##### 



UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
 FORM 20-F o
    
    REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR 12(g) OF THE SECURITIES EXCHANGE ACT OF 1934ORx
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For The Fiscal Year Ended 31 December 2004ORo
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the transition period from _______________ to __________________ Commission file number: 1-9159 NORSK HYDRO ASA (Exact name of Registrant as specified in its charter)
Kingdom of Norway
(Jurisdiction of incorporation or organization)
Drammensveien 264, Vækerø
N-0240 OSLO
Norway
(Address of principal executive offices)
 Securities registered or to be registered pursuant to Section 12(b) of the Act: Title of each class
    
    Name of each exchange on which registeredAmerican Depositary Shares
    
    New York Stock ExchangeOrdinary Shares, par value NOK 18.30 per share
    
    New York Stock Exchange*
   *
    Not for trading, but only in connection with the registration of the American Depositary Shares,
pursuant to the requirements of the Securities and Exchange Commission. 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: Ordinary
Shares, par value NOK 18.30 per share. Indicate the number of outstanding shares of each of the issuers classes of capital or common stock
as of the close of the period covered by the annual report. 250,839,230 Ordinary Shares, par value NOK 18.30 per share 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 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




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TABLE OF CONTENTS ITEM
    
    PAGEExchange Rate Information
    
    
    4PART IItem 1. Identity of Directors, Senior Management and Advisers
    
    
    5Item 2. Offer Statistics and Expected Timetable
    
    
    5Item 3. Key Information
    
    
    5A. Selected Consolidated Financial Data
    
    
    5B. Capitalization and Indebtedness
    
    
    9C. Reasons for the Offer and Use of Proceeds
    
    
    9D. Risk Factors
    
    
    9Item 4. Information on the Company
    
    
    16A. History and Development of the Company
    
    
    16B. Business Overview
    
    
    17C. Organizational Structure
    
    
    79D. Property, Plants and Equipment
    
    
    79Item 5. Operating and Financial Review and Prospects
    
    
    80Item 6. Directors, Senior Managers and Employees
    
    
    113A. Directors, Corporate Assembly and Corporate Management Board
    
    
    113B. Compensation
    
    
    117C. Board Practices
    
    
    119D. Employees
    
    
    123E. Share Ownership
    
    
    123Item 7. Major Shareholders and Related Party Transactions
    
    
    125A. Major Shareholders
    
    
    125B. Related Party Transactions
    
    
    126C. Interests of Experts and Counsel
    
    
    127Item 8. Financial Information
    
    
    127A. Consolidated Financial Statements and Other Financial Information
    
    
    127B. Significant Changes
    
    
    130Item 9. The Offer and Listing
    
    
    131A. Offer and Listing Details
    
    
    131B. Plan of Distribution
    
    
    132C. Markets
    
    
    132D. Selling Shareholders
    
    
    132E. Dilution
    
    
    132F. Expenses of the Issue
    
    
    132
 2




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ITEM
    
    PAGEItem 10. Additional Information
    
    
    132A. Share Capital
    
    
    132B. Articles of Association
    
    
    132C. Material Contracts
    
    
    145D. Exchange Controls
    
    
    145E. Taxation
    
    
    145F. Dividends and Paying Agents
    
    
    150G. Statement by Experts
    
    
    150H. Documents on Display
    
    
    150I. Subsidiary Information
    
    
    150Item 11. Quantitative and Qualitative Disclosures About Market Risk
    
    
    151Item 12. Description of Securities Other Than Equity Securities
    
    
    151PART IIItem 13. Defaults, Dividend Arrearages and Delinquencies
    
    
    152Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
    
    
    152Item 15. Controls and Procedures; CEO and CFO Certifications
    
    
    152Item 16A. Audit Committee Financial Expert
    
    
    152Item 16B. Code of Ethics
    
    
    152Item 16C. Principal Accountant Fees and Services
    
    
    153Item 16D. Exemption from the Listing Standards for Audit Committees
    
    
    154Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchasers
    
    
    154PART IIIItem 17. Financial Statements
    
    
    155Item 18. Financial Statements
    
    
    155Item 19. Financial Statements and Exhibits
    
    
    155
 3




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In the following discussion, references to Hydro or the Company are to Norsk Hydro ASA or
Norsk Hydro ASA and its consolidated subsidiaries, as the context requires. References to the
Group are to Norsk Hydro ASA and its consolidated subsidiaries. References to the Kingdomare
to the Kingdom of Norway. The glossary found immediately after the signature page of this annual
report provides the definitions of certain other terms used throughout this annual report. In
addition, the definitions of oil and gas terms, including terms defined in applicable regulations
and Industry Guide 2 (Disclosure of Oil and Gas Operations) of the U.S. Securities and Exchange
Commission (the SEC), can be found in Item 4.B. of this annual report at the end of the business
description for the Exploration and Development sub-segment of Hydro Oil and Energy. 
 EXCHANGE RATE INFORMATION The Company publishes its consolidated financial statements in Norwegian kroner (NOK). In
this annual report, references to US dollar, US dollars, USD US$ or $ are to United
States dollars. The following tables set forth, for the periods indicated, certain information
concerning the exchange rate of Norwegian kroner for USD 1.00, based on the noon buying rate in the
City of New York for cable transfers in foreign currencies as certified for customs purposes by the
Federal Reserve Bank of New York (the Noon Buying Rate): Calendar Year Period
    
    Average Noon Buying Rate(1)2000
    
    8.832001
    
    9.002002
    
    7.932003
    
    7.062004
    
    6.72
 Noon Buying RateCalendar Monthly Period
    
    High
    
    LowSeptember 2004
    
    
    6.95
    
    6.73October 2004
    
    
    6.77
    
    6.39November 2004
    
    
    6.44
    
    6.09December 2004
    
    
    6.22
    
    6.06January 2005
    
    
    6.36
    
    6.10February 2005
    
    
    6.56
    
    6.20
  (1)
    
    The average of the Noon Buying Rates on the last business day
of each calendar month during the year indicated. The
Noon Buying Rate on 14 March 2005 was NOK 6.12 = $1.00. Fluctuations in the exchange rate between the Norwegian kroner and the US dollar will affect
the US dollar equivalent of the Norwegian kroner price of the Companys ordinary shares on the Oslo
Stock Exchange and, as a result, are likely to affect the market price of the Companys ordinary
shares represented by American depositary shares (ADSs) in the United States. Such fluctuations
could also affect the US dollar amounts received by holders of ADSs on conversion of cash
dividends, paid by the Company in Norwegian kroner, on the ordinary shares represented by the ADSs.
See Item 3.A. Selected Consolidated Financial Data and Item 10.B. Articles of Association 
Description of American Depositary Receipts  Dividends and Other Distributions. 4




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PART I 
 ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 1 if, as is the case in this instance, the Form 20-F is being filed
as an annual report under the Securities Exchange Act of 1934, as amended (the Exchange Act). 
 ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 2 if, as is the case in this instance, the Form 20-F is being filed
as an annual report under the Exchange Act. 
 ITEM 3. KEY INFORMATION 
 ITEM 3.A. SELECTED CONSOLIDATED FINANCIAL DATA The following financial information with respect to the five years ended 31 December 2004,
2003, 2002, 2001 and 2000 has been derived from Hydros audited consolidated financial statements
prepared in accordance with United States generally accepted accounting principles (US GAAP). The
financial information for the three years ended 31 December 2004, 2003 and 2002 should be read in
conjunction with and is qualified in its entirety by reference to the consolidated financial
statements and notes included in the Companys annual report to shareholders for the year ended 31
December 2004 (the Consolidated Financial Statements), included in Exhibit 10 to this annual
report on Form 20-F. The Companys agri business was transferred to Yara International ASA on 24 March 2004 in a
demerger transaction. Results, assets and liabilities of the transferred operations relating to
periods prior to demerger are reported respectively under Income from discontinued operations,
Assets of discontinued operations and Liabilities of discontinued operations. 5




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Income Statement Data(1) (2)Year ended 31 December2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in NOK million, except per share data)Operating revenues (3) (4)
    
    
    155,425
    
    
    
    133,761
    
    
    
    134,093
    
    
    
    116,147
    
    
    
    120,698Operating costs and expenses excluding depreciation,
impairment and restructuring charges (4)
    
    
    106,702
    
    
    
    98,189
    
    
    
    103,707
    
    
    
    85,562
    
    
    
    82,918Depreciation, depletion and amortization
    
    
    16,898
    
    
    
    13,947
    
    
    
    12,729
    
    
    
    10,693
    
    
    
    10,895Restructuring charges (5)
    
    
    (22
    )
    
    
    
    
    
    
    (10
    )
    
    
    921
    
    
    
    Operating income
    
    
    31,847
    
    
    
    21,625
    
    
    
    17,667
    
    
    
    18,971
    
    
    
    26,885Financial and other income (expense), net (6)
    
    
    1,960
    
    
    
    657
    
    
    
    1,226
    
    
    
    3,306
    
    
    
    4,940Interest expense and foreign exchange gain (loss)
    
    
    (1,027
    )
    
    
    (1,136
    )
    
    
    633
    
    
    
    (3,530
    )
    
    
    (3,771
    )Income from continuing operations before taxes and
minority interest
    
    
    32,780
    
    
    
    21,146
    
    
    
    19,526
    
    
    
    18,747
    
    
    
    28,054Provision for taxes
    
    
    (21,197
    )
    
    
    (12,922
    )
    
    
    (12,452
    )
    
    
    (12,945
    )
    
    
    (15,583
    )Minority interest
    
    
    (106
    )
    
    
    151
    
    
    
    26
    
    
    
    92
    
    
    
    (37
    )Income from continuing operations before cumulative
effect of change in accounting principle
    
    
    11,477
    
    
    
    8,375
    
    
    
    7,100
    
    
    
    5,894
    
    
    
    12,434Income from discontinued operations
    
    
    1,083
    
    
    
    2,312
    
    
    
    1,665
    
    
    
    1,998
    
    
    
    1,546Income before cumulative effect of change in accounting
principle
    
    
    12,560
    
    
    
    10,687
    
    
    
    8,765
    
    
    
    7,892
    
    
    
    13,981Cumulative effect of change in accounting principle
    
    
    
    
    
    
    281
    
    
    
    
    
    
    
    
    
    
    
    Net income (loss)
    
    
    12,560
    
    
    
    10,968
    
    
    
    8,765
    
    
    
    7,892
    
    
    
    13,981Earnings (loss) per share:Basic and diluted earnings per share from continuing
operations before cumulative effect of change in
accounting principle
    
    
    45.10
    
    
    
    32.50
    
    
    
    27.50
    
    
    
    22.80
    
    
    
    47.50Basic and diluted earnings per share from discontinued
operations
    
    
    4.20
    
    
    
    9.00
    
    
    
    6.50
    
    
    
    7.70
    
    
    
    5.90Basic and diluted earnings per share before cumulative
effect of change in accounting principle
    
    
    49.40
    
    
    
    41.50
    
    
    
    34.00
    
    
    
    30.50
    
    
    
    53.40Basic and diluted earnings per share
    
    
    49.40
    
    
    
    42.60
    
    
    
    34.00
    
    
    
    30.50
    
    
    
    53.40Avg. number of outstanding ordinary shares
    
    
    254,411,433
    
    
    
    257,528,511
    
    
    
    257,799,411
    
    
    
    258,434,202
    
    
    
    261,620,982Cash dividends paid per share during period:NOK per share (7)
    
    
    11.00
    
    
    
    10.50
    
    
    
    10.00
    
    
    
    9.50
    
    
    
    8.00Converted into USD per share (7)
    
    
    1.64
    
    
    
    1.56
    
    
    
    1.24
    
    
    
    1.05
    
    
    
    0.90
   (1)
    See Note 2 to the Consolidated Financial Statements for a discussion of
significant business acquisitions and dispositions during the three-year period ended 31
December 2004.(2)
    Effective 1 January 2004, Hydro adopted FASB Interpretation 46 Consolidation of
Variable Interest Entities (FIN 46R) which clarifies the application of Accounting Research
Bulletin No. 51, Consolidated Financial Statements, relating to certain entities in which
equity investors do not have the characteristics of a controlling financial interest or do
not have sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support (variable interest entities or VIEs). Hydro has
identified one pre-existing arrangements that meets the requirements of FIN 46R to be
classified as a VIE. Hydro has equity interest in Slovalco, an aluminium smelter in
Slovakia. Hydro has consolidated Slovalco in accordance with the new requirements effective
1 January 2004. See Note 1 to the Consolidated Financial Statements for more information
regarding the consolidation of Slovalco.(3)
    Effective 1 January 2003, Hydro adopted EITF 02-3 Recognition and Reporting of
Gains and Losses on Energy Contracts. This standard requires only energy contracts that
meet the definition of a derivative according to SFAS 133 Accounting for Derivative
Instruments and Hedging Activities and are held for trading be recorded in the balance
sheet at fair value. Other energy contracts are recorded at the lower of historical cost
and fair market value. This change applies to contracts entered into before 25 October
2002. For contracts entered after 25 October 2002, the regulation applied from initial
recognition.(4)
    Prior years amounts have been reclassified to reflect the implementation of EITF
02-3 and EITF 03-11, which require realized and unrealized gains and losses on all
derivative instruments be presented on a net basis in the income statement. Previously,
gains and losses on energy derivative contracts were reported according to EITF 98-10 and
were presented on a gross basis in the income statement.(5)
    See Note 6 to the Consolidated Financial Statements for more information
regarding restructuring charges.(6)
    Equity in net income of non-consolidated investees is included under Financial
and other income (expense), net.(7)
    Cash dividends paid during the period represent payments of dividends with
respect to the previous year. Amounts paid in Norwegian kroner have been converted at
prevailing exchange rates on the date of such payments. 6




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Balance Sheet Data(1)As of 31 December2004
    
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000(in NOK million)Cash, cash equivalents
and other liquid assets
    
    
    25,336
    
    
    
    16,426
    
    
    
    8,158
    
    
    
    28,683
    
    
    
    23,637Total assets
    
    
    200,243
    
    
    
    218,629
    
    
    
    207,211
    
    
    
    197,922
    
    
    
    196,354Short-term debt
    
    
    4,353
    
    
    
    6,485
    
    
    
    8,819
    
    
    
    9,685
    
    
    
    10,379Long-term debt
    
    
    19,487
    
    
    
    28,403
    
    
    
    30,728
    
    
    
    37,608
    
    
    
    39,851Deferred tax liabilities
    
    
    29,899
    
    
    
    33,323
    
    
    
    36,818
    
    
    
    30,648
    
    
    
    30,664Ordinary shares and
additional paid-in capital
    
    
    15,206
    
    
    
    20,403
    
    
    
    20,420
    
    
    
    20,402
    
    
    
    20,391Total shareholders equity
    
    
    85,890
    
    
    
    88,080
    
    
    
    75,867
    
    
    
    74,793
    
    
    
    71,227
   (1)
    See Note 2 to the Consolidated Financial Statements for a discussion of
significant business acquisitions and dispositions during the three-year period ended 31
December 2004. 7




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Segment Data The following table indicates the Groups operating revenues, sales to unaffiliated customers
and operating income (after eliminating inter-segment sales) by business segment for each of the
three fiscal years in the period ended 31 December 2004. Operating Income/(Loss)Sales to Unaffiliated
    
    
    Before Financial and OtherOperating Revenues
    
    
    
    
    
    
    
    

    Customers
    
    IncomeYear ended 31 December
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002
    
    
    2004
    
    
    2003
    
    
    2002Business Segment(1)Exploration and Production
(2)
    
    
    48,962
    
    
    
    37,904
    
    
    
    32,970
    
    
    
    13,519
    
    
    
    12,099
    
    
    
    10,136
    
    
    
    28,363
    
    
    
    18,500
    
    
    
    13,137Energy and Oil Marketing (2)
    
    
    60,788
    
    
    
    49,370
    
    
    
    45,915
    
    
    
    54,629
    
    
    
    44,308
    
    
    
    41,929
    
    
    
    2,650
    
    
    
    2,668
    
    
    
    2,784Eliminations (3)
    
    
    (37,032
    )
    
    
    (27,315
    )
    
    
    (23,040
    )
    
    
    (1,643
    )
    
    
    (1,576
    )
    
    
    (965
    )
    
    
    131
    
    
    
    (25
    )
    
    
    26Hydro Oil and Energy
    
    
    72,718
    
    
    
    59,959
    
    
    
    55,845
    
    
    
    66,505
    
    
    
    54,831
    
    
    
    51,100
    
    
    
    31,144
    
    
    
    21,143
    
    
    
    15,947Metals
    
    
    49,159
    
    
    
    39,923
    
    
    
    39,646
    
    
    
    33,048
    
    
    
    26,509
    
    
    
    26,025
    
    
    
    830
    
    
    
    2,293
    
    
    
    1,690Rolled Products
    
    
    20,373
    
    
    
    18,377
    
    
    
    14,790
    
    
    
    18,814
    
    
    
    17,825
    
    
    
    14,135
    
    
    
    626
    
    
    
    132
    
    
    
    (295
    )Extrusion and Automotive
    
    
    27,600
    
    
    
    24,529
    
    
    
    24,245
    
    
    
    27,563
    
    
    
    24,472
    
    
    
    24,186
    
    
    
    277
    
    
    
    98
    
    
    
    14Other and Eliminations (4)
    
    
    (17,458
    )
    
    
    (13,677
    )
    
    
    (13,630
    )
    
    
    51
    
    
    
    190
    
    
    
    162
    
    
    
    72
    
    
    
    (67
    )
    
    
    289Hydro Aluminium
    
    
    79,674
    
    
    
    69,152
    
    
    
    65,051
    
    
    
    79,476
    
    
    
    68,996
    
    
    
    64,508
    
    
    
    1,805
    
    
    
    2,456
    
    
    
    1,698Other Activities (5)
    
    
    12,869
    
    
    
    13,759
    
    
    
    21,557
    
    
    
    9,665
    
    
    
    10,013
    
    
    
    17,859
    
    
    
    312
    
    
    
    (404
    )
    
    
    48Corporate and Eliminations (6)
    
    
    (9,836
    )
    
    
    (9,109
    )
    
    
    (8,360
    )
    
    
    (221
    )
    
    
    (79
    )
    
    
    626
    
    
    
    (1,414
    )
    
    
    (1,570
    )
    
    
    (26
    )Total
    
    
    155,425
    
    
    
    133,761
    
    
    
    134,093
    
    
    
    155,425
    
    
    
    133,761
    
    
    
    134,093
    
    
    
    31,847
    
    
    
    21,625
    
    
    
    17,667
   (1)
    See Note 2 to the Consolidated Financial Statements for a discussion of significant
business acquisitions and dispositions during the three-year period ended 31 December 2004.(2)
    As of 1 January 2003, Hydros gas transportation activities are reported as part of
Energy and Oil Marketing. Prior periods have been reclassified for comparative purposes.(3)
    Eliminations  Oil and Energy includes elimination of unrealized gain on gas
contracts in the amount of NOK 144 million.(4)
    Other and Eliminations includes unrealized gains and losses related to London Metals
Exchange (LME) contracts with a gain of NOK 175 million in 2004, a loss of NOK 49 million
in 2003, and a gain of NOK 266 million in 2002.(5)
    Other Activities consist of Polymers, BioMar AS (previously Treka AS), Flexible
Packaging (sold in April 2003), the industrial insurance company, Industriforsikring, and
Hydro Business Partner.(6)
    Corporate and Eliminations includes the elimination of the unrealized gain/loss on
power contracts between Energy and other units in Hydro with a loss of NOK 235 million in
2004, a loss of NOK 141 million in 2003 and a loss of NOK 588 million in 2002. In addition,
NOK 13 million, NOK 21 million and NOK 26 million is eliminated within Oil and Energy in
2004, 2003, and 2002 respectively. Corporate and Eliminations operating income (loss)
includes a net periodic pension cost of NOK 1,001 million for 2004, NOK 1,111 million for
2003, and NOK 314 million for 2002. 8




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ITEM 3.B. CAPITALIZATION AND INDEBTEDNESS In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 3.B. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 3.C. REASONS FOR THE OFFER AND USE OF PROCEEDS In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 3.C. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 3.D. RISK FACTORS In order to utilize the safe harbor provisions of the United States Private Securities
Litigation Reform Act of 1995, Hydro is providing the following cautionary statement: This annual report contains (and oral communications made by or on behalf of Hydro may
contain) forecasts, projections, estimates, statements of managements plans, objectives and
strategies for Hydro, such as planned expansions, investments or other projects, targeted
production volumes, capacities or rates, start-up costs, cost reductions, profit objectives, and
various expectations about future developments in Hydros markets (particularly prices, supply and
demand, and competition), results of operations, margins, risk management and so forth. These
forward-looking statements are based on a number of assumptions and forecasts, including world
economic growth and other economic indicators (including rates of inflation and industrial
production), trends in Hydros key markets, and global oil and gas, and aluminium supply and demand
conditions. By their nature, forward-looking statements involve risk and uncertainty and various
factors could cause Hydros actual results to differ materially from those projected in a
forward-looking statement or affect the extent to which a particular projection is realized. The
following paragraphs address important factors that may cause actual results or developments to
differ materially from those expressed or implied by the forward-looking statements. Risks Relating to Hydros Oil and Energy Business Hydro Oil and Energys future performance depends on the ability to find or gain access to
additional oil and gas reserves that are economically recoverable. The majority of Hydro Oil and Energys proved reserves (92 percent as of 31 December 2004)
are located on the Norwegian Continental Shelf (the NCS). The southern part of the NCS (the
location of the most easily accessible and exploitable fields offshore Norway) is a maturing
resource province from which reserve additions have been low in recent years. Norways oil
production has been declining for the last two years. See the discussion in Item 4.B. Business
Overview  Hydro Oil and Energy  Exploration and Production  Oil Industry Trends  Reduced
Exploration Results Worldwide and Maturing Areas in the Developed World the NCS Unless Hydro Oil and Energy conducts successful exploration and development activities or
acquires properties containing proved reserves, or both, its proved reserves will decline as
reserves are produced. Because of limited access to major new exploration provinces, and increased
price expectations, the bidding for available properties and prospects has intensified. In
addition, Hydro Oil and Energy may not succeed in exploiting competencies and skills developed on
the NCS in more remote areas. Hydro Oil and Energys future production is dependent upon its
success in finding or acquiring, and developing, additional reserves. 9




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Hydro Oil and Energys development projects and operations involve many uncertainties and operating risks that can prevent Hydro from realizing
        profits and can cause substantial losses. As fields on the NCS mature and demonstrate a decline in production, Hydro Oil and Energy is
seeking to get more production from NCS fields in which it already has an interest and increasingly
developing smaller satellite fields. Other Hydro Oil and Energy development projects are in remote
locations with limited operational histories and, consequently, the success of these projects is
less predictable. In addition, some of Hydro Oil and Energys development projects are located in
deep-water or other hostile environments, such as areas on the NCS, the US Gulf of Mexico and
Angola, or produced from challenging reservoirs. Planning and development of the Ormen Lange field,
for example, has been described as one of the most challenging assignments any oil company has
tackled, not just in Norway but in a global context, given the combination of deep-water, harsh
weather conditions, freezing water temperatures and the need to transport gas for processing over
long distances and a very uneven seabed. The production of oil and natural gas is vulnerable to weather conditions, operator error or
other incidents, which can result in oil spills, gas leakages, equipment failure, unplanned
maintenance stops, loss of well control or other occurrences disrupting the production and
potentially causing harm to the environment. As a result, Hydro Oil and Energy may face increased challenges maintaining targeted levels of
production and production growth in future years. This could negatively affect Hydros results of
operations and financial condition. A substantial or extended decline in oil or natural gas prices would have a material adverse
effect on Hydro Oil and Energys business. Historically, prices for oil and natural gas have fluctuated widely in response to changes in
many factors, including:  
    oil companies spending on exploration and production activities;
    global and regional economic and political developments in resource-producing regions,
particularly in the Middle East;
    changes in the supply of and demand for oil and natural gas; and
    the ability of the members of the Organization of the Petroleum Exporting Countries
(OPEC) to agree on and maintain oil price and production controls. Notwithstanding current high oil prices, it is impossible to predict future oil and natural
gas price movements. Declines in oil and natural gas prices will reduce Hydro Oil and Energys
financial results. Based on Hydros analysis of indicative price and currency sensitivities
included in this annual report (see Item 5. Operating and Financial Review and Prospects  Risk
Management), a USD 1 decline in oil prices will reduce Hydro Oil and Energys pre-tax income and
after-tax income by approximately NOK 1,150 million and NOK 310 million, respectively. Hydro Oil and Energy is exposed to foreign currency exchange rate fluctuations. Oil prices are denominated in US dollars while operating results are reported in Norwegian
kroner. Accordingly, operating results will, in general, decline when the Norwegian kroner
strengthens against the U.S. dollar. Based on Hydros analysis of indicative price and currency
sensitivities included in this annual report (see Item 5. Operating and Financial Review and
Prospects  Risk Management), a strengthening of the Norwegian kroner against the US dollar of NOK
1 per US$1.00 will reduce Hydro Oil and Energys pre-tax income and after-tax income by
approximately NOK 7,250 million and NOK 1,960 million, respectively. 10




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Hydro Oil and Energys oil and gas reserves are only estimates and may prove inaccurate. There are numerous uncertainties inherent in estimating quantities of proved reserves and
their values, including many factors beyond the control of the producer.The reserve data included
in this annual report represent only Hydros estimates; the estimates of other companies with
interests in the same oil and gas field or fields may differ and the magnitude of the differences
may be substantial. This reflects the degree to which reservoir engineering is a subjective and
inexact process, requiring the estimate of underground accumulations of oil and natural gas that
cannot be measured in an exact manner. Evaluating properties for their recoverable reserves of oil
and natural gas entails the assessment of geological, engineering and production data, some or all
of which may prove to be unreliable. Accordingly, reserve estimates may be subject to downward or
upward adjustment. See the discussion in Item 5. Operating and Financial Review and Prospects 
Hydros Critical Accounting Policies  Proved Oil and Gas Reserves. Actual production, revenues
and expenditures with respect to Hydro Oil and Energys reserves will likely vary from estimates,
and those variances may be material. Any downward adjustment in Hydro Oil and Energys reserve data
could lead to lower future production, which would negatively affect Hydros results of operations
and financial condition. Hydro may be subject to the imposition of sanctions by the U.S. government in connection with
its activities in Iran and/or Libya. Hydro Oil and Energy is engaged in certain activities in Iran and has an interest in oil and
gas exploration licenses in Libya, where exploratory and appraisal wells are in the process of
being drilled and limited production has commenced. In August 1996, the United States adopted the
Iran and Libya Sanctions Act of 1996 (the Sanctions Act) with the objective of denying Iran and
Libya the ability to support acts of international terrorism and fund the development and
acquisition of weapons of mass destruction. The Sanctions Act provides that the President of the
United States is to impose two or more sanctions against any person, regardless of nationality, if
the President determines that the person, with actual knowledge, made an investment of US$ 20
million or more in any 12-month period in Iran or Libya that directly and significantly
contributed to the enhancement of Irans or Libyas ability to develop its petroleum resources. In April 2004, the Bush administration announced the termination of application of the
Sanctions Act with respect to Libya, though it is unclear whether the waiver has retroactive
effect. The Sanctions Act continues in force with respect to Iran. Hydro presently has no assets
under development or in production in Iran, suggesting that there may be minimal risk of
application of the Sanctions Act with respect to Hydros existing activities in Iran. However, no
sanctions have ever been imposed against any person or entity under the Sanctions Act. This makes
it difficult for Hydro to predict the political and other policy considerations that would prompt
the U.S. government to apply the Sanctions Act. Should the U.S. government determine that a
violation of the Sanctions Act exists or has occurred, the Sanctions Act provides for sanctions
that include a ban on the issuance of a license to export goods or technology to a sanctioned
person, the prohibition of loans or extensions of credit by U.S. financial institutions to a
sanctioned person, and restrictions on imports into the United States from a sanctioned person. Hydro Oil and Energys expansion of business in emerging and transitioning markets presents a
higher degree of financial, political, economic and business risk Hydro Oil and Energy is exposed to general financial, political, economic and business risks
in connection with its international exploration, development and production activities, with the
degree of risk being generally higher in emerging and transitioning markets such as Angola and
Russia. For example, the government of Angola is in the process of enacting a new foreign exchange law
to supersede the current regime that Hydro and other foreign oil companies are operating under. The
proposed law would require foreign oil companies to remit their revenues back to Angola to be held
in local accounts for extended periods until approvals could be obtained to use them outside
Angola. Oil companies and other interested parties strongly objected this initial proposal. The
Angolan government 11




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is in process of revising the proposed law. This process is expected to be finalized during
the second quarter of 2005 for implementation before the end of the year. Depending on the outcome
of this process, a new law could have material adverse effects on Hydros current and future
operations in Angola. In Russia, Western oil companies continue to assess the impact of the Russian governments
recent actions relating to what had been Russias second-largest oil concern, Yukos. Risks Relating to Hydro Aluminiums Business Hydro Aluminiums results of operations are affected by fluctuations in LME prices The aluminium industry is highly cyclical. Virtually all aluminium end-use markets, including
the building, transportation and packaging industries, are also cyclical. In addition, there is
uncertainty concerning developments in supply and demand, in particular, regarding the overall
economic developments in China as well as potential further restructuring within the aluminium
industry as a whole. Price developments within the London Metal Exchange (LME), which represents the main
reference price for the industry, reflects the cyclicality and uncertainties discussed above. For
more information, see Item 4.B Hydro Aluminium  Long Term Market Developments. Fluctuations in prevailing aluminium prices, could negatively affect the financial results of
Hydro Aluminiums business areas. Based on Hydros analysis of indicative price and currency
sensitivities included in this annual report (see Item 5. Operating and Financial Review and
Prospects  Risk Management), a USD 100 decline in the LME price per tonne will reduce Hydro
Aluminiums pre-tax income and after-tax income by approximately NOK 800 million and NOK 560
million, respectively. Hydros extensive use of derivatives in managing its aluminium price exposure may result in
additional volatility of its financial results from period to period. Hydro Aluminium is exposed to foreign exchange rate fluctuations. Because Hydro Aluminiums smelters are located predominately in Norway and Germany, a
substantial portion of fixed costs are denominated in NOK and Euro. The weakening US dollar has
resulted in a decline in the competitive position of Hydro Aluminiums smelter system. In addition,
Hydro Aluminiums downstream operations are negatively impacted by the increasing euro compared to
US based competitors. Hydro Aluminiums operations are dependent on substantial amounts of energy and, as a
result, its profitability may decline if energy costs rise or if energy supplies are
interrupted. Hydro Aluminiums operations consume large volumes of energy, mainly electricity, in producing
primary aluminium. Most of Hydro Aluminiums smelters in Norway, Canada and Australia have
electricity supply contracts with terms ranging from approximately 10 to 15 years. The electricity
supply contracts for Hydro Aluminiums German smelters, scheduled to expire at the end of 2005,
will need to be extended or alternative supply arrangements made.Hydro Aluminium may not be able
to renew or replace these contracts on comparable terms following the expiry of these contracts. As
a result of increasing energy costs, as well as weakened competitiveness due to the strengthened
Euro compared to the US dollar, Hydro has written down the value of the German smelter system by
approximately NOK 2.3 billion. See the discussion in Item 4.B. Business Overview  Hydro Aluminium
 Hydro Aluminiums Operating Sub-Segments  Metals  Raw Materials  Energy. 12




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Hydro Aluminium is particularly exposed to energy tax regimes in Norway and Germany because of
its substantial electricity consumption in these countries. If electricity costs rise as a result
of market or other factors such as new taxes, or if electricity supplies or supply arrangements are
disrupted, Hydro Aluminiums operating results could decline. For further information see Item 4.B.
Business Overview  Hydro Aluminium  Government Regulation. Hydro Aluminium is subject to a broad range of environmental laws and regulations in the
jurisdictions in which it operates. Hydro Aluminium is subject to a broad range of environmental laws and regulations in each of
the jurisdictions in which it operates. See Item 4.B. Business Overview  Hydro Aluminium 
Environmental Matters. These laws and regulations, as interpreted by relevant agencies and courts,
impose increasingly stringent environmental protection standards regarding, among other things, air
emissions, the storage, treatment and discharge of waste waters, the use and handling of hazardous
or toxic materials, waste disposal practices, and the remediation of environmental contamination.
The costs of complying with these laws and regulations, including participation in assessments and
remediation of sites, could be significant. In addition, these laws and regulations create the risk
of substantial environmental liabilities, including liabilities associated with divested assets and
past activities. Hydro Aluminiums expansion of business in emerging and transitioning markets presents a
higher degree of financial, political, economic and business risks. Hydro Aluminium is increasing its business operations in emerging and transitioning markets.
Such markets present a higher degree of risk than more developed markets. In addition to the
business risks inherent in developing and servicing new markets, economic conditions may be more
volatile, legal systems less developed and predictable and the possibility of various types of
adverse governmental action more pronounced. Hydro Aluminium is exposed to the non performance of its contracts partners Hydro Aluminium enters into various contracts to secure the price and availability of raw
material and products for its manufacturing and remelt operations. These activities contain the
risk that one or more counter parties will default on their obligations to Hydro resulting in
direct financial losses, unexpected increased market exposure or higher operating costs. Poor or
deteriorating economic conditions on a global, regional or industry sector level increase the risk
of counter party default. Hydro Aluminium could be adversely affected by disruptions of its operations. Many of Hydro Aluminiums customers are, to varying degrees, dependent on planned deliveries
from Hydro Aluminiums plants located in various parts of the world. Breakdown of equipment or
other events leading to production interruptions in Hydro Aluminiums plants could lead to
financial losses. Interruption in the energy supply to a smelter for more than six to eight hours
could lead to the metal solidifying in the pots (see Item 4.B. Business Overview  Hydro Aluminium
 Overview of the Aluminium Industry  Aluminium Smelting), which would result in Hydro Aluminium
incurring significant costs to restore the smelter to normal operations. Reduced production,
itself, could result in reduced income. Further, customers may have to reschedule their own
production due to Hydro Aluminiums missed deliveries, which may result in customers pursuing
financial claims against Hydro Aluminium. For example, Hydro Aluminium supplies many of the
automotive manufacturers in the world and, in a number of cases, is a sole supplier for special
products. The automotive industry is particularly dependent on regular, on-time supplies. The
consequences of not meeting scheduled deliveries or quality standards might be costly. Hydro
Aluminium may incur costs to correct any of such problems, in addition to facing claims from
customers. Further, Hydro Aluminiums reputation among actual and potential customers may be
harmed, potentially resulting in a loss of business. While Hydro Aluminium maintains insurance
policies covering, among other things, physical


 damage, business interruptions, product liability and transportation, these policies may not cover
all of Hydro Aluminiums losses. 13




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Hydro Aluminium could be subject to unusual or significant litigation arising out of
alleged defects in products Hydro Aluminium is a leading supplier of extrusion based application within crash
management (ie. bumper beams) in Europe and has crash management operations in the United States.
Hydro Aluminium could be subject to class action suits in the event of failure of such systems or
be subject to claims or litigation relating to recall campaigns by automobile manufactures deemed
necessary as a result of defects within such systems. Risks Relating to Hydros Shares Preferential rights may not be available to U.S. holders of Hydros shares. Under Norwegian law, prior to Hydros issuance of any new shares against consideration in
cash, Hydro must offer holders of its then-outstanding shares preferential rights to subscribe and
pay for a sufficient number of shares to maintain their existing ownership percentages, unless
these rights are waived at a general meeting of Hydros shareholders. These preferential rights are
generally transferable during the subscription period for the related offering and may be quoted on
the Oslo Stock Exchange (the OSE). U.S. holders of Hydros shares may not be able to receive, trade or exercise preferential
rights for new shares unless a registration statement under the U.S. Securities Act of 1933, as
amended (the Securities Act) is effective with respect to such rights or an exemption from the
registration requirements of the Securities Act is available. If U.S. holders of Hydros shares are
not able to receive, trade or exercise preferential rights granted in respect of their shares in
any rights offering by Hydro, then they may not receive the economic benefit of such rights. In
addition, their proportional ownership interests in Hydro will be diluted. Holders of Hydros shares that are registered in a nominee account may not be able to exercise
voting rights as readily as shareholders whose shares are registered in their own names with
the VPS. Beneficial owners of Hydros shares that are registered in a nominee account (e.g., through
brokers, dealers or other third parties) may not be able to vote such shares unless their ownership
is re-registered in their names with the Norwegian Central Securities Depository,
Verdipapirsentralen (the VPS), prior to Hydro general meetings. Hydro cannot guarantee that
beneficial owners of its shares will receive the notice for a general meeting in time to instruct
their nominees to either effect a re-registration of their shares or otherwise vote their shares in
the manner desired by such beneficial owners. See the discussion in Item 10.B Articles of
Association  Description of Ordinary Shares  Voting Rights. It may be difficult for investors based in the United States to enforce civil liabilities
predicated on U.S. securities laws against Hydro, its Norwegian affiliates, or Hydros
directors and executive officers. Hydro is organized under the laws of the Kingdom of Norway. All of Hydros directors and
executive officers reside outside the United States. Further, a significant portion of Hydros
assets, and those of its directors and executive officers, are located in Norway and other Western
European countries. As a result, it may be difficult for investors in the United States to effect
service of process within the United States upon Hydro or its directors and executive officers or
to enforce against Hydro or its directors and executive officers judgments obtained in U.S. courts
predicated on the civil liability 14




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provisions of U.S. federal securities laws. Although U.S. investors may bring actions against
Hydro, its Norwegian affiliates or any of its directors or executive officers resident in Norway,
Norwegian courts are unlikely to apply U.S. law when deciding such cases. Accordingly, there is
doubt as to the enforceability, in original actions in Norwegian courts, of liabilities predicated
solely on U.S. federal securities laws. Furthermore, judgments of U.S. courts are not enforceable
in Norway. 15




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ITEM 4.
    INFORMATION ON THE COMPANY 
  ITEM 4.A.
    HISTORY AND DEVELOPMENT OF THE COMPANY Historical Overview Norsk Hydro ASA was organized under Norwegian law as a public company in 1905 to utilize
Norways large hydroelectric energy resources for the industrial production of nitrogen
fertilizers. In the years since, energy, in the form of hydroelectric power, natural gas and
petroleum, has been the basis for Hydros growth and the common link among its core business
activities. Following the end of the Second World War, Hydro expanded into a number of new businesses. In
1951, Hydro began to produce magnesium metal and polyvinyl chloride at Porsgrunn, Norway. In 1967,
Hydro opened an aluminium reduction plant and semi-fabricating facilities at Karmøy, Norway, and
built the Røldal-Suldal hydroelectric power project to provide energy to the Karmøy facilities. In 1965 and 1967, Hydro commenced production of ammonia at two large ammonia plants in Norway,
one of which made use of naphtha and the other, heavy fuel oil, as feedstocks (i.e., sources of
hydrogen) in the ammonia production process. Hydro had previously depended on the electrolysis of
water to provide the hydrogen needed to produce ammonia used in nitrogen-based fertilizers. The
discovery of natural gas in the Netherlands and on the continental shelf off England in the North
Sea created a new and competing source of feedstock for ammonia in Europe. Consequently, Hydro
began to take steps to ensure that it could continue to compete with other European producers of
ammonia that were obtaining access to these relatively inexpensive natural gas supplies. As a
result, Hydro began to investigate various opportunities to participate in oil and gas production.
In 1965, Hydro obtained concessions from the Norwegian State to explore for petroleum on the NCS. Hydro and its partners discovered oil and gas in the Ekofisk field in 1969 and in the Frigg
field in 1971. Exploration of these discoveries ensured Hydro a source of feedstock for its
fertilizer plants and also brought Hydro into the petroleum refining and marketing business. In
1975, Hydro began oil refining operations at Mongstad, Norway. Norways natural gas liquids resources and Hydros experience in the chemical process industry
served as the foundation for its investments in the petrochemicals industry in Norway, and in 1978,
Hydro commenced production of ethylene and vinyl chloride monomer. In the 1980s, Hydro acquired a number of businesses, both in Norway and in other areas.
Hydros expansion of its fertilizer operations resulted in Hydro becoming one of the leading
suppliers of fertilizer in Europe. Hydro also entered a new era as an oil company, becoming
operator of the Oseberg offshore oil field. Hydro also developed or tested new technologies for
deep-water oil and gas production and horizontal drilling, which Hydro subsequently put to
commercial use in developing the Troll oil project. In 1986-87, Hydro acquired the Norwegian
State-owned aluminium company, Årdal og Sunndal Verk, and several European aluminium extrusion
plants from Alcan and Alcoa, thus establishing Hydro Aluminium as a major business within Hydro and
an important player in the European aluminium industry. In recent years, each of Hydros Oil and Energy and Aluminium businesses has grown as a result
of substantial investments, including several acquisitions. In 1999, Hydro acquired Saga Petroleum
a.s, a Norwegian-based oil company, merging Sagas operations into Hydro Oil and Energy. In 2002,
Hydro acquired interests in eight oil and gas licenses on the NCS from the Norwegian State. This
acquisition increased Hydros interests in the Oseberg, Tune and Grane fields, where Hydro is the
operator. Hydro paid NOK 3.45 billion (US$415 million) for the license interests which expire
between 2015 and 2032. In March 2002, Hydro acquired all the outstanding shares of VAW for a total
purchase price, including indirect acquisition costs, of euro 1,911 million (NOK 14.8 billion;
US$1.7 billion). 16




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Earlier in that same year, Hydro acquired the French building systems supplier, Technal. A
significant portion of the expansion of these two core business areas has been financed through the
sale of non-core businesses. In March of 2004, Hydro completed the demerger of its Agri business transferring all assets,
rights, liabilities and obligations primarily relating to the Agri business to Yara International
ASA. Today, Hydro is a Fortune 500 energy and aluminium supplier operating in more than 40
countries. Hydros other activities include: its petrochemicals business; a 68.8 percent interest
in BioMar Holding AS (formerly Treka AS), whose activities consist of fish feed operations; the
Companys service and support operations including Hydro Business Partner, Hydro IS Partner and
Hydro Production Partner; and Industriforsikring a.s, a captive insurance company. General Information As a public limited company organized under Norwegian law, the Company is subject to the
provisions of the Norwegian act relating to public limited liability companies (i.e., the Norwegian
Public Limited Companies Act). See the disclosure under Item 10.B.  Articles of Association 
Description of Ordinary Shares for a more complete discussion of certain provisions of the
Norwegian Public Limited Companies Act. The Companys principal executive offices are located at Drammensveien 264, Vækerø, N-0240
Oslo, Norway; telephone number: 47-22-53-81-00. The Companys registered agent in the United States
is Trygve Faksvåg, whose address is c/o Norsk Hydro Americas, Inc., 100 North Tampa Street, Suite
3300, Tampa, Florida 33802; telephone number: (813) 222-5700. Hydros internet site is
www.hydro.com. The information on Hydros website is not incorporated by reference to this annual
report on Form 20F and should not be considered part of this report. 
 ITEM 4. B. BUSINESS OVERVIEW HYDRO OIL AND ENERGY Hydro Oil and Energy consists of two sub-segments, Exploration and Production and Energy and
Oil Marketing.  
    Exploration and Productionconsists of Hydros oil and gas exploration activities,
field development activities and the operation of production and oil transportation
facilities.
    Energy and Oil Marketingconsists of Hydros commercial operations in the oil,
natural gas and power sectors, the operation of Hydros power stations, management of
Hydros interest in the gas transportation system on the Norwegian Continental Shelf as
well as Hydros seaborne transportation of crude oil, natural gas liquids and other
petroleum products and the marketing and sales of refined petroleum products (e.g.,
gasoline, diesel and heating oil). Definitions of oil and gas terms used throughout the business description of the Oil and
Energy segment are provided at the end of the Exploration and Production business description.
These terms have the meanings indicated unless the context indicates otherwise. EXPLORATION AND PRODUCTION Introduction and Overview Exploration and Productions business activities encompass oil and gas exploration, field
development and the operation of production and oil transportation facilities. 17




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Hydro has a significant position on the Norwegian Continental Shelf (NCS), where it is the
third-largest producer of equity (i.e., owned) oil and natural gas. In 2004, approximately 90
percent of Hydros average daily production of 572,000 barrels of oil equivalents (boe) was from
the NCS. As an operator of 11 producing fields on the NCS with a total production in 2004 of
approximately 979,000 boe per day (boed), Hydro is a relatively large operator of oil and gas
fields, in particular, offshore fields. Internationally, Hydros main producing fields are in Canada and Angola. Hydro also has
producing fields in Russia and Libya. In addition to these countries, Hydro is involved in
exploration activities in other countries, including the United States (Gulf of Mexico) and Iran. Hydro has a history of delivering strong production growth. From 1998 to 2004, Hydro has more
than doubled its total equity production of oil and gas. Oil Industry Trends The main trends in the oil industry affecting Hydros Exploration and Production activities
are described below. Trends affecting the energy market are described under the Energy business
description. High Crude Oil Price Levels Spot Brent prices have increased from about USD 20 per barrel to roughly USD 40 per barrel
during the latest three years. Most of the price increase has occurred since the summer of 2003.
Spot Brent averaged USD 38.2 per barrel in 2004, almost USD 10 per barrel higher than the 2003
average at USD 28.8 per barrel. There are primarily two main factors underlying the significant
price increase over the last 18 months. First, there has been a tremendous growth in oil demand in particular in China and also in
North America as a result of substantial economic growth. According to the International Energy
Agency (IEA), Chinese demand grew by 850,000 barrels per day in 2004 while demand in North America
grew by 550,000 barrels per day. Most of the increase in demand related to light oil products such
as gasoline and other distillates. However, growth in global refining capacity has not kept pace
with the growth in demand, resulting in high margins for light oil products and a corresponding
oversupply of heavy products. This, in turn, created large incentives for refiners to purchase
light sweet crude oils like Brent and West Texas Intermediate (WTI). OPEC reacted by increasing
production, however, the additional OPEC crude oil was not of the quality refiners were demanding.
Second, there has been increasing political unrest in key oil producing countries, in particular,
Iraq and Saudi Arabia. Acts of terror and sabotage in these countries have escalated throughout
2004. OPEC aims to function as a stabilizing force in the market. Its long-term price target has
been considered to be USD 25 per barrel. However, many analysts believe that the cartel will raise
its price target in 2005 to above USD 30 per barrel. Increasing finding and development costs
outside OPEC and few indications of declines in consumption resulting from oil prices over USD 30
per barrel are factors underlying a higher target price for OPEC. Analysts believe that a higher
target price may increase exploration activity outside OPEC, as more projects become economical to
develop. However, notwithstanding an increase in target price, crude oil prices could continue to
reflect cyclical periods of high and low prices from the interplay between market forces and
actions taken by OPEC. Exploration activity changing expenditure trends The IHS Energys 2004 report on world petroleum trends shows that while total expenditures
increased from 1994 to 2003, exploration expenditures as a proportion of total exploration and
development expenditures has decreased from 26.8 percent in 1998 to 18.7 percent in 2003. However,
there is a time-lagged correlation between higher oil prices and exploration activity, which
indicates that there could be an upturn in strategic exploration investment. 18




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Reduced Exploration Results Worldwide Based on preliminary data from IHS Energy, worldwide oil and gas exploration activity during
2004 resulted in significantly smaller discoveries and lower amounts of hydrocarbons discovered
compared to the previous two years. Based on the top two hundred discoveries world wide, average
discovery sizes dropped significantly from 2003/2002 to 2004. It is becoming increasingly difficult to replace oil production by new discoveries. As a
result, advances in reservoir management technology to increase recovery are becoming more
important. Fewer major discoveries has also increased the focus on developing viable solutions for
exploiting smaller oil fields. Deepwater Dominates Major Finds Advances in deep water technology have opened up new areas for exploration and development.
According to IHS Energy data, the trend observed in 2003 of the dominance of deep-water discoveries
continued in 2004. During the year, 12 of the 20 largest discoveries originated from deep-water
explorations. Areas with significant
discoveries were India, Brazil, Angola, Egypt, Vietnam, Mauritania, as well as parts of West Africa. Overall
exploration results offshore Canada, Norway and the UK continued to be disappointing. Maturing Areas in the Developed World the NCS The NCS, where 92 percent of Hydros proven reserves are located, is maturing. Norways oil
production continued to decline in 2004, with total oil production reduced by about 1.6 percent
compared to 2003. Oil production from new development is not keeping pace with production declines
from maturing fields. Increasing gas production offset to some extent the negative trends in oil production. In 2004
approximately 78 billion cubic metres of gas were sold from the NCS, an increase of more than 7
percent compared to 2003. Combined with increased condensate and natural gas liquids (NGL)
production, total petroleum production for 2004 resulted in a marginal increase of 0.5 percent
compared to 2003. The increased price assumptions mentioned above are believed to have a positive impact on
Hydros investment opportunities in Norway and internationally over time. A permanent increase in
NCS exploration and development activity will, however, be dependent on more than just high prices.
Two major factors that will also affect long-term activity on the NCS are whether the Norwegian
authorities will allow increased access to attractive acreage and whether the Norwegian tax system
will be revised to increase the international competitiveness of the petroleum industry in Norway. As part of the Revised National Budget, passed in June 2004, the Norwegian government made
certain changes to the Petroleum Tax Act, which will be put forward in the budget for 2005. These
changes are described more in detail under the caption Taxation of Oil and Gas Production. Hydro
believes that the changes are moderately positive. Strategy and Competitive Position Hydros goal is to position itself as one of the most profitable players in the upstream oil
and gas business by exploiting its core competencies, underlying all elements of the value chain
including exploration, design, execution and operations. In addition, Hydro is determined to
maintain a strong commercial attitude in all its endeavors to create value. To achieve its goals,
Hydro intends to focus its exploration and production activities on: 19




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
    delivering strong production growth through 2008 based on Hydros existing portfolio
in well-defined, profitable projects;
    building the basis for future, long-term production through three avenues for growth:  
    Existing portfolio
    Exploration
    Acquisitions; andimproving the profitability of existing assets. Delivering Strong Production Growth Growth is important for business performance but also for the development of an organizations
capabilities. Hydro has a history of delivering strong production growth. From 1998 to 2004, Hydro
more than doubled its total equity production of oil and gas. The increase included organic growth
on the NCS, start-up of production from Hydros international activities, and the acquisition in
1999 of Saga Petroleum. In addition, during 2002, Hydro acquired increased ownership interests on
the NCS from the Norwegian State in the Hydro-operated fields Oseberg, Tune and Grane. Total oil and gas production in 2004 was 572,000 boed, representing an increase of almost 8
percent over the prior year. This increase reflected the first full year of production from the
Grane field and the Fram field, both of which came on-stream in the fall of 2003, as well as the
start-up of new fields in 2004, when Skirne came on-stream in May and Kvitebjørn started producing
in the end of September. The positive effects of these developments were partly offset due to the
Snorre, Vigdis and Terra Nova shutdowns caused by oil- and gas leakages and the declining
production from maturing fields. Hydro had previously announced a targeted average compound annual growth rate for production
of 8 percent for the 2001-2007 period. Hydro has extended this target to 2008, and expects that
this production growth will be achieved within its existing portfolio based on producing fields,
fields under development and fields planned for development. More than 60 percent of the production
in 2008 is expected to come from currently booked proved reserves. Hydro has targeted an average
daily production of 575,000 boe for 2005, of which approximately 85 percent is expected to come
from currently booked proved reserves. For further information regarding currently booked proved
reserves, see the table of proved reserves included in Note 27 to the Consolidated Financial
Statements. See, also, the description of fields underlying the growth projections within the
disclosure under Item 4B Business Overview  Hydro Oil and Energy  Exploration and Development 
Development within this annual report. In 2004,approximately 10 percent of Hydros total oil and gas production came from outside
the NCS, mainly Canada and Angola. Total international oil production was approximately 58,000
boed. Building the Basis for Future Production In 2004, Hydro evolved its strategy for upstream growth in each geographical area it
operates in based on the following key elements:  
    the optimal development and exploitation of existing assetsto secure a solid
foundation for new opportunities.
    improved working processes support explorationas a source of longer-term growth. Hydro
has decided to increase the level of exploration in 2005 and plans to operate and
participate in approximately 30 exploration and appraisal wells during the year. 20




---



##### 




    acquiring proven resourceswhere Hydros core competencies and expertise, including
advanced drilling techniques, flow-assurance, reservoir management and execution of complex
and technologically challenging projects, can add value to assets traded in the
marketplace. The current high oil price level creates both opportunities for and challenges
to future production growth. In general, Hydro believes that new opportunities will arise
relating to existing assets and for exploration activities. In addition, although
increasingly more expensive, the acquisition of technical resources still provides
attractive potential through the application of Hydros distinct capabilities, and in 2004,
the Company has entered into deals and evaluated several other opportunities. As a consequence of the high crude oil levels, Hydro has decided to increase the price
assumptions used for oil and gas investment decisions to 25 USD/boe for Brent Blend equivalent
quality for oil-related investments. Similar adjustments have been made for gas-related
investments. However, all investment decisions will be evaluated for robustness using 20 USD/boe
for Brent Blend equivalent. Investment proposals failing to meet this test will be subject to a
more in-depth risk assessment prior to investment decisions. Hydro believes that the changed price
assumptions will result in new business opportunities that were previously deemed uneconomic. Hydros international expansion has been based on alliances with regional producers and
international partners with a focus mainly on oil prospects. Hydro is also pursuing exploration and
production opportunities in gas prospects within close proximity for piped transportation to the
European market (see also Energy and Oil Marketing  Energy  Strategy and Competitive
Position - Enhancing the Value of Hydros Natural Gas Portfolio). Hydros strategy for international expansion has been to concentrate its efforts in areas with
sufficient potential to create economic scale. Hydros technological competence, including the
application of leading-edge reservoir and development solutions developed through its experience as
an operator of oil and gas producing fields in the harsh Norwegian offshore environment, has
provided a solid basis for Hydros international expansion. Over time Hydro has been working to increase its local geological knowledge in focused areas.
The combination of expertise in all parts of the value chain gained on the NCS with an
understanding of complex local geological, political and other business factors is proving valuable
in Hydros increased focus on internationalization of its oil and gas business. Improving the Profitability of Existing Assets Hydro continues to pursue cost improvements in its exploration and production activities. As
fields on the NCS mature and demonstrate a decline in production, high priority will be given to
reducing costs and implementing measures to increase production on existing fields, including
development of satellite fields that may be time critical with respect to utilizing existing
infrastructure. Hydros objective is to maintain and improve its status as an efficient operator. Hydro has announced a targeted production cost1 in 2005 of NOK 24/boe. Hydros
actual cost was NOK 20.7 in 2004. The difference between actual and target results from expected
cost for gas injection into the Grane field. Hydro plans to continue its efforts to drive down
costs on operated facilities despite the underlying maturing nature of the portfolio. Strong Position on the NCS The NCS has been the most important area for Hydros oil and energy business, and this is
expected to continue to be the case for the foreseeable future. The following reflects Hydros view
regarding potential opportunities on the NCS:   1
    
    Production cost is comprised of the
cost of operating fields, including CO2 emission tax, insurance, gas
purchased for injection, and lease costs for production installations, but
excluding transportation and processing tariffs, operation costs for
transportation systems and depreciation. 21




---



##### 




    Many of Hydros oilfields on the NCS contain large amounts of gas. As a result, Hydros
current portfolio on the NCS will become increasingly linked to gas. These gas resources
are highly profitable because most of the necessary infrastructure is in place and flexible
export opportunities exist.
    There are significant unexploited hydrocarbons in most of Hydros operated fields.
Hydro believes that such hydrocarbons could be exploited depending on the
implementation of new technological solutions combined with an aggressive focus on
cost-efficiency.
    Infrastructure-led exploration has resulted in several minor discoveries that could be
developed close to or tied into existing facilities. Hydro is continuously seeking optimal
development solutions for these resources.
    There is a potential for further infrastructure-led exploration. Existing
infrastructure with spare liquid capacity is a key driver for exploration in maturing areas
of the NCS. Hydro plans to drill 4-5 wells per year within its core areas to optimize the
resource utilization in the vicinity of its operated facilities. Active infrastructure-led
exploration is also a key factor in maintaining production cost per barrel at a profitable
level and extending the life of the infrastructure in the tail-end production phase. In recent years frontier exploration in Norway has yielded disappointing results. Licenses
awarded in the 17th and 18th rounds, however, in addition to the re-opening for exploration of the
Barents Sea, have provided acreage with interesting high-risk/high-reward prospects for Hydro.
Hydro plans to drill between 5 to 10 wells on this acreage in the coming years. In December 2003,
the Norwegian government decided to allow further petroleum activities within areas already open
for exploration in the southern part of the Barents Sea with some exceptions. The Norwegian
government also intends to reevaluate the re-opening of Nordland VI as part of an integrated
management plan for the Barents Sea, which is expected to be finalized in the spring of 2006. In total, Hydro has a sizeable and balanced exploration portfolio on the NCS comprising
acreage extending from the southernmost Farsund Basin to the Barents Sea, both near infrastructure
and in frontier areas. In 2004, Hydros strong position on the NCS was reflected through awards of
high equities and operatorships in all prioritized blocks made available in both the
18th Concession Round and the Awards in Predefined Areas. Hydro is the third-largest producer on the NCS, trailing Petoro (the Norwegian State oil and
gas holding company) and the majority State-controlled Statoil. In 2004, approximately 90 percent
of Hydros average daily equity production of 572,000 boe came from the NCS. As of 31 December 2004, Hydro had interests in 104 licenses on the NCS, of which it was
operator of 54 licenses. In total, the licenses cover a gross offshore area of around 38,710 square
kilometers (km) in the North Sea, the Norwegian Sea and the Barents Sea. The corresponding net
offshore area (Hydros share) is around 13,790 square km. Hydro also has interests in four
exploration areas with a total of 9 optional licenses on the NCS, of which it is operator of one
area. Each of the optional licenses may turn into a license under normal conditions if the partners
commit to an exploration well following seismic evaluations. These four exploration areas cover an
additional gross area of more than 14,000 square km and a net area of about 4,480 square km. Hydro is the operator of 11 producing oil and gas fields on the NCS: Oseberg, Oseberg Øst
(East), Oseberg Sør (South), Brage, Tune, Njord, Troll Oil (Troll B and C), Heimdal, Vale, Grane
and Fram Vest. Hydro is also the operator of the development phase of the large Ormen Lange gas
field, for which the Plan for Development and Operation (PDO) was approved by the authorities in
April 2004. Hydro also submitted a PDO for the Vilje field on the NCS in 2004, which is planned to
be developed as a subsea tie-back solution to the Marathon-operated Alvheim facilities. In November
2004, Hydro submitted a PDO for gas export from the Njord Field to the authorities, which was
approved in January 2005. 22




---



##### 



The total average daily production in 2004 from Hydro-operated fields was approximately
979,000 boe, which demonstrates that Hydro is a relatively large operator of oil and gas fields, in
particular offshore fields. Measured in terms of equity production, however, Hydro is a
medium-sized upstream oil and gas company. This is partly due to the Norwegian licensing system,
under which a relatively low equity interest historically has been awarded to the operators. Hydro has an equity interest in most of the main producing oil and gas fields on the NCS. The
most important producing fields for Hydro in 2004 were the fields in the Oseberg area, the Troll
field and the Snorre fields. The Grane oil field, which started production in 2003 and is expected
to reach plateau production at the end of 2005, is now a large contributor to Hydros Norwegian oil
production. Other important fields were Åsgard, Tune, the Sleipner fields, the Gullfaks fields, and
the Ekofisk fields. The Ormen Lange field is the largest field presently under development on the
NCS and Hydro expects that Ormen Lange will be an important part of Hydros production after
start-up in 2007. Hydro will continuously evaluate opportunities to optimize its portfolio on the NCS. In
January 2004, Hydro signed an agreement with Statoil for the sale of Hydros equity share in the
Snøhvit field. The sale was approved by the Norwegian authorities and completed in 2004. In 2003,
Hydro also entered into an agreement to sell its interest in the Gjøa field, which is presently in
the pre-development phase. The sale was completed in the first quarter of 2004. In January 2004, Hydro agreed to purchase an additional 2 percent equity interest in the
Kristin field from Statoil in order to improve Hydros position in the Norwegian Sea. In the second
quarter of 2004 Hydro also signed an agreement for the purchase of ExxonMobils 20 percent equity
share in license PL 248 including gas-condensate discoveries. Hydro is the operator of PL 248 with
an equity share of 40 percent after the acquisition. In order to ensure a cost effective
development of Skinfaks/Rimfaks fields, Hydro acquired a 9 percent share in licenses PL 152, PL 277
and PL 037 E. After this transaction Hydro has 9 percent in all licensees involved in the
Skinfaks/Rimfaks development. Interesting International Positions In 2004, Hydros international oil production represented approximately 10 percent of its
total oil and gas production. The main producing fields are in Canada and Angola. Hydro also has
producing fields in Russia and Libya. In addition to these countries, Hydro is involved in
exploration or exploration-related activity in other countries, including the United States (Gulf
of Mexico), Iran, Denmark, Madagascar and Morocco. Angola:Hydro has participated in Angolas oil and gas industry since 1991. Hydros main asset
is its 10 percent interest in the deep water offshore Block 17, where a total of 15 discoveries
have been made as of 31 December 2004. This includes Girassol and Jasmim, which contributed to
Hydro an average of almost 22,000 boed of oil production in 2004. The development of the Dalia
project is progressing and is expected to come on stream in 2006. The development of the Rosa field
was approved in 2004 as a tie-back to the Girassol field. Rosa is expected to come on stream in
2007. The process of selecting a development solution is ongoing for the Cravo and Lirio
discoveries, as well as for the Acacia, Zinia, Perpetua and Hortenzia discoveries. Development of a
third production hub in Block 17 has been targeted as a potential concept. Hydro also holds a 30 percent interest and is the technical assistant to the Angolan national
oil company, Sonangol, the field operator, on Block 34. The first well, drilled in April 2002, did
not result in the discovery of hydrocarbons. A second exploratory well, drilled in December 2003,
discovered gas, but was considered a non-commercial well. Technical evaluations are continuing and
are focusing on new exploration models for a third exploratory well. 23




---



##### 



As of 31 December 2004, Hydro holds shares in a total acreage of around 9,000 square km,
mainly deep-water or ultra deep-water acreage with water depths down to 2,600 meters. Of this
acreage, about 5,900 square km is exploration acreage where Hydro has a 30 percent interest. Canada: In 1996 Hydro entered into a strategic alliance with Petro-Canada which included a
swap of certain Hydro interests in licenses on the NCS in exchange for the right to participate in
oil production from proven fields and explore for further oil discoveries on the Grand Banks of
Newfoundland. Hydro has maintained its ownership position in the ongoing projects acquired in 1996.
Hydro has ownership in two producing fields, Hibernia and Terra Nova, and is presently focusing on
optimization of these two fields. Hydro holds a 5 percent interest in the Hibernia field and a 15
percent interest in the Terra Nova field. These fields contributed a total average oil production
of approximately 27,000 boed in 2004. Hydro is also working together with the operator,
ChevronTexaco, to develop the Hebron field in the same area. Hydros strategy in Canada includes infrastructure led exploration, maturing the existing
exploration license portfolio and assessing risks and volumes in immature basins on the Grand Banks
and on the Scotian Shelf. At present, Hydro is working with its partners in evaluating the
Annapolis discovery located offshore Nova Scotia. As of 31 December 2004, Hydros 11 exploration
licenses cover a gross exploration area of approximately 18,000 square km and a net exploration
area of approximately 6,200 square km, including shelf and deep-water acreage with water depths
ranging from 50 to 3,100 meters. Russia: Hydro has been present in Russia for 15 years and has equity production from the
onshore Kharyaga field, which covers about 350 square kilometers of acreage in the Timan Pechora
basin. Hydro is a 40 percent co-owner. This field started production in 1999 and phase two came on
stream in 2003. In 2004, average equity production was 6,700 boed, which was less than expected
partly due to lack of access to transportation. Hydro believes that this problem will be solved in
2005. Hydro is also pursuing new business opportunities in Russia. In December 2004, Hydro signed a
Memorandum of Understanding (MoU) with Gazprom for the evaluation of the giant Shtokman gas field,
which is located in the deep water continental shelf on the Russian side of the Barents Sea. The
MoU outlines a joint work program between the two companies covering technical, marketing and
commercial aspects of the project. Libya: Hydro is a partner in the onshore Mabruk field, which lies in the northern part of the
country. Hydro holds a 25 percent interest in Mabruk. In addition, Hydro has taken part in oil
exploration in the Murzuq Basin, in the Sahara Desert, since 1998. Production in the Murzuq Basin
started in the autumn of 2003 from the A-field and in June 2004 from the D-field. Hydros equity
share of the fields in the Murzuq basin is 20 percent in the exploration phase, 10 percent in the
development phase and 8 percent in the production phase. Total average daily equity production from
Hydros Libyan fields was around 2,800 boed (net after
royalties and profit oil) in 2004. Libya represents an interesting resource potential. Hydro will
continue to pursue new opportunities in Libya in light of the currently improving general political
situation in the country. As of 31 December 2004, Hydros four licenses in Libya cover a gross
onshore area of around 37,000 square km. The net exploration acreage is around 7,400 square km. In 2004, Hydro and Wintershall formed a consortium for the purpose of evaluating and
negotiating new business opportunities in Libya in 2004 - 2006, and possibly beyond. Wintershall, a
crude oil and natural gas producer based in Germany, has been active in Libya since 1958. Iran: Hydro established an office in Tehran, Iran during November 1999. Hydro currently has no
assets under development or in production in Iran. In April 2000, Hydro entered into a contract
with the National Iranian Oil Company for the exploration of the Anaran Block close to the Iraqi
border. The Anaran Block covers an area of approximately 3,200 square kilometers, of which Hydro
will acquire 1,000 square km of 2D seismic and drill 5 wells. The contract has a term of 4.5 years with an
option for a one-year extension. In July 2004, Hydro was granted a one-year extension until October
2005. The agreement provides Hydro with the right to enter into negotiations for a buy-back
agreement to develop 24




---



##### 



reserves in the event of a commercial discovery. The Anaran block is considered challenging to
explore, with a difficult geological environment. After clearing seismic tracks for mines, Hydro
completed the seismic acquisition program. The first well (Azar 1) was spudded in the spring of
2003, but drilling proved to be more difficult than anticipated, and the well was abandoned in
January 2004. Azar 2 was spudded in May 2004 with the same target as Azar 1, and is estimated to be
completed in the second quarter of 2005. Pending the results from this well, Hydro plans to drill a
third well on the block (the Changuleh West well) during the second half of 2005. Hydros farm-out
of 25 percent of the interest in the Anaran contract to the Russian company, Lukoil, was approved
by the Iranian authorities in 2003, leaving Hydro with an equity share of 75 percent. Hydros prime objective in Iran is to focus on completion of the exploration program on the
Anaran Block. A successful completion of the activity in Anaran could better position Hydro for new
opportunities in Iran. Hydro has submitted a bid for a new exploration contract on the Khoramabad
block in the Lurestan area. Awards are expected to be announced in the summer/fall of 2005. In
September 2004, Hydro submitted a bid for negotiating a contract for developing the Yadavaran
field. Awards for companies to enter into negotiations are expected to occur during the first half
of 2005. US Gulf of Mexico: Hydro entered into a joint venture agreement with ConocoPhillips in
September 2001. The agreement provided Hydro with a 25 percent working interest in five firm and
three contingent exploratory wells in the US Gulf of Mexico. An obligation to participate in the
fifth firm well was later eliminated and the joint venture agreement amended to provide for Hydros
participation in the Lorien prospect, which at the time was operated by ConocoPhillips. The Lorien
prospect was drilled in 2003 and resulted in a discovery. The other four firm wells did not result
in commercial discoveries. In 2004, Hydro increased its working interest in the Lorien discovery
from 10 to 30 percent. An appraisal well was drilled in 2004 and an integrated project team is
working on plans for developing the Lorien discovery, which is now operated by Noble Energy. Hydro
also acquired a 57.5 percent interest in the Champlain discovery in 2004. In January 2005, Hydro
was approved by the Minerals Management Service  Gulf of Mexico Region, as operator of the
Champlain field. As the new operator, Hydro has renamed the field Telemark. In total,
Hydros 72 exploration leases as of 31 December 2004 in the US Gulf of Mexico, of which Hydro is
the operator of 27 leases, cover a gross exploration area of around 1,700 square km, and a net
exploration area of around 790 square km, in deep-water. Hydro has concentrated its efforts in the
Central US Gulf of Mexico to establish a good geological knowledge base in the area. In the lease
sale in April 2004, Hydro was awarded seven new exploration blocks, all in these areas. In addition, Hydro has two exploration licenses in Denmark.Hydro had one exploratory license
in Trinidad and Tobago, which was relinquished in December 2004. During 2004 Hydro also commenced
evaluation of frontier acreage offshore Madagascarin the Majunga basin together with ExxonMobil
and Vanco Energy, an oil and gas company based in the US. The gross exploration acreage is almost
18,000 square kilometers, and Hydro has a 30 percent equity share while Vanco is operator of the
project. Acquisition of seismic information was finalized in 2004, and limited financial exposure
exists at present. Drilling alternatives will be evaluated during 2005 prior to potential
exploration decisions. A similar approach was taken relating to the NW Safi offshore basin in
Moroccoduring 2004. Hydro signed an investigation contract for the license in April 2004. The
gross exploration acreage is about 6,500 square km. Hydro is the operator of the project , and
plans to develop possible drilling prospects prior to seeking potential partners to reduce its
financial exposure prior to actual drilling. Exploration The following tables reflect the number of exploratory oil and gas wells drilled by Hydro as
of 31 December 2004. The first table reflects all of the gross exploratory wells drilled and
completed during the years indicated. The second table reflects the exploratory wells in the
process of being drilled as of 31 December 2004. A total of 17 wells were drilled and completed in
2004, of which 11 were considered productive. In addition, 3 wells were in the process of being
drilled at year-end. 25




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##### 



Drilling Activity Norway
    
    
    
    International
    
    
    
    TotalExploratory wells
    
    
    
    2004
    
    
    
    2003
    
    
    
    2002
    
    
    
    2004
    
    
    
    2003
    
    
    
    2002
    
    
    
    2004
    
    
    
    2003
    
    
    
    2002Productive (1)
    
    

Gross    (3)
    
    
    
    2
    
    
    
    
    2
    
    
    
    
    6
    
    
    
    
    9
    
    
    
    
    1
    
    
    
    
    8
    (5)
    
    
    
    11
    
    
    
    
    3
    
    
    
    
    14
    (5)Net    (4)
    
    
    
    0.33
    
    
    
    
    0.4
    
    
    
    
    0.78
    
    
    
    
    1.8
    
    
    
    
    0.1
    
    
    
    
    1.2
    
    
    
    
    2.13
    
    
    
    
    0.5
    
    
    
    
    1.98Dry (2)
    
    
    Gross
    
    
    
    4
    
    
    
    
    4
    
    
    
    
    5
    
    
    
    
    2
    
    

    
    
    6
    
    
    
    
    12
    
    
    
    
    6
    
    
    
    
    10
    
    
    
    
    17Net
    
    
    
    1.05
    
    
    
    
    0.8
    
    
    
    
    1.24
    
    
    
    
    0.45
    
    
    
    
    1.64
    
    
    
    
    2.67
    
    
    
    
    1.5
    
    
    
    
    2.42
    
    
    
    
    3.91
   (1) A productive well is an exploratory well deemed to be commercially viable.(2) A dry well is an exploratory well found to be incapable of producing either oil
or gas in sufficient quantities to justify completion as an oil or gas well.(3) A gross well is a well in which a whole or fractional working interest is owned.(4) A net well is the sum of the whole fractional working interests in gross wells
which equal one.(5) Includes the Acacia and Hortensia discoveries in Angola. These wells were drilled
during 2002 and the result announced in 2003. In Process Drilling Activities As of 31 December 2004
    
    
    
    Norway
    
    
    
    International
    

    
    
    
    TotalExploratory
    
    
    Gross
    
    
    
    0
    
    
    
    
    3
    
    
    
    
    
    
    3Net
    
    
    
    0
    
    
    
    
    1.1
    
    
    
    
    
    
    1.1
 As part of its exploration program in 2005, Hydro plans to participate in approximately
30 exploration and appraisal wells. Around 20 of these wells are planned on the NCS and the
remaining wells are planned internationally, mainly in Libya and Angola. Norway In 2004, Hydro participated in 6 exploratory wells and was operator for one of the wells. Two
of the wells resulted in commercial discoveries: the Linerle well, located north of the Norne
field, and the Topas well, located between the Gullfaks and Visund fields. The Linerle discovery,
in which Hydro holds a 13.5 percent interest, will be evaluated through one or two appraisal wells
in 2005. The Hydro-operated exploratory well, Brontes, which is located south of the Oseberg field,
was dry. In 2004, Hydro also participated in drilling activity in
connection with producing wells that resulted in three additional
commercial discoveries: the Vigdis extension well, the Brage 31/4-A-30 B well, and an
extension of the first production well on the Kristin field that proved a new reservoir zone, the
Tofte formation. Several of the wells planned for 2004 were postponed due to operational problems and a labor
dispute relating to floating rigs on the NCS. These wells include the Obelix well in the Barents
Sea, the Stetind well located in the deepwater Norwegian Sea, as well as the Hejre appraisal well
located in Denmark. In 2004 Hydro was awarded a total of 12 new licenses. Four of the licenses were awarded as
part of the 18th Concession Round initiated in December 2003, and 8 related to licenses
offered in the Awards in Predefined Areas initiated in January 2004. Several of the licenses
awarded to Hydro have the potential for large discoveries and new, stand-alone developments. These
include the award in the Farsund Basin blocks 11/5 and 11/6 and the award in block 35/2, where
Hydro was chosen as operator and awarded a 60 percent equity interest. 26




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##### 



In October 2004, the government requested the nomination of blocks for the
19th Concession Round covering the Norwegian Sea and the Southern Barents Sea. The
deadline for submission of nominations was 23 February 2005. The deadline for submission of license
applications is expected to be the fourth quarter of 2005, with awards of new licenses taking place
early in 2006. In January 2005, the government announced the Awards in Predefined Areas 2005. The
deadline for submission of applications is 30 September 2005 and the awards are planned to take
place in December 2005. Hydro is the operator of PL 248 located in the northern part of the North Sea and
intends to submit a PDO of these gas-condensate discoveries during 2005. Production is planned to
begin during 2008, but the actual start date is highly dependent upon the development concept
selected. The current plan is to develop the discoveries as subsea tie-backs to existing or new
infrastructure in the area. In 2004, Hydro acquired an additional 20 percent equity share in PL 248
from ExxonMobil and now holds a 40 percent equity interest. International In 2004, Hydros international exploration activities encompassed Angola, Canada, Libya, Iran,
the United States (Gulf of Mexico), and Denmark. Hydro participated in 11 exploratory and appraisal
wells that were completed during 2004. In Angola, one appraisal well was successfully drilled and completed on Block 17 during 2004.
A second appraisal well was spudded in December and is scheduled to be completed in the first
quarter of 2005. The appraisal wells are expected to confirm the reserve estimates as a basis for
selecting a development concept during 2005 for the UM area in Block 17. Appraisal of the Lirio
discovery in Block 17 is planned for 2005. One exploration well remains to be drilled in Block 34
and alternative exploration models will be evaluated for the well. In 2004, Sonangol P&P found oil
in Block 4 in cooperation with Hydro. Sonangol P&P and Hydro have signed a letter of intent with
the objective to commercialize the discovery. In Canada, one well was drilled relating to a new prospect in the Annapolis license. The well
did not result in a commercial discovery. In Libya, two exploration wells and six appraisal wells relating to license NC-186 in the
Murzuq basin were drilled during 2004. Three appraisal wells were drilled on the B-structure of
NC-186 and a Field Development Plan (FDP) was submitted to Libyan authorities in December. A new
commercial discovery was made on the H-structure in NC-186 and 3 appraisal wells were drilled. By
year end, production testing was taking place in well H4 in the NC-186 license. The exploration and
appraisal program in Libya will continue in 2005 with the planned drilling of further wells
relating to the Murzuq licenses. In Iran, the Azar 1 well on the Anaran block was spudded in the spring of 2003 and was
abandoned in January 2004 due to technical difficulties. Azar 2 was spudded in May 2004 with the
same target as Azar 1. Completion is estimated during the second quarter of 2005. In the US Gulf of Mexico, Hydro participated in a successful appraisal well relating to the
Lorien discovery. In Denmark, Hydro has a 25 percent interest in license 6/98 covering the Hejre discovery. An
appraisal well was completed at the end of February. The well
discovered
hydrocarbons, and the results will now be further evaluated before a
decision can be taken regarding possible development and production
on Hejre. Reserve Information At the end of 2004, Hydros share of proved developed reserves of oil and gas was estimated to
be 1,447 million boe. Hydros share of proved undeveloped reserves accounted for an additional 629
million boe. Total developed and undeveloped proved reserves amounted to 2,076 million boe, of
which gas reserves represented approximately 56 percent. 27




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##### 



Reserve life, defined as the number of years of production from proved reserves at the present
production level, was approximately 10 years at the end of 2004, with approximately 6 years for oil
and approximately 21 years for gas. The following table summarizes Hydros net quantities of proved oil and gas reserves as of 31
December 2004, 2003 and 2002. Oil and Gas Reserves Oil in millions of boe
    
    2004
    
    
    2003
    
    
    2002Gas in billions of cubic feet
(bcf)
    
    Norway
    
    
    Intl (1)
    
    
    Total
    
    
    Norway
    
    
    Intl (1)
    
    
    Total
    
    
    Norway
    
    
    Intl (1)
    
    
    TotalProved oil reserves, developed and
undeveloped (2)
    
    
    749
    
    
    
    156
    
    
    
    905
    
    
    
    839
    
    
    
    154
    
    
    
    993
    
    
    
    883
    
    
    
    172
    
    
    
    1,055Of which developed
    
    
    607
    
    
    
    97
    
    
    
    704
    
    
    
    690
    
    
    
    88
    
    
    
    778
    
    
    
    559
    
    
    
    93
    
    
    
    652Proved gas reserves, developed and
undeveloped(2)
    
    
    6,626
    
    
    
    
    
    
    
    6,626
    
    
    
    7,317
    
    
    
    
    
    
    
    7,317
    
    
    
    6,629
    
    
    
    
    
    
    
    6,629Of which developed
    
    
    4,197
    
    
    
    
    
    
    
    4,197
    
    
    
    4,415
    
    
    
    
    
    
    
    4,415
    
    
    
    4,416
    
    
    
    
    
    
    
    4,416Proved oil and gas reserves,
developed and undeveloped
(in millions of boe)(2)
    
    
    1,920
    
    
    
    156
    
    
    
    2,076
    
    
    
    2,134
    
    
    
    154
    
    
    
    2,288
    
    
    
    2,053
    
    
    
    172
    
    
    
    2,225Of which developed
    
    
    1,350
    
    
    
    97
    
    
    
    1,447
    
    
    
    1,470
    
    
    
    88
    
    
    
    1,558
    
    
    
    1,339
    
    
    
    93
    
    
    
    1,432
   (1)
    Reserves reflected in the International columns are shown net of royalties
in kind and the governments share of profit oil.(2)
    For the definition of proved reserves, proved developed reserves and proved
undeveloped reserves, and applicable conversion factors, see Definitions of Oil and Gas
Terms at the end of the Exploration and Production business description. Proved reserves are estimates and are expected to be revised as oil and gas are produced and
additional data become available. Accordingly, recoverable reserves are subject to upward and
downward adjustments from time to time. Please see the discussion in Item 5. Operating and
Financial Review and Prospects  Hydros Critical Accounting Policies  Proved Oil and Gas
Reserves. An analysis of changes to proved developed and proved undeveloped reserves of oil and gas as
of and for the three years ended 31 December 2004, 2003 and 2002 is included in the table in Note
27 to the Consolidated Financial Statements. Estimates of the proved reserves, presented on an
individual field basis, as of 31 December 2004, can be found in Exhibit 99.2 Operational Data to
this annual report. Development In
2004, Hydro invested2 NOK 10,678 million in the development of new and existing
fields and transportation systems compared to NOK 8,487 million and NOK 8,222 million in 2003 and
2002, respectively. The implementation of SFAS 143 relating to asset retirement obligations
resulted in an additional charge of NOK 1,089 million for 2003, which is not included in the above
amount. For more information on Hydros adoption of SFAS 143, see Note 1 to the Consolidated
Financial Statements. Hydros most important exploration and production development projects in
2004 were the Snøhvit, Kristin, Ormen Lange, and Dalia fields. Hydros sale of its equity share in Snøhvit was
finalized 31 December 2004.   2
    Includes changes in estimates for asset
retirement costs and new accruals for fields that commenced production during
the year. 28




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##### 



A summary of the fields under development as of 31 December 2004 is included in the following
table. Only the main fields are presented in the table. Development projects in connection with
fields under production and smaller satellite developments relating to fields in production are
described under the caption Production below. Fields under Development Production
    
    
    
    Total Estimated
    
    
    
    InvestmentApproved for
    
    
    
    Scheduled to
    
    
    
    Investment(1)
    
    
    
    Incurred to Date(1)Field
    
    
    Type of Field
    
    
    
    Development
    
    
    
    Commence
    
    
    
    (in NOK billion)
    
    
    
    (in NOK billion)
    
    
    
    Hydros Equity ShareNorwayOrmen Lange (2)
    
    
    Gas/Condensate
    
    
    April 2004
    
    
    October 2007
    
    
    
    52.9
    
    
    
    
    4
    
    
    
    
    18.0728
    %Kristin (3)
    
    
    Oil/Gas
    
    
    December 2001
    
    
    October 2005
    
    
    
    20.8
    
    
    
    
    14.7
    
    
    
    
    14
    %Vilje (4)
    
    
    Oil
    
    
    Pending approval
    
    
    February2007
    
    
    
    2.2
    
    
    
    
    0
    
    
    
    
    28.8
    %InternationalDalia
    
    
    Oil
    
    
    April 2003
    
    
    October 2006
    
    
    
    22.6
    
    
    
    
    7.5
    
    
    
    
    10
    %Rosa
    
    
    Oil
    
    
    August 2004
    
    
    April 2007
    
    
    
    12.4
    
    
    
    
    2
    
    
    
    
    10
    %
   (1)
    Total Estimated Investment and Investment Incurred to Date amounts are as of
31 December 2004. These amounts represent the total estimated investment based on the PDO
or current cost estimate and total incurred investment for the applicable field,
respectively. All amounts are in nominal values (i.e., not discounted to present value).
The exchange rate used for Dalia and Rosa was US dollar/NOK 6.0386 as of 31 December 2004.(2)
    The total estimated investment for Ormen Lange excludes the cost of the Langeled
gas export pipeline.(3)
    Hydros interest in the Kristin field was increased from 12 percent to 14 percent
in 2004. The operator of the Kristin field, Statoil, increased the
investment estimate for Kristin in March 2005. The Kristin reservoir
is very complex and deep, and has a number of faults, and flow
properties are not as good as the development plan forecast.(4)
    The Vilje PDO was submitted to the authorities in December of 2004. Approval is
expected in March 2005. In connection with the development projects described in this section, Hydro has invested
(excluding internal costs) NOK 0.2 billion, NOK 1.1 billion and NOK
2.6 billion for the years 2002, 2003 and 2004,
respectively. Estimated investments for the same projects for 2005, 2006 and 2007 are NOK 4.1
billion, NOK 3.7 billion and NOK 1.7 billion, respectively. Norway The PDO for the Ormen Langegas field was submitted to the Ministry of Petroleum and Energy on
4 December 2003, together with the Plan for Installation and Operation (PIO) for the new gas
export pipeline, Langeled. The authorities approved both the PDO and the PIO in the beginning of
April 2004. Ormen Lange is situated in water depths of 850 to 1,100 meters in the Norwegian Sea,
100 km off the northwest coast of Norway. Based on seismic and other data, Ormen Lange is believed
to be the second-largest gas field and the largest field presently under development in Norway.
Given Hydros estimate of the total proved reserves for the field, Hydros share is 234 million boe
including 35.0 billion cubic meters (bcm) of gas. The field development is planned as a sub-sea
installation linked to the Nyhamna onshore processing plant not far from the city of Molde in
Norway. Gas is to be exported
from the plant through a new pipeline (Langeled) via the Sleipner riser platform to Easington 29




---



##### 



on the east coast of England. Langeled will be merged with the Gassled pipeline joint venture after
start-up of operations of the southern leg of the pipeline in 2006. Production is scheduled to
begin in October 2007. The total investment, in nominal terms, is estimated at NOK 72.9 billion,
including NOK 52.9 billion for field and plant development and NOK 20 billion for the pipeline.
Hydros equity share is 18.0728 percent. Hydro is the operator during the development phase of the
field. The Kristinoil and gas field is situated in the Norwegian Sea, approximately 20 km south of
the Åsgard field. The field will be developed with sub-sea production facilities tied back to a
semi-submersible production platform. Gas will be exported through the Åsgard transport pipeline
while condensate will be loaded offshore from Åsgard C. Production from the field is expected to
commence in October 2005. Hydro entered into an agreement with Statoil in 2004 to increase its
interest in the Kristin field from 12 to 14 percent. The Norwegian authorities approved the
transaction during the second quarter of 2004. The transaction was finalized in December 2004.
Given Hydros estimate of the total proved reserves for the field, Hydros share is 43 million boe
including 2.8 bcm of gas. The Viljeoil field (formerly called Klegg) will be developed as a 2-well subsea tie-back to
the Alvheim Floating Production, Storage and Offloading unit (FPSO) situated 18 km away. The PDO
is expected to be approved in March 2005. The total investment, in nominal terms, is estimated at
NOK 2.2 billion. Hydros equity share in the Vilje field is 28.8 percent. Production is expected to
commence in February 2007, dependent upon production start of the Alvheim FPSO, which is currently
under construction. Hydro has no equity interest in the Alvheim development. In January 2004, Hydro announced that it had entered into an agreement to sell its equity
share in licenses relating to the Snøhvitfield to Statoil. The Norwegian authorities approved the
transaction during the second quarter of 2004. The transaction was finalized in December 2004. International Angola: The Dalia field is the third development on Block 17 and was sanctioned by the Angolan
government at the end of April 2003. The development concept comprises a sub-sea production system
linked to a FPSO with an average production capacity of 225,000 boed. Production is expected to
commence in October 2006. The total proved reserves for the Dalia field are 31 million boe. Hydros
equity share is 10 percent. The Rosa field was sanctioned by the Angolan government in August 2004.
The Rosa field will be developed as a tie-back to the Girassol FPSO. Production is expected to
commence in April of 2007 and is expected to reach a plateau production of 130,000 boed. The total
proved reserves for the Rosa field are 9 million boe. Hydros equity share is 10 percent. Production The following table includes the number of gross and net productive oil and gas wells in
which Hydro had interests as of 31 December 2004. Type of well
    
    
    
    
    
    Norway(1)
    
    
    
    International
    
    
    
    TotalCrude oil
    
    
    Gross
    
    
    
    531
    
    
    
    
    120
    
    
    
    
    651Net
    
    
    
    72
    
    
    
    
    20
    
    
    
    
    92Natural gas
    
    
    Gross
    
    
    
    106
    
    
    
    
    0
    
    
    
    
    106Net
    
    
    
    11
    
    
    
    
    0
    
    
    
    
    11
   (1)
    Includes 52 wells with multiple completions (i.e., more than one formation
producing into the same well bore). If one of the multiple completions in a well is an oil
completion, the well is classified as an oil well. 30




---



##### 



The following table reflects Hydros share of the average daily production of oil and gas
from fields in which Hydro had an interest during 2004 and 2003. Information regarding the total
production of oil and gas in 2004, the remaining production period of the producing fields and the
license period for such fields can be found in the table included in Exhibit 99.2 Operational
Data to this annual report. Hydros Share of Average Daily Production(1) 2004
    
    
    2003Total in
    
    
    Oil in
    
    
    Gas in
    
    
    Total in
    
    
    Oil in
    
    
    Gas inthousands
    
    
    thousands
    
    
    millions of
    
    
    thousands
    
    
    thousands
    
    
    millions ofField
    
    of boe
    
    
    of boe(1)
    
    
    cubic feet
    
    
    of boe
    
    
    of boe(1)
    
    
    cubic feetOseberg fields (2)
    
    
    115.7
    
    
    
    95.3
    
    
    
    104.3
    
    
    
    115.1
    
    
    
    103.0
    
    
    
    59.6Troll
    
    
    74.9
    
    
    
    32.1
    
    
    
    247.6
    
    
    
    80.0
    
    
    
    37.0
    
    
    
    248.1Snorre fields (3)
    
    
    58.1
    
    
    
    56.2
    
    
    
    10.7
    
    
    
    67.5
    
    
    
    65.0
    
    
    
    12.8Grane
    
    
    46.3
    
    
    
    46.3
    
    
    
    
    
    
    
    5.5
    
    
    
    5.5
    
    
    
    Åsgard
    
    
    37.7
    
    
    
    21.3
    
    
    
    92.4
    
    
    
    40.6
    
    
    
    24.2
    
    
    
    91.6Tune
    
    
    33.4
    
    
    
    6.1
    
    
    
    144.8
    
    
    
    30.8
    
    
    
    7.8
    
    
    
    122.0Sleipner fields (4)
    
    
    32.8
    
    
    
    10.4
    
    
    
    122.9
    
    
    
    35.2
    
    
    
    12.0
    
    
    
    127.0Gullfaks fields (5)
    
    
    28.6
    
    
    
    23.0
    
    
    
    32.0
    
    
    
    26.0
    
    
    
    21.2
    
    
    
    26.8Ekofisk fields (6)
    
    
    28.5
    
    
    
    24.0
    
    
    
    23.4
    
    
    
    28.2
    
    
    
    23.9
    
    
    
    23.0Fram Vest
    
    
    12.3
    
    
    
    12.3
    
    
    
    
    
    
    
    2.9
    
    
    
    2.9
    
    
    
    Norne
    
    
    11.3
    
    
    
    10.1
    
    
    
    7.2
    
    
    
    13.2
    
    
    
    12.2
    
    
    
    5.9Visund
    
    
    6.2
    
    
    
    6.2
    
    
    
    
    
    
    
    6.6
    
    
    
    6.6
    
    
    
    Brage
    
    
    6.1
    
    
    
    5.7
    
    
    
    2.1
    
    
    
    7.3
    
    
    
    7.0
    
    
    
    1.9Njord
    
    
    5.8
    
    
    
    5.8
    
    
    
    
    
    
    
    6.1
    
    
    
    6.1
    
    
    
    Mikkel
    
    
    5.5
    
    
    
    2.6
    
    
    
    15.5
    
    
    
    1.5
    
    
    
    0.7
    
    
    
    4.4Frigg
    
    
    4.8
    
    
    
    
    
    
    
    27.7
    
    
    
    3.9
    
    
    
    
    
    
    
    22.6Heimdal fields(7)
    
    
    3.8
    
    
    
    1.3
    
    
    
    13.3
    
    
    
    2.1
    
    
    
    0.9
    
    
    
    6.9Kvitebjørn
    
    
    2.3
    
    
    
    0.8
    
    
    
    8.5
    
    
    
    
    
    
    
    
    
    
    
    Total Norway
    
    
    514.1
    
    
    
    359.5
    
    
    
    852.4
    
    
    
    472.5
    
    
    
    336.0
    
    
    
    752.6Girassol
    
    
    19.0
    
    
    
    19.0
    
    
    
    
    
    
    
    19.5
    
    
    
    19.5
    
    
    
    Terra Nova
    
    
    16.5
    
    
    
    16.5
    
    
    
    
    
    
    
    20.1
    
    
    
    20.1
    
    
    
    Hibernia
    
    
    10.2
    
    
    
    10.2
    
    
    
    
    
    
    
    10.1
    
    
    
    10.1
    
    
    
    Kharyaga
    
    
    6.7
    
    
    
    6.7
    
    
    
    
    
    
    
    5.5
    
    
    
    5.5
    
    
    
    Jasmim
    
    
    2.7
    
    
    
    2.7
    
    
    
    
    
    
    
    0.2
    
    
    
    0.2
    
    
    
    Mabruk
    
    
    2.0
    
    
    
    2.0
    
    
    
    
    
    
    
    2.1
    
    
    
    2.1
    
    
    
    Murzuq
    
    
    0.8
    
    
    
    0.8
    
    
    
    
    
    
    
    0.2
    
    
    
    0.2
    
    
    
    Total International
    
    
    57.9
    
    
    
    57.9
    
    
    
    
    
    
    
    57.7
    
    
    
    57.7
    
    
    
    Total
    
    
    572.0
    
    
    
    417.4
    
    
    
    852.4
    
    
    
    530.2
    
    
    
    393.7
    
    
    
    752.6
   (1)
    Includes crude oil and NGL/condensate.(2)
    Includes Oseberg, Oseberg Vest, Oseberg Sør and Oseberg Øst fields.(3)
    Includes Snorre, Tordis, Statfjord Øst and Sygna fields.(4)
    Includes Sleipner Vest, Sleipner Øst, Gungne and Sigyn fields.(5)
    Includes Gullfaks and Gullfaks Sør fields.(6)
    Includes Ekofisk, Eldfisk, Embla and Tor fields.(7)
    Includes Heimdal, Vale and Skirne fields. 31




---



##### 



Norway Oseberg Fields. Hydro is operator and has a 34 percent equity share in the Oseberg fields.
The Oseberg fields are core areas for Hydro on the NCS, contributing 22 percent of Hydros total
NCS production in 2004. The Oseberg Fields include the main Oseberg field (the Field Center
installations and the Oseberg C production platform) and the two satellite fields, Oseberg Øst
(East) and Oseberg Sør (South). Oil and gas from the satellites are piped to the Oseberg Field
Center for processing and transportation. Oil is brought ashore through the Oseberg Transport
System pipeline to the Sture terminal in Norway. Gas is exported through the Oseberg Gas Transport
pipeline to the Heimdal field and further through the Gassled pipeline system. Oil production from
the Oseberg Field Center and the Oseberg C platform are currently in the decline phase. Natural gas
export from the Oseberg Field Center and Oseberg Øst and Oseberg Sør began in 2000 and 2001,
respectively. A revised PDO for the development of the Oseberg Sør field was approved by the
authorities in May 2003. The revised PDO covers the J-structure that will be developed with a
separate sub-sea installation with production start-up in the early part of 2005. The total cost
for the J-development is estimated at NOK 1.6 billion, of which NOK 0.87 billion was invested as of
31 December 2004. The PDO of the Oseberg Vestflanken (West flank) was submitted to the authorities
in October 2003 and approved in December 2003. Production start-up is planned for December 2005.
Oseberg Vestflanken is planned to be developed by a sub-sea installation tied into the Oseberg
Field Center platforms. Total investments are estimated at NOK 2.3 billion, of which NOK 396
million was invested as of 31 December 2004. In 2004, partners in the Oseberg license and the
Norwegian authorities approved a plan for upgrading the Oseberg Øst platform to achieve a
profitable solution for further drilling and well activities, and the drilling of seven new wells.
Total project costs are expected to be NOK 1.9 billion, of which NOK 25 million was invested as of
31 December 2004. Production from the new wells is planned to commence early in 2007. In June 2004
the Agreement relating to Unitization and Operation of the Oseberg Area was signed, establishing
the Oseberg Area Unit. The agreement established the foundation for a coordinated and long-term
view on the development of the resources in the Oseberg area through balanced ownership, a
prolonged license period and the establishment of the Oseberg Area Unit. Hydro is currently
preparing a PDO for the Delta and G-Sentral structures in the Oseberg region, scheduled for
submittal to the Norwegian authorities in June 2005. Troll Field.The Troll field is the largest gas field on the NCS. Hydro holds a 9.78 percent
interest in the Troll field, which comprises two main structures: Troll East and Troll West. A
staged development has taken place with Phase 1 covering gas reserves in Troll East and Phase 2
focusing on the oil reserves in Troll West. Statoil is the operator of the Troll East facilities
and Hydro is the operator of the Troll West. Gas from the Troll field represents a major part of
Hydros current developed gas reserves and gas production. In 2004, approximately 30 percent of
Hydros gas production came from the field. The gas development consists of a platform linked to
the Kollsnes gas terminal. The gas is exported from Kollsnes through the Gassled system. Gas
production started in 1996. Troll is also a major oil field. The oil development on the western
part of Troll consists of two floating production units linked by two oil pipelines to the Mongstad
terminal. Oil production started in 1995. Snorre Fields.The Snorre fields, operated by Statoil, are located in the Tampen area and
include the Snorre, Tordis, Vigdis, Statfjord Øst and Sygna fields. Hydros interest in the Snorre
field is 17.65 percent. Production of oil and associated gas from the Snorre fieldbegan in 1992.
The Snorre B platform came on stream in June 2001. Oil and gas from the Snorre field is piped to
the Statfjord field for processing, storage and transportation. Production of oil and gas from the
Tordis fieldbegan in 1994. Hydros interest in the Tordis field is 13.28 percent. Oil from the
Tordis field is processed on the Gullfaks C platform. Production from the field peaked in 1996 and
is currently in the decline phase. Since the Tordis field started declining, several satellite
structures have been connected to the field including Tordis Øst in 1998, Borg in 1999 and Tordis
Sørøst in 2001. In 1999, water injection was implemented to increase the recoverable reserves from
the field. Production of oil and gas from the Vigdis fieldbegan in early 1997. Hydros interest in
the Vigdis field is 13.28 percent. Production began declining in 2000. To maintain production
levels, a PDO for the Vigdis Extension was submitted to and approved by the government in 2002 with
production start-up in October 2003. Oil from the Vigdis field is processed on the Snorre platform
and piped to Gullfaks A for storage and transportation. In order to 32




---



##### 



maintain production levels,
several projects for increased oil recovery (IOR) have been initiated in the
Snorre area during 2004. This applies for the Snorre A, Vigdis and Tordis fields. If approved
by the partnerships, these projects are expected to commence with a 2007 to 2009 time frame. The
Statfjord Østand Sygnafields started production in 1994 and 2000, respectively. Hydros interest
in the Statfjord Øst field is 6.64 percent and in the Sygna field 5.98 percent. Both fields are
linked to the Statfjord C platform. Due to technical problems related to a gas leak from a gas
injector underneath the Snorre A platform, both the Snorre and Vigdis fields were closed down on 28
November 2004. Production from both fields started up again in January 2005. Grane Field. The Grane field is located in the North Sea and is developed with an integrated
production and drilling platform. Hydro is operator of Grane and has a 38 percent equity share.
Production from the field started September 2003. Oil from the field is exported in a new pipeline
from the Grane platform to the Sture terminal in Øygarden, Norway. Gas for injection into the field
is imported through a 50 km pipeline from the Heimdal Gas Center to ensure optimum production of
oil. The Grane field contains heavier oil than what is normally found on the NCS. Åsgard Field.The Åsgard field, operated by Statoil, is situated in the Norwegian Sea. Hydros
interest in the Åsgard field is 9.6 percent. The Åsgard Unit covers the three fields, Midgard,
Smørbukk and Smørbukk Sør. The field is developed with a production ship (Åsgard A) for oil and
condensate production and a floating production platform (Åsgard B) for condensate and gas
production and a storage vessel (Åsgard C). Oil production started in May 1999 and gas export
commenced in October 2000. The gas is transported through the Åsgard Transport pipeline to the
Kårstø gas terminal for processing. Sleipner Fields.Production of gas and condensate began at Sleipner Østin late 1993 and from
Sleipner Vestin the middle of 1996. Statoil is operator of both fields, and Hydros interest in
the fields is 10 percent and 8.85 percent respectively. Production from the satellite fields,
Gungne, Loke Triasand Sigyn, began in 1996, 1999 and 2002, respectively. Gas from Sleipner is
exported through Gassled and the condensate is transported to the Kårstø facilities. In 2002, a
decision was made to develop the northern part of the Sleipner Vest field with four sub-sea wells.
These wells came on stream in October 2004. Tune Field. The Tune gas and condensate field (phase 1), operated by Hydro, is developed as a
sub-sea satellite to Oseberg. Hydros interest in the Tune field is 40 percent. The Tune field came
on stream in November 2002, using spare processing capacity at the Oseberg Field Center and was a
major contributor to Hydros growth in production in 2003. A decision to develop Tune phase 2 was
made in June 2004, with start up of a single well planned for October 2005. Tune Phase 2
exploration well was determined to be dry in February 2005. Further evaluation on the use of subsea
equipment for Tune Phase 3 is ongoing. Under considerations for Tune phase 3, is a 4-slot satellite
with a potential production start-up late 2005 or spring 2006 depending on rig availability. Gullfaks Fields. The Gullfaks fields, where Hydro has a 9 equity share, are situated in the
Tampen area. Statoil is the operator of Gullfaks. The main Gullfaks field consists of three
integrated platforms, where production started in 1986. The satellite fields, Gullfaks Vest,
Gullveig, Rimfaksand Gullfaks Sør, are linked to the main field. Tankers transport the oil from
the fields while gas is transported by pipeline to the Kårstø terminal in Norway. The Gulltopp
satelliteis under development (one long-reach well) and is expected to start production in
August 2005. A PDO relating to the Skinfaks/RimfaksIncreased Oil Recovery (IOR) satellite project
was submitted to the Norwegian authorities in December 2004 and approved in February 2005.
Production is planned to start in December 2006. Recovery from Rimfaks will be improved by drilling
supplementary wells. The development solution for the Skinfaks discovery is based on a subsea
production system tied back to the Gullfaks C platform. The total project investment is estimated
at approximately NOK 3.4 billion. Ekofisk Fields.Ekofisk, operated by ConocoPhillips, is situated in the southern part of the
North Sea and is the oldest operating field complex within Hydros portfolio, having commenced
production in 1971. Oil is exported through the Norpipe oil pipeline to Teesside in England, while
gas is 33




---



##### 



exported through the Gassled system. The Ekofisk Area Growth project includes installing of
a new
wellhead platform tied in to the Ekofisk II process platform. The platform jacket was
installed in August 2004 and pre-drilling of production wells started in November 2004. The
platform deck will be installed during second quarter of 2005 with potential first production in
the third quarter of 2005. Total investments for the Ekofisk Area Growth project are estimated at
NOK 8.5 billion, of which NOK 3.6 billion was invested as of 31 December 2004. Hydros equity share
is 6.65 percent. Alternatives for further development of the Eldfisk and Tor fields are being
discussed among the owners. A delineation well in the satellite field Embla is planned to be
drilled during the summer of 2005 with the potential of increasing the reserves in Embla
considerably. Fram Field. The Fram field is located approximately 22 km from the Troll field. Hydro is
operator and has a 25 percent equity share in the Fram field.The first phase of the
field, Fram Vest that comprises the H structure, is developed by a sub-sea installation linked to
the Troll C platform for processing. Production commenced in October 2003. Processed oil is
transported to the Mongstad terminal while gas will be used for re-injection for a period of
approximately six years to facilitate oil recovery. After this period, gas will be transported to
the Kollsnes gas terminal. The second phase of the Fram field, Fram Øst, comprises the F-East Upper
Sognefjord, the F-East Lower Sognefjord, the C-West Sognefjord and the C-West Etive reservoirs.
Fram Øst, is in the final stages of development planning, and is expected to include 5 horizontal
oil production wells and 2 multilateral (branched) water injection wells, drilled from two 4-slot
subsea templates. Investments are estimated at NOK 4.4 billion. The Sognefjord well streams will be
routed via a new production pipeline to the existing Fram and Troll facilities on the Troll C
Platform for processing, while the Etive well stream will be routed through the existing Fram Vest
production flowline. Water produced from Troll and Fram will be re-injected through a new flowline
into the Sognefjord reservoirs for pressure support. Processed oil will be transported to the
Mongstad terminal, while gas will be sent to the Kollsnes gas terminal. Production is expected to
start in October 2006. The drilling program on Fram Øst includes appraisal aspects, which could
lead to a third phase of Fram field development in the future. Facilities designed for Fram Øst
incorporate flexibility to add two more subsea templates. Hydro submitted a PDO for the Fram Øst
Field to the Norwegian Authorities in February 2005. Norne Field.The Norne field, operated by Statoil, is located in the Norwegian Sea. Oil
production started in late 1997. Gas production started in February 2001. The installation consists
of a combined production and storage vessel with gas handling facilities and a gas transportation
pipeline. The gas is transported via the Åsgard transportation pipeline to the Kårstø gas terminal
in Norway. Hydros equity share in the Norne field is 8.1 percent. In May 2004, the PDO for Urd
(also known as Norne satellites) was submitted to the Norwegian authorities. The PDO was approved
by the authorities in July. The two discoveries will be developed with sub-sea installations tied
back to the Norne Field installation. Total investments are estimated to be NOK 3.5 billion.
Hydros equity share in Urd is 13.5 percent. Visund Field.The Visund field, operated by Statoil, is situated in the Tampen area. The field
is developed with a floating production unit that came on stream in early 1999. Oil produced from
Visund is stored in and shipped from Gullfaks A. A sub-sea installation for developing the northern
reservoir of Visund was put on stream in early 2002. In October 2002, the authorities approved the
PDO of the Visund Gas Extension, which covers development of the gas volumes. The project includes
increased gas treatment and injection capacity and a gas export pipeline connected to the
Kvitebjørn gas pipeline for transport to the Kollsnes terminal. Gas export is expected to start in
October 2005. The total investment is estimated at NOK 2.0 billion, of which approximately NOK 1.1
billion was invested as of 31 December 2004. Hydros equity share is 20.3 percent. Brage Field.The Brage field is located in the North Sea, approximately 13 km east of the
Oseberg Field Center. Production began in 1993. Hydro is operator and has a 20 percent equity share
in the Brage field. Oil from the field is transported to the Sture terminal via the Oseberg Field
Center. Production from the field is currently in the decline phase. 34




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##### 



Njord Field.The Njord field, operated by Hydro, is located in the Norwegian Sea. Hydros
equity share in the Njord field is 20 percent. Production from the field began in late 1997. The
installation consists of a floating production unit (Njord A) combined with a tanker, Njord
Bravo, for storage and loading of oil. Gas produced is re-injected into the field to maintain
reservoir pressure. In November 2004, Hydro submitted a PDO for gas export from the Njord Field to
the authorities for approval. The PDO was approved in January 2005. Investments are estimated to be
NOK 1.1 billion. Gas exports are planned to commence late in 2007. The gas will be exported through
the Åsgard gas transportation system to Kårstø. Mikkel Field. The Mikkel field, operated by Statoil, is located in the Norwegian Sea and
started production in October 2003. Hydro has a 10 percent interest in the Mikkel field. The
development concept consists of sub-sea installations linked to the Åsgard B platform for
processing. The condensate will be exported from Åsgard C for offshore loading. The gas will be
transported to the Kårstø terminal through the Åsgard transport system. Frigg Field.The Frigg gas field was permanently shut down in October 2004. A removal and
abandonment project relating to the field installations and wells is scheduled to be completed
2010. Kvitebjørn Field. The Kvitebjørngas and condensate field, operated by Statoil, is situated
southeast of the Gullfaks field. Hydros equity share is 15 percent. The field is developed with a
fixed production platform. Rich gas is transported through a new pipeline to the Kollsnes gas
terminal for processing and export. Condensate is transported through the new Kvitebjørn oil
pipeline, which is connected to the Troll2 pipeline and further to the Mongstad terminal.
Production commenced in the end of September 2004. Drilling of production wells will continue
through year 2005. Skirne Field.The Skirnegas and condensate field, operated by Total, is situated
approximately 20 km east of the Heimdal field. Hydros equity share is 10 percent. The field
consists of the Skirne and Byggve structures, which have each been developed with one single subsea
well and tied back to the Heimdal gas center. Production started in March 2004. A booster
compressor module will be installed at the Heimdal gas center in 2005. Vale Field.Hydro is operator and has a 28.9 percent interest in the Vale field. The Vale
field was developed by one satellite well that is tied to the Heimdal Gas Center. Production
started in May 2002. In June 2005, the production will be suspended due to drilling of a new
sidetrack well. Production is expected to start up again in September 2005. Heimdal Field. Hydro is operator and has a 19.44 percent equity share in the Heimdal field.
The Heimdal gas and condensate field is currently operated as a gas processing and distribution
center after reconstruction of the platform in 2000 and 2001. Production of remaining reserves
began in August 2001 after a temporary shut down during the construction period. This tail-end
production is expected to last until early 2005. In March 2004, production started from the small
Skirne field, which is connected to the Heimdal Gas Center. International Angolan Fields.The Girassolfield, operated by Total, is an offshore field located on Block
17 in Angola. Hydro has a working interest of 10 percent. Oil production started in December 2001.
The installation consists of a production and storage-offloading vessel. The processing capacity is
above 250,000 boed and the storage capacity is two million barrels. The Jasmimfield is a sub-sea
satellite connected to the Girassol FPSO. Production started in November 2003. Canadian Fields. Both of Hydros producing fields in Canada are located in the Grand Banks
area off the east coast of Newfoundland. Oil production from the Hiberniafield, operated by
HMDC3,   3
    HMDC: Hibernia Management Development Company 35




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##### 



came on stream in November 1997. Hydro has a five percent interest in the field.
The Terra Novafield, operated by Petro-Canada, is southeast of Hibernia and started production in
January 2002. Hydro has a
working interest of 15 percent. The Terra Nova field was shut down from the end of November to mid
December 2004 due to an oil spill. Russian Fields. The Kharyagafield, operated by Total, is located in Northwest Russia.
Production commenced in October 1999 under the Production Sharing Agreement (PSA) entered into
with the Russian authorities. Hydros share in the PSA is 40 percent. Production from phase 2 of
the project has been gradually phased in since May 2003. A third phase is planned to further
increase the total production from 2007. Libyan Fields. Production from the Mabruk West field in the north of Libya, operated by Total,
started in 1995. Hydro became owner of a 25 percent interest in the license through the acquisition
of Saga in 1999. A FDP for Mabruk Phase IV (Mabruk Central and East) was approved by the Libyan
authorities in July 2004. The development includes construction of new facilities and drilling of
additional development wells in East and West Mabruk. The total estimated investment is USD 20
million. As of 31 December 2004, the incurred investment amounted to USD 25.3 million. Production
from the Murzuq A-field in the south of Libya started in October 2003 and from the Murzuq D-field
in June 2004. The Murzuq A- and D-fields are being developed as an integrated unit. A FDP for
Murzuq B was sent to the Libyan authorities for approval on 9 December 2004. Approval is expected
in the first half of 2005. The total estimated investment is USD 67.8 million. The NC 186 B-field
will also be integrated with the NC 186 A-field. Oil from the A, B and D-fields will be transported
from the NC 186 A gas oil separation plant to the El-Sharara field 29 km away, where it will be
blended with oil from NC 115 and NC 174 and transported by pipeline 726 km to the As Zawiyah
terminal west of Tripoli. Hydros equity share of the fields in the Murzuq basin is 20 percent in
the exploration phase, 10 percent in the development phase and 8 percent in the production phase. Transportation of Oil and Gas Norway All the main gas pipelines and terminals in Norway are owned and operated by a joint venture
called Gassled. Gassled is described in more detail in the business description for Energy and Oil
Marketing, which includes more comprehensive information regarding Hydros ownership share in
Gassled than is reflected in the table below. The information in the following table reflects Hydros interest in the major pipelines for
the transportation of oil and gas from the NCS and in the corresponding land terminals as of 31
December 2004. Length
    
    
    
    Hydros percentagePipeline
    
    
    End Point
    
    
    (km)
    
    
    
    interestGassled (gas)
    
    
    From the NCS to Germany,  Belgium, France and the U.K.
    
    
    
    > 6,000
    
    
    
    
    11.134
    (1)Langeled (2)
    
    
    Nyhamna - Sleipner (Norway) - Easington (U.K)
    
    
    
    1170
    
    
    
    
    17.6102Norpipe Oil A/S (oil)
    
    
    Ekofisk - Teesside (U.K.)
    
    
    
    354
    
    
    
    
    3.50Oseberg Transport System (OTS) (oil)
    
    
    Oseberg - Sture (Norway)
    
    
    
    115
    
    
    
    
    22.23Frostpipe (oil)
    
    
    Frigg - Oseberg (Norway)
    
    

    
    82
    
    
    
    
    13.75Sleipner Øst NGL pipeline (NGL)
    
    
    Sleipner - Kårstø (Norway)
    
    
    
    245
    
    
    
    
    10.00Troll Oil 1 & 2 (oil)
    
    
    Troll - Mongstad (Norway)
    
    
    
    165
    
    
    
    
    9.73Grane Oil Pipeline (oil)
    
    
    Grane - Sture (Norway)
    
    
    
    212
    
    
    
    
    24.40Grane Gas Pipeline (gas)
    
    
    Grane - Heimdal (Norway)
    
    
    
    50
    
    
    
    
    38.00Norne Gas Transport (gas)
    
    
    Norne- Åsgard (Norway)
    
    
    
    130
    
    
    
    
    8.10Vestprosess (NGL)
    
    
    Kollsnes/Sture - Mongstad  (Norway)
    
    
    
    56
    
    
    
    
    17.00
   (1)
    Initial interest. For further information please see Energy and Oil
Marketing business description.(2)
    The plan for installation and operation was approved by the authorities
in April 2004. 36




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The Stureterminal outside Bergen receives crude oil and condensate from the Oseberg
fields, Brage, Veslefrikk and Huldra through the Oseberg Transport System (OTS), and since 2003,
from the Grane field through the Grane Oil Pipeline. The terminal started operations in 1988. The
Sture terminal includes facilities for further processing of crude oil and for production of LPG (a
mix of propane and butane gases). The Sture terminal has the same ownership structure as OTS
excluding the LPG facilities that are owned 100 percent by Hydro and the export facilities for NGL
that are owned by Vestprosess DA, in which Hydro has an equity share of 17 percent. International Crude oil from the Hibernia and Terra Nova fields in Canada is transported from the fields
either directly to market or to a terminal located at Whiffen Head, Newfoundland in dedicated
offshore loading tankers. Hydro has an ownership interest in two of the tankers of 14.9 percent and
12.7 percent, respectively, and a 5 percent interest in the terminal. In addition, Hydro has
long-term contracts for use of storage capacity at the terminal. 37




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Definitions of Oil and Gas Terms Term
    
    
    Definitionbbl
    
    
    Barrelsbcm
    
    
    Billion cubic meters (Sm3)boe
    
    
    Barrels of oil equivalentsboed
    
    
    Barrels of oil equivalents per daybcf
    
    
    Billion cubic feetcf
    
    
    Cubic feet measured at 60 degrees Fahrenheit. See also Sm3condensate
    
    
    Light hydrocarbon substances produced with natural gas, which condense
into liquid at normal temperatures and pressures associated with
surface production equipment.development well
    
    
    A well drilled within the proved area of an oil or gas reservoir to
the depth of a stratigraphic horizon known to be productive. See
Regulation S-X, Rule 4-10(a)(11).dry well
    
    
    An exploratory well found to be incapable of producing either oil or
gas in sufficient quantities to justify completion as an oil or gas
well.exploratory well
    
    
    A well drilled to find and produce oil or gas in an unproved area, to
find a new reservoir in a field previously found to be productive of
oil or gas in another reservoir, or to extend a known reservoir. See
Regulation S-X, Rule 4-10(a)(10).FDP
    
    
    Field Development Planfield
    
    
    An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural
feature and/or stratigraphic condition. See Regulation S-X, Rule
4-10(a)(8).FPSO
    
    
    Floating Production, Storage and Offloadinggross well
    
    
    A well in which a whole or fractional working interest is owned.LPG
    
    
    Liquefied petroleum gas, a liquid composed chiefly of butane and
propane.net well
    
    
    The sum of the whole or fractional working interests in gross wells
that equals one.NGLs
    
    
    Oil and gas condensate and natural gas liquids. For purposes of
converting quantities of NGL cited in this annual report, 1 ton NGL =
11.951 boe.PDO
    
    
    Plan for development and operationproved reserves,,
proved developed
reserves, proved
undeveloped
reserves
    
    
    Proved reserves are estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions (i.e.,
prices and costs as of the date the estimate is made).
 38




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Term
    
    
    DefinitionProved developed reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.Proved undeveloped reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion.

For a more complete understanding of these terms, see Regulation S-X,
Rule 4-10(a) (2), (3) and (4). This information can be accessed on the
website of the SEC at www.sec.gov.PSA
    
    
    Production sharing agreement.reservoir
    
    
    A porous and permeable underground formation containing a natural
accumulation of producible oil or gas that is confined by impermeable
rock or water barriers and is individual and separate from other
reservoirs. See Regulation S-X, Rule 4-10(a)(9).Sm3
    
    
    Standard cubic meters measured at 15 degrees C. For purposes of
converting quantities of natural gas cited in this annual report, 1
Sm3 = 35.3826 cubic feet. When converting natural gas into
barrels of oil equivalents, Hydro makes an adjustment for calorific
value to an equivalent 40 MegaJoule/Sm3 volume. 1000
Sm3 of natural gas = 6.2898 boe.
 39




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##### 



ENERGY AND OIL MARKETING ENERGY Overview  Energys business activities include:
    marketing of Hydros equity oil production, including gas liquids;
    marketing of Hydros equity gas production as well as third-party sourced gas to
customers, primarily on the European continent;
    managing Hydros interest in the gas transportation system on the NCS and Hydros
sea-borne transportation of crude oil, NGLs and other petroleum products;
    production and sale of electricity generated at hydroelectric power plants in Norway;
    sourcing Hydros natural gas and power requirements for its Norwegian and European
industrial facilities; and
    developing Hydros hydrogen and renewable energy business activities. Hydro has an established position in the Northern European natural gas and power markets as a
producer of natural gas and power, a holder of an equity interest in the natural gas transportation
systems and as an active trader in the markets. By combining all commercial activities for energy
products and services in one operating segment, Hydro leverages its commercial skills and contacts
in each of the energy sectors. Hydros experience in the Nordic region contributes to Hydros
knowledge base in pursuing opportunities in other markets. Industry Trends Liberalization of European Electricity and Gas Markets In Europe, both the electricity and gas markets are undergoing liberalization as a result of
European Union (EU) policy. For more information on the EUs regulatory initiatives to further
the liberalization of EU energy markets, see    Oil and Energy Government Regulation -
Liberalization of European Electricity Markets and    Oil and Energy Government Regulation  EU
Gas Directives and Related Regulatory Developments. In October 2004, the European Commission announced that 18 member states have failed to
correctly transpose the new generation of electricity liberalization directives (Directive
2003/54/EC) and/or gas liberalization directives (Directive 2003/55/EC) into national law. The European Commission is of the view that the main problem for electricity in coming years
will be the issues of market dominance at the national level and the inadequate level of
interconnection between member states. Significant political, structural and transactional barriers still must be overcome before a
sustained gas wholesale liquidity can support a competitive gas end-customer market. Harmonizing
transmission and transport networks, tariffs, and accounting methods and breaking the strangle hold
of dominant producers is proving a challenging task. The 25 gas markets in the EU are at widely
differing stages of development and maturity, a factor that has long been acknowledged as one of
the key barriers to bringing about a truly liberalized and competitive single European gas market.
However, competition has increased in some markets. One example, the recent decision by the Dutch
government to acquire full ownership of the Dutch gas grid, is viewed as a catalyst toward a more
liberalized Dutch market. 40




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To be successful, exploration and production companies, traders, resellers and even major
industrial gas users need to be present at the international and regional European market hubs. Growth in European Natural Gas Demand It is anticipated that natural gas demand growth in Europe over the coming years will lead to
a shortfall in terms of current committed contracts of approximately 50 billion cubic meters (bcm)
by 2010. By 2010, all European countries, except Norway, are predicted to become net importers of
gas; Russia, Algeria and Norway are predicted to be key suppliers of Europes gas in 2010. Analysts indicate that demand for natural gas in Europe is expected to grow significantly from
the 2003 level of approximately 528 bcm. Electricity generation is the key to growing demand for
gas. Approximately 42 percent of EU power generation in 2030 is expected to come from gas-fired
plants, up from 40 percent in 2020, 29 percent in 2010 and 17 percent in 2000. In 2003, Norway supplied approximately 13 percent of the total consumption of natural gas in
Europe. This percentage is expected to rise in future years based on existing contract commitments
and remaining reserves. The United Kingdom, in particular, is an attractive market for Norwegian
gas due to the declining UK gas reserves. It is estimated that by around 2006 the UK will no longer
be self-sufficient in gas production. By 2010, it is estimated that the UK will be 50 percent
dependent on imported gas, rising to 80 percent by 2020. Integration of Energy Markets Along with the liberalization of the energy markets in Europe, there is a trend towards
integration of the electricity and gas markets because the business models are, to a large degree,
based on the same competence and types of customers. One of the main trends in the development of
the European energy market is the enlargement of companies that want to control more energy
sectors. Increased Focus on Renewable Energy and Hydrogen There is an increasing interest in renewable energy and the utilization of hydrogen in the
energy market in developed economies throughout the world. The major political drive and basis for
a number of public support schemes is driven by concerns about the security of energy supply and
environmental considerations. The International Energy Agency (IEA) expects the dependence on oil
imports in the EU to grow from 50 percent to 70 percent from 2002 to 2030. The IEA further predicts
a higher CO2 emission increase compared to energy demand in the same period, because the rise in
use of fossil fuels is higher than that of renewables. The European Union has adopted a directive (Directive 2001/77/EC) that seeks to promote the
production of electricity from renewable energy sources, including wind and hydropower. EU member
states have set an indicative target of 22 percent share of electricity to be produced from
renewable energy sources by 2010. The Norwegian Ministry of Oil and Energy has announced that
Norway wishes to implement the RES-E Directive and has also put forward a proposal for legislation
on a Norwegian mandatory green certificate market. The certificate market will be linked to the
existing Swedish certificate market and the plan for start-up of the common market is 1 January
2007. This is expected to increase focus on wind energy in an area characterized by having strong
and consistent wind conditions. Strategy and Competitive Position Hydros strategy is to further enhance its position in the Northern European energy market,
based on increasing gas production and commercial competence gained from the European gas market
and the liberalized Nordic power market. Focus areas comprise: 41




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##### 




    enhancing the value of Hydros crude oil portfolio;
    enhancing the value of Hydros natural gas portfolio;
    optimizing Hydros power activities; and
    pursuing hydrogen and renewable energy opportunities. Enhancing the Value of Hydros Crude Oil Portfolio The focus of Hydros marketing efforts with respect to its North Sea and international crude
oil production is to achieve optimal prices by marketing fewer grades of crude oil, in larger
volumes, while minimizing logistical costs. Swap arrangements result in savings in logistical
costs, particularly with respect to production from Hydros international crude oil portfolio. Trading activities include the sale of Hydros crude oil and NGL production. The volumes of
these activities have increased partly due to increased equity oil and gas production over the past
years. Furthermore, Hydro Oil and Energy supplies NGL feedstock to Hydros petrochemical plants, as
well as the former Hydro Agri (now Yara) fertilizer plants. Following the demerger of Agri, Hydro
has continued to supply the Yara fertilizer plants under arms-length agreements. The tables below reflect the volumes of Hydros sales and refining activities, respectively,
in the last three years. Sales(thousands of tonnes)
    
    
    2004
    
    
    
    2003
    
    
    
    2002Crude oil/NGL
    
    
    
    20,096
    
    
    
    
    18,560
    
    
    
    
    19,068Oil products
    
    
    
    0
    
    
    
    
    2,808
    
    
    
    
    2,326
 Enhancing the Value of Hydros Natural Gas Portfolio Hydro is increasingly becoming a key gas supplier for Europe. Because of location,
transportation infrastructure and substantial reserves, Norwegian natural gas is competitive in the
European region. Both the NBP (National Balancing Point in the UK) forward prices and German import
price estimates up to 2008 are well above the expected cost of the Ormen Lange gas to the UK. Hydro is the third-largest producer on the NCS, with a strong expected increase in equity gas
production. Hydro has an interest in all the major natural gas fields and in Gassled. Hydro also
holds capacity rights in Gassled, enabling access to five landing points for natural gas in Europe.
This offers a flexible and favorable position with respect to capturing value in the market. In the
European continental market, Hydro has achieved an attractive position through its flexible
portfolio based on a combination of long-term sales contracts, long-term supply contracts and
access to transportation. Hydros strategy is to combine its role as a natural gas producer with that of a wholesaler
and trader to increase its market share in the developing liberalized European natural gas market.
The main geographic focus is Northwest Europe. Hydro wants to develop a strong and balanced
customer portfolio, including a mix of long-term contracts with wholesalers, end-user sales to the
power and industrial segments, and spot sales, in order to optimize its natural gas portfolio. It is a continuous focus for Hydro to increase the value of Hydros natural gas portfolio
through, among other things, more optimal utilization of Hydros production and transportation
capacity. These upstream positions, combined with Hydros market presence across Europe, provide
Hydro with an opportunity to create business further down the gas value chain in Northwest Europe.
Further development will be based on both increased access to natural gas from fields in which
Hydro has an equity interest, and sourcing natural gas in the market. In line with this strategy,
Hydro has throughout 42




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2004 focused on integrating into its activities the portfolio acquired in late
2003 through the purchase of
Duke Energys gas sales and marketing organization in the Netherlands (Duke Energy Europe
Northwest B.V.), consisting of sourcing, sales, transportation and storage agreements. Another main activity in realizing the strategy has been the successful start-up of the
activities of HydroWingas, the UK joint venture between Hydro and Wingas GmbH, the German gas
transportation and supply company. The main goal in pursuing this joint venture is to establish a
competitive and effective UK gas marketing channel by combining Wingas and Hydros gas positions
and marketing skills. HydroWingas will focus on large industrial customers, power producers and the
wholesale segment. Marketing activities started in 2004, resulting in several signed contracts and
initial gas deliveries in the market. The table below reflects Hydros equity gas production and downstream non-equity gas sales and
sourcing in the last three years. (in bcm)
    
    
    2004
    
    
    
    2003
    
    
    
    2002Equity natural gas production
    
    
    
    8.8
    
    
    
    
    7.8
    
    
    
    
    6.4Sales of non-equity gas
    
    
    
    3.9
    
    
    
    
    3.8
    
    
    
    
    3.7
 In 2004, Hydros equity natural gas production from the NCS amounted to 8.8 bcm, an
increase of 13 percent compared to the previous year. In addition to its equity gas, during 2004 Hydro supplied 3.9 bcm in the downstream market ,
including 1.9 bcm supplied to the former Hydro Agri, now Yara, fertilizer activities. Natural gas produced from fields in which Hydro has an equity interest is mainly sold under
long-term contracts. Pricing under long-term contracts is generally based on a price formula
whereby the natural gas price is indexed to oil product prices in the end-user market, mainly gas
oil and low sulphur fuel oil. These contracts typically have provisions for price reviews based on
changes in certain market conditions. In the future, Hydro expects that an increasing volume of its natural gas will be sold under
contracts indexed to liquid European gas hubs such as NBP or Zeebrügge. Physical positions are
still necessary in order to gain increased margins by optimizing logistics and trading. Liquidity
within the UK NBP market has increased, and is now considered to be a viable, short-term market.
There is less liquidity on the European continent, however, but liquidity is increasing at several
emerging hubs, in particular at Zeebrugge in Belgium. Hydros presence at these major hubs enables
it to optimize its equity gas positions, both short- and long-term. Hydro has made substantial investments in natural gas export capacity from the Oseberg and
Troll fields, together comprising a major portion of its proved reserves of natural gas. This
capacity will enable Hydro to increase exports of gas significantly in the coming years as
reservoir conditions allow higher natural gas production. The start-up of the Ormen Lange gas field
will further increase Hydros gas production and the development of the connected Langeled
transportation system will further increase transportation flexibility on the NCS. The gas will be
transported by the worlds longest subsea export pipeline approximately 1200 kilometres from the
west coast of Norway via Sleipner in the North Sea to Easington in UK. Gassled, the natural gas transportation infrastructure joint venture on the NCS, has been in
operation since 1 January 2003. The NCS natural gas pipelines and associated terminals had
previously been organized as several different joint ventures owned by oil companies and the
Norwegian State. Gassled consists of the following systems: Europipe, Europipe II, Norpipe gas
pipeline, Zeepipe, Franpipe, Vesterled, Statpipe, Oseberg Gas Transport, Åsgard Transport and the
Kårstø terminal. The Kollsnes gas terminal is included in Gassled from 1 February 2004. Currently
Hydro holds a direct ownership interest of 11.134 percent in Gassled. Hydros participation in
future capacity expansions such as Langeled will initially result in a moderate increase in Hydros
ownership interest before it is
expected to be reduced to about 10 percent in 2011 in accordance with the agreed redistribution of
ownership shares. 43




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Optimizing Hydros Power Activities Hydro is one of the largest producers of electric power in Norway, with a normal annual
production from hydroelectric facilities in Telemark, Røldal/Suldal and Sogn of approximately 8.5
terrawatt hours (TWh). Hydro has been engaged in a large development project to expand the Tyin
hydropower plant in Sogn at a cost of approximately NOK 1.3 billion. The new Tyin power plant has
been in operation since fall 2004. Revitalization of the power plant has increased production by 15
percent based on the existing water reservoirs. Hydro has title concessions that will never revert to the Norwegian government for
hydroelectric power plants with an average generating capacity of 2.7 TWh per year. This represents
approximately 32 percent of Hydros normal production capacity. The remaining hydroelectric
production capacity, 5.8 TWh, or approximately 68 percent of Hydros normal production capacity,
will under the present
legislation4 revert to the Norwegian government without
compensation at the expiration date of each concession. Separate concessions apply to each power
plant. The year of expiration of the individual concessions ranges from 2022 to 2051. In
addition to its hydroelectric power stations, Hydro is a partial
owner (44 percent) of the
Havøygavlen wind power plant with a potential annual production of about 105 gigawatt hours (GWh). Hydro is, as a 50 percent owner of the company Naturkraft AS, evaluating the possibility of
building a new gas fired power plant at Kårstø, Norway. The final investment decision regarding the
project is expected to be taken by the summer of 2005. The power plant is planned to be in
operation during the fall of 2007. Hydros share of the expected annual production of the plant is
roughly 1.5 TWh. Since the liberalization of the Norwegian electricity market in 1991, Hydro has developed its
power trading and marketing activities, along with analysis, portfolio and risk management systems.
Hydros Nordic electricity portfolio includes owned generation facilities, long-term supply
contracts, internal and external sales contracts and short-term optimization contracts. The table below reflects Hydros power production and the volumes acquired under long-term
purchase contracts for the last three years. (in TWh)
    
    
    2004
    
    
    
    2003
    
    
    
    2002Power production
    
    
    
    8.1
    
    
    
    
    7.5
    
    
    
    
    10.3Acquired under long-term contracts for Hydros industrial use
    
    
    
    7
    
    
    
    
    7
    
    
    
    
    7
 As reflected in the table above, power production in 2004 was lower than normal due to
low precipitation during the early winter of 2004, and the residual effect of low precipitation in
Norway during the autumn and winter of 2002/03. Hydro Oil and Energy supplies electric power to Hydros industrial plants in Norway. To meet
those needs, Hydro has entered into long-term purchase contracts, the majority of which are with
the Norwegian State-owned power company, Statkraft. These long-term contracts provide assurance of
the availability of and predictable prices for a certain quantity of power to Hydros power
intensive industries. In 1997, Hydro entered into an agreement with Statkraft to purchase
electricity from 2000 to 2020. The agreement replaces supplies under existing contracts, which
terminate during the 2006-2010 period.   4
    The legislation regarding reversion is under
revision. The proposed change would have moderately positive effects for Hydro. 44




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From 2005 and onwards, Hydro Oil and Energy will focus its power activities on management of
the Nordic electricity portfolio and sourcing of power to Hydros larger consuming plants in the
Nordic area and continental Europe. Pursuit of Hydrogen and Renewable Energy Opportunities Hydro has extensive experience within the traditional industrial hydrogen markets as well as
with renewable hydroelectric energy production. Hydro is seeking to leverage its experience to
position itself in renewable energy and new energy markets for hydrogen. Hydro views wind power generation as the most important part of the renewable energy market
and is making selective investments in this market. In 2002, Hydro completed the Havøygavlen wind
park, located in northern Norway. Havøygavlen is one of the largest wind power projects in Norway,
with a potential annual output of around 105 GWh. Further Norwegian and European projects are
continuously evaluated, in Norway pending the framework for production and sale of renewable
energy. Hydro is presently involved in several hydrogen projects. These include partially owned
filling stations for hydrogen-fueled vehicles in Iceland and Germany, and combining hydrogen and
wind power to form a demonstration project of a sustainable energy society on the Norwegian island
of Utsira. OIL MARKETING Oil Marketing markets and sells refined petroleum products (gasoline, diesel and heating oil)
and electricity to customers in Scandinavia and the Baltic countries. Hydro owns 100 percent of its
oil marketing unit in Sweden and 50 percent of Hydro Texaco, an oil marketing company with retail
outlets in Norway, Denmark and the Baltic countries. Hydro markets a range of complementary energy
products in addition to refined petroleum products, such as electricity, natural gas, biogas for
cars and bioenergy for heating purposes, as well as convenience store goods. At the end of 2004, Hydros retail network in Sweden comprised 539 gasoline stations and 130
Hydro Diesel service stations. Hydro operates both Hydro and the Uno-X branded stations in the
Swedish gasoline market. Approximately 50 percent of the station network is Hydro-branded. As of
year-end 2004, Hydro Texaco operated 405 gasoline outlets and 46 diesel sites in Norway, 408
gasoline outlets and 102 diesel sites in Denmark, and 49 gasoline outlets and 10 diesel sites in
the Baltic countries with Hydro Texaco or Uno-X brands. Hydros strategy is to maximize its return
on investments already made in its gasoline station chains by focusing on the most profitable
stations and closing smaller and unprofitable outlets, building strong brand recognition and
expanding on profitable segments of the market. Hydro has a strong brand and market position in the most profitable segments of the industrial
and residential heating oil markets. Its large customer base offers a platform for the sale of
electricity to residential and industrial customers. Also, Hydros and Hydro Texacos large
customer bases provide a potential for cross-sales. Sales of electricity have, to date, been
relatively modest compared to Hydros sale of gasoline and gasoil, but are growing. Gasoline is sold through service stations and unmanned, automated stations in Scandinavia and
the Baltic countries. Gasoils are sold through automated diesel stations and through direct
deliveries from depots to end consumers. Volumes (thousands of m3)(1)
    
    
    2004
    
    
    
    2003
    
    
    
    2002Gasoline
    
    
    
    1,487
    
    
    
    
    1,435
    
    
    
    
    1,476Gasoil
    
    
    
    2,266
    
    
    
    
    2,109
    
    
    
    
    2,074
   (1)
    Volumes reflected in the table include 100 percent of Hydro Texacos
volumes. 45




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In 2004, Hydros market share in the Swedish gasoline market declined by 0.3 percentage
points mainly as a result of the discontinuation of agreements with Volvo dealers and their
customers. These agreements are being phased out over a period of 5 years, from 2001 to 2005. To
compensate for the loss in market share, Oil Marketing has entered into a deal with VW/Audi Sweden,
allowing holders of VW/Audi credit cards access to Hydro and Uno-X stations. Market share (%) ( 2004)(1)
    
    
    Sweden(2)
    
    
    
    Norway(3)
    
    
    
    Denmark(3)Gasoline
    
    
    
    9.6
    
    
    
    
    20.8
    
    
    
    
    17.3Gasoil
    
    
    
    14.4
    
    
    
    
    17.1
    
    
    
    
    18.4
   (1) Includes 100 percent of Hydro Texaco.(2) As of December 2004.(3) As of November 2004. Oil and Energy Government Regulation The principal Norwegian legislation applicable to petroleum activities in Norway and on the
NCS is currently the Norwegian Petroleum Act of 1996, a number of regulations issued under that
Act, and the Petroleum Taxation Act of 13 June 1975.  The general principles underlying the Petroleum Act are that:
    the Norwegian State is the owner of all petroleum resources in the ground;
    the exclusive right to resource management is vested in the Norwegian State; and
    the Norwegian State alone is authorized to award licenses with respect to petroleum
activities. Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy (the Ministry) has
been delegated responsibility for resource management and administering petroleum activities on the
NCS. The Ministry primarily implements petroleum policy through its power to award licenses, to
approve operators field and pipeline development plans, and to approve gas sales contracts. Norwegian Licensing System Hydro normally participates in exploration and production activities with other parties,
including private and state-owned oil and gas companies and other government entities. Contractual
arrangements among partners are generally governed by an operating agreement, which provides that
costs, production entitlements and liabilities are allocated according to each partners respective
percentage interest in a particular field or license area. Normally, one party is appointed as
operator by the Ministry. Field activities are conducted under the overall supervision and control
of an operating committee consisting of representatives from each participant in the field. This
enables each of the non-operator partners to be involved in field development and operations. The Petroleum Act and related regulations contain the main legal basis for the license system,
which regulates Norwegian petroleum activity. The most important type of license award under the
Petroleum Act is the production license. A production license grants the holder an exclusive right
to explore for and produce petroleum within a specified geographical area. The licensee becomes the
owner of the petroleum produced from the field covered by the license, and, together with any
partners, is jointly and severally responsible to the Norwegian State for obligations arising from
petroleum operations carried out under the license. Notwithstanding the exclusive rights granted
under the production license, the Ministry has the power to, in exceptional cases, permit third
parties to carry out exploration in the area covered by a production license. 46




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Production licenses are normally awarded through licensing rounds. The first licensing round
for NCS production licenses was announced in 1965. Awards of licenses take place both through the
principal licensing rounds (of which the 18th was awarded in June 2004) and through
separate rounds covering a defined area. Prior to the development of a field, licensees are required to submit a PDO to the Ministry
for approval. In respect of fields of a certain size, the Norwegian Parliament (Storting) must
accept the PDO before it is formally approved by the Ministry. Production licenses are normally awarded for an initial exploration period, which is typically
six years but can be for a shorter period or for a period of a maximum of ten years. During this
exploration period, the licensees must meet a specified work obligation set out in the license. The
work obligation will typically include seismic surveying and/or exploration drilling. If the
licensees fulfill the obligations under the production license, they are entitled to extend the
license for a period specified at the time when the license is awarded, typically 30 years. The
licensees are, however, normally not entitled to require that the license is extended for more than
half of the originally awarded license area. For licenses granted after 1 July 1985, the Norwegian governmental authorities can delay
development of a field indefinitely under the Norwegian Petroleum Act. Should development be
delayed, licensees can apply for an automatic extension of the license term corresponding to the
delay period. For licenses granted before 1 July 1985, the conditions in the specific license
apply. The Norwegian State may, if important public interests are at stake, direct licensees on the
NCS to reduce their production of petroleum. From 15 July 1987 until the end of 1989, licensees
were directed to curtail oil production by 7.5 percent. Between 1 January 1990 and 30 June 1990,
licensees were directed to curtail oil production by 5 percent. In 1998, the Norwegian State
resolved to reduce Norwegian oil production by about 3 percent, or 100,000 boed. In March 1999, the
Norwegian State decided to further decrease production by 200,000 boed. In the second quarter of
2000, the reduction was brought back to 100,000 boed. On 1 July 2000, this restriction was removed.
By a royal decree of 19 December 2001, the Norwegian government decided that Norwegian oil
production should be reduced by 150,000 boed from 1 January 2002 until 30 June 2002. This amounted
to roughly a 5 percent reduction in output. Licensees may buy or sell interests in production licenses subject to the consent of the
Ministry and the approval of the Ministry of Finance of the tax treatment. The Ministries must also
approve direct or indirect transfers of interests in a license, including change of control of a
licensee, if it would result in a new entity obtaining a decisive influence over the licensee. In
most licenses there are no pre-emption rights in favor of the other licensees. The States Direct
Financial Interest (SDFI), or the Norwegian State, as appropriate, however, still holds
pre-emption rights in most licenses. A license from the Ministry is also required in order to establish facilities for transport
and utilization of petroleum. When applying for such licenses, the owners, which are in practice
licensees under a production license, must prepare a plan for installation and operation. Licenses
to establish facilities for transport and utilization of petroleum will normally be awarded subject
to certain conditions. Typically, these conditions require the facility owners to enter into a
participants agreement. For major new gas infrastructure, the Ministry will typically require that
the new facilities shall be included in Gassled when operational. The ownership of most facilities
for transport and utilization of petroleum in Norway and on the NCS is organized as a partnership
or joint venture of a group of license holders, and the participants agreements are similar to the
joint operating agreements entered into among the members of the partnership holding production
licenses. Licensees are required to prepare a decommissioning plan before a production license or a
license to establish and use facilities for transportation and utilization of petroleum expires or
is relinquished, or the use of a facility ceases. The decommissioning plan must be submitted to the
Ministry no sooner than five and no later than two years prior to the expiry of the license or the
cessation of the use of the facility, and must include a proposal for the disposal of facilities on
the field. 47




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On the basis of the decommissioning plan, the Ministry makes a decision as to the disposal of
the facilities. The Norwegian government can require that licensees participate in the removal of offshore oil
and gas installations (platforms, pipelines, etc.) on the NCS when production ceases or at the
expiration of the concessions, whichever occurs first. The Norwegian government has the option to
take ownership of a permanent offshore installation at no cost to it when a license expires, is
surrendered or revoked or when the use of such installation has been terminated permanently. For
onshore installations, compensation for expropriation has to be paid. In such cases, the Norwegian
government would assume total responsibility for any well closure and decommissioning costs after
this time, as well as removal costs of the installation. As a basis for estimating Hydros future
liabilities related to well closures, decommissioning and removal costs of the installation,
Hydros management evaluates Norwegian and international laws, treaties and practices, and the
estimated value of recoverable oil and gas reserves that are expected to exist at the end of the
various concession periods. See the discussion in Item 5. Operating and Financial Review and
Prospects  Hydros Critical Accounting Policies  Asset Retirement Obligations. The regulations
allow for full deductibility in taxable income of dismantlement and removal costs. Organization of Norwegian Gas Sales and Transportation Until June 2001, gas sales contracts with buyers for the supply of Norwegian gas were required
by Norwegian authorities to be concluded with the Gas Negotiation Committee, known as the
Gassforhandlingsutvalget(GFU). The structural changes taking place in the European gas market (see the discussion under  
EU Regulation   EU Gas Directives and Related Regulatory Developments below) prompted the
Norwegian State to consider whether changes to the gas resource management system on the NCS could
contribute to further enhancing the efficiency of Norwegian gas producers. Accordingly, the
Norwegian State, by a royal decree dated 1 June 2001, determined to abandon the GFU system and put
in place a system whereby the individual licensees manage the disposal of their own gas.
Adjustments in legislation, license agreements and other existing contracts necessary to implement
the new system were finalized during 2002. With the approval of Gassled, Norwegian authorities have, by a royal decree of 31 December
2002, issued regulations for access to and tariffs for capacity in the upstream gas transportation
system. Gassled has a uniform access regime, giving all natural gas undertakings and eligible
customers who have a duly substantiated reasonable need of transportation a right to access the
system under non-discriminatory, objective and transparent conditions. Access to the system is
based on long-term and short-term transportation agreements. Gassled tariffs have been established
through regulations established by the Ministry of Petroleum and Energy with effect from 1 January
2003. Health, Safety and Environment Regulations Petroleum operations in Norway are subject to extensive regulation with regard to health,
safety and the environment (HSE). Under the Petroleum Act, which is in this respect administered
by the Ministry of Labor and Social Affairs, all petroleum operations must be conducted in
compliance with a reasonable standard of care, taking into consideration the safety of employees,
the environment and the economic values represented by installations and vessels. The Petroleum Act
specifically requires that petroleum operations be carried out in such a manner that a high level
of safety is maintained and developed in accordance with technological developments. Licensees and other persons engaged in petroleum operations are required to maintain at all
times a plan to deal with emergency situations. During an emergency, the Ministry of Labor and
Social Affairs may decide that other parties should provide the necessary resources, or otherwise
adopt measures to obtain the necessary resources, in order to deal with the emergency on the part
of the licensees. 48




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In the HSE area, the Norwegian Pollution Control Authority, the Norwegian Social and Health
Directorate and the Petroleum Safety Authority Norway ( separated from the Norwegian Petroleum
Directorate as of 1 January 2004) have adopted joint, total regulations relating to health,
environment and safety on the NCS. The Ministry of Labor and Social Affairs and the Ministry of
Environment administer these regulations. In addition, a number of regulations adopted under other
acts, such as the Working Environment Act of 1977 and the Pollution Act of 1981, apply to Hydros
operations. Violations of such regulations can lead to fines. In Hydros capacity as a holder of licenses under the Petroleum Act, it is subject to strict
statutory liability in respect of losses or damages suffered as a result of pollution caused by
spills or discharges of petroleum from petroleum facilities covered by any of its licenses. This
means that anyone who suffers losses or damages as a result of pollution caused by any of Hydros
NCS license areas can claim compensation from Hydro without needing to demonstrate that the damage
is due to any fault on Hydros part. If the pollution is caused by a force majeure event, a
Norwegian court may reduce the level of damages to the extent it considers reasonable. EU Regulation Although Norway is not a member of the EU, it is a member of the European Free Trade
Association (EFTA). The European Union and its Member States have entered into the Agreement on
the European Economic Area (the EEA Agreement) with the members of the EFTA other than
Switzerland. The main purpose of the EEA Agreement is to include the EFTA countries in the European
Common Market. The EEA Agreement makes relevant provisions of EU legislation binding for the EFTA
states other than Switzerland. Regulations and directives affecting Hydro are being adopted, in an
increasing number, within the EU and then implemented in Norway under the EEA Agreement. EU Emissions Trading Directive In January 2005, the Union Greenhouse Gas Emission Trading Scheme (EU ETS) commenced
operation. The scheme is based on Directive 2003/87/EC, which became effective in October 2003. The
scheme will limit carbon dioxide emissions from a broad range of industries, including power
generation, and place them within a regulatory framework. Under the directive, all producers with
significant emissions of climate gases will be given an emissions permit for each year of
production. Each member state will develop a national allocation plan for such permits. The
emissions trading system will increase a producers costs if that producer does not achieve its
targets. Additional costs would also be associated with the development of emissions reduction
technology and trading tools. Norway considers the directive to fall outside the scope of the EEA
Agreement and has passed an act establishing its own national emissions trading scheme with effect
from 1 January 2005. Offshore oil and gas production is currently not included in this scheme. EU Gas Directives and Related Regulatory Developments Fundamental changes are now taking place in the organization and operation of the European gas
market, with the objective of opening up national markets to competition and integrating them into
a single EU internal market for natural gas. It is difficult to predict the effect of
liberalization measures on the evolution of gas prices, but the main objective of the single gas
market is to bring greater choice and reduced prices for customers through increased competition. The EU Gas Directive of 1998 (Directive 98/30/EC, 1st Internal Gas Market
Directive) established common rules for the transmission, distribution, supply and storage of
natural gas. The main purpose of the directive was to require owners of natural gas pipelines to
open up their transport systems, including systems within domestic markets, to customers,
such as distribution companies and large industrial customers, in order to bring greater
competition into the European gas market. The directive established rules relating to the
organization and functioning of the natural gas sector, access to the market, the operation of
systems, and the criteria and procedures applicable to the granting of 49




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authorizations for transmission, distribution, supply and storage of natural gas. The
directive imposed a series of obligations on EU member states and other states implementing the
directive. In June 2002, the Norwegian Parliament (Storting) agreed to incorporate the directive
into its legislation as part of the EEA Agreement. On 26 June 2003, the European Parliament and the Council of the European Union adopted
Directive 2003/55/EC (2nd Internal Gas Market Directive), providing for common rules for
the internal market for natural gas. Directive 2003/55/EC repealed the earlier Directive 98/30/EC,
which was viewed as taking the first relatively tentative steps toward the creation of an internal
market for natural gas. Directive 2003/55/EC is not yet incorporated in the EEA Agreement.
Directive 2003/55/EC is expected to provide the necessary structural changes in the regulatory
framework to tackle the remaining barriers to the completion of the internal market. The directive
provides for:  
    the right for all non-household gas customers to freely choose their supplier no later
than 1 July 2004, with all customers to have this right by 1 July 2007;
    third party access to transmission and distribution networks on the basis of published
and ex ante regulatory approved tariffs;
    the establishment of a regulatory authority in each Member State with a common minimum
set of responsibilities;
    legal unbundling of transmission and large and medium-sized distribution companies; and
    access to storage facilities either on a negotiated or regulated basis. In addition, the directive contains provisions relating to upstream pipeline networks. EU
member states are required to take the necessary measures to ensure that natural gas undertakings
and eligible customers, wherever they are located, are able to obtain access to upstream pipeline
networks, including facilities supplying technical services incidental to such access in accordance
with the directive, except for the parts of such networks and facilities which are used for local
production operations at the site of a field where the natural gas is produced. Access is to be
provided in a manner determined by the EU member state in accordance with the relevant legal
instruments. EU member states are to apply the objectives of fair and open access, achieving a
competitive market in natural gas and avoiding any abuse of a dominant position, taking into
account security and regularity of supplies, capacity that is or can reasonably be made available
and environmental protection. In February 2002, the European Gas Regulatory Forum, which is chaired by the EU
Commission and made up of national regulators, network operators and users and gas consumers,
agreed on a set of voluntary guidelines (referred to as the Guidelines for Good TPA Practice) on
granting access to the gas transmission system. The guidelines were revised in September 2003. In a
first compliance report presented to the Forum in October 2002, the EU Commission observed
significant lack of compliance with the rules. In its second report presented at the Forums
meeting in September 2003, the EU Commission indicated a significant improvement in terms of
compliance with the guidelines, but a continuing unacceptable level of non-compliance such that a
level playing field in terms of access conditions to the gas transmission networks was far from
being achieved. As a result, in December 2003, the EU Commission proposed a regulation providing
for a set of basic principles to be respected as regards third party access (TPA) services to be
offered by the system operators, capacity allocation and congestion management procedures,
transparency requirements and tariff structures. The proposal also provides for detailed
implementing rules to be contained in guidelines annexed to the regulation, which can be adopted
and modified through a regulatory comitology procedure whereby the Commission submits a proposal
to a committee consisting of representatives of the Member States. On April 20, 2004, the EU
Parliament in its first reading adopted the proposal with a number of amendments, and on 15
November 2004, the Energy Council adopted a common position on the draft regulation. The common
position is based on the Commissions proposal, but is more limited with regard to subjects that
are covered by the Commissions authority to propose implementing guidelines. 50




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The Energy Council agreed that the date for applying the regulation should be moved from 1
July 2005 to 1 July 2006. Liberalization of European Electricity Markets The EU electricity liberalization directive of 1996, to a large extent, left implementation of
the deregulation process to the EU member states. As a result, each country designed its own
national market structure. These structures are not entirely compatible. The European Commission
has acknowledged this problem on a number of occasions, indicating that action will be taken to
remedy the situation. In 2003, the European Union enacted a number of provisions bearing on the
European electricity market:  
    Directive 2003/54/EC sets forth common rules for the internal
market in electricity. The directive establishes common rules for the
generation, transmission, distribution and supply of electricity. This
directive replaces the directive from 1996.  
    Regulation (EC) No. 1228/2003 on cross-border trade in electricity
addresses conditions for access to the network for cross-border exchanges of
electricity. It attempts to establish fair rules for cross-border exchanges of
electricity, thus enhancing competition within the internal electricity market,
taking into account the specificities of national and regional markets.
Realizing that objective will involve the establishment of a compensation
mechanism for cross-border flows of electricity, the setting of harmonized
principles on cross-border transmission charges, and the allocation of
available capacities of interconnections between national transmission systems.
The European Commission is currently working on binding guidelines to be
adopted through EU committee procedure. The future guidelines are expected to
enter into force in 2005. Taxation of Oil and Gas Production Norway Ordinary Taxes.Profits from petroleum production and pipeline transportation are subject to
Norwegian income tax at the rate of 28 percent. Revenue for tax purposes is based on market norm
prices (as determined by a government-appointed board, normally on a quarterly basis but in recent
years with large price fluctuations, on a monthly basis) for crude oil and on realized prices for
gas and other primary products. The taxation of a companys income associated with its exploration
and production activities on the NCS is assessed on a consolidated basis. Investments in oil and gas production facilities are, in general, depreciated for tax purposes
over six years using a straight-line method of depreciation (i.e., 16.66 percent per year).
However, there is an exception for certain large-scale gas liquefaction facilities; such
investments are depreciated over three years (i.e., 33.33 percent per year). Depreciation commences
when expenditures are incurred. Deductions for exploration and other costs can be taken in the year
such costs are incurred. Any NCS losses may be carried forward indefinitely against subsequent income earned. Any
onshore losses may be carried forward for 10 years. Half of the losses relating to activity
conducted onshore in Norway may be deducted from NCS income subject to the 28 percent tax rate.
Losses from foreign activities may not be deducted against NCS income. Losses from offshore
activities are fully deductible against onshore income. Special Petroleum Tax.A special petroleum tax is levied on profits derived from petroleum
production and pipeline transportation on the NCS. The special petroleum tax is currently levied at
a rate of 50 percent. The special petroleum tax comes in addition to the standard 28 percent income
tax, resulting in a 78 percent marginal tax rate on income subject to the petroleum tax. The basis
for computing the special petroleum tax is the same as for income subject to ordinary corporate
income tax, except that onshore losses are not deductible against the special petroleum tax, and a
tax-free allowance, or uplift, has been granted at a rate of 5 percent of capital expenditures per
year over a period of a 51




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minimum of six years (equal to a maximum total of 30 percent of the capital expenditures). The
uplift is computed on the basis of the original capitalized cost, including capitalized interest,
of offshore production installations. The uplift may be deducted from taxable income for a period
of six years beginning in the year in which the capital expenditures are incurred. Unused uplift
may be carried forward indefinitely. Special provisions apply to investments made prior to 1992.
Deficits relating to NCS exploration and production activities can be carried forward indefinitely,
both for ordinary and special petroleum tax purposes. Deficits incurred in 2002 and later can for
both tax categories be carried forward with interest. The Ministry of Finance is authorized to
issue guidelines on the interest rate. As part of Revised National Budget passed in June 2004, the Norwegian government adopted
changes to the Petroleum Tax Act effective for 2005. The tax-free allowance, or uplift, will be
accelerated to 7.5 percent of capital expenditures per year over a period of four years.
Furthermore, if in a non-taxpaying position, the State will pay in cash the tax value of deficits
connected to exploration in connection with the yearly tax assessment. The State will also pay in
cash the tax value of deficits if a company ceases its activities on the Norwegian Continental
Shelf. Changes also include simplification of tax-related conditions in relation to transfer of
licenses, and changes in regulations regarding depreciation of investments in fields with life
spans of less than six years. Larger flexibility in contracts between oil companies and contractors
will be allowed. Taxation Outside Norway Hydros international petroleum activities are covered by local tax legislation. The following
provides a brief description of the relevant tax systems of the countries where Hydro has
production. Hydros Canadian production is covered by the corporate income tax regime, which is not
project specific. Royalties apply to both producing projects and the terms are project specific.
Hydros remaining international production is regulated by production sharing agreements (PSAs).
Under a PSA, the host government typically retains the right to the hydrocarbons in place. The
contractor under a PSA normally receives a share of the oil produced to recover its cost, and is
entitled to an agreed share of the oil as profit in addition. Normally, the contractors carry the
exploration costs and risk prior to a commercial discovery. Provisions are, to a large extent,
negotiable and are unique to each block. All negotiated and bilateral provisions in the PSAs are
subject to a confidentiality clause. The presentation of the taxation as such is, therefore,
limited to the structure of the PSAs and to the official information involved. Under some PSAs, all government take will be in the form of royalty and/or profit oil
allocated to the state, whereas other PSAs also include an income tax element. Income is split
between a cost oil share for the recovery of costs, and a profit oil pool for further split between
the state and the contractors. Allocation of profit oil between the state and the contractor group
may depend on many factors, for example, the development of the internal rate of the return of the
project, the production rate or the accumulated production. As a result, a larger share will
normally be allocated to the state during the life of the production period. Linear depreciation
over the first four to five years in production is commonly used. Some PSAs allow for an uplift of
the investments, which is included as an additional depreciation in the investment costs and
thereby increases the cost recovery entitlement. Most PSAs allow unrecovered costs in one year to
be carried forward for recovery in later years. The direct state participation in PSAs has varied,
but seems to be more frequent in recently awarded blocks. Different variations as to financing of
the direct state share are seen. Some PSA regimes allow for consolidation of income from different developments in a block;
other PSAs set a ring fence for tax purposes around each development. A ring fence around a
development area means that the area is defined as a separate entity for tax calculation purposes,
meaning that all development and production costs related to a development can only be recovered
through income from the same development. One development may also consist of more development
areas, all of which are ring fenced for tax purposes. The term development area in this respect
may be a defined geological structure that may be produced from a common production facility. 52




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Under a tax/royalty regime, the companies are granted licenses by the government to extract
petroleum, and the state may be entitled to royalties, in addition to income tax based on the
contractors net income from the operations. The terms are, in general, not negotiable and are
subject to legislative change. Canada. The fiscal regime consists of both royalty and provincial/federal tax systems. There
are generic royalty regimes for the Grand Banks and Scotian Shelf areas; however, the Hibernia and
Terra Nova fields have unique royalty systems. An allowance of 25 percent of operating income is
deductible for income tax purposes, and replaces the actual royalty paid. This allowance will be
phased out by 2007 and replaced by full deductibility of royalties paid for income tax purposes.
The East Coast royalty regimes are progressive with the size of the royalty depending on the
fields economy and life cycle. Tax depreciation of facilities is 25 percent per year based on a
declining balance method of depreciation. Exploration expenses may be fully written off. The
combined Canadian federal and provincial tax rates are declining and will be reduced from the
current 40 percent to 36 percent by 2007. Consolidation for tax purposes across all Canadian income
is allowed within one legal entity (corporation); however, it is not allowed between separate legal
entities. Russia.The Kharyaga field is taxed based on a PSA. Gross income after deduction of the
royalty is split in cost oil and a profit oil share. A 35 percent income tax is levied on the
contractor share of the profit oil. The profit oil split is based on the projects cumulative
internal rate of return. Libya.The Mabruk field is taxed based on a PSA. Gross income after deduction of royalty is
eligible as cost oil, and any surplus oil is allocated as profit oil. The profit oil is divided
between the state and the contractors based on a sliding scale which is related to the daily
production rate and a cumulative income to cost ratio. No further income tax is levied on the
contractors share of the profit oil. The Murzuq fields are taxed based on a PSA. The Libyan
national company (NOC) is carried through the exploration phase and partly through the
development phase, and then takes a certain ownership share of total production. The net income,
after deduction of NOC`s direct share, is used for cost recovery. Any surplus is split as profit
oil between the NOC and the contractors, with a sharing principle as for the Mabruk development. No
further income tax is levied. Consolidation of operations within the Murzuq blocks is allowed. Angola.The producing fields, Girassol and Jasmim, are taxed based on the Block 17 PSA. Gross
income is split in cost oil and a profit oil share. The contractors share of the profit oil is
based on the projects cumulative internal rate of return. A 50 percent income tax is levied on the
contractors share of the profit oil. A ring fence around each development area in the block
applies for tax purposes. Exploration costs, however, can be recovered from the entire block. Taxation of Electricity Ordinary Taxes (Norway) Profits from hydroelectric power production are subject to ordinary Norwegian income taxation
at a rate of 28 percent. Fixed assets are depreciated for tax purposes over 67 years or the
concession period, if shorter (dams and tunnels); 40 years (machinery); and at a 5 percent
declining balance (transmission and other electrical equipment). A companys ordinary income tax for hydroelectric power plants is assessed on an aggregate
basis and may be tax consolidated with other activities in Norway. A natural resource tax of NOK 0.013 per KWh is leveled on hydro-generated electricity. The tax
is fully deductible from the ordinary income tax of the company. 53




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Resource rent tax on hydroelectric power plants (Norway) The resource rent tax on hydroelectric power production in Norway is a tax on profits above a
certain level and is additional to the ordinary tax. The tax rate is 27 percent and it is assessed
individually for each hydroelectric power plant (i.e., ring-fenced taxation). Unlike the ordinary
income tax, finance costs are not deductible. Uplift is a special deduction in the net income
computed as a percentage of the average tax basis of fixed assets (including intangible assets and
goodwill) for a given year. The percentage, which is determined annually by the authorities,
essentially provides for a certain return on fixed assets that is not subject to surtax. The
percentage used to calculate the uplift for 2004 was 8.5 percent. Revenue for resource rent tax is, with certain exceptions, calculated on the plants
production, hour by hour, multiplied by the area spot price in the corresponding hour. Revenues
from power supplies used for a companys own industrial production facilities and from sales under
certain long-term contracts are not subject to market spot price assessment. As most of Hydros
hydroelectric production is used for its own industrial production or sold under qualifying
contracts, only a minor portion of the production is subject to taxation based on spot prices at
the time of production. The resource rent price for power production supplied to the corporations
own industrial use in Norway is 170 NOK/MWh in 2004. Losses in the resource rent assessment can be carried forward indefinitely or until the plant
reverts to the Norwegian government. Losses carried forward are increased with interest. HYDRO ALUMINIUM Introduction and Overview Hydro Aluminium is one of the top three integrated aluminium suppliers in the world, in terms
of volume of integrated aluminium products produced. Hydro Aluminium is a full range aluminium
supplier including primary aluminium, rolled products, extruded and other fabricated products. In
2004, Hydro Aluminiums total revenues were NOK 79.7 billion compared to NOK 69.2 billion in the
prior year. Over the past few years, Hydro Aluminium has focused on improving performance through:  
    the execution of major improvement programs including targeted annual cost reductions of
NOK 2.5 billion with full effect from 2004 and related aggregate manning reduction of over
1700 employees;
    major developments such as the expansion of the Sunndal smelter in Norway, the Alouette
smelter in Canada and the expansion of the alumina refinery Alunorte in Brazil, projects
executed on time and within budget; and
    strengthening of market positions. 54




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Hydro Aluminiums organizational structure in 2004 has been as follows: (HYDRO ALUMINIUM DIAGRAM ) The graph below depicts Hydro Aluminiums aluminium operations, in terms of 2004 tonnage along
the value chain. (BAR CHART) Overview of Aluminium Industry Aluminium is the third-most abundant element in the earths crust and the second-most used
metal. The main properties that make aluminium an attractive material include its light weight,
strength, recyclability, corrosion resistance, durability, ductility and electrical conductivity.
Because of aluminiums unique combination of properties, the variety of aluminium products
continues to grow. Aluminium Smelting The primary raw material for aluminium smelting is alumina, which is refined from bauxite.
Bauxite deposits are most commonly found in tropical and subtropical regions of the world, such as
West-Africa, India, Jamaica, South America (Brazil, Surinam, Venezuela, and Guyana) and Australia.
Bauxite is generally extracted by open pit mining. More than 100 million tonnes of bauxite are
mined each year. Approximately two tonnes of bauxite are required to produce one tonne of alumina;
and approximately two tonnes of alumina are required to produce one tonne of aluminium. 55




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Alumina is dissolved in an electrolyte, which is contained in a silicon carbide and graphite
lined steel container known as a pot. An electric current is passed through the electrolyte at
low voltage, but at very high current, typically 150,000 amperes, or as high as 300,000 amperes
with modern technology. By means of electricity and carbon (anode), the alumina is reduced into
liquid aluminium metal and carbon dioxide gas . Various technologies can be used for the process.
Some production lines are based on the Søderberg technology, which will be phased out of Hydros
Norwegian smelters due to environmental legislation (see discussion under Metals  Primary
Aluminium Production below). Newer and more efficient is the so-called prebake cell technology.
Hydros own prebake cell technology, HAL 275, combines low investment costs with high productivity,
low energy consumption and reduced emissions. The technology is compact, economical and
environmentally friendly. The molten aluminium is periodically siphoned off into a holding furnace, then cleaned and
cast into metal products, such as extrusion ingot, sheet ingot, wire rod, primary foundry alloy,
continuous cast coil and standard ingot. The molten aluminium is often alloyed with other metals,
including iron, silicon, zinc, copper and magnesium, to form alloys with different properties. It takes roughly 14 kilowatt-hours (kWh) of electricity (industry average) to produce one
kilogram of aluminium from alumina. Design and process improvements have progressively reduced this
figure from about 21 kWh in the 1950s. In a modern smelter, the electricity consumption could be
approximately 13 kWh per kilogram. Nonetheless, aluminium smelting remains an energy-intensive
process, which is why the worlds smelters are located in areas that have access to abundant power
resources. High energy prices have reinforced this trend with more smelters being located in
remote, low energy cost areas, where electricity is generated specifically for the aluminium plant.
A significant part of the energy used to produce aluminium is supplied to the European market from
hydro-electricity. The reduction process is continuous. A metal plant cannot easily be stopped or started. If
production is interrupted by a power failure of more than three to five hours, the metal in the
pots will solidify, often requiring an expensive restarting process. Processing of Aluminium Rolled Products The aluminium rolling process changes the characteristics of the metal, making it less brittle
and more ductile. Prior to rolling, the aluminium is in the form of a continuous cast coil or
rolling sheet ingot that typically is up to 600 millimetres (mm) thick. The rolling sheet ingot
is then heated to around 500 degrees Celsius and passed several times through a hot rolling mill.
This gradually reduces the thickness of the metal to around 3-13 mm. The thinner aluminium is then
cooled and transported to a cold rolling mill for further processing. There are various types of
cold rolling mills, producing various types of rolled product with thicknesses as low as 0.006 mm
in the case of foil. In general, the type of product depends on the alloy used, the rolling
deformation and the thermal treatment used in the process. Rolling mills are controlled by very
precise instruments and measuring systems. Rolled products include: 
    
    Foil  typically less than 0.06 mm thick, foil is used mainly in the packaging industry
(e.g., for foil containers and wrapping), for electrical applications and for building
insulation.
    
    Lithographic sheet  typically of a thickness between 0.12  2.2 mm and with a high
surface quality, lithographic sheet is used in the printing industry.
    
    Sheet and strip  typically between 0.06 and 3-4 mm in thickness. Sheet and strip are
widely used in the construction industry, in transport applications and in packaging.
    
    Plate and shate  over 3-4 mm in thickness, plate and shate are used in a number of
applications, including airframes, military vehicles and structural components in bridges and
buildings.
 56




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Extrusion Aluminium cylinders, referred to as extrusion ingots, which are cast from molten aluminium,
can be extruded by heating the aluminium to around 450-500 degrees Celsius and pushing it through a
die at great pressure to form intricate shapes and sections. The primary applications for
extrusions include:  
    Building and construction applications such as window frames, door frames and facades;  
    Automotive applications like bumper beams, window and door frames and subframes;  
    Transport segments such as components for trucks, trains and airplanes; and
    Machines, furniture and consumer durables. Extruded products are sold in various forms, such as long lengths (e.g., six meters), cut to
length, machined, formed, assembled in a component or module or as systems. Casting Aluminium can be cast into an infinite variety of shapes. Cast parts are used in a variety of
applications including: light weight components for vehicles, aircraft, ships and spacecraft;
general engineering components; architectural fittings; and high-tech products for office and home.
Cast products can be produced using either sand casting (used for high production volume
processing) or die casting. Recycling Anything made of aluminium can be recycled repeatedly. The recycling of aluminium requires
only about five percent of the energy needed to produce primary metal. Scrap aluminium has
significant value and commands good market prices. Many aluminium companies, including Hydro
Aluminium, have invested in dedicated state-of-the-art secondary metal processing or remelt
plants to recycle aluminium. Long-term Market Developments Growth in Aluminium Consumption Aluminium consumption in the Western World (i.e., the world, excluding China, the Commonwealth
of Independent States (CIS), North Korea and Eastern Europe) has realized an average annual growth
rate of approximately 2.5 percent over the last two decades. Industry analysts, such as Brook Hunt,
predict future growth in the Western Worlds consumption of aluminium in the next decade to be
approximately three percent per year. On a global basis, the growth rate is expected to be about
four percent, mainly due to increasing consumption in China and the CIS. World consumption of
primary aluminium in 2004 was approximately 30 million tonnes. Asias, and in particular Chinas influence on the aluminium market has increased over the
last years. Chinas rapid increase in aluminium production has created increased
uncertainty around the potential oversupply situation that could negatively affect international
prices. China has traditionally been a net importer of primary aluminium. However, during 2002,
Chinas capacity and production increased by about 30 percent while consumption grew by about 17
percent, and the country became a net exporter (approximately 200,000 tonnes). For 2003, net
exports increased by an estimated 150,000 tonnes to a total estimated 350,000 tonnes. Production in
China increased significantly during the last quarter of 2004, leading to a growth rate of roughly
20 percent in 2004 compared with 2003. Consumption increased by an estimated 17 percent for 2004 as
a whole. Net exports of primary 57




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aluminium surged during the fourth quarter of 2004, to a total accumulated 2004 volume of
about 650,000 tonnes. This development was apparently triggered by an announcement by the Chinese
authorities of the abolition of an eight percent export subsidy by year end, together with the
imposition of a five percent export tax. However, including scrap, semi-fabricated and other
aluminium products, China imported an estimated 350,000 tonnes on a net basis in 2004 according to
Chinese trade statistics. Over the longer term, China is expected to devote more or all of its
aluminium production to domestic consumption. However, if consumption and production in China fail
to develop in parallel, it will likely influence the metal pricing and the need for new capacity in
the rest of the world. China has few natural advantages for primary production. The country must
import alumina and power sources are located far inland. In addition, Chinese authorities announced
a reduction of available credit for industrial development in China during the first quarter of
2004. In 2004, growth in demand in the United States, the worlds largest aluminium consuming
region, was high, while growth in Europe was moderate. Total shipments of primary aluminium in the
Western World increased approximately 7.5 percent (or 1.6 million tonnes) compared to the prior
year. New capacity, adjusted for idled capacity, resulted in increased production of about 550,000
tonnes. In the worlds third largest consuming region, China, the increase in consumption was
estimated at 17 percent. There was an increase in net primary exports to the Western World from
China of about 300,000 tonnes. In addition, the CIS and Eastern Europe are estimated to have
increased their net exports to the Western World by about 150,000 tonnes in 2004 compared to 2003.
According to CRU International (CRU), total reported and unreported stocks are estimated to have
decreased by about 200,000 tonnes in 2004, compared with an increase of about 400,000 tonnes in
2003. Development in aluminium inventories In 2004, reported inventories of primary aluminium (defined to include London Metal Exchange
(LME), International Aluminium Institute (IAI), Japanese merchant/consumer and other reported
stocks) in the Western World decreased significantly by approximately 700,000 tonnes to a level of
approximately 2.9 million tonnes. Historically, stocks in the Western World have fluctuated considerably. From a level of
approximately 1.5 million tonnes in the late 1980s, stocks peaked in 1993 at approximately 4.5
million tonnes and were thereafter rapidly reduced to approximately 2.6 million tonnes at the end
of 1995. These changes were mainly attributable to the export of Russian metal to the Western
World, and the subsequent production reduction implemented by producers. Since 1995 and until 2004,
the annual fluctuations have been less than 500,000 tonnes. High and increasing stocks historically
have had a downward impact on the aluminium price as illustrated in the following graph showing the
LME 3-month price (i.e., the price quotation on the LME for delivery of metal three months from the
date of quotation) and reported stocks estimated in days of consumption since 1994. 58




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(PERFORMANCE GRAPH) Aluminium price development Primary aluminium is traded on the LME. The most common benchmark is the 3-month price. Prices
are quoted on a daily basis, and normally reflect the markets expectations as to the future supply
and demand balance, together with actual consumption and production data. Due to the liquidity in
the LME market, hedge funds enter the market to varying degrees to capitalize on volatility in the
prices. The LME price, which is stated in US dollars per tonne, serves as the main reference price
for aluminium purchase and sale contracts worldwide. For medium to long-term alumina contracts,
prices are also normally linked to the LME price of aluminium rather than alumina spot prices. For
semi-fabricated products, a variety of contracts are used, both with respect to duration and
pricing. The graph below illustrates the annual average LME 3-month price of aluminium during the
1981-2004 period. (PERFORMANCE GRAPH) 59




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During the 1981-2004 period, the nominal LME 3-month price has reflected fluctuations based
upon the factors described above while increasing marginally on an average annual basis. Seen over
a long period (1960  2003) and adjusting for the U.S. GDP deflator, the LME 3-month price, stated
in real terms,
declined at an average annual rate of approximately one percent. Industry sources, like CRU, expect
a decline in the real price of aluminium to continue in the long term. However, the increases in the prices of input factors (including alumina and energy) have
contributed to high LME prices throughout 2004. According to independent market analysts alumina
prices are expected to remain high in 2005, while a softening in the alumina market is expected
from 2006 and onwards due to the introduction of new capacity. Average energy prices are expected
to increase in real terms. An additional factor affecting the aluminium price is an expected
favorable aluminium market balance in the short-term. Development in downstream consumption Aluminium is used in a variety of applications in several industries. The table below reflects
a percentage breakdown of the estimated levels of Western World consumption by the principal
consuming industries in 2004, and the historic annual growth rates for these industries over the
period of 1998 through 2004 (2004 reflects forecasted figures). Percentage of Western World
    
    
    
    Annual Growth RatesIndustry
    
    
    Consumption in 2004
    
    
    
    (1998-2004) %Transport
    
    
    
    29.5
    
    
    
    
    3.0Building & Construction
    
    
    
    20.6
    
    
    
    
    2.4Packaging
    
    
    
    18.0
    
    
    
    
    1.0Electrical
    
    
    
    9.1
    
    
    
    
    1.4Consumer Goods
    
    
    
    8.6
    
    
    
    
    3.2Machinery and equipment
    
    
    
    7.8
    
    
    
    
    1.3Other
    
    
    
    6.4
    
    
    
    
    0
   Source: Brook Hunt Regarding major applications, the transport segment is expected to experience the most
significant growth rates in the foreseeable future. The packaging, as well as building and
construction industries, appear to be more mature industries in terms of aluminium consumption. During 2004, there was a significant economic recovery in the United States, which has
impacted the downstream aluminium industry, while the economy in Europe has experienced only a
moderate improvement. Geographical production and market balance The table below provides a breakdown of the 2004 production volumes in the principal aluminium
producing regions and the estimated percentage of total global production represented by each such
region. 60




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Net export 2004Estimated
    
    
    
    (estimated asProduction Volume
    
    
    
    Percentage of
    
    
    
    production (in millions of
    
    
    
    Total Global
    
    
    
    consumption, inRegion
    
    
    tonnes)
    
    
    
    Production
    
    
    
    millions of tonnes)North America
    
    
    
    5.1
    
    
    
    
    17.1
    
    
    
    
    - 2.0South America
    
    
    
    2.4
    
    
    
    
    8.1
    
    
    
    
    1.3Western Europe
    
    
    
    4.3
    
    
    
    
    14.4
    
    
    
    
    -2.5Eastern Europe
(including Russia
and Ukraine)
    
    
    
    4.5
    
    
    
    
    15.1
    
    
    
    
    2.6Asia
    
    
    
    9.5
    
    
    
    
    31.9
    
    
    
    
    -3.0Oceania
    
    
    
    2.3
    
    
    
    
    7.7
    
    
    
    
    -1.9Africa
    
    
    
    1.7
    
    
    
    
    5.7
    
    
    
    
    1.3Total
    
    
    
    29.8
    
    
    
    
    100.0
    
    
    
    
    -0.4
   Source: Brook Hunt The net import of primary aluminium into Europe, USA and Asia (excluding China) has increased
during the period from 2001 to 2004. Based on estimates from CRU and other market analysts, this
trend is expected to increase further in the medium and long-term reflecting among other things,
the shift of aluminium smelter locations to areas with lower energy costs  see Overview of
Aluminium Industry  Aluminium Smelting. The main uncertainty is how Chinese production and
consumption of primary aluminium develops over this time horizon. However, the Chinese government
has taken steps to discourage export of energy through primary aluminium. Industry Structure Aluminium competes with substitution materials like steel, plastic materials such as polyvinyl
chloride (PVC), wood, glass, magnesium, etc. In addition, there is strong competition among the
various aluminium producers focused on supplying their customers and offering new solutions, and
focused on reducing costs in order to retain or improve their competitive position. As a
consequence, pressure has been put on uneconomic smelters using outdated technology, and some
closures have been completed or announced. According to CRU, as of the end of 2004, approximately 2
million tonnes of capacity remained idle in the Western World, 1.2 million tonnes of which were
located in the Northwest United States, due primarily to the high price of electricity in the
regions where the production capacity is located, as well as high alumina prices. The likelihood
and timing of significant reactivation of this capacity is uncertain. In response to the
competition, aluminium producers are seeking to expand their existing smelter units to capture
economies of scale and investing in the development of cost-efficient plants (i.e., in areas with
ample energy supplies and favorable energy prices). This is expected to continue in the foreseeable
future. Over the last decade the aluminium industry has consolidated significantly. Alcoa (based in
the United States) has established itself as the number one integrated aluminium company through
the acquisitions of Alumix (based in Italy), Inespal (based in Spain), Alumax (based in the United
States) and Reynolds (based in the United States). Alcoa has also developed a significant position
in alumina. Alcan (based in Canada), the number two integrated aluminium company, has acquired
Alusuisse (based in Switzerland), and, in February 2004, Pechiney (based in France). Following the
acquisition of Pechiney, Alcans integrated aluminium operations are estimated to be approximately
of a size comparable to that of Alcoa. However, Alcan subsequently announced the spin-off of
substantially all of the rolled products businesses held by them prior to its acquisition of
Pechiney and that the spin-off would achieve the regulatory divestiture requirements stipulated by
the European Commission as a
result of the acquisition. The name of the new company is Novelis and the transaction was completed
on 6 January 2005. 61




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Hydro Aluminium, following its acquisition of VAW in March 2002, has become the third-largest
globally integrated aluminium company in terms of volume, with approximately 25 percent of the
revenues of Alcoa and of the combined Alcan/Pechiney. Industry analysts expect that the
consolidation activity within the aluminium industry will continue, although at a reduced scale
compared to previous years. In addition to the integrated companies mentioned in the preceding paragraph, there are
several large companies whose focus is on upstream operations (i.e., bauxite, alumina and/or
primary metal), such as BHP Billiton (based in Australia and the United Kingdom), Rio Tinto,
through its subsidiary, Comalco Limited (Comalco) (based in Australia), and CVRD/Aluvale (based in
Brazil). The Russian aluminium industry has consolidated into two companies, Rusal and Sual. Both
companies focus on metal production in Russia, with minor downstream operations. Since the 1990s,
China has emerged as a major producer of primary metal. The industry structure in China is still
fragmented with many small- and medium-sized companies, of which Chalco has evolved as the most
significant. Downstream, there are a few major independent semi-fabricating producers outside the large
integrated systems. In finished products, the structure is much more fragmented. Hydro Aluminiums Competitive Position and Strategy Optimizing its Business Portfolio As a result of the acquisitions over the last several years, Hydro has achieved a better
balance between Hydro Aluminiums primary upstream production and downstream activities. The
downstream activities added to Hydro Aluminiums business activities through the VAW acquisition
have complemented and broadened Hydro Aluminiums product portfolio, contributing to such
activities achieving a critical size. Hydro Aluminiums management believes the composition of its portfolio has several benefits
compared with other integrated aluminium companies. The benefits enable Hydro to maximize high
margin product offerings with less capital employed. This is accomplished by or as a result of:  
    sourcing a similar tonnage of metal from scrap, other ingot sources and alliance
partners (see Focus on Midstream Activities below) as Hydro Aluminium produces from its
own electrolysis production.
    the composition of its downstream product mix. Hydro Aluminium has a higher proportion
of extrusion production than rolled products production when compared with other integrated
aluminium companies. Extruded products offer attractive margins and require less capital
invested per tonne than rolled products. Hydro Aluminium also has a higher level of
automotive activity than its competitors, a market with the highest expected growth rate.
    sourcing approximately 50 percent of the alumina needed to produce aluminium through
medium- to long-term contracts, rather than through ownership interests. Improving Relative Cost Position for Alumina Hydro Aluminium has, over the last decade, based its supply of alumina on a combination of
equity investments in production facilities having competitive, low cost positions and a portfolio
of medium- to long-term contracts. As a consequence of the second expansion of the Alunorte alumina
plant in Brazil, and the sale of the German based special alumina business, Hydro Aluminium will
improve the cash-cost position of its equity alumina interests (see discussion under Metals-Raw
Materials-Alumina below). Hydros average cash cost of equity alumina production is expected to
decrease from around USD 165 per tonne in 2000 to approximately USD 120 per tonne in 2006. 62




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Hydro Aluminium has never been an operator of alumina plants, but has instead prioritized its
capital and management resources in areas of the value chain where Hydro Aluminium believes it can
add greater value. In general, over the last decade there has been a favorable alumina supply
situation, with the exception of a few short periods of tight supply. Consequently, it has been
possible for Hydro Aluminium to capitalize on its financial strength to enter into favorable
contracts. During 2003 and in 2004, the alumina market was tight with spot prices remaining at high
levels. For Hydro Aluminium, this had little impact due to its combination of supply from equity
interests and long-term contracts. While this situation may continue for several years, Hydro
Aluminiums management believes the risk for a long-term tightening of supply of alumina in the
market is limited, since there is remaining potential to expand current capacity with moderate
investments. Accordingly, Hydro Aluminium will continue to pursue an alumina strategy based on
sourcing a substantial part of its needs through medium- to long-term contracts. Restructured Smelter Portfolio; Improving Relative Cost Position for Primary Metal Hydro Aluminium, like the other leading integrated aluminium companies, plans to increase the
share of its production being produced at larger smelters. Based on approved projects, Hydro
Aluminium expects to increase its share of production being produced by smelters with a capacity of
more than 350,000 tonnes per year from 4 percent in 2002 to approximately 30 percent by the end of
2007. Expansions in primary production are completed or underway in plants where the existing
infrastructure supports a larger capacity. Expansion of existing facilities improves the operating
cost position of the plant, thereby improving the overall long-term cost position. In 2004, Hydro Aluminium completed an expansion of its fully owned Sunndal metal plant (in
Norway) increasing the plants annual primary aluminium capacity to 360,000 tonnes. In 2002, Hydro
approved participation in the expansion of the Alouette smelter in Canada. Total annual primary
aluminium production capacity will increase by 307,000 tonnes to 550,000 tonnes in 2005, making
Alouette the largest aluminium smelter in North America and among the worlds lowest cost smelters.
Hydros ownership interest and share of the production is 20 percent. Including other smaller
projects, the expansions of primary aluminium production capacity will increase Hydro Aluminiums
total annual primary aluminium capacity to approximately 1.8 million tonnes by 2005, from the level
of nearly 1.5 million tonnes in 2003. In December 2004, Hydro entered into a Heads of Agreement with Qatar Petroleum to evaluate the
possible construction of what would be one of the worlds largest aluminium plants (consisting of
an aluminium metal plant, anode plant and cast house, along with a dedicated power plant), to be
located in Qatar. The Heads of Agreement is non-binding and reflects a number of uncertainties that
could cause the parties to determine not to go forward with the project. The current contemplation
is that, if completed, the initial capacity of the plant would be 570,000 tonnes. Total project
costs have been estimated to be USD 3 billion, with Hydros share being approximately USD 1.5
billion. As indicated earlier, aluminium smelting is an energy intensive process. However, Hydro has
self-generated power production and long-term energy contracts (10  15 years) for a vast majority
of its production with the exception of the German metal plants. The current electricity contracts
for Hydro Aluminiums German metal plants will expire at the end of 2005. Based on ongoing
negotiations for renewal of the contracts, Hydro expects substantial increases in energy costs for
these plants. As a result of the higher expected costs and a weakened competitiveness due to the
strengthening Euro compared to the US dollar, Hydro wrote down the value of the German metal plants
in 2004 by approximately NOK 2.3 billion (See discussion under Metals  Raw Materials  Energy
below). Even with Hydros efforts to improve the relative cost position of its smelter system through
continuous improvement and reduced cost within existing capacity and expanding capacity at low cost 63




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smelters, Hydros European smelters face challenges in reaching acceptable cost levels.
Approximately 30 percent of production costs in these smelters relate to direct and indirect labor.
A combination of higher wages, social benefits, shift schedules, higher manning for support
functions and higher prices for purchased services in Norway result in a cost disadvantage for
these smelters. As a result, on 7 May 2004, Hydros Board of Directors decided to recommend to the
Corporate Assembly a plan aimed at reducing annual costs by NOK 350 to NOK 400 million. The plan
implies a reduction of manning by about 800 employees in the Norwegian plants. As of the end of
2004, a total of NOK 432 million of related costs had been expensed.  Focus on midstream activities Since the early 1990s Hydro Aluminium has pursued a multi-sourcing strategy, which it refers
to as the metal supplier concept. This strategy, focusing on building a strong market position in
the metal products market, the mid-stream part of the value chain, has been based on three primary
components:  
    better utilize Hydro Aluminiums casthouse capacity;
    expand Hydro Aluminiums remelt activities; and
    develop alternative metal sources through commercial alliances and other agreements. To optimize its casthouse capacity for the production of midstream aluminium
products, Hydro Aluminium supplements the metal produced by its own smelters with remelt
metal. In addition to remelting scrap returned from its customers and purchased from third parties,
aluminium ingot is procured globally under a combination of short and long-term contracts, with the
major sources in the CIS, South America and in Southern Africa. Hydro Aluminiums total remelting
activities in 2004 accounted for approximately 1.7 million tonnes. Hydro Aluminium has entered into several long-term commercial alliances and agreements to
enhance its strategy of developing and leveraging the metal supplier concept with limited asset
investment. In 2004, Hydro Aluminium was supplied with approximately 300,000 tonnes of aluminium remelt
ingot from the Tajik Aluminium Plant in Tajikistan (TadAZ) under long-term arrangements. However,
at the end of 2004, the metal deliveries to Hydro Aluminium from this source stopped prematurely.
Although Hydro Aluminium is attempting to find an amicable solution, it is confident that, if
required, it can replace such volumes, but most likely at higher costs. In order to protect its
legal rights and recover damages, Hydro Aluminium has commenced arbitration proceedings in London. Under another agreement, Hydro Aluminium is participating in the upgrading of the aluminium
casthouse at Rusals Sayanogorsk smelter, located in southern Siberia. After completion of the
first stage of the construction during the first half of 2004,Hydro Aluminium is being supplied
with 80,000 tonnes per year of high quality extrusion ingot under the terms of a technology and
remarketing agreement. The second stage, to follow within a few years is expected to double the
production capacity. Hydro Aluminium has also entered into a long-term agreement with Talum in Slovenia, under
which Talum will supply Hydro Aluminium with 70,000 tonnes of foundry alloy products per year
during 2004-2010. 64




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Focused Growth in Selected Markets Downstream Hydro Aluminium has downstream operations both within and outside of Europe. However, the
major parts of the downstream activities are in Europe representing approximately 84 percent of the
related total operating revenues. Rolled Products Hydro Aluminium is the second largest producer in the European rolling industry in terms of
market share, which management estimates to be approximately 19 percent. Hydro Aluminium has important European positions within high margin rolled products segments
such as lithographic (printing) plates and foil. Each of Hydro and Alcan has a 50 percent ownership
interest in Aluminium Norf GmbH (AluNorf), which is the worlds largest hot rolling mill
according to CRUs Rolled Mills Equipment Profiles 2000 report. (See discussion above regarding
Novelis, which will include the Alunorf rolling mill.) Hydro Aluminiums management does not expect
that the change of legal entity status of its partner in Alunorf will influence the operations of
the rolling mill. Hydro Aluminiums rolled products strategy is to focus on growth in selected segments such as
lithography, while at the same time continuing to work on operating improvements. Several
initiatives have been launched to improve the Rolled Products sub-segments financial results,
addressing selling, general and administrative costs and direct production costs. Plant
specialization has been and will continue to be pursued to improve efficiency. For example, there
has been upgrading of foil mills and a new litho line is under construction. A key ambition here is
also to ensure high plant capacity utilization. Following completion of a number of projects in
2004, the level of capital expenditures is expected to decrease to a similar level as depreciation. Extrusions Hydro Aluminium currently holds a leading position in the European soft-alloy extrusions
market with a market share estimated by Hydro Aluminiums management to be approximately 14
percent. Hydro Aluminium is one of the leaders in the building systems market in Europe, with its
position having been bolstered by the acquisition of the French-based company, Technal, in 2002. In
a similar manner, the acquisitions of the former Wells Aluminum (based in the United States) in
2000 and VAW in 2002 have strengthened Hydro Aluminiums position in the North American extrusions
markets. In South America, the plants in Brazil and Argentina have been established as important
footholds that will provide bases for future developments. In parallel with this growth, Hydro
Aluminium has focused on improving the performance of its extrusions operations to position itself
to capture new growth opportunities. Hydro Aluminium intends to continue to expand its product
offerings in the global extrusions markets through selected forward integration into value-added
services (including surface treatment processes and various forms of fabrication, such as
cut-to-length, machining, etc.) to improve margins and volume as well as further expansion of its
building systems operations. Further, Hydro Aluminium will seek to increase its presence in these
markets through organic growth and selective acquisitions. Automotive Hydro Aluminium is actively engaged in meeting the needs of the automotive market, which has
become the principal source of the growth in demand in the aluminium industry during the last ten
years. On average, approximately 25 percent of Hydro Aluminiums sales in tonnes of own primary
metal production have been ultimately destined for the automotive sector, either as customers of
Hydro Aluminiums own semi-fabricated and finished products or through other tier suppliers using
Hydro Aluminiums foundry alloys to make automotive parts. Hydro Aluminiums product portfolio
includes casting of engine blocks and cylinder heads, and precision tubing and crash management
systems (e.g., bumper beams). In addition to production in Europe, Hydro Aluminium produces
aluminium engine blocks and cylinder heads in Mexico, precision tubing in United States, Brazil and
China and crash management systems in the United States. 65




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In 2004, Hydro Aluminiums Automotive sector focused on improving its profitability by
streamlining production processes to reduce costs. The short- to medium-term strategy is to
continue to focus on selected products, turn around underperforming units and leverage the
investments made to improve profitability. Hydro Aluminiums Operating Sub-Segments METALS Hydro Aluminiums Metals sub-segment (Metals) consists of the two sectors, Primary Metal and
Metal Products. The Metals sub-segment encompasses Hydro Aluminiums upstream activities,
principally the production and sale of primary aluminium produced in Hydro Aluminiums smelters,
both in wholly-owned and part-owned units. Metals activities also include the processing of scrap
and ingot into high quality products for the mid- and downstream markets, all aluminium and raw
materials trading activities, Hydro Aluminiums high purity business and magnesium operations. As
of 1 January 2005 the magnesium operations have been transferred to the Automotive sector.  Primary Aluminium Production Hydro Aluminium produces its primary aluminium at 12 wholly or partly owned primary aluminium
smelters. Most smelters operated at full capacity during 2004. Production at the smelters during
the three most recent years are reflected in the table below: Aluminium production (tonnes)
    
    
    2004
    
    
    
    2003
    
    
    
    2002(1)Primary AluminiumKarmøy
    
    
    
    278,000
    
    
    
    
    271,000
    
    
    
    
    273,000Årdal
    
    
    
    222,000
    
    
    
    
    215,000
    
    
    
    
    206,000Sunndal (2)
    
    
    
    306,000
    
    
    
    
    210,000
    
    
    
    
    153,000Høyanger
    
    
    
    76,000
    
    
    
    
    74,000
    
    
    
    
    73,000Søral (Hydros 49.9 percent share) (3)
    
    
    
    82,000
    
    
    
    
    79,000
    
    
    
    
    67,000Slovalco (4) (5)
    
    
    
    157,000
    
    
    
    
    27,000
    
    
    
    
    22,000Neuss
    
    
    
    223,000
    
    
    
    
    221,000
    
    
    
    
    173,000Stade
    
    
    
    69,000
    
    
    
    
    69,000
    
    
    
    
    48,000HAW (33.3 percent share)
    
    
    
    44,000
    
    
    
    
    43,000
    
    
    
    
    33,000Kurri Kurri
    
    
    
    155,000
    
    
    
    
    156,000
    
    
    
    
    122,000Tomago (12.4 percent share)
    
    
    
    60,000
    
    
    
    
    59,000
    
    
    
    
    45,000Alouette (20 percent share)
    
    
    
    48,000
    
    
    
    
    49,000
    
    
    
    
    38,000Total primary aluminium production
    
    
    
    1,720,000
    
    
    
    
    1,473,000
    
    
    
    
    1,253,000Average price primary aluminium (U.S.$/tonne per
LME 3-month price)
    
    
    
    1,721
    
    
    
    
    1,428
    
    
    
    
    1,365
   (1)
    
    Includes VAW volumes from the VAW acquisition date of 15 March 2002.(2)
    
    The Sunndal smelter has been expanded to an annual primary aluminium capacity of
360,000 tonnes. The 2003 and 2004 production volume reflects the partial completion of the
expansion, which was completed in 2004.(3)
    
    The annual production capacity of the Søral smelter has been expanded by
approximately 32,000 tonnes. The 2003 and 2004 production volume reflects Hydros share of
that expansion.(4)
    
    The annual production capacity of the Slovalco smelters has been expanded by
approximately 34,000 tonnes. The 2003 production volume reflects Hydros share of that
expansion.(5)
    
    As of 1 January 2004 Slovalco has been fully consolidated in Hydro both in terms of
financial results and in volumes. In 2003 and 2002 Hydros share of 20 percent is included. 66




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Emission standards, established by the Norwegian Pollution Authority in accordance with
the Oslo and Paris Convention regulations (see Environmental Matters  Oslo and Paris Commission
(OSPAR) below), require primary aluminium production facilities using the Søderberg technology in
the Høyanger and Årdal primary aluminium plants to be closed by the end of 2006 and at Karmøy by
the end of 2009. Hydro has decided that investments to replace this capacity will not be made in
Høyanger and Årdal. The resulting closures will reduce Hydro Aluminiums annual primary aluminium
production capacity by 72,000 tonnes by 2007 and another 125,000 tonnes by 2010.  Raw Materials Alumina Hydro Aluminium has secured a part of its long-term alumina requirements for its primary metal
production through investments in alumina plants. In 2004 approximately 45 percent of its alumina
requirements for primary metal production was provided by such equity investments. In 2004, Hydro entered into an agreement to sell its German based alumina business to the
Dadco Group for approximately NOK 700 million. The business sold consists of a 50 percent share in
Aluminium Oxid Stade GmbH (AOS), which has a total production capacity of 850,000 tonnes of
alumina. The sale also included AOSs related chemical grade alumina business and a dedicated
bauxite supply source represented by Hydros 10 percent share in Halco (Mining) Inc. AOS was sold
primarily because the chemical grade alumina is not used in Hydro Aluminiums production process.
AOS will continue to produce smelter grade alumina to supply Hydros wholly owned primary aluminium
unit in Stade and Hamburger Aluminium-Werk, in which Hydro has a 33 percent shareholding, through a
long term supply agreement with Dadco. Hydro Aluminiums major alumina investment is its 34 percent participation in Alunorte. After
an expansion of the plant in 2003, capacity reached approximately 2.4 million tonnes, enabling
Hydro Aluminium to secure access to 810,000 tonnes of alumina per year. In the third quarter of
2003, Hydro decided to participate in a further expansion of Alunorte. This planned expansion will
increase capacity to approximately 4.2 million tonnes in 2006, providing Hydro Aluminium with a
total of approximately 1.4 million tonnes of alumina annually. Hydro Aluminium believes that
Alunortes cash operating costs are significantly below the alumina industrys world average. As a
result of this investment in Alunorte, Hydro Aluminium will maintain approximately 50 percent
coverage of its alumina needs through its equity investments, taking into account the higher
production arising from planned primary metal expansions. Hydro Aluminium also has a 35 percent equity interest in the Alpart alumina refinery in
Jamaica, which has an annual production capacity of approximately 1.5 million tonnes. In late May
2004, Hydro decided to exercise its right of first refusal, provided under the Alpart partnership
agreement between Hydro Aluminium and Kaiser Aluminum, to acquire the remaining 65 percent
interest. Immediately after this purchase was completed, Hydro sold its 65 percent interest to the
Swiss-based Glencore AG on the same terms and conditions as those governing Hydros acquisition of
the interest. Following the completion of these transactions, Alpart changed from being operated by
a managing partner to having independent management. Both Hydro and Glencore are represented on
Alparts ultimate governing body, the Executive Committee. The changes in the ownership have been
approved by the US Bankruptcy Court for the District of Delaware and the Jamaican government. Hydro
and Glencore have also entered into a memorandum of understanding under which each company will
explore the possibility of closer cooperation and utilization of synergies between Alpart and
Windalco, an alumina refining company in Jamaica that is partially owned by Glencore. 67




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In addition to the equity interests in alumina production capacity mentioned above, Hydro
Aluminium has a number of short-, medium- and long-term purchase contracts to secure alumina for
its own smelters and trading activities. These contracts typically have pricing formulas based upon
a percentage of the LME price. In June 2003, Hydro Aluminium and Comalco signed one of the largest alumina supply contracts
in the history of the aluminium industry. Under the agreement, Comalco will supply Hydro Aluminium
with 300,000 tonnes of alumina in 2005 and 500,000 tonnes of alumina annually from 2006 through
2030. Energy Energy represents on average about 25 percent of the operating costs associated with primary
aluminium production. As mentioned earlier, Hydro Aluminium has access to self-generated power and
negotiated long-term contracts for a vast majority of its production. Much of the energy for Hydro Aluminiums Norwegian smelters is purchased from or through Hydro
Oil and Energy. Hydro Oil and Energy produces, in its own hydroelectric generating plants,
electricity amounting to more than 70 percent of the requirements of Hydro Aluminiums Norwegian
primary aluminium smelters. Virtually all of the electricity needed to operate the Norwegian
smelters in 2005 is covered by contracts. Certain long term supply contracts with Statkraft expire
in the summer of 2006. Hydro has already entered into new contacts with Statkraft replacing these
contracts through year 2020. Compared with the expiring contracts, the new pricing structure will
increase energy costs starting in the second half of 2006. Long-term availability of electricity at
predictable prices is considered a prerequisite for the further development of the Norwegian
operations particularly since Nordic spot market prices can be highly volatile. The smelters outside Norway source energy under contracts with local producers. For the large
smelters in Canada and Australia, Hydro has entered into long-term contracts. The German smelter system is comprised of the fully owned smelters located in Neuss
(Rheinwerk) and Stade (Elbewerk) and the Hamburger Aluminium Werk smelter in which Hydro owns 33.33
percent. Together these smelters provide Hydro with approximately 330,000 tonnes or around 20
percent of the total production of Hydro. The current electricity contracts for the German smelters
will expire at the end of 2005. Current negotiations for new contracts and other increasing
tariffs, indicate that significant price increases can be expected. Hydro Aluminium is currently
considering future improvement initiatives and the overall competitiveness of these smelters.
Should it not prove possible to obtain new power contracts at an acceptable price, the ultimate
consequence could be the closure of the German smelter system. As a result of weakened competitiveness due to the strengthen Euro compared to the US dollar
and increasing energy costs, Hydro has written down the value of the German primary metal plants
system by approximately NOK 2.3 billion in December 2004. Anodes Anodes are used and consumed in the smelting process. Most of Hydro Aluminiums smelters
produce their anodes at their own on-site facilities. During the last several years Hydro Aluminium
has expanded its capacity of anode production both in its Årdal plant and in its part-owned company
Aluchemie in the Netherlands. In addition, Hydro has upgraded the anode facility at its Kurri Kurri
plant in Australia. 68




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Remelt Activities Hydro Aluminium has established remelt plants for conversion of scrap metal and ingot into
extrusion ingot and sheet ingot in all major European markets. Facilities are located in Norway,
Luxembourg, the United Kingdom, Germany, Spain, Italy and France, as well as at the primary
metal plants in Norway, Germany and Slovakia. Scrap is sourced from internal and external customers, and in addition standard ingot is used
as input material. The main customers are internal and external extrusion plants and internal
rolling mills.  Sales and Distribution; Trading Activities Most of Hydro Aluminiums own production of aluminium cast house products is sold in Western
Europe and in the United States to semi-fabricating plants like extruders, rollers and wire and
cable mills, as well as foundries. The main consumer areas are transportation, construction and
packaging. The major consuming countries in Western Europe are Germany, France, the United Kingdom,
Italy and Spain. Most of the aluminium is sold in the form of value-added products such as
extrusion ingot, rolling ingot, wire rod and foundry alloys. Hydro Aluminium has consistently strengthened its commitment to customer service and increased
the efficiency of its production systems. Metals regional market teams have competencies within
technical and commercial service, research and development, logistics, contract administration and
scrap conversion. To enhance its existing service level, Metals implemented a program in 2001
called Hydro Billet Plus. The aim of the program is to reward the Metals sub-segments most
important customers and customers who wish to increase their business volume. This service concept
includes a web-enabled tool allowing customers to improve their understanding of commercial and LME
price risk and to optimize their production system. To support the metal supplier concept, Hydro Aluminium engages in trading of aluminium and
related raw materials, mainly alumina. Trading is a natural extension of Hydros internal sourcing
activity. Trading contributes to optimizing capacity utilization within Hydros own system as well
as reducing logistical costs by sourcing from a variety of sources. Aluminium trading activities
consist of physical metal purchases and sales, as well as trading on the LME. In 2004, Hydros
metal traders sold externally 738,000 tonnes of primary aluminium products, compared to 705,000
tonnes in 2003. The main trading product is aluminium ingot, which is also the global aluminium
product on which price quotations on the LME and other metal exchanges are based. In addition,
Hydro Aluminium has an alumina trading activity that has been profitable during the last five
years. Alumina is often used in combination with metal trading/sourcing activities, for example, by
supplying a third party smelter with alumina and receiving metal as compensation.  High Purity Aluminium Hydro Aluminium produces and sells high purity aluminium products, which are mainly used in
the electronics industry in products like electrolytic capacitors, semiconductors and flat panel
displays. The aluminium content varies between 99.98 to 99.9999 percent depending on the final end
product. High purity aluminium is produced in Europe, Japan, China and Russia. Markets for 99.99
percent high purity aluminium are mainly Japan, Europe and China. Markets for 99.999 percent high
purity aluminium are mainly in the USA and Japan Global production of 99.99 high purity aluminium is estimated at around 75,000 tonnes and
around 1,000 tonnes for 99.999 high purity aluminium. Hydro Aluminium produces and casts high
purity aluminium at three production sites located in Vigeland (Norway), Naoetsu (Japan) and
Grevenbroich (Germany). Sales volumes of 99.99 are 14,000 tonnes and of 99.999 the volume is 500
tonnes.  Magnesium The magnesium industry in the Western World comprises only a few producers of primary
magnesium. The International Magnesium Association (IMA) estimates that worldwide net shipments of
primary magnesium reached approximately 402,000 tonnes for 2004 compared with its estimate of 69




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actual
shipments of 387,000 tonnes for 2003. Based on the latest statistics available, China
and CIS shipments represented about 60 percent of the total. Increased quantities of Chinese
magnesium available in Western markets over the past several years have resulted in significant
downward pressure on magnesium prices. However the pressure has eased over the past year. In 2004
prices for pure magnesium were up by around 19 percent due to energy shortages and higher raw
material (silicon) prices. Silicon is principally used by Chinese producers. Hydro Aluminium has a primary (electrolytic) magnesium plant in Becancour, Canada, that
produced approximately 57,000 tonnes in 2004.In addition, it has remelt operations in Norway,
Germany and China with a combined remelt and recycling capacity of approximately 50,000 tonnes. ROLLED PRODUCTS Hydro Aluminiums Rolled Products sub-segment (Rolled Products) is centered in Europe, with
rolling mills in Germany, Norway, Spain and Italy, as well as a foil rolling mill in Malaysia that
provides a foothold in Asia. Production capacity includes a 50 percent share in the AluNorf hot
rolling mill in Germany, which in 2004 provided almost 576,500 tonnes to Rolled Products. Most of
Hydro Aluminiums entitlement to the products from AluNorf is further processed in Hydros nearby
plant in Grevenbroich before being delivered to customers. Grevenbroich is the center (from the
standpoint of technology, best competence and capacity) of Rolled Products foil and lithographic
sheet operations. The table below shows the ownership interest and sales volume per main site in Rolled
Products production system. Ownership
    
    
    
    2004 Sales Volume(1)Site
    
    
    Percentage
    
    
    
    (in thousands of tonnes)Grevenbroich, Germany
    
    
    
    100
    
    
    
    
    534.9Hamburg, Germany
    
    
    
    100
    
    
    
    
    134.7Slim, Italy
    
    
    
    100
    
    
    
    
    78.7INASA, Spain
    
    
    
    100
    
    
    
    
    22.8AISB, Malaysia
    
    
    
    81
    
    
    
    
    22.0Karmøy, Norway
    
    
    
    100
    
    
    
    
    63.4Holmestrand Norway
    
    
    
    100
    
    
    
    
    84.6Total, excluding internal
sales and wire rod
    
    
    
    
    
    
    
    
    941.1AluNorf, Germany
    
    
    
    50
    
    
    
    
    576.5
   (1)
    
    Excludes intra-company shipments, except volume cited for
AluNorf.(2)
    
    100 percent of shipments from AluNorf are intra-company. In 2004, Rolled Products had external shipments of 941,000 tonnes, mainly to the European
market, where Hydro Aluminiums management estimates it holds a market share of approximately 18
percent. Rolled Products, like the rest of the rolling industry, produces a wide variety of products
for different industries and with different product margins. Important success factors within the
rolling industry are optimizing the product mix and capacity utilization, as well as streamlining
the production system. Because the rolling industry is capital intensive, high capacity utilization
(volume) is important to reach an acceptable fixed cost per tonne. This must be balanced with
optimizing margins and product mix. Capacity utilization in the industry varies between the
products. In general the strip business has overcapacity while Hydro Aluminiums Foil and
Lithography units have a higher capacity utilization. Rolled Products customer base includes customers in the packaging, automotive, transport,
building, engineering, electrical and printing industries. A major part of Rolled Products sales
functions is organized centrally along the product lines. Such organization enables optimization of
sales, planning and production in Rolled Products total system. 70




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Rolled Products consists of three business units serving different market segments, which in
2004 had the following sales volumes to external customers: 2004 External Sales VolumesUnit
    
    
    (in tonnes)Lithography
    
    
    
    146.8Foil
    
    
    
    153.4Strip
    
    
    
    640.8Total
    
    
    
    941.0
 In 2004, the Lithography business unit had an average annual growth in sales volume of
about 19 percent, outpacing managements estimate of five to seven percent growth in general
lithography demand in the market. Rolled Products management attributes this primarily to Rolled
Products focus on quality and customer service. Hydro Aluminiums Lithography business unit is
well positioned to continue to expand its customer base and meet increased competition. Both on the
demand and supply side, the lithography market is characterized by a high degree of concentration. Rolled Products Foil business unit has endeavored to leverage its market position in Europe
to respond to the needs of global customers for a global supplier with a local presence. Within
important foil segments such as liquid packaging, management estimates Rolled Products to be the
global leader (in terms of volume). In 2001, Rolled Products acquired a 65 percent ownership
interest (increased to 81 percent in 2002) in a Malaysian rolling mill to serve as a base for
supplying customers in the Asian region. The Strip units business is characterized by higher volumes and lower margins compared to the
other units within Rolled Products. For this business, high capacity utilization and production
efficiency are particularly important. The current strategy is to optimize the combined production
and market system of Rolled Products to realize the full potential. Automotive flat rolled products (part of the Strip unit) are expected by Hydro Aluminiums
management to have higher growth than other flat rolled products in Europe. Principally using its
existing asset base, Rolled Products is expanding its flat rolled product range from non-visible
applications to applications that are visible on a finished manufactured vehicle (referred to as
the body-in-white market). Body applications are expected to be a strong, growing market segment
due to auto manufacturers continued desire to reduce weight. CRU projects that auto body sheet
consumption will approximately double in size from 2002 to 2007 in Europe. As the surface
requirement demands a special quality, a new finishing line has been constructed in Grevenbroich,
Germany. Most of the metal required for the production in Rolled Products is delivered from Metals. In
addition, process scrap from Rolled Products customers and scrap collected from the market are,
together with Rolled Products own process scrap, remelted and cast to rolling ingots in the
casting facilities of Metal Products. Supplies from Metals are priced on an arms-length basis with
reference to the LME price. External supplies of rolling ingot to Rolled Products are approximately
10 percent of its total requirements. EXTRUSION AND AUTOMOTIVE The Extrusion and Automotive sub-segment of Hydro Aluminium consists of three sectors:
Extrusion, Automotive and North America. Their main products are extruded aluminium profiles, used
primarily in the building and construction markets and the transportation segment. 71




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Extrusion The Extrusion sector (Extrusion) is primarily focused on the European market. Extrusion is
Europes largest soft alloy extruder of aluminium, in terms of volume, based upon estimates of
Hydro Aluminiums management. Extrusion also has operating entities in Brazil and Argentina, and
has a minority participation in a South African entity. In 2004,Hydro Aluminiums total production
of extruded products (i.e., from all sectors) was approximately 626,000 tonnes. Extrusion mainly consists of general extrusion activities and its Building Systems unit. With
respect to its general extrusion activities, Extrusion supplies custom-made general extrusions of
soft alloy aluminium, surface treatments such as anodizing and powder coating, fabrication,
components and finished products. Building Systems supplies complete design and solution packages
to metal builders, enabling them to supply both the commercial and residential building markets
with products, such as facades, partition walls, doors and windows, as well as other building
applications through its three main brands: TechnalTM, WiconaTM and
DomalTM. A key to the success in the Extrusion sector is its network of smaller, relatively independent
extrusion plants where decentralized organizations ensure good market alignment and close contact
with customers and where plants actively use internal benchmarking and apply best practices to
ensure continuous improvements in flexibility and efficiency. In January 2002, Extrusion enhanced its position through the acquisition of Technal, a
French-based manufacturer of aluminium building systems. The Technal acquisition augmented
Extrusions general extrusion operations through the addition of extrusion capacity in France and
by doubling Building Systems volumes.  Automotive The Automotive sector (Automotive) is comprised of Hydro Aluminiums Precision Tubing,
Structures and motor Casting business units which include all related worldwide operations and
activities. In the last few years, Automotive has followed a strategy of continuous growth in order
to strengthen its position as a supplier to the automotive industry. Automotive is currently
introducing several new products with start-up of new production lines. From 1 January 2005 the
Magnesium business unit has been combined with Hydro Aluminiums Automotive sector because many of
the customers are common to both units and a vast majority of magnesium applications are within the
automotive sector. In addition, growth in the magnesium business is expected to be within the
automotive market sector. Hydro Aluminiums management believes that its Automotive Structures unit is the leading
supplier of aluminium extrusion-based applications within crash management (e.g., bumper beams,
crash boxes) in Europe. Automotive also has crash management operations in the United States. The
sector has received safety awards for crash management systems supplied to several vehicles.
Automotive Structures will concentrate on its activities within crash management in order to
improve profitability. Automotives Precision Tubing unit produces applications used primarily within radiators, fuel
coolers and liquid lines. This unit has a significant market presence in Europe, North America and
South America. The unit also supplies part of the Chinese market through its joint venture plant in
China. Hydro Aluminium announced that it would start construction of its first wholly owned
precision tubing plant in China, to deliver precision drawn tubing, multi-port extrusions and
extruded tubular profiles used in automotive heat transfer applications. Construction began in the
first half of 2004 and production is expected to start in first half 2005. The plant, which is
estimated to cost NOK 150 million, is expected to create about 140 new jobs in Suzhou. In addition
Hydro Aluminium has decided to build a new precision tubing plant in Reynosa in Northern Mexico
with an expected capital expenditure of USD 30 million. Construction of the plant started in second
half 2004 and production is expected to begin in second half 2005. 72




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Automotives Casting unit is one of a few independent (i.e., not affiliated with an automotive
manufacturer) suppliers in Europe of aluminium cylinder heads and engine blocks. In June of 2004,
Hydro announced its intended closing of the aluminium cylinder head production plant located in
Leeds in the U.K. as a result of an unfavorable competitive environment/position. Production is
planned to cease in 2005. Remaining outstanding orders will be transferred to the plant in Györ,
Hungary. Automotive has a 49 percent ownership in Meridian Technologies Inc. (Meridian) a Canadian
company owned 51 percent by Teksid S.p.A. (a subsidiary of the Fiat group). Meridian provides
magnesium die-casting products to the automotive industry.  North America The North America sector (North America) comprises all non-automotive extrusion and remelt
plants in the United States. Through the acquisition of Wells Aluminum in 2000 and VAWs North
American extrusion assets in 2002, the sector has increased its size as an extrusion company in the
North American market, with seven extrusion plants and four stand-alone component manufacturing
fabrication facilities, including one in Mexico. The North America sector produces a broad range of extruded shapes, and provides finishing
services, for numerous end markets. The sector has a leading position within the North American
drawn tube market for demanding applications in office imaging products and health care. It also
supplies extrusion-based products to the transportation, building and construction, and consumer
durable markets. However, the US extrusion market still suffers from overcapacity in general. The sector operates six remelters representing one of the largest remelt systems in the United
States. Since its inception, the North American sector has upgraded and refurbished the older
remelters within its system. When the last plant finishes its upgrade in 2005, the sector will
operate a portfolio of modern, cost efficient remelters. The remelt network produces extrusion
ingot and offers cost-efficient remelt solutions to the North American sectors customers. The U.S. market experienced a strong recovery in 2004 growing approximately 11 percent
compared to 2003 (according to CRU), with apparent consumption for 2004 estimated at 1,905 kt. By
comparison, estimated consumption in the Western European market increased by about 3.8 percent
from 2003 to 2004 (according to CRU), ending up at 2,589 kt for 2004. Environmental
Matters Hydro Aluminium is subject to a broad range of environmental laws and regulations in each of
the jurisdictions in which it operates. These laws and regulations, as interpreted by relevant
agencies and the courts, impose increasingly stringent environmental protection standards
regarding, among other things, air emissions, the storage, treatment and discharge of wastewater,
the use and handling of hazardous or toxic materials, waste disposal practices, and the remediation
of environmental contamination. The costs of complying with these laws and regulations, including
participation in assessments and remediation of sites, could be significant. Aluminium production is an energy-intensive process that has the potential to produce
significant environmental emissions, especially air emissions. Carbon dioxide, a greenhouse gas, is
a major emission from primary aluminium production. The European Commission has adopted a directive
that would limit carbon dioxide emissions from a broad range of industries and establish an
internal emission trading system. So far the aluminium industry has not been included in the
emission-trading directive, but will be exposed to the EU emission trading system through the
indirect effects on power prices. 73




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In the European Union and other jurisdictions, various protocols address trans-boundary
pollution controls, including the reduction in emissions from industrial sources of various toxic
substances such as poly-aromatic hydrocarbons, and the control of pollutants that lead to
acidification. Carbon dioxide regulation has been the subject of significant political debate in
the United States, but thus far the United States has decided not to ratify the Kyoto Protocol.
U.S. legislation regarding carbon dioxide emissions could be enacted in the future. Such
legislation could have an effect on costs, but until such legislation is passed, it is not possible
to provide a meaningful estimate. The United States has an extensive regulatory program to control
other air emissions from aluminium facilities, including hazardous air pollutants. The European Union has a framework of environmental directives integrated into the Water
Framework Directive (2000/60/EC) regarding discharges of dangerous substances to water. The
implementation of the directive has started in Europe and must be finalized by 2009. The manner in
which this directive will be interpreted and enforced cannot be predicted. However, based upon the
information currently available, Hydro Aluminiums management does not believe it will have a
material negative impact on its business. The United States has a regulatory permit system limiting
the discharge from facilities to water bodies and publicly owned treatment works, as well as
regulations to prohibit discharges of hazardous substances into groundwater. Hydro Aluminium has a number of facilities that have been operated for a number of years by
Hydro Aluminium or have been acquired by Hydro Aluminium after operation by other entities.
Subsurface contamination of soil and groundwater has been identified at a number of such sites and
may require remediation under the laws of the various jurisdictions in which the plants are
located. Hydro Aluminium has reserved amounts for sites where contamination has been identified
that it believes will be sufficient to pay the cost of remediation under existing laws. Because of
uncertainties inherent in making such estimates, it is possible that such estimates could be
revised in the future. In addition, contamination may be determined to exist for additional sites
that could require future expenditure. Therefore, actual costs could be greater than the amounts
reserved. Hydro Aluminium believes that it is currently in material compliance with the various
environmental regulatory and permitting systems that affect its facilities. However, the effect of
new or changed laws or regulations or permit requirements, or changes in the ways that such laws,
regulations or permit requirements are administered, interpreted or enforced, cannot be predicted.  Oslo and Paris Commission (OSPAR) The Oslo and Paris Convention for the Protection of the Marine Environment of the North-East
Atlantic has resulted in new emission levels for the aluminium industry related to the prevention
of marine pollution, which are scheduled for implementation by all signatories to the Convention
before 2007. Emission standards, established by the Norwegian Pollution Authority in accordance
with the Oslo and Paris Convention regulations, require primary aluminium production facilities
using the Søderberg technology in the Høyanger and Årdal primary aluminium plants to be closed by
the end of 2006. Due to scrubbing equipment, the Søderberg line at the Karmøy plant meets the above
requirements at least until 2010.  Integrated Pollution Prevention and Control Under the EU Directive on Integrated Pollution Prevention and Control 96/61/FC, from October
2007 existing industrial installations will require national emission permits, which will be based
on best available techniques (BAT) for pollution prevention and control. The directive already
applies to all new installations. The European Commission has issued a guidance document relevant
for the aluminium industry; Best Practice Reference (BREF) for the Non-Ferrous Metals Industries
(2001). This is also relevant for the European Economic Area (EEA) and the Norwegian authorities
will start a process whereby the emission permits will be changed accordingly, to be effective by,
at the latest, 2007. Hydro Aluminiums production facilities currently meet the EU requirements and
are positioned to comply with future expected requirements from the Norwegian authorities. 74




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Climate Gases EU directive 2003/87/EC issued on 13 October 2003, establishes a scheme for trading greenhouse
gas emission allowances. The directive introduces mandatory trading of carbon dioxide from
combustion plants and certain specified industry sectors effective as of 1 January 2005. The
intention with the directive is to broaden it to include more gases and sectors as of 1 January
2008. EU Member States national authorities are currently setting up National Allocation Plans and
registries. This EU directive is also believed to be relevant for the EEA, although it is not clear
at this time how the directive will be implemented in the EEA. The aluminium industry is not
expected to be included before, at the earliest, 2008. Hydro Aluminiums operations are positioned
to comply with the new requirements, when applicable. The directive could impact production costs at facilities in the EU indirectly through
increased electricity costs. Government Regulation  EU Aluminium Tariffs The EU has implemented an import duty of six percent on non-EU imports of primary aluminium.
This import duty became effective for the Eastern European countries that joined the EU on 1 May
2004 although inventories of aluminium located in these countries prior to the date of accession
were exempt from duty regardless of origin. The EEA, of which Norway is a member, is exempt from
such duty for aluminium metal produced in the EEA. The import duty has been subject to debate within the European Union and it is not possible to
predict to what extent it will be maintained. The World Trade Organization (WTO) round of
negotiations on tariff and non-tariff barriers on industrial products may ultimately lead to a
reduction, if not elimination, of aluminium tariffs. However, it is likely that changes arising
from WTO commitments will not be phased in until 2007, at the earliest. Thus, the WTO negotiations
are not expected to have a substantial impact on Hydro Aluminium in the near future. The Federation
of Aluminium Consumers in Europe, which represents some aluminium consuming industries in the EU,
has been pressing the EU authorities for the removal of the EUs aluminium tariff for the past
several years. The EU Commission has, however, so far resisted a unilateral reduction of the
tariff. In addition, some of the new EU member countries are requesting duty free quotas, which, if
granted, would tend to reduce the effect of the duty.  Energy Taxation An EU directive on the taxation of energy products became effective on 1 January 2004. The
directive expanded the minimum tax system of energy products from mineral oils to all energy
products, including coal, coke, natural gas and electricity. This could affect Hydro Aluminium by
making energy inputs, including electricity, more expensive as a result of the tax. However,
countries subject to the directive will be authorized to apply reduced rates or tax exemptions on
certain products or energy uses, such as energy used in reduction processes, renewable energy
sources or heat produced in combined generation installations. Accordingly, aluminium producers in
the European Union may be able to secure tax relief depending upon how the individual countries
implement the directive and its reductions and exemptions. OTHER ACTIVITIES Other activities comprise businesses and activities outside of Hydros core business areas Oil
& Energy and Aluminium. 75




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Other activities include both production units as well as service functions. Hydros main
focus relating to Other activities is profitability improvements and strategic development of the
units as well as sales or disposals of businesses Hydro wishes to exit. Other activities also includes Industriforsikring a.s., Hydros captive insurance company. The main businesses and activities included in Other are: HYDRO POLYMERS Hydro Polymers is involved in all stages of production of the plastic raw material, PVC, also
known as vinyl, and its intermediate products, ethylene, chlorine and vinyl chloride monomer
(VCM). Hydro Polymers is the largest PVC supplier in the Nordic countries, with a market share of
approximately 65 percent. In the United Kingdom, Hydro Polymers ranks first with approximately 38
percent of the market. The PVC industry in Europe is relatively fragmented, reflecting the
industrys development on a national, rather than a European, basis. Hydro has an advantage in
being backward integrated into ethylene and having close proximity to other Scandinavian countries
and the United Kingdom, as well as long-term strategic relationships with customers in these
markets. Hydro has a 29.7 percent interest in Qatar Vinyl Company Ltd., which operates a petrochemical
plant at Mesaieed Industrial City, Qatar. The plant has an annual nameplate capacity of 230,000
tonnes of VCM, 175,000 tonnes of ethylene dichloride and 290,000 tonnes of caustic soda. The
operation in Qatar enjoys low gas prices, and is very competitive when world energy prices are
high. In China, Hydro has a 31.8 percent interest in Suzhou Huasu Plastics Co., Ltd., which
produces PVC film and has a suspension PVC (S-PVC) capacity of 120,000 tonnes per year. Hydro
also has a 26.2 percent interest in CIRES, a PVC resin and compound manufacturer in Portugal. Hydro Polymers will continue to focus on operational improvements through the establishment of
best practice teams to ensure the transfer of knowledge in both operations management and process
technology. The efficiency enhancement process is expected to entail further staff reductions,
improved supply contracts, increased productivity and improved margin management. Through the last
part of 2004, the business climate for PVC producers in Europe has improved substantially, and the
prospects for Hydro Polymers in 2005 are considered good. Raw Materials and Production Hydro has a 50 percent ownership interest in an ethylene cracker through Hydros joint venture
interest in Noretyl AS. The cracker is integrated with Hydros chlorine and VCM production
facilities located at Rafnes, in Norway. The production efficiencies inherent in an integrated
production process contribute to higher margins compared to margins of competitors that rely on
purchased ethylene. In June 2004, Hydro decided to carry out a project to debottleneck the
production process at Noretyl, increasing total capacity to 557,000 tonnes of ethylene per year.
With this expansion, Hydro Polymers will cover its total ethylene needs from own production. The
total cost of the project is estimated to be NOK 700 million. Petrochemicals production (in tonnes) 2004
    
    
    
    2003
    
    
    
    2002
    
    
    
    2001Base ProductsVCM
    
    
    
    541,000
    
    
    
    
    575,000
    
    
    
    
    540,000
    
    
    
    
    591,000Caustic Soda
    
    
    
    260,000
    
    
    
    
    281,000
    
    
    
    
    262,000
    
    
    
    
    279,000PolymersS-PVC
    
    
    
    496,000
    
    
    
    
    507,000
    
    
    
    
    458,000
    
    
    
    
    465,000P-PVC
    
    
    
    82,000
    
    
    
    
    81,000
    
    
    
    
    70,000
    
    
    
    
    72,000Total Polymers
    
    
    
    578,000
    
    
    
    
    588,000
    
    
    
    
    528,000
    
    
    
    
    537,000PVC Compounds
    
    
    
    132,000
    
    
    
    
    129,000
    
    
    
    
    128,000
    
    
    
    
    143,000
 76




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Average Market Quoted Prices in Northwest Europe 2004
    
    
    
    2003
    
    
    
    2002
    
    
    
    2001Ethylene
 /tonne delivered
    
    
    
    629
    
    
    
    
    522
    
    
    
    
    518
    
    
    
    
    616VCM  Spot export fob US$/tonne
    
    
    
    722
    
    
    
    
    452
    
    
    
    
    451
    
    
    
    
    345S-PVC
 /tonne delivered
    
    
    
    853
    
    
    
    
    683
    
    
    
    
    714
    
    
    
    
    656
 Hydro manufactures PVC at the following plants: Hydro Polymers AS (Porsgrunn, Norway),
Hydro Polymers AB (Stenungsund, Sweden) and Hydro Polymers Ltd. (Aycliffe, United Kingdom). The
Nordic sites produce S-PVC and paste PVC (P-PVC) while the U.K. site produces S-PVC for external
sale and mixing with additives to generate PVC compounds in a variety of grades to meet customer
specifications. There is also a small compounding plant at Halsingborg, Sweden. VCM is produced at
Hydros Rafnes and Stenungsund plants. Ethylene feedstock for the Rafnes facility is supplied by long-term contracts for NGLs from a
number of North Sea fields for approximately 50 percent of the required volumes. The remaining
needs are covered by spot purchases. The share of NGL purchased under long-term contracts will
increase from the autumn of 2005. Price formulas are linked to naphtha and therefore indirectly to
oil prices. As such, oil prices are an important driver of ethylene costs. Hydros share of
ethylene produced at Rafnes in 2004 was 215,000 tonnes. Hydro Polymers AS and Borealis have entered
into an agreement with Statoil and Petoro, under which it will purchase their ethane production at
Kårstø, for the period up until 2015. This, together with the Noretyl project described above,
should help enhance the long-term competitiveness of the ethylene plant. The total production of chlorine in 2004 was approximately 231,000 tonnes. Chlorine feedstock
in excess of Hydros own production is covered by medium-term and spot purchases (approximately
95,000 tonnes). Plant closures in Europe reduced the chlorine supply in 2002. In March 2003,
Hydros Board of Directors approved a plan to build a new 130,000 tonne chlorine plant at Rafnes,
based on modern membrane technology, at a cost of approximately NOK 1,000 million (phase 1). The
project is expected to be completed in the summer of 2005. In addition, a further investment of
approximately NOK 700 million to convert the existing chlorine plant from diaphragm to membrane
technology (phase 2) was approved in February 2005, with start-up of production scheduled for 2006. At present, Hydro Polymers transports raw materials and intermediates among its plants in
Rafnes, Stenungsund and Aycliffe. Increased efficiency and lower transportation costs could be
achieved by an improved balance between input (raw materials) and output (final product) streams at
the individual plants. The new chlorine plant (phase 1) will make Rafnes self-sufficient in
chlorine, and transportation of chlorine will cease. Sales and Distribution PVC and PVC compounds are mainly sold by Hydros own sales organization. Distribution is
mainly by truck. Pipe grade S-PVC is considered to be a commodity product, while there is
considerable product and price differentiation in other S-PVC applications. P-PVC accounts for
about 7 percent of the total PVC market. P-PVC is traditionally considered to be a specialty
product influenced only to a limited extent by S-PVC price developments. Caustic soda, a by-product of chlorine production, which is used by a variety of industries
such as in paper and pulp, alumina and soap production, is sold to customers in Europe and North
America mainly through Hydros own sales organization. Distribution is by vessel, rail or truck. In
addition to its own production, Hydro trades moderate quantities of caustic soda in the same
markets. 77




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Environmental issues Hydros chlorine plant in Stenungsund uses mercury in the production process. As a result of
actions taken by the Swedish authorities, all industrial use of mercury should cease by 2010. As a
result, a provision of SEK 36 million has been accrued to cover potential clean-up costs. In
addition, it is intended that all waste containing mercury will be removed and stored in a secure
environment by 2015. Due to substantial uncertainties regarding economic, technical and practical
aspects of the final treatment and deposition of such waste, it is presently not possible to make
an estimate of the potential costs involved. PVC has been the focus of environmental groups due to alleged negative health and
environmental effects arising from the production and use of PVC. Scientific research has indicated
that much of this criticism is unjustified. However, because the requirements imposed by laws and
regulations are frequently changed, laws and regulations enacted in the future, including changes
to existing laws and regulations, could adversely affect Hydro Polymers business. In addition, Hydro Polymers is subject to environmental laws and regulations in the different
jurisdictions in which it operates. These laws and regulations impose increasingly stringent
environmental protection standards regarding, among other things, air emissions, the storage,
treatment and discharge of waste waters, the use and handling of hazardous or toxic materials,
waste disposals practices, and the remediation of environmental contamination. The cost of
complying with these laws and regulations, including participation in assessments and remediation
of sites, could be significant. OTHER BioMar Holding AS(previously Treka AS) is a publicly held Danish company listed on the
Copenhagen stock exchange. Hydro has a 68.8 percent ownership in BioMar Holding AS. The operational
activity in BioMar Holding AS consists of the fish feed company BioMar. BioMar is the third largest producer of salmon feed globally (in terms of production volume)
with factories in Norway, Denmark, UK, France, Greece and Chile. Biomar has an annual production of
close to 450,000 tonnes. Biomar experienced a difficult year in 2003 including write-downs of
goodwill and intangible assets as well as well as significant losses on bad debts. In 2004, BioMar
improved its position through focus on cost efficient operations and by reducing risk exposure.
Biomar has approximately 500 employees. Hydro Production Partneris extensively involved in production and maintenance support within
Hydro and also with external customers. The main activities are in Norway. The operations include
approximately 1,400 employees. Hydro IS Partneris a wholly owned subsidiary rendering IT/IS services primarily to Hydro
units but also to external customers in Norway and internationally. The company has approximately
600 employees. Hydro IS Partner AS was established as a legal company 1 April 2004. Hydro holds 100
percent of the shares. Hydro Business Partnerrenders services and support functions mainly to Hydro units in Norway.
Its activities are mainly in the areas of procurement, accounting, human resources, and media as
well as the operation of industrial parks at Porsgrunn and Rjukan. INDUSTRIFORSIKRING Industriforsikring a.s., a captive insurance company, is a wholly-owned subsidiary of Hydro.
Industriforsikring provides property damage, business interruption, cargo and third party liability
insurance coverage for subsidiary companies of the Hydro Group. Industriforsikring also provides 78




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similar coverage for several related companies where Hydro owns a substantial equity interest.
Industriforsikring has an extensive reinsurance program and has maximum exposure per policy varying
from NOK 5 million for cargo insurance up to NOK 110 million for third party liability claims
exceeding NOK 1,500 million. Industriforsikring is also a member of a mutual insurance pool in
order to reduce the cost of insurance coverage it provides to Hydro operating units. The operations
of Industriforsikring are not substantial to Hydros overall business and the Companys exposure to
uninsured risk is not material. 
 ITEM 4.C. ORGANIZATIONAL STRUCTURE The following significant subsidiaries, as that term is
defined by applicable rules of the SEC, are included in the Hydro Group: Company Name
    
    
    Country of Incorporation
    
    
    Proportion of ownership Interest*Norsk Hydro Produksjon AS
    
    
    Norway
    
    
    100 percentHydro Aluminium AS
    
    
    Norway
    
    
    100 percentHydro Aluminium Deutschland GmbH
    
    
    Germany
    
    
    100 percent
   *
    
    Ownership percentage reflects proportion of voting power. 
 ITEM 4.D. PROPERTY, PLANTS AND EQUIPMENT The Groups rights to oil and gas located on the Norwegian Continental Shelf, mainly in the
North Sea, are among its most important assets. See Item 4.B. Business Overview  Oil and Energy 
Exploration, Development and Production for information with regard to reserves and sources of oil
and gas and Item 4.B. Business Overview  Hydro Oil and Energy  Oil and Energy Government
Regulation with regard to the Norwegian governments authority to increase its participation in
the development of certain oil and gas fields and other regulatory matters. The Groups major production plants in Norway are located at Porsgrunn (PVC), Rafnes
(petrochemicals), Karmøy, Årdal, Sunndalsøra, Holmestrand and Høyanger (aluminium). The Group owns
clear title concessions to hydroelectric power stations with a generating capacity of 2.7 TWh per
year. Generating capacity of approximately 5.8 TWh is operated under concessions from the Norwegian
government that will expire without compensation in the period between 2022 and 2051. Hydros
principal aluminium production facilities abroad are located in Austria, Belgium, Brazil, Canada,
China, Denmark, France, Germany, Hungary, Italy, Luxembourg, Poland, Portugal, Australia, Spain,
Sweden, the United Kingdom and the United States. Hydro has an interest in a retail gasoline and
fuel oil marketing network through an affiliated company in Denmark, Norway and the Baltic
countries, and wholly owned operations in Sweden. Hydro also participates in alumina refineries in
Jamaica and Brazil, and an automotive parts casting plant in Mexico. Virtually all of the Groups properties are owned by the Companys subsidiaries, except
certain facilities in the oil and gas, hydroelectric and petrochemicals businesses which are
jointly-owned with other companies. All major facilities of the Group are insured in line with
customary industry practices. Hydro is subject to changing environmental laws and regulations that in the future may require
Hydro to modernize technology to meet more stringent emissions standards or to take actions for
contaminated areas. See Note 21 to the Consolidated Financial Statements for a description of
expenses and accruals relating to corrective environmental measures for 2004 and preceding fiscal
years. There were no environmental measures, implemented voluntarily or required by law, which had
a significant effect on the utilization of Hydros main production facilities in 2004. 
 79




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ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS  ITEMS 5.A.-D.
    OPERATING RESULTS; LIQUIDITY AND CAPITAL RESOURCES; RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES; TREND INFORMATION The comparative discussion of Hydros financial condition and results of operations as of and
for the years ended 31 December 2004, 2003 and 2002 as well as information regarding Hydros
material commitments for capital expenditures as of year-end 2004 and Hydros research and
development policies for the three-year period ended 31 December 2004 is included in the following
discussion. (BAR CHART)

(BAR CHART) Financial review NOK million
    
    2004
    
    
    2003
    
    
    2002Operating revenues
    
    
    155,425
    
    
    
    133,761
    
    
    
    134,093Operating costs and expenses
    
    
    123,578
    
    
    
    112,136
    
    
    
    116,426Operating income
    
    
    31,847
    
    
    
    21,625
    
    
    
    17,667Non-consolidated investees
    
    
    628
    
    
    
    620
    
    
    
    (24
    )Financial income (expense), net
    
    
    136
    
    
    
    154
    
    
    
    1,806Other income (expense), net
    
    
    169
    
    
    
    (1,253
    )
    
    
    77Income from continuing operations
before tax and minority interest
    
    
    32,780
    
    
    
    21,146
    
    
    
    19,526Income tax expense
    
    
    (21,197
    )
    
    
    (12,922
    )
    
    
    (12,452
    )Minority interest
    
    
    (106
    )
    
    
    151
    
    
    
    26Income from continuing operations
    
    
    11,477
    
    
    
    8,375
    
    
    
    7,100Income from discontinued operations
    
    
    1,083
    
    
    
    2,312
    
    
    
    1,665Income before cumulative effect of
change in accounting principle
    
    
    12,560
    
    
    
    10,687
    
    
    
    8,765Cumulative effect of change
in accounting principle
    
    
    
    
    
    
    281
    
    
    
    Net income
    
    
    12,560
    
    
    
    10,968
    
    
    
    8,765Basic and diluted earnings per share
from continuing operations (in NOK)
    
    
    45.10
    
    
    
    32.50
    
    
    
    27.50Basic and diluted earnings
per share (in NOK)
    
    
    49.40
    
    
    
    42.60
    
    
    
    34.00
 This discussion should be read in conjunction with the
information contained in the Companys consolidated
financial statements and the related notes included in this
annual report. Overview Hydro completed the demerger of its Agri business
operation in 2004 following a comprehensive strategic review
concluding that the Company should move forward as one, strong
business enterprise with Oil and Energy and Aluminium as core
focus areas. Results for 2004 were strongly influenced by
worldwide economic developments driving demand for energy in
particular. Growth in China and the United States and the
depreciation of the US dollar were key elements underlying
market developments. Exceptionally high oil prices, combined
with improved market conditions for aluminium together with
increased production for both of the Companys core business
areas delivered one of the best results in Hydros 100 year
history. However, expiring energy contracts resulting in
higher future energy costs for the Companys primary aluminium
plants in Germany, together with a weakening in
competitiveness as a result of the weak US dollar, resulted in
a write down impacting after tax results by NOK 1.5 billion.
Market volatility generally had a notable impact on results
during the year. Strong production performance and capacity increases
positioned the Company to take advantage of the robust market
fundamentals. Average oil and gas production for 2004 reached
a record level of 572,000 barrel of oil equivalents (boe) per
day for the year while aluminium volumes increased 17 percent
for the year. The expansion of the Sunndal aluminium plant in
Norway was completed during the year. The plant is now the
largest and most modern in Europe. Increased competition in a rapidly changing market environment
also continued to drive cost reduction initiatives. The
Aluimprover cost reduction program announced early in 2004 is
well underway and expected to be completed at the end of the
first quarter of 2005. Total annual cost savings resulting
from the program are expected to range between NOK 350  400
million. This follows the completion of improvement programs
in 2003 generating estimated annual cost reductions of more
than NOK 2.5 billion. A solid financial position enabled Hydro
to buy back shares and pay an extraordinarily high dividend
for 2004. A total of 5 million shares, or approximately 2
percent of the Companys outstanding shares, were repurchased
and cancelled during the year while a second buy back program
covering up to 10 million shares was authorized by an
extraordinary General Meeting of shareholders on 1 December
2004. The Board of Directors proposed to the 2004 annual
General Meeting of shareholders a dividend of NOK 20 per share
compared to dividends of NOK 11 per share in 2003. Summary of operating results Hydros income from continuing operations in 2004 was
NOK 11,477 million (NOK 45.10 per share), compared with NOK
8,375 million (NOK 32.50 per share) for 2003 and NOK 7,100
million (NOK 27.50 per share) in 2002. On 24 March 2004,
Hydros agri business was transferred to Yara International
ASA in a demerger transaction. Results of the transferred
operations relating to periods prior to the demerger are
reported under Income from discontinued operations. The
following discussion excludes those activities. 80




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Operating income (in NOK million)
    
    2004
    
    
    2003
    
    
    2002Hydro Oil & Energy
    
    
    31,144
    
    
    
    21,143
    
    
    
    15,947Hydro Aluminium
    
    
    1,805
    
    
    
    2,456
    
    
    
    1,698Other activities
    
    
    312
    
    
    
    (404
    )
    
    
    48Corporate and eliminations
    
    
    (1,414
    )
    
    
    (1,570
    )
    
    
    (26
    )Total operating income
    
    
    31,847
    
    
    
    21,625
    
    
    
    17,667
 The change in 2004 operating income compared to the prior
year and the most important items affecting the change are
included in the table below. Amounts in NOK millionOperating income 2004
    
    
    31,847Operating income 2003
    
    
    21,625Change in Operating Income
    
    
    10,222Prices and currency, E & P 2)
    
    
    8,205Margin including currency effects 1)
    
    
    1,085Volume
    
    
    5,915Fixed costs
    
    
    (1,035
    )Depreciation
    
    
    (1,045
    )Production and exploration costs, E & P 2)
    
    
    (1,120
    )Write downs, demanning, other
    
    
    (2,080
    )Trading and unrealized LME effects, Aluminium
    
    
    (330
    )New / disposed business
    
    
    170Restructuring costs
    
    
    20Other
    
    
    437Total change in operating income
    
    
    10,222
   1)
    
    Including negative variances for elimination of
unrealized gain/loss on electricity contracts of NOK 94
million and a positive variance for elimination of the
gain\loss on gas contracts of NOK 144 million for 2004.2)
    
    Exploration and Production. Operating Income Increased operating results for Oil & Energy reflected
continued high oil prices and strong production growth during
2004. Measured in Norwegian kroner, realized average prices
increased about 24 percent for oil and approximately 6 percent
for gas in 2004. Realized average prices measured in Norwegian
kroner increased during 2003 approximately 4 percent and 7
percent for oil and gas respectively. During 2004, oil and gas
production reached record levels averaging 572,000 boe per
day, compared with 530,000 boe per day in 2003 and 480,000 boe
per day in 2002. However, unscheduled shutdowns of the partner
operated fields Snorre and Vigdis on the Norwegian Continental
Shelf (NCS) and the Terra Nova field in Canada resulted in a
total average production loss of approximately 20,000 boe per
day for the fourth quarter of 2004. Exploration costs declined
to NOK 1,264 million as a result of lower exploration activity
in 2004. The decline also reflected higher cost capitalization
due to successful wells and wells in progress. Exploration
costs amounted to NOK 1,577 million in 2003, a substantial
decline from NOK 3,558 million in 2002. The decline over the
last two years resulted from lower exploration activity level
and a substantially higher level of previously capitalized
exploration and acquisition costs expensed in 2002. Total
operating income for Energy and Oil Marketing for 2004 was
relatively unchanged from the previous year. However, a
decline in operating income, as a result of the divestment of
Hydros refining operations, Scanraff, in 2003, was offset by
inventory gains resulting from the increase in oil prices in
2004. In addition, forward price developments resulted in
unrealized gains on contracts for future deliveries of gas in
particular, and long term purchase contract for power, which
are valued at market prices at the end of the year. Operating
income for Energy and Oil Marketing declined about 4 percent
in 2003 compared to 2002 primarily as a result of lower power
production. Development activities relating to the Ormen Lange
gas field proceeded according to plan and the project was 20
percent complete at the end of 2004. Operating income for
Aluminium declined in 2004 as a result of a write down
relating to the Companys primary aluminium plants in Germany
in the amount of NOK 2,042 million. In addition, NOK 268
million relating to the write down was included in results for
non-consolidated investees.


Operating income was also impacted
by NOK 519 million of costs relating to manning reductions in
Norway. Aluminium operating results were positively influenced
by volume increases combined with strengthened
London Metal Exchange (LME) prices. For 2004, Hydro realized
average aluminium prices of US dollar 1,638 per tonne
compared to US dollar 1,440 per tonne in the previous year and
US dollar 1,372 in 2002. Average realized aluminium prices
measured in Norwegian kroner increased 9.5 percent for 2004
and declined 7.3 percent in 2003 reflecting fluctuations in
the US dollar\NOK exchange rate.
Upstream volumes increased in 2004 mainly as a result of
new capacity and improved capacity utilization. Volumes also
increased in 2003 as a result of the inclusion of VAW for the
entire year as well as new capacity. The implementation of the
Aluimprover cost-reduction program progressed during 2004. The
total estimated cost of the program was reduced by NOK 200
million to NOK 600 million of which NOK 432 million was
charged to the results for 2004. Improvement programs
initiated in 2001 and 2002 were completed in 2003 at an
accumulated cost of NOK 1,116 million of which NOK 176 million
impacted the results in 2003. These programs are generating
estimated annual cost reductions of more than NOK 2.5 billion. In December, Hydro signed a Heads of Agreement with Qatar
Petroleum to evaluate the development of one of the worlds
largest aluminium plants in Qatar. Results for Other activities reflected improved operating
results in 2004 for Hydros polymer business and positive
developments within BioMar Holding AS (formerly Treka AS).
Results for BioMar in 2003 included write downs relating to
goodwill and intangible assets as well as significant losses
on bad debts, in total amounting to around NOK 570 million.
Results for Other activities was also impacted by an insurance
loss provision of NOK 230 million relating to the Companys
captive insurance company, Industriforsikring. Corporate
activities and eliminations operating losses increased in 2004
impacted by the elimination of unrealized gains on power
purchase contracts. Net costs related to pensions and related
social security charged to Corporate and eliminations amounted
to NOK 1,001 million in 2004, relatively unchanged compared to
NOK 1,111 million in 2003. Net costs relating to pensions and
related social security costs amounted to NOK 312 million in
2002. The increase for 2003 primarily related to increased
pension obligations and a reduction in plan assets during
2002. Hydro Energy is responsible for ensuring the supply of
electricity for the Companys own consumption, and has entered
into sales contracts with other units in the Group. Certain of
these sales contracts are recognized at market value by Hydro
Energy while the related internal purchase contracts are
regarded as normal purchase agreements and are not recognized
at market value. The 81




---



##### 



elimination of the market value
adjustment recorded by Hydro Energy resulted in a negative
effect of NOK 235 million for 2004, compared to a negative
effect of NOK 141 million for 2003 and a positive effect of
NOK 588 million in 2002. The power purchase contracts have a
duration of up to 10 years and can result in significant
unrealized gains and losses, impacting the reported results in
future periods. The magnitude of the reported effects depends
on trends in forward prices for electricity and changes in the
contract portfolio. Restructuring costs included in operating income for 2004
amounted to a credit of NOK 22 million, representing the
difference between an accrual of NOK 650 million charged in
2001, relating to the restructuring of the Companys magnesium
operations in Norway and the final cost of the program, which
ended in the fourth quarter of 2004. No amounts relating to
restructuring costs were charged or credited to operating
income in 2003. Earnings from non-consolidated investees Earnings from non-consolidated investees for 2004
amounted to NOK 628 million, compared to earnings of NOK 620
million in 2003 and losses of NOK 24 million in 2002. Results
for 2004 included NOK 268 million relating to the write down
of the German plants described above. In addition, results for
2004 included unrealized currency gains relating to Alunorte
of NOK 63 million, compared with a gain of NOK 218 million in
2003 and a currency loss of NOK 461 million in 2002. Improved
operating results relating to non-consolidated investees
mainly within Aluminium Metals, Extrusion and Automotive, and
Polymers offset the effects of the lower unrealized currency
gains in 2004. Financial income (expense) net Net financial expenses for 2004 amounted to NOK 136
million, including foreign currency gains of NOK 1,350 million
reflecting the significant weakening of the US dollar during
the year and in the fourth quarter in particular. The amount
for 2004 also included a charge of approximately NOK 860
million relating to the prepayment of bonds denominated in US
dollars, Euro and British pounds totalling about NOK 5 billion
in nominal value. Net interest expense declined approximately
NOK 300 million
for the year, mainly as a result of the repayment of debt and
as a result of higher tax related interest earnings amounting
to about NOK 235 million. Net financial income was NOK 154
million in 2003 including foreign currency gains of NOK 1,035
million. For 2002, net financial income amounted to NOK 1,806
including foreign currency gains of NOK 3,262 million. Other income (loss) Other income (loss) for 2004 amounted to NOK 169
million reflecting a gain of NOK 110 million on the
divestment of 80.1 percent of Pronova Biocare and NOK 59
million relating to the divestment of Skandinaviska
Raffinaderi AB (Scanraff). For 2003, Other income (loss)
resulted in a loss of NOK 1,253 million. The amount included
a charge of NOK 2,207 million resulting from amended
Norwegian tax regulations relating to the removal costs for
oil and gas installations on the NCS. The change in
regulations also resulted in a reduction to the tax provision
for the second quarter of 2003 by NOK 2,380 million, for a
net non-recurring effect of NOK 173 million. Other income for
2003 also included a gain of NOK 326 million from the sale of
the Companys interest in the Sundsfjord power plant in
exchange for shares in the acquiring power company. In
addition, Other income in 2003 included a gain of NOK 490
million on the sale of Hydros interest in Scanraff. The sale
agreement included the possibility of a price adjustment
depending on the development in refinery margins during 2004
and 2005. High refinery margins during 2004 have resulted in
an additional gain of NOK 59 million being recognized in the
fourth quarter of 2004. Other income amounted to NOK 77
million in 2002. Income tax expense The provision for current and deferred taxes for 2004
amounted to NOK 21,197 million, approximately 65 percent of
income from continuing operations before tax. Current taxes
amounted to NOK 24,142 million in 2004. The total provision
for current and deferred taxes for 2003 was NOK 12,922
million, approximately 61 percent of income from continuing
operations before tax. For 2002, the total provision for
current and deferred taxes amounted to NOK 12,452 million,
approximately 64 percent of income from continuing operations
before tax. In the fourth quarter of 2004, Norwegian tax legislation
was changed to eliminate tax on the sale of shares in
companies registered within countries in the European Economic
Area. As a result, Hydro has reversed deferred tax liabilities
relating to such share holdings amounting to approximately NOK
900 million, reducing the tax rate by around 2.5 percentage
points for 2004. The tax rate for 2003 included the effect of
the amended regulations relating to the tax treatment of
expenses incurred in removing oil and gas installations from
the NCS. As a result, Income from continuing operations
before tax for the period included a negative non-recurring
amount of NOK 2,207 million, offset by a positive
non-recurring amount of NOK 2,380 million included in tax
expense. Excluding the effect of the change in regulations,
the tax rate was 66 percent of the pre-tax result for the
period. The high effective tax rate for Hydro results from oil
and gas activities in Norway, which account for a
relatively large part of earnings and are charged a
marginal tax rate of 78 percent. Discontinued operations Income from discontinued operations amounted to NOK
1,083 million for 2004, all relating to the first quarter of
the year, prior to the completion of the demerger of the agri
activities. Income from discontinued operations amounted to
NOK 2,312 million in 2003 and NOK 1,665 million for 2002. The
amounts relate to activities transferred to Yara International
ASA in the demerger transaction completed 24 March 2004. All
results directly connected to the demerged operations as well
as the demerger transaction costs and gains are included in
Income from discontinued operations. The amounts include
Yaras results for the period up to its listing on the Oslo
Stock Exchange and the direct costs of the demerger. The
amounts also include Hydros gain from the sale of its
remaining 20 percent shareholding in Yara, amounting to NOK
385 million after tax. The effects of internal transactions,
including interest and currency gains and losses, are excluded
from Income from discontinued operations. Previous periods
have been adjusted in order to present the results on a
comparable basis. Return on average Capital Employed(RoaCE
1) from continuing operations was 13 percent for
2004. RoaCE for the Segments and Hydro as a whole for the
three years ending 31 December 2004 is presented in the table
below: 82




---



##### 



2004
    
    
    2003
    
    
    2002Hydro Oil & Energy
    
    
    23.4
    %
    
    
    16.2
    %
    
    
    11.6
    %Hydro Aluminium 2)
    
    
    3.5
    %
    
    
    4.7
    %
    
    
    2.7
    %Total Hydro 2)
    
    
    13.0
    %
    
    
    8.4
    %
    
    
    7.2
    %
    1)
    
    RoaCE is defined as Earnings after tax divided by
average Capital Employed. See discussion pertaining to
Use of Non GAAP financial measures included this report.2)
    
    RoaCE and normalized RoaCE for 2004 was negatively affected
by the write down of the primary metal plants in Germany and
change in tax regulations by 3.5 percent for Aluminium and 0.6
percent for Total Hydro. Hydro also measures RoaCE based on long-term price
assumptions, referred to as normalized prices. Normalized
prices are used in order to avoid placing undue emphasis on
such variables as historically high or low prices of its
commodity products, and the effect of changes in currency
exchange rates. RoaCE based on long term price assumptions of
USD 25 per barrel of oil, USD 1,500 per tonne of Aluminium,
NOK 7 per USD and NOK 8 per EUR and excluding other income and
restructuring costs was 7.9 percent for 2004 representing a
substantial improvement from 6.2 percent achieved in 2003.
Normalized RoaCE for the Segments and Hydro as a whole for the
three years ending 31 December 2004 is presented in the table
below: 2004
    
    
    2003
    
    
    2002Hydro Oil & Energy
    
    
    13.0
    %
    
    
    11.4
    %
    
    
    9.2
    %Hydro Aluminium 2)
    
    
    1.5
    %
    
    
    4.1
    %
    
    
    2.9
    %Total Hydro 2)
    
    
    7.9
    %
    
    
    6.2
    %
    
    
    6.6
    %
 Adjusted EBITDA3) In the segment discussion below, Hydro refers to
adjusted EBITDA which is an integral part of Hydros steering
model, Value Based Management, reflecting the Companys focus
on cash flow based indicators. A reconciliation of Operating
income to adjusted EBITDA for 2004 for each of Hydros
operating segments is presented in the table below: Operating income -
adjusted EBIT - adjusted EBITDA 2004 SelectedAmounts in
    
    Operating
    
    
    Non-cons.
    
    
    Interest
    
    
    financial
    
    
    Other
    
    
    Adjusted
    
    
    Depr.
    
    
    AdjustedNOK million
    
    income (loss)
    
    
    Investees
    
    
    Income
    
    
    income
    
    
    income
    
    
    EBIT
    
    
    and amort.
    
    
    EBITDAExploration and Production
    
    
    28,363
    
    
    
    4
    
    
    
    46
    
    
    
    3
    
    
    
    
    
    
    
    28,416
    
    
    
    9,752
    
    
    
    38,168Energy and Oil Marketing
    
    
    2,650
    
    
    
    73
    
    
    
    35
    
    
    
    (3
    )
    
    
    59
    
    
    
    2,814
    
    
    
    664
    
    
    
    3,478Eliminations
    
    
    131
    
    
    
    (2
    )
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    130
    
    
    
    2
    
    
    
    132Hydro Oil & Energy
    
    
    31,144
    
    
    
    75
    
    
    
    81
    
    
    
    1
    
    
    
    59
    
    
    
    31,360
    
    
    
    10,418
    
    
    
    41,778Metals
    
    
    830
    
    
    
    281
    
    
    
    5
    
    
    
    107
    
    
    
    
    
    
    
    1,223
    
    
    
    4,173
    
    
    
    5,396Rolled Products
    
    
    626
    
    
    
    (13
    )
    
    
    3
    
    
    
    (1
    )
    
    
    
    
    
    
    615
    
    
    
    746
    
    
    
    1,361Extrusion and Automotive
    
    
    277
    
    
    
    113
    
    
    
    15
    
    
    
    (5
    )
    
    
    
    
    
    
    400
    
    
    
    1,427
    
    
    
    1,827Other and eliminations
    
    
    72
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    72
    
    
    
    
    
    
    
    72Hydro Aluminium
    
    
    1,805
    
    
    
    381
    
    
    
    23
    
    
    
    101
    
    
    
    
    
    
    
    2,310
    
    
    
    6,346
    
    
    
    8,656Other activities
    
    
    312
    
    
    
    170
    
    
    
    130
    
    
    
    108
    
    
    
    110
    
    
    
    830
    
    
    
    533
    
    
    
    1,363Corporate and eliminations
    
    
    (1,414
    )
    
    
    2
    
    
    
    739
    
    
    
    (20
    )
    
    
    
    
    
    
    (693
    )
    
    
    13
    
    
    
    (680
    )Total
    
    
    31,847
    
    
    
    628
    
    
    
    973
    
    
    
    190
    
    
    
    169
    
    
    
    33,807
    
    
    
    17,310
    
    
    
    51,117
   3)
    
    See discussion pertaining to Segment Measures included in footnote 5 Operating and
geographic segment information to the Consolidated Financial Statements 83




---



##### 



(BAR CHART) NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    72,718
    
    
    
    59,959
    
    
    
    55,845Operating Costs
    
    
    41,574
    
    
    
    38,816
    
    
    
    39,898Operating Income
    
    
    31,144
    
    
    
    21,143
    
    
    
    15,947Adjusted EBITDA
    
    
    41,778
    
    
    
    31,826
    
    
    
    25,340RoaCE
    
    
    23.4
    %
    
    
    16.2
    %
    
    
    11.6
    %Number of employees
    
    
    3,527
    
    
    
    3,465
    
    
    
    4,039
 Hydro Oil & Energy consists of the sub segments Exploration
and Production and Energy and Oil Marketing. Overview As operator of 11 producing fields on the Norwegian
Continental Shelf (NCS) with a total production of
approximately 979,000 boe per day (boed) in 2004, Hydro is
the second largest operator company in Norway. Hydro is
among the world leaders offshore, and has strong competence
over the entire exploration and production value chain. In
terms of equity production, Hydro is the third-largest
producer of oil and natural gas on the NCS. In 2004, the
companys equity oil and gas production increased
approximately 8 percent compared to the previous year, to an
average of 572,000 boed. Fields on the NCS accounted for
approximately 90 percent of the production. The remaining
production came from fields in Canada, Angola, Libya and
Russia. In addition, Hydro is involved in ongoing
exploration activities in most of these areas and also in
the United States (Gulf of Mexico), Iran, Denmark, Morocco
and Madagascar. Natural gas is becoming increasingly
important to Hydro. The Company expects a strong increase in
equity gas production, and is becoming a key gas supplier
for a growing European market. In 2004, Hydro Oil & Energys
equity natural gas production from the NCS amounted to 8.8
billion cubic meters (bcm), an increase of 13 percent
compared to the previous year. Hydro holds capacity rights
in Gassled, the natural gas transportation infrastructure on
the NCS, enabling access to five landing points for natural
gas in Europe. Oil & Energys natural gas export capacity
together with its solid reserves, makes Hydro one of the
most reliable suppliers to Northern Europe. Hydro is an
active trader of oil and energy in Europe, and markets
gasoline and energy products in Scandinavia and the Baltic
countries. Oil & Energy is one of the largest producers of
electric power in Norway, with a normal annual production
from hydroelectric
facilities of approximately 8.5 terrawatt hours (TWh). Oil &
Energy has about 3,500 employees, and reached total
operating revenues of close to NOK 73 billion in 2004. Hydro Oil & Energys results in 2004 were an all-time
high, due to solid growth in production combined with
favourable market conditions. Strong demand growth, in
particular in China and the United States, combined with
worldwide capacity constraints, were the key drivers
underlying the high oil prices. However, it is uncertain if
the economic growth underlying demand is sustainable and
whether oil prices will remain at the present high levels or
revert towards the lower longer-term trend indicated by
forward prices. The oil industry as a whole continues to
experience reduced exploration results worldwide. The main
challenge facing Oil & Energy is the replacement of existing
reserves and the need to discover major new oil and gas
resources. Hydro is continuously working towards improved oil
recovery from its existing fields in addition to finding
viable development solutions for exploiting smaller fields,
including satellite fields which can be economically developed
by optimal use of present infrastructure. However, in order to
secure future production, exploration and acquisitions are
important elements in Hydros strategy. While the current high
oil price level creates opportunities relating to optimal
development and exploitation of existing assets, the high oil
price level is also a challenge in that the acquisition of
technical resources is becoming increasingly expensive. Based
on expectations of continued high oil price levels Oil &
Energy has increased its price assumptions for oil and gas
investment decisions from US dollar 16 per boe to US dollar 25
per boe. This decision is expected to result in new business
opportunities that were previously deemed uneconomic. Hydro
also intends to acquire technical resources where its
competencies and expertise can add value to assets traded in
the marketplace. Hydro plans to continue its focus on new
sources of energy, such as wind-power and hydrogen. The main
factors driving the development of new energy include
environmental concerns, rising energy demands, and the
security of existing energy supply. The share of renewable
energy is expected to grow in the years to come as OECD
(Organization for Economic Cooperation and Development)
countries increasingly depend on oil from OPEC countries and
developing countries. Summary of Oil & Energys operating results Hydro Oil & Energys operating income in 2004 was NOK
31,144 million, an increase of 47 percent compared to 2003.
Operating income amounted to NOK 21,143 in 2003, increasing
33 percent compared to 2002. The change in 2004 operating
income compared to the prior year and the most important
items affecting the change are included in the table below. 84




---



##### 



Amounts in NOK millionOperating income 2004
    
    
    31,144Operating income 2003
    
    
    21,143Change in Operating Income
    
    
    10,001Prices and currency for E&P- Oil
    
    
    8,900- Gas
    
    
    700- Currency
    
    
    (1,395
    )8,205Margin
    
    
    (15
    )Volume
    
    
    3,490Fixed costs
    
    
    25Depreciation
    
    
    (750
    )Production costs
    
    
    (1,435
    )Exploration costs
    
    
    315New / diposed business
    
    
    (205
    )Other
    
    
    371Total change in Operating income
    
    
    10,001
   1)
    
    Defined as the cost of operating fields,
including CO2emission tax, insurance,
gas purchased for injection and lease costs for
production installations (but excluding transportation
and processing tariffs, operating cost transportation
systems and depreciations). The most significant
developments that influenced Hydro Oil & Energys
operating income in 2004 were as follows: Oil and gas prices were high throughout the year,
reflecting continued high demand for crude oil with world oil
production running close to full capacity. Oil prices
increased in 2004 reaching an average realized oil price of US
dollar 37.3, up 30 percent from US dollar 28.7 in 2003.
However, part of the effect of the price increase was offset
by the depreciation of the US dollar against NOK. Measured in
Norwegian kroner, the oil prices in 2004 were about 24 percent
higher than in 2003, and realized
gas prices increased by approximately 6 percent. In 2003,
oil prices and gas prices increased roughly 4 and 7 percent
respectively, measured in Norwegian kroner. Oil and gas production increased in 2004 by approximately 8
percent to an average of 572,000 boe per day (boed). The
increase came from Norwegian fields, while international
fields remained at the same production level as in 2003. In
2003, oil and gas production increased by about 10 percent to
an average of 530,000 boed. Prices in the Nordic electric power market were NOK 0.24 per
kWh in 2004, compared to NOK 0.29 kWh in 2003 and NOK 0.20
kWh in 2002. Power production in 2004 was 8.1 TWh, 8 percent
higher than in 2003. Power production declined by 27 percent
in 2003 to 7.5 TWh compared to 2002 as a result of low
reservoir levels. During 2004, Hydro has been engaged in a
development project to expand the Tyin hydropower plant in
Sogn, Norway. The expansion was completed in the autumn
resulting in a 15 percent increase in production capacity for
the plant with no change in the existing water reservoir
capacity. Hydros average oil and gas production cost 1)was NOK 20.7 per boe in 2004, the same level as the
previous year. Average production cost amounted to NOK 22.6 in
2002. Total expensed exploration costs including appraisal costs of
discoveries amounted to NOK 1,264 million in 2004, a reduction
of about 20 percent compared to the previous year. The decline
is the result of a larger proportion of capitalized
exploration well costs as a result of successful wells and
wells in progress, in addition to a 12 percent reduction in
the level of exploration activity for 2004 compared to 2003.
There were 17 exploration wells drilled and completed in 2004
resulting in 11 discoveries. In 2004, NOK 248 million relating
to costs capitalized in previous years was expensed, compared
to NOK 88 million in 2003. Exploration costs expensed in 2003
amounted to NOK 1,577 million, a substantial decline from NOK
3,558 million in 2002. The decline resulted from lower
exploration activity level and a substantially higher level of
previously capitalized exploration and acquisition costs
expensed in 2002. The sale of Hydros interest in the Gjøa field, which is
in the pre-development phase, was approved by the Norwegian
authorities in January 2004 and resulted in a tax-free gain of
NOK 285 million for the year. Hydro continued activities to
optimize its oil and gas portfolio during 2004. In January
2004, Hydro signed an agreement to sell its 10 percent share
in the Snøhvit field to Statoil. The sale was completed in
December 2004, and resulted in a gain of approximately NOK 100
million after tax. Hydro completed a purchase of a two percent
share in the Kristin field from Statoil at the same time. As a
result, Hydro now owns 14 percent of the Kristin field and has
improved its position in the Norwegian Sea area on the NCS. Adjusted EBITDA for Oil & Energy for 2004 was NOK 41,778
million, an increase of 31 percent compared with 2003.
Adjusted EBITDA increased 26 percent in 2003 compared to the
previous year. The improvement in adjusted EBITDA resulted
from the same factors underlying the improvement in operating
income described above. Eliminations Oil & Energy As part of its downstream activities, Hydro Energy
enters into purchase contracts for natural gas with
Exploration and Production for resale to external customers.
Hydro Energy recognizes both the internal purchase and the
external sales contracts at market value. As a result, Hydro
Energy recognizes unrealized gains and losses on the internal
contracts as a result of fluctuations in the forward price of
gas. Exploration and Production regard the supply contracts to
Hydro Energy as normal sales agreements and does not recognize
unrealized gains and losses on the contracts. Eliminations of
the internal sales and purchase contracts between Hydro Energy
and Exploration and Production resulted in a positive effect
on the operating income for Oil and Energy of NOK 144 million
for 2004 as a result of declining forward prices. Key development activities and other projects Hydro has extended its average compound annual
growth rate for production of 8 percent for the 2001-2007
period to 2008. The growth target is based on Hydros current
portfolio of fields in production, fields under development or
fields considered for development. The production target for
2005 is an average of 575,000 boed of which approximately 85
percent is expected to come from currently booked proved
reserves. The partner operated Snorre and Vigdis fields have
gradually regained production after being shut down from
November to late January 2005 due to an underground gas
leakage. In early February the fields were producing close to
normal. Hydros proved oil and gas reserves were 2,076 million
barrels of oil
equivalents (mboe) at the end of 2004, compared to 2,288
mboe at the end of 2003 and 2,225 mboe at the end of 2002: 85




---



##### 



Reserves in mboe
    
    2004
    
    
    2003
    
    
    2002Proved reserves at beginning of year
    
    
    2,288
    
    
    
    2,225
    
    
    
    2,073New reserves
    
    
    23
    
    
    
    265
    
    
    
    118Revisions of reserves
    
    
    39
    
    
    
    (6
    )
    
    
    23Net purchase and sales
    
    
    (65
    )
    
    
    (2
    )
    
    
    186Production
    
    
    (209
    )
    
    
    (194
    )
    
    
    (175
    )Proved reserves at end of year
    
    
    2,076
    
    
    
    2,288
    
    
    
    2,225
 New reserves amounted to 23 mboe in 2004 including; Njord gas
export, the Rosa field, and Gulltopp. Proved reserves are
estimates and are expected to be revised as oil and gas are
produced and additional data become available, and in 2004
revisions of reserves in producing fields increased reserves
by 39 mboe. Revisions included a reduction of 9 mboe relating
to production sharing agreements. Net purchases and sales
decreased reserves by 65 mboe including the sale of Snøhvit.
Production amounted to 209 mboe in 2004. Reserve life (defined
as the number of years of production from proved reserves at
the present production level) was 10 years at the end of 2004;
comprised of 6 years for oil and 21 years for gas. The Ormen Lange development will continue to be a main
development project for Hydro in 2005. Hydro is the operator
during the development phase of the field. Ormen Lange is the
largest discovered undeveloped gas field on the NCS, at water
depths of 850 to 1,100 meters. Production is scheduled to
begin in the final quarter of 2007. The Ormen Lange project is
proceeding according to plan, and was about 20 percent
complete at year-end. The related Langeled gas pipeline which
is under development will transport gas from Ormen Lange
approximately 1,200 kilometers from Nyhamna on the west coast
of Norway via Sleipner in the North Sea to Easington in the
UK. The Langeled Gas Export system will have a transport
capacity of around 25.5 billion Sm3gas per year
and is expected to be completed in 2007. Langeled will be
merged with the Gassled pipeline joint venture after start up
of operations. The United Kingdom is an attractive market for
Norwegian gas due to the declining UK gas reserves. Hydro has
established a UK gas marketing channel through a joint venture
with Wingas GmbH called HydroWingas. As a result of international business development during
2004, Hydro was awarded its first international operatorship,
responsible for the development of the Telemark field
(formerly called the Champlain field) in the Gulf of Mexico
(GoM). A final development solution for the Telemark field is
expected to be decided in 2005. In 2005, Hydro plans to
increase its exploration level to around NOK 2 billion
including drilling approximately 30 exploration wells. Around
20 of the wells are planned for the NCS (including 3 wells in
the Barents sea) with the remaining wells relating to the
Companys international interests, mainly in Libya and Angola. Hydro intends to maintain its position as an efficient
operator on the NCS, and to contain cost levels on operated
facilities despite the underlying maturing nature of the
portfolio. Hydro has targeted a production cost of NOK 24 per
boe for 2005, an increase from actual production cost of NOK
20.7 in 2004, reflecting among other things, costs for
purchase and transportation of increased volumes of gas to be
injected into the Grane field in order to increase oil
recovery from Grane. Naturkraft AS, a 50 percent Hydro owned
company, is in process of developing a gas-fired power plant
at Kårstø, located on the west coast of Norway. A final
investment decision is scheduled for 2005. The power plant is
planned to be in operation during fall 2007. Hydros share of
the expected annual production of the plant is roughly 1.5
TWh. The total investment cost of the project is estimated to
be somewhat more than NOK 2 billion. Hydro has a strong gas
infrastructure position in Northern Europe, and a marketing
system in place for the sale of uncommitted volumes. The
European continental gas market continues to be dominated by
long-term contracts indexed to oil products. However, the
ongoing liberalization process of the European gas market is
expected to lead to a more liquid market with contract prices
influenced also by short-term gas market developments. Hydro
intends to combine its role as a natural gas producer with
that of a wholesaler and trader to increase its share in this
emerging market. Liquidity within the UK market has increased,
and is now considered well functioning short term market.
While there is less liquidity on the European continent, it is
increasing at several emerging hubs, in particular at
Zeebrugge in Belgium. Outlook The tight market fundamentals driving the oil price
increases discussed above are reflected in the forward
markets. In early February, the Brent forward price was
several dollars above the average Brent spot price in 2004.
Many analysts are predicting that growth in global oil demand
will lead to higher demand for OPECs oil in 2005, because of
insufficient capacity in the non-OPEC countries to satisfy the
growth in demand. Several analysts believe that Iraq will not
be able to increase its average crude output from 2004 levels
due to the mismanagement of wells and continuing sabotage of
the oil infrastructure. The risk for supply interruptions in
large oil producing countries is expected to persist in 2005.
The main factor which could dampen prices is a decline in the
high levels of demand experienced in 2004. If economic growth
fades in China and the US, oil demand is expected to suffer as
a consequence. Although high energy costs have not affected
economic growth substantially in 2004, several analysts see
the possibility of weaker economic growth in 2005. The development of the US dollar against the NOK will
impact Hydros realized price in Norwegian kroner. The negative price differential of the Grane oil,
compared to the lighter and sweeter benchmark Brent crude, is
expected to have a larger effect on Hydros average realized
oil price in 2005 than in 2004, mainly because the Grane field
is expected to account for a larger part of Hydros production
in 2005. Water reservoir levels were approximately on average
at the end of 2004 for Hydro-owned power stations and for the
Nordic market area in general. Further improvement in
reservoir levels have occurred since the beginning of 2005. As
a result, the Companys hydro electric power generation in
2005 is expected to be above normal. While the present
reservoir levels in the Nordic market are close to normal,
snow reservoirs are above normal, in particular in Norway
which has surplus levels. This is expected to put downward
pressure on prices during the summer of 2005. Beyond this
temporary surplus situation, a tighter capacity balance is
expected during the next several years as a result of demand
growth. The highly volatile markets with potential substantial
impact on market valuation of Hydros gas and power contracts
are expected to continue in 2005. 86




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##### 



Exploration and Production Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    48,962
    
    
    
    37,904
    
    
    
    32,970Operating Costs
    
    
    20,599
    
    
    
    19,404
    
    
    
    19,833Operating Income
    
    
    28,363
    
    
    
    18,500
    
    
    
    13,137Adjusted EBITDA
    
    
    38,168
    
    
    
    27,624
    
    
    
    21,593Number of employees
    
    
    2,821
    
    
    
    2,800
    
    
    
    3,372
 Exploration and Production (E&P) includes Hydros oil and gas
exploration activities, field development activities and oil
and gas production activities. Hydro currently has production
of oil and gas in Norway, Canada, Angola, Libya and Russia. In
addition, Hydro is conducting exploration activities in most
of these areas and also in the USA (Gulf of Mexico), Iran,
Denmark, Morocco and Madagascar. Market Conditions Oil prices increased to exceptionally high levels
in 2004. In addition to the increased demand described above,
a shortage of global refining capacity has been driving price
increases for light, sweet oil such as Brent and West Texas
Intermediate (WTI). There has also been increasing political
unrest in key oil producing countries, in particular Iraq and
Saudi Arabia. Hydro realized average oil prices of US dollar
37.3 in 2004, up 30 percent from US dollar 28.7 in 2003. This
is approximately 0.9 US dollar below the average Brent price
of US dollar 38.2. The lower realized prices resulted
primarily from negative price differentials on oil from the
Grane field, which is heavier than Brent blend and therefore
sold at lower average prices. Expressed in Norwegian kroner
average oil prices went up from NOK 203 in 2003 to NOK 251 in
2004, an increase of 24 percent. Average realized gas prices
in 2004 were NOK 1.09 per standard cubic meter, up 6 percent
from NOK 1.03 per standard cubic meter in 2003. The increase
primarily reflected higher prices of oil products (gas prices
in long term contracts are, to a large extent, linked to the
price of oil products with a lag of
approximately six months). Realized average NOK prices
increased during 2003 approximately 4 percent and 7 percent
for oil and gas respectively. Revenues Operating revenues for E&P in 2004 were NOK 48,962
million, an increase of 29 percent from the previous year.
Operating revenues increased 15 percent in 2003 compared to
2002. In addition to the higher price levels experienced for
oil and gas, in particular for 2004, the increase reflected
substantial growth in total production volumes for both years.
During 2004, average production increased from 530,000 boed in
2003 to 572,000 boed. Average production increased in 2003
from a level of 480,000 boed in 2002. The 2004 increase of
approximately 8 percent was in line with the targeted 8
percent compound annual growth rate for the 2001-2007 period.
Oil production in 2004 increased by 6 percent and accounted
for 73 percent of the total production compared to 74 percent
in 2003. Gas production increased to a total of 8.8 billion
standard cubic meters, an increase of 13 percent compared to
7.8 billion standard cubic meters in 2003. Hydro achieved production growth from Norwegian fields in
2004, while international fields remained at the same
production level as in 2003. New fields coming on stream in
2004 were the Kvitebjørn field in Norway, and new fields in
the Murzuq basin in Libya. In addition Hydro experienced
production growth from fields coming on stream in the end of
2003, including the Grane, Fram and Mikkel fields in Norway,
as well as the Jasmim field in Angola. The relative proportion
of production outside the Norwegian Continental Shelf (NCS)
was stable for the three-year period accounting for 10-11
percent of the total production. Maintenance stops and other
shutdowns resulted in production losses (or delayed
production) of 20,000 boed compared to 12,000 boed in 2003 and
9,000 boed in 2002. Approximately 5,000 boed of the production
loss in 2004 related to the shutdown of partner operated
Snorre and Vigdis fields in Norway due to gas leakage and the
Terra Nova field in Canada due to an oil leak in the end of
2004. Terra Nova resumed production in mid-December. Operating Costs Operating costs for E&P were NOK 20,599 million in
2004, an increase of 6 percent compared to the previous
year. Operating costs declined slightly in 2003 compared to
2002. Hydros average production cost was NOK 20.7 per boe in
2004, the same level as in 2003. Average production costs
amounted to NOK 22.6 per boe in 2002. Production costs per
barrel in 2004 excluding gas injection cost relating to the
Grane field fell by about 10 percent from the 2003 level.
However, costs related to increased volumes of injection gas to
the Grane field offset this reduction. Depreciation, including
write-downs and depreciation of capitalized costs relating to
abandonment and well closure (but excluding depreciation on
transportation systems), averaged NOK 46 per boe, the same
level as in 2003 and 2002. Included in the amount for 2004 was
an additional charge for depreciation relating to an increase
in the estimate for abandonment and well closure on the Ekofisk
and Frigg fields of approximately NOK 260 million (NOK 1 per
boe). The Frigg field, operated by Total, ceased production in
October 2004, and preparation for removal is under way. The
estimate for abandonment on Frigg was increased after receiving
tender offers from contractors. In general, there is little
experience with removing large installations on the NCS, and
cost estimates are uncertain. Total depreciation costs
increased from NOK 9,052 million in 2003 to NOK 9,752 million
in 2004 as a result of higher production levels. Total
exploration costs including appraisal costs of discoveries
amounted to NOK 1,264 million in 2004 compared to NOK 1,577
million in 2003 and NOK 3,558 million in 2002 for the reasons
described above. Capitalized exploration well costs amounted to
NOK 397 million in 2004 compared to NOK 121 million in 2003 and
NOK 429 million in 2002. Expenditures relating to exploration
activity in 2004 were NOK 1,412 million, compared to NOK 1,609
million in 2003 and NOK 2,376 million in 2002. Roughly 66
percent of the exploration activity related to areas outside
the NCS compared to about 73 percent in 2003. International
exploration activities in 2004 occurred mainly in Angola,
Canada, Iran and the Gulf of Mexico. Out of a total of 17
exploration wells drilled and completed during 2004, 11
discoveries were made. One discovery was made in Gulf of
Mexico, one in Angola, 7 in Libya and 2 discoveries were made
in Norway. Hydro also participated in drilling activity in
connection with producing wells that resulted in three
additional commercial discoveries on the NCS. In addition,
three wells were in the process of being drilled at the end of
2004. Of total exploration costs, NOK 1,016 million was
expensed relating to exploration activities in 2004, including
about NOK 183 million related to unsuccessful efforts in
Angola, Canada and Norway
and NOK 248 million was expensed relating to costs
capitalized in previous years. For information pertaining to
accounting for exploration costs please see Oil and Gas
Exploration Costs in Hydros Critical 87




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##### 



Accounting Policies below. See also Note 1, of the Consolidated
Financial Statements for additional disclosure information proposed
by the Financial Accounting Standards Board relating to suspended
well costs. Hydro does not expect any changes in amounts
capitalized as a result of the proposed amendment to Statement of
Financial Accounting Standard No. 19. Operating Income Operating income in 2004 was NOK 28,363 million, a 53 percent
increase from the previous year. As discussed above the main reasons
underlying the increase were higher oil and gas prices, higher
production volumes and lower exploration costs. Operating income
increased 41 percent in 2003 compared to 2002 primarily driven by
higher volumes and a substantially lower level of exploration costs. Adjusted EBITDA Adjusted EBITDA in 2004 amounted to NOK 38,168 million, an
increase of NOK 10,544 million compared to 2003. Adjusted
EBITDA increased 28 percent in 2003 compared to 2002. Energy and Oil Marketing Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    60,788
    
    
    
    49,370
    
    
    
    45,915Operating Costs
    
    
    58,138
    
    
    
    46,702
    
    
    
    43,131Operating Income
    
    
    2,650
    
    
    
    2,668
    
    
    
    2,784Adjusted EBITDA
    
    
    3,478
    
    
    
    4,226
    
    
    
    3,721Number of employees
    
    
    706
    
    
    
    665
    
    
    
    667
 Energy and Oil Marketing includes Hydros commercial operations
in the oil, natural gas and power sectors, the gas transportation
operations and the operation of Hydros power stations in Norway.
Energy and Oil Marketing markets and sells refined petroleum
products (gasoline, diesel and heating oil) to customers in Scandinavia
and the Baltic countries. Hydro owns 100 percent of the
operating unit in Sweden and 50 percent of Hydro Texaco, an oil
marketing company with retail outlets in Norway, Denmark and the
Baltic countries. Energy and Oil Marketing is also responsible for
developing Hydros hydrogen and renewable energy business
activities such as wind power. Except for the operation of Hydros own power stations, gas
infrastructure activities and development activities, Energy and Oil
Marketings business mainly consists of margin-based sales and
trading activities. As a result, operating revenues and costs in any
given year are largely a function of volume traded and the level of
prevailing market prices for crude oil, natural gas and electricity. As
part of the commercial operations in the oil, natural gas and power
sectors, Energy and Oil Marketing enters into both short term and
long term buying and selling contracts. Many of the contracts are
valued at market price at reporting period ended. Some of the
power and gas contracts may have several years of duration. The
market value is calculated based on forward prices, and changes
in forward prices may therefore affect the operating income in
Energy and Oil Marketing. Market Conditions As described under the section Market Conditions for the Exploration
and Production sub-segment, the price level for oil, oil products
and gas has been high during 2004 and higher than in 2003. Nordic electricity prices have been lower in 2004 than last year.
Average spot prices for 2004 were NOK 0.24 per kWh, compared
to NOK 0.29 per kWh in the prior year and NOK 0.20 kWh in
2002. The decline in prices reflected reservoir levels approaching
almost normal levels at the end of 2004. Water reservoir levels in
Norway and Sweden were close to normal by the end of 2004,
and considerably higher than in 2003. The forward prices for gas for 2005 and onwards have
increased since the end of 2003, but the forward prices have been
very volatile during 2004. Operating Revenue Energy and Oil Marketings operating revenues for
2004 were NOK 60,788 million, up NOK 11,418 million or 23
percent from the prior year. Operating revenues were
relatively unchanged in 2003 compared to 2002. Power
production in 2004 was 8.1 TWh compared with 7.5 TWh in 2003
and 10.3 TWh in 2002. The fluctuations in power production
resulted from changes in reservoir levels due to variation in
weather conditions.      In 2004, internal sales to other business
areas within Hydro amounted to NOK 6,159 million. Internal
sales in 2003 were NOK 5,062 million and NOK 3,986 in 2002.
All internal sales are at market prices. Operating costs Energy and Oil Marketings operating costs of NOK 58,138
million in 2004 were 24 percent higher than the prior year.
Operating costs increased about 8 percent in 2003 compared to
2002. As described above, Energy and Oil Marketings operating
costs are mainly comprised of purchases of crude oil, natural
gas and electricity. Operating cost also includes process
costs relating to the operations of power stations, the gas
infrastructure and other fixed costs. There were no
substantial changes in these fixed costs in 2004 compared to
the previous year. Operating income Energy and Oil Marketings operating income in 2004 was
NOK 2,650 million, almost the same level as the operating
income of NOK 2,668 million in 2003. Operating income was
somewhat higher in 2002. Increased power production and
unrealized gains relating to market value adjustments on gas
and power contracts had a positive effect on operating income
in 2004, while the loss of refinery income following the sale
of the Scanraff refinery in December 2003 had a negative
impact on income from operations. Operating income (in NOK million)
    
    2004
    
    
    2003
    
    
    2002Power activities
    
    
    732
    
    
    
    664
    
    
    
    1,184Gas activities
    
    
    1,833
    
    
    
    1,795
    
    
    
    1,255Oil trading activities
    
    
    188
    
    
    
    406
    
    
    
    388Oil marketing
    
    
    104
    
    
    
    (16
    )
    
    
    68Other 1)
    
    
    (207
    )
    
    
    (181
    )
    
    
    (111
    )Operating income
    
    
    2,650
    
    
    
    2,668
    
    
    
    2,784
   1)
    
    Other mainly consists of new energy activities Operating income from power activities was NOK 732
million in 2004, up NOK 68 million or 10 percent from the
prior year. The increase in operating income resulted
primarily from higher power production. Energy and Oil
Marketing secures electricity in the market for Hydros own
consumption, and to exploit commercial opportunities in the
external market. The new Tyin hydropower plant in Sogn in
Norway commenced commercial production in the beginning of
October 2004. The project was completed according to plan and
below original cost estimates and resulted in an increase of
15 percent compared to the earlier production capacity 88




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##### 



at the
site. The decline in operating income from power activities in
2003, compared to 2002, resulted from lower production offset
somewhat by higher prices. Operating income from gas
activities was NOK 1,833 million in 2004, slightly higher than
the previous year. Gas activities consist of gas
transportation and gas trading activities. Operating income
for gas transportation has been relatively stable during the
year amounting to NOK 1,496 million in 2004 compared to NOK
1,525 million in 2003. Operating income for gas trading
activities has been very volatile during 2004. During the
fourth quarter of 2004, forward price developments resulted in
substantial unrealized gains on contracts for future
deliveries, which are valued at market prices at the end of
the quarter. The magnitude of the unrealized gains and losses
for the year has been influenced by
exceptionally large geographic price differentials and spreads
on various gas contract indices. Operating income from gas
activities increased 43 percent in 2003 compared to 2002.
Approximately NOK 350 million of the increase related to gas
transportation and was mainly due to lower depreciation
charges resulting from the extension of license periods for a
number of gas pipelines following the establishment of Gassled
in January of 2003. Operating income from oil trading activities was NOK 188
million in 2004, a decrease of 54 percent from the prior year.
The decline resulted primarily from the divestment of
Skandinaviska Raffinaderi AB, the Scanraff oil refinery, in
the fourth quarter of 2003. The activities include crude oil
trading, gas liquids trading and shipping.  Operating income
from oil trading activities increased slightly 2003 compared
to 2002. Operating income for Oil Marketing amounted to NOK
104 million, compared to an operating loss of NOK 16 million
in 2003 and operating income of NOK 68 million in 2002. The
improved result for 2004 primarily resulted from inventory
gains, compared to inventory losses in the previous year. Adjusted EBITDA Adjusted EBITDA for 2004 was NOK 3,478 million, a
decrease of 18 percent compared to the prior year. In 2003,
adjusted EBITDA was 14 percent higher than 2002. In the fourth
quarter of 2003, Hydro sold its interest in Skandinaviska
Raffinaderi AB, Scanraff, recognizing a gain of NOK 490
million. The sale agreement included the possibility of a
price adjustment depending on the development in refinery
margins during 2004 and 2005. High refinery margins during
2004 have resulted in an additional gain of NOK 59 million
being recognized in the fourth quarter of 2004. In addition,
Hydro transferred its interest in Sundsfjord Kraft ANS in
return for 20.2 percent of the shares of SKS Produksjon AS
resulting in a gain of NOK 326 million reflected in the EBITDA
in 2003. Adjusted EBITDA also included Hydros share of net
income from Hydro Texaco of NOK 39 million in 2004, a decrease
of 78 million compared to last year. The result from Hydro
Texaco was negatively impacted by intense gasoline price
competition in Denmark. (BAR CHART) Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    79,674
    
    
    
    69,152
    
    
    
    65,051Operating Costs
    
    
    77,869
    
    
    
    66,696
    
    
    
    63,353Operating Income
    
    
    1,805
    
    
    
    2,456
    
    
    
    1,698Adjusted EBITDA
    
    
    8,656
    
    

    
    6,498
    
    
    
    4,334RoaCE 1)
    
    
    3.5
    %
    
    
    4.7
    %
    
    
    2.7
    %Number of employees
    
    
    25,967
    
    
    
    26,728
    
    
    
    27,110
   1)
    
    RoaCE for 2004 was negatively affected by the write down of the primary
metal plants in Germany by 3.5 percent. Overview Hydro Aluminium is one of the worlds largest
integrated global aluminium suppliers in terms of sales
volume with activities in 28 countries, 2004 revenues of
approximately NOK 80 billion and around 26,000 employees. The
company is an industry leader for a range of products and
markets, in particular deliveries to the transportation,
building, packaging and lithographic market sectors. In 2004
Hydro Aluminium produced approximately 1.7 million tonnes of
primary metal. A total of 3.4 million tonnes was delivered to
the market. Hydros Aluminium business is integrated from the
alumina to finished products. The Company has ownership
interests in alumina refineries providing approximately 45
percent of its alumina requirements. The remaining needs are
covered through medium to long-term contracts. Virgin primary
aluminium is produced in Australia, Canada, Norway, Germany
and Slovakia. In addition, Hydro has developed a
multi-sourcing strategy with a focus on building strong market
positions in the metal products market (extrusion billet,
sheet ingot and product foundry alloys), the mid-stream part
of the value chain. Aluminium is further
processed to meet customers needs in casthouses
integrated with the Companys primary aluminium plants and in
specialized remelters located close to customers in Europe and
the US. Components for the automotive industry are produced in
several countries in Europe as well as in the US, Mexico,
Brazil and China. Through a global extrusion system Hydro
serves customers with tailor made profiles and building
systems. Hydro Aluminium also produces aluminium strip, sheet
and foil in rolling mills located in Europe and Malaysia. During 2004 there has been a continued increase in the worlds
consumption of aluminium, most notably in China. Western world
shipments grew an estimated 7.5 percent while consumption in 89




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##### 



China increased an estimated 17 percent. China
increased its net primary exports to the Western World by an
estimated 300,000 tonnes in 2004 to a total of about 650,000
tonnes. This development was apparently enhanced by an
announcement of the abolition of the eight percent export
subsidy from year-end, which was replaced by a five percent
export tax. However, with scrap, semi-fabricated and other
aluminium products taken into account, China imported an
estimated 350,000 tonnes of aluminium on a net basis in 2004. Market prices increased during the year by 20 percent
(LME three months average). Volume increases made possible by
expanded capacity combined with the higher prices made a solid
contribution to Hydros results for the year. However, the
depreciation of the US dollar offset more than half of the
aluminium price increase measured in Norwegian kroner. In
addition, the soft dollar weakened the competitiveness of
Aluminiums European operations. Increasing energy costs
combined with the decline in the dollar led to a write-down of
Hydros German primary aluminium plants by approximately NOK
2.3 billion in December of 2004. The write down impacted
operating income by roughly NOK 2.0 billion and results from
Non-consolidated investees by about NOK 0.3 billion. Results for Hydro Aluminiums downstream operations
improved significantly in 2004. Market developments resulted
in increased volumes, however, margins are under continuous
pressure particularly for the more standardized products. To boost the Companys competitive position, Hydro
Aluminiums strategy is to continuously improve the relative
cost position of its primary metal production. To execute this
strategy, Hydro is focused on increasing the share of its
production being produced in larger primary metal plants
located in regions with competitive energy costs. Expansions
of primary production are completed or underway in plants
where existing infrastructure supports a larger capacity.
Hydro is in the initial phase of planning a major new
greenfield project in Qatar which has abundant energy
resources in the form of natural gas. Hydro has also taken
steps to improve its relative cost position of alumina, the
primary raw material for aluminium. Hydro has a history of improvement programs generating substantial cost reductions.
Improvement programs completed in 2003 are generating
estimated annual cost reductions of NOK 2.5 billion. Further
programs were initiated in 2004, and cost reduction activities
are expected to continue into 2005 and beyond. Summary of Aluminiums operating results Aluminiums operating income for 2004 was NOK 1,805
million compared to NOK 2,456 million in the prior year and
NOK 1,698 in 2002. The lower result in 2004 was due to the
write down of German primary metal plants of NOK 2,042 million
and costs relating to manning reductions amounting to NOK 519
million. Positive contribution from increased volumes and
higher prices offset a large part of the negative effects. The change in 2004 operating income compared to the prior year and
the most important items affecting the change are included in
the table below: Amounts in NOK millionOperating income 2004
    
    
    1,805Operating income 2003
    
    
    2,456Change in Operating Income
    
    
    (651
    )Margin
    
    
    980Volume
    
    
    2,295Fixed costs
    
    
    (835
    )Depreciation
    
    
    (325
    )Write downs, demanning, other
    
    
    (2,650
    )Trading
    
    
    (560
    )Unrealized LME-effects
    
    
    230New/disposed business
    
    
    305Restructuring costs
    
    
    20Other
    
    
    (111
    )Total change in Operating income
    
    
    (651
    )
 Margins, excluding the effect of hedge programs, were
higher and positively impacted operating results by
approximately NOK 980 million compared with 2003. Margins
improved for the Metals, Rolled Products and Extrusion but
were slightly weaker for Automotive. During 2004, aluminium
prices measured in Norwegian kroner increased by slightly more than nine percent compared
with 2003 as a result of the increased LME price but with a
lower average US dollar to NOK exchange rate. In 2003,
aluminium prices measured in Norwegian kroner declined
somewhat more than 7 percent due to the fluctuating US dollar
exchange rate. Realized gains on hedge programs in Metals
declined by NOK 203 million from NOK 476 million in 2003. In
2002, realized gains related to hedge programs amounted to NOK
153 million. Higher volumes contributed an additional NOK
2,295 million to operating income compared to 2003. Volumes
increased for all sub-segments. The ramp up of new capacity in
all sectors and increased capacity utilization were the main
factors underlying the improvement. Volumes increases in 2003
relating to all sectors except North America, contributed NOK
860 million to operating income compared to 2002. New production capacity was a significant reason for the increase
in fixed costs and depreciation. In addition, fixed costs
measured in NOK for European subsidiaries were negatively
impacted by a stronger Euro/NOK exchange rate. However, for
operating income as a whole this currency translation effect
was positive by about NOK 75 million. Total fixed costs and
depreciation increased in 2003 compared to 2002 primarily as a
result of new production capacity as well as translation
effects resulting from a stronger Euro/NOK exchange rate. Write downs, demanning and other consisted primarily of the
impairment loss on the German primary metal plants of NOK
2,042 million and manning reduction costs related to the
Aluimprover project, together with charges for the transfer of
employees relating to magnesium operations, in total amounting
NOK 519 million. Metals results of trading activities were lower mainly
due to reduced currency gains impacting operating income by
NOK 350 million. Results for Metals trading activities
improved by approximately NOK 460 million in 2003 compared to
2002 mainly due to currency gains. The currency effects
impacting results for trading activities are largely offset by
currency gains and losses on forward currency contracts
reported in financial items. The variance relating to new/disposed business relates
primarily to the effect on operating income resulting from
the consolidation of Slovalco. See Hydros Critical
Accounting Policies  Change in Accounting Principles -
Consolidation of Variable Interest Entities 90




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##### 



in this Financial Review for further information pertaining to the
consolidation of Slovalco. Adjusted EBITDA for 2004 was NOK 2,158 million higher
than in the previous year largely due to positive factors
underlying the developments in operating results for the year,
but excluding the non-cash effects of the write downs and
charges described above. Results for non-consolidated
investees decreased by NOK 52 million primarily due to the
write down of NOK 268 million of the share in Hamburger
Aluminium-Werke GmbH where Hydro holds a 33.33 percent
interest. Results from non-consolidated investees included
unrealized currency gains on US dollar denominated loans held
by Alunorte, of NOK 63 million for 2004 compared to NOK 218
million for 2003. The remaining variance in results from
non-consolidated investees resulted from improved operating
results relating to Søral, Alunorte and other investees.
Adjusted EBITDA increased in 2003 compared to 2002 as a result
of the inclusion of VAW and Technal in the first quarter of
2003, and unrealized currency gains of NOK 218 million
relating to Alunorte compared to unrealized losses of NOK 461
million in 2002. During the first quarter of 2002, Hydro
acquired VAW Aluminium AG (VAW) and the French building
systems company, Technal. Hydros consolidated results include
the operating results of VAW as of 15 March 2002 and Technal,
as of 26 January 2002. The effect or variance resulting from
the inclusion of VAW and Technal for a full year in 2003
compared to less than a full year in 2002 is described in the
discussion on Operating revenues, Operating costs and
Operating income below. Key development projects and other activities In December of 2004, Hydro signed Heads of Agreement
with Qatar Petroleum to evaluate the development of a 570,000
tonnes capacity aluminium plant in Qatar with approximately 49
percent Hydro participation. If realized, the project will
consist of power generation, primary aluminium production and
anode production, as well as a casthouse producing value added
aluminium metal products. The plant site is suitable for more
than doubling of the initial primary aluminium production
capacity, up to 1.2 million tonnes per year. The expansion of the aluminium plant at Sunndal, Norway,
has been completed with full production achieved during 2004.
The expansion has more than doubled capacity to 360,000
tonnes. Amperage exceeding design by ten percent was achieved,
resulting in 20,000 additional tonnes of primary capacity per
year at only incremental operating cost and no additional
investment cost. In addition, an accelerated startup resulted in 18,000 additional tonnes
for 2004. The total investment amount is expected to be NOK
150  200 million lower than originally budgeted. The
expansion project in Alouette, Canada, in which Hydro has a
20 percent ownership, is progressing well. The first phase
commenced production in December, two months ahead of plan. Hydro Aluminiums major alumina investment is its 34 percent
participation in Alunorte, a Brazilian alumina refinery. In
2003, Hydro decided to participate in a further expansion of
Alunorte. This planned expansion will increase capacity to
approximately 4.2 million tonnes in 2006, providing Hydro
Aluminium with a total of approximately 1.4 million tonnes of
alumina annually. Hydro Aluminium believes that Alunortes
cash operating costs are significantly below the alumina
industrys world average. Hydro Aluminium also has a 35
percent equity interest in the Alpart alumina refinery in
Jamaica, which has an annual production capacity of
approximately 1.5 million tonnes. The remaining 65 percent was
owned by Kaiser Aluminium. As part of bankruptcy proceedings,
Kaiser initiated a process to dispose of its interest in
Alpart. In May of 2004, Hydro decided to exercise its right of
first refusal to acquire the 65 percent interest and then
transferred the interest to Swiss-based Glencore AG. No gain
or loss resulted from the transaction. Hydro expects the
new ownership arrangement will result in improved operations
and potential cost synergies. In 2004, Hydro sold its German
based alumina business for approximately NOK 700 million.
The operations sold consisted of a 50 percent share in
Aluminium Oxid Stade GmbH (AOS), the related chemical grade
alumina business and the dedicated bauxite source represented
by Hydros 10 percent share in Halco (Mining) Inc. AOS was
sold primarily because the chemical grade alumina is not used
in Hydro Aluminiums production process. The sale did not
result in any significant gain or loss. Outlook Economic indicators are signaling lower global growth
in 2005 compared to 2004, but growth is expected to continue at a
healthy level. Economic development in the US is expected to slow,
but from a high level in 2004. Conditions in Europe are expected
to remain fairly stable, while the major Asian economies are
forecast to show a somewhat reduced growth in activity level. Hydro expects Western World shipments of primary aluminium to
increase about three percent, equivalent to 600,000  700,000
tonnes in 2005 compared to 2004. Western World production, including closures and restarts, is expected to increase by
800,000  900,000 tonnes in 2005. Through 2004 and into 2005, LME
prices have increased significantly, and some idle capacity in the

US North West has been restarted. If LME prices remain at levels
experienced early in 2005, or increase, some additional restart of
idle capacity in this region may take place. Chinese export
subsidies for primary aluminium have been replaced by an export
tax effective 1 January 2005. As a result, incentives for
developing new aluminium capacity for export have been reduced.
The global market for primary aluminium is expected to remain
favorable in 2005, with inventory reductions possibly of the same
magnitude as in 2004. In 2004, there has been a tight supply
relative to demand for alumina which has resulted in a substantial
increase in alumina prices in the spot market. For 2005 the prices
are expected to stay at a fairly high level. In addition,
electricity prices in the North Western US are expected to remain
relatively high. According to CRU International Ltd. (CRU),
consumption of flat rolled products, extruded and automotive
products is expected to continue to grow compared to 2004. Growth
projections for 2005 vary by product and market, but are in the
range of 3-3.5 percent in the US and Western Europe. Hydros Board
of Directors approved the Aluimprover manning and cost reduction
program relating to the Companys Norwegian primary metal plants
in May 2004. The program has targeted annual cost savings of NOK
350-400 million, equivalent to approximately 800 man-years. All
cost reduction initiatives related to the project are expected to
be concluded by the end of the first quarter of 2005. Total
implementation costs of the program are expected to be NOK 600
million, which is NOK 200 million lower than initial cost
estimates. Of this amount, NOK 432 million was charged to results
in 2004. Approximately NOK 170 million is expected to be charged
in 2005. Due to environmental legislation, Hydro will close the Søderberg
production lines at the Companys Høyanger and Årdal primary
metal plants in Norway. Total related costs are estimated at NOK
300  350 million and are expected to be incurred at the latest by
the end of 2006. Hydro is working actively with business development
projects in Årdal and Høyanger in order to facilitate job creation
in these areas, and ultimately to assist affected employees in 91




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##### 



their search for new employment. New, lower cost capacity coming
on stream resulting from the expansions described above will
replace the production at these primary metal plants. As a result of low volume and declining profitability, a decision
was made in June 2004 to close Hydro Aluminium Motorcast Ltd.
located in Leeds, UK, in early 2005. Costs relating to the closure
impacted operating income by NOK 147 million in 2004. Estimated
remaining charges relating to the closure of around NOK 135 million
are expected to be recorded in 2005. Metals Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    49,159
    
    
    
    39,923
    
    
    
    39,646Operating Costs
    
    
    48,329
    
    
    
    37,630
    
    
    
    37,956Operating Income
    
    
    830
    
    
    
    2,293
    
    
    
    1,690Adjusted EBITDA
    
    
    5,396
    
    
    
    4,298
    
    
    
    2,703Number of employees
    
    
    6,161
    
    
    
    6,276
    
    
    
    6,284
 Market conditions Western World shipments of primary metal grew an
estimated 7.5 percent for 2004 compared to the prior year.
Chinas internal consumption continued to grow rapidly in 2004
with an estimated increase of about 17 percent. China
increased its net primary exports to the Western World by an
estimated 300,000 tonnes in 2004 to a total of about 650,000
tonnes. This development was apparently triggered by an
announcement of the abolition of the eight percent export
subsidy from the end of 2004, which was replaced by a five
percent export tax. However, with scrap, semi-fabricated and
other aluminium products taken into account, China imported an
estimated 350,000 tonnes of aluminium on a net basis in 2004. Western World production increased approximately 3.5 percent,
or 480,000 tonnes, as a result of new capacity net of
closures. Reported inventories, including producers
inventories (reported from the International Aluminium
Institute) and LME inventories, declined by about 20 percent,
or approximately 700,000 tonnes, during 2004. Roughly 200,000
tonnes are believed to be offset by an increase in unreported
inventories within the new European Union member states,
countries acceding 1 May 2004. The average market price for
aluminium (LME three months average) was USD 1,721 per tonne
for 2004, an increase of 20 percent. Revenues Operating revenues increased approximately 23 percent or NOK 9 billion. The increase
reflected the higher realized prices measured in Norwegian kroner combined with higher volumes.
Operating revenues declined approximately 10 percent in 2003 compared to 2002, (which was offset by
the variance relating to VAW in the first quarter of the year), primarily as a result of lower
realized aluminium prices measured in Norwegian kroner. Volumes for Hydro Aluminiums primary
metal increased 17 percent to a total of 1,720,000 tonnes in 2004 from 1,473,000 tonnes in 2003.
The increase in primary metal volumes included new capacity relating to the Sunndal expansion of
approximately 94,000 tonnes as well as about 130,000 tonnes relating to the consolidation of
Slovalco. The remaining increase resulted from smaller expansions and better capacity utilization.
New commercial contracts also influenced total sales volumes for 2004. Primary metal volumes
increased 18 percent in 2003 compared to 2002 as a result of the inclusion of VAW for the first
quarter of 2003 as well as new capacity from Sunndal. Hydro realized average aluminium prices of US
dollar 1,638 per tonne for 2004 compared to USD 1,440 per tonne for the same period of 2003.
Measured in Norwegian kroner the realized aluminium price increased by slightly over nine percent.
The realized NOK to US dollar exchange rate was NOK 6.98 for 2004 compared to NOK 7.25 in 2003. The
realized price includes the effect of hedges. Realized effects of the Sunndal hedge programs
3), which are comprised of LME future contracts and US dollar forward contracts,
positively impacted the results by about NOK 273 million in 2004 compared to NOK 476 million in
2003. Product premiums increased both in USD and in Norwegian kroner in 2004. For 2003, product
premiums increased in US dollars but to a lesser extent measured in Norwegian kroner.   3)
    Both the LME and currency hedges related to the Sunndal
program are designated as cash flow hedges against
production. Changes in the fair value of the contracts
are included in Other Comprehensive Income while the
realized amounts are included in revenues. In addition,
Metals economically hedges certain revenues and raw
materials in terms of LME prices with the purpose of
locking in margins on such transactions. These
positions referred to as price hedges are not designated
for hedge accounting. Realized aluminium price hedges are
included in revenues or raw material costs while
unrealized effects are included at the Hydro Aluminium
level under Other and eliminations. Related currency
effects are classified as financial items and excluded
from operating income. Price hedges are excluded from the
numbers for the hedge programs disclosed above. Operating costs Operating costs increased by NOK 10,699 million in 2004,
mainly due to higher volumes from new capacity. However, the
increase also included NOK 519 million relating to the manning
reduction described above, and the write down of the German
smelters of NOK 2,042 million. The strengthening of the Euro
to the US dollar has placed European aluminium producers at a
cost disadvantage in the global aluminium market. In addition,
the existing power contracts for Hydros German primary
aluminium plants will expire at the end of 2005. Current power
prices in Germany are significantly higher than in 2002, when
these plants were acquired. At the time of acquisition Hydro
anticipated a significant increase in future power costs.
However, based on ongoing negotiations for renewal of the
contracts, expected costs are now higher than earlier
estimates. As a result, the Company recognized an impairment
loss relating to its German primary aluminium plants in
December of 2004. The write down impacted operating income by
roughly NOK 2.0 billion and results from Non-consolidated
investees by about NOK 0.3 billion. Operating costs in 2003
were relatively unchanged compared to 2002, however, a decline
in operating costs was offset by the effect of VAW in the
first quarter of 2003. Operating income Operating income for 2004 amounted to NOK 830
million compared to NOK 2,293 million in the prior year and
NOK 1,690 million in 2002. Higher margins resulting from the
price and currency developments in 2004 contributed about
NOK 635 million compared with 2003. Higher volumes
contributed NOK 1.9 billion. However, the positive
developments were offset by the increased fixed costs,
depreciation and write-downs as described above. In
addition, results for Sourcing and Trading activities
declined NOK 350 million mainly as a result of reduced
currency gains. Realized effects of hedge programs declined
NOK 200 million compared to 2003. Operating income in 2003
was negatively impacted by lower margins in the amount of
NOK 760 million, offset by positive effects 92




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##### 



from hedge
programs amounting to NOK 323 million and higher trading
results of NOK 460 million. Adjusted EBITDA Adjusted EBITDA for 2004 was NOK 5,396 million, an
increase of NOK 1,098 million compared to 2003. The increase
in 2004 was largely due to the positive factors underlying the
developments in operating results for the year, but excluding
the non-cash effects of the write-downs and charges described
above. In addition, better results from non-consolidated
investees also contributed to the improvement. Adjusted EBITDA
amounted to NOK 4,298 million in 2003, an increase of NOK
1,595 million compared to 2002. Rolled Products Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    20,373
    
    
    
    18,377
    
    
    
    14,790Operating Costs
    
    
    19,747
    
    
    
    18,245
    
    
    
    15,085Operating Income
    
    
    626
    
    
    
    132
    
    
    
    (295
    )Adjusted EBITDA
    
    
    1,361
    
    
    
    835
    
    
    
    258Number of employees
    
    
    4,013
    
    
    
    4,259
    
    
    
    4,306
 Market conditions Consumption of flat rolled products in Europe
increased by an estimated (CRU International) two percent
compared to 2003. Average capacity utilization for the
European industry improved marginally but remained relatively
low at an estimated 84 percent. The North American market had
an increase in consumption of about seven percent for the year
as a whole compared to 2003. Capacity utilization for the US
industry improved about seven percent to an estimated 79
percent. The stronger Euro compared to the US dollar placed a
disadvantage on producers outside the US for export sales. The
Euro/US dollar exchange rate impacted export pricing of flat
rolled products to Asia, South and North America, which are
typically based on a US dollar price formula and put pressure
on margins. Foil and lithographic sheet are higher margin
products. Automotive flat rolled products are important to the
industry as these products are expected to have attractive
growth rates. Many flat rolled products are relatively mature
in European and North American markets. Revenues Operating revenues increased approximately 10 percent or
about NOK 2,000 million in 2004 compared to the previous year.
The increase was mainly due to the higher volumes and higher
metal prices partly offset by the effect of lower Euro revenues
relating to US dollar denominated export sales. Rolled Products
exports about 21 percent of its sales to Asia, South and North
America. The Euro strengthened 10 percent to the US dollar in
2004. Operating revenues increased approximately 24 percent in
2003 compared to 2002. Operating revenues increased by about 3
percent in addition to increases relating to the VAW effect. Shipments increased around five percent to 941,000 tonnes in
2004 and about seven percent to 893,000 tonnes in 2003
including comparable VAW figures on an annual basis. The total
growth in shipments for 2004 over 2003 was distributed between
Hydros product groups as follows: lithographic sheet (15
percent), foil (7 percent) and strip (2 percent). Rolled
Products activities are primarily denominated in Euro. All
sales revenues are hedged in terms of aluminium prices and
foreign currency exchange rates utilizing commodity and
financial instruments. Realized gains related to aluminium
price hedges are included in revenues while currency effects
are included in financial items. Unrealized effects of
aluminium price hedges are included as part of Other and
Eliminations at the Hydro Aluminium consolidation level. Operating costs Rolled Products operating cost increased in 2004 and
2003 (in addition to the effect of VAW) primarily as a result
of increased volumes. Higher metal prices also impacted
operating costs in 2004. Operating costs were positively
influenced by inventory gains of approximately NOK 155 million
in 2004 compared with inventory losses of approximately NOK 117
million in 2003. Rolled Products sales prices are based on a
margin over the metal price. The production process requires a
lead-time of between two to three months. Therefore, cost of
goods sold (and margins) is impacted by variances in inventory
values resulting from changing aluminium prices. Falling prices
in Euro increase cost (reduce margins) while increasing prices
have the opposite effect. Operating costs also increased as a
result of currency translation effects resulting from the
stronger Euro/NOK exchange rate amounting to about NOK 230
million. Savings from improvement programs offset this increase
by about NOK 100 million. Operating income Operating income for 2004 was NOK 626 million
compared to NOK 132 million in the previous year and an
operating loss of NOK 295 million in 2002. Higher contribution
from margins impacted the results for 2004 by approximately NOK
285 million compared with 2003. The change in the margin
primarily resulted from the inventory gains described above. In
addition, a positive translation effect from the stronger Euro
contributed around NOK 250 million but was offset by lower
margins as a result of the declining US dollar by about the
same amount. Increased shipments contributed around NOK 260
million to results. Rolled Products operating income in 2004
was distributed between the product groups as follows: Litho 32
percent, Foil 22 percent and Strip 46 percent. Adjusted EBITDA Adjusted EBITDA for Rolled Products for 2004 was NOK
1,361 million compared to NOK 835 million for 2003 and NOK 258
million for 2002. The improvement was primarily influenced by
the factors described above. Extrusion and Automotive Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Revenues
    
    
    27,600
    
    
    
    24,529
    
    
    
    24,245Operating Costs
    
    
    27,323
    
    
    
    24,431
    
    
    
    24,231Operating Income
    
    
    277
    
    
    
    98
    
    
    
    14Adjusted EBITDA
    
    
    1,827
    
    
    
    1,432
    
    
    
    1,084Number of employees
    
    
    15,793
    
    
    
    16,193
    
    
    
    16,520
 Market conditions The overall market for general extrusion in Europe
improved during the first three quarters of 2004, but slowed
markedly in the fourth quarter. According to CRU, general
extrusion shipments increased by about four percent in 2004
compared to 2003. Hydros ship- 93




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##### 



ments of general extrusions
grew at a rate higher than market average in 2004, about seven
percent. For extruded products in North America, CRU reported
a growth rate in 2004 of about eleven percent. The market
showed signs of slowing towards year end. Global light vehicle
sales were reported to be approximately 3.6 percent higher
than in 2003. Western European and North American automotive
markets, which are the most relevant to Hydro, lagged behind
the global growth averages with an increase in light vehicle
sales of 2.2 and 1.5 percent, respectively. Revenues Revenues increased about 13 percent or NOK 3,071
million in 2004 compared to the previous year. A decline in
revenues of about NOK 700 million or 3 percent in 2003 was
more than offset by the effects of the VAW and Technal
building systems acquisitions in 2002. Automotive revenues and
sales volumes increased in 2004 compared to 2003, principally
due to the ramp up of shipments on new contracts. Higher
volumes offset lower revenues resulting from price pressure on
motor block castings and crash management systems
although margins were negatively affected. Extrusions
revenues increased by around eleven percent. Both European
extrusion and Building systems shipments were higher. Revenues
increased for both Extrusion and Automotive as a result of
translation effects relating to the stronger Euro/NOK exchange
rate. In North America, revenues increased significantly as a
result of increased shipment volumes relating to extrusion and
remelt activities following production capacity increases. Operating costs Operating costs increased by NOK 2,892 million in
2004, primarily due to higher activity levels in all sectors
resulting in increased volumes. The increases were partly
offset by cost reductions from improvement programs.
Depreciation expense increased due to start up of new
automotive production lines and North American remelt
operations. The increase in operating costs also reflected
write downs of NOK 125 million relating to Automotive plants
in addition to the costs relating to the closure of Hydro
Aluminium Motorcast Ltd in Leeds amounting to NOK 147 million
in 2004. A small decline in operating costs in 2003 compared
to 2002, primarily resulting from currency translation
effects, was offset by the effects of VAW and Technal. Operating income Operating income for 2004 was NOK 277 million
compared to NOK 98 million in the prior year and NOK 14
million in 2002. Operating income (loss) for the three sectors
included in Extrusion and Automotive for the three years
ending 31 December 2004 is included in the following table: Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Extrusion
    
    
    634
    
    
    
    500
    
    
    
    399Automotive
    
    
    (314
    )
    
    
    (192
    )
    
    
    (94
    )North America
    
    
    (35
    )
    
    
    (211
    )
    
    
    (291
    )Eliminations
    
    
    (8
    )
    
    
    
    
    
    
    Total
    
    
    277
    
    
    
    98
    
    
    
    14
 Slightly higher margins contributed about NOK 152 million to
the result in 2004 and improved volumes contributed about NOK
1,000 million. The positive effects were partly offset by the
higher fixed costs and depreciation expense discussed above.
Operating income was also negatively impacted by translation
effects in the amount of around NOK 65 million. Operating
income was stable in 2003 compared to 2002 but improved from
the effects of VAW and Technal acquisitions. In 2004,
operating income for Extrusion, increased as a result of the
currency translation effect on margins, partially offset by
declining margins in local currencies. Results for North
American operations were positively influenced by substantial
improvements in press productivity (nine percent compared to
the previous year), on time delivery and cost control
measures. Automotives operating income declined in 2004 as a
result of costs relating to the Leeds closure and write-downs
relating to plants in China, the US, and the UK described
above. Adjusted EBITDA Adjusted EBITDA for Extrusion and Automotive for 2004
was NOK 1,827 million compared to NOK 1,432 million for 2003
and NOK 1,084 million in 2002. The increase in 2004 was
largely due to the factors underlying the improvements in
operating income excluding the non-cash effects of the
write-downs and charges described above. Other Activities Other activities consists of Polymers (formerly
Petrochemcials), Bio-Mar Holding A/S (formerly Treka AS),
Hydro Business, IS and Production Partners, the Companys
internal service operations, and Industriforsikring, the
Companys captive insurance company. Polymers Operating income for Polymers amounted to NOK 254
million in 2004 while adjusted EBITDA was NOK 774 million, an
increase of NOK 262 million and NOK 373
million respectively compared with last year. The
improvement was mainly due to higher PVC prices, partly offset
by higher raw material costs. Operating income also included
insurance proceeds amounting to NOK 58 million relating to the
explosion at Stenungsund site in Sweden in 2003. The
improvement in adjusted EBITDA also reflected an increase in
results from non-consolidated investees amounting to NOK 88
million, mainly due to better product prices in Asia, which is
the main market for Qatar Vinyl Company. The construction of
the new chlorine plant at Rafnes, which was started in 2003,
is progressing well and within the total estimated investment
cost of NOK 1,000 million. The plant is expected to start
production ahead of schedule in the summer of 2005. In January
2005, Hydro also decided to convert the existing chlorine
plant at Rafnes from diaphragm to membrane technology. The
total cost of the upgrade is expected to be about NOK 700
million, with start-up of production scheduled for 2006. In
June 2004 Noretyl AS, owned 50 percent by Hydro, announced an
expansion of its production of ethylene by 100,000 tonnes. The
expansion is expected to be completed in the second half of
2005 at a total investment cost to Noretyl of approximately
NOK 700 million. These projects are expected to make a strong
contribution to Hydro Polymers competitive position. BioMar Operating income for BioMar amounted to NOK 91
million for 2004, compared to an operating loss of NOK 529
million in 2003. BioMars results improved significantly
compared to 2003, which was impacted by the write down of
goodwill and intangible assets as well as significant losses
on bad debts, in total around NOK 570 million. 94




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##### 



Industriforsikring During the year, Industriforsikring, Hydros captive
insurance company, made provisions of around NOK 230 million
for losses incurred within a mutual insurance pool of which
it is a member. The pool incurred significant damage claims
during the autumn of 2004, which will be covered by the
members of the pool over the coming five years, or upon
withdrawal from the pool. Hydros Critical Accounting Policies Hydros Consolidated Financial Statements and
supplementary information were prepared in accordance with
generally accepted accounting principles in the US (US GAAP).
Note 1 in the Notes to the Consolidated Financial Statements
describes Hydros significant accounting policies. Inherent in
many of the accounting policies is the need for management to
make estimates and judgments in the determination of certain
revenues, expenses, assets, and liabilities. The following
accounting policies represent the more critical areas that
involve a higher degree of judgment and complexity which, in
turn, could materially impact Hydros financial statements if
various assumptions were changed significantly. Hydros senior
management has discussed estimates underlying certain of its
critical accounting policies with its independent auditors. Oil and Gas Exploration Costs Hydro uses the successful efforts method of
accounting for oil and gas exploration and development
costs. All expenditures related to exploration, with the
exception of the costs of drilling exploratory wells,
are charged to expense as incurred. The costs of
drilling exploratory wells are capitalized on the
balance sheet pending determination of whether
commercially producible oil and gas reserves have been
discovered. If the determination is made that a well did
not encounter potentially economic oil and gas
quantities, the well costs are charged to expense. Almost all of our wells capitalized on the balance sheet
at 31 December 2004, 2003 and 2002 are in offshore areas
where a major capital expenditure (e.g., offshore
installation) would be required before production could
begin. In such areas, the economic viability might
depend on the completion of additional exploratory
drilling and the discovery of sufficient commercially
producible reserves. Once the additional exploration
drilling demonstrates that sufficient quantities of
reserves have been discovered, continued capitalization
is dependent on project reviews, which take place
periodically and no less frequently than every quarter,
to ensure that satisfactory progress toward ultimate
development of the reserves
is being achieved. For complicated offshore exploratory
discoveries, it is not unusual to have exploratory well
costs remain suspended on the balance sheet for more
than one year while additional appraisal work on the
potential oil and gas field is performed and regulatory
approvals for development are sought. In all the areas
in which we operate, plans for development are subject
to governmental approval. The wells are transferred to
development when the Plan for Development and Operation
(PDO) has been submitted to the Ministry of Petroleum
and Energy (Norway) or matured to a level corresponding
to a PDO submittal (International). Costs related to
acquisition of exploration rights are allocated to the
relevant geographic areas and are charged to operating
expense if no proved reserves are determined to exist.
If proved reserves are determined to exist, the
acquisition costs are trans- ferred to development cost,
and subsequently amortized to become part of the cost of
the oil and gas produced. A determination that proved reserves do not exist can
result in a reduction of long-term assets and an increase in
operating costs. Each block or area is assessed separately.
The amount of the impact depends on the level of current
drilling activity and the amount of exploration costs
currently capitalized. During 2004, exploration activity
(expenditures) totaled NOK 1,412 million, of which NOK 397
million was capitalized during the year. Including capitalized
exploration costs and acquisition costs from prior periods,
NOK 1,263 million was expensed during the year. At the end of
2004, NOK 1,180 million of such costs were capitalized pending
the evaluation of drilling results and planned development, of
which NOK 213 million related to acquisition costs. In February 2005 the FASB issued a Proposed FASB Staff Position
No FAS 19-a, to provide guidance in the accounting for
exploratory well costs. Paragraph 19 of FASB Statement No. 19,
Financial Accounting and Reporting by Oil and Gas Producing
Companies (FAS 19), requires costs of drilling exploratory
wells to be capitalized pending determination of whether the
well has found proved reserves. Questions have arisen in
practice about the application of this guidance due to changes
in oil- and gas-exploration processes and lifecycles. The
issue is whether there are circumstances that would permit the
continued capitalization of exploratory well costs if reserves
cannot be classified as proved within one year following the
completion of drilling other than when additional exploration
wells are necessary to justify major capital expenditures and
those wells are underway or firmly planned for the near
future. The FSP would amend FAS 19 and allow suspended well
costs to remain capitalized beyond one year from drilling if
certain specific criteria are met, and certain disclosures are
provided. Should the FSP be issued as proposed, Hydro does not
expect any changes to the capitalized amounts. Proved Oil and Gas Reserves Proved reserves are the estimated quantities of crude
oil, natural gas, and natural gas liquids which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under
existing economic and operating conditions. Proved reserves
are related to developed fields (proved developed reserves),
and to undeveloped fields (proved undeveloped reserves). The
estimation of proved reserves is based on technical
evaluations using all available reservoir, well and production
data. Proved reserves do not include volumes after license
expiry or volumes that are not commercially producible with
known technology and prices at year-end. Reserves are revised
upwards or downwards as oil and gas are produced and
additional data become available. Revisions can result from
evaluation of already available geologic, reservoir or
production data, or from new geologic or reservoir data
obtained from wells. Revisions can also include changes
resulting from performance of improved recovery projects,
production facility capacity, significant changes in
development strategy, oil and gas prices or changing
regulatory environment. Proved developed reserves are the
basis for calculating unit-of production depreciation. Future
changes in proved oil and gas reserves can materially impact
unit-of-production rates for depreciation, depletion and
amortization. Downward revisions in reserve estimates can
result in higher per unit depreciation and depletion expense
in future periods. Conversely, upward revisions in reserve
estimates can result in lower future per unit depreciation,
depletion and amortization. Depreciation, depletion and
amortization related to 95




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##### 



oil and gas producing activities in
2004, 2003 and 2002 were NOK 9,825 million, NOK 9,114 million
and NOK 8,553 million respectively. Commodity Instruments and Risk Management Activities Hydros revenues, operating results, financial
condition and ability to borrow funds or obtain additional
capital depend substantially on prevailing commodity prices
for oil, aluminium and the US dollar exchange rate. Volatility
in these commodity prices and currency rates materially affect
Hydros financial condition, liquidity, ability to obtain
financing, and operating results. Depressed prices can have a
negative impact on Hydros financial results. The majority of
Hydros oil and aluminium production is sold at market prices.
To mitigate unwanted price exposure and to protect against
undesirable price developments, Hydro utilizes physical and
financial commodity instruments on a limited basis. Entering
into such positions requires management to make judgments
about market conditions and future price expectations. Certain commodity contracts are deemed to be derivatives under US GAAP
and are required to be recognized at fair value, with changes
in the fair value impacting earnings. Determining whether
contracts qualify as derivative instruments involves
evaluation of market liquidity, traded volumes and
transportation cost for physical products from contract
delivery points to a liquid market for the product. When
market prices are not directly observable through market
quotes, the estimated fair value must be calculated using
valuation models, relying on internal assumptions as well as
observable market information. Such assumptions includes
forward curves, yield curves and interest rates. The use of
models and assumptions are in accordance with prevailing
guidance from the FASB and valuations are based on the
Companys best estimates. However, changes in valuations will
likely occur and such changes may have a material impact on
the estimated fair value of derivative contracts, in
particular long-term contracts, resulting in corresponding
gains and losses affecting future periods income statements.
It is important to note that use of such instruments and other
commodity contracts may preclude or limit Hydros ability to
realize the full benefit of a market improvement. To further
understand Hydros sensitivity to these factors please refer
above to the Indicative income statement sensitivities table
included in the Risk Management section of this Financial
Review. Asset Retirement Obligations Effective 1 January 2003, Hydro adopted SFAS 143,
Accounting for Asset Retirement Obligations which prescribes
the accounting for obligations associated with the retirement
of long-lived assets such as abandonment of oil and gas
production platforms, facilities and pipelines. The fair value
of liabilities for asset retirement is recognized as
liabilities when they are incurred and added to the carrying
amount of the long-lived asset. The effect of the passage of
time on the liability is recognized as an accretion expense,
included in Depreciation, depletion and amortization, and the
costs added to the carrying value of the asset are
subsequently expensed over the assets useful life. Hydros asset retirement obligations consist mainly of accruals for
the dismantlement and removal of oil and gas installations on
the Norwegian Continental Shelf. Norwegian regulations and the
OSPAR convention (convention for the protection of the marine
environment of the north-east Atlantic) regulate which
installations must be disposed of and which can be abandoned.
The OSPAR convention has imposed a general ban on sea disposal
of offshore installations and requires removal and recycling
unless exceptions are made which allow abandonment of specific
installations. The OSPAR convention does not cover pipelines
and cables. Report No. 47 (1999-2000) to Stortinget (the
Norwegian Parliament) on the disposal of pipelines and cables
that have ceased to be used includes general guidelines
permitting such facilities to be left in place if they do not
result in any inconvenience or safety hazards. A termination
and removal plan for each field must be approved by the
Norwegian authorities. The asset retirement obligation is
estimated as the present value of the future expected
dismantlement and removal costs based on an expected
retirement concept and timing and current prices for goods and
services. The timing of retirement activities is normally
assumed to be at the end of production. Retirement activities
relating to most fields where Hydro has an ownership interest
are expected to begin relatively far into the future. There is
substantial uncertainty in the scope and timing of future
termination and removal activities both from the fact that the
activities will take place relatively far into the future, and
because very limited removal activities have occurred on the
NCS in the past. Changes to technology, Norwegian regulations,
prices for necessary goods and services and other factors may
affect the timing and scope of retirement activities. In 2004,
estimates of future asset retirement obligations related to
producing fields were increased by around NOK 560 million. The
major part of the increase was attributable to higher rates
relating to floating rigs used in retirement activities.
Future changes in rig rate levels or other relevant prices may
substantially alter the book value of
property, plant and equipment, asset retirement
obligations and future operating costs. Hydro accounts for
asset retirement obligations that are conditional on a future
event in the period that the conditional event has been
satisfied. In June 2004, the FASB issued an exposure draft
entitled Accounting for Conditional Asset Retirement
Obligations -an interpretation of FASB Statement No. 143,
which would require conditional asset retirement obligations
to be recognized when incurred. Should the exposure draft be
issued as proposed, Hydro would accrue for the removal and
disposal of certain additional assets including lining
material of the cells used in the smelting of aluminium at the
time the lining material is put into use. Currently, these
costs are accrued at the time the lining material is removed. Impairment of Long-Lived Assets Hydro adopted as of January 1, 2002 SFAS 144,
Accounting for Impairment or Disposal of Long-Lived Assets.
Under SFAS 144, management is required to assess the
conditions that could cause an asset to become impaired and to
perform a recoverability test for potentially impaired
long-lived assets held by the Company. These conditions
include whether a significant decrease in the fair value of
the asset(s) has occurred, changes in the Companys business
plan for the asset(s) have been made, or whether a significant
adverse change in the local business and legal climate has
arisen. The amount of such an impairment charge is based on
the estimated fair value of the asset compared to its carrying
value. Fair value measurements include assumptions made
regarding future cash flows associated with the asset under
evaluation. The company uses internal business plans, quoted
forward prices and its best estimate of commodity prices,
currency rates, discount rates and other input. Such estimates
may vary with business cycles and other changes. Impairment charges result in a decrease to Property, Plant and Equipment
on the balance sheet and an increase in operating costs.
Increasing energy costs combined with the decline in the
dollar led to a write-down of Hydros German primary aluminium
plants by approximately NOK 2.3 billion in December of 2004. 96




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##### 



Contingencies and Environmental Liabilities Contingencies and environmental liabilities are recorded
when such items are asserted, or are probable of assertion,
and a loss is probable and can be reasonably estimated.
Evaluation of contingencies requires management to make
assumptions about the probability that contingencies will be
realized and the amount or range of amounts that may
ultimately be incurred. The measurement of environmental
liabilities is based on an evaluation of currently available
facts with respect to each site, and considers factors such as
present laws and regulations, prior experience in remediation
of contaminated material and existing technology.
Environmental liabilities require interpretation of scientific
and legal data, in addition to assumptions about probability
and future costs. The liabilities are reviewed periodically
and adjusted to reflect updated information as it becomes
available. Actual costs to be incurred may vary from the
estimates following the inherent uncertainties in the
evaluation of such exposures. Accruals for contingencies and
environmental liabilities are included in Other current
liabilities and Other long-term liabilities in the balance
sheet. Business Combinations In accounting for the acquisition of businesses, Hydro
is required to determine the fair value of assets,
liabilities, and intangible assets at the time of acquisition.
In the businesses Hydro operates, fair values of individual
assets and liabilities are normally not readily observable in
active markets, which requires the Company to estimate the
fair value of acquired assets and liabilities through
valuation techniques. Such valuations are subject to a number
of assumptions including useful lives of assets, replacement
costs and timing and amounts of certain future cash flows,
which may be dependent of future commodity prices, currency
rates, discount rates and other input. Hydros most recent significant acquisition was the
purchase of VAW for a purchase price of EUR 1,911 million (NOK
14.9 billion) in 2002. A specification of the allocation of
this purchase price to assets and liabilities acquired can be
found in Note 2 in Notes to the Consolidated Financial
Statements. Goodwill Under SFAS 142, Goodwill and Other Intangible
Assets, goodwill and certain intangible assets are reviewed
at least annually for impairment. The largest portion of
goodwill was recorded in the North America sector of the
Extrusion and Automotive sub-segment. Management annually
assesses the fair value of the sectors goodwill in relation to the carrying value of
the sectors net assets. Assumptions related to certain cash
flow forecasts and the discount rate are made reflecting the
sectors industry. Total goodwill evaluated for impairment
during 2004 was approximately NOK 1,000 million. Goodwill is
included in prepaid pension, investments, and other
non-current assets. Income Taxes Hydro calculates deferred income tax expense based on
the difference between the tax assets carrying value for
financial reporting purposes and their respective tax basis
that are considered temporary in nature. This computation
requires managements interpretation of complex tax laws
and regulations in many tax jurisdictions where Hydro
operates. Valuation of deferred tax assets is dependent on
managements assessment of future recoverability of the
deferred benefit. Expected recoverability may result from
expected taxable income in the near future, planned
transactions or planned tax optimizing measures. Economic
conditions may change and lead to a different conclusion
regarding recoverability, and such change may affect the
results for each reporting period. Employee Retirement Plans Hydros employee retirement plans consist primarily of
defined benefit pension plans. Measurement of pension cost and
obligations under the plans requires a number of assumptions
and estimates to be made by management. These include future
salary levels, discount rates, turnover rate, and rate of
return on plan assets. The discount rate used for determining
pension obligations and pension cost is based on the yield
from a portfolio of long-term corporate bonds having one of
the two highest ratings given by a recognized rating agency.
Hydro provides defined benefit plans in several countries and
in various economic environments that will affect the actual
discount rate applied. Almost three-quarters of Hydros
projected benefit obligation relates to Norway. The discount
rate applied for Norwegian plans as of 31 December 2004 is
5.25 percent. The expected rate of return on plan assets is,
based on the current portfolio of plan assets, determined to
be approximately one percentage point above the yield on a
portfolio of long-term corporate bonds that receive one of the
two highest ratings given by a recognized rating agency. Changes in these assumptions can influence the funded
status of the plan as well as the net periodic pension
expense. The PBO is sensitive to changes in assumed discount
rates and assumed compensation rates. Based on indicative
sensitivities, a one percentage point reduction or increase in
the discount rate will increase or decrease the PBO in the
range of 15 to 20 percent. A one percentage point reduction or
increase in compensation rates for all plan member categories
will decrease or increase the PBO in the range of 15 to 20
percent. It should be noted that changes in the aforementioned
parameters and changes in the PBO will affect net periodic
pension cost in subsequent periods, both the service cost and
interest cost components, in addition to amortization of
unrecognized net gains or losses, if any. Change in Accounting Principles  Consolidation of
Variable Interest Entities Effective 1 January 2004, Hydro adopted FASB
Interpretation 46 Consolidation of Variable Interest
Entities (FIN 46R), which clarifies the application of
Accounting Research Bulletin No. 51, Consolidated Financial
Statements, relating to certain entities in which equity
investors do not have the characteristics of a controlling
financial interest or do not have sufficient equity at risk
for the entity to finance its activities without additional
subordinated financial support (variable interest entities or
VIEs). The Interpretation provides guidance for determining
which party retains the controlling financial interest in VIEs
when such interest is achieved through arrangements other than
voting rights. Implementation of the new requirements depended
on when a company became involved with such entities. Because
Hydro did not become involved with any new Variable Interest
Entities (VIEs) during the period 31 January to 31 December
2003 or have any interests in Special Purpose Entities (SPEs)
as of 31 December 2003, implementation of the Interpretation
was required as of 31 March 2004. Hydro has identified one
pre-existing arrangement that meets the requirements of FIN
46R to be classified as a VIE. Hydro has equity interest in
Slovalco, an aluminium smelter in Slovakia. Hydro also has an
agreement to supply Slovalco with alumina and a right and
obligation to purchase approximately 60 percent of Slovalcos
total aluminium production at market based prices. Hydro owns
20 percent of the shares of Slovalco representing 40 percent
of the voting rights. In 2001, Hydro entered into a put and
call option 97




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##### 



arrangement with another
shareholder that could increase Hydros interest up to 65
percent. This arrangement, which expires in the period 2005 to
2006, is the primary reason requiring Hydro to consolidate
Slovalco in accordance with the new VIE regulations. Hydro has
consolidated Slovalco in accordance with the new requirements
effective from 1 January 2004. Related assets, liabilities and
the 80 percent non-controlling interests have been measured
based on their fair values at the time the option arrangement
was entered into in 2001 and recorded based on such values
carried forward to 1 January 2004. As of 1 January 2004, total
assets, liabilities and non-controlling interests were NOK
2,182 million, NOK 725 million and NOK 1,165 million
respectively. At the end of 2003, the difference between
Hydros interest in Slovalco consolidated based on the new
requirements compared to the equity method was immaterial. Liquidity and Capital resources Amounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Cash flow provided by (used for):Operations
    
    
    27,724
    
    
    
    22,773
    
    
    
    19,080Investments
    
    
    (23,962
    )
    
    
    (7,054
    )
    
    
    (35,492
    )Financing
    
    
    (13,579
    )
    
    
    (8,092
    )
    
    
    (5,926
    )Increase (decrease) in cash
and cash equivalents
    
    
    (507
    )
    
    
    9,326
    
    
    
    (20,741
    )Return on Shareholders equity
    
    
    14.4
    %
    
    
    13.4
    %
    
    
    11.6
    %RoaCE
    
    
    13.0
    %
    
    
    8.4
    %
    
    
    7.2
    %Adjusted net debt/equity ratio 1)
    
    
    0.11
    
    
    
    0.38
    
    
    
    0.60
   1)
    
    Adjusted net interest-bearing debt divided by
shareholders equity plus minority interest, adjusted for
unfunded pension obligation (after tax) and present value of
future obligations on operating leases. Cash flow Hydro has historically financed its operations primarily
through cash generated by operating activities. In 2004, net
cash generated by the Companys operations of approximately
NOK 27.7 billion was sufficient to fund the net cash used in
investing activities of approximately NOK 24 billion including
investments in bank term deposits of NOK 9.2 billion (see
Investments Activities below). Cash provided by discontinued
operations, consisting of proceeds from the sale of shares in
Yara, following the demerger of the agri operations, and
Yaras repayment of debt to Hydro, added another NOK 9.6
billion. Approximately NOK 9.3 billion was used to repay
interest bearing debt and approximately NOK 4.5 billion was
used for dividends and share repurchases, reducing the
Companys cash balance by approximately NOK 0.5 billion. Cash from Operations In 2004, net cash provided by operating activities
amounted to NOK 27.7 billion in 2004, and increase of NOK 5
billion, or 22 percent compared to 2003. Cash from operations
improved as a result of increased production and strong market
fundamentals as described above in this Financial Review. The
improvement was reflected in an increase of NOK 1.6 billion in
net income for the year. Significant charges impacting income
but not affecting operating cash for the year included the
write-down of the German primary metal plant amounting to
approximately NOK 2.3 billion. Deferred tax expense declined
approximately NOK 900 million as a result of amended tax
regulations improving net income. The decline in net working
capital compared to 2003, provided approximately NOK 1.4
billion of the increase in cash provided by operations. The
effects of changes in other non-cash incomes and charges such
as gains and losses on asset disposals, unrealized gains and
losses on foreign currencies, and other items were largely
offsetting. Investing Activities Cash payments for investing activities in 2004 were NOK
24 billion, an increase of NOK 16.9 billion compared to 2003.
This increase was primarily due to a significant increase of
spending on purchases of short-term investments reflecting a
change in investment policy during 2004. Hydros previous
policy required that all cash should be deposited with a
maximum maturity of 3 months. However, to take advantage of
somewhat higher interest rates, as well as having the
opportunity of matching
maturities with specified and known large cash outflows (e.g.
oil tax payments, dividend payments, etc.), the maximum
maturity for the cash deposits has been increased to 12
months. At the end of 2004, NOK 9.2 billion of the Groups
liquidity was deposited on bank term deposits with original
maturities beyond 3 months. As a result, such amounts are
classified as net cash used in investing activities and
included with other liquid assets on the balance sheet. At the
end of 2003, no bank deposits had an original maturity over 3
months. In addition, there was a significant reduction of
proceeds from sales of other long-term investments, NOK 1.4
billion in 2004 compared to 6.4 billion in 2003. See Capital Expenditures section below for an
analysis of expenditure for property, plant and equipment
and long-term investments. Financing Activities In 2004, NOK 13.6 billion was used in financing
activities, compared to NOK 8.1 billion in 2003. Principal
repayments of NOK 9.3 billion in 2004, were NOK 4.1 billion
higher than in 2003. Principal repayments included prepayments
of long-term debt of NOK 6.7 billion following the agri
demerger. In addition, repurchase of ordinary shares of NOK
1.7 billion and dividends of NOK 2.8 billion, together
amounting to NOK 4.5 billion, were NOK 1.2 billion higher than
share repurchases and dividends in 2003. In December 2004, an
extraordinary General Meeting of shareholders approved a
capital reduction by cancellation of 2,808,810 treasury shares
acquired in 2004 as part of a share buyback program approved
by the 2004 Annual General Meeting. The extraordinary General
Meeting also authorized the redemption of 2,191,190 shares
owned by the Norwegian State for an amount of NOK 981 million
that was paid in February 2005. Discontinued Operations As indicated above, the cash flow effect from the agri
demerger amounted to NOK 9.6 billion. As part of the demerger,
Yara had assumed a liability to pay to Hydro a net interest
bearing debt which on completion of the demerger amounted to
approximately NOK 7.1 billion. Yaras repayment of this debt
resulted from the proceeds of debt financing arranged through
financial institutions prior to the consummation of the
demerger. In addition, Hydro sold its 20 percent share holding
in Yara for NOK 2.6 billion as part of the demerger process. Liquidity Cash and cash equivalents were NOK 14.4 billion at
the end of 2004 compared to NOK 14.9 billion for 2003.
However, following the change in investment policy mentioned
above, NOK 9.2 billion of the groups liquidity generated in
2004 was deposited on bank 98




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##### 



term deposits with maturities
beyond 3 months at the end of 2004, and included with other
liquid assets on the balance sheet. Including these deposits,
Hydros total cash, cash equivalents and other liquid assets
amounted to NOK 25.3 billion at year end 2004 compared with
NOK 16.4 billion at year end 2003. Hydro believes that cash
from continuing operations, together with the liquid holdings
and available credit facilities will be more than sufficient
to meet its planned capital expenditures, operational
requirements, dividends and debt repayments in 2005. Hydros
capital expenditures are estimated to be approximately NOK 24
billion (including exploration activities) for 2005. Short and long-term borrowings At year-end 2004, short-term bank loans and the
current portion of long-term debt in Hydro amounted to NOK 4.4
billion, down from 6.5 billion year-end 2003. Hydros
long-term interest bearing debt at the end of 2004 was NOK
19.5 billion, a reduction of NOK 8.9 billion from NOK 28.4
billion at the end of 2003. During 2004, a total of NOK 6.7
billion of long-term debt was prepaid and NOK 0.6 billion
became current and was reclassified to short-term liabilities.
The remaining NOK 1.6 billion of the decline in long-term debt
was primarily attributable to a lower USD/NOK exchange rate at
year-end 2004 compared to year-end 2003. Hydro repaid maturing
loans of NOK 1.2 billion in 2004, and no new loans were issued
during the year. As of 31 December 2004 the fair value of
Hydros long-term debt, including the current portion, was NOK
23.6 billion, and the carrying value was NOK 20.1 billion. As a means of adjusting the debt portfolio following the
agri demerger, Hydro prepaid during the year bank debt of SEK
944 million and EUR 51 million and repurchased outstanding
bonds of USD 253 million, NOK 473 million, GBP 209 million and
EUR 100 million, aggregating to a total extraordinary nominal
value debt reduction of NOK 6.7 billion in 2004. Following
this debt reduction, more than 80 percent of Hydros long-term debt was denominated in US
dollars at the end of 2004. The weighted average interest rate
on all long-term debt was approximately 7.1 percent, and
substantially all long-term debt carried fixed interest rates.
The average maturity of the Companys outstanding long-term
debt was approximately 14.7 years, with approximately 16
percent of the long-term debt falling due within the next five
years and the remainder thereafter. (See Note 19 in Notes to
the Consolidated Financial Statements for more comprehensive
information on the composition of long-term debt). Substantially all of Hydros indebtedness is situated in the
parent company, Norsk Hydro ASA. In general, the terms of each
of the debt agreements and indentures governing the
indebtedness contain cross-default provisions under which a
default under any other loan, indebtedness or other obligation
for borrowed money on the part of Hydro would trigger a
default under that debt agreement or indenture. The
cross-default provisions are generally limited to borrowing
obligations of Norsk Hydro ASA or any of its Principal
Subsidiaries (defined to mean a company or other entity (i)
which is fully consolidated in the consolidated balance sheet
of the Company or in which the Company owns more than 50
percent of the issued share capital, (ii) the gross assets of
which represent more than 10 percent of the consolidated gross
assets of the Company and its subsidiaries (taken as a whole)
and (iii) which is incorporated in the Kingdom of Norway, and
require that the indebtedness in default under another
agreement or indenture be greater than USD 25 million). Substantially all of Hydros debt is unsecured. However, the
agreements and indentures contain provisions restricting the
pledging of assets in Norsk Hydro ASA to secure future
borrowings without granting equivalent status to existing
lenders. The debt agreements and indentures contain no
financial ratio covenants and no provisions connected to
Hydros credit rating or value of underlying assets. None of
the agreements give the lenders a right to put the loan and
demand repayment prior to its scheduled maturity. However,
certain agreements allow for Hydros early redemption or
repayment of the indebtedness at certain specified premiums,
plus accrued and unpaid interest. At 31 December 2004, Hydros
senior unsecured debt was rated A2 by Moodys and A with
negative outlook from Standard & Poors. In determining the
rating, the rating agencies have not factored in the Norwegian
States 43.8 percent equity interest in the Company. The
factors given significant weight in determining Hydros
current credit rating include: the diversification of the
Companys portfolio; the cash flow generated from the oil and
gas activities; the strong position in aluminium products; and
a sound financial profile. The ratings also, however, reflect
the commodity characteristics of most of the Companys
products, and consequently, the exposure to market price
fluctuations and economic cyclicality. None of the rating
agencies changed Hydros rating as a consequence of the agri
demerger. Net interest bearing debt (short- and long-term
interest bearing debt, including the current portion of
long-term debt, less cash and cash equivalents and other
liquid assets) at the end of 2004 was NOK 1.5 billion negative
(i.e. a net cash position), compared to NOK 18.5 billion in
net interest bearing debt at the end of 2003. Including net
unfunded pension obligations, after tax, and the present value
of operating lease obligations, the adjusted net
interest-bearing debt divided by adjusted equity was 0.11 by
the end of 2004, which was well within the stated target of
0.5. See Use of Non-GAAP Financial Measures later in this
report for further discussion on adjusted net interest bearing
debt and adjusted equity. As of 31 December 2004, Hydro had unused short-term
credit facilities totaling approximately NOK 2.6 billion. The
Company also had agreements with banks for committed long-term
stand-by credit facilities totaling approximately USD 2
billion (NOK 12.2 billion). Hydro has also entered into a
long-term loan facility of EUR 300 million (NOK 2.5 billion)
with the European Investment Bank (EIB) in connection with the
Ormen Lange & Langeled developments. There were no borrowings
under any of these agreements as of 31 December 2004. Hydro
also has in place a shelf registration in the US under which
it may raise up to an aggregate of USD 1.5 billion in debt
securities. There are no substantial restrictions on the use
of borrowed funds under Hydros material credit and debt
facilities except for the EIB facility mentioned above where
any drawings are subject to ownership and investments in the
Ormen Lange and Langeled projects. Employee Retirement Plans Hydros employee retirement plans consist primarily of
defined benefit pension plans. As of 31 December 2004, the
projected benefit obligation (PBO) associated with Hydros
defined benefit plans was NOK 25.4 billion. The fair value of
pension plan assets was NOK 16.5 billion, resulting in a net
unfunded obligation relating to the plans of NOK 8.9 billion.
In addition, termination benefit obligations and other
pension obligations amounted to NOK 1.2 billion, resulting in
a total net unfunded pension obligation of NOK 10.1 billion.
Hydros net pension cost for 2004 amounted to NOK 2.1
billion. Cash outflows from operating activities in 2004
regarding pensions amounted to NOK 1.6 billion. The discount
rate used for determining pension obligations and pension
cost is based on the yield from a portfolio of long-term
corporate bonds having one of the two highest ratings given
by a recognized rating agency. Hydro provides defined benefit
plans in several countries and in various economic
environments that will affect the actual discount rate
applied. Almost three-quarters of Hydros project- 99




---



##### 



ed benefit obligation relates to Norway. The discount rate applied for
Norwegian plans as of 31 December 2004 was 5.25 percent.
Measurement of pension cost and obligations under the plans
requires a number of assumptions and estimates to be made by
management. These include future salary levels, discount
rates, turnover rate, years of future service, and rate of
return on plan assets. Contractual Obligations, Commitments and
Off Balance Sheet Arrangements A summary of Hydros total contractual obligations and
commercial commitments to make future payments is presented
below. For further details see Notes 7, 19, 22 and 23 in the
Notes to the Consolidated Financial Statements. Contractual Obligations Payments due by PeriodAmounts in
    
    
    
    
    Less than

    
    
    1-3
    
    
    3-5
    
    
    There-NOK million
    
    Total
    
    
    1 year
    
    
    years
    
    
    years
    
    
    afterLong-term debt
    
    
    19,952
    
    
    
    546
    
    
    
    793
    
    
    
    1,870
    
    
    
    16,743Interest related to
long-term debt
    
    
    19,896
    
    
    
    1,382
    
    
    
    2,652
    
    
    
    2,548
    
    
    
    13,314Finance lease
obligations
    
    
    103
    
    
    
    22
    
    
    
    34
    
    
    
    6
    
    
    
    41Operating lease
obligations
    
    
    4,736
    
    
    
    1,171
    
    
    
    1,561
    
    
    
    1,011
    
    
    
    993Unconditional
purchase
obligations
    
    
    47,523
    
    
    
    5,271
    
    
    
    7,962
    
    
    
    6,159
    
    
    
    28,131Contractual
commitments for:PP&E
    
    
    20,499
    
    
    
    8,254
    
    
    
    7,483
    
    
    
    1,080
    
    
    
    3,682Other future
investments
    
    
    342
    
    
    
    325
    
    
    
    17
    
    
    
    Benefit payments
unfunded defined
benefit plans
    
    
    1,582
    
    
    
    275
    
    
    
    613
    
    
    
    694
    
    
    See
    1)Termination
benefits
    
    
    720
    
    
    
    220
    
    
    
    296
    
    
    
    172
    
    
    
    32Other long-term
liabilities
    
    
    1,489
    
    
    
    344
    
    
    
    726
    
    
    
    304
    
    
    
    115Total contractual
cash obligations
    
    
    
    
    
    
    17,810
    
    
    
    22,137
    
    
    
    13,844
    
    
    
    63,051
   1)
    
    Annual payments are expected to continue into the
foreseeable future in the range of NOK 400 to 500 million.The Company also has other obligations connected with pension
plans that are not contractually fixed to timing and amount. In addition, Hydro is contingently liable for
guarantees made directly by the parent company or made on
behalf of subsidiaries in the normal course of business (see
note 22 to the Consolidated Financial Statements). Hydro
grants guarantees at market based fees to enable subsidiary
companies to obtain credit or engage in contracts of a greater
magnitude than would otherwise be possible without such
guarantees. Hydro makes such guarantees to facilitate
transactions, which are considered necessary to reach its
business objectives. The following describes guarantees
outstanding as of 31 December 2004: Hydro has guaranteed NOK
86 million of debt issued on behalf of non-consolidated
investees and is contingently
liable for NOK 92 million of discounted bills. Hydro is also contingently liable to various tax authorities for NOK
1,354 million relating to the non-taxable treatment of gains
on internal sales of non-current assets and subsidiaries.
Gains on such sales could become taxable if certain assets
were sold outside the Group. Hydro controls whether such
assets are offered for sale outside of the Group. Guarantees
in connection with the sale or divestment of companies
amounted to NOK 8,200 million. The amount reflects the maximum
contractual amount that Hydro could be liable for in the event
of certain defaults or the realization of specific
uncertainties. Hydro has, in addition to this amount, certain
guarantees relating to sales or divestment of companies that
are unspecified in amount. Hydro believes that the likelihood
of any material liability arising from guarantees relating to
sales of companies is remote. Historically, we have not made
any significant indemnification payments under such guarantees
and no amount has been accrued in the accompanying
Consolidated Financial Statements. In addition to guarantees
relating to the sale or divestment of companies, Hydro has
guaranteed certain recoverable reserves of crude oil in the
Veslefrikk field as part of an asset exchange between Hydro
and Petro Canada. In 1996, Hydro entered into a strategic
alliance with Petro-Canada that entailed a swap of certain
Hydro interests in licenses on the NCS in exchange for the
right to participate in oil production from proven fields and
explore for further oil discoveries on the Grand Bank. Under
the guarantee, Hydro is obligated to deliver indemnity
reserves to Petro Canada in the event that recoverable
reserves are evaluated to be lower than a specified amount. An
evaluation of the recoverable reserves was completed in 2002
in accordance with the agreement which resulted in
compensation by Hydro to Petro Canada. The agreement with
Petro Canada was renegotiated in 2002 with the possibility of
making a new evaluation of the reserves in 2008, 2014 and the
end of the fields productive lifetime. The agreement includes
the possibility of recovery by Hydro of earlier compensation
if new evaluations indicate improvements in the estimated
recoverability. The guarantee is not applicable in cases of
force majeure, the failure of the field operator to comply
with appropriate field practices and other instances. As of 31
December 2004, the remaining volume covered under the
guarantee was 1.02 million Sm3of crude oil,
equivalent to approximately NOK 1,569 million calculated at
current market prices. Outstanding commercial guarantees made
on behalf of subsidiaries amounted to NOK 9,390 million. Such
guarantees include advance payment guarantees, bid bonds,
performance bonds, stand-by letters of credit and payment
guarantees. Certain of these guarantees are obtained from
external banks and covered by Hydro by a counter indemnity to
such banks. Hydros contingent liability relating to
commercial guarantees is linked to the perform- 100




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##### 



ance of its subsidiaries under various contracts. However, a certain
portion of the guarantees are payable on demand. Therefore,
there is a certain amount of litigation risk in the event of
unfair calls relating to such guarantees. Because the payment
of commercial guarantees is related to events directly or
indirectly controlled by Hydro, the Company considers its risk
related to such instruments to be limited. As a result, these
guarantees do not pose material risk to the Companys future
liquidity, capital resources and results of operations. Since
Hydro is, in effect, guaranteeing its own performance relating
to commercial guarantees, they are not considered off balance
sheet arrangements as defined by SEC regulations. None of the
contingent amounts described above are recorded on the balance
sheet as of 31 December 2004. Minority interest and Shareholders equity Minority interest was NOK 1,571 million as of 31
December 2004 compared to NOK 660 million for the prior year.
The increase resulted from the consolidation of Solvalco
amounting to approximately NOK 1,026 million offset by
approximately NOK 96 million relating to the demerged Agri
operations. Shareholders equity was NOK 85,890 million at the
end of 2004, a decrease of NOK 2,190 million. In addition to
net income, the main items impacting shareholders equity
included dividends, purchases of treasury stock, redemption of
shares from the Norwegian state, foreign currency translation
losses and a reduction related to the demerged Agri
operations. See note 3 to the Consolidated Financial
Statements for a detailed reconciliation of shareholders
equity. Investments Investments in 2004 amounted to NOK 19.5 billion.
The amount contains certain items that have no cash effect in
the near term. The most significant of these include NOK 1,275
million relating to the consolidation of the aluminium
producer Slovalco and NOK 922 million relating to future
assets retirement obligations for oil and gas installations.
Excluding these items, investments were approximately NOK 17
billion for 2004. Just over half of the investment amount
related to oil and gas operations. Investments1) Amounts in NOK million
    
    20042)
    
    
    %
    
    
    2003 3)
    
    
    %
    
    
    2002
    
    
    %Exploration and Production
    
    
    10,607
    
    
    
    54
    
    
    
    10,270
    
    
    
    58
    
    
    
    14,073
    
    
    
    32Energy and Oil Marketing
    
    
    1,460
    
    
    
    8
    
    
    
    989
    
    
    
    6
    
    
    
    622
    
    
    
    1Eliminations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydro Oil & Energy
    
    
    12,067
    
    
    
    62
    
    
    
    11,259
    
    
    
    64
    
    
    
    14,696
    
    
    
    33Metals
    
    
    4,199
    
    
    
    22
    
    
    
    3,572
    
    
    
    20
    
    
    
    12,728
    
    
    
    29Rolled Products
    
    
    553
    
    
    
    3
    
    
    
    466
    
    
    
    3
    
    
    
    7,437
    
    
    
    17Extrusion and Automotive
    
    
    1,442
    
    
    
    7
    
    
    
    1,543
    
    
    
    9
    
    
    
    5,153
    
    
    
    12Other and eliminations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydro Aluminium
    
    
    6,194
    
    
    
    32
    
    
    
    5,581
    
    
    
    32
    
    
    
    25,318
    
    
    
    57Other Activities
    
    
    1,058
    
    
    
    5
    
    
    
    791
    
    
    
    4
    
    
    
    3,008
    
    
    
    7Corporate and eliminations
    
    
    145
    
    
    
    1
    
    
    
    81
    
    
    
    0
    
    
    
    1,144
    
    
    
    3Total
    
    
    19,464
    
    
    
    100
    
    
    
    17,712
    
    
    
    100
    
    
    
    44,166
    
    
    
    100
   1)
    
    Additions to property, plant and equipment (capital expenditures) plus long-term
securities, intangible assets, long-term advances and investments in non-consolidated investees.2)
    
    Includes effect of change in accounting principle (FIN 46R). Non-cash increase in
investment of NOK 1,275 million.3)
    
    Includes non-cash increase in investment from
effect of change in accounting principle (FAS143), of NOK 1,918 million. The largest investments for
Exploration and Production related to new and existing fields;
of which Snøhvit (Hydros share in


 Snøhvit was sold to Statoil and the sale was settled in
December 2004), Kristin, Ormen Lange and Dalia were the most
important. For Energy and Oil Marketing, the most important
investment in 2004 was related to the Langeled project. The
major investments in Aluminium Metals in 2004 included the
expansion activities in Sunndal, Norway, where the third and
final phase was completed, and in Alouette in Canada.
Investments in Rolled Products related primarily to the
construction of a Lithographic line in Germany. Investments in
Extrusion and Automotive continued for the construction of a
new casting line in Dillingen in Germany. Investments for
Other activities relates primarily to the construction of a
new chlorine plant at Rafnes in Norway which was started in
2003. Investments in Exploration and Production in 2003 were
NOK 10,270 million. The largest investments for Exploration
and Production related to new and existing fields, of which
Grane, Kristin and Snøhvit were the most important. The major
investments in Aluminium Metals in 2003 included the
expansion activities pertaining to the smelters in Sunndal,
Norway, where phase II was completed and phase III is under
construction, and in Alouette in Canada. An expansion of the
alumina refinery, Alunorte, in Brazil was also completed
during the year. The investments in Extrusion and Automotive
related to the construction of a new casting line in Dillingen
in Germany. Investments in Exploration and Production in 2002
were NOK 14,073 million. The purchase of assets from SDFI and
investments related to new and existing fields, mainly the
development of the Grane field, were the most important
investment projects for Exploration and Production in 2002.
The largest investments for Hydro Aluminium included the VAW
acquisition, the acquisition of Technal and the expansion
activities relating to the aluminium smelter in Sunndal,
Norway and the alumina refinery Alunorte, in Brazil. Material commitments for capital expenditures Contractual commitments for investments in
property, plant and equipment relating to land-based
activities and oil and gas field activities and transport
systems at the end of 2004 were NOK 986 million and NOK 19,513
million, respectively. The total amount of NOK 20,499 million
is included in the contractual obligations table above in
Contractual commitments for PP&E. Additional authorized future
investments representing projects formally approved by the
Board of Directors or management were NOK 1,306 million
relating 101




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##### 



to land-based activities and NOK 326 million relating
to oil and gas field activities and transport systems. Hydros long-term committed stand-by facilities of approximately USD 2
billion, the EUR 300 million loan facility with EIB in
connection with the Ormen Lange/Langeled developments, as well
as cash holdings and expected cash flow from operations, are
expected to provide sufficient reserves to fund these
expenditures. In addition, the companys A/A2 rating
(investment grade) ensures adequate access to the global
capital markets for raising additional liquidity, if needed. Research and development Hydro engages in research and development (R&D) in
order to maintain its competitive position and to develop new
products and processes. Hydro spent approximately NOK 760
million, NOK 722 million and NOK 639 million during 2004,
2003, and 2002 respectively, on such activities. As part of
its R&D activities, Hydro continues to focus on ecological
issues including life cycle analyses and energy efficiency
studies relating to products produced by the Company. Hydro
maintains major research centers in Porsgrunn and Bergen in
Norway, with a combined staff of 320 as well as smaller
research groups in several other locations. The Bergen
facility, with a staff of 158 people, is dedicated to the
Groups oil and gas activities. Research centers for Hydro
Aluminium are located in Karmøy, Årdal, Raufoss Sunndal and
Porsgrunn in Norway; in Bonn and Ulm in Germany; in Tønder,
Denmark and in Michigan, US. The following highlights major
contributors to total R&D costs incurred in 2004. Hydro Oil
and Energy incurred R&D costs in 2004 totaling approximately
NOK 223 million compared to NOK 194 million in the previous
year. R&D expenditures in 2004 were primarily dedicated to  
    increased discovery rate through improved exploration
technology,
    increased oil recovery in order to prolong the
production from mature fields,
    economic viable development
of smaller fields and,
    further improvement of health, safety
and environmental technology to insure personnel and technical
safety as well as protecting the external environment. Power generation with CO2 capture and storage, hydrogen as
future energy carrier and, renewable energy, were also
part of Hydro Oil and Energys R&D programs in 2004, aimed at
achieving a cleaner and more efficient production. Hydro
Aluminiums R&D is oriented toward the core activities of its
business. Hydro Aluminium incurred a total of NOK 494 million
in 2004 in R&D cost compared with NOK 459 million in R&D costs
in 2003. Metals, Extrusion and Automotive, and Rolled Products
incurred NOK 213 million (NOK 168 million in 2003), NOK 220
million (NOK 240 million) and NOK 61 million (NOK 51 million),
respectively. R&D activities serve to continuously improve
products and manufacturing processes, as well as to develop
innovative technologies and new applications. The work focuses
also on securing the continued progress of aluminium as a
competitive and environmentally sound material. R&D
expenditures were mainly dedicated to developing technologies
for production of primary metal, extrusion, rolling and
casting. In addition, the work covers development of new
aluminium and magnesium alloys, and development of
semi-fabricated and finished products. Hydro Aluminiums R&D
organization consists of an international network covering
Europe, North America and Asia. Risk management Risk management in Hydro is based on the principle that
risk evaluation is an integral part of all business
activities. The main responsibility for risk management is
consequently placed within the Companys business areas and
its corporate finance function, all having policies and
procedures in place for monitoring risks, assessing
appropriate risk levels, and mitigating risk. Overall and
aggregated risk positions are also assessed at the Company
level, most notably in the following categories:  
    Business Strategy and Management  including events that
may impact the Companys reputation and brand
    Financial Risks  including events that may have an
impact on the adjusted net debt/equity ratio, liquidity
and credit rating
    Commercial Risks  mainly comprising fluctuations in
commodity prices, currencies and interest rates
    Operational and Human Resource Risks  comprising
technical risk, continuity risk and risks related to
non-performance of employees
    Health, Security, Safety, Environmental issues and
potential impact on communities
    Information Systems  comprising elements such as poor
data quality and consistency, loss of systems and data,
inadequate administration of access to systems and
malicious attacks.
    Legal and Regulatory  comprising elements such as business
exposure to new regulation including tax, illegal acts,
regulatory non-compliance and unauthorized actions. The following discussion provides additional detail
regarding Hydros exposure to financial and commercial risks
with a focus on commodity prices, foreign exchange rates and
interest rates. Hydros operating results are primarily
affected by price developments of Hydros main products oil
and aluminium, in addition to foreign currency fluctuation of
the most significant currency, the US dollar, against the
Norwegian krone. An indication of the sensitivity regarding
prices and foreign currency fluctuation for 2005 is provided
below. The table illustrates the sensitivity of earnings,
before and after tax, to changes in these factors and is
provided to supplement the sensitivity analysis required by
the SEC, included later in this section. Indicative price and currency sensitivities 20051) Amounts in NOK million
    
    Pre tax
    
    
    After tax
    
    
    ChangeOil price per barrel
    
    
    1,150
    
    
    
    310
    
    
    1 USDAluminium price per tonne
    
    
    800
    
    
    
    560
    
    
    100 USDUS dollar Hydro Oil & Energy
    
    
    7,250
    
    
    
    1,960
    
    
    1 NOKUS dollar Hydro Aluminium
    
    
    2,500
    
    
    
    1,750
    
    
    1 NOKUS dollar before financial items
    
    
    9,750
    
    
    
    3,710
    
    
    1 NOKUS dollar financial items 2)
    
    
    (3,100
    )
    
    
    (1,705
    )
    
    1 NOKUS dollar Net income
    
    
    6,650
    
    
    
    2,005
    
    
    1 NOK
   1)
    
    Based on average 2004 prices and expected business
volumes for 2005: Oil 38 US dollar/bbl, Aluminium 1,700
US dollar/tonne and Norwegian krone/US dollar 6.5.2)
    
    US dollar sensitivity calculated based on long-term debt
denominated in US dollar and net US dollar amounts sold
forward on long-term forward currency contracts. Cash
positions denominated in US dollar, short-term debt
denominated in US dollar and net US dollar amounts sold
forward on short-term forward currency contracts are
excluded. 102




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##### 



In addition to the above sensitivities, the
revaluation of derivative instruments and contracts
classified as derivatives may influence reported earnings,
as described in more detail in the following paragraphs. Financial and Commercial Risk Management The overall objective of financial and commercial
risk management is to safeguard Hydros ability to
continuously meet its cash commitments and maintain a strong
financial position. This includes identifying and monitoring
the Companys main risk exposures, quantifying the potential
impact on key financial ratios and proposing corrective
actions when deemed appropriate. Shortfalls in operational
cash flow due to unfavorable developments in prices of main
products, raw materials and/or exchange rates could
substantially impact Hydros financial position. Cash
commitments are risk evaluated against cash flow from
operations. Probabilities of not meeting set financial
targets, such as maintaining the adjusted net debt/equity
ratio target of 0.5, are monitored. Simulations of cash flow
scenarios, using a 5-year rolling horizon, are carried out for
this purpose. The outcome of this analysis is reported to
management on a quarterly basis. Mitigating financial and
commercial risk exposures through the use of derivative
instruments is done only to some extent. For this purpose,
Hydro utilizes financial derivatives as well as commodity
derivatives. The most common use of financial and exchange
traded commodity derivatives relates to hedging of currency,
and aluminium as part of the Companys day-to-day aluminium
operations. For accounting purposes, unless otherwise
indicated below, derivative financial and commodity
instruments are recognized at fair value with changes in the
fair value impacting earnings. Hedge accounting, as allowed by
Statement of Financial Accounting Standards (SFAS) No. 133
Accounting for Derivative Instruments and Hedging
Activities, is used to a limited extent, and only when
specific hedge criteria are met. This can result in volatility
in earnings since the associated gain or loss on the related
physical transactions may be reported in earnings in different
periods. Commodity price risk A substantial portion of Hydros revenues is derived
from the sale of commodities such as crude oil and aluminium.
Hydro also produces, purchases and sells natural gas,
electricity and petrochemical products. The prices of these
commodities can be volatile, creating fluctuations in Hydros
earnings. Natural hedging positions are established to the
extent possible and economically viable. However derivatives
are used in special situations to mitigate price movements and
to participate in limited speculative trading within strict
guidelines defined by management. Oil Hydro produces and sells crude oil and gas liquids.
Hydro utilizes futures and swaps to mitigate unwanted price
exposure for a limited portion of its crude oil production.
From time to time financial options are used for the same
purpose. In the first half of 2003 Hydro had in place a
hedging program using average rate put options (Asian
options) with the right to sell 10 million barrels of oil for
an average strike price of US dollar 17 per barrel. At the
end of 2004 Hydro had no significant hedging in place for the
purpose of protecting against the risk of low oil prices. Natural gas Hydro is a producer, buyer, seller, and to a limited
extent consumer of natural gas. The majority of Hydros equity
gas production is sold to European counterparties based on
long-term gas supply contracts. Contract prices are mainly
indexed to oil product prices. Hydro utilizes on a limited
basis instruments such as forwards and swaps to mitigate
unwanted price exposures on the portion of the natural gas
portfolio not sold on long-term contracts. Hydro is also
participating in trading activities based on partly own gas
production and partly externally sourced gas volumes. In
addition, Hydro engages in limited speculative trading. An increasing number of the Companys sales and purchase
contracts related to natural gas are being classified as
derivatives or deemed to contain embedded derivatives
according to SFAS 133. These contracts are marked to their
market value with changes to market value recognized in
operating income. Gas contracts can be indexed to oil products
or quoted gas prices at recognized gas delivering points such
as National Balancing Point (NBP) in Great Britain, Zeebrugge
Hub (ZB) in Belgium or the Dutch Title Transfer Facility
(TTF). The discussion on Hydros Critical Accounting Policies
included above provides more detail on the accounting
treatment of these contracts and how they are valued. These
derivative contracts are not fully hedged with other natural
gas derivatives. As such Hydro expects to have certain open
derivative positions at any time, which can result in
fluctuations in earnings. The magnitude of the unrealized
gains and losses on these contracts will be influenced by
geographic price differentials and spreads on the above
mentioned gas contract indices. Electricity Hydro is a producer and consumer of electricity. Hydros
consumption of electricity exceeds its production both in
Norway and in Continental Europe. The deficit is principally
covered through long-term purchase contracts with other
producers and suppliers to secure electricity in the market
for Hydros own consumption and delivery commitments. In order
to manage and hedge the risks of unfavorable fluctuations in
electricity prices and production volume, Hydro utilizes both
physical contracts and financial derivative instruments such
as futures, forwards and options. These are traded either
bilaterally or over electricity exchanges such as the Nordic
power exchange (Nord Pool). Hydro is also offering power
portfolio management services to third party clients and
participates in limited speculative trading. Aluminium Hydro produces primary aluminium and fabricated
aluminium products. The Companys sourcing and trading
activities procures raw materials and primary aluminium for
use in Hydros smelters or in downstream operations. These
materials are also sold directly to third parties. In
addition, the trading activities contribute to optimize
capacity utilization and to reduce logistical costs, as well
as strengthening market positions by providing customers with
flexibility in pricing and sourcing. Hydro has considerable
activities relating to remelting and long-term commercial
agreements to secure sourcing of casthouse products. All these
activities are considered when evaluating the risk profile of
Hydros aluminium activities. Hydro enters into future contracts with the LME with the
following purposes. The first is to achieve an average
aluminium price on smelter production. Secondly, because
the Companys midstream and downstream business, and the sale
of third party products, are margin businesses, Hydro hedges
metal prices when entering into customer and supplier
contracts with corresponding future contracts at fixed prices
(back-to-back hedging). The third is to hedge raw material
contracts. The majority of these contracts mature within one
year. Hydro manages these hedging activities on a port- 103




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##### 



folio
basis, taking LME positions based upon net exposures. These
contracts are intended as an economic hedge of sales and
purchases of aluminium or purchases of raw materials. Because
the related sales or purchases transactions with customers or
vendors have not been completed, i.e. normally delivery has
not taken place, Hydro is not able to recognize an unrealized
offsetting earnings effects which these transactions are
likely to have against the unrealized earnings effects on the
LME positions. Aluminium price volatility can consequently
result in significant fluctuations in earnings since only the
LME positions are marked to their market value with changes to
market value recognized in operating income. The expansion project at the Sunndal metal plant
increased Hydros exposure to commodity prices and foreign
currency exchange rates. Hydro has entered into short
positions using LME future contracts and US dollar forward
contracts to secure an average aluminium price of
approximately NOK 14,000 per tonne of a portion of the
forecasted sales of primary metal production per year until
the end of 2007. This hedging strategy meets certain hedging
criteria in accordance with SFAS 133, and has therefore been
designated as a cash flow hedge. Foreign currency exchange rate risk Prices of many of Hydros most important products,
mainly crude oil, aluminium and natural gas are either
denominated in US dollar or are influenced by movements in
the value of other currencies against the US dollar. The cost of raw materials, including natural gas, Natural
gas liquids (NGLs) and alumina, are affected by the US dollar
price of crude oil or the US dollar price of aluminium, and
variations in the US dollar exchange rates against local
currencies. Hydros primary foreign currency risk is therefore
linked to fluctuations in the value of the US dollar. Hydro
also incurs costs related to production, distribution and
marketing of products in a number of different currencies,
mainly Euro, Norwegian krone, US dollar, Canadian dollar,
Australian dollar, British Pounds and Swedish krone.
Consequently, the effects of changes in currency rates on the
translation of local currencies into Norwegian krone for
subsidiaries outside of Norway can influence comparative
results of operations. Normally, Hydros operating income will increase when
the US dollar appreciates against European currencies and
decline when the value of the US dollar falls. To reduce the
long-term effects of fluctuations in the US dollar exchange
rates, Hydro has issued most of its debt in US dollars (as of
31 December 2004, approximately 80 percent of Hydros
long-term debt was denominated in US dollars). When the US
dollar weakens, the decline in operating income is offset by
unrealized currency gains and lower interest expense relating
to the US dollar denominated debt. Conversely, a stronger US
dollar improves operating income but also results in
unrealized currency losses and higher interest expense. Hydro also employs foreign currency swaps and forward
currency contracts to modify the currency exposures for
Hydros long-term debt portfolio. Forward currency contracts
are entered into to safeguard cash flows for forecasted future
transactions or to cover short-term liquidity needs in one
currency through excess liquidity available in another
currency. As of 1 January 2005 Hydro no longer designates portions
of its long-term debt and certain forward currency contracts
as hedges of net investments in foreign subsidiary companies.
Changes to the Companys long-term debt portfolio and to the
Companys structure during the recent years has rendered these
accounting hedges less material to earnings and Shareholders
equity. Interest rate risk Hydro is exposed to changes in interest rates primarily
as a result of borrowing and investing activities used to
maintain liquidity and fund its business operations in
different currencies. Hydro maintains a high ratio of
long-term, fixed-rate debt, as a proportion of its total
interest-bearing debt, with an even debt repayment schedule.
Hydro uses foreign exchange and interest rate swaps from time
to time and other derivatives to optimize currency and
interest rate exposure. Credit risk Setting counterparty risk limits, requiring insurance,
and establishing procedures for monitoring exposures and
settlement of accounts limits Hydros credit risk. The
Companys overall credit risk level is also reduced through a
diversified customer base representing various industries and
geographic areas. Follow-up of timely payments of accounts

receivables is given high priority in the Company. Credit risk arising from the inability of a counterparty
to meet the terms of derivative financial instrument contracts
is generally limited to amounts by which the counterpartys
obligations exceed the obligations of Hydro. Pre-approval of
exposure limits is required for financial institutions
relating to current accounts, deposits and other obligations.
Credit risk related to derivative commodity instruments is
substantially limited since most instruments are settled
through commodity exchanges. Therefore, counter party risk
related to use of derivative instruments and financial
operations is regarded as limited. Sensitivity analysis In accordance with applicable requirements of the US
Securities and Exchange Commission (SEC), Hydro has chosen to
provide information about market risk and potential exposure
to hypothetical loss from its use of derivative financial
instruments and other financial instruments and derivative
commodity instruments through sensitivity analysis
disclosures. The sensitivity analysis depicted in the tables
below reflects the hypothetical loss in fair values assuming a
10 percent change in rates or prices and no changes in the
portfolio of instruments as of 31 December 2004 and 31
December 2003, respectively. The overall use of derivatives has remained stable from
2003 to 2004. Certain natural gas contracts that were not
classified as derivatives at end of 2003 have over the course
of the year been classified as derivatives or deemed to
contain embedded derivatives. This accounts for the increased
sensitivity to changes in commodity prices and foreign
currency exchange rates for derivative commodity instruments.
The fair value of other financial instruments has increased
compared to 2003, as a consequence of repayment of debt during
2004 and higher cash positions at the end of 2004.
Consequently the sensitivity related to changes in interest
rates and foreign currency exchange rates has been reduced for
other financial instruments. Hydros management emphasizes that the sensitivity
analysis contains material limitations. This is due to the
arbitrary nature of assumptions involved as well as the
inability of such a simple analysis to model reality and
continuous changes to Hydros portfolio. The most significant
limitations on the figures provided are as follows: 104




---



##### 




    The tables only include the effects of the derivative
instruments discussed above and of certain financial
instruments (see Footnote 3). The analysis does not
include any related physical positions, contracts, and
anticipated transactions that many of the derivative
instruments are meant to secure. A rate or price change
of 10 percent will often result in a corresponding effect
to the fair value of the physical or underlying position
such that the resulting gains and losses would offset.  
    As allowed by the SEC regulations, Hydro has excluded
accounts payable and accounts receivable from the
presentation, which may have had a significant effect
on the foreign exchange risk figures provided.  
    The computations, which provide the most negative
effect to Hydro of either a 10 percent increase or
decrease in each rate or price, do not take into account
correlations, which would be expected to occur between
the risk exposure categories. For example, the effect
that a change in a foreign exchange rate may have on a
commodity price is not reflected in the tables.  
    It is not likely that all rates or prices would
simultaneously move in directions that would have
negative effects on Hydros portfolio of instruments. The above discussion about Hydros risk management policies
and the estimated amounts generated from the sensitivity
analyses are forward-looking statements that involve risks
and uncertainties. Actual results could differ materially from
those projected due to actual developments in the global
markets. The methods used by Hydro to analyze risks discussed
above should not be considered projections of future events,
gains or losses. As of 31
December 2004 Hypothetical loss from +/- 10% change in: Fair value as of
    
    
    Interest
    
    
    Foreign currency
    
    
    CommodityAmounts in NOK million (unaudited)
    
    31 December 2004
    1)
    
    rates
    
    
    exchange rates
    
    
    prices
    
    
    Volatility
    
    
    OtherDerivative financial instruments 2)
    
    
    2,115
    
    
    
    8
    
    
    
    827
    
    
    
    
    
    
    
    
    
    
    
    Other financial instruments 3)
    
    
    1,825
    
    
    
    1,136
    
    
    
    1,442
    
    
    
    
    
    
    
    
    
    
    
    182Derivative commodity instruments
    
    
    (130
    )
    
    
    
    
    
    
    325
    
    
    
    695
    
    
    
    (29
    )
    
    
    
 As of 31
December 2003 Hypothetical loss from +/- 10% change in: Fair value as of
    
    
    Interest
    
    
    Foreign currency
    
    
    CommodityAmounts in NOK million (unaudited)
    
    31 December 2003
    1)
    
    rates
    
    
    exchange rates
    
    
    prices
    
    
    Volatility
    
    
    OtherDerivative financial instruments 2)
    
    
    2,410
    
    
    
    30
    
    
    
    823
    
    
    
    
    
    
    
    
    
    
    
    Other financial instruments 3)
    
    
    (19,880
    )
    
    
    1,870
    
    
    
    2,261
    
    
    
    
    
    
    
    
    
    
    
    57Derivative commodity instruments
    
    
    719
    
    
    
    3
    
    
    
    79
    
    
    
    264
    
    
    
    
    
    
    
    
 1)
    
    The change in fair value due to price changes is calculated based on upon pricing formulas
for certain derivatives, the Black-Scholes model for options and the net present value of cash
flows for certain financial instruments or derivatives. Discount rates vary as appropriate for
the individual instruments.2)
    
    Include mainly forward currency contracts and currency swaps.3)
    
    Include cash and cash equivalents, investments in marketable securities, bank loans and other
interest-bearing short-term debt and long-term debt. A substantial portion of the hypothetical
loss in fair value for changes in interest rates relates to Hydros long-term fixed rate debt.
As Hydro expects to hold this debt until maturity, changes in the fair value of debt would
only impact earnings over time as interest payments fall due.
 105




---



##### 



Use Of Non-Gaap Financial Measures Non-GAAP financial measures are defined in the SEC
regulations as financial measures that either exclude or
include amounts that are not excluded from or included in the
most directly comparable measure calculated and presented in
accordance with GAAP. Adjusted net interest-bearing debt, Adjusted equity
and Adjusted net debt/equity ratio. Hydro refers to
Adjusted net interest-bearing debt and Adjusted net
debt/equity ratio in its discussion of its financial
condition. The Adjusted net debt/equity ratio is comprised
of Adjusted net interest-bearing debt divided by Adjusted
equity. Adjusted net interest-bearing debt is defined as
net interest-bearing debt, plus net unfunded pension
obligations, after tax, and the present value of operating
lease obligations. Net interest-bearing debt is comprised of
interest bearing debt less cash and cash equivalents and Other
liquid assets. Hydros interest bearing debt consists
primarily of long-term debenture bonds which are not readily
repayable. Cash and cash equivalents and Other liquid assets
are therefore accumulated in periods with significant cash
in-flow. Investments, including substantial acquisitions,
have, to a large extent been financed through drawing on
accumulated cash positions. Hydro uses net debt to calculate
the Adjusted net debt/equity ratio in order to reflect the
considerable variances in ability to assume additional debt
from variance cash holdings over time. Net interest bearing
debt is adjusted for the estimated effects of changes to the
fair value of net pension liabilities disclosed but not
recognized. Hydro also adjusts Net interest bearing debt for
liabilities relating to operating lease agreements. Both of
the above described obligations, although not recognized as
liabilities under generally accepted accounting principles,
are considered debt-like in nature and therefore affect
Hydros ability to acquire additional debt. Adjusted equity
consists of equity plus minority interests, less unrecorded
pension liabilities which are not reflected in retained
earnings and therefore excluded from equity under GAAP. The
adjustment is net of expected income tax benefit. No
adjustment to Equity is made for operating lease agreements
because the value of the right to use leased assets is
considered to be similar to the payment obligation. The
adjustments are considered important to measure Hydros
financial position, since market conditions may result in
significant differences between pension liabilities recognized
under generally accepted accounting principles and the fair
value of these liabilities, and because the unrecognized
pension liabilities and leases represent commitments effecting
Hydros financial capacity going forward. The Adjusted
debt/equity ratio is calculated by Hydro using similar
methodology as the major credit rating agencies, and the
company believes it helps the company and investors to
evaluate potential changes in credit rating. Management
believes that Adjusted net interest-bearing debt is a useful
tool for investors and other users of the Companys financial
statements in assessing Hydros financial performance,
including its liquidity and ability to meet obligations with
available cash balances. Management makes regular use of among
others, the Adjusted net debt/equity ratio in its assessment
of Hydros financial stability and ability to incur new debt.
Management believes that this ratio provides useful
information to readers of Hydros financial statements and
helps them to assess the effect of pension liabilities and
operating lease commitments that are otherwise not apparent
when analyzing the Companys financial statements prepared in
accordance with GAAP. However, this measure does not recognize
the fact that cash may not be available for debt repayments,
but may be required for operational needs including tax
payments of periodic results, contractual obligations or
necessary investments. Adjusted net interest-bearing debt,
Adjusted equity and Adjusted net debt/equity ratio are
presented in the table below. Management believes that the most directly comparable
GAAP ratio is the Debt/equity ratio. However, this ratio
measures gross interest bearing debt relative to equity, i.e.
it does not measure changes in cash position, and is
therefore not directly comparable with the non-GAAP measure
Adjusted net debt/equity ratio. Hydro managements use of the described non-GAAP measures
should not be construed as an alternative to Debt/equity
ratio, gross debt and statements of cash flows in accordance
with generally accepted accounting principles when evaluating
Hydros financial condition. Management carefully reviews the
appropriateness of adjustments to the GAAP figures, and also makes regular
use of measures calculated according to generally accepted
accounting principles in addition to Adjusted net
interest-bearing debt and Adjusted net debt/equity ratio
when measuring financial condition. Return on average Capital
Employed (RoaCE) In this Report, Hydro refers to certain non-GAAP
financial measures, which are an integral part of Hydros
steering model. These non-GAAP financial measures are:  
    Return on average Capital Employed (RoaCE)  
    Earnings after tax  
    Capital Employed Hydros management makes regular use of these indicators to
measure performance for the group as a whole and within its
operating segments, both in absolute terms and comparatively
from period to period. Management views these measures as
providing additional understanding, - for management and for
investors -, of:  
    The rate of return on investments over time, in
each of its capital intensive businesses  
    The operating results of its business segments  
    Cash flow generation of its business segments Because Hydro is subject to significantly different tax
regimes in its operating segments, e.g. Norwegian surtax on
petroleum and power production, management believes financial
performance must also be measured on an after tax basis, in
order to achieve comparability between Hydros operating
segments. RoaCE is defined as Earnings after tax divided by
average Capital Employed. Earnings after tax is defined as
Operating income plus Equity in net income of
non-consolidated investees plus Other income, net less
Adjusted income tax expense. Because RoaCE represents the
return to the capital providers before dividend and interest
payments, adjusted income tax expense included in Earnings
after tax does not include the tax effect of items reported
as Financial income and expense. Capital Employed is
defined as Shareholders Equity plus Minority interest
plus long-term and short-term interest-bearing debt less
Cash and cash equivalents and Other liquid assets. Capital
Employed can be derived by deducting Cash and cash
equivalents, Other liquid assets and Short-term and
long-term interest 106




---



##### 



free liabilities (including deferred tax
liabilities) from Total assets. The two different approaches
yield the same value. In order to calculate Earnings after
tax for the Companys operating segments, an imputed tax is
calculated for each segment. An adjusted income tax expense is
calculated as Operating income and Other income, net
multiplied by an applicable tax rate. For most operating
segments the applicable tax rate is estimated at 35 percent.
Oil and Energy businesses are subject to various tax regimes
including Norwegian surtax on petroleum and power production.
To calculate tax effects for these business units applicable
statutory tax rates based on the source of income are applied.
For the Group as a whole, Adjusted Income tax expense is
calculated as US GAAP Income tax expense less tax effects
relating to items reported as Financial income and expense. Hydro believes that RoaCE facilitates benchmarking of the
Company with its peers. It is important to note however, that
RoaCE is, similar to all other financial metrics, influenced
by a companys selection of acceptable accounting principles
which can result in significant differences when comparing
RoaCE for different companies applying different GAAPs. This
is particularly important when comparing companies with an
active acquisition history. RoaCE should not be construed as an alternative to
operating income, income before taxes and net income as an
indicator of Hydros results of operations in accordance with
generally accepted accounting principles. Hydros management
make regular use of measures calculated according to
generally accepted accounting principles in addition to non-GAAP financial
measures described above when measuring financial
performance. Hydro also measures RoaCE based on long-term price
assumptions, referred to as normalized prices. Normalized
prices are used in order to avoid placing undue emphasis on
such variables as historically high or low prices of its
commodity products, and the effects of changes in currency
exchange rates. As described more fully in the Risk Management
section of this Financial Review, the development of the
Companys results are primarily affected by the price
developments of Hydros main products, oil and aluminium, in
addition to the US dollar and Euro exchange rates against the
Norwegian kroner. For the purpose of calculating RoaCE on a
normalized basis the following assumptions are used :  
    Oil price 25 US dollar per barrel  
    Aluminium price (London Metal Exchange) 1,500 US dollar per tonne  
    US dollar - Norwegian kroner exchange rate 7.00  
    Euro - Norwegian kroner exchange rate 8.00  
    In addition, items reported as Other income, net and
Restructuring costs according to generally accepted
accounting principles are excluded when calculating
normalized RoaCE. Hydros management views normalization as a tool to
measure underlying financial performance consistently over time
and against the Groups business plans that are prepared
according to the price assumptions described above for each
financial year. By keeping certain main commodity prices and
exchange rates constant, Hydro increases the focus on operating
costs and efficiency improvements. Such a focus would be more
challenging to maintain in periods with high commodity prices
and favorable exchange rates. Other income, net  has two main
components, consisting of gains and losses related to sale of
operations or major assets and certain infrequent items. Gains
and losses on sale of operations or major assets are excluded
because they do not relate to ongoing operations. By excluding
these items, Hydro increases the focus on the results of
ongoing operations such as changes in efficiency and other
operational factors. For the three year period, one infrequent
item was included in Other income, net; the effect of a
change in the Norwegian tax regulations relating to the removal
costs for oil and gas installations on the Norwegian
continental shelf. This item had a substantial effect on Other
income, net as described more fully in footnote 9 to the
Consolidated Financial Statements. The change in regulation was
a major amendment to the system regulating removal of oil and
gas installations in Norway. The previous regulations had been
in place from 1986. Restructuring costs are only incurred
relating to major changes in the business. The most recent
restructuring charge was incurred in 2001, with adjustments to
the estimates in the following periods. These items are
excluded because they are infrequent in nature and could result
in an incorrect picture of the underlying development in
financial performance. During the 2000 to 2004 period Hydro has
employed normalization as a tool in measuring financial
performance. Normalization has resulted, on average, in lower
normalized earnings compared to earnings based on realized
prices. Normalization for certain commodity and exchange rates
is most relevant for Hydros upstream oil and gas business and
the Companys upstream aluminium production. For other parts
of Hydros business, which are more margin based, normalization
for commodity prices is less important and the difference
between actual and normalized RoaCE will be smaller. Normalized
results should not be construed as  alternative to measuring
financial performance based upon realized commodity prices and
exchange rates. Hydros management reviews both realized
results and normalized results. Management makes regular use of
both normalized results and ratios to compare with business
plans; for period-over-period comparisons; and in comparison
with actual results and ratios. Typically, normalized results
receive more attention when realized prices and exchange rates
are above the normalized price assumptions. For an overview of
how Hydro manages commodity price risk and foreign currency
exchange rate risk please refer to the Risk Management section
of the Financial Review included in Hydros Annual Report. In
order to illustrate the effects of certain major events on
RoaCE, both the actual RoaCE and normalized RoaCE have also
been calculated excluding such events. For 2004, the write-down of German
metal plants (affecting the Group and Aluminium), and the
change in tax law in Norway (affecting the Group) have been
excluded for this purpose. Excluding such items from RoaCE
should not be considered as an adjustment of the metric for
these effects but rather as supplemental information to
demonstrate how these events affects RoaCE. 107




---



##### 



Adjusted Net interest-bearing debt to equity December 31
    
    
    December 31NOK million
    
    2004
    
    
    2003Cash and cash equivalents
    
    
    14,366
    
    
    
    14,873Other liquid assets
    
    
    10,970
    
    
    
    1,553Bank loans and other interest-bearing short-term debt
    
    
    (3,785
    )
    
    
    (5,273
    )Current portion of long-term debt
    
    
    (568
    )
    
    
    (1,212
    )Long-term debt
    
    
    (19,487
    )
    
    
    (28,403
    )Net interest-bearing debt discontinued operations
    
    
    
    
    
    
    (86
    )Net interest-bearing debt
    
    
    1,496
    
    
    
    (18,548
    )Net pension liabilities at fair value
    
    
    (10,056
    )
    
    
    (11,974
    )Expected income tax benefit on pension liability 30%
    
    
    3,017
    
    
    
    3,592Operating leases commitments discounted at 10%
    
    
    (3,500
    )
    
    
    (4,916
    )Adjusted Net Interest-bearing debt
    
    
    (9,043
    )
    
    
    (31,846
    )Shareholders equity
    
    
    (85,890
    )
    
    
    (88,080
    )Minority interest
    
    
    (1,571
    )
    
    
    (660
    )Shareholders equity and minority interests
    
    
    (87,461
    )
    
    
    (88,740
    )Net pension
liabilities not recognized without equity effect
    
    
    6,341
    
    
    
    7,863Expected income tax benefit 30%
    
    
    (1,902
    )
    
    
    (2,359
    )Equity adjustment off-balance sheet pension liabilities
    
    
    4,439
    
    
    
    5,504Adjusted Shareholders equity and minority interests
    
    
    (83,022
    )
    
    
    (83,236
    )Adjusted net debt/equity ratio
    
    
    0.11
    
    
    
    0.38
 The most directly comparable GAAP figure is considered to be Debt/equity ratio. However, this ratio measures gross debt relative to
equity, and does not measure changes in cash position, and the non-GAAP measure Adjusted debt/equity ratio is therefore not directly
comparable. Debt/equity ratio
    
    
    0.28
    
    
    
    0.40
 108




---



##### 



Return on average Capital
Employed - Hydro Year ended
    
    
    Year ended
    
    
    Year endedAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Income
    
    
    31,847
    
    
    
    21,625
    
    
    
    17,667Equity in net income of non-consolidated investees
    
    
    628
    
    
    
    620
    
    
    
    (24
    )Other income/expense, net
    
    
    169
    
    
    
    (1,253
    )
    
    
    77Earnings before tax
    
    
    32,644
    
    
    
    20,992
    
    
    
    17,720Adjusted Income tax expense
    
    
    (21,165
    )
    
    
    (13,224
    )
    
    
    (11,589
    )Earnings after tax
    
    
    11,479
    
    
    
    7,768
    
    
    
    6,131
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Current assets 1)
    
    
    45,070
    
    
    
    45,468
    
    
    
    46,914
    
    
    
    37,480Non-consolidated investees
    
    
    10,017
    
    
    
    10,162
    
    
    
    9,410
    
    
    
    7,168Property, plant and equipment
    
    
    106,117
    
    
    
    107,779
    
    
    
    105,251
    
    
    
    87,205Prepaid pension, investments and
other non-current assets 2)
    
    
    13,703
    
    
    
    13,228
    
    
    
    15,585
    
    
    
    11,612Other current liabilities 3)
    
    
    (41,724
    )
    
    
    (37,725
    )
    
    
    (34,359
    )
    
    
    (28,328
    )Other long-term liabilities 4)
    
    
    (47,218
    )
    
    
    (48,083
    )
    
    
    (49,033
    )
    
    
    (38,594
    )Capital Employed
    
    
    85,965
    
    
    
    90,829
    
    
    
    93,768
    
    
    
    76,543
 2004
    
    
    2003
    
    
    2002Return on average Capital Employed (RoaCE)
    
    
    13.0
    %
    
    
    8.4
    %
    
    
    7.2
    %
 Year ended
    
    
    Year ended
    
    
    Year endedAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Reported Earnings before tax
    
    
    32,644
    
    
    
    20,992
    
    
    
    17,720Normalization Other income
    
    
    (169
    )
    
    
    1,253
    
    
    
    (77
    )Normalization Restructuring costs
    
    
    (22
    )
    
    
    
    
    
    
    (10
    )Normalization Price and currency
    
    
    (13,328
    )
    
    
    (6,146
    )
    
    
    (1,761
    )Normalized Earnings before tax
    
    
    19,125
    
    
    
    16,099
    
    
    
    15,872Normalized Income tax expense
    
    
    (11,905
    )
    
    
    (10,165
    )
    
    
    (9,988
    )Normalized Earnings after tax
    
    
    7,220
    
    
    
    5,934
    
    
    
    5,884
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Reported Capital Employed
    
    
    85,965
    
    
    
    90,829
    
    
    
    93,768
    
    
    
    76,543Normalization currency rates (translation effects)
    
    
    1,279
    
    
    
    (1,105
    )
    
    
    5,085
    
    
    
    (1,705
    )Normalization current tax payable
    
    
    5,101
    
    
    
    1,654
    
    
    
    989
    
    
    
    3,162Normalized Capital Employed
    
    
    92,345
    
    
    
    91,378
    
    
    
    99,842
    
    
    
    78,000
 2004
    
    
    2003
    
    
    2002Normalized Return on average Capital Employed (RoaCE)
    
    
    7.9
    %
    
    
    6.2
    %
    
    
    6.6
    %
 1)
    
    Excluding Cash and cash equivalents and Other liquid assets,
but including Deferred tax assets2)
    
    Including Deferred tax assets3)
    
    Including Deferred tax liabilities4)
    
    Including Accrued pension liabilities and Deferred tax
liabilities
 109




---



##### 



Return on average Capital
Employed - Oil and Energy Year ended
    
    
    Year ended
    
    
    Year endedAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Income
    
    
    31,144
    
    
    
    21,143
    
    
    
    15,947Equity in net income of non-consolidated investees
    
    
    75
    
    
    
    107
    
    
    
    179Other income/expense, net
    
    
    59
    
    
    
    816
    
    
    
    77Earnings before tax
    
    
    31,278
    
    
    
    22,066
    
    
    
    16,203Adjusted Income tax expense
    
    
    (22,051
    )
    
    
    (15,089
    )
    
    
    (11,316
    )Earnings after tax
    
    
    9,227
    
    
    
    6,977
    
    
    
    4,887
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Current assets 1)
    
    
    15,545
    
    
    
    16,017
    
    
    
    21,213
    
    
    
    12,979Non-consolidated investees
    
    
    2,347
    
    
    
    2,406
    
    
    
    1,991
    
    
    
    2,095Property, plant and equipment
    
    
    73,437
    
    
    
    74,460
    
    
    
    73,223
    
    
    
    70,146Prepaid pension, investments and
other non-current assets 2)
    
    
    4,392
    
    
    
    3,903
    
    
    
    4,199
    
    
    
    3,909Other current liabilities 3)
    
    
    (23,208
    )
    
    
    (18,829
    )
    
    
    (22,520
    )
    
    
    (15,718
    )Other long-term liabilities 4)
    
    
    (35,985
    )
    
    
    (35,628
    )
    
    
    (34,554
    )
    
    
    (32,988
    )Capital Employed
    
    
    36,528
    
    
    
    42,329
    
    
    
    43,552
    
    
    
    40,423
 2004
    
    
    2003
    
    
    2002Return on average Capital Employed (RoaCE)
    
    
    23.4
    %
    
    
    16.2
    %
    
    
    11.6
    %
 Year ended
    
    
    Year ended
    
    
    Year endedAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Reported Earnings before tax
    
    
    31,278
    
    
    
    22,066
    
    
    
    16,203Normalization Other income
    
    
    (59
    )
    
    
    (816
    )
    
    
    (77
    )Normalization Price and currency
    
    
    (12,531
    )
    
    
    (4,103
    )
    
    
    (2,352
    )Normalized Earnings before tax
    
    
    18,688
    
    
    
    17,147
    
    
    
    13,774Normalized Income tax expense
    
    
    (13,121
    )
    
    
    (12,013
    )
    
    
    (9,674
    )Normalized Earnings after tax
    
    
    5,567
    
    
    
    5,134
    
    
    
    4,100
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Reported Capital Employed
    
    
    36,528
    
    
    
    42,329
    
    
    
    43,552
    
    
    
    40,423Normalization currency rates (translation effects)
    
    
    199
    
    
    
    30
    
    
    
    1,420
    
    
    
    (212
    )Normalization current tax payable
    
    
    4,771
    
    
    
    1,711
    
    
    
    1,039
    
    
    
    2,894Normalized Capital Employed
    
    
    41,498
    
    
    
    44,070
    
    
    
    46,011
    
    
    
    43,105
 2004
    
    
    2003
    
    
    2002Normalized Return on average Capital Employed (RoaCE)
    
    
    13.0
    %
    
    
    11.4
    %
    
    
    9.2
    %
 1)
    
    Excluding Cash and cash equivalents and Other liquid assets,
but including Deferred tax assets2)
    
    Including Deferred tax assets3)
    
    Including Deferred tax liabilities4)
    
    Including Accrued pension liabilities and Deferred tax
liabilities
 110




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##### 



Return on average Capital
Employed - Aluminium Year ended
    
    
    Year ended
    
    
    Year endedAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Operating Income
    
    
    1,805
    
    
    
    2,456
    
    
    
    1,698Equity in net income of non-consolidated investees
    
    
    381
    
    
    
    433
    
    
    
    (219
    )Other income/expense, net
    
    
    
    
    
    
    
    
    
    
    Earnings before tax
    
    
    2,186
    
    
    
    2,889
    
    
    
    1,479Adjusted Income tax expense
    
    
    (632
    )
    
    
    (860
    )
    
    
    (594
    )Earnings after tax
    
    
    1,554
    
    
    
    2,029
    
    
    
    885
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Current assets 1)
    
    
    24,371
    
    
    
    22,860
    
    
    
    21,715
    
    
    
    15,993Non-consolidated investees
    
    
    5,457
    
    
    
    5,787
    
    
    
    4,902
    
    
    
    3,288Property, plant and equipment
    
    
    28,696
    
    
    
    29,504
    
    
    
    26,496
    
    
    
    11,770Prepaid pension, investments and
other non-current assets 2)
    
    
    4,306
    
    
    
    4,849
    
    
    
    5,212
    
    
    
    3,723Other current liabilities 3)
    
    
    (14,699
    )
    
    
    (12,831
    )
    
    
    (10,566
    )
    
    
    (8,587
    )Other long-term liabilities 4)
    
    
    (4,693
    )
    
    
    (5,316
    )
    
    
    (5,782
    )
    
    
    (1,632
    )Capital Employed
    
    
    43,438
    
    
    
    44,853
    
    
    
    41,977
    
    
    
    24,555
 2004
    
    
    2003
    
    
    2002Return on average Capital Employed (RoaCE)
    
    
    3.5
    %
    
    
    4.7
    %
    
    
    2.7
    %
 Year ended
    
    
    Year ended
    
    
    Year endedAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002Reported Earnings before tax
    
    
    2,186
    
    
    
    2,889
    
    
    
    1,479Normalization Other income
    
    
    
    
    
    
    
    
    
    
    Normalization Restructuring costs
    
    
    (22
    )
    
    
    
    
    
    
    (10
    )Normalization Price and currency
    
    
    (1,215
    )
    
    
    (300
    )
    
    
    (99
    )Normalized Earnings before tax
    
    
    949
    
    
    
    2,589
    
    
    
    1,370Normalized Income tax expense
    
    
    (256
    )
    
    
    (760
    )
    
    
    (395
    )Normalized Earnings after tax
    
    
    693
    
    
    
    1,829
    
    
    
    975
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2004
    
    
    2003
    
    
    2002
    
    
    2001Reported Capital Employed
    
    
    43,438
    
    
    
    44,853
    
    
    
    41,977
    
    
    
    24,555Normalization currency rates (translation effects)
    
    
    1,297
    
    
    
    (571
    )
    
    
    2,736
    
    
    
    (1,573
    )Normalization current tax payable
    
    
    409
    
    
    
    99
    
    
    
    199
    
    
    
    244Normalized Capital Employed
    
    
    45,144
    
    
    
    44,381
    
    
    
    44,912
    
    
    
    23,226
 2004
    
    
    2003
    
    
    2002Normalized Return on average Capital Employed (RoaCE)
    
    
    1.5
    %
    
    
    4.1
    %
    
    
    2.9
    %
 1)
    
    Excluding Cash and cash equivalents and Other liquid assets,
but including Deferred tax assets2)
    
    Including Deferred tax assets3)
    
    Including Deferred tax liabilities4)
    
    Including Accrued pension liabilities and Deferred tax
liabilities
 111




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##### 



Effect on RoaCE of major events Actual RoaCE adjusted for major write downs and change in tax regulations in Norway Hydro
    
    
    AluminiumYear Ended
    
    
    Year EndedAmounts in NOK million
    
    2004
    
    
    2004Earnings after tax
    
    
    11,479
    
    
    
    1,554Adjustment for Write down after tax and change in tax regulation
    
    
    606
    
    
    
    1,595Adjusted Earnings after tax
    
    
    12,085
    
    
    
    3,149
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 December2004
    
    
    2003
    
    
    2004
    
    
    2003Capital Employed
    
    
    85,965
    
    
    
    90,829
    
    
    
    43,438
    
    
    
    44,853Adjustment for write down after tax and change in tax regulation
    
    
    680
    
    
    
    
    
    
    
    1,595
    
    
    
    Adjusted Capital Employed
    
    
    86,645
    
    
    
    90,829
    
    
    
    45,033
    
    
    
    44,853
 2004
    
    
    2004RoaCE adjusted for write down and change in tax regulation
    
    
    13.6
    %
    
    
    7.0
    %
 Normalized RoaCE adjusted for major write downs and change in tax regulations in Norway Hydro
    
    
    AluminiumYear Ended
    
    
    Year EndedAmounts in NOK million
    
    2004
    
    
    2004Normalized Earnings after tax
    
    
    7,220
    
    
    
    693Adjustment for Write down after tax and change in tax regulation
    
    
    606
    
    
    
    1,595Adjusted Normalized Earnings after tax
    
    
    7,826
    
    
    
    2,288
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 December2004
    
    
    2003
    
    
    2004
    
    
    2003Normalized Capital Employed
    
    
    92,345
    
    
    
    91,378
    
    
    
    45,144
    
    
    
    44,381Adjustment for write down after tax and change in tax regulation
    
    
    680
    
    
    
    
    
    
    
    1,595
    
    
    
    Adjusted Normalized Capital Employed
    
    
    93,025
    
    
    
    91,378
    
    
    
    46,739
    
    
    
    44,381
 2004
    
    
    2004Normalized RoaCE adjusted for write down
    
    
    8.5
    %
    
    
    5.0
    %
 112




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##### 



ITEM 6. DIRECTORS, SENIOR MANAGERS AND EMPLOYEES 
 ITEM 6.A. DIRECTORS, CORPORATE ASSEMBLY AND CORPORATE MANAGEMENT BOARD The Company is a public limited company organized under Norwegian law and the Groups
governance structure is based on Norwegian corporate law. Norwegian corporate law has been revised
in recent years to, among other things, clarify areas of responsibility of the board of directors
of a Norwegian company. Corporate Assembly In accordance with Norwegian law, Hydro has established a Corporate Assembly. Hydros
Corporate Assembly currently consists of 18 members, of which the annual general meeting of
shareholders has elected 12 members and, according to Norwegian legislation, the employees of
Hydros Norwegian companies have elected six members (i.e., one-third of the Corporate Assemblys
members). The annual general meeting of shareholders and the
employees have elected alternates in 2004. In
addition, the employees have elected three observers. The arrangement
for employee elected observers will be terminated from May 2005. Under Norwegian companies law, the members of the Corporate Assembly have a fiduciary duty to
the Company and the Companys shareholders. Such fiduciary duty requires that the Corporate
Assembly act in the Companys best interests when exercising their functions and exercise a general
duty of loyalty and care towards the Company. The Corporate Assembly communicates to the annual general meeting its recommendations
concerning the Board of Directors proposals about Hydros yearly accounts, and dividend
distribution. The Corporate Assembly elects the members of the Companys Board of Directors and
nominates the external auditor. Upon the recommendation of the Board, the Corporate Assembly adopts
resolutions in matters concerning investments that are substantial in relation to Hydros
resources, or concerning such rationalization of, or changes in, operations as will entail a major
change in or redeployment of the labor force. The Corporate Assembly met three times in 2004. Each member or deputy member and observer of
the Corporate Assembly was paid NOK 5,000 per meeting attended. The Chairperson and the Vice
Chairperson of the Corporate Assembly were paid an additional NOK 75,000 and NOK 37,500,
respectively, for serving in such capacities in 2004. The names of the current members of Hydros
Corporate Assembly, as well as the deputy members and observers, are listed in Exhibit 99.1 to this
annual report. 113




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##### 



Nomination Committee The Companys articles of association (the Articles of Association) provide for a nomination
committee (the Nomination Committee). The Nomination Committee consists of the Chairperson of the
Corporate Assembly, two members elected directly by the shareholders and one member elected by and
among the shareholders representatives in the Corporate Assembly. The Nomination Committee
nominates candidates to the Corporate Assembly to be elected by the shareholders at the annual
general meeting, and candidates to the Companys Board of Directors to be elected by the
shareholder-elected members of the Corporate Assembly. The Nomination Committee operates under a
charter established by the shareholders representatives in the Corporate Assembly. The Nomination
Committee held seven meetings in 2004. The Nomination Committee currently consists of four members:
Svein Steen Thomassen (Chairperson), Westye Høegh, Reier Søberg, and Siri Teigum. Board of Directors The Companys management is vested in its Board of Directors and its President and Chief
Executive Officer. In accordance with Norwegian corporate law, the Board of Directors has the
overall responsibility for management of the Company, while the President and CEO is responsible
for day-to-day management. The Board supervises day-to-day management as carried out by the
President and CEO and the activities of the Company in general, as well as ensuring that
appropriate steering and control systems are in place. The Boards internal rules of procedure were
amended in 2001, and further revised in 2003, to clarify the Boards role in relation to the
management of the Company as well as the other corporate bodies. The President and CEOs authority
and responsibilities were defined in greater detail to allow the Board of Directors to concentrate
on the Companys strategy and organization, while Board committees have been established to prepare
matters for which the Board is responsible. The Companys Articles of Association require that the Board consist of nine members who are
nominated and elected by the Corporate Assembly. The shareholder representatives in the Corporate
Assembly elect six Board members; the employee representatives in the Corporate Assembly, three
Board members. Neither the President and CEO nor any other member of the Companys executive
management is a member of the Companys Board. The Board of Directors held twelve meetings in 2004. Information about each member of the Board of Directors, his or her place of residence, age,
position on the Board and Board committees, year in which his or her term expires, the period
during which the Board member has served as such, and business experience outside of the Company
(including directorships in other companies) is presented in the table below or in the biographical
information which follows: Name
    
    
    Place of Residence
    
    
    Age
    
    
    Position
    
    
    Term ExpiresJan Reinås (1)
    
    
    Oslo, Norway
    
    
    
    60
    
    
    
    Chairperson
    
    
    
    2006Borger A. Lenth
    
    
    Koppang, Norway
    
    
    
    67
    
    
    
    Deputy Chairperson
    
    
    
    2006Elisabeth Grieg
    
    
    Oslo, Norway
    
    
    
    45
    
    
    
    Director
    
    
    
    2006Håkan Mogren
    
    
    Stockholm, Sweden
    
    
    
    60
    
    
    
    Director
    
    
    
    2006Ingvild R. Myhre
    
    
    Oslo, Norway
    
    
    
    47
    
    
    
    Director
    
    
    
    2006Kurt Anker Nielsen (2)
    
    
    Copenhagen, Denmark
    
    
    
    59
    
    
    
    Director
    
    
    
    2006Geir Nilsen (3)
    
    
    Skien, Norway
    
    
    
    49
    
    
    
    Director
    
    
    
    2005Odd Semstrøm (3)
    
    
    Øvre Årdal, Norway
    
    
    
    60
    
    
    
    Director
    
    
    
    2005Terje Friestad (3),(4)
    
    
    Skudeneshavn, Norway
    
    
    
    52
    
    
    
    Director
    
    
    
    2005
   (1)
    
    The Corporate Assembly elected Mr. Reinås to the Board and appointed him as
Chairperson on 16 March 2004, with effect from 25 March 2004. Mr. Reinås succeeded Egil
Myklebust, who announced in November 2003 that he would not stand for re-election to
Hydros Board of Directors when his term expired in 2004.(2)
    
    Elected by the Corporate Assembly 13 May 2004 to succeed Anne Cathrine Høeg
Rasmussen.(3)
    
    Elected by the employee representatives in the Corporate Assembly.(4)
    
    The Corporate Assembly elected Mr. Friestad to the Board on 16 March 2004, with
effect from 25 March 2004. Mr. Friestad succeeded Steinar Skarstein, who stepped down from
the Board at the time of completion of the Agri demerger. 114




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##### 



Jan Reinås. Mr. Reinås has served as Chairperson of the Board since 25 March 2004. Mr.
Reinås served as the Chief Executive Officer of the paper group, Norske Skog, from 1994 until the
end of 2003. He had previously served as the Chief Executive Officer of Scandinavian Airlines. Mr.
Reinås currently serves on the Board of Directors of the media group, Schibsted ASA, and Swiss
International Air Lines. Mr. Reinås serves as the Chairperson of the Boards Compensation
Committee. Borger A. Lenth. Mr. Lenth served as a director from 1990 to 1992, has served as a director
from 1998, and has been the Deputy Chairperson of the Board since 2 May 2001. Mr. Lenth practices
as a lawyer. Previously, from 1991 to 1997, Mr. Lenth
was Chief Executive Officer of Christiania Bank. He has also had the position of Permanent
Secretary in the Ministry of Development Corporation. Mr. Lenth is currently also Chairman of the
Board of Treschow Fritzøe AS and Bolig og Næringsbanken ASA, and Deputy Chairman of the Board of
Directors of Kommunal Landspensjonskasse (KLP) and Norfund. Mr. Lenth serves as the Chairperson of
the Boards Audit Committee. Elisabeth Grieg. Ms. Grieg has served as a director since 2001. Ms. Grieg, who is the co-owner
of the Grieg Group, is the Chief Executive Officer of Grieg International AS. She is also a member
of the Board of Directors of the Norwegian Shipowners Association, Star Shipping, Grieg
International and Grieg Maturitas, a member of the DnV Council and a member of the corporate
assembly of Orkla ASA. Ms. Grieg serves on the Boards Audit Committee. Håkan Mogren. Mr. Mogren has served as a director since 2001. Mr. Mogren served as Chief
Executive Officer of Astra AB from 1988 to 1999. Mr. Mogren is Chairman of Affibody AB, Deputy
Chairman of AstraZeneca PLC, and of Gambro AB, a member of the Board of Directors of Investor AB,
Rémy Cointreau SA, the Swedish-American Foundation and the Group Danone, and a director for the
Marianne and Marcus Wallenberg Foundation. Mr. Mogren is a Swedish national. Mr. Mogren serves on
the Boards Compensation Committee. Ingvild R. Myhre. Ms. Myhre has served as a director since 2001. Ms. Myhre is currently
Director of the Norwegian Red Cross. She is also the Deputy Chairperson of the Norwegian Defense
Research Establishment, a member of the Board of Directors of Flytoget AS, the Research Park in
Narvik, Norges Handels- og Sjøfartstidende/ Dagens Næringsliv, Telecomputing and Folketrygdfondet.
Ms. Myhre serves on the Boards Compensation Committee. Kurt Anker Nielsen. Mr. Nielsen has served as a director since 13 May 2004. Mr. Nielsen served
as co-Chief Executive Officer of Novo A/S, a focused healthcare company and a world
leader in diabetes care, from 2000 to 2003 and as Chief Financial Officer of Novo Nordisk A/S from
1989 to 2000. Mr. Nielsen is a member of the Board of Directors of Novo Nordisk A/S, Novozymes A/S,
Novo A/S, DakoCytomation A/S, ZymoGenetics Inc, Coloplast A/S and TDC A/S. Mr. Nielsen is a Danish
national. Mr. Nielsen serves on the Boards Audit Committee. Geir Nilsen. Mr. Nilsen has served as a director since 2003. He is currently employed by Hydro
as a maintenance supervisor. He represents the employees union, LO, where he is a full time union
official. Odd Semstrøm. Mr. Semstrøm has served as a director since 1997. Mr. Semstrøm represents the
employees union, LO, where he is a full time union official. Mr. Semstrøm is an electrician and is
based at Hydros aluminium plant in Årdal. 115




---



##### 



Terje Friestad.Mr. Friestad has served as a director since 25 March 2004. Mr. Friestad
represents the employees union, NITO, and he is currently employed as a Senior Engineer in Hydro
Aluminium, Karmøy. Mr. Friestad serves on the Boards Audit Committee. President and CEO and Corporate Management Board The President and CEO constitutes a formal corporate body according to Norwegian corporate
law. The President and CEO is responsible for day-to-day management of Hydro in accordance with
legislation and the instructions, policies and operating guidelines set out by Hydros Board of
Directors. A corporate management board is not required under Norwegian corporate law, but Hydros
President and CEO has, in accordance with rules of procedure established by Hydros Board of
Directors, established a corporate management board (the Corporate Management Board) to assist
him in discharging specialized management tasks. The Corporate Management Board consists of the
Executive Vice Presidents for Oil and Energy, and Aluminium, in addition to the Executive Vice
President and Chief Financial Officer, and the Executive Vice President  Leadership and Culture.
The members of the Corporate Management Board have a collective duty to promote Hydros strategic,
financial and other objectives, as well as to safeguard Hydros assets, organization and
reputation. The Corporate Management Board convenes at least once a week. No member of Hydros Board of Directors or the Corporate Management Board has any family
relationship with any other director or member of the Corporate Management Board. Information concerning each member of the Corporate Management Board, as of 14 February 2005,
including his or her age and position, and brief background information regarding his or her
business experience is presented below: Name
    
    
    Place of residence
    
    
    Age
    
    
    PositionEivind Reiten
    
    
    Oslo, Norway
    
    
    
    51
    
    
    
    President and Chief Executive OfficerJohn Ove Ottestad
    
    
    Lierskogen, Norway
    
    
    
    55
    
    
    
    Executive Vice President and Chief Financial OfficerAlexandra Bech Gjørv
    
    
    Oslo, Norway
    
    
    
    39
    
    
    
    Executive Vice PresidentTore Torvund
    
    
    Oslo, Norway
    
    
    
    53
    
    
    
    Executive Vice PresidentJon-Harald Nilsen
    
    
    Oslo, Norway
    
    
    
    53
    
    
    
    Executive Vice President
 Eivind Reiten. Mr. Reiten succeeded Egil Myklebust as President and Chief Executive Officer of
Hydro, effective from 2 May 2001. From 1999 to the date of his appointment as President and CEO,
Mr. Reiten served as Executive Vice President for Hydros Light Metals business area. From 1996 to
1998, he served as President of Hydro Aluminium Metal Products. From 1992 to 1996, he served as
President of Hydros Refining and Marketing Division. From 1991 to 1992, he served as Senior Vice
President, Special Projects. From 1988 to 1990, he served as President of the Energy Division,
following a two-year period as manager, and later Vice President for Hydro Agri. From 1990 to 1991,
he had the position of Minister of Petroleum and Energy in the Norwegian government. During the
seven-year period from 1979 to 1986, Mr. Reiten held several governmental posts including Junior
Executive Officer in the Ministry of Fisheries and Secretary to the Center Partys Parliamentary
Group and State Secretary, Ministry of Finance and Minister of Fisheries. Mr. Reiten graduated from
the University of Oslo in 1978 with a degree in economics. John Ove Ottestad. Mr. Ottestad has served as Executive Vice President and Chief Financial
Officer since 1 March 2002. Employed at Hydro since 1975, Mr. Ottestad has held numerous positions.
Mr. Ottestad served as Senior Vice President for Mergers and Acquisitions from 1999 to 2002, as
President of Hydros Refining and Marketing Division from 1996 to 1999, as President of Hydros
Magnesium Division from 1988 to 1996, and as President of Hydro Innovation from 1985 to 1987.
Between 1975 and 1985, Mr. Ottestad served as Director for Corporate Strategic Planning, as a
manager
in Corporate Financial Planning and as an engineer in the Oil and Gas Division. Mr. Ottestad
also 116




---



##### 



served two years as an EDP scientist with the Norwegian Research Foundation, SINTEF. Mr.
Ottestad graduated from the Norwegian Institute of Technology in 1973 with a degree in physics. Alexandra Bech Gjørv. Ms. Gjørv has served as Executive Vice President since 15 January 2002.
Ms. Gjørv joined Hydro in New York in 1993 as the legal counsel for Hydros U.S. subsidiaries.
Since then, she has served as Company Secretary from 1995 to 1998 and as Vice President of Strategy
and Organization in Hydros Automotive Structures division from 1998 to 2000 and Senior Vice
President of Corporate Human Resources from 2000 to 2002. Ms. Gjørv received a Bachelor of Law
degree from the University of Oslo and a diploma in legal studies from Oxford University. She was
admitted to the bar in the State of New York, United States in 1994. Tore Torvund. Mr. Torvund has served as Executive Vice President for Hydros Oil and Energy
area since January 2000. From 1996 to the date of his appointment as Executive Vice President, Mr.
Torvund served as Senior Vice President with responsibility for all exploration and production
activities in Norway, and from 1992 to 1996, he had responsibility for Hydros operations on the
Norwegian Continental Shelf. Between 1990 and 1992, he served as Vice President for drilling
operations, and from 1982-1990 he held different management positions within the Exploration &
Production Division related to a North Sea field development project. From 1977 to 1982, Mr.
Torvund worked for the French oil company, Elf Aquitaine, where he was involved with oil and gas
projects. Mr. Torvund received an MSc in petroleum engineering from the Norwegian Institute of
Technology in 1976. Jon-Harald Nilsen. Mr. Nilsen has served as Executive Vice President of Hydro Aluminium since
15 February 12001. Mr. Nilsen had previously served as President of Hydro Aluminium Metal Products
from 1999 to 2001, following seven years as Senior Vice President of various areas within the Hydro
Aluminium Metal Products group. From 1985 to 1988, Mr. Nilsen was Hydros Market/Product Director
and held various managerial positions in financial planning and control for the Oseberg project
from 1982 to 1985, and financial and market projects in Hydros Aluminium from 1977 to 1982, and as
an Assistant Export Manager for Bergensmeieriet from 1975 to 1977. Mr. Nilsen graduated from the
Norwegian School of Economics and Business Administration in 1975. 
 ITEM 6.B. COMPENSATION In 2004, total remuneration of NOK 2,362,000 was paid to the members of Hydros Board of
Directors for serving in their capacities as Board members, NOK 393,500 to the members of the
Corporate Assembly, NOK 50,000 to the members of the Nomination Committee, NOK 43,000 to the
members of the Boards Compensation Committee and NOK 191,000 to the members of the Boards Audit
Committee. See Item 6.C. Board Practices for a discussion of the Compensation and Audit
Committees. The remuneration of the Corporate Assembly is determined by the annual general meeting,
while the Corporate Assembly determines the remuneration to the Board and the Nomination Committee. Director Compensation Arrangements Compensation for Employee and Non Employee Directors Annual fees for employee and non-employee directors were NOK 220,000, increasing to NOK
230,000 effective May 2004. Employee director fees are paid in addition to compensation as an
employee. The annual fee for the Deputy Chairperson was NOK 330,000, increasing to NOK 345,000 from May
2004. The annual fee for the Chairperson was NOK 430,000, increasing to NOK 450,000 effective May
2004. 117




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##### 



Mr. Egil Myklebust, who served as Chairperson of the Board until 24 March 2004, received NOK
99,230 for serving on the Board and his salary from Hydro was reduced correspondingly. Mr.
Myklebust received total compensation in 2004 of NOK 3,583,000. In May 2001, Mr. Myklebust retired
as President and Chief Executive Officer of Hydro. He continues to render services to Hydro in
accordance with his employment contract of 1991. Mr. Jan Reinås, who served as Chairperson from 25 March 2004, received NOK 342,000 for serving
on the Board. Compensation of the Chief Executive Officer and Corporate Management Board On 17 June 2004, the Board approved a new employment contract for Mr. Reiten, Hydros
President and Chief Executive Officer. In accordance with the new contract, which can be found at
Exhibit 4 to this annual report, his right to continued employment after retirement as president
has been discontinued. As a compensation, the Board decided to reduce his retirement age from 62 to
60 and to make a one-time payment of NOK 4 million to be used solely for the purchase of Hydro
shares (the amount of shares to be purchased based on the net, after tax proceeds of the lump sum
payment). Under the agreement, Mr. Reiten may not dispose of the shares for a period of 9 years. In 2004, Mr. Reiten, received salary and other remuneration of NOK 4,695,000, as well as a
bonus for 2003 of NOK 1,190,000 and the one-time payment described above. All employees based in Norway are eligible for a bonus linked to performance targets for the
various business units. Mr. Reiten has a bonus potential of six months salary as part of this plan.
The Board also determined in its meeting on 17 June 2004, that Mr. Reiten was entitled to a bonus
for 2003 of NOK 1,190,000 in accordance with the bonus plan and performance related targets
established earlier. Under Mr. Reitens new employment contract, he is entitled to retire at 60 years of age with a
pension benefit representing 65 percent of his salary. In the event his employment terminates
before the age of 60, he has the right to salary for a three-year period. In the event Mr. Reiten
receives salary from other sources during this period, Hydro has the option to reduce its
obligation to Mr. Reiten correspondingly. The total salary and benefits, excluding bonuses, for the four other members of the Corporate
Management Board was NOK 10,445,000 in 2004. The total amount of bonuses paid to this group in 2004
was NOK 1,563,000 as follows: Tore
Torvund
    NOK 490,000Jon
Harald Nilsen
    NOK 351,000John
O. Ottestad
    NOK 556,000Alexandra Bech Gjørv
    NOK 166,000
 Of the other members of the Corporate Management Board, three members have a retirement age of
62 years of age, and one member has a retirement age of 65 years of age. Grants of Share Options in Last Fiscal Year Employee Incentive Plan  Share-Based Compensation Plans Approximately 30 people in the Companys senior management, including the President and Chief
Executive Officer and members of the Corporate Management Board, are eligible to participate in
Hydros share-based compensation plans, currently the 2004, 2003 and 2002 Executive Share Option
Plans. The President and Chief Executive Officer receives options granted under the plans on an
annual basis. Options issued under the 2004 plan may be exercised within a six-year period, but not
before 1 July 2007, their exercise being conditional on the development of the price of the
underlying shares. If the share price reaches above NOK 476 between 1 July 2007 and 30 June 2010,
all the options are exercisable. Options granted under the 2003 and 2002 plans may be exercised
within a five-year period, but not before the expiry of three years from the date of grant.
Exercise of the options is conditional of the development of the price of the underlying shares
(including dividends paid) from the date of the 118




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##### 



grant of the option. If the average increase in share price is less than 12 percent per year, none
of the options vest. If the increase is between 12 percent and 20 percent, the corresponding
percentage of options that vest increases linearly between 20 percent and 100 percent. Upon
exercise of an option granted under 2003 and 2002 plans of the Executive Share Option Plans, the
Company fulfills its obligation toward the option holder by way of a cash payment equal to the
economic value of the option, representing the difference between the market value of the
underlying Company share (the average of the closing price during the last five days of trading
before the option is exercised) and the exercise price of the option. The option holder is liable
for any tax or employee social security contributions arising from the grant or exercise of
options. In addition, the option holder must have or acquire and hold a set number of the Companys
shares equal to the bonus payment. Eligible participants have been granted options relating to a total of 125,000 Company shares
with an exercise price of NOK 476 per share under the 2004 Executive Share Option Plan, 97,500
shares with an exercise price of NOK 321.62 per share under the 2003 Executive Share Option Plan,
and a total of 92,500 shares with an exercise price of NOK 331.14 per share under the 2002
Executive Share Option Plan. As explained more fully below, these prices reflect a downward
adjustment of 8.5 percent as a result of the change in the Companys share capital in connection
with the Yara demerger. The total number of Company shares underlying options which members of senior management are
eligible to receive in any year under the Executive Share Option Plans are presented below: Number of SharesRecipient
    
    
    Underlying Option Grants2002 and 2003
    
    
    
    2004President and Chief Executive Officer
    
    
    
    10,000
    
    
    
    
    15,000Other members of the Corporate Management Board
    
    
    
    7,000
    
    
    
    
    7,000  10,000Other Plan participants
    
    
    
    2,000  3,500
    
    
    
    
    2,500  3,500
 Options for all the shares authorized under each of the 2004, 2003 and 2002 Executive Share Option
Plans have been granted. See Note 4 to the Consolidated Financial Statements. Administration of the Executive Share Option Plans is delegated by the Board to its
Compensation Committee, which has responsibility to interpret, construe and administer each of the
plans and to determine the number, terms, conditions and duration of any grant in accordance with
the terms of the applicable plan. In case of a change in the Companys share capital, the exercise
price may be adjusted in such a manner as the Compensation Committee considers fair and reasonable.
The performance objectives shall only be changed if the Compensation Committee considers this to be
necessary. In connection with the Yara demerger, the Compensation Committee determined that the
exercise price and the base share price for calculation of performance would be adjusted in
accordance with the demerger share split ratio. As a result, the exercise price of outstanding
options at the time of consummation of the demerger and the base share price for calculation of
performance was reduced by 8.5 percent, effective as of the completion date of the demerger (i.e.,
24 March 2004). 
 ITEM 6.C. BOARD PRACTICES The Company adheres to requirements applicable to it in the countries where its
shares are listed and also implements corporate governance initiatives deemed beneficial to the
Companys development. The Company continuously reviews its corporate governance structure in order
to develop and align it with international best practices. The Companys primary share listing is on the Oslo Stock Exchange (OSE). The OSE listing is
governed by Norwegian securities legislation. The Companys shares are also listed on Düsseldorf,
Frankfurt, Hamburg, London and Paris stock exchanges, and its American Depositary Shares are listed
on the New York Stock Exchange (the NYSE). 119




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Beginning in 2002 and on a continuing basis since, the Company has monitored closely the
development of regulations issued or proposed by the SEC to implement provisions of the US
Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act), as well as proposed and adopted changes to NYSE
listing standards. Hydro is complying with the new corporate governance requirements and listing
standards that apply to non-U.S. companies, including the Chief Executive Officer and Chief
Financial Officer certifications that are required to be included in its annual reports on Form
20-F. In light of the required certifications, the Company has, among other things, established a
disclosure committee (the Disclosure Committee) comprised of members of senior management. The
Disclosure Committee is responsible for reviewing financial and related information before it is
made public. Board members are elected for a two-year period. See the biographical information for each of
the Board members, included in Item 6.A. Directors and Corporate Management Board  Board of
Directors, for the period during which each Board member has served as such. Except as noted in the next sentence, none of the Companys non-employee Board members have
any other service contractual agreements with the Company. Elisabeth Grieg, who is a member of the
Board of Directors and serves on the Boards Audit Committee, is part owner of a family owned
company, Grieg Maturitas AS, which indirectly holds 20 percent of the ownership of Aon Grieg. Aon
Grieg acted as a broker for Hydro in relation to offshore insurance
in 2004 and received USD
907,863 in fees from Hydro for such services. Employee directors have no other service
contractual agreements with the Company outside of their employee contracts, though they are
subject to their duties as Board members. Committees of the Board of Directors The Board of Directors has established two Board committees: a compensation committee (the
Compensation Committee) and an audit committee (the Audit Committee). The Board of Directors
has approved mandates or charters for both committees. Compensation Committee On 12 October 2001, the Board of Directors constituted the Compensation Committee, to consist
of not fewer than three members of the Board of Directors who are not officers of the Company. The
members of the Compensation Committee, who are elected by the full Board, are to serve in such
capacity for the two-year term of their service on the Board, but are subject to removal at any
time by a majority of the Board of Directors. The mandate or charter of the Compensation Committee provides that the committee is, on an
annual basis, to:  
    review the performance of the Companys President and Chief Executive Officer and other
members of senior management;
    prepare and recommend to the Board proposals for compensation for the President and
Chief Executive Officer, including base salary adjustments, awards under incentive plans
and other benefits;
    review and advise the President and Chief Executive Officer on the compensation of the
other members of senior management; and
    determine eligible participants in the Companys share incentive plans, and approve the
participants in, and the types of awards and number of shares covered under, each such
plan. The Compensation
Committee held seven meetings in 2004. As of 14 March 2005 the members of
the Compensation Committee are Jan Reinås (Chairperson), Håkan Mogren and Ingvild Myhre. The Board
has determined that each of the members of the Compensation Committee is independent under the
recently adopted NYSE listing standards. 120




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Audit Committee Organization On 1 November 2001, the Board of Directors established the Audit Committee. The Audit
Committees mandate or charter provides that the Audit Committee is to consist of at least three
members of the Board of Directors, each to be appointed by the full Board and to serve in such
capacity for the two-year term of their service on the Board, subject to removal at any time by a
majority of the Board of Directors. The Audit Committee held eight
meetings in 2004. As of 14 March 2005 the members of the Audit
Committee are Borger A. Lenth (Chairperson), Elisabeth Grieg, Kurt Anker Nielsen and Terje
Friestad, an employee representative who was elected to serve on the Board as of 16 March 2004,
with effect from 25 March 2004. Messrs. Lenth and Nielsen, and Ms. Grieg, are each considered
independent under the SECs regulations adopted to implement the provisions of Section 301 of the
Sarbanes-Oxley Act. As a non-management employee of Hydro elected to the Board in accordance with
Norwegian law, Mr. Friestad is exempt from the SECs independence requirement. The Board has
assessed whether reliance on the exemption in the case of Mr. Friestad would materially adversely
affect the ability of the Audit Committee to act independently and satisfy the other requirements
of Rule 10A-3 under the Exchange Act, and has concluded that it would not. In accordance with applicable NYSE listing standards, the Board is of the opinion that each of
the current members of the Audit Committee fulfills the NYSEs listing standard with respect to
being financially literate, as such qualification is interpreted by the Board in its business
judgment. In addition, the Board has determined that Kurt Anker Nielsen, elected to the Board as of
13 May 2004, is an audit committee financial expert, as that term is defined in SEC rules. Role and Responsibilities The Audit Committee operates in accordance with a mandate approved by the entire Board. The
mandate was revised initially in June 2003 and also recently in March 2005 to meet the new
requirements under the SECs rules to implement relevant provisions of the Sarbanes-Oxley Act and
the NYSE listing standards. The Audit Committee mandate can be found at Exhibit 99.3 to this annual
report. The mandate establishes that the Audit Committee acts as a preparatory body related to the
Boards supervisory role with respect to the Companys financial controls, disclosures and external
audit, consistent with Norwegian law. The primary function of the Audit Committee is to assist the
Board with respect to:  
    the integrity of the Companys financial statements;
    the companys financial reporting processes and internal controls;
    the qualifications, independence and performance of the external auditors; and
    the performance of the Companys internal audit function. The Audit Committee mandate provides the Audit Committee with the authority to engage
independent counsel and other advisers, as it deems necessary to carry out its duties. Management
is responsible for the Companys financial reporting process, the preparation of the Companys
consolidated financial statements in accordance with generally accepted accounting principles, and
the design and operation of the Companys system of internal control over financial reporting to
ensure compliance with accounting standards and applicable laws and regulations. The Companys
external auditors, Deloitte Statsautoriserte Revisorer AS, are responsible for performing an
independent audit of the Companys consolidated financial statements in accordance with generally
accepted auditing standards and issuing a report on such financial statements. The Audit
Committees responsibility is, in an oversight role, to monitor, oversee and review these
processes. 121




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Review of the Companys Consolidated Financial Statements In connection with the Audit Committees responsibilities, the Audit Committee reviewed and
discussed the Consolidated Financial Statements and discussed these financial statements with the
Companys management and external auditors. Management and the external auditors advised the Audit
Committee that the Consolidated Financial Statements were fairly stated in accordance with U.S.
GAAP. The Audit Committee also discussed with the Companys external auditors the external auditors
independence, a discussion that encompassed, among other things, whether the external auditors
provision of non-audit related services to the Company is compatible with maintaining such
auditors independence. In accordance with Section 204 of the Sarbanes-Oxley Act and the SECs rules to implement its
provisions, the Companys external auditors also communicated with the Audit Committee, prior to
filing of the external auditors audit report with the SEC with respect to the Consolidated
Financial Statements, regarding all critical accounting policies and practices, alternative
accounting treatments, and other written material communications between the external auditors and
the Companys management. In reliance on the reviews and discussions referred to above, the Audit Committee informed the
Board that it was not aware of any matters weighing against the Boards approval of the
Consolidated Financial Statements to be included in this annual report on Form 20-F for the year
ended 31 December 2004 for filing with the SEC. As noted above, the Company established a Disclosure Committee to strengthen the Companys
disclosure controls and procedures as part of its efforts to ensure the quality and reliability of
Hydros financial reporting and disclosure. Issues considered by the Disclosure Committee are
reviewed and evaluated by the Audit Committee. The Audit Committee reviews the Companys external financial reports and the disclosures in
such reports in separate meetings prior to the Boards review and approval. Pre-Approval Policy The Audit Committee has established a pre-approval policy. See Item 16.C Principal Accountant
Fees and Services for a discussion of the Companys pre-approval policy. Handling of Concerns and Complaints In December 2003, the Audit Committee established and implemented a channel for handling of
concerns and complaints. All Hydro employees may, confidentially and anonymously, raise any
concerns, including concerns about accounting, internal accounting controls or auditing matters,
directly with the head of Internal Audit, who acts in this capacity as, in essence, a secretary for
the Audit Committee. Alternatively, employees may raise any concerns or questions regarding such
matters directly with the Chairperson of the Audit Committee. Cooling-off Policy In December 2004, the Audit Committee approved a cooling-off policy intended to ensure that
the independence of the Companys external auditor is not impaired in connection with Hydros
employment of former or current external auditor personnel and their close family members, as
that term is defined in applicable SEC rules. During 2004, Hydro did not recruit or hire any such
personnel (or close family members of such personnel) to fill positions within the scope of the
policy. 122




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Internal Audit The Audit Committee has reviewed and evaluated the operational audit reports prepared by the
Companys internal audit department. Separate and independent sessions were held between the Audit
Committee and the external and internal auditors. 
 ITEM 6.D. EMPLOYEES As of 31 December 2004, the Group employed approximately 34,600 people, compared with
approximately 42,900 people in 2003, and 49,700 people in 2002. The decline in 2004 reflected the
transfer of approximately 7,500 employees to Yara in connection with the demerger of Hydros Agri
business operations. Approximately 22,500 of the Groups employees were located outside Norway as
of 31 December 2004, compared to approximately 29,200 at the end of 2003 and 35,100 at the end of
2002. The number of people employed in each segment as of 31 December 2004 is as follows: Business Segment
    
    
    Number of EmployeesExploration & Production
    
    
    
    2,821Energy and Oil Marketing
    
    
    
    706Metals
    
    
    
    6,161Rolled Products
    
    
    
    4,013Extrusion and Automotive
    
    
    
    15,793Other Activities (1)
    
    
    
    5,154
   (1)
    
    Other Activities consists of the following: Hydro Polymers AS, BioMar AS
(formerly Treka AS), Pronova, the industrial insurance company, Industriforsikring, Hydro
Business Partner, Hydro Production Partner, Hydro IS Partner AS and other Corporate staff. Production workers and certain staff categories in Norway are generally organized on a
national basis with annual or bi-annual contract negotiations held between employee organizations
and the national employers association. Norwegian employees are represented in Hydros Corporate
Assembly and Board of Directors. The Company considers its relationship with the Norwegian employee
organizations to be good. Outside Norway, the degree of worker organizations and the form of
negotiations with such organizations varies from one country to another. 
 ITEM 6.E. SHARE OWNERSHIP Share Ownership: The following table sets forth the beneficial ownership of ordinary shares as of 18 February 2005
by (i) each director and member of senior management, and (ii) all directors and members of the
Corporate Management Board of the Company as a group. 123




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Shares BeneficiallyName of Beneficial Owner
    
    
    OwnedJan Reinås
    
    
    
    0Borger A. Lenth
    
    
    
    144Elisabeth Grieg
    
    
    
    6,080Håkan Mogren
    
    
    
    0Ingvild Myhre
    
    
    
    0Geir Nilsen
    
    
    
    55Kurt Anker Nielsen
    
    
    
    0Odd Semstrøm
    
    
    
    129Terje Friestad
    
    
    
    236Eivind Reiten
    
    
    
    11,641Alexandra Bech Gjørv
    
    
    
    900John Ove Ottestad
    
    
    
    8,238Jon-Harald Nilsen
    
    
    
    270Tore Torvund (includes 360 shares held by a close family member)
    
    
    
    3,640Total number of ordinary shares owned by all directors and
members of Corporate Management Board as a group (consisting of
14 persons)
    
    
    
    31,333
 The total number of authorized and issued ordinary shares of the Company as of 31 December
2004 was 258,954,428. Excluding shares held in treasury as of 31
December 2004 of 8,115,198 the
total number of issued and outstanding shares was 250,839,230. The percentage beneficial ownership
of the total number of ordinary shares owned by all directors and members of Corporate Management
Board as a group was approximately 0.012 percent. The percentage beneficial ownership of the total number of ordinary shares owned, individually
and collectively by all members of the Corporate Assembly as a group as of 31 December 2004 was
approximately 0.02 percent. The beneficial ownership of ordinary shares by each member, observer,
and deputy member of the Corporate Assembly can be found in Note 26 to the Consolidated Financial
Statements. The percentage of outstanding shares held by residents of different countries as of 18
February 2005, are presented below: Norway
    
    
    61.4
    %United Kingdom
    
    
    15.1
    %United States
    
    
    13.5
    %Other
    
    
    10.0
    %
 Option Ownership The following table sets forth the beneficial ownership of options to acquire ordinary shares
as of 14 March 2005 by (i) each director and member of the Corporate Management Board who has
served in either of such capacities at any time since 1 January 2004, and (ii) all such directors
and members of the Corporate Management Board as a group: 124




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Number of Shares Underlying
    
    
    Exercise PriceName
    
    
    Options Granted
    
    
    (NOK/Share)
    
    
    Expiration Date2002
    
    
    2003
    
    
    2004
    
    
    2002
    
    
    2003
    
    
    2004
    
    
    2002
    
    
    2003
    
    
    2004Eivind Reiten
    
    
    
    10,000
    
    
    
    
    10,000
    
    
    
    
    15,000
    
    
    
    
    331.14
    
    
    
    
    321.62
    
    
    
    
    476
    
    
    
    June 30, 2007
    
    
    June 30, 2008
    
    
    June 30, 2010John Ove Ottestad
    
    
    
    7,000
    
    
    
    
    7,000
    
    
    
    
    10,000
    
    
    
    
    331.14
    
    
    
    
    321.62
    
    
    
    
    476
    
    
    
    June 30, 2007
    
    
    June 30, 2008
    
    
    June 30, 2010Tore Torvund
    
    
    
    7,000
    
    
    
    
    7,000
    
    
    
    
    10,000
    
    
    
    
    331.14
    
    
    
    
    321.62
    
    
    
    
    476
    
    
    
    June 30, 2007
    
    
    June 30, 2008
    
    
    June 30, 2010Jon-Harald Nilsen
    
    
    
    7,000
    
    
    
    
    7,000
    
    
    
    
    10,000
    
    
    
    
    331.14
    
    
    
    
    321.62
    
    
    
    
    476
    
    
    
    June 30, 2007
    
    
    June 30, 2008
    
    
    June 30, 2010Alexandra Bech
Gjørv
    
    
    
    7,000
    
    
    
    
    7,000
    
    
    
    
    7,000
    
    
    
    
    331.14
    
    
    
    
    321.62
    
    
    
    
    476
    
    
    
    June 30, 2007
    
    
    June 30, 2008
    
    
    June 30, 2010All directors
and members of the
Corporate Management
Board as a group
    
    
    
    38,000
    
    
    
    
    38,000
    
    
    
    
    52,000
 All Employee Share Purchase Plan In 2000, the Board decided that the Company would, on an annual basis, offer its employees in
Norway (and employees of Norwegian subsidiaries in which the Company has an ownership interest of
more than 90 percent) the opportunity to purchase the Companys shares on favorable terms. The
amount of the discount from the traded price of the shares is dependent on the development of the
Companys share price (including dividends paid) during the applicable performance period (i.e.,
the 12-month period beginning on 1 January of the preceding year). Eligible employees are offered
the opportunity to buy shares for NOK 6,000 at a 20 percent discount to the market price if the
share price has increased by less than 12 percent, and a 50 percent discount to the market price if
the share price has increased by more than 12 percent, during the performance period. Interest-free
loans are granted to employees in connection with their share purchases. In 1988, Hydro established a stock option purchase program for employees in the United
Kingdom. The stock option purchase program is organized in an independent trust. The trust acquired
shares in the market at the time options were granted. The last options were granted in July 2002
and the program will be operational until July 2012 when the last remaining options expire. Each
year the employees were given the option to acquire a limited number of shares at a fixed price
during a period from the third to the tenth year from grant date. Details as to number of shares awarded to employees and the price per share can be found in
Note 4 to the Consolidated Financial Statements. 
 ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 
 ITEM 7.A. MAJOR SHAREHOLDERS The Kingdom of Norway is the only person or entity known to the Company to own beneficially,
directly or indirectly, more than 5 percent of the Companys ordinary shares. As of 18 February
2005, the Kingdom owned 113,483,658 ordinary shares, representing 43.8 percent of the total number
of ordinary shares issued and 45.2 percent of the total number of outstanding shares as of such
date. There are no different voting rights associated with the ordinary shares held by
the Kingdom. As of 18 February 2005, there were a total of 37,336 registered holders of Hydros
shares resident in Norway. 125




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The Kingdom acquired most of its interest in the Company in 1945. From that time and until
July 1999, the Kingdom owned 51 percent of the total number of ordinary shares issued and
outstanding. Ordinary shares issued in connection with the acquisition of Saga Petroleum in July
1999 increased the total number of shares issued and outstanding with a corresponding decrease in
the Kingdoms percentage ownership interest. Since 1945, the Kingdom has not disposed of any of the Companys ordinary shares owned by it.
However, there can be no assurance that the Kingdom will not do so in the future. The Norwegian
Ministry of Trade and Industry represents the Norwegian government in exercising the Kingdoms
voting rights. Acting through the Norwegian government, the Kingdom, in its capacity as a
shareholder of the Company, has never taken an active role in the day-to-day management of the
Company. As of 18 February 2005, JPMorgan Chase Bank, as depositary of the ADSs (the Depositary),
through its nominee company, Morgan Guaranty Nominees Limited, held interests in 9,099,337 ordinary
shares (approximately 3.6 percent of the issued and outstanding ordinary shares as of such date) on
behalf of 547 registered and an estimated 5,500 beneficial holders of American depositary receipts
(ADRs), evidencing ADSs. There were 339 holders of ordinary shares with addresses in the United
States (not including the Depositary) as of the same date. These shareholders held 24,717,350
ordinary shares, equal to approximately 9.9 percent of the issued and outstanding ordinary shares. 
 ITEM 7.B. RELATED PARTY TRANSACTIONS The following table sets forth
information regarding outstanding loans from Hydro to individuals
who have served on the Board of Directors or the Corporate Management Board since 1 January 2004: Largest
    
    
    AmountAmount
    
    
    Outstanding asOutstanding
    
    
    of 18 FebruaryDuring 2004
    
    
    2005
    
    
    
    
    
    
    
    
    
    
    Remaining(in thousands of
    
    
    (in thousands
    
    
    
    
    
    
    
    
    
    
    RepaymentName of Loan Recipient
    
    
    NOK)
    
    
    of NOK)
    
    
    Nature of Loan
    
    
    Interest Rate(1)
    
    
    Term(2)Odd Semstrøm(3)
    
    
    
    45
    
    
    
    
    37
    
    
    
    Consumer
    
    
    
    4.0
    %
    
    
    2 years-Upon terminationGeir Nilsen
    
    
    
    170
    
    
    
    
    72
    
    
    
    Consumer
    
    
    
    4.0
    %
    
    
    1.5 yearsJohn O. Ottestad
    
    
    
    591
    
    
    
    
    0
    
    
    
    Consumer/Mortgage
    
    
    
    3.25-4.00
    %
    
    
    N/ATore Torvund
    
    
    
    414
    
    
    
    
    365
    
    
    
    Consumer/Mortgage
    
    
    
    3.25-4.00
    %
    
    
    2.5  12 yearsJon-Harald Nilsen
    
    
    
    195
    
    
    
    
    173
    
    
    
    Mortgage
    
    
    
    3.25
    %
    
    
    8.5 yearsEgil Myklebust(4)
    
    
    
    4,565
    
    
    
    
    4,521
    
    
    
    Mortgage
    
    
    
    2.90 -3.25
    %
    
    
    25 years  Upon terminationTerje Friestad
    
    
    
    75
    
    
    
    
    69
    
    
    
    Consumer
    
    
    
    4.0
    %
    
    
    3.5 years
   (1)
    
    Interest rate as of 31 December 2004. All of the above loans bear interest
rates that reflect market rates. The interest rates are variable and are adjusted
periodically by the Company.(2)
    
    Amortized on a monthly basis.(3)
    
    Includes an interest-free loan of NOK 20,000, which is repayable upon the
termination of Mr. Semstrøms employment with the Company.(4)
    
    Mr. Myklebust served as chairman of the board until 24 March 2004.
As of 18 February 2005, Mr. Myklebust had several mortgage loans, including an interest-only
loan of NOK 2,200,000 bearing interest at 2.90 percent and repayable upon the expiration or
earlier termination of his employment agreement, a mortgage loan of NOK 2,071,000 bearing
interest at 2.90 percent with a remaining payment period of 25 years and other mortgage
loans totaling NOK 250,000 bearing interest at 3.25 percent repayable upon the expiration or
earlier termination of his employment agreement. All of these loans are secured by Mr.
Myklebusts principal residence. 126




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Except as described in the notes to the above table, the loans included in the above
table have been extended to members of the Board of Directors or the Corporate Management Board
under terms
and conditions that are equivalent to those made available to all Norway-based employees of the
Company. All loans to directors appointed by the shareholders, and executive officers (i.e.,
members of the Corporate Management Board) of the Company were entered into prior to July 30, 2002.
The Company has not materially modified or renewed any of these loans since that date. Mr. Terje
Friestad, who in May 2004 joined the Board after being elected by the employees in accordance with
Norwegian company law, was extended a loan in the amount of NOK 75,000 in July 2004 under an
employee benefit scheme applicable to all employees in Norway. 
 ITEM 7.C. INTERESTS OF EXPERTS AND COUNSEL In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 7.C. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 8. FINANCIAL INFORMATION 
 ITEM 8.A. CONSOLIDATED FINANCIAL STATEMENTS AND OTHER FINANCIAL INFORMATION The Consolidated Financial Statements are included in Exhibit 10 to this annual report on Form
20-F. Reference is made to Item 19. Financial Statements and Exhibits for a list of all financial
statements included in this annual report. Export Sales See Note 5 to the Consolidated Financial Statements for a listing of the operating revenues by
country of customer for export sales information. Legal Proceedings Tax Claim Relating to Kharyaga Field In May 2003, the Nenets Autonomus Okrug of the Ministry of Taxes and Revenues of the Russian
Federation submitted to Total, the French major oil company and operator for the Kharyaga field
located in Northwest Russia, a claim for tax and the Russian States share of the revenues from oil
extracted under the Production Sharing Agreement (PSA) for this field. Hydro has a 40 percent share
in the PSA and is carrying 50 percent of the 10 percent interest of the Nenets Oil Company. As
such, Hydros share of the claim, if found to be valid, would be approximately USD 32 million. The
claim stems from the unwillingness of the Kharyaga projects joint committee, which includes a
representative of the regions administration, to approve audited accounts relating to the field
for 2001 and 2002, and the work program and budget for 2002, submitted by Total, as the field
operator. Due to this lack of approval, the Russian tax authorities have taken the position that
all revenues from the project technically represented profit, and thus could not be included in the
PSAs cost recovery category. The joint committee has also been unwilling to approve the work
programs and budgets for 2003 and 2004, but no claim has been made related to these periods. Total
and Hydro have filed a lawsuit with an international arbitration court in Stockholm to have
spending on the development of the Kharyaga field recognized. The case is expected to be heard by
the Stockholm Arbitration Court in July 2005. Zero-Rate Electricity Tax The EFTA (European Free Trade Association) Surveillance Authority (ESA) completed a formal
investigation procedure against the Norwegian State to determine if the former zero-rate
electricity tax applicable to Norwegian industry was in accordance with State aid rules included in
the European 127




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Economic Area Agreement (the EEA Agreement). Based on this investigation, ESA issued a
decision on 30 June 2004, reflecting its determination that the exemption of certain Norwegian
businesses from the
electricity tax constituted illegal State aid under the EEA Agreement. The decision requires the
Norwegian government to recover at least a minimum rate of  0.5 per MWh for the period between
6 February and 31 December 2003 from the recipients of such State aid. In another decision of the
same date, ESA determined not to raise any objections to the tax derogations from the new
electricity tax, applicable as of 1 July 2004. The decision to order recovery of electricity tax from the industry has been appealed to the
EFTA Court by the Norwegian government, the Federation of the Norwegian Processing Industry
(Prosessindustriens landsforening, PIL) and several individual member companies of PIL, including
Hydro. The appellants have asserted several bases upon which the ESA decision should be annulled,
including that the decision violates Articles 61 and 62 of the EEA Agreement as regards recovery of
aid and infringes the principle of legal certainty, and that the ESA failed to follow proper
procedure. The appellants have not applied for an interim order to suspend the effect of the
decision with regard to the recovery claim and a dialogue has been instigated between the Norwegian
Government and ESA in order to clarify how the recovery shall be implemented. The exact amount the Norwegian government is to recover from Hydro according to ESAs illegal
State aid ruling depends on an interpretation of the decision. This interpretation issue is part of
the dispute submitted to the EFTA Court, but is also part of a discussion between the Norwegian
Government and ESA as regards how the recovery shall be implemented. Hydro estimates that the
amount may be approximately NOK 15 million, plus interest. Dispute as to Allocation of Pension Liabilities As of 1 January 2001, the system for the charging or allocation of pension costs by operators
of oil and gas fields on the NCS to other companies with interests in such fields was changed.
Prior to that date, the costs of funded pensions were charged based upon pension premiums and the
costs of unfunded pensions were charged when pensions were paid. With effect from 1 January 2001,
pension costs are charged as a percentage of pensionable salary. In transitioning to the current system, Hydro, as an operator of oil and gas fields on the
NCS, recorded pension costs of approximately NOK 796 million in the fourth quarter of 2000, of
which NOK 205 million was for Hydros own account. The balance of the increased pension obligation
was charged for the account of the other companies with interests in the Hydro-operated fields.
Most of the other companies did not accept this allocation. After negotiations with these
companies, Hydro was able to reach an agreement with certain of them. The companies with which
Hydro was not able to reach an agreement have started an arbitration proceeding over this matter. Hydro has charged the companies which are parties to the arbitration an aggregate amount of
approximately NOK 456 million. In preparation of the arbitration proceedings, it has been
recognized that Hydro has the right to allocate amounts to its partners when pensions are paid.
Regardless of which principle to apply with respect to the timing of the allocation, the parties
need to agree upon the actual amounts to be charged. Although no assertion for disputed amounts has been made to the parties of the dispute,
Hydros management does not believe that the amounts will have a material adverse effect on Hydros
results of operations or financial position. Other Legal Proceedings Hydro is involved in or threatened with various other legal, tax and environmental matters
arising in the ordinary course of business. Hydro is of the opinion that resulting liabilities, if
any, will not have a material adverse effect on its consolidated results of operations, liquidity
or financial position. 128




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Dividend Policy The Board of Directors believes that long-term returns to shareholders should reflect the
value created in the Company in the form of dividends and a higher share price. The Boards policy
is that dividends paid should increase steadily in line with the growth in Hydros results, while
taking into consideration opportunities for adding value through profitable new investments. Over
time, the value added will be reflected to a greater extent by a higher share price than through
dividend distributions. The Board considers it appropriate that dividends over a period of several
years average roughly 30 percent of Hydros net income. Future dividends will be dependent on
Hydros future earnings, financial condition and cash flow, as well as other factors affecting
Hydro. The Board of Directors has proposed a dividend of NOK 20 per share for 2004. This is regarded
as an extraordinarily high dividend and should be seen in the context of the solid financial
position achieved by the Company as a result of the strong operating results. In order to achieve the greatest possible value creation over time and to strike a balance
with Hydros operational risk exposure, it is necessary to have adequate access to financial
resources. This requires Hydro to maintain a position that will allow it to be able to access the
necessary loan capital with attractive conditions. As of 31 December 2004, the Companys senior
unsecured debt was rated A2 by Moodys and A with negative outlook from Standard & Poors. To
assist the Company in maintaining its credit ratings, the Company intends its adjusted net
interest-bearing debt over time to be equivalent to half of the Companys adjusted equity capital,
including minority interests. When calculating this ratio, adjustments are made to net
interest-bearing debt and to equity capital. These adjustments are discussed in Item 5 to this
annual report on Form 20-F under the caption Non-GAAP Financial Measures. Share Repurchases In periods of high earnings, the Company will consider implementation of share repurchase or
buy-back programs. Such consideration will be made in light of alternative investment opportunities
available to the Company and its financial condition. On the basis of these considerations, the
Board may propose to the Corporate Assembly that authorization be given for a repurchase of shares. On 1 December 2004, the extraordinary general meeting authorized Hydros Board of Directors to
buy back up to 5,617,621 of the Companys shares in the market over the following 18 months for the
purpose of subsequent cancellation. The Norwegian State has agreed to participate in the redemption
and cancellation of a proportional number of shares. The States ownership share will, therefore,
remain unaffected by the buy-back and cancellation. In total, up to 10 million shares may be
cancelled, equivalent to approximately four percent of the outstanding shares. Final decisions on
cancellation will require the approval of two-thirds of the votes cast at a future general meeting
at which such approval is sought. The extraordinary general meeting also approved a capital reduction by cancellation of the
2,808,810 treasury shares acquired in 2004. These shares were repurchased following the
May 2004 annual general meeting approval. The Company repurchased all of the approved shares during
the months of June through September 2004. Details of the buy-back program such as the total number
of shares repurchased for each period and the average price paid per share, can be found in Item
16.E Repurchase of Shares. The extraordinary general meeting also authorized the redemption of
2,191,190 shares owned by the Norwegian State. These shares were redeemed and cancelled in February
2005. The per share redemption price was based on the volume-weighted average of the price paid for
the 2,808,810 shares purchased in the market. The Company paid the Norwegian State an aggregate
amount of NOK 981 million including interest compensation of NIBOR plus one percent in February
2005. 129




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The Company has also previously purchased its own shares with the intention of using them in
connection with possible business transactions and employee incentive plans. The Company held
8,115,198 of such shares in treasury as of 31 December 2004. 
 ITEM 8.B. SIGNIFICANT CHANGES There have been no significant changes in Hydros results of operations, financial condition
or business prospects since 31 December 2004. 130




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ITEM 9.THE OFFER AND LISTING 
 ITEM 9.A. OFFER AND LISTING DETAILS The following table gives, for the periods indicated, adjusted high and low prices for the
Companys ordinary shares on the Oslo Stock Exchange and the ADSs on the New York Stock Exchange.
Share prices quoted prior to the demerger of the Companys agri business on 24 March 2004 have been
adjusted with a 0.881699 factor in accordance with the practice of Oslo Stock Exchange . Five Most Recent Fiscal Years Oslo Stock Exchange
    
    
    New York Stock ExchangeYear
    
    
    High
    
    
    Low
    
    
    High
    
    
    Low(in NOK)
    
    
    (in NOK)
    
    
    (in US Dollars)
    
    
    (in US Dollars)2000
    
    
    
    365.91
    
    
    
    
    261.42
    
    
    
    
    40.06
    
    
    
    
    31.302001
    
    
    
    356.21
    
    
    
    
    273.33
    
    
    
    
    39.59
    
    
    
    
    30.862002
    
    
    
    388.83
    
    
    
    
    240.70
    
    
    
    
    46.11
    
    
    
    
    32.672003
    
    
    
    365.91
    
    
    
    
    231.01
    
    
    
    
    54.74
    
    
    
    
    31.652004
    
    
    
    521.50
    
    
    
    
    361.50
    
    
    
    
    83.62
    
    
    
    
    53.44
 Quarterly Data for Two Most Recent Fiscal Years Oslo Stock Exchange
    
    
    New York Stock ExchangeHigh
    
    
    Low
    
    
    High
    
    
    LowQuarterly Period
    
    
    (in NOK)
    
    
    (in NOK)
    
    
    (in US Dollars)
    
    
    (in US Dollars)First quarter 2003
    
    
    
    279.94
    
    
    
    
    231.01
    
    
    
    
    40.41
    
    
    
    
    31.65Second quarter 2003
    
    
    
    331.52
    
    
    
    
    238.06
    
    
    
    
    45.76
    
    
    
    
    33.11Third quarter 2003
    
    
    
    350.48
    
    
    
    
    298.90
    
    
    
    
    47.56
    
    
    
    
    40.47Fourth quarter 2003
    
    
    
    365.91
    
    
    
    
    316.97
    
    
    
    
    54.74
    
    
    
    
    45.94First quarter 2004
    
    
    
    464.66
    
    
    
    
    361.50
    
    
    
    
    65.91
    
    
    
    
    53.44Second quarter 2004
    
    
    
    467.00
    
    
    
    
    395.00
    
    
    
    
    67.50
    
    
    
    
    54.92Third quarter 2004
    
    
    
    503.00
    
    
    
    
    419.00
    
    
    
    
    74.19
    
    
    
    
    60.28Fourth quarter 2004
    
    
    
    521.50
    
    
    
    
    457.50
    
    
    
    
    83.62
    
    
    
    
    71.34
 Most Recent Six Months Oslo Stock Exchange
    
    
    New York Stock ExchangeHigh
    
    
    Low
    
    
    High
    
    
    LowMonth
    
    
    (in NOK)
    
    
    (in NOK)
    
    
    (in US Dollars)
    
    
    (in US Dollars)September 2004
    
    
    
    503.00
    
    
    
    
    432.00
    
    
    
    
    74.19
    
    
    
    
    63.00October 2004
    
    
    
    521.50
    
    
    
    
    457.50
    
    
    
    
    77.24
    
    
    
    
    71.24November 2004
    
    
    
    510.00
    
    
    
    
    461.00
    
    
    
    
    83.62
    
    
    
    
    72.99December 2004
    
    
    
    500.50
    
    
    
    
    465.00
    
    
    
    
    81.81
    
    
    
    
    75.00January 2005
    
    
    
    499.00
    
    
    
    
    462.50
    
    
    
    
    79.40
    
    
    
    
    74.00February 2005
    
    
    
    545.00
    
    
    
    
    487.00
    
    
    
    
    86.97
    
    
    
    
    76.60
 Source: Reuters There were 339 holders of ordinary shares with addresses in the United States (not
including the Depositary) as of 18 February 2005. These shareholders held 24,717,350 ordinary
shares, equal to approximately 9.9 percent of the issued and outstanding ordinary shares. As of 18
February 2005, a total of 9,099,337 ADSs (representing approximately 3.6 percent of the issued and
outstanding ordinary shares) were held by 547 registered and approximately 5,500 beneficial holders
of ADSs. 131




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ITEM 9.B. PLAN OF DISTRIBUTION In accordance with the instructions to Form 20-F, the Company does not need to provide
the information called for by Item 9.B if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 9.C. MARKETS The Companys ordinary shares are listed on the stock exchanges in Oslo, London, Paris,
Frankfurt, Hamburg and Düsseldorf. The Board of Directors approved delisting of the Companys
shares from the Stockholm stock exchange effective 25 March 2004. The Companys ADSs are listed on
the New York Stock Exchange. 
 ITEM 9.D. SELLING SHAREHOLDERS In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 9.D. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 9.E. DILUTION In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 9.E. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 9.F. EXPENSES OF THE ISSUE In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 9.F. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 10. ADDITIONAL INFORMATION 
 ITEM 10.A. SHARE CAPITAL In accordance with the instructions to Form 20-F, the Company does not need to provide
the information called for by Item 10.A. if, as is the case in this instance, the Form 20-F is
being filed as an annual report under the Exchange Act. 
 ITEM 10.B. ARTICLES OF ASSOCIATION Norsk Hydro ASA is a public limited company organized under the laws of Norway. Its
registration number in the Norwegian Register of Business Enterprises is 914 778 271. Norsk Hydro
ASA was incorporated on December 2, 1905 and registered with the Norwegian Register of Business
Enterprises in 1906. Section 2 of the Companys Articles of Association provides that the Companys objects or
purposes are to engage in industry, commerce and transport, to utilize energy resources and raw
materials, and to engage in other activities connected with the above-mentioned objects. The
Companys operations may be conducted through participation in or in cooperation with other
enterprises. Board of Directors Section 5 of the Articles of Association provides that the Board of Directors shall be
composed of nine members who are elected by the Corporate Assembly to serve for a term of two
years, such term to expire at the conclusion of the annual general meeting of shareholders in the
year in which the period 132




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of service ends. The Corporate Assembly also elects the Chairman and the Vice-Chairman of the
Board. In the event a director retires, is removed or is disqualified as a result of personal
bankruptcy prior to the end of his or her period of service and there is no alternate Board member,
the rest of the Board of Directors must arrange for the election by the Corporate Assembly of a new
member of the Board of Directors for the remainder of the period of service. There are no requirements for a Board members being qualified to serve in such capacity other
than a requirement under Norwegian law that at least half of the members of the Board of Directors
must reside in the Kingdom of Norway or another country that is a member of the European Economic
Community (absent the grant of an exemption by the King of Norway in an individual case). Section 9
of the Articles of Association requires a director to retire the year he or she reaches the age of
70. Under Norwegian law and the Rules of Procedure for the Board of Directors, a member of the
Board of Directors may not participate in the discussion or in the decision on any matter in which
the Board member (or any person affiliated with such Board member) has a major personal or
financial interest. The rest of the Board may decide whether the Board member has such an interest
in the decision or matter. In addition, no member of the Board may participate in any matter
concerning a loan or other credit to such Board member or with respect to the pledge of security
for such members debt to the Company. Under Norwegian law, the Companys directors have no power to vote compensation to themselves
or any member of their body. Instead, the Corporate Assembly fixes the remuneration to be received
by members of the Board of Directors, alternate members and observers. Norwegian law also
stipulates that members of the Board of Directors are not to receive any remuneration from parties
other than the Company in connection with their services for the Company. However, a Board member
who does not participate in the day-to-day management of the Company is not precluded from acting
as an agent on behalf of a business carried on by the Board member and receiving a standard agency
fee in such capacity, provided that such member does not also represent the Company in the
transaction. Liability of Directors The members of the Board of Directors and the members of the Corporate Assembly owe a
fiduciary duty to the Company and its shareholders. Their principal obligation is to safeguard the
interests of the shareholders. In addition, they may also have duties to other third parties, such
as employees and creditors. The Companys directors and members of the Corporate Assembly can be
held liable for any damage they negligently or intentionally cause the Company. Norwegian law
permits shareholders to exempt any such persons from liability, but the exemption is not binding if
substantially correct and complete information was not provided to the shareholders at the general
meeting at which the shareholder action to exempt the person(s) from liability was taken. If a
resolution to grant such exemption from liability or not to pursue claims against such a person has
been passed by a general meeting with a smaller majority than that required to amend the Articles
of Association, shareholders representing at least ten percent of the share capital or, if there
are more than 100 shareholders, more than ten percent of the shareholders may pursue the claim on
the Companys behalf and in its name. The cost of any such action is not the Companys
responsibility, but can be recovered from any proceeds the Company receives as a result of the
action. If the decision to grant an exemption from liability or not to pursue claims is made by
such a majority as is necessary to amend the Articles of Association, the minority shareholders
cannot pursue the claim in the Companys name. Indemnification of Directors and Officers Neither Norwegian law nor the Articles of Association contains any provision concerning
indemnification by the Company of the members of the Board of Directors. 133




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Description of Ordinary Shares The following is a summary of material information relating to the share capital and the
ordinary shares of the Company, including summaries of certain provisions of the Articles of
Association and applicable Norwegian law (including the Norwegian Public Limited Companies Act) in
effect as of the date of filing of this annual report. General The authorized share capital of the Company consists of one class of shares: 258,954,428
ordinary shares, nominal value NOK 18.30 per share, of which 250,839,230 ordinary shares were
outstanding as of 31 December 2004. All outstanding ordinary shares are validly issued, fully paid
and nonassessable. The extraordinary General Meeting approved on 1 December 2004 a capital
reduction by cancellation of 2,808,810 treasury shares acquired in 2004. These treasury shares were
acquired as part of a buy-back program approved by the 2004 annual general meeting. The
extraordinary general meeting also authorized the redemption of 2,191,190 shares owned by the
Norwegian State. The capital reduction was registered in the Norwegian Registry on the 8th of
February 2005. The above-presented authorized and outstanding numbers of shares are adjusted for
the effects of the extraordinary general meeting decision. The VPS System The ordinary shares are registered in the Norwegian Verdipapirsentralen (the Norwegian Central
Securities Depository), referred to as the VPS. The VPS is Norways paperless centralized registry.
The VPS is owned by a public company and operates under a license from the Ministry of Finance. The
ownership of, and all transactions relating to, Norwegian listed shares must be recorded in a
licensed securities registry. The Companys share register is operated through the VPS. All transactions relating to securities registered with the VPS are made through computerized
book-entries. No physical share certificates are or can be issued. The VPS confirms each entry by
sending a transcript to the registered shareholder, regardless of beneficial ownership. To effect
these entries, the individual shareholder must establish a securities account with a Norwegian
account operator unless the individuals shares are registered in the name of a nominee. Norwegian
banks, the Central Bank of Norway, authorized investment firms in Norway, bond issuing mortgage
companies, management companies for securities funds (insofar as units in securities funds they
manage are concerned), and Norwegian branches of credit institutions established within the
European Economic Area (EEA) are allowed to act as account operators. If a security holder does not
establish such an account, an account agent will be appointed on the security holders behalf by
the issuer of the security in question. The entry of a transaction in the VPS will generally be decisive in determining the legal
rights of parties as against the issuing company or a third party claiming an interest in a
security. The VPS is strictly liable for any loss resulting from an error in connection with
registering, altering or canceling a right, except in the event of contributory negligence, in
which event compensation owed by the VPS may be reduced or withdrawn. A transferee or assignee of the Companys ordinary shares may not exercise the rights of a
shareholder with respect to his or her shares unless the transferee or assignee has registered his
or her shareholding or has reported and shown evidence of such share acquisition and the
acquisition of such shares is not prevented by law, the Articles of Association or otherwise. Shareholder Meetings Under Norwegian law, a companys shareholders are to exercise supreme authority in the company
through the general meeting. In accordance with Norwegian law, the Company is required to hold its annual general meeting
of shareholders within six months following the end of the fiscal year. In accordance with
Norwegian 134




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law and Section 11 of the Articles of Association, the following business must be
transacted at the annual general meeting:  
    approval of the annual accounts and annual report for the prior fiscal year,
including the distribution of any dividend;
    election of the shareholders members and deputy members to the Corporate
Assembly (if subject to election at the annual general meeting); and
    any other business to be transacted at the general meeting by law or in
accordance with the Articles of Association (i.e., matters listed in the notice convening
the meeting). In addition to the annual general meeting, extraordinary general meetings of shareholders may
be held if deemed necessary by the Board of Directors, the Corporate Assembly or the Chairman of
the Corporate Assembly. An extraordinary general meeting must also be convened for the
consideration of specific matters at the written demand of the Companys auditors or shareholders
representing a total of at least five percent of the share capital of the Company. The Board of Directors is to convene a general meeting of shareholders, including any
extraordinary general meeting. A general meeting must be convened by written notice to all
shareholders, sent at least 14 days in advance of the meeting date. Shareholders have the right to
have an issue discussed at a general meeting. In order to exercise this right, shareholders must
deliver written notice to the Board of Directors in sufficient time so that the issue can be
included in the notice convening the general meeting. If the Companys notice of the general
meeting has already been sent, a new notice as to the convening of the general meeting must be sent
if at least two weeks remain before the general meeting is to be held. Neither Norwegian law nor the Articles of Association provides for any quorum requirement
(i.e., a minimum level of voting power to be present, either in person or by proxy, in order to
conduct business at any general meeting). Under Norwegian law, shareholders are entitled to attend and vote at a general meeting, either
in person or by a proxy appointed at their own discretion. The right to attend a general meeting
cannot be restricted in the Articles of Association. Under Section 10 of the Articles of
Association, shareholders or their procurators (proxies) are entitled to attend and to vote at an
annual general meeting provided they have informed the Company of their intended attendance at
least five days in advance of the meeting date. Voting Rights Subject to the terms of a companys articles of association to the contrary, Norwegian law
provides that each outstanding share shall represent a right to one vote. All of the Companys
shares (other than shares held by the Company itself or any of its subsidiaries) have an equal
right to vote at general meetings and are entitled to one vote per share. Generally, all matters to be voted on by shareholders must be approved by a majority of the
votes cast by all ordinary shares that are present in person or represented by proxy at the general
meeting at which such matters are considered. In the case of elections (for example, of members of
the Corporate Assembly), the persons who receive the most votes cast are elected. However, certain
decisions, including resolutions to:  
    amend the Articles of Association;
    approve a merger or demerger;
    authorize an increase or reduction in the Companys share capital; or
    waive preferential rights in connection with an increase in share capital 135




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must be approved by at least two-thirds of the aggregate number of votes cast at the general
meeting at which any such action is before the shareholders for approval. Any resolution which has the effect of reducing shareholders rights to a dividend or to the
assets of the Company requires the approval of shareholders representing more than 90 percent of
the share capital represented at the general meeting at which such action is considered as well as
at least two-thirds of the votes cast at that meeting. Under Norwegian law, certain matters require the unanimous approval of the Companys
shareholders, including the taking of any action that would:  
    increase shareholders obligations to the Company;
    restrict the right to transfer, acquire or own shares in the Company;
    subject the shares to compulsory redemption; or
    change the legal relationship among previously equal shares. If any such action would affect less than all shareholders, such action would require the
unanimous approval of all affected shareholders as well as at least two-thirds of the votes cast
and at least two-thirds of the share capital represented at the general meeting at which such
action is considered. Under Norwegian law, shareholders may not take action by written consent. The beneficial owners of shares which are registered in the name of a nominee are generally
not entitled to vote under Norwegian law, nor are any persons who are designated in the share
register as holding such shares as nominees. Dividends Under Norwegian law, any proposal to pay dividends must be made by the Board of Directors and
approved by the shareholders at the annual general meeting of shareholders. The dividend cannot
exceed the amount proposed or consented to by the Board of Directors. Dividends in respect of a
fiscal year are normally determined at the annual general meeting held in the following year. Any
dividend approved at a general meeting accrues to those shareholders who are shareholders at the
time of shareholder approval, unless otherwise stated in the resolution with respect to such
dividend distribution. Dividends may be paid in cash or in kind. The Norwegian Public Limited Companies Act provides
several constraints on the distribution of dividends:  
    Dividends are payable only out of distributable reserves. Section 8-1 of the Norwegian
Public Limited Companies Act provides that distributable reserves consist of the profit for
the prior fiscal year (as reflected in the income statement approved by the annual general
meeting of shareholders) and the retained profit from previous years (adjusted for any
reclassification of equity), less (i) uncovered losses, (ii) the book value of research and
development, goodwill and net deferred tax assets (as recorded in the balance sheet, as of
the prior fiscal year end, approved by the annual general meeting of shareholders), (iii)
the total nominal value of treasury shares which the Company has acquired for ownership or
as security in previous fiscal years, and credit and security which, pursuant to Sections
8-7 to 8-9 of the Norwegian Public Limited Companies Act, fall within the limits of
distributable equity, and (iv) that part of the profit for the prior fiscal year which, by
law or pursuant to the Articles of Association, must be allocated to the undistributable
reserve or cannot be distributed as a dividend. Distributable reserves are to be calculated
in accordance with Norwegian GAAP. 136




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
    Dividends cannot be distributed if the Companys equity amounts to less than 10 percent
of the total assets, measured with reference to the Companys unconsolidated balance sheet
as of the prior fiscal year end, except if the Company follows a creditor notice procedure
provided for under the Norwegian Public Limited Companies Act in relation to reductions of
share capital.
    Dividends can only be distributed to the extent compatible with good and careful
business practice, with due regard to any losses which the Company may have incurred since
the balance sheet date (i.e., the prior fiscal year end) or which the Company may expect to
incur.
    The amount of dividends the Company can distribute is calculated on the basis of its
unconsolidated financial statements. Norwegian law does not permit the payment of dividends based on interim results of operations. Because the Company pays dividends in Norwegian kroner, exchange rate fluctuations will affect
the US dollar amounts received by holders of ADSs upon the conversion of cash dividends into US
dollars by the Depositary. Limitations on the Right to Own Ordinary Shares There are no restrictions affecting the right of non-Norwegian residents or citizens to own or
exercise voting rights with respect to the Companys ordinary shares. However, based on a 1917 law
as amended in 1994, which applies to Norwegian companies engaged in hydropower, mining and real
estate, no person or entity may acquire more than 20 percent (or the right to vote more than 20
percent) of the share capital of the Company, and no group of two or more persons may, whether by
mutual agreement or by family relationship, jointly or separately acquire an aggregate of more than
20 percent of the share capital of the Company or 20 percent of its voting rights unless such
person or persons obtain the consent of the Norwegian government. The Depositary and The Depository
Trust Company have been granted a concession from the Norwegian government to hold up to 25 percent
of the Companys ordinary shares in their respective capacities as depositaries. Restrictions on Transfer Except in certain circumstances, no acquirer of ordinary shares is entitled to any of the
rights of a shareholder unless and until he has registered the transfer in the Companys share
registry in the VPS. Under Norwegian law, the transferor must ensure that the VPS is notified of
any change of ownership immediately after it has taken place. The Articles of Association do not contain any provisions restricting the transferability of
ordinary shares other than that the Board of Directors may refuse to consent to the transfer of
ordinary shares and may take such other steps as may be necessary to prevent ordinary shares from
being transferred if in contravention of the restrictions, if any, then provided by applicable
Norwegian law. If the Board of Directors refuses to consent to a transfer of ordinary shares, the
Board must, without delay, notify the transferee of the decision as well as the reasons for such
refusal and what is required in order to remedy the matter. If the transferee has not been notified
of a refusal to grant consent within two months of the date of the VPSs receipt of notice of the
acquisition, the Boards consent shall be regarded as having been granted. If the Board refuses to
grant its consent to the acquisition of the ordinary shares, the transferee may (i) rescind the
purchase agreement with the transferor (unless otherwise provided in such agreement), (ii) dispose
of the shares, or (iii) bring a legal action against the Company with respect to the refusal to
grant consent. Any of the foregoing actions must be taken within two months from when the
transferee receives notice of the Boards refusal of consent to the transfer. If the transferee
fails to act in a timely manner, the Board of Directors may demand that the shares be sold. 137




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Additional Issuances and Preferential Rights All issuances of ordinary shares by the Company, including bonus issues (share dividends),
require an amendment of the Articles of Association (which specifies the Companys share capital)
and, thus, shareholder approval. In connection with an increase in the Companys share capital by a
subscription for shares against cash contributions, Norwegian law provides the Companys
shareholders with a preferential right to subscribe for the new shares on a pro ratabasis in
accordance with their then
current shareholdings in the Company. The preferential rights to subscribe to an issue may be
waived by a resolution in a general meeting passed by the same vote required to approve amendments
to the Articles of Association. The general meeting may, with a vote as described above, authorize the Board of Directors to
issue new shares. Such authorization may be effective for a maximum of two years, and the nominal
or par value of the shares to be issued may not exceed 50 percent of the nominal share capital when
the authorization was granted. Under Norwegian law, the general meeting must also approve the
waiver of the preferential rights of shareholders in connection with such issuances. Shareholders preferential rights, if any, are pro ratain accordance with their relative
holdings in the Companys ordinary shares at the time of such issuance. If not all shareholders
exercise their preferential rights (or not all shareholders exercise such rights in full),
shareholders who have exercised their preferential rights and want to acquire additional shares may
subscribe for those shares which have not been subscribed for, generally on a pro ratabasis based
on the number of shares for which preferential rights have been exercised. Under Norwegian law,
preferential rights cannot be set aside in the Articles of Association. The Companys Articles of Association provide that if the share capital is increased, and
provided the Norwegian law then in effect so permits, preferential subscription rights shall be
reserved in connection with each such capital increase, on the conditions stipulated by the Board
of Directors, for up to:  
    0.83 percent of the increase for holders of the 83 unredeemed founder
certificates, and
    2.79 percent of the increase for holders of the 4,343 unredeemed subscription
certificates. These preferential rights shall not apply if the increase is made in order to allot shares to
third parties as compensation for their transfer of assets to the Company. Under Norwegian law, bonus issues (share dividends) of the Companys ordinary shares may be
distributed, subject to shareholder approval, from amounts which (i) could otherwise be distributed
as dividends, or (ii) may be created by transferring funds from the Companys share premium reserve
or from retained earnings available for dividends. Such bonus issues (share dividends) may be
effected either by issuing new ordinary shares, allotted to the Companys shareholders on a pro
ratabasis, or by increasing the nominal value of the ordinary shares outstanding. Redemption of the Ordinary Shares The Articles of Association do not currently contain any provisions regarding the redemption
of the Companys ordinary shares. Under Norwegian law, a company may, upon a motion by its board of
directors and subject to obtaining shareholder approval, reduce its share capital to:  
    cover a loss which cannot be covered in any other way;
    effect a distribution to shareholders;
    effect a cancellation of treasury shares; or
    allocate amounts from share capital to reserves to be used in accordance with
the resolution adopted by the shareholders. The reduction in share capital may be implemented by a redemption of ordinary shares or by a
reduction in the nominal value of the shares. 138




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Related Party Transactions Under Norwegian law, an agreement to acquire assets or services from a shareholder or
connected person (e.g., a spouse or significant other, and other family members) of such
shareholder
which involves consideration from the Company in excess of 1/20th of the Companys share
capital at the time of such acquisition is not binding on the Company unless the agreement has been
approved by a general meeting. Business agreements in the normal course of the Companys business
containing pricing and other terms and conditions which are normal for such agreements, as well as
the purchase of securities at a price which is in accordance with the official quotation, do not
require such approval. Any performance of an agreement which is not binding on the Company must be
reversed. Minority Rights Norwegian law contains a number of protections for minority shareholders against oppression by
the majority. Any shareholder may petition the courts to have a decision of the Board of Directors
or general meeting declared invalid on the grounds that it unreasonably favors certain shareholders
or third parties to the detriment of other shareholders or the Company itself. In certain grave
circumstances, shareholders may require the courts to dissolve the Company as a result of such
decisions. Shareholders holding in the aggregate five percent or more of the Companys share
capital have a right to demand that the Company hold an extraordinary general meeting to discuss or
resolve specific matters. In addition, any shareholder may demand that the Company place an item on
the agenda for any general meeting if the Company is notified in time for such item to be included
in the notice of the meeting. Rights Upon Dissolution and Winding Up Any decision by a Norwegian company to dissolve generally requires the approval of two-thirds
of the votes cast by its shareholders, as well as two-thirds of the share capital represented at
the general meeting called to vote on the issue. If any conditions have occurred which, in
accordance with a companys articles of association, must result in the dissolution of the company,
or if the company must be dissolved as a result of a statutory provision, the shareholder proposal
with respect to the companys dissolution requires approval of the majority of votes cast at the
general meeting called to vote on the proposal. In the event of a dissolution, liquidation or
winding up of the Company, the holders of ordinary shares are entitled to share ratably in all
assets remaining after payment of all liabilities of the Company. Obligations upon Acquiring Certain Percentages of the Companys Shares Norwegian law requires any person, entity or group acting in concert that acquires more than
40 percent of the voting rights of a Norwegian company listed on the Oslo Stock Exchange (OSE) to
make an unconditional general offer to acquire the whole of the outstanding share capital of that
company. The offer is subject to approval by the OSE before submission of the offer to the
shareholders. The offer must be in cash or contain a cash alternative at least equivalent to any
other consideration offered. The offering price per share must be at least as high as the highest
price paid by the offeror in the six-month period prior to the date the 40 percent threshold was
exceeded, but equal to the market price if the market price was higher when the 40 percent
threshold was exceeded. A shareholder who fails to make the required offer must, within four weeks,
dispose of sufficient shares so that the obligation ceases to apply. Otherwise, the OSE may cause
the shares exceeding the 40 percent limit to be sold by public auction. A shareholder who fails to
make such offer cannot, as long as the mandatory offer requirement remains in force, vote the
portion of his shares that exceed the 40 percent limit or exercise any rights of share ownership in
respect of such shares, unless a majority of the remaining shareholders approve. However, such
shareholder retains the right to receive dividends and preferential rights in the event of a share
capital increase. In addition, the OSE may impose a daily fine upon a shareholder who fails to make
the required offer. 139




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If a shareholder, directly or via subsidiaries, acquires shares representing more than 90
percent of the total number of issued shares as well as more than 90 percent of the total voting
rights attached to those shares, then the majority shareholder has the right (and each remaining
minority shareholder of that company has the right to require the majority shareholder) to effect a
compulsory acquisition for cash of any shares not already owned by the majority shareholder. A
compulsory acquisition results in the majority shareholder becoming the owner of the shares of the
minority shareholders with immediate
effect. Upon effecting the compulsory acquisition, the majority shareholder must offer the minority
shareholders a specific price per share and to pay the consideration offered to a separate bank
account for the benefit of the minority shareholders. The determination of the price per share
would be at the discretion of the majority shareholder. If any minority shareholder does not accept
the offered price, such minority shareholder may, within a specified period of not less than two
months, request that the price be set by the Norwegian courts. The cost of the court procedure
would normally be charged to the account of the majority shareholder, and the courts would have
full discretion in determining the consideration due the minority shareholder as a result of the
compulsory acquisition. Transfers and Other Changes in Ownership of the Companys Shares by Directors and Officers Under Norwegian law, the individual members of the Board of Directors, the President and Chief
Executive Officer, and other key employees must immediately notify the Board of Directors of both
their own and their personal connected persons sale or acquisition of the Companys shares or
other securities. Such sale or acquisition must also be reported to the OSE, which will promptly
publish the notice through its information system. Insider Trading Legislation Under Norwegian law, the subscription, purchase, sale or exchange of securities that are
listed must not be undertaken by anyone who has information about the securities, the issuer
thereof, or other factors which may influence the price of the securities, and which is not
publicly available or generally known in the market. No member of the board or auditor associated
with the company issuing securities may subscribe for, or incite anyone to subscribe for, purchase,
sell or exchange financial instruments connected to the issuing company without properly
investigating whether there exists such information. This applies correspondingly to deputy members
and observers of the board of directors, senior employees of the company and senior employees and
board members of a company in the same group who can normally be expected to have access to such
information. The same restrictions apply to entering into the purchase, sale or exchange of
derivative rights connected to such securities. Description of American Depositary Receipts The following is a summary of certain provisions of the Amended and Restated Deposit
Agreement, dated as of 1 October 1987, as amended by Amendment No. 1, dated 27 May 1999 (the
Deposit Agreement), among the Company, JPMorgan Chase Bank (as successor in interest to Morgan
Guaranty Trust Company of New York), as Depositary and holders from time to time of the ADRs issued
by the Depositary under the Deposit Agreement. An ADR is the physical certificate that evidences
any number of American depositary shares (ADSs). Subject to the terms of the Deposit Agreement,
each ADS represents rights attributable to one ordinary share of the Company. This summary is not intended to be a complete description of the Deposit Agreement. Copies of
the Deposit Agreement are available for inspection at the Depositarys office located at 60 Wall
Street, New York, New York 10260 (the Depositarys Office) and at the principal Oslo office of
Den norske Bank (the Custodian) or any successor or additional custodian. The Deposit Agreement and the ADRs are governed by New York law. 140




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Deposit of Ordinary Shares A person or entity may register ordinary shares of the Company in the VPS System in the name
of the Depositary (as a nominee of such person or entity and not as a beneficial owner of such
shares). Ordinary shares (or evidence of rights to receive ordinary shares) may be deposited
through:  
    electronic transfer of such shares to the account of the Depositary in the
Companys share registry on the VPS System, or
    evidence, satisfactory to the Custodian, of irrevocable instructions to cause
the ordinary shares to be transferred to the Depositarys account, together with related
documentation specified in the Deposit Agreement. Subject to the terms and conditions of the Deposit Agreement, upon each deposit of ordinary
shares, receipt of related delivery documentation and compliance with the other provisions of the
Deposit Agreement, including the payment of the fees and charges of the Depositary and any taxes or
other fees or charges owing, the Depositary will issue an ADR or ADRs in the name of the person or
entity entitled to such ADR(s) evidencing the number of ADSs to which such person or entity is
entitled. Certificated ADRs will be delivered at the Depositarys Office. The Depositary may issue ADRs prior to the deposit of ordinary shares (or rights to receive
ordinary shares), referred to in the Deposit Agreement as a pre-release, only if: (i) the ADRs
are fully collateralized (marked to market daily) with cash or U.S. government securities until the
ordinary shares are deposited in the Depositarys name; (ii) the applicant for the ADRs represents
in writing that it owns the ordinary shares, has assigned all beneficial right, title and interest
in such ordinary shares to the Depositary, and will not dispose of such ordinary shares other than
in satisfaction of the pre-release; and (iii) all such ADRs represent not more than 20 percent of
all ADSs (excluding those evidenced by pre-released ADRs). The collateral shall be held for the
benefit of the ADR holders. The Depositary may retain for its own account any compensation for the
issuance of ADRs in connection with a pre-release, including any earnings on the held collateral. Transfer of ADRs The ADRs are transferable on the books of the Depositary; provided, however, that the
Depositary may close the transfer books at any time or from time to time when deemed expedient by
it in its reasonable judgment in connection with the performance of its duties. As a condition
precedent to the execution and delivery, registration of transfer, split-up, or combination or
surrender of, any ADR, or transfer and withdrawal of ordinary shares, the Depositary or the
Custodian may require payment from the person presenting the ADR or the depositor of the ordinary
shares of a sum sufficient to reimburse it for any taxes or other governmental charges and any
stock transfer or registration fees with respect the ADR or ordinary shares and payment of any
applicable fees payable by the holders of ADRs. The Depositary may refuse to deliver an ADR,
register the transfer of any ADR or make any distribution of, or related to, ordinary shares until
it or the Custodian has received such proof of citizenship, residence, exchange control approval,
legal or beneficial ownership or other information as it may deem necessary or proper or as the
Company may require by written request to the Depositary or the Custodian. The delivery, transfer
and surrender of ADRs generally may be suspended during any period when the transfer books of the
Depositary are closed, or if any such action is deemed necessary or advisable by the Depositary or
the Company at any time or from time to time because of any requirement of law or of any government
or governmental body or commission, or under any provision of the Deposit Agreement, or for any
other reason. Surrender of ADRs for purposes of Receiving Ordinary Shares and Other Deposited Securities An ADR holder may surrender its ADRs at the Depositarys Office for the purpose of withdrawal
of the ordinary shares represented thereby, together with all securities, property and cash
received by the Depositary or the Custodian in respect of or in lieu of such ordinary shares
(collectively, the Deposited Securities). Upon such surrender, the payment of applicable fees,
charges and taxes, and delivery of proper instructions, the holder is entitled to have the ordinary
shares relating to the 141




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surrendered ADRs registered in the name of the holder (or such other name as
the holder may request) in the VPS System. The holder is also entitled to delivery, at the
Depositarys Office or at the office of the Custodian, of a certificate or certificates for, or
other documents of title to, the Deposited Securities, if any, not registered in the VPS System
that are then represented by the surrendered ADRs. At the Depositarys discretion, the Depositary
may make delivery of any cash, dividends, distributions or rights with respect to the amount of the
Deposited Securities evidenced by the surrendered ADRs, or any proceeds of sale of such cash,
dividends, distributions or rights held by the Depositary. Under the terms of the Deposit Agreement, the Depositary may refuse or suspend the surrender
of outstanding ADRs only in connection with:  
    temporary delays caused by closing the transfer books of the Depositary or the
Company, the deposit of ordinary shares in connection with voting at a shareholders
meeting, or the payment of dividends;
    the payment of fees, taxes and similar charges; or
    compliance with any laws or governmental regulations relating to the ADRs or
to the withdrawal of Deposited Securities. Dividends and Other Distributions The Company may make various types of distributions with respect to its ordinary shares. Under
the terms of the Deposit Agreement, the Depositary has agreed to pay ADR holders the cash dividends
and other distributions received by the Custodian on any Deposited Securities. ADR holders shall
receive these distributions, in proportion to the number of ADSs held by them, in the following
manner: Cash Distributions Whenever the Depositary receives any cash dividend or other cash distribution by the Company
on any Deposited Securities, the Depositary is to convert such dividend or distribution into US
dollars and remit the amount received, net of applicable taxes and governmental charges, to the ADR
holders, net of any amounts required to be withheld by the Company, the Custodian or the Depositary
on account of taxes or other governmental charges and reasonable and customary expenses incurred by
the Depositary, if any, in the conversion of currency. The Depositary will distribute only such amount of the net cash dividend or other cash
distribution as can be distributed without attributing to any ADR holder a fraction of one cent.
Any balance not distributable on that basis will be held by the Depositary (without liability for
interest on such balance) and added to the next sum received by the Depositary for distribution to
holders of then outstanding ADRs. If the Depositary receives any currency other than US dollars, the Depositary is required, to
the extent that in its judgment it can convert such currency on a reasonable basis into US dollars
and transfer the resulting US dollars to the United States, to convert all cash dividends and other
cash distributions which it receives in respect of the Deposited Securities into US dollars. If the
Depositary determines, in its judgment, that such other currency received by it cannot be so
converted or transferred (or if any approval or license of a governmental authority or agency of
the United States required for such conversion is denied or is not obtainable or is not obtained
within a reasonable period as determined by the Depositary), the Depositary may distribute such
other currency (or documentation evidencing the right to receive the same) or, in its discretion,
hold such currency for the respective accounts of the ADR holders entitled to receive the same. If
any conversion of currency, in whole or in part, cannot be effected for distribution in US dollars
to some of the ADR holders, the Depositary may, in its discretion, convert the currency into US
dollars and distribute the same to ADR holders for whom such conversion and distribution is
practicable and distribute the balance of such currency to, or hold such balance for, the accounts
of the ADR holders for whom such conversion and distribution is not practicable. 142




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Distributions of Ordinary Shares If a distribution by the Company consists of a dividend in, or distribution of, ordinary
shares, the Depositary may, with the Companys approval, and shall, if the Company so requests,
distribute to
the ADR holders additional ADRs for an aggregate number of ADSs representing the number of ordinary
shares received as such dividend or distribution. In lieu of delivering ADRs for fractional ADSs,
the Depositary may sell the amount of ordinary shares represented by the aggregate of such
fractions and distribute the net proceeds in the manner described with respect to cash
distributions. If additional ADRs are not so distributed (other than with respect to fractional
ADSs), each ADS will then represent the additional ordinary shares distributed upon the Deposited
Securities represented thereby. Distributions other than Cash or Ordinary Shares If the Depositary receives any distribution upon the Deposited Securities in a form other than
cash or the Companys ordinary shares (e.g., other securities or property), the Depositary is to
distribute the same in any manner that the Depositary deems equitable and practicable. If, in the
opinion of the Depositary, it cannot distribute such distribution (for example, because of its
determination that such distribution in the United States would be unlawful) or cannot do so
proportionately among the ADR holders, the Depositary may, with the Companys approval, adopt such
method as it deems equitable and practicable to effect the distribution, including the sale (at
public or private sale) of the securities or other property distributed, or any part of the
distribution, and then distribute the net proceeds of any such sale in the manner described with
respect to cash distributions. Subscription Rights In the event that the Company offers (or causes to be offered) to the holders of any Deposited
Securities any rights to subscribe for additional ordinary shares or any rights of any other
nature, the Depositary, after consultation with the Company, has discretion to (i) follow a
procedure to make such rights available to the ADR holders, or (ii) dispose of such rights and make
the net proceeds available in US dollars to such holders. However, if requested by the Company, the
Depositary is to either:  (a)
    if lawful and feasible at the time of the rights offering, make such rights
available to ADR holders by means of warrants or other instruments, or employ another
method deemed feasible to facilitate the exercise, sale or transfer of the rights by the
ADR holders; or(b)
    if not then lawful and feasible by means of warrants or other instruments (or if
the rights represented by such warrants or other instruments are not exercised and appear
to be about to lapse), sell such rights or such warrants or other instruments at public
or private sale on terms the Depositary deems proper, and allocate the proceeds of any
such sale for the accounts of the ADR holders, upon an averaged or other practicable
basis without regard to distinctions among ADR holders because of the application of
exchange restrictions applicable to any particular ADR holder(s), the date of delivery of
ADRs or otherwise. Record Dates Whenever any cash dividend or other cash distribution, if any, becomes payable or any
distribution other than cash is made, or rights are issued, with respect to the Deposited
Securities, or whenever the Depositary receives notice of any meeting of holders of ordinary shares
or other Deposited Securities, the Depositary will, after consultation with the Company, if the
Company so requests, fix a record date for the determination of the ADR holders who will be
entitled to receive such dividend, distribution or rights, or the net proceeds of the sale of the
dividend, distribution or rights, to give instructions for the exercise of voting rights at any
such meeting. 143




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Voting of the Underlying Ordinary Shares Upon receipt of notice of any meeting of holders of ordinary shares or other Deposited
Securities, the Depositary is obligated, as soon as practicable thereafter, to mail to ADR holders
(i) a notice containing a summary of such information as is contained in such notice of meeting and
a statement that ADR holders at the close of business on a specified record date will be entitled,
subject to applicable Norwegian law and the Companys articles of association, to instruct the
Depositary as to the
exercise of voting rights, if any, pertaining to the ordinary shares or other Deposited Securities
underlying their ADSs, and (ii) a statement as to the manner in which such instructions may be
given, including an express indication that instructions may be given to the Depositary to give a
discretionary proxy to a person designated by the Company. Upon the written request of an ADR
holder on such record date, received on or before the date established by the Depositary for such
purpose, the Depositary will endeavor insofar as practicable to vote or cause to be voted the
ordinary shares or other Deposited Securities under the ADSs evidenced by the holders ADRs in
accordance with any non-discretionary instructions set forth in such request. Under the Companys
articles of association, notice of shareholders meeting must be given at least 14 days in advance
of the meeting. Unless notification of a meeting is given in sufficient time to permit the
Depositary to notify ADR holders of the proposed meeting and to allow holders to take the steps
described above, ADR holders will not be able to exercise voting rights with respect to the
ordinary shares underlying their ADRs. The Depositary will not, under any circumstances, exercise any discretion as to voting.
Further, the Depositary will not vote the ordinary shares or other Deposited Securities represented
by ADRs other than in accordance with the written instructions received from ADR holders. Reports and Notices The Depositary will make available for inspection by ADR holders at the Depositarys Office
any reports and communications received from the Company which are both (a) received by the
Depositary or its nominee or nominees as the holder of the Deposited Securities, and (b) made
generally available to the holders of such Deposited Securities by the Company. The Depositary will
mail to ADR holders copies of notices of shareholder meetings (or adjournments thereof) furnished
by the Company to the Custodian, the taking of any action in respect of cash or other
distributions, or any rights offering. Amendment and Termination of the Deposit Agreement The form of the ADRs and the Deposit Agreement may at any time be amended by agreement between
the Company and the Depositary. Any amendment which imposes or increases any fees or charges (other
than stock transfer or other taxes and other governmental charges, transfer or registration fees,
cable, telex or facsimile transmission costs, delivery costs, and expenses of the Depositary in
connection with conversion of any currency into US dollars) or which otherwise prejudices any
substantial existing right of ADR holders, will not take effect as to outstanding ADRs until the
expiration of three months after the Depositary has given notice of such amendment to the ADR
holders. Every ADR holder at the time such amendment becomes effective will be deemed, by
continuing to hold such ADR(s), to consent and agree to such amendment and to be bound by the
Deposit Agreement as amended thereby. In no event may any amendment impair the rights of any ADR
holder to surrender its ADRs and receive the Deposited Securities represented thereby. Whenever so directed by the Company, the Depositary has agreed to terminate the Deposit
Agreement by mailing notice of such termination to the holders of the ADRs then outstanding at
least 60 days prior to the date fixed in such notice for such termination. The Depositary may
likewise terminate the Deposit Agreement at any time 60 days after the Depositary has delivered to
the Company a notice of its election to resign if a successor depositary has not, within the 60-day
period, been appointed and accepted its appointment as provided in the Deposit Agreement. If any
ADRs remain outstanding after the termination date, the Depositary will then discontinue the
registration of transfer of ADRs, suspend the distribution of dividends to the holders and not give
any further notices or perform any further acts under the Deposit Agreement. The Depositary will
continue to collect dividends and 144




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other distributions pertaining to the Deposited Securities, sell
rights as provided in the Deposit Agreement, deliver ordinary shares and other property represented
by ADRs and the net proceeds of the sale of any rights or other property, in exchange for
surrendered ADRs. At any time after the expiration of two years from the termination date, the
Depositary may sell the Deposited Securities and hold the net proceeds, together with any other
cash then held, without liability for interest, for the pro ratabenefit of the holders of ADRs
which have not previously been surrendered. Charges of Depositary The Depositary will charge the party to whom ADRs are delivered against deposits, and the
party surrendering ADRs for delivery of ordinary shares or other deposited securities, property and
cash, $5.00 for each 100 ADSs (or fraction thereof) represented by the ADRs issued or surrendered.
The Company will pay all other charges of the Depositary and those of any registrar or co-registrar
under the Deposit Agreement, except for taxes and other governmental charges, any applicable share
transfer or registration fees on deposits or withdrawals of ordinary shares, certain cable, telex,
facsimile transmission and delivery charges and such expenses as are incurred by the Depositary in
the conversion of foreign currency into US dollars. The Company will pay all charges and expenses
of the Depositary in connection with the initial issuance of ADRs payable as a dividend or
distribution to shareholders and in connection with any rights offering to shareholders. The
charges and expenses of the Custodian are for the sole account of the Depositary. Limitations on Obligations and Liability to ADR Holders Neither the Depositary nor the Company will be liable to the holders of ADRs if prevented or
delayed by law, governmental authority, any provision of the Companys articles of association or
any circumstances beyond its control in performing its obligations under the Deposit Agreement or
if obliged to do or perform any act or thing inconsistent with the provisions of the Deposit
Agreement. The obligations of the Company and the Depositary under the Deposit Agreement are
expressly limited to using their best judgment and good faith in performing their respective duties
specified in the Deposit Agreement. Neither the Depositary nor the Company has any obligation to appear in, prosecute or defend
any action, suit or other proceeding in respect of any Deposited Securities or the ADRs which, in
its opinion, may involve it in expense or liability, unless indemnity satisfactory to it against
all expense (including fees and disbursements of counsel) and liability is furnished as often as
may be required. The Depositary will not be responsible for any failure to carry out any instructions to vote
any of the Deposited Securities, or for the manner in which any vote is cast or the effect of any
such vote, provided that any such action or failure to act is in good faith. The Depositary, subject to the laws of Norway, the Companys articles of association and the
terms of the Deposit Agreement, may own and deal in any class of the Companys securities and in
ADRs. 
 ITEM 10.C. MATERIAL CONTRACTS Item 10.C. of Form 20-F requires a summary of each material contract, other than contracts
entered into in the ordinary course of business, to which the Company or any member of the Group is
a party, for the two years immediately preceding publication of the Form 20-F. In accordance with
this requirement, please see Exhibit 4 and Exhibit 99.4 pertaining to the new employment contract
for Mr. Eivind Reiten, the Companys President and CEO, and the Agri demerger plan. Mr. Reitens
employment contract is required to be filed in accordance with Instruction 4 to Item 19 of Form
20-F. 145




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ITEM 10.D. EXCHANGE CONTROLS Under current Norwegian foreign exchange regulations, transfers of capital to and from Norway
are not subject to prior approval from Norwegian authorities or the Central Bank provided that
payments are made through licensed banks. Thus, non-Norwegian shareholders may receive dividend
payments without a Norwegian exchange control consent. 
 ITEM 10.E. TAXATION United States Federal Income Tax Consequences The following discussion outlines certain potential United States federal income tax
consequences of the acquisition, ownership and disposition of the Companys ordinary shares or
ADSs. The discussion generally applies to a U.S. holder (as defined below) of ordinary shares or
ADSs that holds the same as capital assets for tax purposes. This discussion does not apply to
certain U.S. holders subject to special rules, such as dealers in securities, traders in securities
that elect to use a mark-to-market method of accounting for their securities holdings, tax-exempt
entities (including pension plans), life insurance companies, persons liable for alternative
minimum tax, persons that hold ordinary shares or ADSs through a partnership or other pass-through
entity, persons that hold shares or ADSs as part of a straddle or a hedging or conversion
transaction or persons whose functional currency is not the US dollar. This discussion is based on the Internal Revenue Code of 1986, as amended (the Code), its
legislative history, existing and proposed regulations, published rulings and court decisions, and
the Convention between the United States and the Kingdom of Norway for the Avoidance of Double
Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income and Property (the
"Treaty). These authorities are subject to change at any time, possibly on a retroactive basis. In
addition, this discussion is based in part upon the representations of the Depositary and the
assumption that each obligation in the Deposit Agreement and any related agreement will be
performed in accordance with its terms. A holder of ordinary shares or ADSs is a U.S. holder if the holder is a beneficial owner of
such shares or ADSs and is (i) a citizen or resident of the United States, (ii) a corporation
created or organized in or under the laws of the United States or any political subdivision
thereof, (iii) an estate whose income is subject to United States federal income tax regardless of
its source, or (iv) a trust, if a court in the United States can exercise primary supervision over
the trusts administration and one or more United States persons are authorized to control all
substantial decisions of the trust. A non-U.S. holder is a beneficial owner of ordinary shares or ADSs that is not a U.S.
holder. The Company recommends that you consult your own tax advisor regarding the U.S. federal,
state, local and other tax consequences of acquiring, owning and disposing of ordinary shares and
ADSs in your particular circumstances. Taking into account the above assumptions, for U.S. federal income tax purposes, if you hold
ADRs evidencing ADSs, you generally will be treated as the owner of the ordinary shares represented
by those ADSs. Taxation of Dividends A non-Norwegian shareholder is generally subject to a withholding tax at a rate of 25 percent
on dividends distributed by Norwegian companies, unless the non-Norwegian shareholder is carrying
on business activities in Norway and such shares are effectively connected with such activities.
The withholding tax of 25 percent may be lower pursuant to tax treaties between Norway and the
country in which the shareholder is resident. The Treaty rate is generally 15 percent. The Treaty
withholding tax rate will generally apply to dividends paid on shares held directly by U.S. holders
that are residents of the United States within the meaning of the Treaty. 146




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Dividends paid to the Depositary for redistribution to U.S. holders will generally be subject
to a withholding tax of 15 percent. If you are a U.S. holder, you must generally include in your
gross income for United States federal income tax purposes as a dividend the gross amount of any
distribution made by the Company out of its current or accumulated earnings and profits (as
determined for United States federal income tax purposes). You must include in gross income any
Norwegian tax withheld from any dividend even though you do not, in fact, receive the amount
withheld as tax. You must include any dividend in income when you (in the case of shares) or the
Depositary (in the case of ADSs) receive the dividend, actually or constructively. The dividend
will not be eligible for the dividends-received
deduction generally allowed to United States corporations in respect of dividends received from
other United States corporations. For taxable years beginning after 31 December 2002, and before 1 January 2009, dividends
received by U.S. holders that are individuals, estates or trusts from qualified foreign
corporations, as defined in Section 1(h)(11) of the Code, generally are taxed at the preferential
tax rates applicable to long-term capital gains. Section 1(h)(11) of the Code defines a qualified
foreign corporation as a foreign corporation the stock of which is readily tradable on an
established securities market in the United States (including through ADRs) or a foreign
corporation that is eligible for the benefits of one of certain comprehensive income tax treaties
with the United States that include an exchange of information program. The Company expects that it
will constitute a qualified foreign corporation provided that it is not treated as a Foreign
Personal Holding Company, Foreign Investment Company, or Passive Foreign Investment Company,
which it believes will be the case. There can be no assurance, however, that the Company will not
be treated as a Foreign Personal Holding Company, Foreign Investment Company, or Passive
Foreign Investment Company for 2004. Recently enacted law has eliminated the Foreign Personal
Holding Company and Foreign Investment Company rules for taxable years beginning after 31
December 2004. Accordingly, for 2005 and future taxable years, the Company will constitute a
qualified foreign corporation so long as it is not treated as a Passive Foreign Investment
Company. Dividends received in a taxable year when the Company does not constitute a qualified foreign
corporation, or in a taxable year immediately after one in which the Company did not constitute a
qualified foreign corporation, will be subject to U.S. federal income tax at ordinary income tax
rates. In 2003, the U.S. Department of the Treasury (the Treasury) and the Internal Revenue Service
(the IRS) announced that they expected to issue regulations providing procedures for a foreign
corporation to certify that it is a qualified foreign corporation. Such regulations were not
issued in 2004, but Treasury and the IRS have confirmed their intent shortly to issue the
regulations in proposed form. It is expected that these regulations will require persons required
to file information returns to report a distribution with respect to a foreign security issued by a
foreign corporation as a dividend from a qualified foreign corporation if the foreign corporation
has, among other things, certified under penalties of perjury that the foreign corporation is not,
in the taxable year of the corporation in which the distribution was paid, and was not in the
preceding taxable year, a Foreign Personal Holding Company, Foreign Investment Company, or
Passive Foreign Investment Company. If regulations are issued in 2005, the Company anticipates certifying that it is a qualified
foreign corporation for the year ending 31 December 2005. In addition to the foregoing requirements, a dividend received by a U.S. holder is taxed at
the rate applicable to long-term capital gains only if the U.S. holder satisfies certain holding
period requirements. Thus, a dividend on ordinary shares or ADSs is taxed at preferential rates
only if the U.S. holder receiving the dividend has held such ordinary shares or ADSs for at least
61 days during the 121-day period beginning 60 days before the first date when such ordinary shares
or ADSs could be sold without an entitlement to the dividend (the ex-dividend date). The dividend
rules are complex and the Company recommends that a U.S. holder consult his or her own tax advisor
regarding the dividend rules and how these rules may affect his or her U.S. federal, state, local
and other income tax situation. 147




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The amount of the dividend that any U.S. holder must include in income is the US dollar value
of the gross amount of the Norwegian kroner dividend, determined at the spot Norwegian kroner/US
dollar exchange rate on the date the dividend distribution is included in your income, regardless
of whether the payment is, in fact, converted into US dollars. Distributions to a U.S holder in excess of such holders pro rata share of the Companys
current and accumulated earnings and profits, as determined for United States federal income tax
purposes, will be treated as a nontaxable return of capital to the extent of your tax basis in the
ordinary shares or ADSs and, to the extent such distribution exceeds your tax basis, the
distribution will be treated as capital gain. Subject to certain limitations, the 15 percent Norwegian tax withheld in accordance with the
Treaty and paid over to Norway will be creditable against your United States federal income tax
liability. Dividends will be income from sources outside the United States, but generally will be
passive income or financial services income, which is treated separately from other types of
income, for purposes of computing the foreign tax credit allowable to you. Alternatively, you may
elect to claim a U.S. tax deduction, instead of a foreign tax credit, for such Norwegian tax, but
only for a year in which you elect to do so with respect to all foreign income taxes. Any gain or loss resulting from currency exchange fluctuations during the period from the date
you include the dividend payment in income to the date you convert the payment into US dollars
generally will be treated as ordinary income or loss. Such gain or loss generally will be income or
loss from sources within the United States for foreign tax credit limitation purposes. If you are a non-U.S. holder, dividends paid to you in respect of ordinary shares or ADSs will
not generally be subject to United States federal income tax unless the dividends are effectively
connected with the conduct of a trade or business within the United States or are attributable to
a permanent establishment or fixed base that you maintain in the United States (if that is required
by an applicable income tax treaty as a condition for subjecting you to United States taxation on a
net income basis). In such cases, you will generally be taxed in the same manner as a U.S. holder.
If you are a corporate non-U.S. holder, effectively connected dividends may, under certain
circumstances, be subject to an additional branch profits tax at a 30 percent rate or at a lower
rate if you are eligible for the benefits of an income tax treaty that provides for a lower rate. Taxation of Capital Gains If you are a U.S. holder and you sell or otherwise dispose of your ordinary shares or ADSs,
you will generally recognize capital gain or loss for United States federal income tax purposes
equal to the difference between the US dollar value of the amount that you realize and your tax
basis, determined in US dollars, in your ordinary shares or ADSs. Capital gain of a non-corporate
U.S. holder is generally taxed at a maximum rate of 15 percent where the property has been held for
more than one year. The gain or loss will generally be income or loss from sources within the
United States for foreign tax credit limitation purposes. If you receive any foreign currency on
the sale of ordinary shares or ADSs, you may recognize U.S.-source ordinary income or loss as a
result of currency fluctuations between the date of the sale of the ordinary shares or ADSs and the
date the sales proceeds are converted into US dollars. If you are a non-U.S. holder, you will not be subject to United States federal income tax on
gain recognized on the sale or other disposition of your ordinary shares or ADSs unless: (i) the
gain is effectively connected with a trade or business in the United States, or the gain is
attributable to a permanent establishment or fixed base in the United States (if that is required
by an applicable income tax treaty), or (ii) if you are an individual, you are present in the
United States for at least 183 days in the taxable year of the sale, and certain other conditions
exist. If you are a corporate non-U.S. holder, effectively connected gains that you recognize may
also, under certain circumstances, be subject to an additional branch profits tax at a rate of 30
percent or at a lower rate if you are eligible for the benefits of an income tax treaty that
provides for a lower rate. 148




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Passive Foreign Investment Company (PFIC) Rules The Company believes that its ordinary shares and ADSs should not be treated as shares of a
passive foreign investment company, or PFIC, for United States federal income tax purposes.
However, this conclusion is a factual determination that is made annually and may, therefore, be
subject to change. A PFIC is defined as a corporation that is not formed in the United States and, for any
taxable year, either (i) 75% or more of its gross income is passive income or (ii) the average
percentage, by fair market value (or, if the corporation is not publicly traded and either is a
controlled foreign corporation or makes an election, by adjusted tax basis) of its assets that
produce or are held for the
production of passive income is 50% or more. Passive income generally includes dividends,
interest, certain rents and royalties, certain gains from the sale of stock and securities, and
certain gains from commodities transactions. For purposes of the PFIC income test and the assets test, if a foreign corporation owns
(directly or indirectly) at least 25% by value of the stock of another corporation, such foreign
corporation shall be treated as if it (a) held a proportionate share of the assets of such other
corporation, and (b) received directly its proportionate share of the income of such other
corporation. Also, for purposes of such PFIC tests, passive income does not include any interest,
dividends, rents or royalties that are received or accrued from a related person to the extent
such amount is properly allocable to the income of such related person which is not passive income. U.S. holders owning shares of a PFIC are subject to the highest rate of tax on ordinary income
in effect for the applicable taxable year and to an interest charge based on the value of deferral
of tax for the period during which the shares of the PFIC are owned with respect to certain excess
distributions on and certain dispositions of PFIC stock. However, if the U.S. holder makes a
timely election to treat a PFIC as a qualified electing fund (QEF) with respect to such
shareholders interest therein, the above-described rules generally will not apply. Instead, the
electing U.S. holder would include annually in his gross income his pro rata share of the PFICs
ordinary earnings and net capital gain regardless of whether such income or gain was actually
distributed. A U.S. holder of a QEF may, however, elect to defer the payment of U.S. federal income
tax on such income inclusions. In addition, subject to certain limitations, U.S. holders owning,
actually or constructively, marketable stock (as specifically defined) in a PFIC will be permitted
to elect to mark that stock to market annually, rather than be subject to the tax regime described
above. Amounts included in or deducted from income under this alternative (and actual gains and
losses realized upon disposition, subject to certain limitations) will be treated as ordinary gains
or losses. The Company believes that it was not a PFIC for its fiscal year ended 31 December 2003.
However, there can be no assurance that the Company will not be considered a PFIC for the current
or any future taxable year. There can be no assurance that the Companys determination concerning
its PFIC status will not be challenged by the IRS, or that it will be able to satisfy record
keeping requirements that will be imposed on QEFs in the event that it qualifies as a PFIC. If you are a U.S. holder and you own shares or ADSs during any year that the Company is a
PFIC, you must generally file IRS Form 8621. Backup Withholding and Information Reporting Dividend payments, or other taxable distributions, made within the United States to a
non-corporate U.S. resident generally will be subject to information reporting requirements and
backup withholding tax at a rate of 28 percent if the resident (i) fails to provide an accurate
taxpayer identification number, (ii) is notified by the IRS that the resident has failed to report
all interest or dividends required to be shown on federal income tax returns, or (iii) in certain
circumstances, fails to comply with applicable certification requirements. 149




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Persons that are not United States persons may be required to establish their exemption from
information reporting and backup withholding by certifying their status on an appropriate IRS Form
W-8. If you sell your ordinary shares or ADSs to or through a United States office of a broker, the
payment of the proceeds is subject to both United States backup withholding and information
reporting unless you certify, under penalties of perjury, that you are a non-U.S. person or you
otherwise establish an exemption. If you sell your ordinary shares or ADSs outside the United
States through a non-U.S. office of a non-U.S. broker, and the sale proceeds are paid to you
outside the United States, then United States backup withholding and information reporting
requirements generally will not apply to that payment. However, U.S. information reporting, but not
backup withholding, will apply to a payment of
sales proceeds, even if that payment is made outside of the United States, if you sell your
ordinary shares or ADSs through a non-U.S. office of a broker that:  
    is a U.S. person,
    derives 50 percent or more of its gross income for a specified three-year
period from the conduct of a trade or business in the United States,
    is a controlled foreign corporation as to the United States, or
    is a foreign partnership, if at any time during its tax year: (i) one or more
of its partners are U.S. persons, as defined in U.S. Treasury regulations, who in the
aggregate hold more than 50 percent of the income or capital interest in the partnership,
or (ii) at any time during its tax year the foreign partnership is engaged in a U.S. trade
or business, unless the broker has documentary evidence in its records that you are a non-U.S. person and does
not have actual knowledge that you are a U.S. person or you otherwise establish an exemption. You generally may obtain a refund of any amount withheld under the backup withholding rules
that exceeds your income tax liability by filing a timely refund claim with the IRS. 
 ITEM 10.F. DIVIDENDS AND PAYING AGENTS In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 10.F. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 10.G. STATEMENT BY EXPERTS In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 10.G. if, as is the case in this instance, the Form 20-F is being
filed as an annual report under the Exchange Act. 
 ITEM 10.H. DOCUMENTS ON DISPLAY The English translation of the Articles of Association has been filed as an exhibit to this
annual report. See the Index to Exhibits. 
 ITEM 10.I. SUBSIDIARY INFORMATION In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 10.I. if, as is the case in this instance, the Form 20-F is being
filed in the United States. 150




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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Quantitative and qualitative information about market risk as of 31 December 2004 is included
in the section titled Risk Management in Item 5 of this annual report. All statements other than
historical information included in the Risk Management section are forward-looking statements. The
actual impact of future market changes could differ materially due to, among other things, the risk
factors discussed in the annual report. 
 ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES In accordance with the instructions to Form 20-F, the Company does not need to provide the
information called for by Item 12 if, as is the case in this instance, the Form 20-F is being filed
as an annual report under the Exchange Act. 151




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PART II 
 ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES Item 13 of Form 20-F requires information with respect to (i) any material default in the
payment of principal, interest, a sinking or purchase fund installment, or any other material
default not cured within 30 days, relating to indebtedness of the Company or any of its significant
subsidiaries, (ii) the payment of dividends if in arrears, (iii) any other material delinquency not
cured within 30 days, relating to any class of preferred stock. There is nothing to report by the
Company within the scope of this Item requirement. 
 ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE
OF PROCEEDS None. 
 ITEM 15. CONTROLS AND PROCEDURES; CEO AND CFO CERTIFICATIONS Under the supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, the Company has evaluated (as required by Exchange
Act Rules 13a-15(b) and 15d-15(b)) the effectiveness of the design and operation of its disclosure
controls and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the
end of the period covered by this annual report. In designing and evaluating the Companys disclosure controls and procedures, management,
including the Chief Executive Officer and Chief Financial Officer, recognized that any controls and
procedures, no matter how well designed and operated, can provide only reasonable assurance of
achieving the desired control objectives. Because of the inherent limitations in all control
systems, no evaluation of controls can provide absolute assurance that all control issues and
instances of fraud, if any, have been detected. Management was also necessarily required to apply
its judgment in evaluating the cost-benefit relationship of possible controls and procedures. Based on their evaluation, the Chief Executive Officer and Chief Financial Officer have
concluded that the Companys disclosure controls and procedures are designed to provide reasonable
assurance of achieving the Companys desired control objectives and that these disclosure controls
and procedures are, in fact, effective at a reasonable assurance level. There has been no change in the Companys internal control over financial reporting that
occurred during the period covered by this annual report on Form 20-F that has materially affected,
or is reasonably likely to materially affect, the Companys internal control over financial
reporting. 
 ITEM 16A. AUDIT COMMITTEE FINANCIAL EXPERT The Board of Directors has determined that Hydro has at least one audit committee financial
expert (as that term is defined in SEC rules) serving on its Audit Committee: Kurt Anker Nielsen.
The Board has further determined that Mr. Nielsen is independent within the parameters set forth
in Exchange Act Rule 10A-3. 
 ITEM 16B. CODE OF ETHICS In July 2003, the Board of Directors approved a new code of conduct (the Code of Conduct)
that applies to all Hydro employees (including the Companys President and Chief Executive Officer,
Senior Vice President and Chief Financial Officer, and Senior Vice President, Corporate Accounting
and Consolidation) throughout the world, as well as to Board members of the Company and its
subsidiaries. The main purpose of the Code of Conduct is to ensure that all persons acting on
behalf of 152




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Hydro perform their activities in an ethical matter and in accordance with Hydro standards.
The Code of Conduct provides channels for complaints, for instance over questionable accounting or
auditing matters. It also addresses requirements regarding personal conduct, integrity, compliance
with laws and other matters such as handling of conflicts of interest and a commitment to equal
opportunities for all employees. The Code of Conduct has been posted on Hydros website
(www.hydro.com). 
 ITEM 16C. PRINCIPAL ACCOUNTANT FEES AND SERVICES Deloitte Statsautoriserte Revisorer AS (Deloitte) is the principal auditor of Norsk Hydro ASA.
Certain portions of audits are performed by Ernst & Young and other firms. The following table
shows total audit and non-audit fees for the fiscal years ended 31 December 2004 and 2003. Audit
    
    
    
    OtherYear ended 31 December 2004
    
    
    
    
    
    
    
    related
    
    
    
    non-auditAmounts in NOK thousand
    
    
    Audit fees
    
    
    
    Fees(1)
    
    
    
    Fees(2)
    
    
    
    Tax fees(3)
    
    
    
    TotalDeloitte Norway
    
    
    
    24,691
    
    
    
    
    2,018
    
    
    
    
    1,337
    
    
    
    
    17
    
    
    
    
    28,063Deloitte Abroad
    
    
    
    23,399
    
    
    
    
    4,899
    
    
    
    
    427
    
    
    
    
    7,445
    
    
    
    
    36,170Total Deloitte
    
    
    
    48,090
    
    
    
    
    6,917
    
    
    
    
    1,764
    
    
    
    
    7,462
    
    
    
    
    64,233Ernst & Young (5)
    
    
    
    11,095
    
    
    
    
    929
    
    
    
    
    0
    
    
    
    
    2,200
    
    
    
    
    14,224Others
    
    
    
    3,660
    
    
    
    
    1,314
    
    
    
    
    1,215
    
    
    
    
    1,774
    
    
    
    
    7,963Total fees
    
    
    
    62,845
    
    
    
    
    9,160
    
    
    
    
    2,979
    
    
    
    
    11,436
    
    
    
    
    86,420
 Audit
    
    
    
    OtherYear ended 31 December 2003(4)
    
    
    
    
    
    
    
    related
    
    
    
    non-auditAmounts in NOK thousand
    
    
    Audit fees
    
    
    
    Fees(1)
    
    
    
    Fees(2)
    
    
    
    Tax fees(3)
    
    
    
    TotalDeloitte Norway
    
    
    
    26,257
    
    
    
    
    1,839
    
    
    
    
    8,069
    
    
    
    
    400
    
    
    
    
    36,565Deloitte Abroad
    
    
    
    32,728
    
    
    
    
    2,911
    
    
    
    
    1,863
    
    
    
    
    3,828
    
    
    
    
    41,330Total Deloitte
    
    
    
    58,985
    
    
    
    
    4,750
    
    
    
    
    9,932
    
    
    
    
    4,228
    
    
    
    
    77,895Ernst & Young (5)
    
    
    
    16,998
    
    
    
    
    1,486
    
    
    
    
    1,076
    
    
    
    
    4,768
    
    
    
    
    24,328Others
    
    
    
    11,096
    
    
    
    
    2,941
    
    
    
    
    1,296
    
    
    
    
    2,677
    
    
    
    
    18,010Total fees
    
    
    
    87,079
    
    
    
    
    9,177
    
    
    
    
    12,304
    
    
    
    
    11,673
    
    
    
    
    120,233
   (1)
    
    Audit related fees primarily consist of consultations for financial accounting
reporting standards, SEC filings and compliance with new SEC rules and regulations, as well
as audit and agreed-upon procedures in connection with acquisitions and divestments. In
addition, there are other miscellaneous audit related projects at subsidiaries throughout
the world.(2)
    
    Other non-audit fees primarily consist of agreed-upon procedures associated with the
Companys environmental and sustainability reporting.(3)
    
    Tax fees are made up of various tax services such as: tax planning and support, tax
controversy assistance, expatriate taxes, employee benefit taxes, tax compliance and
support, tax opinions, tax-only valuations, and transfer-pricing evaluations.(4)
    
    Fee amounts for 2003 include services rendered to activities transferred to Yara in
March 2004.(5)
    
    Amounts for Ernst & Young related to Hydro subsidiaries under Ernst & Youngs audit.
Ernst & Young provides non-audit services to subsidiaries that it does not audit; such fees
are not included in this table. Pre-approval Policy In the Spring of 2003, the Audit Committee established a pre-approval policy governing the
engagement of the Companys primary and other external auditors to provide audit and permissible
non-audit services for or on behalf of the Company or any entity within the Hydro Group. The
pre-approval policy is intended to safeguard the continued independence of such auditors, ensuring
that: (1) the auditors are not functioning in the role of management; (2) the auditors are not
auditing their own work; and (3) the auditors are not serving in an advocacy role for the Company
and/or its affiliates. 153




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Under the pre-approval policy, the Audit Committee has defined and pre-approved subcategories
of audit and non-audit services, such non-audit services being limited to services permissible to
be provided by the Companys primary external auditors under SEC regulations. The Audit Committees
pre-approval includes annual monetary frames for each of the following categories of services:  
    audit-related;
    tax; and
    non-audit related. The Audit Committee chairperson is authorized to approve changes to the subcategories of the
services and/or any increase in the monetary frames between regular meetings of the Audit
Committee. Any such change is to be disclosed to the full Audit Committee on a quarterly basis. The Audit Committees pre-approval policy also applies to auditors, other than the Companys
primary external auditors, which, in the aggregate, audit more than 5 percent of Hydros
consolidated assets or income from continuing operations before tax. For such auditors, the
pre-approval policy applies only to services provided to the Hydro subsidiary or subsidiaries under
audit. Within the scope of the pre-approval policy, all services have been pre-approved and all
amounts for audit related, tax and other non-audit related services are within the monetary frames
established by the audit committee. 
 ITEM 16D. EXEMPTION FROM THE LISTING STANDARDS FOR AUDIT COMMITTEES Not Applicable 
 ITEM 16E. PURCHASE OF EQUITY SECURITIES BY THE ISSUER AND AFFILIATED
PURCHASERS The annual general meeting held in May 2004 approved the Board of Directors proposal to
repurchase up to 2,808,810 of the Companys shares for an 18 month period. The following table
shows the total number of shares repurchased in the open market, and the average price paid per share for each month
starting June 2004, the month the Company began to repurchase its shares. Total Number of
    
    
    
    Maximum Number ofShares Purchased as
    
    
    
    Shares that May YetPart of Publicly
    
    
    
    be Purchased UnderPeriod
    
    
    Total Number of
    
    
    
    Average Price Paid
    
    
    
    Announced Plans or
    
    
    
    the Plans or2004
    
    
    Shares Purchased
    
    
    
    per Share in NOK
    
    
    
    Programs
    
    
    
    Programs1 - 30 June
    
    
    
    653,000
    
    
    
    
    434.45
    
    
    
    
    653,000
    
    
    
    
    2,155,8101 - 31 July
    
    
    
    630,460
    
    
    
    
    432.02
    
    
    
    
    630,460
    
    
    
    
    1,525,3501 - 31 August
    
    
    
    1,055,200
    
    
    
    
    434.41
    
    
    
    
    1,055,200
    
    
    
    
    470,1501 - 30 September
    
    
    
    470,150
    
    
    
    
    476.65
    
    
    
    
    470,150
    
    
    
    
    0Total
    
    
    
    2,808,810
    
    
    
    
    440.95
    
    
    
    
    2,808,810
    
    
    
    
    0
 154




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PART III 
 ITEM 17. FINANCIAL STATEMENTS Not applicable. 
 ITEM 18. FINANCIAL STATEMENTS The Companys Consolidated Financial Statements as of and for the year ended 31 December 2004
and the related notes thereto, which are included in Exhibit 10 of this Annual Report, as well as
the schedule to the Consolidated Financial Statements listed in Item 19(a), have been audited by
Deloitte Statsautoriserte Revisorer AS, independent public accountants, as indicated in their
report. Reference is made to Item 19 for a list of all financial statements included in Exhibit 10
or filed herewith. 
 ITEM 19. FINANCIAL STATEMENTS AND EXHIBITS  a.
    Financial StatementsThe following are filed as part of this annual report onForm 20-F:Schedule II  Valuation and qualifying accounts and
reserves  page 157The following is included in Exhibit 10 to this annual report onForm 20-F: Pages *Report of Independent Registered Public Accounting Firm
Consent of Independent Registered Public Accounting Firm
Consolidated income statements for the years ended
31 December 2004, 2003, and 2002
    
    
    10-1Consolidated statements of comprehensive income for the
years ended 31 December 2004, 2003, and 2002
    
    
    10-1Consolidated balance sheets at 31 December 2004 and 2003
    
    
    10-2Consolidated statements of cash flows for the years ended
31 December 2004, 2003, and 2002
    
    
    10-3Notes to the Consolidated Financial Statements
    
    10-4 to 10-39
   *
    
    Page references are to the page numbering in Exhibit 10 b. Exhibits Exhibit No.
    
    Description1.
    
    The Companys Articles of Association (as amended and currently in effect)4.
    
    CEOs Employment Contract8.
    
    Significant Subsidiaries of the Company10.
    
    Consolidated Financial Statements (including the notes thereto)
 155




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##### 



Exhibit No.
    
    Description12.1
    
    Certification of Eivind Reiten, President and Chief Executive Officer of
Norsk Hydro ASA, pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a)12.2
    
    Certification of John Ove Ottestad, Executive Vice President and Chief
Financial Officer of Norsk Hydro ASA, pursuant to Exchange Act Rule 13a-14(a) or Rule
15d-14(a)13.
    
    Certifications furnished pursuant to Rule 13a-14(b) or Rule 15d-14(b)99.1
    
    Information regarding the Corporate Assembly Members, Deputy Members and
Observers99.2
    
    Operational Data99.3
    
    Audit Committee Mandate99.4
    
    The Demerger Plan (incorporated by reference to Exhibit 1 to the Companys
report on Form 6-K dated December 1, 2003)
 156




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##### 



Norsk Hydro ASA and Subsidiaries
Schedule II  Valuation and Qualifying Accounts and Reserves (Amount in NOK million) AdditionsCharged to otherBalance at
    
    
    
    Charged to costs
    
    
    
    accounts
    
    
    
    
    
    
    
    
    Balance at end ofDescription
    
    
    beginning of period
    
    
    
    and expenses
    
    
    
    (1)
    
    
    
    Deductions (2)
    
    
    
    periodYear-end 31 December 2004Allowance for doubtful accounts
    
    
    
    922
    
    
    
    
    199
    
    
    
    
    39
    
    
    
    
    (269
    )
    
    
    
    891Valuation allowance for deferred tax assets
    
    
    
    1,047
    
    
    
    
    (25
    )
    
    
    
    (55
    )
    
    
    
    
    
    
    
    
    967Environment accruals
    
    
    
    5,576
    
    
    
    
    395
    
    
    
    
    895
    
    
    
    
    (235
    )
    
    
    
    6,631Year-end 31 December 2003Allowance for doubtful accounts
    
    
    
    685
    
    
    
    
    737
    
    
    
    
    138
    
    
    
    
    (638
    )
    
    
    
    922Valuation allowance for deferred tax assets
    
    
    
    945
    
    
    
    
    22
    
    
    
    
    80
    
    
    
    
    
    
    
    
    
    1,047Environment accruals (3)
    
    
    
    5,216
    
    
    
    
    337
    
    
    
    
    401
    
    
    
    
    (378
    )
    
    
    
    5,576Year-end 31 December 2002Allowance for doubtful accounts
    
    
    
    559
    
    
    
    
    322
    
    
    
    
    21
    
    
    
    
    (217
    )
    
    
    
    685Valuation allowance for deferred tax assets
    
    
    
    727
    
    
    
    
    (163
    )
    
    
    
    381
    
    
    
    
    
    
    
    
    
    945Environment accruals
    
    
    
    2,188
    
    
    
    
    323
    
    
    
    
    513
    
    
    
    
    (215
    )
    
    
    
    2,809
   (1)
    
    Includes amounts recognized in business combinations and foreign currency
translation adjustments.(2)
    
    Deductions primarily represent uncollectible accounts charged against the allowance
for doubtful accounts and expenditures related to and reductions of environmental accruals.(3)
    
    Effective 1 January 2003, Hydro implemented the accounting standard for asset
retirement obligations, such as decommissioning and abandonment of oil and gas production
platforms, facilities and pipelines [SFAS 143]. The accounting standard requires that the fair
value of future asset retirement obligations be recorded in the Companys balance sheet in the
period it is incurred; accordingly, obligations for oil and gas installations should be
recognized at the start of production. Asset retirement costs are capitalized as part of the
assets original cost and depreciated over the assets useful life, while changes to the
present value of the obligations are charged to earnings. The changes resulted in an increase
in the capitalized value of fixed assets by NOK 1,089 million. The increase in the original
cost of fixed assets was NOK 1,918 million and related accumulated depreciation was NOK 829
million. In addition, liabilities for asset retirement obligations increased NOK 2,407 million
to NOK 4,538 million. 157




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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. NORSK HYDRO ASADate: 18 March 2005
    
    /s/ John O. OttestadJohn O. OttestadExecutive Vice President andChief Financial Officer
 158




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##### 



Glossary Terms Relating to the Groups Businesses and Operations Term
    
    
    DefinitionADRs
    
    
    American Depositary Receipts, evidencing a specified number of ADSsADSs
    
    

American Depositary Shares, each ADS representing one deposited
ordinary shareAluNorf
    
    
    Aluminium Norf GmbHArticles of Association
    
    
    The articles of association of the Company, as amended and
currently in effectAudit Committee
    
    
    The audit committee of the Companys Board of DirectorsAutomotive
    
    
    The Automotive sector of Hydro Aluminium, comprising precision
tubing, structures and shape casting businesses worldwideBAT
    
    
    Best Available Techniques for pollution prevention and controlCode
    
    
    The U.S. Internal Revenue Code of 1986, as amended.Company
    
    
    Norsk Hydro ASA, a Norwegian public company limited by shares, or
Norsk Hydro ASA and its consolidated subsidiaries, as the context
requiresCompensation Committee
    
    
    The compensation committee of the Companys Board of DirectorsConsolidated Financial
Statements
    
    
    The consolidated financial statements and notes included in the
Companys annual report to shareholders for the year ended 31
December 2004, included in Exhibit 10 to this annual report on
Form 20-FCorporate Assembly
    
    
    The corporate assembly, a body contemplated by Norwegian
companies law, with responsibility, among other things, for the
election of the members of the Companys Board of Directors and
nomination of the external auditorCorporate Management
Board
    
    
    The corporate management board established by the Companys
President and Chief Executive Officer to assist him in discharging
his responsibilitiesCRU
    
    
    CRU International LimitedCustodian
    
    
    Den norske Bank, the custodian in connection with the Companys
ADR facilityDeposit Agreement
    
    
    Deposit Agreement, dated as of 3 January 1986, as amended and
restated as of 1 October 1987, and as further amended by Amendment
No. 1 thereto, dated 27 May 1999, among the Company, the
Depositary and the holders from time to time of the ADRsDepositary
    
    
    JPMorgan Chase Bank, as depositary of the ADSsDepositarys Office
    
    

The Depositarys office located at [60 Wall Street, New York, New
York 10260]Deposited Securities
    
    
    ADRs, together with all securities, property and cash received by
the Depositary or the Custodian in respect of or in lieu of the
Companys ordinary sharesDisclosure Committee
    
    
    The disclosure committee of the Company, comprised of members of
senior management, which is responsible for reviewing financial
and
 159




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##### 



related information before it is made publicEEA
    
    
    European Economic AreaEEA Agreement
    
    
    The European Economic Area AgreementEFTA
    
    
    European Free Trade AssociationExchange Act
    
    
    The U.S. Securities Exchange Act of 1934, as amendedExtrusion
    
    
    The Extrusion sector of Hydro AluminiumEU
    
    
    European UnionGFU
    
    
    The Gas Negotiation Committee (Gassforhandlingsutvalget)Group
    
    
    Norsk Hydro ASA and its consolidated subsidiariesHBP
    
    
    Hydro Business Partner, a business unit of Norsk Hydro ASA and
Norsk Hydro Produksjon ASHSE
    
    
    Health, safety and environmentHydro
    
    
    Norsk Hydro ASA and its consolidated subsidiariesHydro Aluminium
    
    
    The aluminium business of Hydro, comprising the sub-segments
Metals, Rolled Products, and Extrusion and AutomotiveHydro Oil and Energy
    
    
    The oil and energy business of Hydro, comprising two sub-segments,
Exploration and Production, and Energy and Oil MarketingkWh
    
    
    Kilowatt hourLME
    
    
    London Metals ExchangeMetals
    
    
    Hydro Aluminiums Metals sub-segment, which comprises the Primary
Metal sector and the Metals Products sectorMinistry
    
    
    The Norwegian Ministry of Petroleum and Energymm
    
    
    MillimeterNCS
    
    
    Norwegian Continental ShelfNOC
    
    
    The National Oil Company of LibyaNOK
    
    
    Norwegian kronerNomination Committee
    
    
    The nomination committee provided for in the Companys Articles of
Association and operating under a charter established by the
shareholders representatives in the Corporate AssemblyNoon Buying Rate
    
    
    The noon buying rate in the City of New York for cable transfers
in foreign currencies, as announced by the Federal Reserve Bank of
New York for customs purposesNorth America
    
    
    The North America sector of Hydro AluminiumNYSE
    
    
    New York Stock ExchangeOPEC
    
    
    Organization of the Petroleum Exporting CountriesOSE
    
    
    Oslo Stock ExchangePVC
    
    
    Polyvinyl chloride, a plastic raw materialP-PVC
    
    
    Paste PVCS-PVC
    
    
    Suspension PVCRolled Products
    
    
    Hydro Aluminiums Rolled Products sub-segmentSanctions Act
    
    
    The Iran and Libya Sanctions Act of 1996, adopted by the United
StatesSarbanes-Oxley Act
    
    
    The U.S. Sarbanes-Oxley Act of 2002SDFI
    
    
    The Norwegian States Direct Financial Interest
 160




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##### 



SEC
    
    
    The United States Securities and Exchange CommissionSecurities Act
    
    
    The U.S. Securities Act of 1933, as amendedtonne
    
    
    One metric tonne (approximately 1,000 kilograms or 2,205 pounds)TWh
    
    
    Terawatt hour (one billion kilowatt hours)US GAAP
    
    
    Generally accepted accounting principles in the United StatesVAW
    
    
    VAW Aluminium AGVCM
    
    
    Vinyl chloride monomer, the main raw material for PVCVPS or VPS System
    
    
    The Norwegian Central Securities Depository, Verdipapirsentralen.WTO
    
    
    World Trade OrganizationYara
    
    
    Yara International ASA
 161