso
through August 31, 1995. As from September 1, 1995, under CNV General
Resolution No. 272, the Company interrupted the use of such method maintaining
the restatements made through such date. This method has been accepted by
professional accounting standards through December 31, 2001. On March 6, 2002, the CPCECABA (Professional Council in Economic Sciences
of the City of Buenos Aires) approved Resolution MD No. 3/2002 providing, among
other things, the reinstatement of the adjustment-for-inflation method for the
interim periods or years ended as from March 31, 2002, allowing for the
accounting measurements restated based on the change in the purchasing power of
the peso through the interruption of adjustments, such as those whose original
date is within the stability period, to be stated in pesos as of December 2001.
Through General Resolution No. 415 dated July 25, 2002, the CNV required that
the information related to the financial statements to be filed after the date
on which the regulation became effective be disclosed adjusted for inflation. The restatement in constant pesos method is applied to the accounting cost
values immediately preceding the capitalization of the exchange differences
mentioned in note 4.o), which represent an anticipation of the effects of
variances in the purchasing power of the Argentine peso, which will be
subsequently absorbed by the restatement in constant pesos of the assets
indicated in such note. On March 25, 2003, the Federal Executive issued Executive Order No. 664
establishing that the financial statements for years ending as from such date
be filed in nominal currency. Consequently, and under CNV Resolution No. 441,
the Company no longer applied inflation accounting as from March 1, 2003. This
method is not in accordance with professional accounting standards effective in
the city of Buenos Aires. The CPCECABA, through Resolution N° 287/03
discontinued the application of the restatement method as from October 1,
2003. Amounts, and the income (loss) for the years ended December 31, 2002 and
2001 presented for comparative purposes result from restating the amounts in
the financial statements as of such date following the guidelines indicated in
the paragraph above. d) Accounting for the transactions of oil and gas exploration and production
joint ventures and foreign branches The Company  ́s interests in oil and gas involve exploration and production
joint ventures and have been proportionally consolidated. Under this method,
the Company recognizes its proportionate interest in the joint ventures
assets, liabilities, revenues, costs and expenses on a line-by-line basis in
each account of its financial statements. Foreign branches have been fully
consolidated. 3. New accounting standards These financial statements have been prepared in accordance with
professional Argentine GAAP and the applicable CNV regulations, except for: a) valuation of deferred tax at nominal value without applying any
discounted values, as required by CNV General Resolution No. 434. b) the non recognition of the restatement in constant money provided for
in FACPCE Technical Resolution No. 6, as described in note 2.c). F-18




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As from January 1, 2003, FACPCE Technical Resolutions Nos. 16, 17, 18, 19,
and 20, approved as amended by the CPCECABA and adopted by the CNV through its
General Resolution No. 434. These new technical resolutions are a consequence
of the process whereby Argentine professional accounting standards are being
made consistent with the international accounting standards issued by the
International Accounting Standards Committee (IASC); in addition, they provide
clarification for certain issues which had not been provided for in past
regulations. The main changes included in the technical resolutions, that have resulted in
significant effects on the Companys financial statements, are: (i) guidelines
regarding the recognition, measurement, and disclosure of derivatives and
hedging transactions; (ii) amendment of the method to translate the financial
statements of foreign subsidiaries stated in foreign currency; (iii) the
mandatory requirement to apply the deferred tax method to recognize income tax;
(iv) measurement of asset and liability amounts on discounted bases; (v)
changes in the frequency and method to compare assets with the recoverable
values thereof; (vi) incorporation of guidelines to assess whether certain
transactions including financial instruments, irrevocable capital contributions
and preferred stock, among others, should be classified as liabilities or
shareholders equity; (vii) incorporation of new disclosure requirements
including proportional consolidation of companies under joint control, change
in the disclosure of direct sales revenues, information by segment, earnings
per share, and the comparative information to be disclosed.; viii)
disbursements for maintenance costs, which may be allocated to the income for
the period when they are made or capitalized, as appropriate. The Company amended the method used to recognize future estimated
abandonment costs in oil & gas areas. Consistently with Statement of Financial
Accounting Standards (SFAS) N° 143 guidelines, such costs discounted at a
rate estimated upon initial measurement are capitalized together with the
assets from which they originate and are depreciated by the production units
method. In addition, a liability is recognized on such account at the estimated
value of the amounts payable discounted at a rate estimated in its initial
measurement. Adopting new accounting standards has resulted in income in the amount of
74, (378) and (115) for the years ended December 31, 2003, 2002 and 2001,
respectively, and a 361 and 22 reduction to retained earnings at the beginning
of the fiscal years ended on December 31, 2002 and 2001, respectively, as
disclosed below: Gains (losses)Retainined earnings as ofIncome for
    
    December 31,2003
    
    2002
    
    2001
    
    2002
    
    2001Derivatives financial instruments (1)
    
    
    (133
    )
    
    
    (334
    )
    
    
    8
    
    
    
    (417
    )
    
    
    (83
    )Foreign currency translation (2)
    
    
    55
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Future abandonment costs (3)
    
    
    
    
    
    
    15
    
    
    
    (1
    )
    
    
    45
    
    
    
    30Labor costs
    
    
    18
    
    
    
    19
    
    
    
    (7
    )
    
    
    (24
    )
    
    
    (43
    )Effects on affiliates
    
    
    
    
    
    
    18
    
    
    
    1
    
    
    
    (8
    )
    
    
    (26
    )Maintenance expenses (4)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    16
    
    
    
    16Discounted effect of nominal values
of assets and liabilities (5)
    
    
    13
    
    
    
    (4
    )
    
    
    
    
    
    
    (4
    )
    
    
    Deferred tax (6)
    
    
    (27
    )
    
    
    (92
    )
    
    
    (116
    )
    
    
    31
    
    
    
    123(74
    )
    
    
    (378
    )
    
    
    (115
    )
    
    
    (361
    )
    
    
    17
 (1) Previously, the fair value of such instruments was not booked but the
related income (loss) was recorded in income when losses and/or gains occurred
as a result of the hedged position. Premiums paid were capitalized and
amortized over the term of the option. (2) Previously, gains (losses) on foreign currency translation were charged to
income. (3) Previously, these costs were accrued at nominal value and charged as a
higher depreciation using the production units method. (4) Previously, maintenance costs were accrued. (5) Calculated as provided for in CPCECABA Resolution MD No. 32/2002. F-19




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(6) Previously, the Company estimated income tax applying the effective rate on
taxable income for the period regardless of any temporary differences between
book and taxable income. As established in the new accounting standards, there are certain
transition regulations enabling to apply prospectively the valuation and
disclosure method incorporated thereto. The transition standards applied by
the Company, affecting the comparability of the financial statements, are: a) The new methods for translating the financial statements of foreign
subsidiaries stated in foreign currency were not applied retroactively. b) The beginning balances resulting from the recognition, measurement, and
booking of derivative financial instruments qualified as effective hedge were
not corrected. 4. Valuation methods The main valuation methods used in the preparation of the consolidated
financial statements have been as follows: a) Accounts denominated in foreign currency: At the prevailing exchange rates at the end of each period, including
accrued interest, if applicable. The summary of accounts denominated in foreign
currency is disclosed in Note 27.d). b) Inventories: Crude oil stock: at reproduction cost. Materials: of high-turnover, at replacement cost; low-turnover, at the
last purchase price, restated in constant money, according to Note 2.c). Work in progress and finished products relating to refining, petrochemical
and electricity activities: at replacement or reproduction cost, as applicable,
proportional in the case of goods in process according to the degree of process
of the related good. Stock of liquid petroleum gases (NGL) in the gas pipeline system in excess
of the line pack and held by third parties and stock of NGL obtained from the
natural gas processing: at replacement or reproduction cost, as appropriate. The carrying amount of these assets, does not exceed their recoverable
value. c) Investments: Government securities:  Available for sale: at market value at the end of each period, less the
estimated selling expenses. Any gain or loss due to market fluctuations is
reflected currently in income in the Financial income (expense) and holding
gains (losses) account.  Held to maturity: at original value increased based on its internal rate
of return at acquisition. Interest gain is credited to income on accrual basis. Under the government-securities voluntary conversion system provided by
Federal Executive Decree No. 1387/01, the Company volunteered to swap
provincial and federal government securities for secured loans for a carrying
value of 6 and a market value of 3. Executive Decree 1579/02 established the
issuance of secured bonds, with final maturity date in 2018, monthly payable as
from 2005. The principal balance shall be adjusted by the Benchmark
Stabilization Coefficient (CER), accruing interest at an annual 2% fixed rate.
Foreign currency liabilities of the federal, provincial and municipal
public sector effective as of February 3, 2002, whose applicable law is only
Argentine law, shall be translated into pesos at the exchange rate of 1.40
pesos per US dollar and adjusted by CER, plus an annual 2% interest rate. F-20




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In addition, as of December 31, 2003, the Company carries other securities
with a market of 1, while their book value amounted to 2. Certificates of deposit and loans to affiliates over which significance
influence is exercised: at face value plus accrued interest. Unlisted Government securities: at the original value increased based on
the internal rate of return at acquisition limited by the recoverable value. Tax credit certificates: at the estimated value based on the application
of the certificates to the payment of federal taxes. Investments in mutual funds: at market prices at the end of each period. Shares  Participation in affiliates, in which the Company exercises
significant influence: By the equity method, following the procedure established by Technical
Resolution No. 5 of the FACPCE. For the determination of the Companys equity
in affiliates over which significance influence is exercised, the Company has
used financial statements from affiliates, or the best available financial
information. For the determination of the Companys equity in affiliates, consideration
has been given to the adjustments to adapt the valuation methods of some
affiliates to those of the Company, irrevocable contributions made by others,
elimination of reciprocal investments, intercompany profits and losses, the
difference between acquisition cost and book value of affiliates at the time of
the acquisition and the holding of preferred stock and dividends by the
affiliates. Cash dividends from affiliates approved by shareholders meetings
held prior to the date of issuance of these financial statements, which are
placed at the shareholders disposal within a term not exceeding one year are
deducted from the value of the investment and included in current investments. Other shares  interests in affiliates in which the Company does not
exercise significant influence: at acquisition cost restated in constant money
as shown in Note 2.c) to the consolidated financial statements. d) Trade receivables and accounts payable: Trade receivables and accounts payable have been valued at the spot cash
estimated at the time of the transaction, plus accrued financial components. Trade receivables include billed uncollected services and services
rendered but not yet billed as of each period. The services rendered but not
yet billed were estimated on the basis of series of actual historical data
billings subsequent to each period. The total amount of receivables is net of
an allowance for doubtful account, which is based on estimates of collection
carried out by the company. e) Financial receivables and payables: Financial receivables and payables have been valued according to the money
paid and collected, respectively, net of transaction costs, plus accrued
financial gains (losses) on the basis of the explicit or estimated rate at such
time. f) Other receivables and payables: Other receivables and payables have been valued on the basis of the best
possible estimate of the amount to be collected and paid, respectively,
discounted in the relevant cases, using the estimated rate at the time of
initial measurement, except for the deferred tax assets and liabilities. As
established by CNV regulations, deferred tax assets and liabilities have not
been discounted. This criterion does not comply with accounting standards
effective in the City of Buenos Aires, which required such balances to be
discounted. F-21




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g) Property, plant & equipment: Property, plant & equipment, except as indicated below, have been valued
at acquisition cost restated in constant money less related accumulated
depreciation. Property, plant & equipment related to foreign transactions were
converted into US dollars since that is the functional currency for such
transactions and they have been translated into Argentine pesos at the exchange
rate effective as of closing in accordance with the method for converting
foreign transactions described in note 2.b). The value of CIESAs PP&E transferred from the privatization of Gas del
Estado was determined based on the price paid for 70% of the capital stock of
TGS. Such price was the basic to determine the total common stock, which when
added to the initial debt assumed under the transfer contract, resulted in the
total value for PP&E. Such value, translated at the effective exchange rate as
of the date of the transfer contract, was restated in constant pesos. Petrobras Participaciones uses the successful efforts method of accounting
for its oil and gas exploration and production activities. Exploration costs, excluding exploratory well costs, are charged to
expenses for the period in which they are incurred. Drilling costs of
exploratory wells, including stratigraphic test wells, are capitalized until it
is assessed if proved reserves justifying the commercial development thereof
are discovered. If such reserves are not found, such drilling cost are charged
to expense. Occasionally, an exploratory well may determine the existence of
oil and gas reserves but they cannot be classified as proved when drilling is
complete. In these cases, one of the following would be applicable: (I)
whether the well found reserves in an area requiring a major capital
expenditures before production may start, and classification of such reserves
as proved is dependent upon whether additional reserves are found justifying
the abovementioned investment. In this case, the cost of the exploratory well
continues capitalized as long as it meets the following two conditions: (a)
reserves found are sufficient to justify completion of the well as producer if
the capital investment is made, and (b) the drilling of additional exploratory
wells is in progress or firmly planned for the near future. Otherwise,
drilling costs are charged to expense. (II) in all other cases, drilling costs
of exploratory wells do not remain capitalized for more than one year after the
completion of the drilling. If after one year found reserves may not be
classified as proved, exploratory well costs are charged to expense. The Company depreciates productive wells, as well as machinery, furniture
and fixtures and camps in the production areas according to the units of
production method, by applying the ratio of oil and gas produced to the proved
developed oil and gas reserves. The acquisition cost of property with proved
reserves is depreciated by applying the ratio of oil and gas produced to
estimated proved oil and gas reserves. Mining property related to unproved
reserves has been valued at cost and its recoverability is assessed from time
to time on the base of geological and engineering estimates of possible and
probable reserves that are expected to be proved over the life of each
concession. Estimated future restoration and abandonment costs discounted at an
estimated rate at the time of their initial measurement, are included in the
value at which the assets that gave rise to such costs are capitalized, and are
depreciated using the units of production method. Additionally, a liability is
recognized for such costs at the estimated value of the amount payable,
discounted at an estimated rate at the time of their initial measurement. The Company estimates its reserves at least once a year. Total oil and gas
reserves as of December 31, 2003, 2002, and 2001, were audited by Gaffney,
Cline & Associates Inc., independent international technical and management
advisors. Petrobras Participacioness remaining property, plant & equipment are
depreciated by the straight-line method based on their existing exploitation
concession terms and their estimated useful lives as the case may be. The cost of works in progress, whose construction will extend over time,
includes the computation of financial costs accrued on loans granted by third
parties, if applicable, and the costs related to putting the facilities into
operation that are considered net of any income obtained from the sale of
commercially valuable production during such process. The carrying value of property, plant & equipment, taken as hole, does not
exceed its recoverable value. F-22




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h) Environmental costs: The costs incurred to limit, neutralize or prevent environmental pollution
are only capitalized if at least one of the following conditions is met: (a)
such costs relate to improvements in the plants (or some other production
assets) capacity and safety; (b) environmental pollution is prevented or
limited; or (c) the costs are incurred to prepare the assets for sale and the
book values of such assets together with the additional cost do not exceed
their respective recoverable values. Liabilities related to future remediation costs are recorded when
environmental assessments are probable, and the costs can be reasonably
estimated. The timing and magnitude of these accruals are generally based on
the Company  ́s commitment to a formal plan of action, such as an approved
remediation plan or the sale or disposal of an asset. The accrual is based on
the probability that a future remediation commitment will be required. The Company records the related liabilities based on its best estimate of
future costs, using currently available technology and applying current
environmental regulations as well as the Company  ́s own internal environmental
policies. i) Income tax, tax on minimum presumed income, royalties and withholdings on
export of hydrocarbons: The Company and its affiliates estimate income tax on individual basis
under the deferred tax method. The deferred tax balance as of the end of each period has been determined
on the basis of the temporary differences generated in certain items that have
a different accounting and tax treatment. To book such differences, the Company uses the liability method, which
established the determination of net deferred tax assets and liabilities on the
basis of temporary differences determined between the accounting measurement of
assets and liabilities and the related tax measurement. Temporary differences
determine the balance of tax assets and liabilities where its future reversal
decreases or increases the taxes determined. Where there are unused Tax loss
carryforwards that may be offset against future taxable income, the Company
will recognize a deferred tax asset, only to the extent that recovery of such
asset is probable. Deferred tax assets and liabilities have been valued at their nominal
value, as established by CNVs General Resolution No. 434. The professional
accounting standards effective in the City of Buenos Aires require that such
nominal value be discounted at a current rate estimated as of each period-end. The tax on minimum presumed income is supplementary to income tax, since
while the latter is levied on the years taxable income, the tax on minimum
presumed income is a minimum tax levied on the potential income of certain
productive assets at the rate of 1%, so that the Companys final liability will
be equal to the higher of both taxes. However, should the tax on minimum
presumed income exceed the tax based on income in any given year, such excess
may be applied to reduce any excess of income tax over the tax on minimum
presumed income in any of the ten succeeding years. For the operations in Argentina, Venezuela, Brazil, Peru, Ecuador and
Bolivia the income tax accrual was calculated at the tax rates of 35%, 34%,
34%, 30%, 25% and 25%, respectively. Additionally, payment of Bolivian-source
income to beneficiaries outside Bolivia is subject to a 12.5% withholding
income tax and, a 34% income tax is levied on the dividends paid by Venezuelan
companies, in event of income in excess of taxable income. Law No. 25,239 and its Administrative Order No. 1037/2000 amended income
tax law to establish, among other things, that shareholders residing in
Argentina of companies organized or operating in countries with low or
no-taxation with non-operating income exceeding 50% of net income, are to book
accrued passive income such as interest, dividends, royalties, rents or other
similar passive income to the fiscal year, although the income was not remitted
or credited to any account. The Law and Administrative Order also establish
that such companies shall not generate Argentine tax credits for the tax paid
abroad. Royalties are paid in Argentina, Peru and Bolivia for the production of
crude oil and for effectively used volumes of natural gas. Those royalties are
12%, 24.5% and from 40% to 60%, respectively, of the wellhead F-23




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estimated price for oil and gas. The wellhead price represents the final
sales price less treatment, storage and transportation costs. Royalties are
charged to production costs in the Oil and gas royalties account. In Venezuela,
for the Acema, Mata and La Concepción (Third Round) areas, 30% royalties are
paid with respect to the excess production, calculated based on the crude
wellhead estimated price. Under contractual terms, royalties of the Third Round
areas are deducted from the sales price. In Ecuador, the exploitation agreement
for Block 18 provides for a schedule of differential royalties, that in the
case of Pata field are applied over a production volume scale and for Palo Azul
field, according to oil prices. As regards the Pichi Picún Leufú Hydroelectric Complex, as provided in the
concession agreement, the Company pays hydroelectric royalties of 1% increasing
at a rate of 1% per annum up to the maximum percentage of 12% of the amount
resulting from applying the rate for the bulk sale to the power sold under the
terms of Section No. 43 of Law No. 15,336, as amended by Law No. 23,164. In
addition, the Company is subject to a license fee payable monthly to the
Federal Government for the use of the power source equivalent to the 0.5% of
the same amount base for hydroelectric royalty calculation. The Public Emergency and Exchange System Reform Law No. 25,561 establishes
the creation of a system of withholdings on exports of hydrocarbons for five
years, since March 1, 2002. The rate of those withholdings is 5% for certain
refined products and 20% for the crude oil. j) Liabilities for labor costs and commitments that generate losses: Liabilities for labor costs are accrued in the periods in which the
employees provide the services that trigger the consideration. For purposes of determining the estimated cost of benefit pension plans
granted to employees, the Company has used actuarial calculation methods,
making estimates with respect to the applicable demographic and financial
variables. k) Contingencies: Certain conditions may exist as of the date of financial statements which
may result in a loss to the Company, but which will only be resolved when one
or more future events occur or fail to occur. Such contingent liabilities are
assessed by the Companys management based on the opinion of Petrobras
Participacioness legal counsel and the available evidence. Such contingencies include outstanding lawsuits or claims for possible
damages to third parties in the ordinary course of the Company  ́s business, as
well as third party claims arising from disputes concerning the interpretation
of legislation. If the assessment of a contingency indicates that it is probable that a
loss has been incurred and the amount can be estimated, a liability is accrued
in the Reserves account. If the assessment indicates that a potential loss
contingency is not probable, but is reasonably possible, or is probable but it
cannot be estimated, then the nature of the contingent liability, together with
an estimate of the possibility of occurrence, is disclosed in a note to the
financial statements. Loss contingencies considered remote are not disclosed
unless they involve guarantees, in which case the nature of the guarantee is
disclosed. However, in some instances in which disclosure is not otherwise required,
the Company may disclose contingent liabilities of an unusual nature which, in
the judgment of management, may be of interest to the users of the financial
statements. Significant litigations in which the Company is involved and the movements
of reserves are disclosed in Note 14. l) Earnings (losses) per share: Earnings (losses) per share for the years ended December 31, 2003, 2002 and
2001, were calculated on the basis of the number of outstanding shares in each
period. Since the Company does not have preferred assets or convertible debt
securities, the basic earnings (losses) per share is equal to the diluted
earnings (losses) per share. F-24




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##### Table of Contents



m) Shareholders  equity accounts: They were restated into constant money, according to Note 2.c), as of
year-end, except for Capital stock that represents subscribed and paid-in
capital. The adjustment arising from the restatement into constant money is
disclosed under Adjustment to capital stock. The account Treasury stock
relates to the purchases of shares of Petrobras Energía Participaciones S.A. by
Petrobras Energía, and are deducted from the shareholders equity at
acquisition cost, disclosed in a separate line in the statement of changes in
shareholders equity. n) Revenue recognition: Revenues from sales are recognized when the products are delivered or the
services are provided, the price is fixed or determinable, collection is
probable and the risk of loss has been transferred to customers. Revenues from sales resulting from the firm natural gas transportation are
recognized by the accrued reserve of the transportation capacity hired,
regardless of the volumes carried. With respect to crude oil prices, in January 2003, at the federal
executive branchs request, hydrocarbon producers and refineries executed a
temporary agreement in connection with crude oil, gasoline and diesel oil price
stability in the domestic market. After successive renewals, the term of this
agreement was extended until May 2004. This agreement provides for crude oil
deliveries to be invoiced and paid based on the West Texas Intermediate Crude
reference price, or WTI, of U.S.$28.5 per barrel instead of the actual relevant
WTI. Any positive or negative difference between the actual relevant WTI, not
exceeding U.S.$36 per barrel, and the reference price would be paid out of any
balance generated in periods where the actual WTI is below U.S.$28.5 per
barrel. Refineries, in turn, will reflect the crude oil reference price in
domestic market prices. In May 2004, hydrocarbon producers and refineries
executed a new agreement effective until June 2004, which provided that, while
the WTI per barrel ranges between U.S.$32 and U.S.$42, crude oil deliveries
will be invoiced and paid considering a reference price equal to (i) 86% of the
WTI as long as this price does not exceed U.S.$ 36 per barrel, or (ii) 80% of
the WTI, in cases where this price exceeds U.S.$36 per barrel. We did not
recognize any revenue over U$S28.5 for the WTI o) Statement of income accounts: Restated into constant money through the end of the period, according to
Note 2.c), considering the following: - Depreciation and consumption expenses related to non monetary assets were
charged to income (losses) taking into account the restated costs of such
assets. - Financial income (expense) and holding gains (losses) are broken down as
generated by assets and generated by liabilities. Financial (expense) income,
net discloses financial income and expenses, exchange differences and income
(loss) from changes in the quotation of government securities and shares, at
their restated nominal value, according to Note 2.c). Additionally, it also
discloses the effects of inflation of monetary assets and liabilities in the
balance sheet. For the years ended December 31, 2002, and 2001, Financial income
(expense) and holding gains (losses) includes net income from conversion and
translation on non monetary assets of foreign operation, in real terms. CNV General Resolution No. 398 allows, as an exceptional treatment, the
one provided for in Resolution M.D. No. 3/2002 of the CPCECABA, whereby the
exchange differences originated as from January 6, 2002, from liabilities in
foreign currency existing as of such date directly related to the acquisition,
construction, or production of property, plant & equipment, intangibles, and
long-term investments in other companies organized in the country should be
allocated at the cost values of such assets with a number of conditions
established in such professional standard. Direct financing shall mean that
granted by the supplier of the goods, billed in foreign currency, or that
obtained from financial institutions for identical purposes. In the cases in
which there is an indirect relation between the financing and the acquisition,
production, or construction of the assets, such exchange differences may also
be allocated, under certain conditions, to the cost values of such assets. The
Company has adopted the method of capitalizing exclusively the foreign exchange
differences resulting from direct financing. F-25




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##### Table of Contents



As mentioned above, as of December 31, 2003, and 2002, the Company has
capitalized exchange differences booked with a residual value of 46 and 48,
respectively. 5. Accounting for derivative financial instruments Hedging and other derivatives: The Company uses various derivative financial instruments such as options,
swaps and others, mainly to mitigate the impact of changes in crude oil prices,
interest rates and future exchange rates. Such derivative instruments are designated as hedging specific exposures,
highly correlated to the risk exposure in question and highly effective in
offsetting changes in cash flows inherent to the covered risk. The use of derivative financial instruments exposes the Company to credit
risk. In addition, the Company uses strict policies for the approval of lines
of credit, applies several procedures to evaluate these risks and seeks to
reduce this credit exposure by means of the use of certain tools, such as
anticipated collections or payment agreements for such operations and the
offsetting of collections and payments. Derivative financial instruments are measured at their fair value,
determined as the amount of cash to be collected or paid to settle the
instrument as of the date of measurement. a) Instruments that qualify for hedge accounting Changes in the accounting measurement of derivative financial instruments
designated as cash flow hedge, which have been determined as effective hedge,
are recognized under Transitory differences-Measurement of derivative
financial instruments designated as effective hedge, and any other change is
recognized under financial income (expense) for the year. Changes in the
accounting measurement of derivate financial instruments recognized under
Transitory differences-Measurement of derivative financial instruments
determined as effective hedge are subsequently reclassified to income (loss)
for the year or years in which the hedged item affects such results. A hedge is considered to be effective when at its inception, as well as
during its life, its changes offset from eighty to one hundred and twenty five
percent the opposite changes of the hedged item. In the respect, the Company
excludes the specific component attributable to the time-value of an option
when measuring the effectiveness of instruments that qualify for hedge
accounting. Hedge accounting must cease for the future upon occurrence of any of the
following events: (a) the hedge instrument has matured or has been settled; (b)
the hedge transaction is no longer effective; (c) the projected transaction
does not have a high likelihood of occurrence. Should that be the case, the
income (loss) arising from the hedge instrument that would have been allocated
to Transitory differences-Measurement of derivative financial instruments
determined as effective hedge should remain there until the committed or
projected transactions occurs in the case of (a) and (b), and are charged to
income in the case of (c). Pursuant to the transitional standards of FACPCE Technical Resolution No.
20, the Company applied the standard of booking derivative positions at their
market value on a prospective basis. As indicated above, as of December 31,
2002 and 2001, the gains (losses) on hedge transactions related to the crude
oil price, without distinguishing between hedge and non-hedge transactions,
were deferred until the related anticipated transaction was recognized, when
they were booked as an integral part of hedged sales. Hedge of produced crude oil price These instruments use West Texas Intermediate (WTI) as reference price,
which is used mainly to determine the sale price in the market. During 2003, the Company maintained hedge transactions through flexible
option contracts, with a total covered volume of 8.3 million barrels. In
addition to the referred hedge, during 2002, the Company settled positions in
the aggregate amount of 42,500 bbls/day for 2003. This volume was realized at
market value with a discount of USD 1.11/bbl. F-26




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##### Table of Contents



For the years ended December 31, 2003, 2002, and 2001, the accrued
portions of hedge instruments represented a lower sale of 81, 373 and 341,
respectively. As of year-end, the Company did not have positions in derivatives of the
crude oil price related to the future production that qualify for hedge
accounting purposes. Hedge of interest rates As of December 31, 2003, the Company has an agreement for the purpose of
hedging class C notes exposed to fluctuations with the LIBOR, fixing the rate
at 7.93% per annual. Such contract term expires in July 2005, payable in quarterly installments
as from 2004. The market value for the year amounts to 23. During the period, the changes in Transitory differences-Measurement of
derivative financial instruments determined signated as effective hedge was: 2003Price of
    
    InterestOil
    
    Rate
    
    TotalBalance at begining at yearCumulative effect of accounting change
    
    
    67
    
    
    
    42
    
    
    
    109Changes of fair value
    
    
    15
    
    
    
    
    
    
    
    15Reclasification to net income (loss)
    
    
    (81
    )
    
    
    (24
    )
    
    
    (105
    )Ineffectiveness
    
    
    (1
    )
    
    
    
    
    
    
    (1
    )Balances at end of year
    
    
    
    
    
    
    18
    
    
    
    18
 b) Instruments that do not qualify for hedge accounting Changes in the accounting measurement of derivative financial instruments
that do not qualify for hedge accounting are recognized in the statement of
income under Financial income (expense) and holding gains (losses). The
difference between the current value of such instruments and the previous value
booked by the Company in the year ended December 31, 2002, was charged to
unappropriated retained earnings recognizing a loss of 426. For the year ended
December 31, 2003, losses of derivative financial instruments that do not
qualify for hedge accounting amount to 294. The main conditions and terms by type of instrument as of December 31,
2003 are as follows: Expected maturity2004
    
    2005
    
    TotalSales price exposureCrude oil price swap (1)Contract volumes (million barrels)
    
    
    4.10
    
    
    
    
    
    
    
    4.10Average settlement prices (US$  per barrels)
    
    
    18.64
    
    
    
    
    
    
    
    Fair value before advanced payments
    
    
    
    
    
    
    
    
    
    
    (152.00
    )Swap options (2)Contract volumes (million barrels)
    
    
    6.90
    
    
    
    7.30
    
    
    
    14.20Average settlement prices (US$  per barrels)
    
    
    19.00
    
    
    
    19.00
    
    
    
    Fair value before advanced payments
    
    
    
    
    
    
    
    
    
    
    (397
    )
 1) Options on swaps exercised by the other party. 2) The transaction included herein are sold swaptions. F-27




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##### Table of Contents



6. Oil and gas areas and participation in joint ventures As of December 31, 2003, Petrobras Participaciones and its subsidiaries
were part of the oil and gas consortiums, joint-ventures and areas indicated in
Note 27.g). As of that date, the aggregate joint ventures and consortia assets,
liabilities and results in which the Company is a party, included in each
account of the balance sheet and the statement of income, respectively,
utilizing the proportionate consolidation method are disclosed in Note 27.h). The production areas in Argentina, Ecuador and Peru indicated in Note
27.g) are operated pursuant to concession production agreements with free crude
oil availability. Those related to Venezuela are exploitation service
agreements, in which Petróleos de Venezuela S.A. (PDVSA) owns all the oil and
gas produced and is responsible for the payment of all royalties and taxes
related to the production and will receive, upon expiration of the agreement
term, the exclusive ownership of all operating facilities, property and
equipment used by the joint ventures to perform the activities under the
agreement. In Bolivia it is a shared-risk contract signed with Yacimientos
Petrolíferos Fiscales Bolivianos (YPFB) with free production availability. The Company is jointly and severally liable with the other joint venturers
for meeting the contractual obligations under these arrangements. As regards the Oritupano-Leona area, in Venezuela, the joint venture
awarded the area receives a variable operation fee based on production volumes,
which amounts to US$ 6.14 per barrel as of December 31, 2003, plus a capital
fee for reimbursement of certain exploration and development investments. Under
the terms of the service agreement executed with PDVSA, the total amount to be
paid may not exceed approximately US$ 28.72 per barrel, variable according to a
basket of oil market prices. In relation to the Mata, Acema and La Concepción fields, also in
Venezuela, the joint ventures awarded the areas are paid a fee for the
operation services rendered, which covers the investments and production costs
plus a gross profit. The fee has a fixed component related to contractual
baseline production and a variable component related to the incremental
production, that covers investments and production costs plus a gross profit up
to a maximum tied to a basket of international oil prices. Divestments of equity in oil and gas areas In August 2003, Petrobras Energía sold to Central International
Corporation, Argentine Branch, the 85% interest over the rights and obligations
on the concession of the Catriel Oeste area. Considering the transfer price
agreed, of US$ 7 million, Petrobras Energía recognized a loss of 28 presented
under Other expenses, net. In June 2003, Petrobras Energía sold to Geodyne Energy Inc., Argentine
branch, the 50% equity interest over the rights and obligations pertaining to
the Faro Vírgenes concession area, recognizing a loss of 11, disclosed under
Other expenses, net. This transaction shall be settled over a ten-year
period, in quarterly installments, whose value in US dollars shall be
determined as 8.8% of the total production of gas from the Faro Vírgenes area
for each quarter. Petrobras Energía has the option to receive such
consideration directly in gas. Such future revenue stream is recognized in
income for the period as natural is produced. In October 2002, Petrobras Energía signed an association agreement with
Teikoku Oil Co., Ltd., whereby it transferred 50% of its rights and obligations
to exploit gas in exploratory areas in San Carlos and Tinaco, located in th
State of Cojedes, Venezuela. The participation assignment agreement provides
the initial cash payment of US$ 1 million and a subsequent disbursement of US$
2 million, which shall finance the plan of exploratory investments of the
Tinaco area, as regards geological studies, 2D seismic and evaluations and
interpretation thereof. Also if the development of those areas is agreed,
Petrobras Energía will receive an additional payment of US$ 3 million. Considering the recoverable value as of December 31, 2002, Petrobras
Energía recognized a loss of 37, disclosed under Other expenses, net. In October 2001 the Company sold the operating rights over the Pampa del
Castillo-La Guitarra field and the 13.79% shareholding in Terminales Marítimas
Patagónicas S.A. For such the net realizable value which was fixed in 225 and
represented a loss of 65. F-28




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##### Table of Contents



Assets exchange In February 2001, the Company concluded an asset exchange, which had
economic effects as from January 1, 2001. Under the exchange terms: (i) the
Company incorporated interest in the Santa Cruz I (30%) and Santa Cruz II
(62.2%) joint ventures; (ii) in contrast, the Company conveyed its 50% interest
in the Manantiales Behr and Restinga Alí areas, together with the 40.5% holding
in Andina Corporation, holder of 50% of Empresa Petrolera Andina S.A.
(Bolivia). Such transaction was approved by the Federal Anti-Trust Board in May
2001, and generated an income of 251 in the year ended December 31, 2001. Investment commitments Petrobras Energía operates oil and gas areas under several contractual
arrangements that provide for minimum investment commitments for exploration
and development of oil and gas fields. Total commitments as of December 31,
2003, are approximately US$ 7 million through 2005. 7. Credit risk Petrobras Participaciones provides credit in the normal course of business
to refiners, petrochemical companies, marketers of petroleum products, crude
oil exporting companies, electric power generation companies, retail customers,
natural gas distributors, electric power large users and power distribution
companies, among others. As a result of the business of Petrobras Participaciones and sale
locations, the portfolio of receivables is well diversified, and such
diversification makes the credit risk moderate. Thus, Petrobras Participaciones
constantly performs credit evaluations of the financial capacity of its
clients, which minimizes the potential risk of bad debt losses. Sales for the year ended December 31, 2003, were made mainly to Petróleos de
Venezuela S.A., Petroperú Petróleos del Perú S.A., Repsol  YPF Trading y
Transporte S.A. and Glencone AG and represented about 11%, 7%, 5% and 4%,
respectively, of sales for such period, before computing gain (loss) generated
by derivative financial instruments and before deducting export duties. Sales for the year ended December 31, 2002, were made mainly to Petróleos de
Venezuela S.A., Petroperú Petróleos del Perú S.A., Repsol  YPF Trading y
Transporte S.A. and Petrobras and represented about 16%, 8%, 7% and 6%,
respectively, of sales for such period, before computing gain (loss) generated
by derivative financial instruments and before deducting export duties. Sales for the year ended December 31, 2001, were made mainly to Petróleos de
Venezuela S.A., Repsol  YPF Trading y Transporte S.A., Petroperú Petróleos del
Perú S.A., Petrobras and EG3 S.A., and represented about 13%, 6%, 6%, 4% and
3%, respectively, of sales for such period, before computing gain (loss)
generated by derivative financial instruments and before deducting export
duties. 8. Inventories 2003
    
    2002Current
    
    Noncurrent
    
    Current
    
    NoncurrentCrude oil stock
    
    
    41
    
    
    
    
    
    
    
    32
    
    
    
    Materials
    
    
    125
    
    
    
    63
    
    
    
    166
    
    
    
    39Work in progress and finished products  refining and petrochemical
    
    
    122
    
    
    
    
    
    
    
    149
    
    
    
    Prepayments to vendors
    
    
    33
    
    
    
    
    
    
    
    9
    
    
    
    Other
    
    
    2
    
    
    
    
    
    
    
    3
    
    
    
    Reserve for materials  ́ obsolescence (Note 14.f)
    
    
    (4
    )
    
    
    (2
    )
    
    
    (3
    )
    
    
    319
    
    
    
    61
    
    
    
    356
    
    
    
    39
 F-29




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##### Table of Contents



9. Investments, equity in earnings of affiliates and dividends collected from
affiliates The breakdown of current and noncurrent investments, the equity in
earnings of affiliates and dividends collected from affiliates as of December
31, 2003 and 2002, and for the years ended December 31, 2003, 2002 and 2001,
are as follows: a) Investments 2003
    
    2002Name and issuer
    
    Cost
    
    Book value
    
    Book valueCurrent:Government securities
    
    
    41
    
    
    
    23
    
    
    
    59Certificates of tax credits
    
    
    5
    
    
    
    5
    
    
    
    4Certificates of deposit
    
    
    146
    
    
    
    146
    
    
    
    83Mutual funds
    
    
    626
    
    
    
    626
    
    
    
    492Loans to unconsolidated affiliates (Note 18)
    
    
    
    
    
    
    
    
    
    
    19Other
    
    
    2
    
    
    
    2
    
    
    
    7820
    
    
    
    802
    
    
    
    664Noncurrent:Government securities
    
    
    2
    
    
    
    2
    
    
    
    26Advances to joint ventures
    
    
    157
    
    
    
    157
    
    
    
    245Loans to unconsolidated affiliates (Note 18)
    
    
    127
    
    
    
    127
    
    
    
    Equity in affiliates (Note 27 b.)
    
    
    1,007
    
    
    
    996
    
    
    
    832Other
    
    
    
    
    
    
    2
    
    
    
    1,293
    
    
    
    1,284
    
    
    
    1,103
 F-30




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##### Table of Contents



b) Equity in earnings of affiliates 2003
    
    2002
    
    2001Cerro Vanguardia S.A.
    
    
    
    
    
    
    59
    
    
    
    16Cia. de Inversiones de Energía S.A.
    
    
    (33
    )
    
    
    (398
    )
    
    
    Citelec S.A.
    
    
    87
    
    
    
    (241
    )
    
    
    19Empresa Boliviana de Refinación S.A.
    
    
    (5
    )
    
    
    12
    
    
    
    8Enron de Inversiones de Energía S.C.A.
    
    
    
    
    
    
    (32
    )
    
    
    5Oleoducto de Crudos Pesados Ltd.
    
    
    (5
    )
    
    
    
    
    
    
    Pecom Agra S.A.
    
    
    
    
    
    
    
    
    
    
    17Inversora Mata S.A.
    
    
    4
    
    
    
    (9
    )
    
    
    (2
    )Oleoductos del Valle S.A.
    
    
    2
    
    
    
    11
    
    
    
    11Petrolera Entre Lomas S.A.
    
    
    13
    
    
    
    12
    
    
    
    8Petroquimíca Cuyo S.A.
    
    
    16
    
    
    
    (10
    )
    
    
    4Refinería del Norte S.A.
    
    
    28
    
    
    
    9
    
    
    
    6Transportadora de Gas del Sur S.A.
    
    
    52
    
    
    
    (52
    )
    
    
    10Yacylec S.A.
    
    
    2
    
    
    
    2
    
    
    
    5Other
    
    
    2
    
    
    
    (1
    )
    
    
    12163
    
    
    
    (638
    )
    
    
    119
 c) Dividends collected from affiliates 2003
    
    2002
    
    2001Citelec S.A.
    
    
    
    
    
    
    
    
    
    
    15Pecom Agra S.A.
    
    
    
    
    
    
    
    
    
    
    4Yacylec S.A.
    
    
    3
    
    
    
    1
    
    
    
    7Empresa Boliviana de Refinación S.A.
    
    
    
    
    
    
    4
    
    
    
    Petrolera Entre Lomas S.A.
    
    
    9
    
    
    
    12
    
    
    
    7Oleoductos del Valle S.A.
    
    
    7
    
    
    
    3
    
    
    
    7Transportadora de Gas del Sur S.A.
    
    
    
    
    
    
    
    
    
    
    11Refinería del Norte S.A.
    
    
    7
    
    
    
    
    
    
    
    Other
    
    
    
    
    
    
    
    
    
    
    426
    
    
    
    20
    
    
    
    55
  I.
    
    Investment in companies over which joint control or significant influence
is exercised and are subject to transfer restrictions: a) Distrilec Inversora S.A. (Distrilec): Distrilec is able to change its equity interest and sell its shares of
Edesur S.A. (Edesur) only with the approval of the ENRE (Federal Power
Regulation Authority). In addition, over the entire term of the concession, the Class A shares
in Edesur shall remain posted as bond to guarantee compliance with the
obligations undertaken in the Concession Agreement. This bond in no way limits
the exercise of financial and voting rights associated with the Edesur shares. b) Cía. de Inversiones de Energía S.A. (CIESA): Shareholders of CIESA, parent company of Transportadora de Gas del Sur
S.A. (TGS), may not sell over 51% of its Class A shares representing 51% of
CIESA#s capital stock, without the prior authorization of the regulatory agency
and the approval of the shareholders of CIESA. There are certain disagreements between the Company and the Enron Group,
which jointly control CIESA, as to the actual occurrence of an event of change
of shareholders. Under the CIESA Shareholders Agreement, in the event of a
change in the ultimate parent of a shareholder, such shareholder must offer its
shares to the others. Although from opposing standpoints, both companies
interpret that such an event has taken place: the Company interprets it has
occurred with the bankruptcy of the Enron Group, while the Enron F-31




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##### Table of Contents



Group
interprets it has occurred upon the transfer of the shares of the Company. In
January 2003, the Company was notified by Enrons legal counsel that such
company would file arbitration proceedings in this regard. See note 26 for
events subsequent to December 31, 2003. c) Compañía Inversora en Transmisión Eléctrica Citelec S.A. (Citelec): The Company may not modify or sell its equity interest in Citelec in a
proportion and number of shares exceeding 49% of its shareholding without prior
approval by the ENRE. Citelec is not permitted to modify its 65% equity interest in Compañía de
Transporte de Energía en Alta Tensión Transener S.A. (Transener) nor sell its
Class A shares representing 51% of Transeners capital stock, without prior
approval by the ENRE. Transener may not modify or sell its shareholding in Empresa de Transporte
de Energía Eléctrica por Distribución Troncal de la Provincia de Buenos Aires
Transba S.A., without prior approval by the ENRE. d) Yacylec S.A. (Yacylec): Yacylecs Class A shares will remain pledged during the term of the
concession, as security for the compliance with the obligations undertaken
under the concession agreement. Any transfer of shares requires ENREs prior
authorization. II. Enecor S.A. For the entire term of the concession, the Class A shares in Enecor
shall remain posted as bond to guarantee compliance with the obligations
undertaken in the Concession Agreement. Prior authorization from the ENRE is
required for any transfer of shares. III. Assets exchange The Regular Shareholders Meeting held on April 3, 2002, approved an
agreement with economic effects as from January 1, 2002, whereby:  i)
    
    Petrobras Energía sold to IRHE (Argentine Branch) and GENTISUR
S.A. (a company wholly owned by IRHE) its 50% equity interest in Pecom
Agra S.A. in the amount of US$ 30 million, which represented a gain of
81.ii)
    
    IRHE (Argentine Branch) and GENTISUR S.A. transferred to Petrobras Energía:  
    
    0.75% interest in the Puesto Hernández joint venture in the amount of US$4.5 million;
    
    7.5% interest in Citelec, in the amount of US$15 million;
    
    9.187% interest in Hidroneuquén S.A., a company holding 59%
of Hidroeléctrica Piedra del Águila S.A. stock, in the amount of US$
5.5 million. The remaining balance, US$ 5 million, was settled through a document
maturing in October 2002, which accrues interest at six-month LIBOR plus annual
3% spread. IV. Sale of companies a) Disposal of farming, forestry and mining activity assets The agreements made in relation to the transfer of the controlling shares
of Petrobras Participaciones granted Petrobras an option, whereby if, within a
30-day term subsequent to the end of the purchase-sale of shares, Petrobras
Energía would not have sold the assets related to agricultural, forestry and
mining activities, Petrobras would be entitled to, but not required to, make
the seller acquire those assets in an amount of US$ 190 million or, if any of
those assets has been sold, the amount resulting from deducting from such
addition, the price received in consideration of the sale made. F-32




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##### Table of Contents



Under these agreements, during 2002 Petrobras Energía perfomed the
following transactions:  
    
    In July 2002, Petrobras Energía sold to Anglogold its indirect ownership
interest of 46.25% in Cerro Vanguardia S.A., and the assets associated
therewith. The price of the transaction has been fixed at US$ 90 million.
The transaction represented a profit of 123. In September 2002, Petrobras Energía sold to Argentina Farmland Investors LLC
the ownership interest representing 100% of the capital stock of Pecom
Agropecuaria S.A. The price of the transaction totaled US$ 53 million, which
implied a profit of 27.  
    
    In December 2002, it concluded the disposal of the operations that form
part of the forestry business, which included the sale of the 100%
shareholding in Pecom Forestal S.A., jointly with the ownership of
forestry located in the Paraná delta region, to DRT Investments LLC. In
addition, it transferred the going concern related to forestry related
industrial activities in Misiones to Alto Paraná S.A. In January 2004, the
Company completed all the formalities needed for the transfer of the going
concern of forestry related industrial activities. The total price of the
abovementioned transactions amounted to US$ 53.16 million, resulting in a
153 loss. b) Sale of interest in Combustibles Nucleares Argentinos S.A. (CONUAR) In October 2002, the Company sold its 66.67% shareholding in CONUAR to
Sudacia S.A., a company controled by the Perez Companc Family, including the
68% interest in Fabricación de Aleaciones Especiales S.A. The transaction price
amounted to US$ 8 million, while no income (loss) was derived from such sale. V. Situation of the interests in public utility companies The new scenario after enactment of the Law on Public Emergency deeply
changed the financial equation of public utility companies. Particularly, the
tremendous effect of the devaluation, within a context where revenues remained
fixed, as a consequence of de-dollarization of rates, has affected the
financial and cash flow position of companies, as well as their ability to
comply with certain loan covenants. This situation has extremely conditioned
the financial ability to comply with obligations. Public Emergency Law provided for the conversion into Argentine pesos and
the elimination of indexation clauses on public service rates, thus fixing them
at the exchange rate of ARS 1 = US$ 1. In addition, the Executive Branch was
empowered to renegotiate those agreements entered into to provide public
services, pursuant to the following criteria: (i) rates impact on economic
competitiveness and revenue allocation, (ii) service quality and investment
plans, to the extent that they were contractually agreed upon, (iii) users
interests and access to services, (iv) the safety in the system involved, and
(v) utilities profitability. To allow for preserving the provision of public services, and
consistently the renegotiation process underway, the Executive Branch issued
Executive Order No. 146/03 authorizing to increase gas and electric power
rates. This caused a 10% increase for TGS, 9% for Edesur and 22% for
Transener. The increase in rates was objected by the ombudsman and consumer
associations. On February 25, 2003, a trial court issued an injunction and
suspended the increase in rates authorized by Executive Order No. 146/03. On October 1, 2003, Argentine Congress passed a bill that established the
extension to December 2004 of the term granted by the Federal Executive by
virtue of Public Emergency Law to renegotiate the agreements executed with
privatized public-service companies. Such law also will allow the Federal
Executive to fix public utilities rates until the completion of the
renegotiation process. It is not possible to foresee the future development of the rate
renegotiation process. In addition, it is not possible to guarantee that
regulations will not be changed and that they will not have an adverse
impact on the financial position and results of operations of such companies. CIESA, TGS and Transener have defaulted on their obligations and strive to
reschedule them (see Note 12.X). The managements of these companies have
drafted and implemented a plan of action to mitigate the adverse impact caused
by these circumstances. The Company cannot guarantee the success in
implementing it and whether it will fulfill the proposal aims. The impact
generated by the measures adopted by the Federal Government on CIESA, TGS,
Transener and Citelec financial statements was recognized based on the
evaluations and estimations carried out by the related managements. Actual
future income or losses could differ from estimates and such differences may be
significant. Consequently, these companies financial statements may not report
all the adjustments that could derive from these circumstances. F-33




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As of December 31, 2003, the valuation of the equity interests in CIESA
(which has been proportionally consolidated), TGS and Citelec amounts to 190,
167 and 158, respectively. In the opinion of the Companys Management, the
book value of such equity interests does not exceed the recoverable value. The
estimation of the respective recoverable values is subject to the significant
uncertainties described, which affect the quality of the assumptions,
estimations and evaluations inherent in such determination. Consequently, in
the current situation, the listed value of shares of stock is the most
objective guideline for determining the net realizable value of such holdings.
The reliability and the applicability of any values in use that might be
determined become relative because of the prolongation of the uncertainties and
the fact that, in projecting the future, multiple scenarios can be drawn up
while the estimation of their respective probabilities is extremely subjective,
a problem that extends to agreeing on the discount rate to be applied. As of December 31, 2002, the valuation of the equity interests in CIESA,
TGS and Citelec amounted to zero, 88 and 71, respectively. The equity interest
in CIESA valued under the equity method in conformity with accounting
principles consistent with those applied by the Company would have represented
an amount of 33 negative. However, considering that the Company has not
undertaken commitments to contributing capital or providing financial aid to
its affiliates, such equity interest has been stated at zero value, thus
restricting the recognition of losses related to the respective book value.
The value of the equity interest in Citelec was presented net of the allowance
for impairment in value of 66, determined as mentioned above. In the year ended December 31, 2001, the Company charged to expenses the
CIESA acquisition value exceeding the related book value, which implied a 202
loss. 10. Impairment of assets a) Operations in Argentine The Argentine peso devaluation, the enactment of Public Emergency Law and
the different events that took place caused a significant change in the
Companys estimation of the future income or loss evolution and the flow of
certain businesses and assets. Considering the uncertainties existing
with respect to the final breakdown of the economic and financial equation
and their recoverability, during 2002 and 2003 the Company adjusted the book
value of certain investments to their related recoverable values, booking
these allowances:  
    
    Gas areas in Argentina and shareholding in Hidroneuquén: Considering
the significant adverse impact on gas and power local prices, and the
limited possibilities of negotiating price increases within the
context of Public Emergency Law, the Company adjusted the book value
of certain investments in gas producing areas in Argentina to its
recoverable value, booking 44 and 37 losses during 2003 and 2002,
respectively. Also, during 2002, the Company adjusted the book value
of its investment in Hidroneuquén to its recoverable value, booking 10
losses.  
    
    Argentine Government public securities: as a result of the Argentine
Government declaration of its default on the payment of most its
sovereign debt and the significant uncertainties over the Argentine
economic scenario, as of December 31, 2003, the Company booked a
valuation allowance for the notional value of Argentine External Bills
in U.S. dollars, survey rate series 74, amounting to 23. As of
December 31, 2002, the above mentioned allowance amounted 30. Applying
a criterion of prudence, and recognizing the effects of applying
Federal Executive Decree No. 1,264, which allows settling tax
obligations with the principal coupons of such securities taken at
nominal value, the Company reverses the allowance as and when the
securities are actually applied. - Tax on minimum presumed income credit: considering the future income
(loss) evolution estimations, the Company carries an allowance for 72. b) Operations in Ecuador OCP is a company organized to build and operate a heavy crude oil pipeline
in Ecuador. The pipeline has a transportation capacity of 450,000 barrels per
day. During 2003, the oil pipeline construction was completed. After the
maximum flow system had been tested and the Ministry of Energy and Mining  ́s
approval had been obtained, the oil pipeline started to operate officially on
November 10, 2003. The oil pipeline passes through sensitive areas from an
ecological standpoint. Accordingly, such oil pipeline has been built under the
strictest technical and environmental protection standards. F-34




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The total cost of the oil pipeline was about US$ 1.4 billion, which were
financed by banks, including commercial loans and debt issuance at capital
markets for an amount of US$ 900 million and capital contributions. The
original budget for investing in OCP amounted to US$ 1.2 billion. Due to the
restrictions on Petrobras Energía to make capital expenditures, Petrobras
Energía decided not to increase its ownership interest in increasing the
investments to US$ 1.4 billion. Therefore, the ownership interest decreased
from 15% to 8.96%. To secure compliance of the capital contribution commitments, and in its
capacity as shareholders, and with the corresponding OCPs financial
obligations and Petrobras Energía Ecuador commercial obligations, as of
December 31, 2003, Petrobras Energía placed letters of credit for a total
amount of about US$ 224 million. Through Petrobras Energía Ecuador, the Company operates blocks 18
(operating) and 31 (undeveloped, without proved reserves). In relation to the
exploitation of those blocks, Petrobras Energía Ecuador has executed a Ship or
Pay Transportation agreement with OCP, whereby an oil transportation capacity
of 80,000 barrels per day has been ensured for a 15-day term, as from November
10, 2003. Therefore, the Company should meet the contractual obligations for
the entire volume hired, rather than the crude oil transportation, paying, as
in the case of the other producers, a rate that covers the operating costs and
financial services of OCP, among others. Cost of transportation capacity are
billed by OCP monthly and charged to expenses as incurred. The Company estimates that during the term of the agreement there will be
successive shortages of crude oil carried due to several delays in developing
Block 31, the new term of the capital expenditures flow for the joint
development of blocks 18 and 31 and the new potentiality vision of Block 31. Consequently, as of December 31, 2003, Petrobras Energía has expensed 321 representing
impairment losses for its operations in Ecuador.
During fiscal year 2003, the company accrued losses for 309, primarily due to
the delays in block 31 developing, the increase in crude oil rate together with
the dilution of the equity interest in OCP from 15% to 8.96% and the
anticipation of the estimated date for the beginning of operations of the oil
pipeline. The book value of net assets in Ecuador, after computing the
referred allowance, does not exceed the recoverable value. The Company and Techint Internacional Construction Corp. (Tenco) signed an
agreement to exercise call and put options, whereby Tenco grants the Company
the irrevocable call option of shares and subordinated debt composing its 2.4%
equity interest, whereas the Company granted Tenco the irrevocable option to
require the purchase of shares and subordinated debt composing such equity
interest. Both options may be sold as from December 31, 2003, through December
31, 2004. The option price shall be determined in terms of the total amount
paid by Tenco, or on its behalf, plus accrued interest, considering for that
purpose that Tencos put option rate will be 7.5% per annum and the Companys
call option rate will be 18% per annum. See Note 26 for subsequent events to
December 31, 2003. 11. Pichi Picún Leufú Hydroelectric Complex (the Complex) The Company, through Petrobras Energía, has a thirty-year concession for
the generation of hydroelectric power in the Complex from August 1999. To ensure completion of works within the term of the concession and a
profitability to make the investment viable, the Energy Department granted the
Company the amount of 25, to be taken out of a Unified Fund created by section
37 of Law No. 24,065. For the purpose of determining whether or not such amount
should be repaid, a support price system was implemented for the electric power
to be generated by the Complex and sold on the Wholesale Electric Power Market. Such support price system will be applied over a ten-year term, which will
be divided into two consecutive five-year periods, as from December 1999. In
order to implement such system, an Annual Monomial Support Price (AMSP) was set
in the amounts of $/Kwh 0.021 and $/Kwh 0.023 for the first and second period,
respectively. In order to determine the amount to be reimbursed, every year of
the above mentioned term, the difference between the Annual Average Monomial
Price of the Complex bars generation, and the aforesaid AMSP, valued in terms
of the electric power generated by the Complex during such year will be
determined. F-35




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Owing to the depressed selling prices set for the energy generated by the
Complex, and the prices estimated for the remaining term of the initial
five-year period, and considering that the above support price system entails a
profitability reassurance to make the investment practicable, as of December
31, 2003, the Company accrued an income of 15 of which 3 were recognized in
income for year then ended. 12. Financing The detail of debt as of December 31, 2003 and 2002, is as follows: 2003
    
    2002Current
    
    Noncurrent
    
    Current
    
    NoncurrentFinancial institutions
    
    
    923
    
    
    
    293
    
    
    
    710
    
    
    
    212Notes
    
    
    2,214
    
    
    
    4,474
    
    
    
    712
    
    
    
    5,427Investment agreement with IFC
    
    
    61
    
    
    
    331
    
    
    
    65
    
    
    
    193Related companies (Note 18)
    
    
    6
    
    
    
    
    
    
    
    
    
    
    
    Payable for purchase of 10%
interest in Distrilec S.A.
    
    
    
    
    
    
    
    
    
    
    56
    
    
    
    2983,204
    
    
    
    5,098
    
    
    
    1,543
    
    
    
    6,130
 I. Financial debt refinancing In the course of 2002, Petrobras Energía was able to restructure
comprehensively a substantial portion of its financial debt. This allowed it
to align the principal amortization payments with the cash flows obtained
from its operations, resulting in a manageable time frame for payments. On June 10, 2002, Petrobras Energía made an offer to exchange four
series of new corporate bonds for four series of existing notes, whose
closing date was July 31, 2002. Based on the bids received by the holders of
corporate bonds, on August 1, 2002, Petrobras Energía issued Class F, G, H
and I notes, with a face value of US$ 845.2 million. Additionally, and in
line with the exchange offer conditions, Petrobras Energía simultaneously
paid US$ 70 million. As a result of the exchange offer, the remaining
outstanding amounts of corporate bonds swapped have been reduced to reflect
the amounts not exchanged. Subsequently, on October 4, 2002, Petrobras Energía issued Class J, K, L
and M notes for US$ 599.4 million and other medium-term credit instruments
for US$ 249.2 million, having simultaneously settled a debt of US$ 74
million. Credit instruments issued replace short-term letters of credit, which
cover the compliance with certain financial obligations related to hedge
agreements of crude oil prices and the investment in OCP. Long-term letters
of credit issued under this credit facility fall due annually, which may be
automatically extended to successive annual periods, with maturity dates in
December 2005, at the latest, for letters of credit related to crude oil
derivative agreements, and October 2007, for obligations related to OCP. In
case those letters of credit are not renewed on their related maturity dates,
they shall be disbursed, in which case they will constitute new loans granted
to the Company. F-36




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II. Petrobras Energías Global Programs of nonconvertible notes a) US$ 2.5 billion program The Regular Shareholders Meeting of Petrobras Energía held on April 8,
1998, approved the establishment of a global corporate bond program for up to a
maximum principal amount outstanding at any time of US$ 1 billion or its
equivalent in other currency. Later, the Regular and Special Shareholders
Meeting held on June 20, 2002, authorized the increase of the maximum program
amount outstanding at any time during the effectiveness of the program up to
US$ 2.5 billion or its equivalent in other currency. The Regular and Special Shareholders Meeting of Petrobras Energía held on
July 8, 2003, extended the term of the Petrobras Energía Medium-Term Corporate
Bonds Program for five years counted as from May 5, 2003, or the maximum term
that may be allowed under any new regulations that might become applicable in
the future. The establishment of the Program was authorized by Certificate No. 202,
dated May 4, 1998, and Certificate No. 290, dated July 3, 2002 and Certificate
No. 296 dated September 16, 2003, of the CNV. As of December 31, 2003, there remained outstanding the following
classes of corporate bonds under the medium-term global program:  
    
    Class B, for US$ 5 million, payable in a single installment in May,
2006, at a 9% fixed annual rate.  
    
    Class C, for US$ 220 million, with the last maturity in July 2005,
which will be amortized in quarterly installments as from 2004. Class C
notes shall accrue interest at LIBOR plus 2.50% for the first year,
2.75% for the second year, and 3% for the third and fourth years. As to
this transaction, the Company arranged an interest rate swap, fixing
the annual interest rate at 7.93%. Should the Argentine Government
impose restrictions on transfers of US dollars, the Company is entitled
to meet the payment obligations arising from this transaction by
delivering oil or a combination of US dollars and oil, at the Companys
choice. In the event of payment being made in oil, the volume
delivered to the holders of the securities shall be priced at the WTI
spot price at the time; the guaranteed minimum price for such oil is 15
US$/bbl, and the volume shall not exceed 18.5 million barrels over the
whole life of the agreement. Deutsche Bank AG London undertook, if
such conditions were verified, to buy such oil while guaranteeing
holders of the securities full repayment of the debt. In this
connection, the Company executed a conditional call option that will
trigger if and when the price of WTI drops below 15 US$/bbl. As
regards the Companys exposure to the price of WTI, the effect of the
above is economically and financially neutral.  
    
    Class F, for a face value of US$64.4 million maturing in August 2005, at a 7,875% annual rate.  
    
    Class G, for a face value of US$250 million maturing in January 2007 at a 9% annual rate.  
    
    Class H, for a face value of US$181.5 million maturing in May 2009, at a 9% annual rate.  
    
    Class I, for a face value of US$349.2 million maturing in July 2010, at a 8.125% annual rate.  
    
    Class K, for a face value of US$ 286.3 million, quarterly payable
as from January 2004 and with final maturity date in October 2007,
accruing interest at three month LIBOR per annum, plus 4%.  
    
    Class M, for a face value of US$ 181.8 million, quarterly payable
as from January 2004 and with final maturity date in October 2007,
accruing interest at three month LIBOR per annum, plus 4.75%.  
    
    Class N, for a face value of USD 97 million, with principal
amortized in two installments, the first  equivalent to 9.9099% of
face value  settled on the same day of issuance, January 24,2003, and
the remaining due in June 2011, accruing interest at six-month LIBOR
plus 1%.  
    
    Class O, for a face value of USD 15,3 million, with due in March
2004, accruing interest at 7.5%. F-37




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
    
    Class P, for a face value of USD 3.6 million, with due in March
2004, accruing interest at 8.5%.  
    
    Class Q, for a face value of US$ 3.98 million, with two principal
amortization installments: the first equivalent to 10% of the face
value settled on the same day of issuance, April 25, 2003, and the
remainder in April 2008, at an interest rate of 5.625%. As of December
31, 2003, the Company is carrying US$ 760,000 of such issuance in its
own portfolio.  
    
    Class R, for a face value of USD 100 million, with due in October
2013, accruing interest at 9.375%. b) US$1.2 billion program As of December 31, 2003, under the medium-term Global Program which date
for the issuance of new notes expired in June 1998, the following classes of
general unsecured notes were outstanding, ranking pari passu in right of
payment with all other unsecured and unsubordinated obligations of the
Company: - Fourth Series, for US$ 22.8 million, payable in a single installment
in January 2004, at a 9% fixed annual rate. - Sixth Series, for US$ 32.6 million, payable in a single installment
in July 2007, at a 8.125% fixed annual rate. The proceeds from all issuances, were used to refinance liabilities,
increase working capital, for capital expenditures of fixed assets located in
Argentina or capital contributions to affiliates. The obligations arising out of issuances, are disclosed net of the
issuance discounts to be accrued. The deferred cost for such issuances are
included in Prepaid expenses and interests within Other receivables account. III. Cross default covenants Class F, G, H, I, N, O, P, Q and R notes include cross default covenants,
whereby the Trustee, as instructed by the noteholders representing at least 25%
of the related outstanding capital, shall declare all the amounts owed due and
payable, if any debt of the Company or its significant subsidiaries is not
settled upon the maturity date, provided that those due and unpaid amounts
exceed the higher of US$ 25 million or 1% of Petrobras Energías shareholders
equity upon those maturities, and that the default has not been defeated or
cured within 30 days after the Company has been served notice of the default. Class K and M notes include cross default covenants, whereby the Trustee,
as instructed by the noteholders representing at least the majority of the
respective outstanding capital, shall declare all the amounts owed due and
payable, if any debt of the Company or its significant subsidiaries is not
settled upon the maturity date, provided that those due and unpaid amounts
exceed the higher of US$ 15 million or 1% of Petrobras Energías shareholders
equity upon those maturities. Class C notes issued under the US$2.5 billion program, as well as certain
loan agreements, include cross default covenants, whereby the Trustee or the
creditor bank, as appropriate, shall declare all the amounts owed as due and
payable, if any debt of the Company is not settled upon the maturity date,
provided that those due and unpaid amounts exceed the amount of US$ 10 million
or 1% of Petrobras Energías shareholders equity in relative terms, upon those
maturities. The remaining outstanding amount of the Fourth and Sixth Series and Class
B notes does not include cross default covenants, as unanimously decided by the
special meetings held by the noteholders of those series on July 10, 2002. F-38




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IV. Covenants In relation to the issuance of Class K and M notes and medium-term credit
instruments (the refinanced financial debt), while some portion of the debt
remains unpaid, the Company shall be subject to the compliance with a series of
restrictions and obligations, which include, among others, the following:  i)
    
    Restrictions on liens: Petrobras Energía shall not create, except for limited
number exceptions, any lien upon the whole or any part of its assets and
its current or future income, including any right to earn income, unless
it grants identical security interests to the refinanced financial debt.ii)
    
    Restrictions on the payment of dividends: Petrobras
Energía shall not distribute
cash dividends prior to December 31, 2004, in cash exceeding U$S
650,000. As an exception, Petrobras Energía could make a sole payment of
extraordinary dividends to its shareholders up to US$ 19 million, based
on whether Petrobras Participaciones allocates its share of distributed
dividends to settle Petrobras Participacioness payable to Petrobras
Energía. On July 8, 2003, Special and Regular Shareholders meeting
approved the payment of an extraordinary cash dividend for an amount
equivalent in pesos to the above mentioned amount. After this date, the
aggregate amount paid shall not exceed 50% of the excess cash (cash
provided by operating activities less aggregate capital expenditures
allowed, up to the amount of actual capital expenditures, less financial
debt repaid) for the immediately preceding fiscal year, less the
extraordinary dividends paid.iii)
    
    Restrictions on capital expenditures: Petrobras Energía shall not make any
capital expenditure, including the amount of debt incurred in relation
thereto, in excess of US$ 425 million in 2003, US$ 450 million in 2004,
US$ 425 million in 2005 and US$ 475 million in 2006 and 2007. These
limits shall be increased by: (i) proceeds from the sale of capital
assets, (ii) 50% of the excess cash for the prior fiscal year, (iii)
contributed capital for capital increases, subordinated debt and project
finance, and (iv) 50% of contributed capital for new debt issuance.
Otherwise, the aggregate dividends paid shall decrease the limit of
capital expenditures.iv)
    
    Restrictions on the incurrence of financial debt: Petrobras
Energía shall not
incur any financial debt as long as, after the estimation thereof, the
ratio of: (A) consolidated financial debt, and (B) consolidated EBITDA
(defined as gross profit less administrative, selling and exploration
expenses, plus depreciation and amortization, dividends and advisory
services collected) exceeds 3.5. The referred restriction shall be not
applicable to subordinated debt, debt resulting from the investment
project finance and that incurred to settle the existing debt.v)
    
    Restrictions on the ratio of consolidated financial debt (excluding
subordinated debt) and consolidated EBITDA: the ratio of both shall not
be greater than 4.5 in 2003, 3.5 in 2004 and 3 as from 2005 through
2007. For interim periods, the restriction will be weighted considering
the period of four consecutive quarters prior to the end of the quarter.vi)
    
    Restrictions on the ratio of EBITDA to Interest: the ratio between
both shall not be lower than 2.75 in 2003 and 3 as from 2004 through
2007. For interim periods, the restriction will be weighted considering
a period of four consecutive quarters prior to the end of the quarter.vii)
    
    Restrictions on the maturity date of the financial debt: at any time,
the short-term financial debt shall not exceed an amount equal to US$
650 million.viii)
    
    Export obligation: the exports  to  total principal services
(principal repayments, plus accrued interest) ratio for Series K shall
be higher than 1.1.ix)
    
    Mandatory financial debt redemption: Within a term that shall not
exceed 120 days as from fiscal year-end, the Company shall mandatorily
redeem on a pro rata basis a portion of the refinanced financial debt of
up to 50% of the excess cash during such fiscal year. Likewise,
proceeds from the sale of assets, excluding those that constitute the
business purpose, not reinvested within 360 days, and the 50% of the
cash proceeds from new debt, shall be used to prepay the refinanced
financial debt. F-39




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V. Financing of the Genelba Electric Power Generation Plant The investment was financed through debt granted by international banks,
which are being semiannually repaid from June 1998 over a period of 10 years.
They may be settled in advance at any time, at Petrobras Energías discretion,
and the remainder with the use of cash inflows. The debt may be prepaid at any
time at Petrobras Energías option. As of December 31, 2003, the amounts
outstanding from the financing of the plant were US$ 51 million, of which US$
20 million is related to a contract which contains restrictive covenants,
including restriction on selling or leasing more than 40% of the plant during
the year in which the debt is outstanding. VI. Loan from International Finance Corporation (IFC) to Innova S.A.
(Innova) In October 1999, Innova executed a long-term loan agreement for US$80
million comprising tranches A and B of US$20 million and US$60 million,
respectively. Amortization of principal will be as from June 2002, in 16 and 12
semiannually installments for tranches A and B, respectively. The originally
applicable interest rate is LIBOR plus 3.25%. The loan was secured by a mortgage on certain real property owned by
Innova. In addition, unless certain conditions indicated in the loan agreement
occur, Petrobras Energía guarantees its timely payment. The IFC financing was completed by issuing preferred stock in the amount
of US$5 million, fully paid-in during December 1999. Certain covenants in the agreement prescribe restrictions in relation to
dividends, investments in property, plant and equipment, restrictions upon the
transfer, sale or rental of an important part of the assets, incurring
long-term debt and providing mortgages. In addition, Petrobras Energía directly
or through its subsidiaries, is committed to retain a 51% participating
interest in Innovas common stock. The funds provided by the IFC were used to construct styrene and
polystyrene plants in the Brazilian State of Rio Grande do Sul. VII. Payable for purchase of 10% interest of Distrilec In June 1999, the Company, through its subsidiary Petrobras Bolivia
International S.A., or PBI, acquired a 10% interest in Distrilec for an amount
of US$ 101 million. The related payment was documented through a promissory
note issued by PBI and secured by Petrobras Energía for the benefit of Entergy,
with a maturity date in June 2002, at a 7% annual fixed rate. The note was
later transferred to a financial trust located in Argentina through a
securitized transaction, whereby bonds denominated in US dollars were issued
and placed among Argentine investors. Upon the promissory note maturity date, the Company and holders of trust
certificates represented contrary interpretations with respect to the
application to that debt of measures related to the conversion into pesos
(dedollarization) of payable obligations stated in foreign currencies issued
under the Public Emergency and Foreign Exchange System Reform Law. At the
request of the trustee, the Company started a mediation process to reach an
agreement that documents the debt payment. This agreement expired without
fulfilling its terms and conditions. In November 2002, PBI irrevocably transferred all its rights and duties by
virtue of the promissory note issuance to Petrobras Energía. Afterwards, on
January 8, 2003, Petrobras Energía launched a Class N corporate bonds swap
offer for a face value amounting up to US$ 101 million maturing in 2011, for
all and each of the debt securities, stating that such offer was not a waiver
or release from any of the Companys rights in favor of the conversion of the
abovementioned promissory note in Argentine pesos, or an acknowledgement or
acceptance of any claim against such conversion. F-40




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Petrobras Energía has received and accepted offers from debt security
holders equivalent to 96.0594% of their outstanding face value. To offset this,
and according to the conditions of the swap offer, the Company issued class N
corporate bonds amounting to a face value of US$ 97 million. Given that the
terms and conditions of the new debt instruments differ substantially form the
original as regards both maturity and financial expense, upon refinancing, the
Company recognized a new liability that has been measured in accounts on the
basis of the best estimate of the discounted value of total amount payable.
On such a basis, the original liability was reduced to US$ 77 million, giving
rise to a gain of 34. On April 16, 2003, the Company launched an offer to exchange every and all
trust debt securities that had not been entered into the previous exchange for
Class Q Corporate Bonds for an aggregate face value of up to US$ 4 million and
maturing in 2008. Due to the offers received, the Company issued Class Q for a
face value of US$ 3.98 million. As of December 31, 2003, the Company offset in its accounts the receivable
resulting from its holding of trust debt-securities against the payable
resulting from the promissory note issued by PBI, which amounted to about US$
100.24 million, considering that it has the financial capacity to settle it in
full. VIII. Distrilec Indebtedness Certain loan agreements entered into by Edesur S.A. contain
cross-default covenants, whereby creditor banks are entitled to declare all
amounts owed to be due and payable if any debt item is not paid when due and
the outstanding past due amounts exceed the respective stipulations in the
agreements. Some of the abovementioned agreements include cross-acceleration
covenants, whereby the creditor banks are entitled to declare all amounts owed
to be due and payable in the event of Edesur S.A. being subject to the
acceleration of any other debt in circumstances provided for in such
agreements. As of the date of issuance of these financial statements, the Company is
negotiating with creditor banks the refinancing and/or the manner of repayment
of certain short-term loans. Based on the results of other refinancings
obtained by Edesur S.A. during 2002, such companys financial statements have
been prepared assuming that it will reach agreements with its creditors
allowing it to avoid the default situations mentioned above. This assumption
remained unchanged for purposes of the proportional consolidation of Distrilec
S.A. IX. Loan agreement signed between Petrobras Energía Venezuela S.A. and the IFC In July 2003, Petrobras Energía Venezuela S.A., a wholly-owned subsidiary
of Petrobras Energía, executed loan agreements in the amount of US$ 105 million
with the International Finance Corporation. In December 2003, the first principal installment was disbursed in the
amount of USD 70 million. The loan is primarily composed of Tranche A for USD 80 million, maturing
in a term of eights years and a half, including one grace period, payable
semiannually and at an annual LIBO nominal rate + 4.75%, and Tranche C for USD
25 million, maturing in a term of 9 years and a half. These loans will be used in executing the investment plan related to the
development of the Companys oil reserves in Venezuela in the Acema, Mata, La
Concepción and Oritupano Leona areas. The Company believes that the IFC will disburse the financing remainder
during 2004. X. CIESA and TGS indebtedness As of December 31, 2003, CIESAs financial debt relates to the issuance of
corporate bonds with a par value of up to USD 220 million and with original
maturity in April 2002. F-41




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##### Table of Contents



In the wake of the new Argentine macroeconomic situation, as from the
enactment of Public Emergency Law (see Note 9.IV Situation of interests in
public utility companies ) ,CIESA did not pay the principal and the last
interest installment upon maturity and obligations under cap and collar
agreements. CIESAs Management is currently negotiating with the creditors to agree to
extend the term to fulfill the related payment. In relation to those
negotiations, CIESA has engaged an international prestigious financial advisor.
No pledges have been made by CIESAs shareholders to provide financial aid. On February 24, 2003, TGS started a global rescheduling process of USD
1,027 billion of its current financial indebtedness, which represents almost
the entire debt. This process is primarily intended to spread out the maturity
dates in the short term, change certain financial restrictions included in the
financial agreements and adjust the interest rate and amortization term, so as
to adjust the cash flows required for the debt repayment to the estimated cash
flows, without requiring debt principal reductions. Based on TGSs proposal to its creditors, the debt rescheduling agreement
would be implemented through the out-of-court composition agreement (APE),
recently introduced by Argentine laws, whereby the approval by two thirds of
the creditors should be required for the judges approval. As TGS could not
meet this required majority, on May 14, 2003, it withdrew the referred
rescheduling proposal and simultaneously announced the postponement of the
interest payment. As of the date of issuance of these financial statements, TGS continues to
negotiate with its main creditors in order to achieve the financial debt
rescheduling. In the wake of the withdrawal of the debt rescheduling proposal and the
postponement of the interest payment, TGSs indebtedness has been reclassified
as Short-term debt, since, according to the financial agreements executed
between TGS and its creditors, obligations may become due and payable. F-42




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##### Table of Contents



XI. Detail of long-term debt Long-term debt as of December 31, 2003, are made up as follows: Type
    
    Amount
    
    Currency
    
    Annual interest rateFinancial institutions
    
    
    43
    
    
    US$
    
    Libor+0.12528
    
    
    US$
    
    Libor+0.7534
    
    
    US$
    
    Libor+2.0023
    
    
    US$
    
    6.15%81
    
    
    US$
    
    Libor+5.7511
    
    
    US$
    
    Libor+3.517
    
    
    US$
    
    5.73%20
    
    
    US$
    
    4.68%24
    
    
    US$
    
    3.54%Investment agreement with IFC
    
    
    125
    
    
    US$
    
    Libor+3.25132
    
    
    US$
    
    Libor+5.7574
    
    
    US$
    
    Libor+1.50NotesClass B
    
    
    15
    
    
    US$
    
    9.00%Class C
    
    
    277
    
    
    US$
    
    Libor+2.50/3.00Class F
    
    
    190
    
    
    US$
    
    7.875%Serie Sixth
    
    
    96
    
    
    US$
    
    8.125%Class G
    
    
    735
    
    
    US$
    
    9.00%Class H
    
    
    534
    
    
    US$
    
    9.00%Class I
    
    
    1,027
    
    
    US$
    
    8.125%Class K
    
    
    656
    
    
    US$
    
    Libor+4Class M
    
    
    417
    
    
    US$
    
    Libor+4.75Class N
    
    
    227
    
    
    US$
    
    Libor+3Class Q
    
    
    11
    
    
    US$
    
    5.625%Class R
    
    
    294
    
    
    US$
    
    9.375%Other
    
    
    75,098
 (1) The maturities of long-term debt as of December 31, 2003 and 2002, are as
follows: 2003
    
    2002From 1 to 2 years
    
    
    1,055
    
    
    
    994From 2 to 3 years
    
    
    480
    
    
    
    1,051From 3 to 4 years
    
    
    1,283
    
    
    
    514From 4 to 5 years
    
    
    48
    
    
    
    1,447Over 5 years
    
    
    2,232
    
    
    
    2,1245,098
    
    
    
    6,130
 F-43




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##### Table of Contents



13.
    
    Income tax and deferred tax The Companys provision for income taxes was comprised of the following: 2003
    
    2002
    
    2001Current
    
    
    (48
    )
    
    
    (66
    )
    
    
    (268
    )Deferred tax  (loss) gain
    
    
    30
    
    
    
    (16
    )
    
    
    (117
    )Total income tax
    
    
    (18
    )
    
    
    (82
    )
    
    
    (385
    )
  The tax effect of the significant differences between the book value and the tax value of the
Companys assets and liabilities and tax loss carryforwards are as follows: 2003
    
    2002Deferred tax assetsTax loss carryforwards and
other tax losses
    
    
    1,898
    
    
    
    2,146Current investments
    
    
    6
    
    
    
    3Reserve for contingencies
    
    
    77
    
    
    
    30Pension plan obligations
    
    
    7
    
    
    
    7Derivatives
    
    
    216
    
    
    
    149Receivables
    
    
    10
    
    
    
    15Other
    
    
    66
    
    
    
    2Less-valuation allowance
    
    
    (1,786
    )
    
    
    (2,055
    )Deferred tax liabilityRevenue Recognition
    
    
    (33
    )
    
    
    (4
    )Current Investments
    
    
    (14
    )
    
    
    Property, plant and equipment
    
    
    (137
    )
    
    
    (155
    )Prepaid expenses
    
    
    (25
    )
    
    
    (32
    )Investories
    
    
    (16
    )
    
    
    (19
    )Discounted assets and liabilities
    
    
    (11
    )
    
    
    Non-current investments
    
    
    (124
    )
    
    
    (18
    )Other
    
    
    (12
    )
    
    
    (10
    )122
    
    
    
    59
 F-44




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##### Table of Contents



The reconciliation of tax provision at the statutory rate to the tax provision,
(before taxes) and the minority interest in the subsidiarys earnings (losses),
is as follows: 2003
    
    2002
    
    2001Income (losses) before income tax and minority
interests in the subsidiaries income (loss)
    
    
    557
    
    
    
    (1,525
    )
    
    
    598Statutory tax rate
    
    
    35
    %
    
    
    35
    %
    
    
    35
    %Statutory tax rate applied to income (loss) for the period
    
    
    195
    
    
    
    (534
    )
    
    
    209Permanent differences at income tax rate- Equity in (earnings) losses from noncurrent investments
    
    
    (59
    )
    
    
    85
    
    
    
    37- Inflation adjustment
    
    
    116
    
    
    
    (26
    )
    
    
    34- (Decrease) increase in allowances for tax loss carryforwards
    
    
    (525
    )
    
    
    1,176
    
    
    
    - Foreign (earnings) losses
    
    
    277
    
    
    
    (639
    )
    
    
    (66
    )- Tax on minimum presumed income
    
    
    
    
    
    
    19
    
    
    
    102- Other
    
    
    14
    
    
    
    1
    
    
    
    69Income tax expense
    
    
    18
    
    
    
    82
    
    
    
    385
 Tax loss carryforwards and deferred losses include the following items and may
be used through the dates indicated below: Items
    
    2003
    
    2002
    
    2001General Tax loss carryforwards
    
    
    1,691
    
    
    
    1,867
    
    
    
    324Deferred losses
    
    
    207
    
    
    
    279
    
    
    
    1,898
    
    
    
    2,146
    
    
    
    324
 Use up to
    
    2003
    
    2002
    
    20012004
    
    
    
    
    
    
    58
    
    
    
    82005
    
    
    15
    
    
    
    27
    
    
    
    92006
    
    
    43
    
    
    
    54
    
    
    
    112007
    
    
    52
    
    
    
    100
    
    
    
    402008 and thereafter
    
    
    1,788
    
    
    
    1,907
    
    
    
    2561,898
    
    
    
    2,146
    
    
    
    324
 F-45




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##### Table of Contents



14.
    
    Contingencies and environmental matters a) Petrobras Energía Stamp Tax Contingency In previous years, Petrobras Energía received inquiries from some
Argentine Provinces with the purpose of imposing stamp tax on instruments
which, under effective legislation, are not subject to such tax. These actions
are the consequence of a decision of the Supreme Court of the Province of
Neuquén dated October 2, 1996 (in the case SOLBA vs. the Province of Neuquén)
to the effect that an agreement that could be inferred from correspondence
exchanged between the parties that did not meet the taxability requirements
provided in the related Tax Code was, however, indeed subject to stamp tax. The
Federal Supreme Court rejected the case on the basis of Section 280 of the Code
of Procedures (considering there was no Federal issue involved or that the
issue did not merit its attention). In March and April 2001, the Federal Supreme Court changed its view and
accepted its jurisdiction to hear the declaratory judgment filed by TGS, as
described in c) below, whereby TGS expects the requests made by the Province of
Santa Cruz and Río Negro to apply stamp tax on the agreements reached by mail
and other acts related to the privatization process, to be considered
illegitimate and contrary to the Argentine Constitution. In July 2003, by virtue of the decision on the case Banco Río de la Plata
S.A. vs. Province of La Pampa, the Federal Supreme Court of Justice reasserted
the instrumentation requirement established by the Federal Revenue Sharing Law
in connection with the performance of acts, agreements and transactions levied
by stamp tax. On April 15, 2002, the Federal Supreme Court issued its judgment
regarding the declarative judgment requested by TGS, upholding the latter  ́s
position to he effect that the instruments that are autonomously executable are
not subject to the tax. Given that it is very recent, the Company is studying
consequences that such ruling will have on its operations. As of December 31, 2003, the estimated aggregate amount of claims,
including interest and fines, is 70. The Company keeps booking a provision for
the potential adverse effects of those claims amounting to 7. Setting an
allowance is a conservative measure adopted to comply with the applicable
accounting principles and, therefore, should not be considered as a recognition
of the claim made. b) Environmental matters The Company is subject to extensive environmental regulation at both the
federal and local levels in Argentina and in other countries in which it
operates. Petrobras Participaciones  ́s management believes that its current
operations are in material compliance with applicable environmental
requirements, as these are currently interpreted and enforced, including
sanitation commitments assumed. Petrobras Participaciones and its subsidiaries
have not incurred any material pollution liabilities as a result of their
operations to date. Petrobras Participaciones undertakes environmental impact
studies for new projects and investments and, to date, environmental
requirements and restrictions imposed on such new projects have not had
material adverse impact on Petrobras Participacioness business. There are no
significant lawsuits or administrative proceedings against the Company related
to environmental issues. The Companys management has produced policies, objectives and procedures
relating to environmental care and control. Through its policies, the Company
assumed the commitment to ensure product and service quality preserving the
environment in which it operates, the safety and health of its personnel,
contractor, and neighboring communities. Management believes that this policy
is an integral part of its business and, therefore, it forms the framework
within which each business area sets its annual objectives in this regard.
This policy ratifies the commitment to meeting the applicable laws and
implementing environmental management, quality, security, and occupational
health systems. The Company has over 90 Environment (ISO 14001), Quality (ISO 9001) and
Security & Occupational Health (OHSAS 18001/IRAM 3800) certifications. In view of this situation, the Company engaged an international consulting
firm to conduct the environmental audit of its operations pursuant to effective
laws, future requirements and, in light of the lack of local regulations, based
on international environmental standards. F-46




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##### Table of Contents



The final audit report confirmed the high environmental standards under
which the Companys operations are carried out and determined the necessary
actions to be taken to implement the Security, Environment and
Occupational Health Policy principles whereby the Company commits to
preserving the environment where it operates, as well as the security and
health of its personnel, contractors and neighboring communities. Being responsible therefore and as a result of an environmental study, the
Company will make investments of nearly USD 23 million in the coming years,
which include improvements of prevention systems and production facilities.
Additionally, several corrective and remediation actions will be taken, due to
incurred damages according to which the Company booked a loss of P$45 million
in the fiscal year ended December 31, 2003. c) TGS stamp tax TGS has received inquiries from the Provincial Tax Bureaus of the
Provinces of Neuquén, Río Negro, Santa Cruz and La Pampa, for an approximate
amount of 813 (including interests and penalties), with the purpose of
collecting stamp tax that, according to tax authorities, would be applicable to
the Share-Transfer Agreement executed in the privatization of Gas del Estado
(GdE) and the transportation services offers from TGS to its customers. TGS filed declarative actions with the Federal Supreme Court, seeking that
such court issue its opinion about the legitimacy of provincial claims and
requiring that provinces be ordered to refrain from conducting any actions
intended to collect the tax claimed until the Federal Supreme Court decides on
the merits of the case. In all the cases, the Federal Supreme Court granted the
precautionary measures requested by TGS. TGSs management considers that agreements predating takeover date were
not subject to provincial stamp tax as the parties to the agreement were stamp
tax exempt. Furthermore, TGSs management believes that even if the agreements
executed before takeover date had been subject to stamp tax, under the terms of
the Transfer Agreement such tax should be borne by GdE or the Argentine
government. As regards the remaining assessments, TGSs management is of the
opinion that offers to render transportation services are not subject to the
tax in question. TGS believes that, should it be determined that such offers
are taxable, this should be considered a change in interpretation of tax law
and, its impact should be reflected in the tariff according to regulations on
the subject. Ente Nacional Regulador del Gas (ENARGAS, the federal gas
regulatory agency) believes that the claims for stamp tax lack merit because it
considers the tax unlawful. d) Fixed charges for connection with Transener The ENRE authorized, by Resolution No. 1650/98, an increase in the
connection charge, in full compliance with effective rules and regulations.
Many generation companies filed administrative appeals before the Energy
Department seeking that such increase be reversed; the Energy Department
rejected such appeals. Only Central Térmica Güemes S.A. filed an appeal
directly with the Federal Administrative-Contentious Court of Appeals, which
decided in favor of the request. Transener and the ENRE filed an extraordinary
appeal before the Supreme Court of Justice of the Nation. On June 27, 2003,
the appellate court allowed the appeal before the Supreme Court. The case was
referred to the Supreme Court and is pending resolution. As reported by the legal counsel, Transener considers that the final
outcome of this issue will not give rise to any significant obligation.
Therefore, no provisions have been booked in this regard. e) Contractual commitments, warranty bond, suretyships and guarantees
granted The warranty bonds, suretyships and guarantees as of December 31, 2003,
which are not disclosed in the remaining notes, amount to 57. F-47




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##### Table of Contents



In addition, as of December 31, 2003, the Company had the following
contractual commitments: TotalUnits
    
    Total
    
    Until(In millionsof pesos)Purchase CommitmentsShip or pay agreement with OCP (in bbls/ day) (1)
    
    
    80,000
    
    
    
    3,298
    
    
    
    2018Long term service agreement (in millions of USD)
    
    
    47
    
    
    
    141
    
    
    
    2006Gas transportation agreement with TGS (in MMm3)
    
    
    11,873
    
    
    
    300
    
    
    
    2014Ethylene (in thousands of tons)
    
    
    337
    
    
    
    550
    
    
    
    2015Benzene (in thousands of tons)
    
    
    930
    
    
    
    1,233
    
    
    
    2015Sales commitmentsNatural gas (in MMm3)
    
    
    18,854
    
    
    
    
    
    
    
    2019Styrene (in thousands of tons)
    
    
    56
    
    
    
    
    
    
    
    2004Electric power (in MWh)
    
    
    329,115
    
    
    
    
    
    
    
    2004
  (1)
    
    Equivalent to about USD 200,000 per day. F-48




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##### Table of Contents



f) Reserves for contingencies The movements of reserves for contingencies were as follows: Balances at
    
    Net increase
    
    BalancesAccount
    
    beginning
    
    (decrease)
    
    at endDeducted from assets:CurrentFor investments (a)
    
    
    30
    
    
    
    (7
    )
    
    
    23For doubtful accounts
    
    
    27
    
    
    
    15
    
    
    
    42For other receivables
    
    
    72
    
    
    
    
    
    
    
    72Inventories obsolescence
    
    
    3
    
    
    
    1
    
    
    
    4132
    
    
    
    9
    
    
    
    141NoncurrentFor investments (a)
    
    
    68
    
    
    
    (58
    )
    
    
    10For property, plant & equipment (b)
    
    
    44
    
    
    
    18
    
    
    
    62Inventories obsolescence
    
    
    
    
    
    
    2
    
    
    
    2112
    
    
    
    (38
    )
    
    
    742003
    
    
    244
    
    
    
    (29
    )
    
    
    2152002
    
    
    208
    
    
    
    36
    
    
    
    244Included in liabilities:CurrentLabor and commercial contingencies
    
    
    28
    
    
    
    16
    
    
    
    4428
    
    
    
    16
    
    
    
    44NoncurrentLabor and commercial contingencies
    
    
    24
    
    
    
    51
    
    
    
    75Operations in Ecuador
    
    
    62
    
    
    
    140
    (c)
    
    
    20286
    
    
    
    191
    
    
    
    2772003
    
    
    114
    
    
    
    207
    
    
    
    3212002
    
    
    96
    
    
    
    18
    
    
    
    114
  a)
    
    See Note 9.IV and 10.b)
    
    See Note 10.c)
    
    Includes a charge for 2003 fiscal year in the amount of 269, a
transitory translation difference amounting to (10) and reclassification for
(119) to account payable  15.
    
    Contribution, benefit pension and stock option plans of Petrobras Energía a) Contribution and benefit pension plans  
    
    Defined contribution plan: The Company sponsors a defined contribution plan that applies to all
employees of Petrobras Energía with salaries above a specified level. Through
this plan, the Company matches contributions by employees which are in excess
of legally required amounts. Such contributions are charged to expenses in the
year they are paid. Due to the significant changes in the Argentine economic
scenario and the uncertainties posed by the Argentine economic conditions, as
from January 2002, Petrobras Energía has suspended, at the moment, this
benefit. Such benefit will be reestablished as soon as there is a social
security savings means considered adequate to such end.  
    
    Defined benefit pension plan: All employees of the Company, that take part without interruption in the
defined contribution plan, that have joined the Company prior to May 31, 1995,
and that qualify subject to certain years of service, are F-49




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##### Table of Contents



participants in this
plan. The employee benefit is based on the last computable salary and years of
service of the employee. The plan is of a supplemental nature, that is to say the benefit to the
employee is represented by the amount determined under the provisions of this
plan, after deducting benefits payable to the employee under the contribution
plan and the public retirement system, in order that the aggregate benefit to
each employee from the three plans equals the one stipulated in the plan. Once
retired, the employees are entitled to a fixed monthly payment. The plan calls for a contribution to a fund exclusively by the Company and
without any contribution by the employees, provided that they should make
contributions to the retirement system for their whole salary. Assets of the
fund were contributed to a trust and they are invested mainly in bonds,
corporate bonds, mutual funds, and certificates of deposits. The Bank of New
York is the trustee and Watson Wyatt is the managing agent. The Company
determines the liability related to this plan by applying actuarial calculation
methods. As of December 31, 2003, the most relevant actuarial information on
the defined-benefits pension plan is as follows: Plan assets
    
    
    47Projected benefit obligations
    
    
    (51
    )Position uncovered
    
    
    (4
    )Unrecognized actuarial gain
    
    
    (3
    )Net liability recognized
    
    
    (7
    )
 According to its By-laws, the Company contributes to the fund through a
contribution proposed to the Shareholders meeting by the Board of Directors
and can increase up to a maximum of 1.5% of the net income for the year. During
the years ended December 31, 2003, 2002, and 2001, the Board of Directors did
not make use of this power. Should there be an excess (duly certified by an independent actuary) of
the funds under the trust agreement to be used to settle the benefits granted
by the plan, the Company will be entitled to make a choice and use such excess,
in which case it would have to notify the trustee thereof. During the last quarter of 2002, Petrobras Energía admitted the advanced
collection of this plan by beneficiaries should they expressly state so. All
the individuals that exercised the abovementioned option before February 13,
2003, have lost their rights to collect their retirement supplement, thus they
are no longer plan beneficiaries. b) Stock option plan The Board of Directors of Petrobras Energía approved the application of a
long-term incentive program for the purpose of aligning the interests of
officers and shareholders. As part of this program, the Board of Directors of Petrobras Energía
approved the Plans for year 2001 (2001 Plan) and for year 2000 (2000 Plan),
focused on senior officers of Petrobras Energía. Both plans consist in granting
the right to exercise certain options to receive Petrobras Participaciones
shares or the cash equivalent at market, as described below: 2001 Plan  i.
    
    5,364,125 options to receive the value arising from the positive
difference between the average listed price of Petrobras Participaciones
shares on the New York Stock Exchange during the 20 days prior to
exercising the option and 1.64 Argentine pesos per share, for such
number of shares (appreciation rights). F-50




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##### Table of Contents



Regarding these options, 1,609,237 options may be exercised as from March
5, 2002, 1,609,238 options may be exercised as from March 5, 2003, and
2,145,650 options as from March 5, 2004. As of December 31, 2003 and
March 31, 2004 the exercised options amount to 967,152 and 2,834,550,
respectively.ii.
    
    596,014 options to receive the same number of shares at no cost for
the beneficiary. These options may be exercised as from March 5, 2005
(full value).Beneficiaries of this plan will be entitled to exercise their rights
until March 5, 2007, from the dates mentioned above. 2000 Plan  i.
    
    3,171,137 options to receive the value arising from the positive
difference between the average listed price of Petrobras Participaciones
shares on the New York Stock Exchange during the 20 days
prior to exercising the option and 1.48 Argentine pesos per share, for
such number of shares (appreciation rights).Regarding these options, 951,341 options may be exercised as from May 29,
2001, 951,341 options may be exercised as from May 29, 2002, and
1,268,455 options as from May 29, 2003. As of December 31, 2003 and
March 31, 2004, the exercised options amount to 1,232,692 and
2,275,589, respectively.ii.
    
    352,347 options to receive the same number of shares at no cost for
the beneficiary. These options may be exercised as from May 29, 2004
(full value).Beneficiaries of this plan will be entitled to exercise their rights
until May 29, 2006, from the dates mentioned above. The cost of such benefit is allocated on proportional basis to each year
within the exercise years and adjusted in accordance with the listed price of
the share. Accordingly, an amount of 8 was charged to operating expenses for
year ended December 31, 2003. 16. Capital stock and restrictions on unappropriated retained earnings As of December 31, 2003 the Companys capital stock totaled 2,132 fully
subscribed, issued, paid-in and registered. Changes in capital stock in the last three fiscal years: December, 312003
    
    2002
    
    2001Common stock  face value
    
    $
    1
    
    
    
    1
    
    
    
    1Class A: 5 votes per share
    
    
    
    
    
    
    
    
    
    
    628Class B: 1 vote per share
    
    
    2,132
    
    
    
    2,132
    
    
    
    1,5042,132
    
    
    
    2,132
    
    
    
    2,132
 Since January 26, 2000, the Company Class B shares are listed on the
Buenos Aires Stock Exchange and on the New York Stock Exchange. Based on the change in the interest control described in Note 21, on
October 17, 2002, the BCBA (Buenos Aires Stock Exchange) authorized the
conversion of class A common shares into the same number of class B common
shares and their admission into the listing system. In addition, the CNV
approved their public offer. F-51




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##### Table of Contents



17.
    
    Other receivables, other liabilities, other exploitation income, and other
expenses, net. 2003
    
    2002Current
    
    Noncurrent
    
    Current
    
    Noncurrenta) Other receivablesJoint ventures
    
    
    53
    
    
    
    
    
    
    
    74
    
    
    
    Related companies (Note 18)
    
    
    3
    
    
    
    
    
    
    
    4
    
    
    
    Tax credits
    
    
    287
    
    
    
    73
    
    
    
    251
    
    
    
    116Advisory services to other companies
    
    
    40
    
    
    
    
    
    
    
    30
    
    
    
    Receivables from the sale of companies
    
    
    89
    
    
    
    16
    
    
    
    3
    
    
    
    25Premiums and derivatives collateral payments
    
    
    
    
    
    
    
    
    
    
    30
    
    
    
    11Letters of credit advances
    
    
    175
    
    
    
    
    
    
    
    143
    
    
    
    Prepaid expenses and interest
    
    
    66
    
    
    
    22
    
    
    
    83
    
    
    
    50Gas oil supply stability agreement
    
    
    
    
    
    
    
    
    
    
    12
    
    
    
    Other collaterals
    
    
    23
    
    
    
    
    
    
    
    
    
    
    
    Other
    
    
    125
    
    
    
    20
    
    
    
    104
    
    
    
    18861
    
    
    
    131
    
    
    
    734
    
    
    
    220
 2003
    
    2002Current
    
    Noncurrent
    
    Current
    
    Noncurrentb) Other liabilitiesSale of capital fees (1)
    
    
    107
    
    
    
    
    
    
    
    126
    
    
    
    122Debt for investments in companies
    
    
    16
    
    
    
    
    
    
    
    
    
    
    
    Derivatives
    
    
    102
    
    
    
    98
    
    
    
    
    
    
    
    268Unified Fund  Basic Price of Electric Power (Note 11)
    
    
    5
    
    
    
    5
    
    
    
    
    
    
    
    13Related companies (Note 18)
    
    
    
    
    
    
    
    
    
    
    48
    
    
    
    Financial advances
    
    
    34
    
    
    
    
    
    
    
    34
    
    
    
    Accrual for expenses- Environmental remediation
    
    
    
    
    
    
    66
    
    
    
    
    
    
    
    18- Other
    
    
    52
    
    
    
    
    
    
    
    71
    
    
    
    Innova preferred stock
    
    
    
    
    
    
    17
    
    
    
    
    
    
    
    17Abandonment cost in oil & gas areas
    
    
    
    
    
    
    73
    
    
    
    
    
    
    
    57Joint ventures
    
    
    7
    
    
    
    
    
    
    
    16
    
    
    
    Other
    
    
    56
    
    
    
    3
    
    
    
    49
    
    
    
    1379
    
    
    
    262
    
    
    
    344
    
    
    
    496
  (1)
    
    In December 2001, the Company, through its subsidiaries Petrobras Energía
Venezuela S.A. and Corod Producción S.A., assigned to an international
lending institution a part of the capital fees (related to investments
made by such companies) to be collected from PDVSA, as provided by the
Oritupano Leona Consortium Service Agreement (see Note 6), in the amount
of US$ 120 million. Capital fees assigned are settled by PDVSA in twelve
quarterly, equal, and consecutive installments starting February 2002.
This transaction was made net of the discount made at LIBOR plus 2.75%. In
order to guarantee the lending institution that PDVSA will meet the
obligations under this agreement, the Company assigned an additional part
of the capital fees to be collected from PDVSA in the amount of US$ 10
million. Should PDVSA not settle any amount payable on this account by the
due-date, exclusively in the event that such noncompliance stems from any
commercial challenge or claim that such company may have with respect to
billings for investments made, the Company may choose to assign the
lending institution additional capital fees in an amount equivalent to
that challenged, or else it may settle the payable in cash. This
assignment does not release Consortium members from the obligations under
the previously mentioned service agreement. F-52




---



##### Table of Contents



2003
    
    2002
    
    2001c) Other exploitation (expenses) income, netAdvisory services to other companies
    
    
    36
    
    
    
    37
    
    
    
    57Idle facilities
    
    
    (7
    )
    
    
    (10
    )
    
    
    (11
    )Environmental remediation expenses
    
    
    (58
    )
    
    
    (15
    )
    
    
    Taxes on bank transactions
    
    
    (45
    )
    
    
    (37
    )
    
    
    (15
    )Contingencies
    
    
    (57
    )
    
    
    
    
    
    
    Other, net
    
    
    10
    
    
    
    (3
    )
    
    
    (8
    )(121
    )
    
    
    (28
    )
    
    
    23
 2003
    
    2002
    
    2001d) Other expenses, netIncome (loss) from sale of:- Pecom Agra S.A.
    
    
    
    
    
    
    81
    
    
    
    - Pecom Agropecuaria S.A.
    
    
    
    
    
    
    27
    
    
    
    - Cerro Vanguardia S.A.
    
    
    
    
    
    
    123
    
    
    
    - Catriel Oeste field
    
    
    (28
    )
    
    
    
    
    
    
    - Faro Vírgenes field
    
    
    (11
    )
    
    
    
    
    
    
    - San Carlos field
    
    
    
    
    
    
    (37
    )
    
    
    - Forestry activity
    
    
    12
    
    
    
    (153
    )
    
    
    - Pampa del Castillo  La Guitarra and Terminales MaritimasPatagónicas S.A.
    
    
    
    
    
    
    
    
    
    
    (65
    )- Other assets
    
    
    
    
    
    
    (5
    )
    
    
    Asset impairment of:- Operations
in Ecuador
    
    
    (309
    )
    
    
    (63
    )
    
    
    - Gas producing areas
    
    
    (37
    )
    
    
    (44
    )
    
    
    - Hidroneuquén S.A.
    
    
    
    
    
    
    (10
    )
    
    
    - Impairment of allocated purchased price related to CIESA
    
    
    
    
    
    
    
    
    
    
    (202
    )- Other assets
    
    
    (12
    )
    
    
    (8
    )
    
    
    (15
    )Projects
    
    
    
    
    
    
    (5
    )
    
    
    (4
    )Loans granted to exploitation partners in Venezuela
    
    
    (27
    )
    
    
    (42
    )
    
    
    Debt restructuring
    
    
    
    
    
    
    (17
    )
    
    
    Income from assetts exchange
    
    
    
    
    
    
    
    
    
    
    251Discounted values for assets and liabilities
    
    
    17
    
    
    
    
    
    
    
    Reversal of provision for TGS rates increase
    
    
    
    
    
    
    
    
    
    
    (64
    )Other, net
    
    
    (26
    )
    
    
    (34
    )
    
    
    11(421
    )
    
    
    (187
    )
    
    
    (88
    )
 F-53




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##### Table of Contents



18.
    
    Balances and transactions with related companies The outstanding balances from transactions with related companies are as
follows: 2003Current
    
    NoncurrentTrade
    
    Other
    
    Accounts
    
    
    
    
    
    Advances toCompany
    
    receivables
    
    receivables
    
    payable
    
    Loans
    
    InvestmentsOleoductos del Valle S.A.
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    Petroquímica Cuyo S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6
    
    
    
    Oleoductos de Crudos Pesados Ltd.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    127EG3 S.A.
    
    
    55
    
    
    
    
    
    
    
    2
    
    
    
    
    
    
    
    Transportadora de Gas del Sur S.A.
    
    
    9
    
    
    
    
    
    
    
    4
    
    
    
    
    
    
    
    Refinería del Norte S.A.
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    Petrobras Petroleo Brasileiro S.A.
    
    
    10
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    74
    
    
    
    3
    
    
    
    7
    
    
    
    6
    
    
    
    127
 2002CurrentTrade
    
    Other
    
    Accounts
    
    OtherCompany
    
    Investments
    
    receivables
    
    receivables
    
    payable
    
    liabilitiesEmpresa Boliviana de Refinación S.A.
    
    
    19
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Oleoductos del Valle S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    Petroquímica Cuyo S.A.
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    
    
    
    
    Petrobras Petroleo Brasileiro S.A.
    
    
    
    
    
    
    17
    
    
    
    
    
    
    
    
    
    
    
    Transportadora de Gas del Sur S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    Refinería del Norte S.A.
    
    
    
    
    
    
    1
    
    
    
    2
    
    
    
    4
    
    
    
    Coroil S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    48Total
    
    
    19
    
    
    
    19
    
    
    
    4
    
    
    
    10
    
    
    
    48
 The principal transactions with affiliates for the years ended
December 31, 2003, 2002 and 2001, were as follows: 2003
    
    2002
    
    2001Company
    
    Purchases
    
    Sales
    
    Purchases
    
    Sales
    
    Purchases
    
    SalesOleoductos del Valle S.A.
    
    
    17
    
    
    
    
    
    
    
    14
    
    
    
    
    
    
    
    20
    
    
    
    Transportadora de Gas del Sur S.A.
    
    
    13
    
    
    
    
    
    
    
    48
    
    
    
    
    
    
    
    106
    
    
    
    Refinería del Norte S.A.
    
    
    55
    
    
    
    1
    
    
    
    60
    
    
    
    
    
    
    
    37
    
    
    
    Petrobras Petroleo Brasileiro S.A.
    
    
    
    
    
    
    149
    
    
    
    
    
    
    
    79
    
    
    
    
    
    
    
    EG3 S.A.
    
    
    26
    
    
    
    196
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    Petroquímica Cuyo S.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    5
    
    
    
    
    
    
    
    9Petrolera Entre Lomas S.A.
    
    
    
    
    
    
    
    
    
    
    22
    
    
    
    
    
    
    
    
    
    
    
    Total
    
    
    111
    
    
    
    346
    
    
    
    144
    
    
    
    85
    
    
    
    163
    
    
    
    9
 In addition, losses on derivatives for the crude oil price hedge made
with Petrobras International Finance Co. (PIFCO) amounted 12.  19.
    
    Business segment and geographic consolidated information Petrobras Participacioness business is mainly concentrated in the
energy sector, especially through its activities in oil and gas exploration
and production, hydrocarbons marketing and transportation, refining,
petrochemicals and electricity. The Oil and Gas Exploration and Production segment is composed of
Petrobras Energías directly held oil and gas operations and the operations
of some of its subsidiaries and affiliates. F-54




---



##### Table of Contents



The Refining segment includes Petrobras Energías operations in Refinería
San Lorenzo, and its interests in Refinería del Norte S.A. and Empresa
Boliviana de Refinación S.A. The Petrochemical segment includes Petrobras Energías operations in PASA,
and its interests in Innova S.A. and Petroquímica Cuyo S.A. The Hydrocarbons Marketing and Transportation segment includes Petrobras
Energía  ́s operations of hydrocarbons trading and liquids processing and its
interest in Transportadora de Gas del Sur S.A., Oleoductos del Valle S.A. and
Oleoducto de Crudos Pesados Ltd. The Electricity segment includes Petrobras Energía  ́s operations in the
Genelba plant and Pichi Picún Leufú Hydroelectric Complex, and its interest in
Conuar S.A. (See Note 9.III), Edesur S.A., Transener S.A., Enecor S.A., Yacylec
S.A. and Hidroneuquén S.A. Assets and results of operations related to the Corporate Structure, those
not attributable to any given business segment, discontinued operations 
including mining, farming, and forestry and related activities and intercompany
eliminations are all disclosed together. The applicable valuation methods to report business segment information
are those described in Note 4 to these financial statements. The transfer
prices of inter-segment transactions are the respective market prices. The following information shows total assets, total liabilities and net
income (loss) for each of the business segments identified by Petrobras
Participacioness management: Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    Marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalTotal assets 2003
    
    
    7,809
    
    
    
    642
    
    
    
    1,100
    
    
    
    3,096
    
    
    
    2,461
    
    
    
    1,030
    
    
    
    16,138Total liabilities 2003
    
    
    3,742
    
    
    
    179
    
    
    
    361
    
    
    
    2,078
    
    
    
    592
    
    
    
    3,461
    
    
    
    10,413Total assets 2002
    
    
    8,764
    
    
    
    592
    
    
    
    1,280
    
    
    
    258
    
    
    
    2,581
    
    
    
    1,174
    
    
    
    14,649Total liabilities 2002
    
    
    4,577
    
    
    
    192
    
    
    
    688
    
    
    
    
    
    
    
    798
    
    
    
    3,386
    
    
    
    9,641
 F-55




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##### Table of Contents



2003Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    Marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalStatement of incomeNet salesTo third parties
    
    
    1,785
    
    
    
    1,231
    
    
    
    1,294
    
    
    
    502
    
    
    
    680
    
    
    
    2
    
    
    
    5,494Inter-segment
    
    
    944
    
    
    
    71
    
    
    
    
    
    
    
    19
    
    
    
    11
    
    
    
    (1,045
    )
    
    
    2,729
    
    
    
    1302
    
    
    
    1294
    
    
    
    521
    
    
    
    691
    
    
    
    (1,043
    )
    
    
    5,494Cost of sales
    
    
    (1,448
    )
    
    
    (1,179
    )
    
    
    (982
    )
    
    
    (281
    )
    
    
    (523
    )
    
    
    1,027
    
    
    
    (3,386
    )Gross profit
    
    
    1,281
    
    
    
    123
    
    
    
    312
    
    
    
    240
    
    
    
    168
    
    
    
    (16
    )
    
    
    2,108Administative and selling expenses
    
    
    (178
    )
    
    
    (57
    )
    
    
    (110
    )
    
    
    (34
    )
    
    
    (73
    )
    
    
    (107
    )
    
    
    (559
    )Exploration expenses
    
    
    (196
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (196
    )Other exploitation income (expense), net
    
    
    (46
    )
    
    
    (12
    )
    
    
    (17
    )
    
    
    (1
    )
    
    
    17
    
    
    
    (62
    )
    
    
    (121
    )Exploitation income (loss)
    
    
    861
    
    
    
    54
    
    
    
    185
    
    
    
    205
    
    
    
    112
    
    
    
    (185
    )
    
    
    1,232Equity earnings of affiliates
    
    
    19
    
    
    
    22
    
    
    
    16
    
    
    
    16
    
    
    
    90
    
    
    
    
    
    
    
    163Other income (expense)
    
    
    (943
    )
    
    
    10
    
    
    
    (39
    )
    
    
    26
    
    
    
    (19
    )
    
    
    (49
    )
    
    
    (1,014
    )Net income (loss)
    
    
    (63
    )
    
    
    86
    
    
    
    162
    
    
    
    247
    
    
    
    183
    
    
    
    (234
    )
    
    
    381
 2002Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    Marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalStatement of incomeNet salesTo third parties
    
    
    2,033
    
    
    
    942
    
    
    
    1,254
    
    
    
    16
    
    
    
    755
    
    
    
    106
    
    
    
    5,106Inter-segment
    
    
    773
    
    
    
    66
    
    
    
    
    
    
    
    
    
    
    
    11
    
    
    
    (850
    )
    
    
    2,806
    
    
    
    1008
    
    
    
    1254
    
    
    
    16
    
    
    
    766
    
    
    
    (744
    )
    
    
    5,106Cost of sales
    
    
    (1,600
    )
    
    
    (944
    )
    
    
    (892
    )
    
    
    (11
    )
    
    
    (608
    )
    
    
    771
    
    
    
    (3,284
    )Gross profit
    
    
    1,206
    
    
    
    64
    
    
    
    362
    
    
    
    5
    
    
    
    158
    
    
    
    27
    
    
    
    1,822Administative and selling expenses
    
    
    (224
    )
    
    
    (48
    )
    
    
    (122
    )
    
    
    (2
    )
    
    
    (92
    )
    
    
    (121
    )
    
    
    (609
    )Exploration expenses
    
    
    (58
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (58
    )Other exploitation income (expense), net
    
    
    (22
    )
    
    
    (16
    )
    
    
    11
    
    
    
    13
    
    
    
    23
    
    
    
    (37
    )
    
    
    (28
    )Exploitation income (loss)
    
    
    902
    
    
    
    
    
    
    
    251
    
    
    
    16
    
    
    
    89
    
    
    
    (131
    )
    
    
    1,127Equity earnings (losses) of affiliates
    
    
    2
    
    
    
    20
    
    
    
    (10
    )
    
    
    (470
    )
    
    
    (239
    )
    
    
    59
    
    
    
    (638
    )Other income (expense)
    
    
    447
    
    
    
    190
    
    
    
    190
    
    
    
    
    
    
    
    271
    
    
    
    (3,166
    )
    
    
    (2,068
    )Net income (loss)
    
    
    1,351
    
    
    
    210
    
    
    
    431
    
    
    
    (454
    )
    
    
    121
    
    
    
    (3,238
    )
    
    
    (1,579
    )
 F-56




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##### Table of Contents



2001Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    Marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalStatement of incomeNet salesTo third parties
    
    
    1,502
    
    
    
    788
    
    
    
    809
    
    
    
    695
    
    
    
    1,248
    
    
    
    128
    
    
    
    5,170Inter-segment
    
    
    473
    
    
    
    
    
    
    
    9
    
    
    
    
    
    
    
    38
    
    
    
    (520
    )
    
    
    1,975
    
    
    
    788
    
    
    
    818
    
    
    
    695
    
    
    
    1286
    
    
    
    (392
    )
    
    
    5,170Cost of sales
    
    
    (1,188
    )
    
    
    (711
    )
    
    
    (666
    )
    
    
    (297
    )
    
    
    (906
    )
    
    
    421
    
    
    
    (3,347
    )Gross profit
    
    
    787
    
    
    
    77
    
    
    
    152
    
    
    
    398
    
    
    
    380
    
    
    
    29
    
    
    
    1,823Administative and selling expenses
    
    
    (167
    )
    
    
    (59
    )
    
    
    (95
    )
    
    
    (37
    )
    
    
    (137
    )
    
    
    (170
    )
    
    
    (665
    )Exploration expenses
    
    
    (41
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (41
    )Other exploitation income (expense), net
    
    
    (4
    )
    
    
    (13
    )
    
    
    2
    
    
    
    17
    
    
    
    44
    
    
    
    (23
    )
    
    
    23Exploitation income (loss)
    
    
    575
    
    
    
    5
    
    
    
    59
    
    
    
    378
    
    
    
    287
    
    
    
    (164
    )
    
    
    1,140Equity earnings of affiliates
    
    
    6
    
    
    
    14
    
    
    
    4
    
    
    
    26
    
    
    
    24
    
    
    
    45
    
    
    
    119Other income (expense)
    
    
    34
    
    
    
    (7
    )
    
    
    (53
    )
    
    
    (511
    )
    
    
    (179
    )
    
    
    (442
    )
    
    
    (1,158
    )Net income (loss)
    
    
    615
    
    
    
    12
    
    
    
    10
    
    
    
    (107
    )
    
    
    132
    
    
    
    (561
    )
    
    
    101
 The following information shows total assets and net sales by geographic area. 2003Argentina
    
    Venezuela
    
    Bolivia
    
    Perú
    
    Brazil
    
    Ecuador
    
    Other
    
    Eliminations
    
    TotalTotal assets
    
    
    10,269
    
    
    
    3,544
    
    
    
    461
    
    
    
    678
    
    
    
    547
    
    
    
    586
    
    
    
    53
    
    
    
    
    
    
    
    16,138Net sales
    
    
    3,804
    
    
    
    594
    
    
    
    108
    
    
    
    374
    
    
    
    502
    
    
    
    115
    
    
    
    2
    
    
    
    (5
    )
    
    
    5,494
 2002Argentina
    
    Venezuela
    
    Bolivia
    
    Perú
    
    Brazil
    
    Ecuador
    
    Other
    
    Eliminations
    
    TotalTotal assets
    
    
    7,744
    
    
    
    3,886
    
    
    
    379
    
    
    
    908
    
    
    
    722
    
    
    
    751
    
    
    
    259
    
    
    
    
    
    
    
    14,649Net sales
    
    
    3,368
    
    
    
    700
    
    
    
    112
    
    
    
    359
    
    
    
    561
    
    
    
    28
    
    
    
    3
    
    
    
    (25
    )
    
    
    5,106
 2001Argentina
    
    Venezuela
    
    Bolivia
    
    Perú
    
    Brazil
    
    Ecuador
    
    Other
    
    Eliminations
    
    TotalNet sales
    
    
    4,122
    
    
    
    489
    
    
    
    84
    
    
    
    182
    
    
    
    297
    
    
    
    
    
    
    
    
    
    
    
    (4
    )
    
    
    5,170
  20.
    
    Argentines economic situation Argentina is under a serious economic situation that is mainly
characterized by the high foreign debt level, a financial system in crisis, a
country risk that reached unprecedented international levels and an economic
recession. This situation has generated a major fall in product and service
demand, a significant increase in unemployment levels, and has hampered the
Argentine Governments ability to meet its obligations thus declaring the
default on public debt services at the end of 2001. F-57




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In order to address the crisis in which Argentina is enmeshed by, since
December 2001, Argentine authorities implemented a number of monetary and
exchange control measures that mainly included restrictions on the free
disposition of funds deposited with banks and the practical impossibility of
making transfers abroad, with the exception of transfers related to foreign
trade and other authorized transactions subject, in some cases, to the previous
authorization of the Central Bank of Argentina (BCRA). The obligation was established to deposit with Argentine banks foreign
currency arising from exports, as long as no prior exemption mechanisms were in
place. In this regard, Executive Decree No. 1,589/89 establishes that producers
with free availability of crude oil, natural gas and/or liquefied gases under
the terms of Law No. 17,319 and supplementary executive orders, and produces
who agree so in the future, shall have the free availability of the percentage
of funds established by the bids and/or renegotiations, or provided in the
respective agreements, in which case they shall not be required to pay and
settle the funds related to that percentage. In all cases, the freely
available maximum percentage of funds shall not exceed 70% of each transaction.
No assurance can be given whether the government will not amend the above
mentioned system in the future. Later, the Federal Government declared the official default on foreign
debt payments and, on January 6, 2002, the Argentine Congress approved Law No.
25,561 on Public Emergency and Exchange System Reform that introduced dramatic
changes to the economic model implemented until that date which resulted in a
significant devaluation of the peso with the ensuing rise in domestic prices. The government measures included the switch into pesos of certain assets
and liabilities denominated in foreign currency and held in Argentina and the
rescheduling of bank deposits, subsequently enabling the option to convert
deposits into ten-year bonds in US dollars, or three- or five-year bonds in
pesos, of fixed-term bills; the issuance of Federal Treasury bonds to
compensate the losses resulting from the asymmetrical switch into pesos of the
receivables and payables mentioned above; the switch into pesos of all private
agreements executed before January
6, 2002, at the exchange rate of US$ 1 = ARS 1 and their subsequent indexation
by the CER; the de-dollarization and elimination of indexation on public
utility service rates, with rates remaining set at the exchange rate of US$ 1 =
ARS 1; and imposing duties on the export of oil and gas and their derivatives. On March 5, 2003, the Supreme Court declared that the conversion of
deposits denominated in U.S. dollars into Argentine pesos was not
constitutional. The Supreme Court authorized the claim of the Province of San
Luis to redollarize its deposits. Although this decision does not generalize
the redollarization, it constitutes an important background for the remaining
bank deposits converted into pesos, regarding the treatment of the rest of the
actions initiated in connection with de-dollarized bank deposits. Since 2002, the Argentine federal government has implemented several
measures relaxing controls and restrictions on economic activity and fostering
the gradual normalization of the foreign exchange market and commercial and
financial flows. In this respect the measures included lifting the restrictions
on demand deposits, relaxing restrictions on principal and interest payments to
foreign creditors, increased latitude in the payment terms for capital goods
exports and imports, easier access to foreign exchange markets by entities and
individuals, and authorization for authorized foreign-exchange dealers to
channel remittances abroad of earnings and dividends from fiscal years closed
and with financial statements certified by external auditors. On September 22, 2003, the Argentine government submitted to the
bondholders a rescheduling plan related to Argentine bonds in default. By
virtue of such plan, the Argentine bonds issued prior to December 31, 2001,
would be eligible (eligible debt) for the proposed swap of bonds, maintaining
a strict equity principle among all types and classes of creditors. The
interest past due as from the default that took place in early 2002 would not
be paid and the debt principal would be reduced by 75%. Negotiations are
likely to be complicated as a result of the large number of creditors holding
over 100 different bonds denominated in different currencies. The governments
main objective is to restore the solvency by improving the debt to GDP and debt
service to tax revenues ratios in order to establish a new debt profile
consistent with the Argentine payment ability. These financial statements comprise the effects deriving from the
new political, economic and foreign exchange regulations known as of
their date of issuance. All the Companys Management estimations have
been made considering such policies. The impact deriving from the
additional measures to be implemented by Government and from putting
those previously adopted in practice shall be booked once the Companys
Management becomes aware of them. F-58




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21.
    
    Controlling Group On October 17, 2002, Petrobras Participacoes, S.L., a wholly-owned
subsidiary of Petróleo Brasileiro S.A.  PETROBRAS (Petrobras), acquired
58.6% of Petrobras Participacioness capital stock from the Perez Companc
Family and Fundación Perez Companc. Petrobras is a Brazilian company, whose
business is concentrated on exploration, production, refining, sale and
transportation of oil and its byproducts in Brazil and abroad.  22.
    
    Summary of significant differences between accounting principles followed
by the Company and US GAAP The Companys financial statements have been prepared in conformity
with Argentine GAAP, which differ in certain respects from US GAAP. The
differences are reflected in the amounts provided in Note 23 and relate
to the items discussed in the following paragraphs. As explained in Note
3, several accounting changes were made in the year ended December 31,
2003 under Argentine GAAP on retroactive basis. As a result of such
retroactive changes, the following discussions and the reconciliations,
and other information presented in Note 23 and 24, were restated
accordingly for figures corresponding to prior years under Argentine
GAAP. a) Restatements of financial statements for general price-level changes Prior to September 1, 1995, Argentine GAAP required the restatement of
non-monetary assets and liabilities into constant Argentine pesos as of the
date of the financial statements. Effective September 1, 1995, the CNV passed
General Resolution No. 272 which provided that public companies would no
longer be permitted to present financial statements that were adjusted to
recognize the effect of inflation prevailing after such date. Therefore for
periods ending subsequent to September 1, 1995, and until December 31, 2001,
there had been no further restatement of non-monetary items or recognition of
monetary gains and losses. This resolution matched Argentine GAAP so long as
the change in the price index applicable to the restatement did not exceed 8%
per annum. Due to the new inflationary environment in Argentina in 2002, and the
conditions created by the Public Emergency Law, the Professional Council in
Economic Sciences of the City of Buenos Aires (CPCECABA) approved on March 6,
2002 Resolution MD No. 3/2002 applicable to financial statements for fiscal
years or interim periods ending on or after March 31, 2002. Resolution MD No.
3/2002 required the reinstatement of the adjustment-for-inflation method of
accounting in financial statements, which provides that all recorded amounts be
restated by changes in the general purchasing power through August 31, 1995, as
well as those arising between that date and December 31, 2001 stated in
currency as of December 31, 2001. On July 16, 2002, the Argentine government issued Decree 1,269/02,
instructing the CNV and other regulatory authorities to issue the necessary
regulations for the delivery to such authorities of balance sheets or financial
statements prepared in constant currency. On July 25, 2002, under Resolution
No. 415/02, the CNV reinstated the requirement to submit financial statements
in constant currency. As the inflation rate stabilized, on March 25, 2003,
Decree 664/03 rescinded the requirement that financial statements be prepared
in constant currency. On April 8, 2003, the CNV issued Resolution 441/03
discontinuing inflation accounting as of March 1, 2003. Through Resolution No.
287/03 the CPCECABA also discontinued inflation accounting, but as from October
1, 2003. Accordingly, inflation accounting for the period from March 1, 2003 to
September 30, 2003 is required by the CPCECABA but not allowed by the CNV. In accordance with the above, our financial statements for the fiscal
years ended December 31, 2002 and 2001 were restated in constant pesos as of
February 28, 2003 based on changes in the Argentine wholesale price index
published by the INDEC. This price index does not reflect any specific
variation in the price of products and services sold by us, and therefore,
variations in gains (losses) for both periods include positive or negative
price variations that may be higher or lower than the general price variation
or price variations for the products or services sold by us. After March 1,
2003, in accordance with the CNV standards described above, we no longer apply
adjusting-for-inflation accounting. Under US GAAP, general price level adjusted financial statements are not
required. However, pursuant to the SECs rules, these adjustments are not
removed when performing the reconciliation to US GAAP included in Note 23. F-59




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b) Capitalization of exchange differences Under Argentine GAAP, Resolution No. 3/2002 of the CPCECABA requires that
exchange differences resulting from the peso devaluation on liabilities
denominated in foreign currencies existing as of January 6, 2002, that are
directly related to the acquisition, construction or production of property,
plant and equipment, intangibles and long-term investments in other companies
incorporated in Argentina, should be capitalized at the cost values of such
assets, subject to a number of conditions. As described in Note 4.o), as of December 31, 2003 and 2002, the Company
records capitalized negative foreign exchange differences through its
affiliates Citelec and CIESA. Under US GAAP, foreign currency exchange gains or losses are recognized
currently in income. c) Accounting for peso devaluation in January 2002 Under Argentine GAAP, assets and liabilities in foreign currency as of
December 31, 2001, have been valued at the P$1=U.S.$ 1 exchange rate that was
in effect when transactions in the foreign exchange market were suspended.
Accordingly, all the effects of the devaluation of the Argentine peso were
recognized in the 2002 fiscal year. Under US GAAP, such assets and liabilities in foreign currency should be
valued at the exchange rate effective as of the date of reopening of the
exchange market (January 11, 2002), which was P$ 1.70 to US$ 1.00. As a result,
the effects of such devaluation were recognized in 2001 fiscal year, and
included as an adjustment in the reconciliation of net income to US GAAP in
Note 23, on the following line items: On net income:  
    
    Exchange differences
    
    US GAAP adjustments applicable to equity in affiliates and to equity in earnings of affiliates. Since no difference in exchange rates is verified as of December 31, 2002,
the effects described above are reversed on 2002 fiscal year in the
reconciliation presented in Note 23. d) Income taxes Both Argentine GAAP and US GAAP, require the liability method to be used
to account for deferred income taxes. Under this method, deferred income tax
assets or liabilities are recorded for temporary differences that arise between
the financial and tax bas es of assets and liabilities at each reporting date.
The benefits of tax loss carry-forwards are recognized as deferred income tax
assets, with an appropriate valuation allowance. A valuation allowance is
provided when it is more likely than not (under US GAAP) or probable (under
Argentine GAAP) that some portion or all of the deferred tax assets will not be
realized. However, Argentine GAAP and US GAAP may differ under certain circumstances
in deferred income tax accounting. Under Argentine GAAP, differences between
accounting and tax basis generated due to the recognition of the inflation
effect on non-monetary assets, are accounted for as permanent differences for
deferred income tax purposes. Under US GAAP, pursuant to Emerging Issues Task
Force (EITF) No. 93-9, such differences are accounted for as temporary
differences for deferred income tax purposes. F-60




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e) Deferred charges Under Argentine GAAP, costs such as organization and pre-operating
expenses may be deferred and amortized over the resultant period of benefit,
under certain circumstances. For US GAAP purposes these amounts are expensed as incurred. f) Discounting of certain receivables and liabilities Under Argentine GAAP, certain receivables and liabilities which are valued
on the basis of the best possible estimate of amount to be collected and paid,
are required to be discounted using the estimated rate at the time of the
initial measurement. Under
US GAAP, receivables and liabilities arising from transactions with
customers and suppliers in the normal course of business, which are
done in customary trade terms not exceeding one year, are accounted for at nominal
value, including accrued interest, if applicable. g) Proportionate consolidation Under Argentine GAAP, an investor is required to consolidate
proportionally line by line its financial statements with the financial
statements of the companies over which it exercises joint control. Joint
control exists where all the shareholders, or only the shareholders owning a
majority of votes, share the power to define and establish a companys
operating and financial policies on the basis of written agreements. In the
consolidation of companies over which an investor exercises joint control, the
amount of the investment in the company under joint control and the interest in
its income (loss) and cash flows are replaced by the investors proportional
interest in the companys assets, liabilities, income (loss) and cash flows.
Under Argentine GAAP, participations in Distrilec and CIESA qualify for
proportionate consolidation. Under US GAAP, participation in companies over which the investor
exercises joint control is accounted for by the equity method and no
proportional consolidation is allowed. However, pursuant to the SECs rules,
differences in classification or display that result from using proportionate
consolidation in the reconciliation to US GAAP, may be omitted if certain
requirements are met. Such requirements are met by Distrilec but not by CIESA.
As a result such differences corresponding to proportional consolidation of
Distrilec are not presented. h) Accounting for business combinations In July 2001, the FASB issued Statement of Financial Accounting Standards
(SFAS) No. 141, Business Combinations and SFAS No. 142 Goodwill and Other
Intangible Assets. These standards change the accounting for business
combinations by, among other things, prohibiting the prospective use of
pooling-of-interests accounting. In addition, SFAS No. 142 requires that,
effective January 1, 2002, goodwill included in the carrying value of
investments accounted for using the equity method of accounting, and certain
other intangible assets deemed to have an indefinite useful life, cease
amortizing. The new rules also require that goodwill and certain intangible
assets be assessed for impairment using fair value measurement techniques. The
Company has completed the annual impairment test of goodwill under the new
standard and no additional adjustment was required. Business combinations
performed before June 30, 2001 were accounted for under APB Opinion No. 16. Under this past standard, goodwill was amortized on a straight-line basis
over 40 years, resulting in an accumulated amortization of 46 through December
31, 2001. As from January 1, 2002, goodwill is no longer amortized. All
business combinations described below were performed before June 30, 2001. F-61




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1) Petrobras Energía share exchange offer Under US GAAP, the 2000 exchange offer was accounted for under the
purchase method. The purchase price of 6,766, calculated based upon the
market price of Petrobras Energía common stock, has been allocated to the
identifiable assets acquired and liabilities assumed based upon their fair
value as of the acquisition date. The excess of the purchase price over the
fair value of the net assets acquired has been reflected as goodwill, which
was amortized on a straight-line basis over 40 years until December 31, 2001.
The purchase price has been allocated as follows: Fair value of assets acquired
    
    
    10,927Goodwill
    
    
    928Fair value of liabilities assumed
    
    
    (5,089
    )Total purchase price
    
    
    6,766
 Under Argentine GAAP, the accounting practice followed in 2000 fiscal
year for nonmonetary exchange of shares was to recognized net assets at book
value. Accordingly, issued shares of Petrobras Energía Participaciones S.A.
(formerly Perez Companc S.A) were subscribed and accounted for at the book
value of Petrobras Energía shares exchanged. Therefore, the US GAAP
reconciliation of shareholders equity reflects the additional purchase
price of Petrobras Energía capital stock, and the reconciliation of net
income reflects the incremental depreciation, depletion, amortization,
effective interest rate of liabilities and the related effects on the
deferred income tax, as a result of the purchase price allocation mentioned
above and the amortization of goodwill until December 31, 2001, which
amounted to 24 for the year ended December 31, 2001. Beginning 2003 fiscal year, new Argentine GAAP pursuant to CNV
Resolution N° 434 adopted the purchase method or the pooling of interests
method, depending on the circumstances. However, such new standards are not
applied in retroactive basis. 2) Impairment of goodwill, Property, Plant and Equipment, and equity in
affiliates As described above, the purchase price of Petrobras Energía has been
allocated under US GAAP (but not under Argentine GAAP) to the identifiable
assets acquired and liabilities assumed, based upon their fair values as of
acquisition date, being the excess reflected as goodwill. In 2001 fiscal year, the US GAAP reconciliation reflected impairment
charges of goodwill of 571, impairment charges of Property, plant and
equipment of 628, and impairment charges of equity in affiliates of 411, to
reduce the book value under US GAAP to fair values as of year-end, because
such goodwill was not reflected under Argentine GAAP and book value of equity
in affiliates subject to impairment was higher under US GAAP, as explained
above. Impairment losses reflected under US GAAP in 2001 fiscal year were a
consequence of the crisis in Argentina as described in Notes 20 and 9.VI),
and included identified goodwill and equity in the affiliates: CIESA, TGS,
Enron de Inversiones de Energía S.C.A. (Edidesca), Distrilec and Citelec.
Total impairment loss adjustments from Argentine GAAP to US GAAP were 653 for
hydrocarbons, marketing and transportation segment, and 987 for electricity
segment. For purposes of determining impairment loss, fair values were
estimated based on quoted market prices and other information available. As a result of recognizing such impairment losses and the devaluation
effects on 2001 fiscal year as explained in Note 22.c), under US GAAP the
value of the Companys interest in Citelec, Transener, CIESA, TGS and
Edidesca as of December 31, 2001, accounted for under the equity method was
nil. As of December 31, 2003 and 2002, as a result of the devaluation effects
mentioned above, under US GAAP the book value of the Company  ́s interest in
Citelec, Transener and CIESA accounted for under the equity method is nil. As
of such dates, the valuation of the interest in TGS amounts to 82 and 37,
respectively, under US GAAP. F-62




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3) Negative goodwill For the Hidroeléctrica Pichi Picún Leufú S.A. (HPPL) acquisition, the
fair value of assets was substantially represented by the acquired deferred
tax assets, consisting of the tax effects of the difference between tax and
book basis of fixed assets and net operating loss carry forwards, which were
only recognized under US GAAP. To the extent of the excess of such deferred
tax assets acquired over the consideration paid, a negative goodwill was
recognized under US GAAP, which was amortized over a 30 year period beginning
at the plant start-up of operations until December 31, 2001. As the Company
adopted SFAS 142 effective January 1, 2002, such negative goodwill has been
reversed, and a cumulative effect of change in accounting principle of 179
was recognized in 2002. Neither the deferred tax assets nor the related negative goodwill and
its reversal were recognized under Argentine GAAP. 4) Deferred charges in privatized companies acquired In Argentina, it is an accepted practice for costs associated with
voluntary retirement programs incurred in the acquisition and start-up of a
privatized company to be recognized as a liability with a corresponding
deferred asset, which is amortized over the period expected to be benefited. The only difference between US and Argentine GAAP related to qualifying
liabilities assumed is that for Argentine GAAP the offsetting purchase price
is allocated to intangible assets and for US GAAP the offsetting purchase
price is allocated to the fair value of the acquired assets which, in this
case, is property, plant and equipment (PP&E). Therefore, the US GAAP
reconciliation of net income and shareholders equity reflects in this
respect, the difference between intangible asset amortization and property,
plant and equipment depreciation. i) Foreign Currency Translation Under Argentine GAAP, all foreign operations are remeasured into U.S.
dollars, their functional currency. Assets and liabilities, stated at current
values are to be converted at the closing exchange rates, assets and
liabilities measured at cost and revenues, expenses, gains and losses are to be
converted at the historical exchange rates. Once the transactions are
remeasured into U.S. dollars, assets and liabilities are translated into pesos
at current rate, and revenues, expenses, gains and losses are translated at
historical exchange rates. Resulting remeasurement and translation gain or loss
is recognized currently in earnings in the Financial income (expense) and
holding gain (losses) account for fiscal years 2002 and 2001. In accordance with new accounting standards pursuant to CNV Resolution No.
434 as from fiscal year 2003, the translation gain or losses arising from the
translation into pesos of the financial statements of all foreign operations is
presented in the Transitory differencesforeign currency translation account,
a separate component of the balance sheet. Under US GAAP, gains or losses resulting from translation of U.S. dollars
remeasured operations into pesos, are included as other comprehensive income, a
separate component of shareholders equity. A portion of the
companys foreign currency denominated debt portfolio is designated as a hedge of the volatility in stockholders equity
caused by changes in the functional currency exchange rates with respect to the
peso. Exchange differences resulting from such debt are reflected in the
Transitory differencesForeign currency translation account under Argentine GAAP (for 2003), and in the
cumulative translation adjustment account under US GAAP (for all periods presented), thereby offsetting the translation
gain or loss from hedged foreign subsidiaries net assets.
Remaining exchange differences recognized in income differ from
Argentine GAAP to US GAAP, as a result of differences in the book
value of foreign subsidiaries net assets and resulting designated debt. j) Capitalization of interest costs on certain assets Prior to January 1, 1993, Argentine GAAP did not require capitalization of
interest charges relating to the financing of major projects under
construction. Capitalization of interest as part of the acquisition cost of an
asset is required under US GAAP. However, qualifying assets and eligible
interest cost may differ under certain circumstances. Under US GAAP, foreign
currency exchange gains or losses are excluded from interest cost base. F-63




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k) Depreciation of Property, plant and equipment Under Argentine GAAP, depreciation of certain non-oil and gas fixed assets
is accounted for by the Company by applying rates established for technical
revaluation, which are based on engineering formulas. Under US GAAP depreciation of such assets is calculated primarily using
the straight-line method over the useful lives of the assets. l) Minority interest An adjustment to record the portion of all US GAAP adjustments
attributable to minority interests in consolidated subsidiaries has been
recorded. m) Accounting for derivative instruments Under US GAAP, SFAS No. 133 as amended by SFAS No. 137 and SFAS No. 138,
requires that all derivative financial instruments be recognized in the
consolidated balance sheets as either an asset or liability measured at fair
value. SFAS No. 133 requires that changes in the derivative  ́s fair value be
recognized in earnings unless specific hedge accounting criteria are met. For
derivatives accounted for as hedges, fair value adjustments are recorded to
earnings or other comprehensive income, a component of shareholders equity,
depending upon the type of hedge and the degree of hedge effectiveness. For
hedges classified as fair value hedges, adjustments are recorded through
earnings with an offsetting, partial mark to fair value of the hedged item
currently through earnings. For hedges classified as cash flow hedges,
adjustments are recorded to other comprehensive income, and the gain or loss on
the derivative is removed from equity and recognized in earnings in the same
period as the loss or gain on the hedged cash flow. Under Argentine GAAP in the fiscal year 2003, changes in the fair value or
derivatives accounted for as effective hedges are recognized in the Transitory
differencesMeasurement of derivative financial instruments determined as
effective hedge account, a separate component of the balance sheet. Prior to the adoption of new accounting standards in fiscal year 2003
pursuant to CNV Resolution No. 434, under Argentine GAAP there were no specific
requirements governing derivatives accounting and the Company used hedge
accounting for derivatives in fiscal years 2002 and 2001 in conjunction with
its risk management objectives. Pursuant to special transition standards, the balances as of December 31,
2002 resulting from the recognition, measurement and booking of financial
instruments, which qualified as effective hedges, were not adjusted
retroactively. n) Valuation of timber Under Argentine GAAP, timber was valued at current values, recognizing
their organic growth currently in income. Under US GAAP, timber is valued at historical cost. Forestry operations
were sold in 2002. o) Debt refinancing costs Under Argentine GAAP, unamortized deferred costs incurred with third
parties related to debt issuance are charged to expenses when such debt is
restructured, while such costs related to the new debt are capitalized and
amortized on a straight  line basis. Under US GAAP, SFAS No. 15 and SFAS No. 140 and related EITF issues
require for debt restructuring not considered to be an extinguishment, the
Company continues amortizing those costs related to the old debt and charge to
expenses for debt restructuring direct costs. F-64




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##### Table of Contents



p) Guarantors Accounting for Guarantees Under US GAAP, FASB Interpretation No. 45, Guarantors Accounting and
Disclosure requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others, clarifies that at the time a company issues a
guarantee, the company must recognize an initial liability for the fair value,
or market value, of the obligations it assumes under that guarantee. Under
Argentine GAAP, guarantees issued are generally not recognized as
liabilities. q) Accounting for stock option plans Under Argentine GAAP, the Company has accounted for stock option plans
consistently with Accounting Principles Board (APB) Opinion No. 25,
Accounting for stock issued to employees, in accounting for its employee
stock option plan. Since Petrobras Energías stock option plan is a liability
award, there is no differences in the reported net income and earning per share
for the years 2003, 2002 and 2001 based on SFAS No. 123, Accounting for stock
based compensation, amended by SFAS No. 148. r) Classification of sale of future revenues Under Argentine GAAP, net proceeds from an assignment of future capital
fees to be earned in Venezuela are presented in the Balance Sheet as current
and noncurrent other liabilities for US$ 36 million and US$ 73 million as of
December 31, 2003 and 2002, respectively. Under US GAAP, a sale of future revenues of this nature is classified as
debt. Therefore, a reclassification was made for purposes of US GAAP
consolidated balance sheet data presented in Note 23. s) Classification of impairment losses Under Argentine GAAP, impairment losses for fixed assets, if any, are
generally presented in the income statement as non-operating expenses. US GAAP requires such losses to be presented as operating. Therefore,
impairment losses recognized under Argentine GAAP and additional impairment
losses recognized under US GAAP, are included in the Operating income (loss)
subtotal of the US GAAP Consolidated income data presented in Note 23. t) Accounting for discontinued operations Under Argentine GAAP, the gain or loss on sales of a business segment is
presented in the Other expenses, net account. According to US GAAP, the results of continuing operations should be
presented separately from discontinued operations and any gain or loss from
disposal of a component of business segment should be reported in conjunction
with the result of discontinued operations. Therefore, required
reclassifications have been made for purposes of US GAAP consolidated income
data presented in Note 23. u) Accounting for changes in accounting principles  Asset retirement
obligations Under Argentine GAAP, changes in accounting principles are generally
accounted for on retroactive basis. Under US GAAP, such changes are generally recognized as a cumulative
effect in current earnings for the period the change is effective. In connection with the adoption of SFAS No. 143 Accounting for Asset
Retirement Obligations for both US GAAP and Argentine GAAP as from January 1,
2003, the reconciliation of net income presented in Note 23 reflects the
difference described above in recognizing such change in accounting principle. F-65




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##### Table of Contents



v) New accounting standards under US GAAP 1) Derivative Instruments In May 2003, the FASB issued SFAS No. 149, Amendment of Statement 133
on Derivative Instruments and Hedging Activities. This Statement amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities. SFAS No. 149 did not impact the
Companys consolidated financial statements. 2) Accounting for Certain Financial Instruments with Characteristics of
Both Liabilities and Equity In May 2003, the FASB issued SFAS No. 150, Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity.
This Statement establishes standards for how an issuer classifies and
measures certain financial instruments with characteristics of both
liabilities and equity. It requires that an issuer classify a financial
instrument that is within its scope as a liability (or an asset in some
circumstances). Many of those instruments were previously classified as
equity. SFAS No. 150 is effective for financial instruments entered into or
modified after May 31, 2003, and otherwise is effective at the beginning of
the first interim period beginning after June 15, 2003, except for
mandatorily redeemable financial instruments of non-public entities. SFAS
No. 150 did not impact the Companys consolidated financial statements. 3) Employers Disclosures about Pensions and Other Postretirement
Benefits On December 23, 2003 the Financial Accounting Standards Board released
revised FASB Statement No. 132, Employers Disclosures about Pensions and
Other Postretirement Benefits (SFAS No. 132). The revised standard
provides required disclosures for pensions and other postretirement benefit
plans and is designed to improve disclosure transparency in financial
statements. The revised standard replaces existing pension disclosure
requirements. The requirements of the standard are effective for public
entities for fiscal years ending after December 15, 2003. The adoption of
SFAS No. 132 did not have a material impact on the Companys consolidated
financial statements. 4) Revenue recognition On December 17, 2003, the Securities and Exchange Commission issued
Staff Accounting Bulletin No. 104 (SAB No. 104), which revises or rescinds
portions of the interpretative guidance included in Staff Accounting
Bulletin No. 101, Revenue Recognition (SAB No. 101). The main
modifications introduced by SAB No. 104 are aimed at making this
interpretive guidance consistent with current authoritative accounting and
auditing guidance and SEC rules and regulations. The principal revisions
relate to the rescission of material no longer necessary because of private
sector developments in the US generally accepted accounting principles. The
adoption of SAB No. 104 did not have a material impact on the Companys
consolidated financial statements. F-66




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##### Table of Contents



23. Reconciliation of net income and shareholders equity to US GAAP The following is a summary of the significant adjustments to net income
for the years ended December 31, 2003, 2002 and 2001, and the shareholders
equity as of December 31, 2003 and 2002, which would be required if US GAAP had
been applied instead of Argentine GAAP in the Companys financial statements. Reconciliation of net income to US GAAP 2003
    
    2002
    
    2001Net income (loss) in accordance with Argentine GAAP
    
    
    381
    
    
    
    (1,579
    )
    
    
    101US GAAP adjustments:Exchange differences from devaluation of the Argentine peso
    
    
    
    
    
    
    218
    
    
    
    (218
    )Foreign currency translation adjustment
    
    
    (108
    )
    
    
    87
    
    
    
    Valuation of timber
    
    
    
    
    
    
    (2
    )
    
    
    2Deferred charges
    
    
    
    
    
    
    1
    
    
    
    2Amortization of deferred charges
    
    
    3
    
    
    
    5
    
    
    
    4Debt refinancing costs
    
    
    24
    
    
    
    (64
    )
    
    
    Deferred income taxes
    
    
    66
    
    
    
    (1,123
    )
    
    
    34Derivatives
    
    
    88
    
    
    
    91
    
    
    
    138Depreciation of PP&E
    
    
    (168
    )
    
    
    (252
    )
    
    
    (168
    )Impairment of PP&E
    
    
    
    
    
    
    
    
    
    
    (628
    )Fair value of liabilities
    
    
    (36
    )
    
    
    12
    
    
    
    (46
    )Negative goodwill
    
    
    
    
    
    
    179
    
    
    
    7Amortization of goodwill
    
    
    
    
    
    
    
    
    
    
    (24
    )Impairment of goodwill
    
    
    
    
    
    
    
    
    
    
    (571
    )Discounted value of assets and liabilities
    
    
    17
    
    
    
    
    
    
    
    Difference in accounting basis for assets sold
    
    
    (29
    )
    
    
    (92
    )
    
    
    (207
    )Asset retirement obligations
    
    
    45
    
    
    
    (15
    )
    
    
    1Minority Interest
    
    
    (4
    )
    
    
    46
    
    
    
    54Other
    
    
    41
    
    
    
    20
    
    
    
    25Deferred income taxes on US GAAP adjustments
    
    
    97
    
    
    
    148
    
    
    
    582US GAAP adjustments applicable to equity in earnings of affiliatesImpairment of equity in affiliates
    
    
    
    
    
    
    
    
    
    
    (441
    )Exchange differences from devaluation of Argentine peso
    
    
    
    
    
    
    803
    
    
    
    (803
    )Other differences
    
    
    (317
    )
    
    
    (37
    )
    
    
    (110
    )Total US GAAP adjustments
    
    
    (281
    )
    
    
    25
    
    
    
    (2,367
    )Reclasification of discontinued operations and cumulative effect of
changes in accounting principles, net of income tax
    
    
    9
    
    
    
    (314
    )
    
    
    12Income (loss) from continuing operations
    
    
    109
    
    
    
    (1,868
    )
    
    
    (2,254
    )Discontinued operations:Income (loss) from operations (1)
    
    
    7
    
    
    
    72
    
    
    
    (12
    )Income (loss) from disposal (2)
    
    
    (46
    )
    
    
    63
    
    
    
    Income (loss) before cumulative effect of changes
in accounting principles
    
    
    70
    
    
    
    (1,733
    )
    
    
    (2,266
    )Cumulative effect of changes in accounting principles, net of tax
(3)
    
    
    30
    
    
    
    179
    
    
    
    Net income (loss) under US GAAP
    
    
    100
    
    
    
    (1,554
    )
    
    
    (2,266
    )
 F-67




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##### Table of Contents



2003
    
    2002
    
    2001Basic net income (loss) per share under US GAAPClass A
    
    
    
    
    
    
    
    
    
    
    (0.786
    )Class B
    
    
    0.047
    
    
    
    (0.729
    )
    
    
    (1.179
    )Diluted net income (loss) per share under US GAAP
    
    
    0.047
    
    
    
    (0.729
    )
    
    
    (1.063
    )Basic net income (loss) per share under US GAAPClass AContinuing operations
    
    
    
    
    
    
    
    
    
    
    (0.782
    )Discontinued operations
    
    
    
    
    
    
    
    
    
    
    (0.004
    )Class BContinuing operations
    
    
    0.051
    
    
    
    (0.876
    )
    
    
    (1.172
    )Discontinued operations
    
    
    (0.018
    )
    
    
    0.063
    
    
    
    (0.006
    )Cumulative effect of changes in accounting principles
    
    
    0.014
    
    
    
    0.084
    
    
    
    Diluted net loss per share under US GAAPContinuing operations
    
    
    0.051
    
    
    
    (0.876
    )
    
    
    (1.057
    )Discontinued operations
    
    
    (0.018
    )
    
    
    0.063
    
    
    
    (0.006
    )Cumulative effect of changes in accounting principles
    
    
    0.014
    
    
    
    0.084
    
    
    
    Basic net income (loss) per share under Argentine GAAPClass A
    
    
    
    
    
    
    
    
    
    
    0.035Class B
    
    
    0.179
    
    
    
    (0.744
    )
    
    
    0.053Diluted net income per share under Argentine GAAP
    
    
    0.179
    
    
    
    (0.744
    )
    
    
    0.047Number of shares -in millions (4)
    
    
    2,132
    
    
    
    2,132
    
    
    
    2,132
  (1)
    
    Net of applicable income tax expenses of 26 and 27 for the years ended
December 31, 2002 and 2001.(2)
    
    Including applicable income tax benefit of 10 and 3 for the years
ended December 31, 2003 and 2002.(3)
    
    Net of applicable income tax expense of 15 for the year ended
December 31, 2003.(4)
    
    Earnings per share are calculated based on the weighted average
number of shares outstanding during the year. Consolidated pro forma income data As mentioned in Note 22, SFAS No. 142 and SFAS No. 143 were effective from
January 1, 2002 and January 1, 2003, respectively. If the new standards had
been effective before January 1, 2001, net income for the years ended December
31, 2003, 2002 and 2001, would have been as follows: 2003
    
    2002
    
    2001Net income (loss) under US GAAP
    
    
    100
    
    
    
    (1,554
    )
    
    
    (2,266
    )Amortization of goodwill
    
    
    
    
    
    
    
    
    
    
    9Reversal of negative goodwill
    
    
    
    
    
    
    (179
    )
    
    
    (7
    )Accounting for asset retirement obligation, net of tax
    
    
    (30
    )
    
    
    10
    
    
    
    (1
    )Proforma net income (loss) under US GAAP
    
    
    70
    
    
    
    (1,723
    )
    
    
    (2,265
    )Proforma basic net income (loss) per share under US GAAPClass A
    
    
    
    
    
    
    
    
    
    
    (0.785
    )Class B
    
    
    0.033
    
    
    
    (0.808
    )
    
    
    (1.178
    )Proforma diluted net income (loss) per share under US GAAP
    
    
    0.033
    
    
    
    (0.808
    )
    
    
    (1.062
    )
 F-68




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##### Table of Contents



Consolidated statement of comprehensive income 2003
    
    2002
    
    2001Net income (loss) under US GAAP
    
    
    100
    
    
    
    (1,554
    )
    
    
    (2,266
    )Foreign currency translation adjustment:Net change during period, net of tax
    
    
    (78
    )
    
    
    (374
    )
    
    
    455Deferred hedge gains and losses, net of tax:Cumulative effect of accounting change
    
    
    
    
    
    
    
    
    
    
    (228
    )Reclassification to net income
    
    
    (15
    )
    
    
    78
    
    
    
    162Deferred hedge (loss) gains
    
    
    17
    
    
    
    (54
    )
    
    
    26Total Comprehensive Income
    
    
    24
    
    
    
    (1,904
    )
    
    
    (1,851
    )Cumulative Other Comprehensive Income:Foreign currency translation adjustment
    
    
    (48
    )
    
    
    30
    
    
    
    404Deferred hedge gains and losses, net of tax
    
    
    (12
    )
    
    
    (14
    )
    
    
    (38
    )Total Cumulative Other Comprehensive Income
    
    
    (60
    )
    
    
    16
    
    
    
    366
 Reconciliation of shareholders  ́ equity to US GAAP 2003
    
    2002Shareholders equity in accordance with Argentine GAAP
    
    
    4,833
    
    
    
    4,452US GAAP adjustments:Deferred charges
    
    
    (29
    )
    
    
    (37
    )Debt refinancing costs
    
    
    (41
    )
    
    
    (65
    )Deferred income taxes
    
    
    (1,242
    )
    
    
    (1,308
    )Minority interest
    
    
    132
    
    
    
    136Derivatives
    
    
    (18
    )
    
    
    (109
    )Foreign currency translation adjustment
    
    
    (161
    )
    
    
    (123
    )PP&E
    
    
    1,513
    
    
    
    1,909Goodwill
    
    
    155
    
    
    
    155Fair value of liabilities
    
    
    86
    
    
    
    140Discounted value of assets and liabilities
    
    
    17
    
    
    
    Asset retirement obligations
    
    
    
    
    
    
    (45
    )Other
    
    
    11
    
    
    
    6Deferred income taxes on U.S. GAAP adjustments
    
    
    (360
    )
    
    
    (543
    )US GAAP adjustments applicable to equity in affiliates
    
    
    (373
    )
    
    
    (69
    )Total US GAAP adjustments
    
    
    (310
    )
    
    
    47Shareholders equity in accordance with US GAAP
    
    
    4,523
    
    
    
    4,499
 F-69




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##### Table of Contents



Description of changes in shareholders ́ equity under US GAAP 2003
    
    2002
    
    2001Shareholders ́ equity under US GAAP as of beginning of the year
    
    
    4,499
    
    
    
    6,403
    
    
    
    8,408Cash dividends
    
    
    
    
    
    
    
    
    
    
    (134
    )Acquisition of own stock held by subsidiary
    
    
    
    
    
    
    
    
    
    
    (20
    )Other comprehensive income
    
    
    (76
    )
    
    
    (350
    )
    
    
    415Net income (loss) under US GAAP
    
    
    100
    
    
    
    (1,554
    )
    
    
    (2,266
    )Shareholders ́ equity under US GAAP as of the end of the year
    
    
    4,523
    
    
    
    4,499
    
    
    
    6,403
 US GAAP Summarized Consolidated Data The consolidated income data and the consolidated cash flow data for the
years ended December 31, 2003, 2002 and 2001, and the consolidated balance
sheets data as of December 31, 2003 and 2002, presented below have been
adjusted to reflect the differences between US GAAP and Argentine GAAP
discussed above: Year ended December 31,US GAAP consolidated income and loss data
    
    2003
    
    2002
    
    2001Sales
    
    
    5,192
    
    
    
    5,321
    
    
    
    4,658Less  taxes on sales and services
    
    
    (114
    )
    
    
    (139
    )
    
    
    (28
    )Net sales
    
    
    5,078
    
    
    
    5,182
    
    
    
    4,630Cost of sales
    
    
    (3,282
    )
    
    
    (3,374
    )
    
    
    (3,084
    )Gross profit
    
    
    1,796
    
    
    
    1,808
    
    
    
    1,546Administrative and selling expenses
    
    
    (529
    )
    
    
    (645
    )
    
    
    (629
    )Exploration expenses
    
    
    (196
    )
    
    
    (58
    )
    
    
    (41
    )Other operating income (expense), net
    
    
    (449
    )
    
    
    (275
    )
    
    
    (23
    )Operating income
    
    
    622
    
    
    
    830
    
    
    
    853Equity in earnings of affiliates
    
    
    65
    
    
    
    (125
    )
    
    
    (2,713
    )Financial income (expense) and holding gains (losses)
    
    
    (663
    )
    
    
    (1,564
    )
    
    
    (911
    )Other income, net
    
    
    
    
    
    
    
    
    
    
    185Income (loss) before income taxes, minority interest,
discontinued operations and cumulative effect of
changes in accounting principles
    
    
    24
    
    
    
    (859
    )
    
    
    (2,586
    )Income tax (expense) benefit
    
    
    92
    
    
    
    (1,089
    )
    
    
    326Minority interest in subsidiaries
    
    
    (7
    )
    
    
    80
    
    
    
    6Discontinued operationsIncome (loss) from discontinued operations, net
of income taxes (1)
    
    
    7
    
    
    
    72
    
    
    
    (12
    )Income (loss) from disposal, net of income taxes (2)
    
    
    (46
    )
    
    
    63
    
    
    
    Cumulative effect of changes in accounting
principles (3)
    
    
    30
    
    
    
    179
    
    
    
    Net income (loss) for the year
    
    
    100
    
    
    
    (1,554
    )
    
    
    (2,266
    )
  (1)
    
    Net of income tax expense of 26 and 27 for the years ended December
31, 2002 and 2001.  (2)
    
    Net of income tax benefit of 10 and 3 for the years ended December
31, 2003 and 2002.  (3)
    
    Net of income tax expense of 15 for the year ended December 31, 2003. F-70




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##### Table of Contents



Year ended December 31,US GAAP condensed consolidated balance sheet data
    
    2003
    
    2002Current assets
    
    
    2,614
    
    
    
    2,750Investments
    
    
    1,071
    
    
    
    1,055Property, plant and equipment
    
    
    10,522
    
    
    
    12,105Other non current assets
    
    
    301
    
    
    
    198Total non current assets
    
    
    11,894
    
    
    
    13,358Total assets
    
    
    14,508
    
    
    
    16,108Short-term debt
    
    
    1,304
    
    
    
    1,624Other liabilities
    
    
    1,282
    
    
    
    1,155Total current liabilities
    
    
    2,586
    
    
    
    2,779Long-term debt
    
    
    5,027
    
    
    
    6,152Other non current liabilities
    
    
    1,967
    
    
    
    2,238Total noncurrent liabities
    
    
    6,994
    
    
    
    8,390Total liabilities
    
    
    9,580
    
    
    
    11,169Minority interest in subsidiaries
    
    
    405
    
    
    
    440Shareholders equity
    
    
    4,523
    
    
    
    4,49914,508
    
    
    
    16,108
 Year ended December 31,US GAAP condensed consolidated cash flow data
    
    2003
    
    2002
    
    2001Net cash provided by operations
    
    
    1,209
    
    
    
    826
    
    
    
    1,415Net cash used in investing activities
    
    
    (886
    )
    
    
    (172
    )
    
    
    (1,746
    )Net cash (used in) provided by financing activities
    
    
    (369
    )
    
    
    (1,953
    )
    
    
    986(Decrease) Increase in cash
    
    
    (46
    )
    
    
    (1,299
    )
    
    
    655Effect of the exchange rate on cash
    
    
    (88
    )
    
    
    (63
    )
    
    
    818Cash and cash equivalent at beginning
    
    
    725
    
    
    
    2,087
    
    
    
    614Cash and cash equivalent at end
    
    
    591
    
    
    
    725
    
    
    
    2,087
 F-71




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##### Table of Contents



24.
    
    Additional financial statements disclosures required by US GAAP and the
SEC a) Income taxes The tax effect of the significant differences between the book value and
the tax value of the Companys assets and liabilities and tax loss carryfowards
are as follows: 2003
    
    2002Deferred tax assetsTax loss carryforwards
    
    
    1,399
    
    
    
    1,867Other tax losses
    
    
    207
    
    
    
    279Property, plant and equipment
    
    
    62
    
    
    
    58Reserve for contingencies
    
    
    76
    
    
    
    29Non-current investments
    
    
    82
    
    
    
    86Pension plan obligations
    
    
    7
    
    
    
    7Derivatives
    
    
    216
    
    
    
    187Receivables
    
    
    10
    
    
    
    22Accounts payable
    
    
    12
    
    
    
    5Other deferred tax assets, not significant individually
    
    
    68
    
    
    
    17Less-Valuation allowance
    
    
    (1,619
    )
    
    
    (2,071
    )Deferred tax liabilitiesRevenue recognition
    
    
    (40
    )
    
    
    (21
    )Current investments
    
    
    (16
    )
    
    
    Fair value of liabilities
    
    
    (30
    )
    
    
    (49
    )Prepaid
expenses
    
    
    (29
    )
    
    
    (8
    )Property, plant and equipment
    
    
    (1,551
    )
    
    
    (1,827
    )Non-current investments
    
    
    (351
    )
    
    
    (352
    )Other deferred tax liabilities, not significant individually
    
    
    (41
    )
    
    
    (21
    )Net deferred tax liabilities
    
    
    (1,538
    )
    
    
    (1,792
    )
 The tax loss carryforwards as of December 31, 2003 expire as follows: 2005
    
    
    152006
    
    
    432007
    
    
    52Beyond 2008
    
    
    1,4961,606Valuation allowance on tax loss carryforwards
    
    
    (1,516
    )
 F-72




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##### Table of Contents



The reconciliation of tax provision at the statutory rate to the tax
provision for the years ended December 31, 2003, 2002 and 2001, computed in
accordance with US GAAP, is as follows: 2003
    
    2002
    
    2001Pre-tax income (loss) in accordance with U.S. GAAP
    
    
    6
    
    
    
    (523
    )
    
    
    (2,574
    )Statutory tax rate
    
    
    35
    %
    
    
    35
    %
    
    
    35
    %Statutory tax rate applied to pre-tax income (loss)
    
    
    2
    
    
    
    (183
    )
    
    
    (901
    )Equity in
(earnings) losses and dividends from affiliates
    
    
    (56)
    
    
    
    (97
    )
    
    
    20Inflation
adjustment on nonmonetary assets and liabilities
    
    
    13
    
    
    
    973
    
    
    
    Inflation adjustment, remeasurement and foreign earnings
    
    
    332
    
    
    
    1
    
    
    
    4Increase (decrease) in valuation allowances
    
    
    (422
    )
    
    
    333
    
    
    
    279Tax on minimum presumed income
    
    
    11
    
    
    
    19
    
    
    
    104Impairment,
amortization and other decreases of goodwill
    
    
    13
    
    
    
    39
    
    
    
    218Tax adjustments and other,
net
    
    
    20
    
    
    
    27
    
    
    
    (23)Tax (benefit) expense
    
    
    (87
    )
    
    
    1,112
    
    
    
    (299
    )
 The Companys provision for income taxes under US GAAP was comprised of
the following: 2003
    
    2002
    
    2001CurrentArgentina
    
    
    
    
    
    
    44
    
    
    
    180Foreign
    
    
    48
    
    
    
    22
    
    
    
    2048
    (1)
    
    
    66
    
    
    
    200DeferredArgentina
    
    
    (74
    )
    
    
    1,118
    
    
    
    (585
    )Foreign
    
    
    (61
    )
    
    
    (72
    )
    
    
    86(135
    )
    
    
    1,046
    
    
    
    (499
    )Total tax (benefit)
expense
    
    
    (87
    )
    
    
    1,112
    
    
    
    (299
    )
 
  b) Fair value of financial instruments US GAAP requires disclosure of the estimated fair value of the Companys
financial instruments. The following methods and assumptions were used to
estimate the fair value of each class of financial instruments. The carrying amounts of cash, cash equivalents, accounts receivables and
short-term obligations approximate its fair value, because of the short-term
maturities of these instruments. Fair value of trading and held-to-maturity investments is based on quoted
market prices. The fair value of publicly traded long-term debt is based on
quoted market prices, and for the remaining long-term debt was estimated based
on the current rates available to the Company for debt of similar remaining
maturities. Fair values of derivative financial instruments represent the
estimated amount that would have been required to terminate the contracts. The
fair value of performance bonds and other guarantees approximate the notional
amount of these instruments. F-73




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##### Table of Contents



The estimated fair values of financial instruments are as follows, except
for those financial instruments noted above for which the carrying values
approximate fair values: 2003
    
    2002Carrying
    
    
    
    
    
    Carryingamount
    
    
    
    
    
    amountunder
    
    Fair
    
    under
    
    FairUS GAAP
    
    Value
    
    US GAAP
    
    ValueFinancial assets:Held-to-maturity securities
    
    
    2
    
    
    
    1
    
    
    
    14
    
    
    
    5Financial liabilities:Long-term debt
    
    
    5,027
    
    
    
    5,161
    
    
    
    6,152
    
    
    
    5,324Derivative financial instruments:Energy commodities price swaps and options:Accounted for as a hedge:· Unfavorable
    
    
    
    
    
    
    
    
    
    
    (67
    )
    
    
    (67
    )Accounted for as non-hedge:· Favorable
    
    
    
    
    
    
    
    
    
    
    105
    
    
    
    105· Unfavorable
    
    
    (583
    )
    
    
    (583
    )
    
    
    (507
    )
    
    
    (507
    )Foreign currency and interest rate:Accounted for as a hedge:· Unfavorable
    
    
    (23
    )
    
    
    (23
    )
    
    
    (47
    )
    
    
    (47
    )
 c) Held-to-maturity securities Held-to-maturity securities: The change in the carrying amount of held-to-maturity securities has been
as follows: 2003
    
    2002Balance at beginning of the year
    
    
    14
    
    
    
    13· Increase for securities to held to
maturity
    
    
    
    
    
    
    2· Inflation and remeasurement effect
    
    
    (2
    )
    
    
    (1
    )· Decrease for securities to held to
maturity
    
    
    (2
    )
    
    
    · Redemption and interest collection
    
    
    (8
    )
    
    
    Balance at end of year
    
    
    2
    
    
    
    14
 At December 31, 2003 and 2002 the outstanding held-to-maturity securities
are scheduled to mature in one to sixteen years. F-74




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##### Table of Contents



d) Summarized financial information of unconsolidated affiliates The following table provides summarized financial information on a 100%
basis, for the main affiliates accounted for by the equity method, combined per
business unit, under Argentine GAAP. Each business unit includes the following companies as of December 31,
2003 and 2002:  
    
    Oil and Gas Exploration and Production: Petrolera Entre Lomas S.A.,
Inversora Mata S.A. and Coroil S.A.
    
    Refining: Refinería del Norte S.A. and Empresa Boliviana de Refinación S.A.
    
    Petrochemical: Petroquímica Cuyo S.A.
    
    Hydrocarbons marketing and Transportation: TGS S.A., Oleoductos del
Valle S.A. and Oleoducto de Crudos Pesados Ltd.
    
    Electricity: Citelec S.A., Yacylec S.A. and Urugua-í S.A. As of December 31, 2001, the Other Investments business unit includes
the following companies: Pecom Agra S.A. and Cerro Vanguardia S.A. (see Note
9.IV and 9.V) 2003Oil and Gas
    
    
    
    
    
    
    
    
    
    HydrocarbonsExploration
    
    
    
    
    
    
    
    
    
    marketing andand Production
    
    Refining
    
    Petrochemical
    
    Transportation
    
    ElectricityCurrent Assets
    
    
    115
    
    
    
    893
    
    
    
    105
    
    
    
    1,221
    
    
    
    263Noncurrent Assets
    
    
    517
    
    
    
    524
    
    
    
    115
    
    
    
    8,864
    
    
    
    2,209Current Liabilities
    
    
    49
    
    
    
    848
    
    
    
    60
    
    
    
    3,862
    
    
    
    1,208Noncurrent Liabilities
    
    
    32
    
    
    
    17
    
    
    
    34
    
    
    
    3,739
    
    
    
    614Shareholders Equity
    
    
    551
    
    
    
    552
    
    
    
    126
    
    
    
    2,484
    
    
    
    430Minority interest
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    220Sales
    
    
    278
    
    
    
    1,988
    
    
    
    225
    
    
    
    1,196
    
    
    
    324Gross profit
    
    
    150
    
    
    
    350
    
    
    
    68
    
    
    
    582
    
    
    
    96Income ( loss) from continuing operations
before extraordinary items and Cumulative
effectof changes in accounting principles
    
    
    78
    
    
    
    87
    
    
    
    21
    
    
    
    236
    
    
    
    50Net income
    
    
    78
    
    
    
    87
    
    
    
    21
    
    
    
    236
    
    
    
    50
 2002Oil and Gas
    
    
    
    
    
    
    
    
    
    HydrocarbonsExploration
    
    
    
    
    
    
    
    
    
    marketing andand Production
    
    Refining
    
    Petrochemical
    
    Transportation
    
    ElectricityCurrent Assets
    
    
    130
    
    
    
    878
    
    
    
    110
    
    
    
    1,182
    
    
    
    172Noncurrent Assets
    
    
    575
    
    
    
    535
    
    
    
    121
    
    
    
    13,728
    
    
    
    2,391Current Liabilities
    
    
    73
    
    
    
    819
    
    
    
    114
    
    
    
    8,428
    
    
    
    1,252Noncurrent Liabilities
    
    
    22
    
    
    
    42
    
    
    
    12
    
    
    
    3,086
    
    
    
    715Shareholders Equity
    
    
    610
    
    
    
    552
    
    
    
    105
    
    
    
    2,603
    
    
    
    398Minority interest
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    793
    
    
    
    198Sales
    
    
    272
    
    
    
    2,145
    
    
    
    211
    
    
    
    2,000
    
    
    
    343Gross profit
    
    
    143
    
    
    
    340
    
    
    
    69
    
    
    
    1,070
    
    
    
    131Income ( loss) from continuing operations
before extraordinary items and Cumulative
effectof changes in accounting principles
    
    
    46
    
    
    
    151
    
    
    
    (2
    )
    
    
    (1,154
    )
    
    
    (319
    )Net income
    
    
    46
    
    
    
    151
    
    
    
    (2
    )
    
    
    (1,154
    )
    
    
    (319
    )
 F-75




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##### Table of Contents



2001Oil and Gas
    
    
    
    
    
    
    
    
    
    HydrocarbonsExploration
    
    
    
    
    
    
    
    
    
    marketing and
    
    
    
    
    
    Otherand Production
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    InvestmentsCurrent Assets
    
    
    90
    
    
    
    514
    
    
    
    110
    
    
    
    581
    
    
    
    150
    
    
    
    285Noncurrent Assets
    
    
    433
    
    
    
    539
    
    
    
    131
    
    
    
    5,371
    
    
    
    2,362
    
    
    
    661Current Liabilities
    
    
    61
    
    
    
    590
    
    
    
    110
    
    
    
    852
    
    
    
    574
    
    
    
    266Noncurrent Liabilities
    
    
    8
    
    
    
    12
    
    
    
    12
    
    
    
    2,206
    
    
    
    762
    
    
    
    286Shareholders Equity
    
    
    454
    
    
    
    451
    
    
    
    119
    
    
    
    2,894
    
    
    
    776
    
    
    
    394Minority interest
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    400
    
    
    
    Sales
    
    
    212
    
    
    
    1,409
    
    
    
    132
    
    
    
    1,357
    
    
    
    527
    
    
    
    956Gross profit
    
    
    104
    
    
    
    200
    
    
    
    24
    
    
    
    862
    
    
    
    281
    
    
    
    166Income (loss) from continuing operations
before extraordinary items and Cumulative
effectof changes in accounting principles
    
    
    50
    
    
    
    39
    
    
    
    
    
    
    
    284
    
    
    
    75
    
    
    
    82Net income
    
    
    50
    
    
    
    39
    
    
    
    
    
    
    
    284
    
    
    
    75
    
    
    
    82
 e) Summarized financial information of proportionally consolidated jointly
controlled companies The following table provides summarized financial information on a
proportional basis, for jointly controlled companies, which are proportionally
consolidated under Argentine GAAP: 2003
    
    2002 (a)
    
    2001CIESA
    
    Distrilec
    
    Total
    
    Distrilec
    
    CIESA
    
    Distrilec
    
    TotalCurrent Assets
    
    
    406
    
    
    
    129
    
    
    
    535
    
    
    
    115Noncurrent Assets
    
    
    2,348
    
    
    
    1,372
    
    
    
    3,720
    
    
    
    1,488Current Liabilities
    
    
    2,053
    
    
    
    348
    
    
    
    2,401
    
    
    
    481Noncurrent Liabilities
    
    
    7
    
    
    
    103
    
    
    
    110
    
    
    
    63Shareholders Equity
    
    
    234
    
    
    
    600
    
    
    
    834
    
    
    
    606Minority Interest
    
    
    460
    
    
    
    450
    
    
    
    910
    
    
    
    453Sales
    
    
    432
    
    
    
    447
    
    
    
    879
    
    
    
    519
    
    
    
    595
    
    
    
    946
    
    
    
    1,541Gross Profit
    
    
    232
    
    
    
    74
    
    
    
    306
    
    
    
    113
    
    
    
    376
    
    
    
    292
    
    
    
    668Income (loss) from
continuing operations
before extraordinary items
and cumulative effect of
changes in accounting
principles
    
    
    110
    
    
    
    (6
    )
    
    
    104
    
    
    
    (9
    )
    
    
    36
    
    
    
    49
    
    
    
    85Net Income (loss)
    
    
    110
    
    
    
    (6
    )
    
    
    104
    
    
    
    (9
    )
    
    
    36
    
    
    
    49
    
    
    
    85Cash provided by (used in):Operating activities
    
    
    261
    
    
    
    90
    
    
    
    351
    
    
    
    177
    
    
    
    213
    
    
    
    141
    
    
    
    354Investing activities
    
    
    (31
    )
    
    
    (28
    )
    
    
    (59
    )
    
    
    (69
    )
    
    
    (236
    )
    
    
    (96
    )
    
    
    (332
    )Financing activities
    
    
    1
    
    
    
    (46
    )
    
    
    (45
    )
    
    
    (74
    )
    
    
    65
    
    
    
    (83
    )
    
    
    (18
    )
  (a)
    
    As mentioned in Note 2.a, as of December 31, 2002, CIESA was not
proportionally consolidated since such equity interest was stated at zero
value. F-76




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##### Table of Contents



f) Supplemental cash flow information Cash and cash equivalents include: 2003
    
    2002
    
    2001Cash
    
    
    200
    
    
    
    93
    
    
    
    93Time deposits and Mutual Funds
    
    
    388
    
    
    
    582
    
    
    
    1,994Securities
    
    
    3
    
    
    
    50
    
    
    
    591
    
    
    
    725
    
    
    
    2,087
 Non-cash investing and financing activities for the years ended December
31, 2003, 2002 and 2001, include an increase in accounts payable for the
acquisition of property, plant and equipment in the amount of 141, 50 and 192,
respectively. Additionally, an increase in the Other receivables account is
included for the sale of subsidiaries and other business in the amount of 106
for the year ended December 31, 2002. g) Pension plan: Defined contribution plan: Contributions expensed under this plan amounted to 1 for the year ended
December 31, 2001. During 2003 and 2002 fiscal years, no contributions were
made under this plan (see Note 15.a). Defined benefit pension plan: Information for the Companys major defined benefit plan is as follows: 2003
    
    2002Change in benefit obligationBenefit obligation at beginning
    
    
    78
    
    
    
    128Service cost
    
    
    1
    
    
    
    2Interest cost
    
    
    2
    
    
    
    4Actuarial gain
    
    
    9
    
    
    
    45Effect of remeasurement in constant money
    
    
    (1
    )
    
    
    (70
    )Benefits paid
    
    
    (5
    )
    
    
    (5
    )Curtailment effect
    
    
    (33
    )
    
    
    (26
    )Benefit obligation at end of year
    
    
    51
    
    
    
    78Change in plan assetsFair value of plan assets at beginning
    
    
    97
    
    
    
    130Actual return on plan assets
    
    
    (11
    )
    
    
    67Effect of remeasurement in constant money
    
    
    (1
    )
    
    
    (69
    )Benefits paid
    
    
    (5
    )
    
    
    (5
    )Settlement payments
    
    
    (33
    )
    
    
    (26
    )Fair value of plan assets at end of year
    
    
    47
    
    
    
    97
 F-77




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##### Table of Contents



2003
    
    2002Reconciliation of funded (unfunded) statusFunded status, end of year
    
    
    (4
    )
    
    
    19Unrecognized net actuarial gain
    
    
    (3
    )
    
    
    (40
    )Net amount recognized
    
    
    (7
    )
    
    
    (21
    )Amounts recognized in the statement of financial position
consist of:Accrued benefit liability
    
    
    (7
    )
    
    
    (21
    )Projected benefit obligation
    
    
    51
    
    
    
    78Accumulated benefit obligation
    
    
    51
    
    
    
    77Fair value of plan assets
    
    
    47
    
    
    
    97Components of net periodic benefit costService cost
    
    
    1
    
    
    
    2Interest cost
    
    
    2
    
    
    
    4Expected return on plan assets
    
    
    (3
    )
    
    
    (4
    )Amortization of unrecognized transition obligation
    
    
    
    
    
    
    1Amortization of unrecognized gains
    
    
    (1
    )
    
    
    (2
    )Gains from settlements
    
    
    (14
    )
    
    
    Effect of remeasurement in constant money
    
    
    1
    
    
    
    (24
    )Net periodic benefit (gain) cost
    
    
    (14
    )
    
    
    (23
    )Weighted-average assumptionsDiscount rate
    
    
    4
    %
    
    
    4
    %Expected return on plan assets
    
    
    4
    %
    
    
    4
    %Rate of compensation increase
    
    
    2
    %
    
    
    2
    %
 As
of December 31, 2003 and 2002, pension plan assets are
investments in
mutual funds. The Company expects to contribute approximately 1 to its pension
plan fund in 2004,
which will be subject to Board of Directors approval. Benefit
obligations are expected to be paid as follows: Pension Benefits2004
    
    
    32005
    
    
    32006
    
    
    32007
    
    
    32008
    
    
    32009 - 1013
    
    
    18
 F-78




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##### Table of Contents



h) Business segment consolidated information The Company determines operating segments based on differences in the
nature of their operations, consistent with the measure of profit and the basis
used by its management in making strategic decisions. The Company applies the
same accounting policies to each of the segments that are used in the
preparation of the consolidated financial statements under Argentine GAAP.
Intersegment revenues are generally representative of market prices or
arms-length negotiated transactions. Likewise, affiliated sales are not
segregated because they are generally made at market prices. Managements
measure of segment profit does not include interest, income taxes and other
non-operating income and expenses. Other non-cash items in segment income are
principally comprised of undistributed earnings of affiliates. The following information shows additional disclosures under Argentine
GAAP about the Companys business segments as defined by its management. 2003Oil and Gas
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Corporate, otherExploration and
    
    
    
    
    
    
    
    
    
    marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalUnaffiliated
revenues
    
    
    1,785
    
    
    
    1,231
    
    
    
    1,294
    
    
    
    502
    
    
    
    680
    
    
    
    2
    
    
    
    5,494Intersegment
revenues
    
    
    944
    
    
    
    71
    
    
    
    
    
    
    
    19
    
    
    
    11
    
    
    
    (1,045
    )
    
    
    Total revenues
    
    
    2,729
    
    
    
    1,302
    
    
    
    1,294
    
    
    
    521
    
    
    
    691
    
    
    
    (1,043
    )
    
    
    5,494Depreciation,
depletion
and amortization
    
    
    653
    
    
    
    20
    
    
    
    77
    
    
    
    86
    
    
    
    147
    
    
    
    33
    
    
    
    1,016Equity in earnings
of
unconsolidated
affiliates
    
    
    19
    
    
    
    22
    
    
    
    16
    
    
    
    16
    
    
    
    90
    
    
    
    
    
    
    
    163Interest expense
    
    
    (267
    )
    
    
    (1
    )
    
    
    (30
    )
    
    
    (134
    )
    
    
    (23
    )
    
    
    (168
    )
    
    
    (623
    )Interest revenue
    
    
    28
    
    
    
    1
    
    
    
    5
    
    
    
    9
    
    
    
    12
    
    
    
    10
    
    
    
    65Dividends received
from unconsolidated
affiliates
    
    
    9
    
    
    
    7
    
    
    
    
    
    
    
    7
    
    
    
    3
    
    
    
    
    
    
    
    26Additions to
property,
plant and equipment
    
    
    508
    
    
    
    23
    
    
    
    37
    
    
    
    12
    
    
    
    40
    
    
    
    33
    
    
    
    653Identifiable assets
    
    
    7,610
    
    
    
    419
    
    
    
    1,054
    
    
    
    2,768
    
    
    
    2,261
    
    
    
    1,030
    
    
    
    15,142Investments in and
advances to
unconsolidated
affiliates
    
    
    199
    
    
    
    223
    
    
    
    46
    
    
    
    328
    
    
    
    200
    
    
    
    
    
    
    
    996Total assets
    
    
    7,809
    
    
    
    642
    
    
    
    1,100
    
    
    
    3,096
    
    
    
    2,461
    
    
    
    1,030
    
    
    
    16,138
 F-79




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##### Table of Contents



2002Oil and Gas
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Corporate, otherExploration and
    
    
    
    
    
    
    
    
    
    marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalUnaffiliated revenues
    
    
    2,033
    
    
    
    942
    
    
    
    1,254
    
    
    
    16
    
    
    
    755
    
    
    
    106
    
    
    
    5,106Intersegment revenues
    
    
    773
    
    
    
    66
    
    
    
    
    
    
    
    
    
    
    
    11
    
    
    
    (850
    )
    
    
    Total revenues
    
    
    2,806
    
    
    
    1,008
    
    
    
    1,254
    
    
    
    16
    
    
    
    766
    
    
    
    (744
    )
    
    
    5,106Depreciation, depletion
and amortization
    
    
    749
    
    
    
    18
    
    
    
    94
    
    
    
    
    
    
    
    150
    
    
    
    40
    
    
    
    1,051Equity in earnings of
unconsolidated affiliates
    
    
    2
    
    
    
    20
    
    
    
    (10
    )
    
    
    (470
    )
    
    
    (239
    )
    
    
    59
    
    
    
    (638
    )Interest expense
    
    
    (350
    )
    
    
    
    
    
    
    (42
    )
    
    
    
    
    
    
    (52
    )
    
    
    (439
    )
    
    
    (883
    )Interest revenue
    
    
    12
    
    
    
    1
    
    
    
    11
    
    
    
    
    
    
    
    33
    
    
    
    31
    
    
    
    88Dividends received from
unconsolidated affiliates
    
    
    12
    
    
    
    4
    
    
    
    
    
    
    
    3
    
    
    
    1
    
    
    
    
    
    
    
    20Additions to property,
plant and equipment
    
    
    366
    
    
    
    5
    
    
    
    30
    
    
    
    
    
    
    
    37
    
    
    
    (264
    )
    
    
    174Identifiable assets
    
    
    8,575
    
    
    
    367
    
    
    
    1,251
    
    
    
    (17
    )
    
    
    2,467
    
    
    
    1,174
    
    
    
    13,817Investments in and
advances to
unconsolidated affiliates
    
    
    189
    
    
    
    225
    
    
    
    29
    
    
    
    275
    
    
    
    114
    
    
    
    
    
    
    
    832Total assets
    
    
    8,764
    
    
    
    592
    
    
    
    1,280
    
    
    
    258
    
    
    
    2,581
    
    
    
    1,174
    
    
    
    14,649
 2001Oil and Gas
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    
    
    
    
    Corporate, otherExploration and
    
    
    
    
    
    
    
    
    
    marketing and
    
    
    
    
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Transportation
    
    Electricity
    
    Eliminations
    
    TotalUnaffiliated revenues
    
    
    1,502
    
    
    
    788
    
    
    
    809
    
    
    
    695
    
    
    
    1,248
    
    
    
    128
    
    
    
    5,170Intersegment revenues
    
    
    473
    
    
    
    
    
    
    
    9
    
    
    
    
    
    
    
    38
    
    
    
    (520
    )
    
    
    Total revenues
    
    
    1,975
    
    
    
    788
    
    
    
    818
    
    
    
    695
    
    
    
    1,286
    
    
    
    (392
    )
    
    
    5,170Depreciation, depletion
and amortization
    
    
    514
    
    
    
    15
    
    
    
    64
    
    
    
    88
    
    
    
    164
    
    
    
    32
    
    
    
    877Equity in earnings of
unconsolidated affiliates
    
    
    6
    
    
    
    14
    
    
    
    4
    
    
    
    26
    
    
    
    24
    
    
    
    45
    
    
    
    119Interest expense
    
    
    (227
    )
    
    
    
    
    
    
    (28
    )
    
    
    (116
    )
    
    
    (23
    )
    
    
    (218
    )
    
    
    (612
    )Interest revenue
    
    
    20
    
    
    
    2
    
    
    
    13
    
    
    
    6
    
    
    
    25
    
    
    
    25
    
    
    
    91Dividends received from
unconsolidated
affiliates
    
    
    7
    
    
    
    
    
    
    
    
    
    
    
    18
    
    
    
    22
    
    
    
    8
    
    
    
    55Additions to property,
plant and equipment
    
    
    1,891
    
    
    
    26
    
    
    
    13
    
    
    
    226
    
    
    
    159
    
    
    
    49
    
    
    
    2,364Identifiable assets
    
    
    6,903
    
    
    
    433
    
    
    
    1,132
    
    
    
    2,483
    
    
    
    2,648
    
    
    
    2,204
    
    
    
    15,803Investments in and
advances to
unconsolidated affiliates
    
    
    160
    
    
    
    132
    
    
    
    39
    
    
    
    285
    
    
    
    271
    
    
    
    180
    
    
    
    1,067Total assets
    
    
    7,063
    
    
    
    565
    
    
    
    1,171
    
    
    
    2,768
    
    
    
    2,919
    
    
    
    2,384
    
    
    
    16,870
 F-80




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##### Table of Contents



i) Derivative financial instruments As described in Note 5, the Company holds several derivative financial
instruments to reduce exposure to crude oil price fluctuations and changes in
interest rates. Changes in the accounting measurement of derivative financial
instruments designated as cash flow hedge, which have been determined as
effective hedge, are recognized under US GAAP in the other comprehensive income
account. The following information refers to the other comprehensive income
accounted for the years ended December 31, 2003, 2002 and 2001: Commodity Price Risk As of December 31, 2003, there are no unrealized gains or losses in the
accumulated other comprehensive income. As of December 31, 2002 and 2001, the
Company has a net unrealized gain of 14 after taxes and a net unrealized loss
of 22 after taxes, respectively, on derivative instruments entered into to
hedge production recorded in accumulated other comprehensive income. Net income
(loss) under US GAAP for 2002 and 2001 fiscal years includes 99 of net loss,
and 44 of net gain, respectively, due to recognition of unrealized gains and
losses related to hedge ineffectiveness. Interest rate risk As of December 31, 2003, 2002 and 2001, the Company has an after taxes net
unrealized loss of 12, 28 and 16, respectively, on a derivative instrument
entered into to hedge interest rate recorded in accumulated other comprehensive
income. Approximately, 9 of net loss in the accumulated other comprehensive
income balance as of December 31, 2003, is expected to be reclassified into
financial expenses during 2004 as hedged transaction occurs. 25. Oil and Gas Supplementary Disclosures (unaudited) The following information for the oil and gas producing activities has
been prepared in accordance with the methodology prescribed by Statement of
Financial Accounting Standards N° 69 Disclosures about Oil and Gas Producing
Activities and includes the Company and its subsidiaries oil and gas
production activities as well as the equity shares in its affiliates valued by
the equity method. The Company has oil and gas properties in the Argentina and
other countries of Latin America; the respective detail is disclosed in Note
27.g. to the financial statements. The amounts derived from minority interest in consolidated subsidiaries
are not significant, therefore, they have not been included. Amounts in millions of pesos are stated as mentioned in Note 2.c. to the
financial statements. F-81




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##### Table of Contents



Capitalized costs The following table presents the capitalized costs as of December 31, 2003
and 2002, for proved and unproved oil and gas properties, and the related
accumulated depreciation, depletion and amortization. 2003
    
    2002Argentine
    
    
    
    
    
    ArgentineGAAP
    
    US GAAP
    
    GAAP
    
    US GAAP(In millions of constant pesos  note 2.c)Consolidated companies:Proved properties:Equipment, camps and other facilities
    
    
    2,036
    
    
    
    1,926
    
    
    
    2,527
    
    
    
    2,354Producing properties and wells
    
    
    7,372
    
    
    
    8,192
    
    
    
    7,012
    
    
    
    7,921Unproved properties
    
    
    569
    
    
    
    569
    
    
    
    950
    
    
    
    950Total capitalized costs
    
    
    9,977
    
    
    
    10,687
    
    
    
    10,489
    
    
    
    11,225Accumulated depreciation, depletion and amortization, and
allowances which reduce the value of assets
    
    
    (3,528
    )
    
    
    (2,913
    )
    
    
    (3,264
    )
    
    
    (2,447
    )Subtotal of consolidated companies
    
    
    6,449
    
    
    
    7,774
    
    
    
    7,225
    
    
    
    8,778Companys share in capitalized costs by unconsolidated
affiliates
    
    
    198
    
    
    
    285
    
    
    
    206
    
    
    
    300Total net capitalized costs
    
    
    6,647
    
    
    
    8,059
    
    
    
    7,431
    
    
    
    9,078
 F-82




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##### Table of Contents



Costs incurred The following table presents those costs capitalized as well as expensed
that were incurred during each of the years ended as of December 31, 2003, 2002
and 2001. The acquisition of properties includes the cost of acquisition of
proved or unproved oil and gas properties. Exploration costs include geological
and geophysical costs, costs necessary for retaining undeveloped properties,
and drilling costs and exploratory well equipment. Development costs include
drilling costs and equipment for developmental wells, costs incurred in
improved recovery, the construction of facilities for extraction, treatment and
storage of hydrocarbons and all necessary costs to maintain facilities for the
existing developed reserves. 2003
    
    2002Argentine and US GAAP
    
    Argentine and US GAAPRest of Latin
    
    
    
    
    
    
    
    
    
    Rest of LatinArgentina
    
    América
    
    Total
    
    Argentina
    
    América
    
    Total(In millions of constant pesos - note 2.c)Consolidated CompaniesAcquisition of properiesProved
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    26
    
    
    
    
    
    
    
    26Unproved
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Exploration Costs
    
    
    
    
    
    
    103
    
    
    
    103
    
    
    
    22
    
    
    
    67
    
    
    
    89Developement Costs
    
    
    343
    
    
    
    346
    
    
    
    689
    
    
    
    222
    
    
    
    262
    
    
    
    484Total Costs incurred by
consolidated companies
    
    
    343
    
    
    
    449
    
    
    
    792
    
    
    
    270
    
    
    
    329
    
    
    
    599Companys share in
costs incurred by
unconsolidated
companies
    
    
    9
    
    
    
    5
    
    
    
    14
    
    
    
    7
    
    
    
    10
    
    
    
    17Total costs incurred
    
    
    352
    
    
    
    454
    
    
    
    806
    
    
    
    277
    
    
    
    339
    
    
    
    616
 2001Argentine and US GAAPRest of LatinArgentina
    
    América
    
    Total(In millions of constant pesos - note 2.c)Consolidated CompaniesAcquisition of properiesProved
    
    
    468
    
    
    
    71
    
    
    
    539Unproved
    
    
    173
    
    
    
    132
    
    
    
    305Exploration Costs
    
    
    35
    
    
    
    22
    
    
    
    57Developement Costs
    
    
    497
    
    
    
    736
    
    
    
    1,233Total Costs incurred by
consolidated companies
    
    
    1,173
    
    
    
    961
    
    
    
    2,134Companys share in
costs incurred by
unconsolidated
companies
    
    
    7
    
    
    
    46
    
    
    
    53Total costs incurred
    
    
    1,180
    
    
    
    1,007
    
    
    
    2,187
 F-83




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##### Table of Contents



Results of operations The breakdown of results of the operations shown below summarizes revenues
and expenses directly associated with oil and gas producing activities for the
years ended December 31, 2003, 2002 and 2001. These activities are a part of
the Oil and Gas Exploration and Production segment. This breakdown does not
include any allocation of financial costs or expenses from Corporate and
therefore it is not necessarily an indicator of the contribution in operations
for oil and gas producing activities to the net income of the Company. Income
tax for the years presented was calculated utilizing the deferred income tax
criteria. 2003Argentine GAAP
    
    US GAAPRest of
    
    
    
    
    
    
    
    
    
    Rest ofLatin
    
    
    
    
    
    
    
    
    
    LatinArgentina
    
    América
    
    Total
    
    Argentina
    
    América
    
    Total(In millions of constant pesos - note 2.c)Results of operations of consolidated
companies:Net sales:- to third parties
    
    
    594
    
    
    
    1,191
    
    
    
    1,785
    
    
    
    681
    
    
    
    1,191
    
    
    
    1,872- transfers to other operations
    
    
    944
    
    
    
    
    
    
    
    944
    
    
    
    944
    
    
    
    
    
    
    
    944Total net sales
    
    
    1,538
    
    
    
    1,191
    
    
    
    2,729
    
    
    
    1,625
    
    
    
    1,191
    
    
    
    2,816Production costs:- Operating Costs
    
    
    (242
    )
    
    
    (247
    )
    
    
    (489
    )
    
    
    (242
    )
    
    
    (247
    )
    
    
    (489
    )- Royalties and other
    
    
    (245
    )
    
    
    (161
    )
    
    
    (406
    )
    
    
    (245
    )
    
    
    (161
    )
    
    
    (406
    )Total production costs
    
    
    (487
    )
    
    
    (408
    )
    
    
    (895
    )
    
    
    (487
    )
    
    
    (408
    )
    
    
    (895
    )Exploration costs
    
    
    (11
    )
    
    
    (185
    )
    
    
    (196
    )
    
    
    (11
    )
    
    
    (185
    )
    
    
    (196
    )Depreciation, depletion, amortization
and allowances which reduce the value
of assets
    
    
    (368
    )
    
    
    (593
    )
    
    
    (961
    )
    
    
    (388
    )
    
    
    (726
    )
    
    
    (1,114
    )Results of operations before income tax
    
    
    672
    
    
    
    5
    
    
    
    677
    
    
    
    739
    
    
    
    (128
    )
    
    
    611Income tax
    
    
    (235
    )
    
    
    (1
    )
    
    
    (236
    )
    
    
    (228
    )
    
    
    46
    
    
    
    (182
    )Results of
operations - consolidated companies
    
    
    437
    
    
    
    4
    
    
    
    441
    
    
    
    511
    
    
    
    (82
    )
    
    
    429Companys share in results of
operations by unconsolidated affiliates
    
    
    13
    
    
    
    5
    
    
    
    18
    
    
    
    9
    
    
    
    2
    
    
    
    11Total
    
    
    450
    
    
    
    9
    
    
    
    459
    
    
    
    520
    
    
    
    (80
    )
    
    
    440
 F-84




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##### Table of Contents



2002Argentine GAAP
    
    US GAAPRest of
    
    
    
    
    
    
    
    
    
    Rest ofLatin
    
    
    
    
    
    
    
    
    
    LatinArgentina
    
    América
    
    Total
    
    Argentina
    
    América
    
    Total(In millions of constant pesos - note 2.c)Results of operations of consolidated
companies:Net sales:- to third parties
    
    
    849
    
    
    
    1,184
    
    
    
    2,033
    
    
    
    1,006
    
    
    
    1,292
    
    
    
    2,298- transfers to other operations
    
    
    773
    
    
    
    
    
    
    
    773
    
    
    
    777
    
    
    
    
    
    
    
    777Total net sales
    
    
    1,622
    
    
    
    1,184
    
    
    
    2,806
    
    
    
    1,783
    
    
    
    1,292
    
    
    
    3,075Production costs:- Operating Costs
    
    
    (257
    )
    
    
    (267
    )
    
    
    (524
    )
    
    
    (236
    )
    
    
    (267
    )
    
    
    (503
    )- Royalties and other
    
    
    (238
    )
    
    
    (159
    )
    
    
    (397
    )
    
    
    (238
    )
    
    
    (159
    )
    
    
    (397
    )Total production costs
    
    
    (495
    )
    
    
    (426
    )
    
    
    (921
    )
    
    
    (474
    )
    
    
    (426
    )
    
    
    (900
    )Exploration costs
    
    
    (21
    )
    
    
    (37
    )
    
    
    (58
    )
    
    
    (21
    )
    
    
    (37
    )
    
    
    (58
    )Depreciation, depletion, amortization
and allowances which reduce the value
of assets
    
    
    (356
    )
    
    
    (391
    )
    
    
    (747
    )
    
    
    (395
    )
    
    
    (593
    )
    
    
    (988
    )Results of operations before income tax
    
    
    750
    
    
    
    330
    
    
    
    1,080
    
    
    
    893
    
    
    
    236
    
    
    
    1,129Income tax
    
    
    (280
    )
    
    
    (32
    )
    
    
    (312
    )
    
    
    (519
    )
    
    
    102
    
    
    
    (417
    )Results of operations  consolidated
companies
    
    
    470
    
    
    
    298
    
    
    
    768
    
    
    
    374
    
    
    
    338
    
    
    
    712Companys share in results of
operations by unconsolidated affiliates
    
    
    23
    
    
    
    8
    
    
    
    31
    
    
    
    20
    
    
    
    
    
    
    
    20Total
    
    
    493
    
    
    
    306
    
    
    
    799
    
    
    
    394
    
    
    
    338
    
    
    
    732
 F-85




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##### Table of Contents



2001Argentine GAAP
    
    US GAAPRest of
    
    
    
    
    
    
    
    
    
    Rest ofLatin
    
    
    
    
    
    
    
    
    
    LatinArgentina
    
    América
    
    Total
    
    Argentina
    
    América
    
    Total(In millions of constant pesos - note 2.c)Results of operations of consolidated
companies:Net sales:- to third parties
    
    
    714
    
    
    
    787
    
    
    
    1,501
    
    
    
    827
    
    
    
    796
    
    
    
    1,623- transfers to other operations
    
    
    475
    
    
    
    
    
    
    
    475
    
    
    
    475
    
    
    
    
    
    
    
    475Total net sales
    
    
    1,189
    
    
    
    787
    
    
    
    1,976
    
    
    
    1,302
    
    
    
    796
    
    
    
    2,098Production costs:- Operating Costs
    
    
    (272
    )
    
    
    (162
    )
    
    
    (434
    )
    
    
    (264
    )
    
    
    (154
    )
    
    
    (418
    )- Royalties and other
    
    
    (218
    )
    
    
    (97
    )
    
    
    (315
    )
    
    
    (218
    )
    
    
    (97
    )
    
    
    (315
    )Total production costs
    
    
    (490
    )
    
    
    (259
    )
    
    
    (749
    )
    
    
    (482
    )
    
    
    (251
    )
    
    
    (733
    )Exploration costs
    
    
    (20
    )
    
    
    (21
    )
    
    
    (41
    )
    
    
    (20
    )
    
    
    (22
    )
    
    
    (42
    )Depreciation, depletion, amortization
and allowances which reduce the value
of assets
    
    
    (332
    )
    
    
    (181
    )
    
    
    (513
    )
    
    
    (376
    )
    
    
    (301
    )
    
    
    (677
    )Results of operations before income tax
    
    
    347
    
    
    
    326
    
    
    
    673
    
    
    
    424
    
    
    
    222
    
    
    
    646Income tax
    
    
    (125
    )
    
    
    (57
    )
    
    
    (182
    )
    
    
    (231
    )
    
    
    (103
    )
    
    
    (334
    )Results of operations  consolidated
companies
    
    
    222
    
    
    
    269
    
    
    
    491
    
    
    
    193
    
    
    
    119
    
    
    
    312Companys share in results of
operations by unconsolidated
affiliates
    
    
    9
    
    
    
    4
    
    
    
    13
    
    
    
    4
    
    
    
    2
    
    
    
    6Total
    
    
    231
    
    
    
    273
    
    
    
    504
    
    
    
    197
    
    
    
    121
    
    
    
    318
 F-86




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##### Table of Contents



Estimated oil and gas reserves Proved reserves represent estimated quantities of oil (including crude
oil, condensate and natural gas liquids) and natural gas, which available
geological and engineering data demonstrates with reasonable certainty to be
recoverable in the future from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods. The Company believes that its estimates of remaining proved recoverable
oil and gas reserve volumes are reasonable and such estimates have been
prepared in accordance with Rule 4-10 of Regulation S-X, the Companys reserve
estimates as of December 31, 2003, 2002 and 2001, were audited by Gaffney,
Cline & Associates Inc., international technical advisors. The choice of method
or combination of methods employed in the analysis of each reservoir was
determined by the stage of development, quality and reliability of basic data,
and production history. Reserves engineering is a subjective process of estimation of hydrocarbon
accumulation, which cannot be accurately measured, and the reserve estimation
depends on the quality of available information and the interpretation and
judgment of the engineers and geologists. Therefore, the reserves estimations,
as well as future production profiles, are often different than the quantities
of hydrocarbons which are finally recovered. The accuracy of such estimations
depends, in general, on the assumptions on which they are based. The following table sets forth the estimated proved reserves of oil
(includes crude oil, condensate and natural gas liquids) and natural gas as of
December 31, 2003, 2002 and 2001: F-87




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##### Table of Contents



CRUDE OIL, CONDENSATE ANDNATURAL GAS LIQUIDS INTHOUSAND OF BARRELSCONSOLIDATED
    
    UNCONSOLIDATEDCOMPANIES
    
    COMPANIESProved reserves
    
    
    
    
    
    REST OF
    
    
    
    
    
    REST OF(developed and
    
    
    
    
    
    LATIN-
    
    
    
    
    
    LATIN-undeveloped)
    
    ARGENTINA
    
    AMERICA
    
    ARGENTINA
    
    AMERICA
    
    TOTALReserves as of
December 31,2000
    
    
    286,321
    
    
    
    474,794
    
    
    
    8,270
    
    
    
    44,779
    
    
    
    814,164Increase(Decrease)
originated in:Revisions of
previous
estimates
    
    
    (31,960
    )
    
    
    (17,103
    )
    
    
    (2,519
    )
    
    
    (956
    )
    
    
    (52,538
    )Improved recovery
    
    
    12,596
    
    
    
    17,913
    
    
    
    1,670
    
    
    
    177
    
    
    
    32,356Extensions and
discoveries
    
    
    14,303
    
    
    
    17,769
    
    
    
    
    
    
    
    830
    
    
    
    32,902Purchase of
proved reserves
in place
    
    
    24,115
    
    
    
    18,398
    
    
    
    
    
    
    
    
    
    
    
    42,513Sale of proved
reserves in place
    
    
    (50,816
    )
    
    
    
    
    
    
    
    
    
    
    (32,632
    )
    
    
    (83,448
    )Years production
    
    
    (24,122
    )
    
    
    (21,645
    )
    
    
    (578
    )
    
    
    (432
    )
    
    
    (46,777
    )Reserves as of
December 31,2001
    
    
    230,437
    
    
    
    490,126
    
    
    
    6,843
    
    
    
    11,766
    
    
    
    739,172Increase (Decrease)
originated in:Revisions of
previous
estimates
    
    
    (14,493
    )
    
    
    (112,545
    )
    
    
    (375
    )
    
    
    (880
    )
    
    
    (128,293
    )Improved recovery
    
    
    4,027
    
    
    
    3,510
    
    
    
    168
    
    
    
    
    
    
    
    7,705Extensions and
discoveries
    
    
    6,839
    
    
    
    9,596
    
    
    
    99
    
    
    
    461
    
    
    
    16,995Purchase of
proved reserves
in place
    
    
    516
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    516Sale of proved
reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Years production
    
    
    (20,225
    )
    
    
    (21,029
    )
    
    
    (494
    )
    
    
    (469
    )
    
    
    (42,217
    )Reserves as of
December 31,2002
    
    
    207,101
    
    
    
    369,658
    
    
    
    6,241
    
    
    
    10,878
    
    
    
    593,878Increase (Decrease)
originated in:Revisions of
previous
estimates
    
    
    (18,987
    )
    
    
    (3,215
    )
    
    
    (39
    )
    
    
    (63
    )
    
    
    (22,304
    )Improved recovery
    
    
    9,292
    
    
    
    15,045
    
    
    
    790
    
    
    
    347
    
    
    
    25,474Extensions and
discoveries
    
    
    3,174
    
    
    
    18,303
    
    
    
    84
    
    
    
    
    
    
    
    21,561Purchase of
proved reserves
in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Sale of proved
reserves in place
    
    
    (7,707
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (7,707
    )Years production
    
    
    (20,538
    )
    
    
    (20,367
    )
    
    
    (559
    )
    
    
    (376
    )
    
    
    (41,840
    )Reserves as of
December 31,2003
    
    
    172,335
    
    
    
    379,424
    
    
    
    6,517
    
    
    
    10,786
    
    
    
    569,062Proved developed reserves:As of December 31, 2000
    
    
    178,844
    
    
    
    172,702
    
    
    
    6,278
    
    
    
    17,245
    
    
    
    375,069As of December 31, 2001
    
    
    147,560
    
    
    
    198,964
    
    
    
    4,364
    
    
    
    4,844
    
    
    
    355,732As of December 31, 2002
    
    
    141,891
    
    
    
    173,820
    
    
    
    4,428
    
    
    
    4,056
    
    
    
    324,195As of December 31, 2003
    
    
    117,765
    
    
    
    166,349
    
    
    
    4,320
    
    
    
    3,576
    
    
    
    292,010
   [Continued from above table, first column(s) repeated] NATURAL GAS IN MILLIONOF CUBIC FEETSCONSOLIDATED
    
    UNCONSOLIDATEDCOMPANIES
    
    COMPANIESProved reserves
    
    
    
    
    
    REST OF
    
    
    
    
    
    REST OF(developed and
    
    
    
    
    
    LATIN-
    
    
    
    
    
    LATIN-undeveloped)
    
    ARGENTINA
    
    AMERICA
    
    ARGENTINA
    
    AMERICA
    
    TOTALReserves as of
December 31,2000
    
    
    1,162,028
    
    
    
    421,810
    
    
    
    24,975
    
    
    
    1,162,492
    
    
    
    2,771,305Increase(Decrease)
originated in:Revisions of
previous
estimates
    
    
    (402,740
    )
    
    
    48,114
    
    
    
    (7,054
    )
    
    
    
    
    
    
    (361,680
    )Improved recovery
    
    
    20,605
    
    
    
    18,605
    
    
    
    1,798
    
    
    
    
    
    
    
    41,008Extensions and
discoveries
    
    
    71,307
    

    
    
    30,582
    
    
    
    
    
    
    
    
    
    
    
    101,889Purchase of
proved reserves
in place
    
    
    376,365
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    376,365Sale of proved
reserves in place
    
    
    (18,002
    )
    
    
    
    
    
    
    
    
    
    
    (1,162,492
    )
    
    
    (1,180,494
    )Years production
    
    
    (98,206
    )
    
    
    (24,058
    )
    
    
    (1,590
    )
    
    
    
    
    
    
    (123,854
    )Reserves as of
December 31,2001
    
    
    1,111,357
    
    
    
    495,053
    
    
    
    18,129
    
    
    
    
    
    
    
    1,624,539Increase (Decrease)
originated in:Revisions of
previous
estimates
    
    
    (247,448
    )
    
    
    (123,594
    )
    
    
    (10,702
    )
    
    
    
    
    
    
    (381,744
    )Improved recovery
    
    
    64,550
    
    
    
    9,687
    
    
    
    11,821
    
    
    
    
    
    
    
    86,058Extensions and
discoveries
    
    
    88,265
    
    
    
    10,662
    
    
    
    
    
    
    
    
    
    
    
    98,927Purchase of
proved reserves
in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Sale of proved
reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Years production
    
    
    (90,860
    )
    
    
    (22,352
    )
    
    
    (1,324
    )
    
    
    
    
    
    
    (114,536
    )Reserves as of
December 31,2002
    
    
    925,864
    
    
    
    369,456
    
    
    
    17,924
    
    
    
    
    
    
    
    1,313,244Increase (Decrease)
originated in:Revisions of
previous
estimates
    
    
    (127,415
    )
    
    
    23,110
    
    
    
    (4,549
    )
    
    
    
    
    
    
    (108,854
    )Improved recovery
    
    
    
    
    
    
    7,261
    
    
    
    
    
    
    
    
    
    
    
    7,261Extensions and
discoveries
    
    
    60,416
    
    
    
    7,571
    
    
    
    954
    
    
    
    
    
    
    
    68,941Purchase of
proved reserves
in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Sale of proved
reserves in place
    
    
    (49,450
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (49,450
    )Years production
    
    
    (72,819
    )
    
    
    (22,517
    )
    
    
    (1,006
    )
    
    
    
    
    
    
    (96,342
    )Reserves as of
December 31,2003
    
    
    736,596
    
    
    
    384,881
    
    
    
    13,323
    
    
    
    
    
    
    
    1,134,800Proved developed reserves:As of December 31, 2000
    
    
    495,936
    
    
    
    241,754
    
    
    
    19,793
    
    
    
    473,684
    
    
    
    1,080,125As of December 31, 2001
    
    
    548,526
    
    
    
    290,638
    
    
    
    13,308
    
    
    
    
    
    
    
    852,472As of December 31, 2002
    
    
    539,731
    
    
    
    209,854
    
    
    
    14,373
    
    
    
    
    
    
    
    763,958As of December 31, 2003
    
    
    444,951
    
    
    
    207,144
    
    
    
    10,514
    
    
    
    
    
    
    
    662,609
 F-88




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##### Table of Contents



The estimated reserves were subjected to economic tests to determine
economic limits. Such estimated reserves in Argentina, Perú and Bolivia, are
stated prior to the payment of any royalties as they have the same attributes
as taxes on production and, therefore, are treated as operating costs. In
Ecuador, due to the type of contract in which the Government has the right to a
percentage of production and takes it in kind, the reserves are stated after
such percentage. In Venezuela, the Company receives, for its interest in the
Oritupano-Leona Block, a fee per barrel delivered to the Government of
Venezuela. Additionally, the Company receives a fee for reimbursement of
certain capital expenditures. In the Mata, Acema and La Concepción areas, the
Company collects a variable fee per barrel delivered that contemplates
production costs plus a mark-up. Under these contracts, the Venezuelan
government maintains full ownership of all hydrocarbons in fields. The reserve
volumes in Venezuela are computed by multiplying the Companys working interest
by the gross proved recoverable volumes for the contract area, In accordance
with the agreement governing current petroleum operations in Venezuela. The
Company is exempt from production royalty payments. Had the economic method of calculating proved reserves (future expected
cash flows of each field divided by the oil market prices at year end) been
used, the reported amounts of crude oil, condensate and natural gas liquids
proved reserves for consolidated companies in Rest of Latin America would
have decreased by approximately 22.9 %, 28.4 % and 14.6 % , and the reported
crude oil, condensate and natural gas liquids proved reserves for
unconsolidated companies in Rest of Latin America would have decreased by
approximately 37.3 %, 42 % and 30.1 % as of December 31, 2003, 2002 and 2001,
respectively. The information in this paragraph was not audited by Gaffney,
Cline & Associates. Standardized measure of discounted future net cash flows The following table discloses estimated future net cash flows from future
production of proved developed and undeveloped reserves of crude oil,
condensate, natural gas liquids and natural gas. As prescribed by Statement of
Financial Accounting Standards N° 69, such future net cash flows were estimated
using each year-end prices and costs held constant for the life of the reserves
(except in such circumstances in which the sale of hydrocarbons is governed by
contracts fixing the sale price or its escalation) and using a 10% annual
discount factor. Future development costs include estimated drilling costs,
exploitation installations and abandonment costs. These future development
costs were estimated based on evaluations made by the Company and the operators
of the fields in which the Company has an interest. The future income tax was
calculated by applying the tax rate in effect as of the date this supplementary
information was filed. This standardized measure is not intended to be and should not be
interpreted as an estimate of the market value of the Companys reserves. The
purpose of this information is to give standardized data to help the users of
the financial statements to compare different companies and make certain
projections. It is important to point out that this information does not
include, among other items, the effect of future changes in prices, costs and
tax rates, which past experience indicates that are likely to occur, as well as
the effect of future cash flows from reserves which have not yet been
classified as proved reserves, of a discount factor more representative of the
value of money over the lapse of time and of the risks inherent to the
production of oil and gas. These future changes may have a significant impact
on the future net cash flows disclosed below. For all these reasons, this
information does not necessarily indicate the perception the Company has on the
discounted future net cash flows derived from the reserves of hydrocarbons. F-89




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##### Table of Contents



2003
    
    2002
    
    2001Rest of
    
    
    
    
    
    
    
    
    
    Rest of
    
    
    
    
    
    
    
    
    
    Rest ofLatin-
    
    
    
    
    
    
    
    
    
    Latin-
    
    
    
    
    
    
    
    
    
    Latin-Argentina
    
    America
    
    Total
    
    Argentina
    
    America
    
    Total
    
    Argentina
    
    America
    
    Total(in millions of constant pesos  note 2.c.)Consolidated companies:Future cash flows
    
    
    15,158
    
    
    
    22,513
    
    
    
    37,671
    
    
    
    19,873
    
    
    
    25,149
    
    
    
    45,022
    
    
    
    18,715
    
    
    
    25,951
    
    
    
    44,666Future production costs
    
    
    (3,522
    )
    
    
    (6,653
    )
    
    
    (10,175
    )
    
    
    (3,793
    )
    
    
    (6,994
    )
    
    
    (10,787
    )
    
    
    (5,122
    )
    
    
    (8,945
    )
    
    
    (14,067
    )Future development and
abandonment costs
    
    
    (1,379
    )
    
    
    (2,875
    )
    
    
    (4,254
    )
    
    
    (1,389
    )
    
    
    (3,023
    )
    
    
    (4,412
    )
    
    
    (1,837
    )
    
    
    (4,184
    )
    
    
    (6,021
    )Future income tax
    
    
    (3,158
    )
    
    
    (3,308
    )
    
    
    (6,466
    )
    
    
    (4,794
    )
    
    
    (3,868
    )
    
    
    (8,662
    )
    
    
    (3,431
    )
    
    
    (2,849
    )
    
    
    (6,280
    )Future net cash flows
    
    
    7,099
    
    
    
    9,677
    
    
    
    16,776
    
    
    
    9,897
    
    
    
    11,264
    
    
    
    21,161
    
    
    
    8,325
    
    
    
    9,973
    
    
    
    18,29810% annual discount
    
    
    (2,784
    )
    
    
    (4,466
    )
    
    
    (7,250
    )
    
    
    (4,079
    )
    
    
    (5,268
    )
    
    
    (9,347
    )
    
    
    (3,359
    )
    
    
    (4,957
    )
    
    
    (8,316
    )Subtotal of
consolidated companies
    
    
    4,315
    
    
    
    5,211
    
    
    
    9,526
    
    
    
    5,818
    
    
    
    5,996
    
    
    
    11,814
    
    
    
    4,966
    
    
    
    5,016
    
    
    
    9,982Companys share in
standardized measure
by unconsolidated
affiliates
    
    
    150
    
    
    
    117
    
    
    
    267
    
    
    
    156
    
    
    
    143
    
    
    
    299
    
    
    
    117
    
    
    
    136
    
    
    
    253Total
    
    
    4,465
    
    
    
    5,328
    
    
    
    9,793
    
    
    
    5,974
    
    
    
    6,139
    
    
    
    12,113
    
    
    
    5,083
    
    
    
    5,152
    
    
    
    10,235
 As described in Note 5, the Company uses various derivative financial
instruments to mitigate the impact of changes in crude oil prices. Had such
instruments been considered, the effects on (a) Future cash flows and (b) Total
would have been as follows: 2003
    
    2002
    
    2001Rest of
    
    
    
    
    
    
    
    
    
    Rest of
    
    
    
    
    
    
    
    
    
    Rest ofLatin-
    
    
    
    
    
    
    
    
    
    Latin-
    
    
    
    
    
    
    
    
    
    Latin-Argentina
    
    America
    
    Total
    
    Argentina
    
    America
    
    Total
    
    Argentina
    
    America
    
    TotalEffect on  increase (decrease):(a) Future cash flows
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (38
    )
    
    
    
    
    
    
    (38
    )
    
    
    (9
    )
    
    
    20
    
    
    
    11(b) Total
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (22
    )
    
    
    
    
    
    
    (22
    )
    
    
    (7
    )
    
    
    11
    
    
    
    4
 F-90




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##### Table of Contents



Changes in the standardized measure of discounted future net cash flows The following table discloses the changes in the standardized measure of
discounted future net cash flows for the years ended December 31, 2003, 2002
and 2001: Consolidated and unconsolidated Companies2003
    
    2002
    
    2001Rest of
    
    
    
    
    
    
    
    
    
    Rest of
    
    
    
    
    
    
    
    
    
    Rest ofLatin-
    
    
    
    
    
    
    
    
    
    Latin-
    
    
    
    
    
    
    
    
    
    Latin-Argentina
    
    America
    
    Total
    
    Argentina
    
    America
    
    Total
    
    Argentina
    
    America
    
    Total(in millions of constant pesos - note 2.c.)Standardized measure at beginning of year
    
    
    5,974
    
    
    
    6,139
    
    
    
    12,113
    
    
    
    5,083
    
    
    
    5,152
    
    
    
    10,235
    
    
    
    3,697
    
    
    
    4,109
    
    
    
    7,806Changes related to oil & gas activities:Sales net of production costs
    
    
    (1,161
    )
    
    
    (805
    )
    
    
    (1,966
    )
    
    
    (1,396
    )
    
    
    (900
    )
    
    
    (2,296
    )
    
    
    (989
    )
    
    
    (574
    )
    
    
    (1,563
    )Net change in sales prices, net of future production costs
    
    
    (1,520
    )
    
    
    (2,015
    )
    
    
    (3,535
    )
    
    
    2,675
    
    
    
    3,245
    
    
    
    5,920
    
    
    
    1,815
    
    
    
    2,429
    
    
    
    4,244Changes in future development costs
    
    
    (325
    )
    
    
    (112
    )
    
    
    (437
    )
    
    
    192
    
    
    
    793
    
    
    
    985
    
    
    
    (710
    )
    
    
    (1,845
    )
    
    
    (2,555
    )Extensions, discoveries and improved recovery, net of
futures production and associated costs
    
    
    444
    
    
    
    800
    
    
    
    1,244
    
    
    
    905
    
    
    
    256
    
    
    
    1,161
    
    
    
    802
    
    
    
    736
    
    
    
    1,538Development costs incurred
    
    
    351
    
    
    
    352
    
    
    
    703
    
    
    
    229
    
    
    
    272
    
    
    
    501
    
    
    
    504
    
    
    
    783
    
    
    
    1,287Revisions of quantity estimates
    
    
    (1,003
    )
    
    
    (56
    )
    
    
    (1,059
    )
    
    
    (1,072
    )
    
    
    (2,774
    )
    
    
    (3,846
    )
    
    
    (1,785
    )
    
    
    (182
    )
    
    
    (1,967
    )Purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    15
    
    
    
    
    
    
    
    15
    
    
    
    1,036
    
    
    
    145
    
    
    
    1,181Sale of reserves in place
    
    
    (164
    )
    
    
    
    
    
    
    (164
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (466
    )
    
    
    (805
    )
    
    
    (1,271
    )Net change in income taxes
    
    
    944
    
    
    
    230
    
    
    
    1,174
    
    
    
    (792
    )
    
    
    (673
    )
    
    
    (1,465
    )
    
    
    (480
    )
    
    
    (156
    )
    
    
    (636
    )Accretion of discount
    
    
    899
    
    
    
    835
    
    
    
    1,734
    
    
    
    730
    
    
    
    669
    
    
    
    1,399
    
    
    
    461
    
    
    
    472
    
    
    
    933Changes in production rates
    
    
    (30
    )
    
    
    (181
    )
    
    
    (211
    )
    
    
    (578
    )
    
    
    353
    
    
    
    (225
    )
    
    
    1,125
    
    
    
    (257
    )
    
    
    868Other changes
    
    
    56
    
    
    
    141
    
    
    
    197
    
    
    
    (17
    )
    
    
    (254
    )
    
    
    (271
    )
    
    
    73
    
    
    
    297
    
    
    
    370Standardized measure at end of year
    
    
    4,465
    
    
    
    5,328
    
    
    
    9,793
    
    
    
    5,974
    
    
    
    6,139
    
    
    
    12,113
    
    
    
    5,083
    
    
    
    5,152
    
    
    
    10,235
 F-91




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##### Table of Contents



26. Subsequent events  a)
    
    Master settlement and mutual release agreement for CIESA In April 2004, the shareholders of CIESA reached a framework agreement
whereby Petrobras Energía and Enron will reciprocally waive any right to make
claims arising from or related to certain agreements executed by such groups in
connection with their interests in CIESA and TGS. In addition, and in order to
provide the flexibility necessary to make progress in restructuring CIESAs
financial debt, the framework agreement also provides for the transfer in two
phases of certain shares issued by TGS and CIESA. During the first phase (a)
Enron will transfer 40% of the shares issued by CIESA to a trust to be
organized or an alternative entity; and (b) Petrobras Energía will transfer
common class B            shares issued by TGS (representing 7.35% of the capital stock
of TGS) to Enron. During the second phase, Enron will transfer its remaining
interest in CIESA to the abovementioned trust or to an alternative institution
while CIESA will simultaneously transfer common class B            shares issued by TGS
(representing about 4.3 % of the capital stock of TGS) to Enron. In no case
shall Petrobras Energía hold (directly or indirectly) more than 50% of the
capital stock currently held in CIESA or any controlling interest in CIESA. The
transfers are subject to certain conditions, one of which is the approval by
the ENARGAS (Argentine gas regulatory agency), which is pending. The framework
agreement was subject to the definitive and unappealable approval by the
Bankruptcy Court competent in the Enron bankruptcy, which has already been
obtained.  b)
    
    Corporate bond issuance On April 30, 2004, Petrobras Energía issued the second series of Class R
medium-term corporate bonds for a total face value amounting to US$ 100 million
(the New Class R Corporate Bonds) which make up a single and fungible class
with medium-term corporate bonds for a face value of US$ 100 million issued on
October 31, 2003. The New Class R Corporate Bonds will mature on October 30,
2013, and accrue interest at 9.375% p.a. The funds were used to settle
existing liabilities.  c)
    
    Increase in our share in OCP: The Company and Tenco entered into a put and call option agreement whereby
Tenco granted the Company the irrevocable option to require Tenco to sell to
the Company the shares and subordinated debt comprising its 2.46% ownership
interest, and the Company granted to Tenco the irrevocable option to require
the Company to purchase from Tenco the shares and subordinated debt comprising
its ownership interest. On May 2004, the option was exercised by Tenco,
causing the Company to pay U$S 14 million. Consequently, the Companys current
interest in OCP increased to 11.42%. 27. Other consolidated information The following tables present additional consolidated financial statement
disclosures required under Argentine GAAP.  a)
    
    Property, plant and equipment.b)
    
    Equity in affiliatesc)
    
    Costs of sales.d)
    
    Foreign currency assets and liabilities.e)
    
    Consolidated detail of expenses incurred and depreciation.f)
    
    Information about ownership in subsidiaries and affiliates.g)
    
    Oil and gas areas and participation in joint ventures.h)
    
    Combined joint ventures and consortia assets, liabilities and results. F-92




---



##### Table of Contents



a)
    
    Property, plant and equipment as of December 31, 2003, 2002 and 2001
(Stated in millions of Argentine Pesos  See Note 2.c) 2003Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hidrocarbons
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    Marketing
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    
    
    
    
    and
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Electricity
    
    Transportation
    
    Eliminations
    
    TotalNet book value at beginning of the year
    
    
    7,225
    
    
    
    178
    
    
    
    770
    
    
    
    2,123
    
    
    
    
    
    
    
    137
    
    
    
    10,433Net book value at begining from
proportional interest in CIESA
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,198
    
    
    
    
    
    
    
    2,198Effect of translation
    
    
    (631
    )
    
    
    
    
    
    
    (78
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (709
    )Net increase
    
    
    508
    
    
    
    23
    
    
    
    37
    
    
    
    40
    
    
    
    12
    
    
    
    33
    
    
    
    653Depreciation
    
    
    653
    
    
    
    20
    
    
    
    77
    
    
    
    147
    
    
    
    86
    
    
    
    33
    
    
    
    1,016Net book value at end of year
    
    
    6,449
    
    
    
    181
    
    
    
    652
    
    
    
    2,016
    
    
    
    2,124
    
    
    
    137
    
    
    
    11,559
 2002Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hidrocarbons
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    Marketing
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    
    
    
    
    and
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Electricity
    
    Transportation
    
    Eliminations
    
    TotalNet book value at beginning of the year
    
    
    5,888
    
    
    
    191
    
    
    
    633
    
    
    
    2,236
    
    
    
    2,244
    
    
    
    441
    
    
    
    11,633CIESA decolsolidation
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (2,244
    )
    
    
    
    
    
    
    (2,244
    )Effect of translation
    
    
    1,720
    
    
    
    
    
    
    
    201
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,921Net increase
    
    
    366
    
    
    
    5
    
    
    
    30
    
    
    
    37
    
    
    
    
    
    
    
    (264
    )
    
    
    174Depreciation
    
    
    749
    
    
    
    18
    
    
    
    94
    
    
    
    150
    
    
    
    
    
    
    
    40
    
    
    
    1,051Net book value at end of year
    
    
    7,225
    
    
    
    178
    
    
    
    770
    
    
    
    2,123
    
    
    
    
    
    
    
    137
    
    
    
    10,433
 2001Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hidrocarbons
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    Marketing
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    
    
    
    
    and
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Electricity
    
    Transportation
    
    Eliminations
    
    TotalNet book value at beginning of the year
    
    
    4,511
    
    
    
    180
    
    
    
    684
    
    
    
    774
    
    
    
    
    
    
    
    424
    
    
    
    6,573Net book value at begining from
proportional interest in CIESA and
DISTRILEC
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,467
    
    
    
    2,106
    
    
    
    
    
    
    
    3,573Net increase
    
    
    1,891
    
    
    
    26
    
    
    
    13
    
    
    
    159
    
    
    
    226
    
    
    
    49
    
    
    
    2,364Depreciation
    
    
    514
    
    
    
    15
    
    
    
    64
    
    
    
    164
    
    
    
    88
    
    
    
    32
    
    
    
    877Net book value at end of year
    
    
    5,888
    
    
    
    191
    
    
    
    633
    
    
    
    2,236
    
    
    
    2,244
    
    
    
    441
    
    
    
    11,633
 F-93




---



##### Table of Contents



b)
    
    Equity in affiliates
(Stated in millions of Argentine Pesos - See Note 2.c) 2003Description of securitiesFaceCompany
    
    value
    
    Amount
    
    Cost
    
    Book valueSharesCitelec S.A.
    
    $
    1
    
    
    
    73,154,437
    
    
    
    298
    
    
    
    158Coroil S.A.
    
    Bs
    1.000
    
    
    
    490
    
    
    
    47
    
    
    
    56Empresa Boliviana de Refinación S.A.
    
    $Bl
    1.000
    
    
    
    178,752
    
    
    
    103
    
    
    
    114Enron de inversiones de Energía S.C.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hidroneuquén S.A.
    
    $
    10
    
    
    
    25,744,097
    
    
    
    26
    
    
    
    16Inversora Mata S.A.
    
    Bs
    1.000
    
    
    
    490
    
    
    
    72
    
    
    
    98Oleoducto de Crudos Pesados Ltd.
    
    U$S
    0,01
    
    
    
    31,500
    
    
    
    98
    
    

    
    81Oleoductos del Valle S.A.
    
    $
    10
    
    
    
    2,542,716
    
    
    
    61
    
    
    
    80Petrolera Entre Lomas S.A.
    
    $
    1
    
    
    
    96,050
    
    
    
    2
    
    
    
    45Petroquímica Cuyo S.A.
    
    $
    0,083
    
    
    
    240,000,000
    
    
    
    43
    
    
    
    46Refinería del Norte S.A.
    
    $
    10
    
    
    
    2,610,809
    
    
    
    63
    
    
    
    109Transportadora de Gas del Sur S.A.
    
    $
    1
    
    
    
    58,408,751
    
    
    
    169
    
    
    
    167Yacylec S.A.
    
    $
    0,1
    
    
    
    100,000,000
    
    
    
    25
    
    
    
    26Total
    
    
    
    
    
    
    
    
    
    
    1,007
    
    
    
    996
   [Continued from above table, first column(s) repeated] 2003
    
    2002Last available financial statementsNet incomeMain
    
    
    
    
    
    Capital
    
    for theCompany
    
    business
    
    Date
    
    stock
    
    year
    
    Equity
    
    Book valueSharesCitelec S.A.
    
    Investor in Transener S.A.
    
    
    30/09/2003
    
    
    
    249
    
    
    
    61
    
    
    
    333
    
    
    
    71Coroil S.A.
    
    Investor in Acema consortium
    
    
    30/09/2003
    
    
    
    
    
    
    
    (3
    )
    
    
    109
    
    
    
    37Empresa Boliviana de Refinación S.A.
    
    Refining
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    136Enron de inversiones de Energía S.C.A.
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hidroneuquén S.A.
    
    Electric transmission
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    16Inversora Mata S.A.
    
    Investor in Mata consortium
    
    
    30/09/2003
    
    
    
    
    
    
    
    6
    
    
    
    200
    
    
    
    112Oleoducto de Crudos Pesados Ltd.
    
    Oil storage and shipment
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    98Oleoductos del Valle S.A.
    
    Oil storage and shipment
    
    
    31/12/2003
    
    
    
    110
    
    
    
    9
    
    
    
    346
    
    
    
    89Petrolera Entre Lomas S.A.
    
    Oil & Gas
    
    
    31/12/2003
    
    
    
    1
    
    
    
    69
    
    
    
    234
    
    
    
    40Petroquímica Cuyo S.A.
    
    Petrochemical
    
    
    30/09/2003
    
    
    
    50
    
    
    
    16
    
    
    
    142
    
    
    
    29Refinería del Norte S.A.
    
    Refining
    
    
    30/06/2003
    
    
    
    92
    
    
    
    56
    
    
    
    341
    
    
    
    89Transportadora de Gas del Sur S.A.
    
    Oil transportation
    
    
    30/09/2003
    
    
    
    794
    
    
    
    244
    
    
    
    2,016
    
    
    
    88Yacylec S.A.
    
    Electric transmission
    
    
    30/09/2003
    
    
    
    45
    
    
    
    8
    
    
    
    118
    
    
    
    27Total
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    832
 F-94




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##### Table of Contents



c)
    
    Costs of sales for the years ended December 31, 2003, 2002 and 2001
(Stated in millions of Argentine Pesos - See Note 2.c) 2003Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    Marketing
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    
    
    
    
    and
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Electricity
    
    Transportation
    
    Eliminations
    
    TotalInventories at beginning
    
    
    129
    
    
    
    97
    
    
    
    169
    
    
    
    38
    
    
    
    
    
    
    
    (38
    )
    
    
    395Effect of traslation
    
    
    (10
    )
    
    
    
    
    
    
    (6
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (16
    )Investores at begining from
proportional interest in CIESA
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    3Costs (Section e)
    
    
    1,383
    
    
    
    54
    
    
    
    149
    
    
    
    283
    
    
    
    156
    
    
    
    1
    
    
    
    2,026Holding gain (losses)
    
    
    2
    
    
    
    12
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    (6
    )
    
    
    9Purchases, consumption and other
    
    
    54
    
    
    
    1,146
    
    
    
    824
    
    
    
    236
    
    
    
    133
    
    
    
    (1,044
    )
    
    
    1,349Inventories at end
    
    
    (110
    )
    
    
    (129
    )
    
    
    (155
    )
    
    
    (35
    )
    
    
    (8
    )
    
    
    57
    
    
    
    (380
    )Costs of sales
    
    
    1,448
    
    
    
    1,180
    
    
    
    981
    
    
    
    523
    
    
    
    284
    
    
    
    (1,030
    )
    
    
    3,386
 2002Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    Marketing
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    
    
    
    
    and
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Electricity
    
    Transportation
    
    Eliminations
    
    TotalInventories at beginning
    
    
    92
    
    
    
    75
    
    
    
    130
    
    
    
    28
    
    
    
    2
    
    
    
    231
    
    
    
    558Effect of traslation
    
    
    4
    
    
    
    
    
    
    
    3
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    7Costs (Section e)
    
    
    1,538
    
    
    
    40
    
    
    
    157
    
    
    
    337
    
    
    
    3
    
    
    
    55
    
    
    
    2,130Holding gain (losses)
    
    
    16
    
    
    
    (43
    )
    
    
    (4
    )
    
    
    5
    
    
    
    
    
    
    
    21
    
    
    
    (5
    )Purchases, consumption and other
    
    
    79
    
    
    
    969
    
    
    
    775
    
    
    
    299
    
    
    
    6
    
    
    
    (939
    )
    
    
    1,189Assets for sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (23
    )
    
    
    
    
    
    
    (177
    )
    
    
    (200
    )Inventories at end
    
    
    (129
    )
    
    
    (97
    )
    
    
    (169
    )
    
    
    (38
    )
    
    
    
    
    
    
    38
    
    
    
    (395
    )Costs of sales
    
    
    1,600
    
    
    
    944
    
    
    
    892
    
    
    
    608
    
    
    
    11
    
    
    
    (771
    )
    
    
    3,284
 2001Oil and Gas
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydrocarbons
    
    Corporate,Exploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    Marketing
    
    Other Discontinuedand
    
    
    
    
    
    
    
    
    
    
    
    
    
    and
    
    Investments andProduction
    
    Refining
    
    Petrochemical
    
    Electricity
    
    Transportation
    
    Eliminations
    
    TotalInventories at beginning
    
    
    75
    
    
    
    95
    
    
    
    132
    
    
    
    37
    
    
    
    
    
    
    
    240
    
    
    
    579Costs (Section e)
    
    
    1,139
    
    
    
    49
    
    
    
    145
    
    
    
    384
    
    
    
    239
    
    
    
    63
    
    
    
    2,019Purchases, consumption and other
    
    
    66
    
    
    
    642
    
    
    
    519
    
    
    
    539
    
    
    
    63
    
    
    
    (493
    )
    
    
    1,336Inventories at end
    
    
    (92
    )
    
    
    (75
    )
    
    
    (130
    )
    
    
    (28
    )
    
    
    (2
    )
    
    
    (231
    )
    
    
    (558
    )Investores at end from
proportional interest in CIESA
and DISTRILEC
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (26
    )
    
    
    (3
    )
    
    
    
    
    
    
    (29
    )Costs of sales
    
    
    1,188
    
    
    
    711
    
    
    
    666
    
    
    
    906
    
    
    
    297
    
    
    
    (421
    )
    
    
    3,347
 F-95




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##### Table of Contents



d)   Foreign currency assets and liabilities as of December 31, 2003 and 2002
      (Stated in millions of Argentine Pesos  See Note 2.c) Foreign currency
    
    
    
    
    
    Book amount inand amount
    
    Exchange rate
    
    local currencyCURRENT ASSETSCash
    
    US$
    
    
    30
    
    
    
    2.9400
    
    
    
    88BS
    
    
    575
    
    
    
    0.0018
    
    
    
    290Investments
    
    US$
    
    
    248
    
    
    
    2.9400
    
    
    
    729Rs
    
    
    3
    
    
    
    1.0177
    
    
    
    3732Trade receivables
    
    US$
    
    
    167
    
    
    
    2.9400
    
    
    
    491Rs
    
    
    74
    
    
    
    1.0177
    
    
    
    75BS
    
    
    4,948
    
    
    
    0.0018
    
    
    
    9575Other receivables
    
    US$
    
    
    132
    
    
    
    2.9400
    
    
    
    389BS
    
    
    56,075
    
    
    
    0.0018
    
    
    
    102$Bol
    
    
    24
    
    
    
    0.3750
    
    
    
    9Rs
    
    
    12
    
    
    
    1.0177
    
    
    
    12512TOTAL 2003
    
    
    
    
    
    
    1,909TOTAL 2002
    
    
    
    
    
    
    1,908NONCURRENT ASSETSTrade receivables
    
    US$
    
    
    11
    
    
    
    2.9400
    
    
    
    32Other receivables
    
    US$
    
    
    15
    
    
    
    2.9400
    
    
    
    45BS
    
    
    43,980
    
    
    
    0.0018
    
    
    
    80125Investments
    
    US$
    
    
    97
    
    
    
    2.9400
    
    
    
    284TOTAL 2003
    
    
    
    
    
    
    441TOTAL 2002
    
    
    
    
    
    
    282TOTAL ASSETS 2003
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,350TOTAL ASSETS 2002
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,190
 Foreign currency
    
    
    
    
    
    Book amount inand amount
    
    Exchange rate
    
    local currencyCURRENT LIABILITIESAccounts payable
    
    US$
    
    
    182
    
    
    
    2.9400
    
    
    
    535Rs
    
    
    4
    
    
    
    1.0177
    
    
    
    4BS
    
    
    17,592
    
    
    
    0.0018
    
    
    
    32571Short-term debt
    
    US$
    
    
    1,072
    
    
    
    2.9400
    
    
    
    3,1523,152Payroll and social security taxes
    
    US$
    
    
    2
    
    
    
    2.9400
    
    
    
    5BS
    
    

    1,100
    
    
    
    0.0018
    
    
    
    2Sol
    
    
    2
    
    
    
    0.8487
    
    
    
    2Rs
    
    
    3
    
    
    
    1.0177
    
    
    
    312Taxes payable
    
    US$
    
    
    1
    
    
    
    2.9400
    
    
    
    2Rs
    
    
    12
    
    
    
    1.0177
    
    
    
    12BS
    
    
    23,090
    
    
    
    0.0018
    
    
    
    4256Other liabilities
    
    Rs
    
    
    2
    
    
    
    1.0177
    
    
    
    2US$
    
    
    94
    
    
    
    2.9400
    
    
    
    276278TOTAL 2003
    
    
    
    
    
    
    4,069TOTAL 2002
    
    
    
    
    
    
    1,898NONCURRENT LIABILITIESAccounts payable
    
    US$
    
    
    1
    
    
    
    2.9400
    
    
    
    2Long-term debit
    
    US$
    
    
    1734
    
    
    
    2.9400
    
    
    
    5,098Taxes payable
    
    US$
    
    
    
    
    
    
    2.9400
    
    
    
    1BS
    
    
    1,100
    
    
    
    0.0018
    
    
    
    2Rs
    
    
    3
    
    
    
    1.0177
    
    
    
    36Other liabilities
    
    US$
    
    
    69
    
    
    
    2.9400
    
    
    
    204BS
    
    
    12644
    
    
    
    0.001819
    
    
    
    23227Reserves
    
    
    U$S
    
    
    
    68
    
    
    
    2.9400
    
    
    
    201TOTAL 2003
    
    
    
    
    
    
    5,534TOTAL 2002
    
    
    
    
    
    
    6,315TOTAL LIABILITIES 2003
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,603TOTAL LIABILITIES 2002
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    8,213
 US$
    
    Millions of United States DollarsBS
    
    Millions of BolívaresRs
    
    Millions of Reales$Bol
    
    Millions of Pesos BolivianosSol
    
    Millions of Nuevos Soles Peruanos
 F-96




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##### Table of Contents



e) Consolidated detail of expenses incurred and depreciation for the years ended
      December 31, 2003, 2002 and 2001
(Stated in millions of Argentine Pesos  See Note 2.c) 2001
    
    2002
    
    2003Administrativeand selling
    
    ExplorationTotal
    
    Total
    
    Total
    
    Costs
    
    expenses
    
    expensesSalaries and wages
    
    
    413
    
    
    
    268
    
    
    
    266
    
    
    
    110
    
    
    
    152
    
    
    
    4Social security taxes
    
    
    55
    
    
    
    32
    
    
    
    37
    
    
    
    17
    
    
    
    19
    
    
    
    1Other benefits to personnel
    
    
    70
    
    
    
    58
    
    
    
    100
    
    
    
    30
    
    
    
    69
    
    
    
    1Taxes, charges and contributions
    
    
    67
    
    
    
    51
    
    
    
    47
    
    
    
    28
    
    
    
    18
    
    
    
    1Fees and professional advisory
    
    
    140
    
    
    
    81
    
    
    
    80
    
    
    
    37
    
    
    
    42
    
    
    
    1Depreciation of property, plant and
equipment
    
    
    877
    
    
    
    1,051
    
    
    
    1,016
    
    
    
    940
    
    
    
    76
    
    
    
    Amortization of other assets
    
    
    17
    
    
    
    8
    
    
    
    14
    
    
    
    11
    
    
    
    3
    
    
    
    Oil and gas royalties
    
    
    264
    
    
    
    348
    
    
    
    332
    
    
    
    331
    
    
    
    
    
    
    
    1Spares and repairs
    
    
    99
    
    
    
    103
    
    
    
    110
    
    
    
    109
    
    
    
    1
    
    
    
    Geological and geophysical expenses
    
    
    31
    
    
    
    28
    
    
    
    6
    
    
    
    
    
    
    
    
    
    
    
    6Transportation and freights
    
    
    148
    
    
    
    156
    
    
    
    178
    
    
    
    35
    
    
    
    143
    
    
    
    Construction contracts and other services
    
    
    291
    
    
    
    328
    
    
    
    309
    
    
    
    252
    
    
    
    56
    
    
    
    1Impairment of unproved oil and gas properties
    
    
    
    
    
    
    17
    
    
    
    180
    
    
    
    
    
    
    
    
    
    
    
    180Fuel, gas, energy and other
    
    
    44
    
    
    
    37
    
    
    
    35
    
    
    
    34
    
    
    
    1
    
    
    
    Other operating costs and consumption
    
    
    282
    
    
    
    260
    
    
    
    139
    
    
    
    96
    
    
    
    43
    
    
    
    Allowances for doubful accounts
    
    
    34
    
    
    
    30
    
    
    
    31
    
    
    
    21
    
    
    
    10
    
    
    
    Recovery of administrative expenses
    
    
    (107
    )
    
    
    (59
    )
    
    
    (99
    )
    
    
    (25
    )
    
    
    (74
    )
    
    
    Total 2003
    
    
    
    
    
    
    
    
    
    
    2,781
    
    
    
    2,026
    
    
    
    559
    
    
    
    196Total 2002
    
    
    
    
    
    
    2,797
    
    
    
    
    
    
    
    2,130
    
    
    
    609
    
    
    
    58Total 2001
    
    
    2,725
    
    
    
    
    
    
    
    
    
    
    
    2,019
    
    
    
    665
    
    
    
    41
 F-97




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##### Table of Contents



f) Information about ownership in subsidiaries and affiliates as of December 31, 2003 % OF OWNERSHIP AND VOTESDIRECT
    
    INDIRECT
    
    BUSINESS SEGMENTSubsidiariesCorod Producción S.A. (Venezuela)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionEcuadortlc S.A. (Ecuador)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionEnecor S.A.
    
    
    
    
    
    
    68.74
    
    
    ElectricityInnova S.A. (Brasil)
    
    
    
    
    
    
    98.21
    
    
    PetrochemicalPCI Power Edesur Holding Ltd. (Islas Bermudas)
    
    
    
    
    
    
    98.21
    
    
    ElectricityPetrobras Holding Austria AG (Austria)
    
    
    
    
    
    
    98.21
    
    
    CorporatePecom de Valores Internacional de España S.A. (España)
    
    
    
    
    
    
    98.21
    
    
    CorporatePecom Forestal S.A. (1)
    
    
    
    
    
    
    98.21
    
    
    Other investmentPetrobras Energia S.A.
    
    
    98.21
    
    
    
    
    
    
    CorporatePecom Energía Internacional S.A.
    
    
    
    
    
    
    98.21
    
    
    CorporatePetrobras Energía Operaciones S.A. (Ecuador)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionPetrobras Financial Services (Gran Cayman)
    
    
    
    
    
    
    98.21
    
    
    CorporatePetrobras Financial Services GMBH (Austria)
    
    
    
    
    
    
    98.21
    
    
    CorporatePecom Hispano Argentina S.A. (España)
    
    
    
    
    
    
    98.21
    
    
    CorporatePetrobras Bolivia International S.A. (Bolivia)
    
    
    
    
    
    
    98.21
    
    
    CorporatePetrobras Energía Ecuador (Gran Cayman)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionPetrobras Energia Perú S.A. (Perú)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionPetrobras Energia Venezuela S.A. (Venezuela)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionPetrolera San Carlos S.A. (Venezuela)
    
    
    
    
    
    
    98.21
    
    
    Oil and Gas Exploration and ProductionPetroleum Commercial Supply, Inc. (EEUU)
    
    
    
    
    
    
    98.21
    
    
    Other investmentWorld Energy Business S.A.
    
    
    
    
    
    
    99.21
    
    
    Hydrocarbons Marketing and TransportationWorld Fund Global Investment (Gran Cayman)
    
    
    
    
    
    
    98.21
    
    
    CorporateWorld Fund Investment S.A. (Bolivia)
    
    
    
    
    
    
    98.21
    
    
    CorporateWorld Fund Financial Services (Gran Cayman)
    
    
    
    
    
    
    98.21
    
    
    CorporateMain affiliates  join controlCía. de Inversiones de Energía S.A.
    
    
    
    
    
    
    49.10
    
    
    Hydrocarbons Marketing and TransportationCitelec S.A.
    
    
    
    
    
    
    49.10
    
    
    ElectricityDistrilec Inversora S.A.
    
    
    
    
    
    
    47.63
    
    
    ElectricityEdesur S.A.
    
    
    
    
    
    
    26.84
    
    
    ElectricityTransba S.A.
    
    
    
    
    
    
    28.72
    
    
    ElectricityTransener S.A.
    
    
    
    
    
    
    32.50
    
    
    ElectricityTransportadora de Gas del Sur S.A.
    
    
    
    
    
    
    34.37
    
    
    Hydrocarbons Marketing and TransportationMain affiliates  significance influenceCoroil S.A. (Venezuela)
    
    
    
    
    
    
    48.12
    
    
    Oil and Gas Exploration and ProductionEmpresa Boliviana de Refinación S.A. (Bolivia)
    
    
    
    
    
    
    48.10
    
    
    RefiningHidroneuquén S.A.
    
    
    
    
    
    
    9.02
    
    
    ElectricityInversora Mata S.A. (Venezuela)
    
    
    
    
    
    
    48.12
    
    
    Oil and Gas Exploration and ProductionOleoducto de Crudos Pesados Ltd. (Gran Cayman)
    
    
    
    
    
    
    8.80
    
    
    Hydrocarbons Marketing and TransportationOleoducto de Crudos Pesados S.A. (Ecuador)
    
    
    
    
    
    
    8.80
    
    
    Hydrocarbons Marketing and TransportationOleoductos del Valle S.A.
    
    
    
    
    
    
    22.69
    
    
    Hydrocarbons Marketing and TransportationPropyme S.G.R
    
    
    
    
    
    
    49.08
    
    
    CorporatePetrolera Entre Lomas S.A.
    
    
    
    
    
    
    18.87
    
    
    Oil and Gas Exploration and ProductionPetroquímica Cuyo S.A.
    
    
    
    
    
    
    39.28
    
    
    PetrochemicalRefinería del Norte S.A.
    
    
    
    
    
    
    27.99
    
    
    RefiningUrugua-í S.A.
    
    
    
    
    
    
    28.80
    
    
    ElectricityYacylec S.A.
    
    
    
    
    
    
    21.82
    
    
    Electricity
 (1) See Vote 9.V.a) F-98




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##### Table of Contents



g) Oil and gas areas and participation in joint ventures as of December 31,
2003 WORKING
    
    
    
    DURATIONNAME
    
    LOCATION
    
    INTEREST (2)
    
    OPERATOR
    
    THROUGHProductionArgentina25 de Mayo  Medanito S.E.
    
    La Pampa and Río Negro
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2016Jagüel de los Machos
    
    Río Negro and La Pampa
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2015Puesto Hernández  U.T.E.
    
    Mendoza and Neuquén
    
    
    38.45
    %
    
    Petrobras Energía
    
    
    2016Bajada del Palo  La Amarga Chica  U.T.E.
    
    Neuquén
    
    
    80.00
    %
    
    Petrobras Energía
    
    
    2015Santa Cruz II  U.T.E.
    
    Santa Cruz
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2017Río Neuquén
    
    Neuquén and Río Negro
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2019Entre Lomas
    
    Neuquén and Río Negro
    
    
    17.90
    %
    
    Petrolera Entre Lomas S.A.
    
    
    2016Aguada de la Arena
    
    Neuquén
    
    
    80.00
    %
    
    Petrobras Energía
    
    
    2022Veta Escondida y Rincón de Aranda  U.T.E.
    
    Neuquén
    
    
    55.00
    %
    
    Petrobras Energía
    
    
    2016Santa Cruz I  U.T.E.
    
    Santa Cruz
    
    
    71.00
    %
    
    Petrobras Energía
    
    
    2016ForeignColpa  Caranda
    
    Bolivia
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2029Oritupano  Leona
    
    Venezuela
    
    
    55.00
    %
    
    PE Venezuela
    
    
    2014Acema
    
    Venezuela
    
    
    86.23
    %
    
    Petrolera Coroil
    
    
    2017La Concepción
    
    Venezuela
    
    
    90.00
    %
    
    PE Venezuela
    
    
    2017Mata
    
    Venezuela
    
    
    86.23
    %
    
    Petrolera Mata
    
    
    2018Lote X
    
    Perú
    
    
    100.00
    %
    
    PE Perú
    
    
    2024Bloque 18
    
    Ecuador
    
    
    70.00
    %
    
    Ecuadortlc
    
    
    2021ExplorationArgentinaGlencross (1)
    
    Santa Cruz
    
    
    96.68
    %
    
    Petrobras Energía
    
    
    1999Santa Cruz I  Oeste
    
    Santa Cruz
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2006Santa Cruz II  Oeste
    
    Santa Cruz
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2005Cuenca Marina 2A Norte-U.T.E.
    
    Santa Cruz
    
    
    50.00
    %
    
    Petrobras Energía
    
    
    2006ForeignSan Carlos
    
    Venezuela
    
    
    50.00
    %
    
    Pet. San Carlos
    
    
    2005Tinaco
    
    Venezuela
    
    
    50.00
    %
    
    PE Venezuela
    
    
    2005Bloque 31
    
    Ecuador
    
    
    100.00
    %
    
    Petrobras Energía
    
    
    2004
  (1)
    
    Pecom Energía has requested that the lot be declared operational with commercial operation held in suspense.(2)
    
    Indirect interest through Pecom Energía and its subsidiaries. F-99




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##### Table of Contents



h) Combined joint ventures and consortia assets and liabilities as of
December 31, 2003 and 2002 and results for the years as of December
2003, 2002 and 2001 then ended.  2003
    
    2002Assets and liabilitiesCurrent assets
    
    
    687
    
    
    
    705Noncurrent assets
    
    
    2,726
    
    
    
    2,909Total assets
    
    
    3,413
    
    
    
    3,614Current liabilities
    
    
    353
    
    
    
    206Noncurrent liabilities
    
    
    25
    
    
    
    Total liabilities
    
    
    378
    
    
    
    206
 2003
    
    2002
    
    2001Statements of incomeNet sales
    
    
    1,071
    
    
    
    1,224
    
    
    
    881Costs of sales
    
    
    (536
    )
    
    
    (661
    )
    
    
    (426
    )Gross profit
    
    
    535
    
    
    
    563
    
    
    
    455Administrative and selling expenses
    
    
    (40
    )
    
    
    (66
    )
    
    
    (52
    )Exploration expenses
    
    
    (6
    )
    
    
    (25
    )
    
    
    (11
    )Other exploitation income, net
    
    
    18
    
    
    
    (13
    )
    
    
    4Financial income (expense) and holding gains (losses)
    
    
    2
    
    
    
    1,195
    
    
    
    2Income tax provision
    
    
    13
    
    
    
    (14
    )
    
    
    (15
    )Net income
    
    
    522
    
    
    
    1,640
    
    
    
    383
 2003
    
    2002
    
    2001Net cash provided by operating activities
    
    
    164
    
    
    
    48
    
    
    
    580Net cash used in investing activities
    
    
    (407
    )
    
    
    (378
    )
    
    
    (850
    )Net cash provided by financing activities
    
    
    249
    
    
    
    354
    
    
    
    273
 F-100