##### 



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 1934
 OR x
    
    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For The Fiscal Year Ended December 31, 2003 OR o
    
    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, Vaekerø
 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
Ordinary Shares, par value NOK 18.30 per share
    
    New York Stock Exchange
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. 256,712,000 Ordinary Shares, whose par value was then NOK 20.00 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




---



##### 



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
    
    
    18C. Organizational Structure
    
    
    76D. Property, Plants and Equipment
    
    
    76Item 5. Operating and Financial Review and Prospects
    
    
    77Item 6. Directors, Senior Managers and Employees
    
    
    118A. Directors, Corporate Assembly and Corporate Management Board
    
    
    118B. Compensation
    
    
    122C. Board Practices
    
    
    124D. Employees
    
    
    128E. Share Ownership
    
    
    129Item 7. Major Shareholders and Related Party Transactions
    
    
    130A. Major Shareholders
    
    
    130B. Related Party Transactions
    
    
    131C. Interests of Experts and Counsel
    
    
    131Item 8. Financial Information
    
    
    132A. Consolidated Financial Statements and Other Financial Information
    
    
    132B. Significant Changes
    
    
    135Item 9. The Offer and Listing
    
    
    136A. Offer and Listing Details
    
    
    136B. Plan of Distribution
    
    
    137C. Markets
    
    
    137D. Selling Shareholders
    
    
    137E. Dilution
    
    
    137F. Expenses of the Issue
    
    
    137
 2




---



##### 



ITEM
    
    PAGEItem 10. Additional Information
    
    
    137A. Share Capital
    
    
    137B. Articles of Association
    
    
    137C. Material Contracts
    
    
    150D. Exchange Controls
    
    
    151E. Taxation
    
    
    151F. Dividends and Paying Agents
    
    
    155G. Statement by Experts
    
    
    155H. Documents on Display
    
    
    155I. Subsidiary Information
    
    
    155Item 11. Quantitative and Qualitative Disclosures About Market Risk
    
    
    156Item 12. Description of Securities Other Than Equity Securities
    
    
    156PART IIItem 13. Defaults, Dividend Arrearages and Delinquencies
    
    
    157Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds
    
    
    157Item 15. Controls and Procedures; CEO and CFO Certifications
    
    
    157Item 16A. Audit Committee Financial Expert
    
    
    158Item 16B. Code of Ethics
    
    
    158Item 16C. Principal Accountant Fees and Services
    
    
    159PART IIIItem 17. Financial Statements
    
    
    160Item 18. Financial Statements
    
    
    160Item 19. Financial Statements and Exhibits
    
    
    160
 3




---



##### 



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)1999
    
    7.842000
    
    8.832001
    
    9.002002
    
    7.932003
    
    7.06
 Noon Buying RateCalendar Monthly Period
    
    High
    
    LowDecember 2003
    
    
    6.83
    
    6.64January 2004
    
    
    7.07
    
    6.66February 2004
    
    
    7.07
    
    6.84March 2004
    
    
    7.14
    
    6.82April 2004
    
    
    7.00
    
    6.82May 2004
    
    
    6.97
    
    6.70
  (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 June 18, 2004 was NOK 6.89 = $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




---



##### 



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
December 31, 2003, 2002, 2001, 2000 and 1999 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 December 31, 2003, 2002 and 2001 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 December 31, 2003 (the
"Consolidated Financial Statements), included in Exhibit 10 to this annual
report on Form 20-F. 5




---



##### 



Income Statement Data(1)  Year ended December 31,2003
    
    2002
    
    2001
    
    2000
    
    1999(in NOK million, except per share data)Operating revenues (2)(3) (4)
    
    
    171,782
    
    
    
    167,040
    
    
    
    152,999
    
    
    
    156,467
    
    
    
    111,955Operating costs and expenses excluding
depreciation, impairment
and restructuring charges (2)(4)
    
    
    132,431
    
    
    
    133,297
    
    
    
    118,722
    
    
    
    115,328
    
    
    
    93,094Depreciation
    
    
    15,093
    
    
    
    13,912
    
    
    
    12,273
    
    
    
    12,538
    
    
    
    10,494Restructuring charges (5)
    
    
    
    
    
    
    (10
    )
    
    
    921
    
    
    
    135
    
    
    
    632Operating income before financial
and other items
    
    
    24,258
    
    
    
    19,841
    
    
    
    21,083
    
    
    
    28,466
    
    
    
    7,735Financial and other income (expense), net (6)
    
    
    1,484
    
    
    
    1,670
    
    
    
    3,991
    
    
    
    5,580
    
    
    
    3,193Interest expense and foreign exchange gain
(loss)
    
    
    (1,266
    )
    
    
    517
    
    
    
    (3,609
    )
    
    
    (3,905
    )
    
    
    (3,055
    )Income before taxes and minority interest
    
    
    24,476
    
    
    
    22,028
    
    
    
    21,465
    
    
    
    30,141
    
    
    
    7,873Provision for taxes
    
    
    (13,937
    )
    
    
    (13,278
    )
    
    
    (13,750
    )
    
    
    (16,178
    )
    
    
    (4,337
    )Minority interest
    
    
    148
    
    
    
    15
    
    
    
    177
    
    
    
    18
    
    
    
    (90
    )Income (loss) before cumulative effect of
accounting changes
    
    
    10,687
    
    
    
    8,765
    
    
    
    7,892
    
    
    
    13,981
    
    
    
    3,446Cumulative effect of accounting change for:Start-up costs
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (30
    )Asset
retirement (implementation of SFAS 143)
    
    
    281
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net income (loss)
    
    
    10,968
    
    
    
    8,765
    
    
    
    7,892
    
    
    
    13,981
    
    
    
    3,416Earnings (loss) per share:Before cumulative effect of accounting
changes
    
    
    41.50
    
    
    
    34.00
    
    
    
    30.50
    
    
    
    53.40
    
    
    
    13.90Cumulative effect of accounting changes
    
    
    1.10
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (0.10
    )Earnings (loss) per share:
    
    
    42.60
    
    
    
    34.00
    
    
    
    30.50
    
    
    
    53.40
    
    
    
    13.80Avg. number of outstanding ordinary shares
    
    
    257,528,511
    
    
    
    257,799,411
    
    
    
    258,434,202
    
    
    
    261,620,982
    
    
    
    247,045,270Cash dividends paid per share during period:NOK per
share (7)
    
    
    10.50
    
    
    
    10.00
    
    
    
    9.50
    
    
    
    8.00
    
    
    
    7.50Converted into USD per share (7)
    
    
    1.56
    
    
    
    1.24
    
    
    
    1.05
    
    
    
    0.90
    
    
    
    0.94
  (1)
    
    See Note 2 to the Consolidated Financial Statements for a
discussion of significant business acquisitions and dispositions during
the three-year period ended December 31, 2003.(2)
    
    As of fiscal year 2000, operating revenues for certain trading
activities have been presented on a gross basis in the income
statement. The amounts for 1999 have been restated to reflect the
change. As a result, operating revenues and operating costs have
increased by NOK 9,522 million in 1999.(3)
    
    Effective January 1, 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 October 25, 2002. For contracts entered
after October 25, 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




---



##### 



Balance Sheet Data(1)  As of December 31,2003
    
    2002
    
    2001
    
    2000
    
    1999(in NOK million)Cash, cash equivalents
and other liquid assets
    
    
    16,830
    
    
    
    8,612
    
    
    
    29,569
    
    
    
    24,257
    
    
    
    9,970Total assets
    
    
    218,629
    
    
    
    207,211
    
    
    
    197,922
    
    
    
    196,354
    
    
    
    177,419Short-term debt
    
    
    6,811
    
    
    
    9,264
    
    
    
    10,424
    
    
    
    11,297
    
    
    
    8,268Long-term debt
    
    
    28,568
    
    
    
    30,902
    
    
    
    37,853
    
    
    
    40,174
    
    
    
    42,228Deferred tax liabilities
    
    
    34,083
    
    
    
    37,071
    
    
    
    31,429
    
    
    
    31,644
    
    
    
    30,573Ordinary shares and
additional paid-in capital
    
    
    20,403
    
    
    
    20,420
    
    
    
    20,402
    
    
    
    20,391
    
    
    
    20,387Total shareholders equity
    
    
    80,080
    
    
    
    75,867
    
    
    
    74,793
    
    
    
    71,227
    
    
    
    59,497
  (1)
    
    See Note 2 to the Consolidated Financial Statements for a
discussion of significant business acquisitions and dispositions during
the three-year period ended December 31, 2003. 7




---



##### 



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 December 31, 2003.  Operating Income/(Loss)Sales to Unaffiliated
    
    Before Financial andOperating Revenues
    
    Customers
    
    Other IncomeYear ended December 31,Business Segment (1)
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Exploration and Production (2)
    
    
    37,904
    
    
    
    32,970
    
    
    
    32,426
    
    
    
    12,099
    
    
    
    10,136
    
    
    
    6,992
    
    
    
    18,500
    
    
    
    13,137
    
    
    
    16,910Energy and Oil Marketing (2)
    
    
    49,370
    
    
    
    45,915
    
    
    
    45,824
    
    
    
    44,308
    
    
    
    41,929
    
    
    
    41,315
    
    
    
    2,668
    
    
    
    2,784
    
    
    
    2,267Eliminations
    
    
    (27,315
    )
    
    
    (23,040
    )
    
    
    (26,070
    )
    
    
    (1,576
    )
    
    
    (965
    )
    
    
    (846
    )
    
    
    (25
    )
    
    
    26
    
    
    
    Hydro Oil and Energy
    
    
    59,959
    
    
    
    55,845
    
    
    
    52,180
    
    
    
    54,831
    
    
    
    51,100
    
    
    
    47,461
    
    
    
    21,143
    
    
    
    15,947
    
    
    
    19,177Metals
    
    
    39,923
    
    
    
    39,646
    
    
    
    31,475
    
    
    
    26,509
    
    
    
    26,025
    
    
    
    24,961
    
    
    
    2,293
    
    
    
    1,690
    
    
    
    372Rolled Products
    
    
    18,377
    
    
    
    14,790
    
    
    
    4,228
    
    
    
    17,825
    
    
    
    14,135
    
    
    
    4,126
    
    
    
    132
    
    
    
    (295
    )
    
    
    58Extrusion and Automotive
    
    
    24,529
    
    
    
    24,245
    
    
    
    22,487
    
    
    
    24,472
    
    
    
    24,186
    
    
    
    21,854
    
    
    
    98
    
    
    
    14
    
    
    
    (228
    )Other and Eliminations (3)
    
    
    (13,677
    )
    
    
    (13,630
    )
    
    
    (7,107
    )
    
    
    190
    
    
    
    162
    
    
    
    1
    
    
    
    (67
    )
    
    
    289
    
    
    
    (17
    )Hydro Aluminium
    
    
    69,152
    
    
    
    65,051
    
    
    
    51,083
    
    
    
    68,996
    
    
    
    64,508
    
    
    
    50,942
    
    
    
    2,456
    
    
    
    1,698
    
    
    
    185Hydro Agri
    
    
    38,174
    
    
    
    33,348
    
    
    
    37,407
    
    
    
    37,828
    
    
    
    32,818
    
    
    
    36,809
    
    
    
    2,800
    
    
    
    2,207
    
    
    
    2,114Other Activities (4)
    
    
    14,013
    
    
    
    21,769
    
    
    
    22,361
    
    
    
    10,206
    
    
    
    17,988
    
    
    
    17,714
    
    
    
    (414
    )
    
    
    13
    
    
    
    (340
    )Corporate and Eliminations (5)
    
    
    (9,516
    )
    
    
    (8,973
    )
    
    
    (10,032
    )
    
    
    (79
    )
    
    
    626
    
    
    
    73
    
    
    
    (1,727
    )
    
    
    (24
    )
    
    
    (53
    )Total
    
    
    171,782
    
    
    
    167,040
    
    
    
    152,999
    
    
    
    171,782
    
    
    
    167,040
    
    
    
    152,999
    
    
    
    24,258
    
    
    
    19,841
    
    
    
    21,083
  (1)
    
    See Note 2 to the Consolidated Financial Statements for a
discussion of significant business acquisitions and dispositions during
the three-year period ended December 31, 2003.(2)
    
    As of January 1, 2003, Hydros gas transportation activities are
reported as part of Energy and Oil Marketing. Prior periods have been
reclassified for comparative purposes.(3)
    
    Other and Eliminations includes unrealized gains and losses
related to London Metals Exchange (LME) contracts with a loss of NOK 49
million in 2003, a gain of NOK 266 million in 2002 and a loss of NOK 50
million in 2001.(4)
    
    Other Activities consist of the following: Petrochemicals, Treka
AS (previously A/S Korn- og Foderstof Kompagniet or KFK), Flexible
Packaging, Pronova, the industrial insurance company,
Industriforsikring, and Hydro Business Partner.(5)
    
    Corporate and Eliminations includes the elimination of the
unrealized gains included in Hydro Energys results relating to
internal sales contracts for power. These eliminations resulted in a
charge to Corporate and Eliminations of NOK 141 million in 2003
compared with a gain of NOK 588 million in 2002. Corporate and
Eliminations operating income (loss) also includes a net periodic
pension cost of NOK 1,146 million for 2003, NOK 312 million for 2002,
and a credit of NOK 421 million in 2001. 8




---



##### 



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
and develop additional oil and gas reserves that are economically
recoverable. The majority of Hydro Oil and Energys proved reserves (93 percent as of
December 31, 2003) 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 NCS. Exploration for oil and gas involves a high degree of risk that
hydrocarbons will not be found or that they will not be found in commercial
quantities. The 3-D seismic data and other appraisal technologies Hydro Oil and
Energy uses do not provide conclusive knowledge prior to drilling a well that
oil or gas is present or economically feasible to extract. Accordingly, Hydro
Oil and Energys drilling activity with respect to any particular project area
or areas may be unsuccessful. The overall performance of Hydros exploration
activity during the last few years has not met expectations, in particular, the
activity on Block 34 in Angola and the drilling activity in the US Gulf of
Mexico. See the discussion in Item 4.B. Business Overview  Hydro Oil and
Energy  Exploration and Production  Strategy  Building the Basis for Future
Production. 9




---



##### 



The cost of drilling, completing and operating a well is often uncertain
and can result in cost overruns negatively impacting the potential returns of a
given project. Offshore drilling in deep-water (such as in Angola and the US
Gulf of Mexico) is extremely expensive and long-term in nature. Drilling
operations may be curtailed, delayed or cancelled as a result of factors
outside of Hydros control, such as unexpected drilling conditions, pressure or
irregularities in geological formations, equipment failures or accidents,
adverse weather conditions, and shortages or delays in the availability of
drilling rigs. Further, completion of a well does not guarantee that it will be
profitable or even that it will result in recovery of drilling, completion and
operating costs. 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. In addition,
the volume of production from oil and natural gas properties generally declines
as reserves from those prospects are depleted. Hydro Oil and Energys future
production is highly dependent upon its success in finding or acquiring, and
developing, additional reserves. If unsuccessful, proved reserves will decline,
which will, in turn, adversely affect Hydros results of operations and
financial condition. Hydro Oil and Energys development projects involve many uncertainties and
operating risks that can prevent Hydro from realizing profits and can cause
substantial losses. On the NCS, Hydro Oil and Energy is increasingly developing smaller
satellite fields in mature areas. 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 a very uneven seabed. 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:  
    
    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. 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
results of operations and financial condition, and ability to finance planned
capital expenditures. 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 1,450 million and NOK 390 million, respectively. Lower oil
and natural gas prices also may influence the amount of oil and natural gas
that Hydro can produce economically or reduce the potential return and
viability of projects being considered or in development. 10




---



##### 



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 2,900 million and NOK 785 million,
respectively. 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. In April 2004, the
Bush administration announced the termination of application of the Sanctions
Act with respect to Libya, but the Sanctions Act continues in force with
respect to Iran. If the U.S. government were to determine that a persons activities in
Iran or Libya are covered by the Sanctions Act, the Act requires the President
of the United States to apply two or more sanctions, including a ban on any
license to export goods or technology to a sanctioned person, a prohibition of
loans or extensions of credit by U.S. financial institutions in an amount
greater than U.S.$10 million in any 12-month period to the sanctioned person,
and restrictions on imports into the United States from a sanctioned person.
The President also has the authority to grant country-specific and
project-specific waivers of these sanctions under certain circumstances. To
date, there have not been any sanctions imposed against any person or entity
under the Sanctions Act, which makes it difficult to predict how any sanctions,
if imposed, would be implemented and enforced against an individual company if
a violation of the Sanctions Act were to be determined to exist or have
occurred. Hydro cannot predict future interpretations of, or the implementation
policy of the U.S. government with respect to, the Sanctions Act. However,
taking into consideration the limited size of Hydros operations in Iran and
Libya relative to its total oil and energy activities, as well as Hydros
operations not currently importing from the United States any goods or
technology requiring a license from the U.S. government, the absence, at
present, of any loans or extensions of credit from U.S. 11




---



##### 



financial institutions, and other relevant considerations, Hydro does not
believe that imposition of sanctions under the Sanctions Act (should a
violation be determined to exist or have occurred) would have a material
adverse effect on Hydros financial condition or results of operations. Risks Relating to Hydro Aluminiums Business Hydro Aluminiums results of operations are affected by the cyclicality of
the aluminium industry. The aluminium industry is highly cyclical. Hydro Aluminiums results of
operations could be negatively affected as a result of unfavorable economic
conditions or conditions affecting the aluminium industry specifically. In
particular, Hydro Aluminium is exposed to economic conditions in Europe, as a
significant portion of its products is sold into the European market. Virtually
all aluminium end-use markets, including the building, transportation and
packaging industries, are also cyclical. When downturns occur in these
industries, decreased demand for aluminium may result in lower prices for Hydro
Aluminiums products, which may have an adverse effect on Hydro Aluminiums
results of operations. Aluminium product prices, reflecting the cyclicality of the aluminium
industry, have been volatile historically. Hydro Aluminium expects such
volatility to continue. The London Metals Exchange (LME) price, in US
dollars, is the main reference price for aluminium contracts worldwide. The
variance in the LME price can have a material effect upon Hydro Aluminiums
results as a whole. The operating results of Hydro Aluminiums Metals
sub-segments upstream operations, in particular, are negatively affected by
lower LME prices. 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 875 million and NOK 615 million, respectively. Hydro makes extensive use of derivatives in managing its aluminium price
exposure, which can result in volatility of its accounting results from period
to period. Hydro Aluminium is exposed to foreign exchange rate fluctuations. The LME price for aluminium is denominated in US dollars. Further, a
portion of Hydro Aluminiums production of aluminium is sold in local
currencies, including the euro, based on US dollar exchange rates. Accordingly,
operating results, which are reported in Norwegian kroner, will be reduced by a
strengthening of the Norwegian kroner against the US dollar. Based on our
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 Aluminiums pre-tax income and after-tax
income by approximately NOK 2,100 million and NOK 1,475 million, respectively. As a result of Hydros acquisition in 2002 of the German and overseas
smelters of VAW Aluminium AG, a major integrated international aluminium
company based in Germany (VAW), Hydro Aluminiums Metals sub-segment has
reduced Hydro Aluminiums relative exposure to the USD/NOK exchange rate, but
increased the exposure to changes in the USD/euro and NOK/euro exchange rates. Although alumina prices are denominated in US dollars (as are most of
Hydro Aluminiums raw materials costs), Hydro Aluminiums Brazilian-based
alumina business, through its non-consolidated investee, Alunorte, is exposed
to the USD/Brazilian real exchange rate, which can affect Hydro Aluminiums
operating results. A decline in the value of the Brazilian real against the US
dollar (the US dollar being the predominant financing currency for Alunorte)
can lead to a currency loss with respect to the Metals sub-segments interest
in Alunorte. In 2002, currency losses related to Alunorte
were NOK 461 million, while changes in currency rates resulted in a currency
gain of NOK 218 million for 2003. 12




---



##### 



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 7 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. See the discussion in Item 4.B.
Business Overview  Hydro Aluminium  Hydro Aluminiums Operating Sub-Segments
 Metals  Raw Materials  Energy. Reduction in regulation of electricity markets in Europe continues at
varying rates of progress from country to country. See the discussion in Item
4.B. Business Overview  Hydro Oil and Energy  Oil and Energy Government
Regulation  Liberalization of European Electricity Markets. There is a
possibility of new environmental taxes on electricity. 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. 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 operating results could decline as a result of government
actions or the absence of such actions in respect of third parties, under
current or future laws and regulations pertaining to the market and trade
in aluminium. Hydro Aluminiums operating results could decline as a result of
government actions such as controls on imports, exports and prices, new forms
of taxation, and increased government regulation in the countries in which
Hydro Aluminium operates or services customers. In addition, Hydro Aluminium is
subject to the disruptive effects of dumped or subsidized products in markets
by producers engaging in unfair competition. Such activities may not result in
the application of anti-dumping or countervailing duties by appropriate
governmental agencies and any such duties imposed may be insufficient to
eliminate all of the potential negative effects of such practices. For example,
increased quantities of Chinese magnesium available in Western markets
contributed to Hydros decision to close its primary magnesium facility in
Norway in 2001, notwithstanding anti-dumping duties imposed on China by the
European Community. In addition, Hydro Aluminiums shipments to certain markets may be
subjected to anti-dumping and/or countervailing duties that could negatively
affect Hydros competitive position. Any such actions could affect Hydro
Aluminiums revenues, expenses and results of operations. 13




---



##### 



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s operations may also be unable to meet customers
quality demands due to obsolete technology or other problems in Hydro
Aluminiums operations. 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. Risks Relating to the Demerger Norwegian law subjects Hydro and Yara to joint liability after the
Demerger. As a result of the demerger of Hydros Agri business (the Demerger),
which was completed on March 24, 2004, the obligations of Hydro have been
divided between Hydro and Yara International ASA (Yara), the company formed
to act as the transferee company in the Demerger, in accordance with the
agreement memorializing the terms of the Demerger (the Demerger Plan). For
more information on the Demerger, see Item 4.A. History and Development of the
Company  Demerger of Hydro Agri. If either Hydro or Yara is liable under the
Demerger Plan for an obligation that arose prior to completion of the Demerger
and fails to satisfy that obligation, the non-defaulting party will, in
accordance with applicable provisions of the Norwegian Public Limited Companies
Act, be jointly and severally liable for the obligation. This statutory
liability is unlimited in time, but is limited in amount to the equivalent of
the net value allocated to the non-defaulting party in the Demerger. In addition to the joint and several liability provided under Norwegian
law, Hydro has issued a number of guarantees for the payment and performance
obligations of companies that are now part of the Yara group following
consummation of the Demerger. The aggregate amounts payable under such
guarantees that are limited in amount was approximately NOK 3.4 billion as of
March 5, 2004. In addition, Hydro has issued some guarantees that are not
limited in amount as credit support for long-term commercial contracts.
Although Hydro and Yara are using commercially reasonable efforts to obtain
Hydros release from outstanding guarantees in consideration for the
substitution of Yara, there can be no assurance that such releases will
actually be obtained. Certain aspects of the Demerger could cause Hydro to incur tax or
tax-related liabilities. The Demerger involved the separation of the activities of Hydros Agri
business from those of Hydro in a number of countries. Certain of these
separations were structured so as not to be subject to tax in Norway and other
jurisdictions. However, in certain circumstances, actions taken after the
Demerger could cause one or more of the separations, or the Demerger, to be
taxable to Hydro. For example, a change in either Hydros or Yaras business or
corporate structure after the Demerger could result in a tax liability for one
or more companies within the Hydro Group because such changes would constitute
a breach of the conditions for tax exemption in connection with an earlier
transaction. 14




---



##### 



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
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




---



##### 



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. Since the end of the Second World War, Hydro has 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 company in
the European aluminium industry. In 1999, Hydros management determined to concentrate Hydros business in
three core areas, Oil and Energy, Aluminium, and Agri, and to divest other
non-core businesses. 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 16




---



##### 



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). 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. Since 1999, Hydro has divested non-core
businesses with an aggregate enterprise value of approximately NOK 26 billion. Demerger of Hydro Agri In the second half of 2001, Hydros Board of Directors initiated a
corporate portfolio strategy project that was concluded in June 2003, when
Hydro announced that preparations for establishing Hydros Agri business as a
separate, Norwegian-based company would commence, with the aim of listing the
shares of such company on the Oslo Stock Exchange in the first half of 2004.
After considering various possible ways of separating Hydro Agri from Hydro,
the Board determined that Hydro Agri should be established as a separate,
publicly traded company by means of a demerger transaction effected in
accordance with Norwegian law. Under Norwegian law, a demerger is the transfer
of part of the assets, rights and liabilities of a company (the transferor
company) to one or more newly formed or pre-existing companies (the transferee
company or companies) in exchange for consideration in the form of shares of
the transferee company (or companies) issued to the holders of shares in the
transferor company, and possibly other consideration which must not exceed 20%
of the total consideration. On November 10, 2003, Hydro established Yara International ASA, initially
named AgriHold ASA, for purposes of acting as the transferee company in the
Demerger. Hydro subscribed for all of the initially issued shares of Yara at a
total subscription price of approximately NOK 2.0 million. On November 28,
2003, the Board of Directors of the Company and Yara entered into the Demerger
Plan. Hydro transferred all assets, rights and liabilities primarily relating
to Hydro Agri to Yara on March 24, 2004 (the Completion Date), in accordance
with the Demerger Plan. The transferred assets consisted primarily of shares,
partnership interests and other financial interests held by Hydro in companies
(including minority interest companies) and partnerships forming the business
activities of Hydro Agri. In consideration for this transfer of assets, rights and liabilities, Yara
issued one of its shares for each Hydro share outstanding on the Completion
Date. The Demerger resulted in the split of Hydros share capital through a
reduction of the par value of each Hydro share (from NOK 20.00 to NOK 18.30 per
share) simultaneously with the issuance of one new share of Yara for each
outstanding Hydro share. The Yara shares issued in the Demerger constituted
80% of Yaras total outstanding shares at the time of completion of the
Demerger. These shares were registered in the names of the registered holders
of Hydros shares in the Yara shareholder registry with the VPS on March 30,
2004. Hydro retained a 20% interest in the Yara shares immediately following the
completion of the Demerger. Hydro offered half of these shares in a global
offering (the Global Offering) that consisted of (i) in Norway, a public
offering and an offering to institutional investors; (ii) in the United States,
an offering to qualified institutional buyers (QIBs) as defined in, and in
reliance on, Rule 144A under the Securities Act; (iii) outside Norway and the
United States, an offering to institutional investors in reliance on Regulation
S under the Securities Act; and (iv) an offering to directors and senior
management of Yara. The offer price (the Offer Price) was NOK 41 per share.
Hydro also granted to the managers of the Global Offering an option (the
"Over-Allotment Option), exercisable for a period of 30 days starting at the
opening of trading of the Yara shares on the Oslo Stock Exchange (which
occurred on March 25, 2004), to purchase some or all of the remaining Yara
shares held by the Company, at the Offer Price, less underwriting commissions.
The managers exercised the Over-Allotment Option in full on March 29, 2004, at
which time Hydro ceased to have any equity interest in Yara. The total
proceeds from the sale of the Yara shares (including the shares subject to the
Over-Allotment Option) amounted to approximately NOK 2.6 billion, resulting in
a pre-tax gain of approximately NOK 530 million. The gain has been included in
income from discontinued operations in the first quarter of 2004. 17




---



##### 



With the completion of the Demerger of Hydro Agri, Hydros core business
areas now consist of Oil and Energy, and Aluminium. 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 Treka AS, whose activities consist of fish feed operations; Hydro Pronova,
which is responsible for commercializing products and businesses at the
periphery of Hydros core business areas; Industriforsikring a.s, a captive
insurance company; and Hydro Business Partner, which provides service and
support functions throughout Hydro. 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. Following the Demerger, the Companys principal executive offices have
been moved to 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. 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 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. The gas transportation activities were transferred
to the Energy and Oil Marketing sub-segment as of January 1, 2003. Hydro has a strong position on the Norwegian Continental Shelf (NCS),
where it is the third-largest producer of equity (i.e., owned) oil and natural
gas. In 2003, approximately 89 percent of Hydros average daily production of
530,000 barrels of oil equivalents (boe) was from the NCS. As an operator of
11 producing fields on the NCS with a total production in 2003 of approximately
880,000 boe per day (boed), Hydro is a relatively large operator of oil and gas
fields, in particular, offshore fields. 18




---



##### 



Internationally, Hydros main producing fields are in Angola and Canada.
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
2003, Hydro has nearly 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 Crude oil prices have been high over the past three years. This has
resulted from stronger OPEC market management, political unrest in important
producing countries such as Iraq and Venezuela and, of late, increasing world
demand combined with a limited margin of unused capacity. Spot Brent Blend
crude oil has averaged USD 26.70 per barrel between 2000 and 2003 and has
mostly ranged within the USD 22-28 per barrel price band initiated by OPEC for
its basket of crude oil types at the beginning of 2000. OPEC aims to function as a stabilizing force in the market. Its long-term
price target is considered to be USD 25 per barrel, which is considered above
the marginal cost of new production outside OPEC. As a result, it is
reasonable to question whether maintaining this price target is realistic over
a longer-term (e.g., 5-20 years) perspective. Should this remain OPECs price
target, crude oil prices could reflect cyclical periods of high and low prices
from the interplay between market forces and actions taken by OPEC. Reduced Exploration Results Worldwide Based on data from the consulting firm, IHS Energy, worldwide oil and gas
exploration activity during 2002-2003 resulted in proportionally smaller
discoveries and lower amounts of hydrocarbons discovered compared to previous
years. According to IHS Energy data, a significant trend in 2003 was the
dominance of deep-water discoveries. South Atlantic deep-water exploration
resulted in 11 of the top 20 discoveries in 2003, seven in Brazil and four in
Angola. Other areas with significant discoveries were the Sudan, Vietnam,
Indonesia, Mauritania, Egypt and Nigeria. Exploration results offshore Canada,
Norway and the UK were disappointing. Maturing NCS The NCS, where 93 percent of Hydros proven reserves are located, is
maturing. Norways oil production has been in decline after 2001, while total
production has been increasing due to increased gas production. In August 2003, Kon-Kraft, a policy group representing the Norwegian
petroleum industry, recommended in a report to the Norwegian government certain
changes in the petroleum tax regime and other incentives, as well as opening of
new areas on the NCS, in order to stimulate more exploration activity, new
developments and increasing recovery from existing fields. Hydro believes that
there is significant potential for adding new production and value to its NCS
portfolio if changes are made in line with the groups recommendations. 19




---



##### 



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. For Hydro the changes may stimulate marginal
investments in tail-end producing assets, but will have only marginal effects
with respect to exploration decisions. In December 2003, the government announced the extensive 18th Concession
Round on the NCS covering 95 blocks or parts of blocks in the North Sea and the
Norwegian Sea. At the same time, the government concluded the evaluations of
year round petroleum activities in the Barents Sea and the Lofoten area. A
decision was made to allow further petroleum activities within areas already
open for exploration in the southern part of the Barents Sea with some
exceptions. Furthermore, the government decided to discontinue further

activities in Nordland VI, an area outside Lofoten. Nordland VI will be
reevaluated when the governments integrated management plan for the Barents
Sea is completed, which is expected during the winter of 2005/06. Strategy Hydros strategic goal is to position itself as a profitable participant
in the upstream oil and gas business based on Hydros core competencies,
including advanced drilling techniques, reservoir management and the
development and execution of complex and technologically challenging projects.
To achieve its strategic aim, Hydro intends to focus its exploration and
production activities on:  
    
    delivering strong production growth through 2007 based on Hydros
existing portfolio in well-defined, profitable projects;
    
    building the basis for future production growth; and
    
    improving the profitability of existing assets. Delivering Strong Production Growth Hydro has a history of delivering strong production growth. From 1998 to
2003, Hydro nearly 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 in Hydro-operated fields on the NCS (i.e., Oseberg, Tune and Grane)
from the Norwegian State. Total oil and gas production in 2003 was 530,000 boed, representing an
increase of 10 percent over the prior year. This increase reflected the
start-up of production from the Grane, Fram Vest and Mikkel fields on the NCS,
the second phase of the Kharyaga field in Russia, the Murzuq-A field in Libya
and the Jasmim field in Angola. Production also increased from fields (e.g.,
Tune, Snorre B, Åsgard, Oseberg Sør, Girassol and Terra Nova) that came on
stream in recent years. Hydros increased interests in fields, through the
acquisition of such interests from the Norwegian State as described above, also
contributed to the growth with a full year effect in 2003. Hydro has earlier announced a targeted compound annual growth rate for
production of 8 percent for the 2001-2007 period. Hydro 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 70 percent of the production in 2007 is expected to come from
currently booked proved reserves. Hydro has targeted an average daily production
of 560,000 boe for 2004 from fields with currently booked reserves, of which
approximately 90 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 4.B. 20




---



##### 



Business Overview  Hydro Oil and Energy  Exploration and Development 
Development within this annual report. In 2003,approximately 11 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, an increase of 20 percent compared to
the previous year. Building the Basis for Future Production Hydro will continue to explore for and develop new oil and gas fields that
can contribute to a sustainable production profile for the long-term. The
substantial Grane oil field commenced production in September 2003. Development
of the Ormen Lange gas field is expected to make a significant contribution to
Hydros income for many years after planned start-up of production in 2007. Future activity on the NCS will depend on, among other things, whether the
tax system and other incentives are adjusted to promote exploration activities,
new field developments and increased recovery from existing fields, as well as
the access to new prospective exploration areas. The large number of blocks
offered in the 18th Concession Round and the announcement by the government of
the continuation of year round exploration activity in parts of the Barents Sea
are positive developments as seen by Hydro. Hydro believes that there is
attractive exploration potential on the NCS, as follows:  
    
    Areas around existing infrastructures in the North Sea offer
additional oil and gas potential primarily in terms of satellite
tie-ins to increase the economic life of current installations.
These areas are perceived as moderate risk.
    
    The Norwegian Sea may still have a potential for large gas
prospects, although the disappointing results from the exploration
on licenses awarded in the 16th Concession Round have increased
Hydros perceived exploration risk in this area.
    
    The northern part of the NCS, including the Barents Sea, a
large under-explored area, has potential in terms of both oil and
gas prospects, although the perceived risk is high. Hydros international expansion has been based on alliances with regional
producers and international partners with a focus mainly on oil prospects.
Hydros strategy for international expansion has been to concentrate its
efforts in a limited number of 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. Areas in which Hydro is currently active include the East Coast of Canada,
the US Gulf of Mexico, Angola, Russia, Libya and Iran. Activities in Russia,
Libya and Iran are in onshore areas that have different cost structures than
the activities in the deep-water areas in the US Gulf of Mexico and Angola,
providing balance in the portfolio. In general, Hydro strives to balance the
total risk in its commercial portfolio by seeking partnerships with other
companies to share geological, commercial and political risks. In light of the maturity of the NCS, Hydro has increased its focus on
international exploration opportunities by building up a portfolio of prospects
that has been explored mainly over the last three years. In 2001, Hydros
international exploration activity was, for the first time, greater than on the
NCS. In 2002 and 2003, international exploration activity represented around
three quarters of Hydros total exploration activity. This, combined with the
acreage awarded in the 16th Concession Round on the NCS, has resulted in high
exploration budgets, reaching an all time high of around NOK 2.4 billion for
2002. 21




---



##### 



The overall performance of Hydros exploration activity during the last
few years has not met expectations, in particular, the activity on Block 34 in
Angola and the drilling activity in the US Gulf of Mexico. As a result, Hydro
has completed a thorough review of the past years exploration activities. The
results of this review indicate, among other things, that Hydros portfolio has
had too high a share of high risk/high reward prospects. As a result, a more
centralized exploration organization has been implemented and exploration
activities are being scaled down in 2004 to approximately NOK 1 billion in
order to continue the review of the portfolio. In future years, an exploration
level of about NOK 1.5 billion is expected. In addition, Hydro intends to search actively to acquire resources, under
the condition that returns will have a clear priority over volume growth, where
Hydro can add value based on its core competencies in reservoir management,
flow assurance and/or management of development projects. Hydro will primarily
concentrate on the geographical areas where Hydro has an active presence,
including adjoining areas. 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 its status as an efficient
operator. Hydro has announced a targeted production cost in 2004 of NOK 24/boe. The
increase of around NOK 3/boe compared to 2003 is, to a large extent, caused by
increased gas injection cost on the Grane field in order to increase oil
production from that field. Hydro is actively seeking to concentrate its activities on the NCS by
increasing ownership interests in core areas and by selling license interests
in non-core areas. The purchase of assets from the Norwegian State in 2002
strengthened Hydros position in core assets (i.e., the Oseberg, Tune and Grane
fields). In recent years Hydro has divested non-core assets on the NCS,
including the sale of its equity interest in the Snøhvit field in 2004, which
is subject to government approval. Exploration and Productions Competitive Position The following discussion includes a description of Hydros exploration and
production positions on the NCS and internationally. This should be read in
connection with the description of the relevant risk factors relating to
Hydros Oil and Energy business included in Item 3.D. Strong Position on the NCS 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 2003, approximately 89 percent of Hydros average daily equity
production of 530,000 boe came from the NCS. As of December 31, 2003, Hydro had interests in 102 licenses on the NCS,
of which it was operator of 48 licenses. In total, the licenses cover a gross
offshore area of around 33,000 square kilometers (km) in the North Sea, the
Norwegian Sea and the Barents Sea. Hydro also has interests in four exploration
areas with a total of 12 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 18,000 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. 22




---



##### 



The total average daily production in 2003 from Hydro-operated fields was
approximately 880,000 boe. This means 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 an operator. 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 2003 were
the fields in the Oseberg area, the Troll field and fields in the Tampen area.
Other important fields were the Åsgard field, the Sleipner fields and the
Ekofisk fields. In the coming years, the Grane oil field, which started
production in 2003, will be an important contributor to Hydros Norwegian oil
production. The Ormen Lange field is the largest field presently under
development on the Norwegian Continental Shelf and Hydro expects that Ormen
Lange will be an important part of Hydros production after start-up in 2007. Hydro has a strong focus on optimizing its portfolio on the NCS through
reducing its interest in or selling non-core assets and increasing its
ownership share in its core areas. In January 2004, Hydro signed an agreement
with Statoil for the sale of Hydros equity share in the Snøhvit field. At the
same time, Hydro agreed to purchase an additional equity interest in the
Kristin field from Statoil, which will improve Hydros position in the
Norwegian Sea. The Norwegian authorities approved the transaction
during the second
quarter of 2004 subject to certain commercial conditions which are expected
to be resolved during the third quarter of 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.
That sale was completed in the first quarter of 2004. Interesting International Positions In 2003, Hydros international oil production increased by 20 percent
compared to the previous year and represented approximately 11 percent of its
total oil and gas production. The main producing fields are in Angola and
Canada. Hydro also has producing fields in Russia and Libya. In addition to
these countries, Hydro is involved in exploration activity in other countries,
including the United States (Gulf of Mexico) and Iran. 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 December 31,
2003. This includes Girassol and Jasmim, which contributed an average of almost
20,000 boed of oil production in 2003, as well as the Dalia field that is under
development. Further geological and engineering studies are planned in order to
appraise newly discovered structures, including the Acacia and Hortensia
discoveries that were announced in the spring of 2003. 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 to identify potential targets for a third well in the block. As of
December 31, 2003 , Hydros two exploration licenses in Angola in total cover a
gross exploration area of around 9,000 square km, mainly deep-water or ultra
deep-water acreage with water depths down to 2,600 meters. 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 Banks. Hydro presently has
ownership in two producing fields, Hibernia and Terra Nova. These fields
contributed a total average oil production of approximately 30,000 boed in
2003. Hydro is also working together with 23




---



##### 



the operator, ChevronTexaco, to develop the Hebron field in the same area.
Hydro is also evaluating the Annapolis discovery located offshore of Nova
Scotia to determine possible development solutions. As of December 31, 2003, Hydros 16
exploration licenses in Canada in total cover a gross exploration area of
approximately 25,000 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 in the Timan Pechora basin. This
field started production in 1999 and phase two came on stream in 2003. Further
development of the field is being planned. In 2003, average equity production
was 5,500 boed. Hydro is also pursuing new business opportunities in Russia.
In 2003, Hydro signed a technical cooperation agreement with Rosneft for the
evaluation of development scenarios relating to the giant Shtokman gas field,
located in the deep water continental shelf on the Russian side of the Barents
Sea. In June 2004, the Russian gas company, Gazprom, indicated that Hydro could
become one of the most important partners in the Shtokman field. A work group
shall now draw up a proposal for the concrete agreements for Hydros possible
participation in the development of the field. There are a number of issues to
be clarified, including the progress plan for the development, ownership stakes
and other conditions. Libya: Hydro is a partner in the onshore Mabruk field, which lies in the
northern part of the country. 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. Total average daily equity production from Hydros
Libyan fields was around 2,000 boed in 2003. Libya represents an interesting
resource potential. Hydro anticipates continuing to pursue new opportunities in
Libya in light of the currently improving general political situation there. As
of December 31, 2003, Hydros four licenses in Libya cover a gross onshore area
of around 37,000 square km. Iran: Hydro established an office in Tehran, Iran during November 1999. 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 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. Hydro has applied for
extension of the contract. The agreement provides Hydro with the right to enter
into negotiations for a buy-back agreement to develop reserves in the event of
a commercial discovery. After clearing minefields, Hydro completed the seismic
acquisition program. The first well was spudded in the spring of 2003, but
drilling proved to be more difficult than anticipated, and the well was
abandoned in January 2004. New wells will be drilled during 2004. 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 may better position Hydro for new
opportunities in Iran. US Gulf of Mexico: Hydro entered into a joint venture agreement with
ConocoPhillips in September 2001. This 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 ConocoPhillips-operated Lorien prospect. The Lorien
prospect was drilled in 2003 and resulted in a discovery believed to be
commercial and is planned to be developed as a tie-back to existing infrastructure. During the
first quarter of 2004, Hydro purchased an additional ownership interest in the
Lorien discovery in the US Gulf of Mexico, increasing its ownership from 10 to
30 percent. The other four firm wells did not result in commercial discoveries.
Evaluation of prospects relating to leases in ConocoPhillips portfolio that
Hydro has options to participate in will continue in 2004. In total, Hydros 63
exploration leases as of December 31, 2003 in the US Gulf of Mexico, of which
Hydro is an operator of 14 leases, cover an exploration area of around 1,500
square km, mainly deep-water acreage with water depths down to 2,300 meters.
Hydro has concentrated its efforts in the US Gulf of Mexico
in the Walker Ridge and Green Canyon areas to establish a good geological
knowledge base in the area. In the most recent 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 February
2004. 24




---



##### 



Exploration The following tables reflect the number of exploratory oil and gas wells
drilled by Hydro as of December 31, 2003. The first table reflects all 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 December 31, 2003. A total of 13 wells were drilled and completed in 2003,
of which three were considered productive. In addition, two wells were in the
process of being drilled at year-end, of which one resulted in a commercial
discovery and one was abandoned. Drilling Activity Norway
    
    International
    
    Total2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Exploratory wells
    
    Productive(1)
    
    
    2
    
    
    
    6
    
    
    
    8
    
    
    
    1
    
    
    
    8
    (3)
    
    
    7
    
    
    
    3
    
    
    
    14
    (3)
    
    
    15(presented on a gross basis)
    
    Dry(2)
    
    
    4
    
    
    
    5
    
    
    
    10
    
    
    
    6
    
    
    
    12
    
    
    
    4
    
    
    
    10
    
    
    
    17
    
    
    
    14
  (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)
    
    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 December 31, 2003
    
    Norway
    
    International
    
    TotalExploratory
    
    Gross(1)
    
    
    0
    
    
    
    2
    
    
    
    2Net(2)
    
    
    0
    
    
    
    1
    
    
    
    1
  (1)
    
    A gross well is a well in which a whole or fractional working interest
is owned.(2)
    
    A net well is the sum of the whole fractional working interests in
gross wells which equal one. In 2004, Hydro plans to participate in approximately 20 exploratory wells.
Around half of these are planned on the NCS and the remaining are planned
internationally, mainly in Iran, Angola and Libya. Norway In 2003, Hydro participated in six exploratory wells on the NCS, and was
operator for two of the wells. Two of the exploratory wells resulted in
commercial discoveries (the Klegg and Ringhorne Øst (East) discoveries in the
North Sea). Hydro is the operator of Klegg and intends to submit a Plan for
Development and Operation of the discovery before December 2004. Production is
expected to start-up in 2006. Hydro is considering developing this small
discovery through a sub-sea development connected to the Heimdal field or other
installations in the area. Hydro holds an equity interest of 28.5 percent in
Klegg. The Ringhorne Øst discovery is the second oil discovery on Ringhorne and
is being evaluated for connecting to the existing infrastructure on Ringhorne,
Balder and/or Jotun. Hydro has an ownership interest of 45 percent in
production license 169 that covers part of the discovery. 25




---



##### 



In March 2003, Hydro was awarded operatorship in two licenses and
partnership in one license in the North Sea area through the 2002 annual North
Sea round. In December 2003, Hydro was awarded operatorship in six licenses and
partnership in three licenses under the new system of Awards in Predefined
Areas that includes mature areas close to existing or planned infrastructure. The Norwegian authorities announced the 18th Concession Round in December
2003 covering 95 blocks or parts of blocks in the Norwegian Sea and the North
Sea. At the same time, the government decided to allow further year round
petroleum activity in the Barents Sea South, excluding certain valuable areas.
However, the government decided not to continue further petroleum activities in
the Nordland VI area outside Lofoten. This decision will be reevaluated when
the governments integrated management plan for the Barents Sea is completed.
In June 2004 Hydro was granted operatorship in two licenses and partnership in
two licenses in the awards of the 18th Concession Round. In January 2004, the Norwegian authorities announced a new round of Awards
in Predefined Areas covering mature areas close to existing or planned
infrastructure in the North Sea, the Norwegian Sea and the Barents Sea. The
deadline for application is October 1, 2004. Awards are expected to take place
in December 2004. International In 2003, Hydros international exploration activities encompassed Angola,
Canada, Libya, Iran, and the United States (Gulf of Mexico). Hydro participated
in seven exploratory and appraisal wells that were completed during 2003. One
discovery was made in the Gulf of Mexico. In addition, two wells were in the
process of being drilled at year-end. In Angola, one well was drilled on Block 25 during 2003. This well did not
result in a commercial discovery and the block was relinquished to Sonangol at
the end of the exploration period on December 31, 2003. In December 2003, the
second exploratory well on Block 34 was drilled. While gas was discovered, the
well was not considered to be commercially viable. Technical evaluations are
continuing to identify potential targets for a third well in the block. In
April 2003, the Acacia and Hortensia discoveries on Block 17 were announced,
based on exploratory drilling in 2002. In Canada, none of the three wells drilled during 2003 resulted in
commercial discoveries. New exploration wells are planned for 2004. In Libya, one exploratory well was ongoing at year-end, which resulted in
a commercial discovery. The exploration and appraisal program in Libya will
continue in 2004 with the planned drilling of further wells. In the first
quarter of 2004, a delineation well on Block 186 was completed, resulting in
additional commercial resources. In Iran, the Anaran well was spudded in spring 2003 and was abandoned in
January 2004 due to technical difficulties. New wells are planned for 2004. In the US Gulf of Mexico, Hydro participated in two wells during 2003, one
of which resulted in the Lorien discovery, believed to be commercially viable. In Denmark, Hydro has a 25 percent interest in license 6/98 with the Hejre
discovery. An appraisal well is planned for 2004. In addition, the second
commitment well on license 4/98 is presently under evaluation. Reserve Information At the end of 2003, Hydros share of proved developed reserves of oil and
gas was estimated to be 1,558 million boe. Hydros share of proved undeveloped
reserves accounted for an additional 730
million boe. Total developed and undeveloped proved reserves amounted to
2,288 million boe, of which gas reserves represented approximately 57 percent. Reserve life, defined as the number of years of production from proved
reserves at the present production level, was approximately 12 years at the end
of 2003, with approximately 7 years for oil and approximately 27 years for gas. The following table summarizes Hydros net quantities of proved oil and
gas reserves as of December 31, 2003, 2002 and 2001. 26




---



##### 



Oil and Gas Reserves 2003
    
    2002
    
    2001Oil in millions of boeGas 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)
    
    
    839
    
    
    
    154
    
    
    
    993
    
    
    
    883
    
    
    
    172
    
    
    
    1055
    
    
    
    825
    
    
    
    193
    
    
    
    1,018Of which developed
    
    
    690
    
    
    
    88
    
    
    
    778
    
    
    
    559
    
    
    
    93
    
    
    
    652
    
    
    
    564
    
    
    
    62
    
    
    
    626Proved gas reserves, developed and
undeveloped(2)
    
    
    7,317
    
    
    
    
    
    
    
    7,317
    
    
    
    6,629
    
    
    
    
    
    
    
    6,629
    
    
    
    5,986
    
    
    
    
    
    
    
    5,986Of which developed
    
    
    4,415
    
    
    
    
    
    
    
    4,415
    
    
    
    4,416
    
    
    
    
    
    
    
    4,416
    
    
    
    3,669
    
    
    
    
    
    
    
    3,669Proved oil and gas reserves,
developed and undeveloped
(in millions of boe)(2)
    
    
    2,134
    
    
    
    154
    
    
    
    2,288
    
    
    
    2,053
    
    
    
    172
    
    
    
    2,225
    
    
    
    1,880
    
    
    
    193
    
    
    
    2,073Of which developed
    
    
    1,470
    
    
    
    88
    
    
    
    1,558
    
    
    
    1,339
    
    
    
    93
    
    
    
    1,432
    
    
    
    1,211
    
    
    
    62
    
    
    
    1,273
  (1)
    
    Reserves reflected in the International columns are shown net of
royalties 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. Hydros reserve replacement ratio in 2003, including purchase and sale of
reserves, was approximately 133 percent. Excluding purchase and sale of reserves,
the ratio was approximately 134 percent. 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 December 31, 2003, 2002 and
2001 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 December 31, 2003, can be found in Exhibit 99.2 to this annual
report. Development In 2003, Hydro invested NOK 8,487 million in the development of new and
existing fields and transportation systems compared to NOK 8,222 million and
NOK 7,763 million in 2002 and 2001, 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 three most important development
projects in 2003 were the Grane, Kristin and Snøhvit fields. A summary of the fields under development as of December 31, 2003, 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. 27




---



##### 



Development Fields under Development(1) Total
    
    InvestmentEstimated
    
    IncurredProduction
    
    Investment(2)
    
    to Date (2)
    
    HydrosApproved for
    
    Scheduled to
    
    (in NOK
    
    (in NOK
    
    EquityField
    
    Type of Field
    
    Development
    
    Commence
    
    billion)
    
    billion)
    
    ShareNorwayOrmen Lange(3)
    
    Gas/Condensate
    
    April 2004
    
    October 2007
    
    
    51.6
    
    
    
    0
    
    
    
    18.0728
    %Kvitebjørn
    
    Gas/Condensate
    
    July 2000
    
    October 2004
    
    
    9.8
    
    
    
    7.5
    
    
    
    15
    %Kristin
    
    Oil/Gas
    
    December 2001
    
    October 2005
    
    
    17.5
    
    
    
    8.2
    
    
    
    12
    %(4)Byggve/Skirne(5)
    
    Gas/Condensate
    
    July 2002
    
    March 2004
    
    
    2.0
    
    
    
    1.5
    
    
    
    10
    %InternationalDalia
    
    Oil
    
    April 2003
    
    October 2006
    
    
    24.4
    
    
    
    2.6
    
    
    
    10
    %Murzuq D(6)
    
    Oil
    
    August 2003
    
    June 2004
    
    
    2.1
    
    
    
    0.5
    
    
    
    8
    %
  (1)
    
    The table does not include the Snøhvit field because an agreement
was entered into with Statoil in January 2004 for the sale of Hydros
equity interest in the field.(2)
    
    Total Estimated Investment and Investment Incurred to Date
amounts are as of December 31, 2003. These amounts represent the total
estimated investment based on the Plan for Development and Operation or
current cost estimate and total incurred investment for the applicable
field, respectively. All amounts are in nominal values.(3)
    
    The Ormen Lange PDO was submitted to Norwegian authorities on
December 4, 2003. The PDO was approved by the authorities in April
2004. The total estimated investment for Ormen Lange excludes the cost
of the Langeled gas export pipeline.(4)
    
    Hydros interest in the Kristin field will increase to 14 percent
if the Norwegian authorities approve the agreement entered into with
Statoil in January 2004, under which Hydro has agreed to purchase an
additional equity interest in the field. The operator of the Kristin
field, Statoil, has announced an expected increase in the estimated
investment level.(5)
    
    The Byggve/Skirne field started production in the beginning of
March 2004.(6)
    
    The total estimated investment relates to the Murzuq A and D
fields, which are an integrated development. Production from the
A-field started in October 2003 and from the D-field in June 2004.
Hydro has an equity interest of 20% in the exploration phase, 10% in
the development phase and 8% in the production phase. In connection with the development projects described in this section,
Hydro has invested NOK 0.4 billion, NOK 0.9 billion and NOK 2.3 billion for the
years 2001, 2002 and 2003, respectively. Estimated investments for the same
projects for 2004, 2005 and 2006 are NOK 4.6 billion, NOK 6.4 billion and NOK
4.4 billion, respectively. Norway The PDO for the Ormen Langegas field was submitted to the Ministry of
Petroleum and Energy on December 4, 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 28




---



##### 



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 (i.e., not discounted to present value), is
estimated at NOK 71.8 billion, including NOK 51.6 billion for field and plant
development and NOK 20.2 billion for the pipeline. Hydros equity share is
18.0728 percent. Hydro is the operator during the development phase of the
field. The Kvitebjørngas and condensate field is situated southeast of the
Gullfaks field. The field is to be developed using a fixed production platform.
Rich gas will be transported through a new pipeline to the Kollsnes gas
terminal for processing and export. Condensate will be transported through the
new Kvitebjørn oil pipeline to the Mongstad terminal. Production is scheduled
to commence in October 2004. Given Hydros estimate of the total proved
reserves for this field, Hydros share is 49 million boe, including 5.4 bcm of
gas. Hydros equity share is 15 percent. 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. Given Hydros estimate of the total
proved reserves for this field, Hydros share, based on its current 12 percent
equity interest, is 36 million boe, including 2.3 bcm of gas. As
previously announced, Hydro has adjusted downward the reserve
estimates of certain fields as of December 31, 2003, from that
reflected in its 2003 annual report to shareholders following the
conclusion of a dialogue initiated with the staff of the SEC relating
to the reserve estimate for Ormen Lange. Kristin was one of those
fields. The downward adjustment for Kristin was 3 million boe or eight
percent. In January 2004 Hydro entered into an agreement with Statoil to increase its interest in
the Kristin field to 14 percent. The Norwegian authorities approved
the transaction during the second quarter of
2004 subject to certain commercial conditions which are expected to
be resolved during the third quarter of 2004. 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 subject to certain commercial conditions
which are expected to be resolved during the third quarter of 2004. The authorities
approved the development concept for the Snøhvit field in March 2002. The plan
consists of a sub-sea development with a pipeline to the LNG plant at Melkøya,
close to Hammerfest, for processing. Statoil, the operator, announced in June
2004 that the total Snøhvit investments may increase by NOK 4-6 billion to
between 49.3 and 51.3 billion, of which NOK 10.1 billion was invested as of
December 31, 2003. Hydros equity share in the field prior to entering into the
agreement was 10 percent, representing proved reserves of 71 million boe,
including 9.5 bcm of gas, based on Hydros estimate of the total proved
reserves. Hydro has adjusted downward the reserve estimate for
Snøhvit as of December 31, 2003, by 19 million boe (21
percent) from that reported in its 2003 annual report to shareholders. The Skirneand Byggvegas and condensate fields are situated approximately
20 km east of the Heimdal field. The fields will be developed with a wellhead
platform at each field tied to the Heimdal gas center. Production started in
March 2004. A booster compressor module will be installed on the Heimdal field
in 2005. Given Hydros estimate of the total proved reserves for the fields,
Hydros share is 4 million boe, including 0.5 bcm of gas. Hydros equity share
is 10 percent. 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 floating production
and storage-offloading unit with an average production capacity of 225,000
boed. Production is expected to commence in October 2006. Given Hydros
estimate of the total proved reserves for this field, Hydros share is 35
million boe. In light of the delay in the expected timing of final approval of the development of the
Rosa/Lirio field, Hydro has determined to remove from its portfolio of proved reserves its estimate of
26 million boe of proved reserves that were booked for this field. Libya: The field development plan for the onshore Murzuq D-field was
submitted for approval to the Libyan authorities in October 2002 and was
approved in August 2003. Production started in June 2004. The field
development is integrated with the A-field 30 km away, which started production 29




---



##### 



in October 2003. Oil from the field will be transported to the El Sahara
field 29 km away, where it will be blended with oil from El Sahara and
transported by a 800 km pipeline to the As Zawiyah terminal west of Tripoli.
Given Hydros estimate of the total proved reserves for the Murzuq fields,
Hydros share is 10 million boe. Hydros equity share is 20 percent in the
exploration phase, 10 percent in the development phase and 8 percent in the
production phase. Production The following table includes the number of gross and net productive oil
and gas wells in which Hydro had interests as of December 31, 2003. Type of well
    
    
    
    
    
    Norway (1)
    
    International
    
    TotalCrude oil
    
    Gross
    
    
    546
    
    
    
    101
    
    
    
    647Net
    
    
    72
    
    
    
    18
    
    
    
    89Natural gas
    
    Gross
    
    
    88
    
    
    
    0
    
    
    
    88Net
    
    
    11
    
    
    
    0
    
    
    
    11
  (1)
    
    Includes 43 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 2003 and 2002.
Information regarding the total production of oil and gas in 2003, Hydros
ownership interest, 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 to this annual report. Hydros Share of Average Daily Production(1) 2003
    
    2002Total
    
    Oil(2)
    
    Gas
    
    Total
    
    Oil(2)
    
    Gas(in thousands of
    
    (in thousands of
    
    (in millions of
    
    (in thousands of
    
    (in thousands of
    
    (in millions ofField
    
    boe)
    
    boe)
    
    cubic feet)
    
    boe)
    
    boe)
    
    cubic feet)Oseberg fields(3)
    
    
    115.1
    
    
    
    103.0
    
    
    
    59.6
    
    
    
    114.5
    
    
    
    97.7
    
    
    
    89.3Troll
    
    
    80.0
    
    
    
    37.0
    
    
    
    248.1
    
    
    
    79.7

    
    
    
    37.7
    
    
    
    242.5Snorre fields(4)
    
    
    67.5
    
    
    
    65.0
    
    
    
    12.8
    
    
    
    66.4
    
    
    
    63.6
    
    
    
    14.6Åsgard
    
    
    40.6
    
    
    
    24.2
    
    
    
    91.6
    
    
    
    33.5
    
    
    
    21.5
    
    
    
    67.4Sleipner fields(5)
    
    
    35.2
    
    
    
    12.0
    
    
    
    127.0
    
    
    
    34.1
    
    
    
    11.8
    
    
    
    122.3Tune
    
    
    30.8
    
    
    
    7.8
    
    
    
    122.0
    
    
    
    0.4
    
    
    
    0.1
    
    
    
    1.6Ekofisk fields(6)
    
    
    28.2
    
    
    
    23.9
    
    
    
    23.0
    
    
    
    28.6
    
    
    
    24.0
    
    
    
    24.9Gullfaks fields(7)
    
    
    26.0
    
    
    
    21.2
    
    
    
    26.8
    
    
    
    24.9
    
    
    
    21.0
    
    
    
    22.3Norne
    
    
    13.2
    
    
    
    12.2
    
    
    
    5.9
    
    
    
    15.6
    
    
    
    14.6
    
    
    
    5.9Brage
    
    
    7.3
    
    
    
    7.0
    
    
    
    1.9
    
    
    
    9.9
    
    
    
    9.4
    
    
    
    2.3Visund
    
    
    6.6
    
    
    

    6.6
    
    
    
    
    
    
    
    8.2
    
    
    
    8.2
    
    
    
    Njord
    
    
    6.1
    
    
    
    6.1
    
    
    
    
    
    
    
    7.2
    
    
    
    7.2
    
    
    
    Grane
    
    
    5.5
    
    
    
    5.5
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Frigg
    
    
    3.9
    
    
    
    
    
    
    
    22.6
    
    
    
    4.0
    
    
    
    
    
    
    
    23.1Fram Vest
    
    
    2.9
    
    
    
    2.9
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Mikkel
    
    
    1.5
    
    
    
    0.7
    
    
    
    4.4
    
    
    
    
    
    
    
    
    
    
    
    Vale
    
    
    1.3
    
    
    
    0.7
    
    
    
    3.2
    
    
    
    0.5
    
    
    
    0.2
    
    
    
    1.2Heimdal
    
    
    0.8
    
    
    
    0.2
    
    
    
    3.7
    
    
    
    1.2
    
    
    
    0.3
    
    
    
    5.3Varg
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3.5
    
    
    
    3.5
    
    
    
    Total Norway

    
    
    472.5
    
    
    
    336.0
    
    
    
    752.6
    
    
    
    432.2
    
    
    
    320.8
    
    
    
    622.7Terra Nova
    
    
    20.1
    
    
    
    20.1
    
    
    
    
    
    
    
    15.8
    
    
    
    15.8
    
    
    
    Girassol
    
    
    19.5
    
    
    
    19.5
    
    
    
    
    
    
    
    17.6
    
    
    
    17.6
    
    
    
    Hibernia
    
    
    10.1
    
    
    
    10.1
    
    
    
    
    
    
    
    9.0
    
    
    
    9.0
    
    
    
    Kharyaga
    
    
    5.5
    
    
    
    5.5
    
    
    
    
    
    
    
    3.4
    
    
    
    3.4
    
    
    
    Mabruk
    
    
    2.1
    
    
    
    2.1
    
    
    
    
    
    
    
    2.4
    
    
    
    2.4
    
    
    
    Jasmim
    
    
    0.2
    
    
    
    0.2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Murzuq
    
    
    0.2
    
    
    
    0.2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total Intl
    
    
    57.7
    
    
    
    57.7
    
    
    
    
    
    
    
    48.2
    
    
    
    48.2
    
    
    
    Total
    
    
    530.2
    
    
    
    393.7
    
    
    
    752.6
    
    
    
    480.4
    
    
    
    369.0
    
    
    
    622.7
  (1)
    
    For information regarding conversion factors for the measurement
units in the table, please see Definitions of Oil and Gas Terms at
the end of the Exploration and Production business description.(2)
    
    Includes crude oil and NGL/condensate.(3)
    
    Includes Oseberg, Oseberg Vest, Oseberg Sør and Oseberg Øst fields.(4)
    
    Includes Snorre, Tordis, Tordis Sørøst, Tordis Øst, Borg, Vigdis,
Statfjord Øst and Sygna fields.(5)
    
    Includes Sleipner Vest, Sleipner Øst, Gungne and Sigyn fields.(6)
    
    Includes Ekofisk, Eldfisk, Embla and Tor fields.(7)
    
    Includes Gullfaks, Gullfaks Vest, Gullfaks Sør, Gullveig and
Rimfaks fields. 31




---



##### 



Norway Oseberg Fields. The Oseberg fields are core areas for Hydro on the NCS,
contributing 24 percent of Hydros total NCS production in 2003. 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. In February 2003, a revised PDO for the development of the
Oseberg Sør field was sent to the authorities for approval, and was approved 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 October 2004. The
total cost for the J-development is estimated at NOK 1.6 billion, of which NOK
0.2 billion was invested as of December 31, 2003. The Plan for Development and
Operation 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 October 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 23 million was
invested as of December 31, 2003. Hydros equity share in the Oseberg fields is
34 percent. Troll Field.The Troll field is the largest gas field on the NCS. Gas from
the Troll field represents a major part of Hydros current developed gas
reserves and gas production. In 2003, approximately one-third 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 is operated by Hydro
and 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 are located in the Tampen area and
include the Snorre, Tordis, Vigdis, Statfjord Øst and Sygna fields. 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. 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.
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. The Statfjord Østand Sygnafields started production in 1994
and 2000, respectively. Both fields are linked to the Statfjord C platform. Åsgard Field.The Åsgard field is situated in the Norwegian Sea. 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. Since the
commencement of production, average gas export from Åsgard B has varied due to
considerable technical problems. However, the platform is now in stable
production at maximum available gas capacity. Sleipner Fields.Production of gas and condensate began at Sleipner Østin
late 1993 and from Sleipner Vestin the middle of 1996. 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 three sub-sea wells.
These wells are expected to come on stream during the second half of 2004. 32




---



##### 



Tune Field. The Tune gas and condensate field (phase 1) developed as a
sub-sea satellite to Oseberg, 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. Ekofisk Fields.Ekofisk 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 exported through the Gassled system. In
1984, subsidence of the seabed around the complex was observed as a result of
gradually decreasing reservoir pressure. In 1987, water injection started with
the result that subsidence now is under control and reservoir pressure has
returned to its original level. At the same time installations were raised to a
higher level. In 1998, the new Ekofisk II facilities replaced old production
facilities. Problems related to the gas processing equipment have affected and
continue to affect production efficiency relating to gas output; however,
measures have been introduced to limit the effects on oil production. Gas
production rates are expected to increase after planned repair during a
maintenance shutdown scheduled for August 2004. Abandonment of the satellite
platforms is ongoing and alternatives are being discussed for extending the
lifetime of the centrally located Ekofisk I and Eldfisk platforms in order to
increase both well potential and production capacities. The Ekofisk Area Growth
project includes installing a new wellhead platform tied in to the Ekofisk II
process platform. The authorities approved the Plan for Development and
Operation in June 2003, 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 1.0 billion was invested as of December 31, 2003.
Hydros equity share is 6.65 percent. Alternatives for further development of
the Eldfisk and Tor field are being discussed among the owners. Gullfaks Fields. The Gullfaks fields are situated in the Tampen area. 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. Oil is transported by tankers from
the fields while gas is transported by pipeline to the Kårstø terminal in
Norway. A decision to develop the Gulltopp satellite was concluded by the
license owners at the end of 2003. Production is planned to start in July
2005. Gulltopp will be developed by a long extended reach well from the
Gullfaks A platform. The total project investment is estimated at approximately
NOK 0.3 billion. Hydros equity share is 9 percent. Due to the nature and small
size of the investment, the authorities will not require the submission of a
PDO for the development. Norne Field.The Norne field 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. In
May 2004, the PDO for Norne satellites was submitted to the Norwegian
authorities. A decision by the authorities is expected during the summer of
2004. The two discoveries are due to be developed with sub-sea installations
tied back to the existing installation. Total investments are estimated to be
NOK 3.6 billion. Hydros equity share is 13.5 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. 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. As part of Hydros
active management of its oil and gas portfolio, Hydro entered into an
agreement in 2002 with OER Oil AS to reduce its ownership in Brage to 20
percent. The authorities approved the transaction in 2003. Visund Field.The Visund field 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 33




---



##### 



on stream in early 2002. In October 2002, the authorities approved the plan for
development and operation 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 2.2 billion, of which
approximately NOK 0.4 billion was invested as of December 31, 2003. Hydros
equity share is 20.3 percent. Njord Field.The Njord field is located in the Norwegian Sea. 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. As part of Hydros active management of its oil and gas
portfolio, Hydro entered into an agreement in 2002 with OER Oil AS to reduce
its ownership in Njord to 20 percent. The transaction was approved by the
authorities in 2003. Grane Field: The Grane field is located in the North Sea and is developed
with an integrated production and drilling platform. Production from the field
started three weeks ahead of schedule on September 23, 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 will be imported through a
50 km pipeline from the Heimdal Gas Center to ensure optimum production of oil.
The Grane field contains heavier oil than is normally found on the NCS and is
therefore expected to be sold at a lower price than, for example, Brent Blend. Frigg Field.It is currently anticipated that the Frigg gas field will be
permanently shut down in 2004. Fram Vest Field. The field is located approximately 22 km from the Troll
field. The field 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. Hydro is
currently evaluating further sub-sea developments in the Fram region, phased in
to the existing Troll installations as soon as there is available capacity. Mikkel Field. The Mikkel field is located in the Norwegian Sea and started
production in October 2003. 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. 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 July 2004,
the production will be suspended due to drilling of a new sidetrack well.
Production is expected to start up again in October 2004. 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 June 2005. In March 2004,
production started from the small Skirne and Byggve fields, which are connected
to the Heimdal Gas Center. International Angolan Fields.The Girassolfield is an offshore field located on Block
17 in Angola. Oil production started in December 2001. The installation
consists of a production and storage-offloading vessel that is the largest of
its type ever built. The processing capacity is above 200,000 boed and the
storage capacity is two million barrels. Hydro has a working interest of 10
percent. The Jasmimfield is a sub-sea satellite connected to the Girassol
field. Production started in November 2003. 34




---



##### 



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 came on stream in November 1997. Hydro has a five percent
interest in the field. The Terra Novafield is southeast of Hibernia and
started production in January 2002. Hydro has a working interest of 15 percent. Russian Fields. The Kharyagafield 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 Westfield in the north of Libya
started in 1995. Hydro became owner of a 25 percent interest in the license
through the acquisition of Saga in 1999. 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. Hydros
equity share is eight percent of the production phase. Transportation of Oil and Gas Norway Effective January 1, 2003, ownership of the major gas transportation
pipelines on the NCS was merged into a new joint venture named Gassled. This is
described in more detail in the business description for Energy and Oil
Marketing below, 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 December 31, 2003. Length
    
    Hydros percentagePipeline
    
    End Point
    
    (km)
    
    interestGassled (gas)
    
    From the NCS to Germany,
    
    
    >6,000
    
    
    
    11.134
    (1)Belgium, France and the U.K.Langeled
North(2)
    
    Nyhamna  Sleipner (Norway)
    
    
    630
    
    
    
    17.96Langeled
South(2)
    
    Sleipner  Easington (U.K)
    
    
    540
    
    
    
    17.14Norpipe 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 Transport (gas)
    
    Norne- Åsgard (Norway)
    
    
    130
    
    
    
    8.10Vestprosess (NGL)
    
    Kollsnes/Sture  Mongstad
    
    
    56
    
    
    
    17.00(Norway)
  (1)
    
    Initial interest.(2)
    
    The plan for installation and operation was approved by the
authorities in April 2004. The final route is to be decided. 35




---



##### 



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 in dedicated offshore loading tankers directly to market or to
a terminal located at Whiffen Head, Newfoundland. 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. The terminal has been
expanded to accommodate the commencement of production at Terra Nova. 36




---



##### 



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).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).gross well
    
    A well in which a whole or fractional working interest is owned.LNG
    
    Liquefied natural gas. A liquid composed chiefly of natural gas
(i.e., mostly methane). Natural gas is liquefied to make it
easy to transport if a pipeline is not feasible (as across a
body of water). Not as easily liquefied as LPG, LNG must be put
under low temperature and high pressure or under extremely low
(cryogenic) temperature and close to atmospheric pressure to
become liquefied.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
    
    Proved reserves are estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering
data demonstrate
 37




---



##### 



Term
    
    Definitionundeveloped
reserves
    
    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).Proved 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.
 38




---



##### 



ENERGY AND OIL MARKETING While Energy and Oil Marketing represents a single sub-segment within the
Oil and Energy business segment, Hydro believes that the business activities of
Energy and Oil Marketing are better explained through a separate discussion
of their respective activities. 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 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, an active trader in the markets, and
through customer portfolios in the industrial/wholesale markets for both
natural gas and electricity. 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 as a
major producer and consumer of energy products has enabled it to provide
services to major electricity customers in the Nordic region. Its experience in
the Nordic region contributes to Hydros knowledge base in pursuing
opportunities in other markets. As part of its development of the business activities, Hydro in 2003
acquired Duke Energys Dutch gas marketing operations (Duke Energy Europe
Northwest B.V.) and entered into an agreement with the German gas
transportation and supply company, Wingas GmbH, to set up a joint venture for
marketing and sales of natural gas in the UK. Furthermore, Hydro sold its
interest in the Scanraff refinery and no longer holds an ownership interest in
the refining business. Industry Trends Liberalization of European Energy Markets In Europe, both the gas and electricity 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 below. Growth in European Natural Gas Demand The demand for natural gas in Europe is, by some estimates, expected to
grow significantly from the 2002 level of approximately 500 bcm, fueled in
large part by demand from the electric power 39




---



##### 



industry. However, the timing of the electricity sectors increase in gas
consumption is uncertain. Current market conditions in continental Europe
appear not to justify new investment in gas for power facilities at the present
time. However, the Nordic region is experiencing a trend of much tighter
electricity supply, as experienced during the winter of 2002/03, and gas for
power production may become economic sooner in this area than in continental
Europe. In 2002, 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
maturing of U.K. North Sea fields, which is expected to result in a decline of
production by 2005. Given its close proximity, the NCS is considered a
competitive source for new deliveries. Norwegian fields are presently linked to
the United Kingdom through the Vesterled pipeline to St. Fergus, which can
handle 11-12 bcm of natural gas per year. In 2003 the Norwegian and U.K.
authorities agreed on the main principles for a treaty relating to new
pipelines between the two countries, making possible the shipment of gas from
new gas fields, such as the Ormen Lange field, to the United Kingdom. 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. 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 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 are encouraged
by the directive to set targets in line with global expectations of 12 percent
of gross domestic energy consumption by 2010. A more efficient renewable energy
framework is expected to be developed in Norway and implemented in 2005/06.
This is expected to increase focus on wind energy in an area characterized by
having relatively good wind conditions. Strategy 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:  
    
    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. 40




---



##### 



Trading activities include the sale of Hydros crude oil, refined oil
products and NGL production. The volumes of these activities have increased
partly due to increased equity oil and gas production over the past years.
Furthermore, Energy supplies NGL feedstock to Hydros petrochemical plants, as
well as the former Hydro Agri (now Yara) fertilizer plants. Following the
Demerger, Hydro expects to continue to supply the Yara fertilizer plants under
arms-length agreements. In 2003, Hydro sold its 25 percent interest in the Scanraff oil refinery,
located at Lysekil, Sweden, to the oil company, Preem, which owned the other 75
percent of the refinery at the time of the transaction. As a result, Hydro no
longer holds an ownership interest in the refining business. Hydro is now
sourcing the refined products requirements for its Swedish retail marketing
activities through a long-term supply agreement with Preem. The tables below reflect the volumes of Hydros sales and refining
activities, respectively, in the last three years. Sales (thousands of tonnes)
    
    2003
    
    2002
    
    2001Crude oil/NGL
    
    
    18,560
    
    
    
    19,068
    
    
    
    17,507Oil products
    
    
    2,808
    
    
    
    2,326
    
    
    
    2,912
 Refining (thousands of tonnes)
    
    2003(1)
    
    2002
    
    2001Gasoline
    
    
    797
    
    
    
    660
    
    
    
    841Diesel fuels, gasoils, etc.
    
    
    766
    
    
    
    796
    
    
    
    897Heavy fuel oil
    
    
    502
    
    
    
    550
    
    
    
    440Other
    
    
    77
    
    
    
    36
    
    
    
    66Total refining
    
    
    2,142
    
    
    
    2,042
    
    
    
    2,244
  (1)
    
    Volumes for 2003 are through December 17, 2003, the effective sales
date of Scanraff. Enhancing the Value of Hydros Natural Gas Portfolio Because of location, transportation infrastructure and substantial
reserves, Norwegian natural gas is competitive in the European region. Hydro is
the third-largest producer on the NCS. Hydro has an interest in all the major
natural gas fields and in Gassled, the gas pipeline joint venture on the NCS.
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 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. The wholesale market includes larger industrial customers, power
companies and local distribution companies, as well as the traditional
transmission companies. 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. A major focus for Hydro in 2003 was increasing 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 growth 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 in 2003 acquired Duke Energys
gas sales and marketing organization in the Netherlands (Duke Energy Europe
Northwest B.V.), which has a portfolio of sourcing, sales, transportation and
storage agreements. 41




---



##### 



Furthermore, Hydro entered into a sourcing contract with Maersk, the
Danish oil company, which will deliver 0.6 bcm/year of gas from the Danish
Continental Shelf into the Netherlands for five year starting in 2005. In
December 2003, Hydro also entered into an agreement with the German gas
transportation and supply company, Wingas GmbH, to set up a joint venture,
HydroWingas, for marketing and sales of natural gas in the UK. The main goal
in pursuing this joint venture is to establish a competitive and effective U.K.
gas marketing channel by combining Wingas and Hydros gas positions and
marketing skills. HydroWingas commenced marketing activities in the spring of
2004. The table below reflects Hydros equity gas production and downstream
non-equity gas sales and sourcing in the last three years. (in bcm)
    
    2003
    
    2002
    
    2001Equity natural gas production
    
    
    7.8
    
    
    
    6.4
    
    
    
    5.4Sales of non-equity gas
    
    
    3.8
    
    
    
    3.7
    
    
    
    2.4
 In 2003, Hydros equity natural gas production from the NCS amounted to
7.8 bcm, an increase of 22 percent compared to the previous year. In addition to its equity gas, during 2003 Hydro supplied 3.8 bcm in the
downstream market based on non-equity natural gas, including 2.0 bcm supplied
to Hydros industrial factories (mainly those of the former Hydro Agri) on the
European continent. Following the Demerger, Hydro expects that deliveries will
continue to be governed under arms-length agreements. 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 an increasing volume of its natural gas will
be sold under short-term contracts. Physical positions are still necessary in
order to gain increased margins by optimizing logistics and trading. However,
more natural gas is available on the European continental short-term market and
liquidity is increasing at new hubs, complementing the existing long-term,
bilateral agreements between producers and large end-users and distributors.
Hydro intends to evolve its trading activities as liquidity increases. Such
market developments have been evident in the United Kingdom for some time and
similar developments are underway on the European continent, most notably
around the market hubs in Zeebrugge in Belgium and in the Netherlands. 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. Gassled, the new natural gas transportation infrastructure joint venture
on the NCS, has been in operation since January 1, 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 February 1, 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. 42




---



##### 



Optimizing Hydros Power Activities Hydro is one of the largest producers of power in Norway, with a normal
annual production from hydroelectric facilities in Telemark, Røldal/Suldal and
Sogn of approximately 8.3 terrawatt hours (TWh). Hydro is presently engaged
in a large development project to expand the Tyin hydropower plant in Sogn at a
cost of approximately NOK 1.5 billion. In 2003, Hydro disposed of its interest
in Sundsfjord Kraft ANS in exchange for a 20.2 percent ownership interest in
the power producing company, SKS Produksjon AS. Hydro has title concessions
that do not revert to the Norwegian government for power plants with an average
generating capacity of 2.7 TWh per year. This represents approximately 33
percent of Hydros normal production capacity. The remaining production
capacity, 5.6 TWh, or approximately 67 percent of Hydros normal production
capacity, will revert to the Norwegian government without compensation at the
expiration date of the concessions. Separate concessions apply to each power
plant. The year of expiration of the individual concessions ranges from 2022 to
2051 and does not include a phase-out period. In addition to its hydroelectric
power stations, Hydro is a partial owner of the Havøygavlen wind power plant
with an expected total annual production of 120 gigawatt hours (GWh). Since the liberalization of the Norwegian electricity market in 1991,
Hydro has developed 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)
    
    2003
    
    2002
    
    2001Power production
    
    
    7.5
    
    
    
    10.3
    
    
    
    9.8Acquired under long-term contracts for Hydros industrial use
    
    
    7
    
    
    
    7
    
    
    
    7
 As reflected in the table, production in 2003 was lower than normal due to low
precipitation in Norway during the autumn and winter of 2002/03. 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. More recently, Hydro has started to build a European continental
electricity portfolio based on optimizing supply to Hydros larger consuming
plants, including plants that are now owned by Yara. Hydro is providing Nordic
and European continental customers with structured energy products and energy
services ranging from physical power supply to advanced hydro-power
optimization, pricing services and portfolio management, including market
analysis, price forecasting and risk management/trading. Hydro intends to continue to expand into new markets and grow its Nordic
and European continental power portfolios based on demonstrated profitability
while controlling risk. 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. 43




---



##### 



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, in
which Hydro holds a 44 percent interest. Havøygavlen is one of the largest wind
power projects in Norway, with an expected annual output of around 120 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
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 2003, Hydros retail network in Sweden comprised 526
gasoline stations and 124 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 2003, Hydro Texaco operated 407 gasoline outlets and 46 diesel sites
in Norway, 443 gasoline outlets and 106 diesel sites in Denmark, and 43
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 all of Hydros markets. Gasoils are sold through automated diesel stations
and through direct deliveries from depots to end consumers. Volumes (thousands of m3) (1)
    
    2003
    
    2002
    
    2001Gasoline
    
    
    1,435
    
    
    
    1,476
    
    
    
    1,500Gasoil
    
    
    2,109
    
    
    
    2,074
    
    
    
    2,084
  (1)
    
    Volumes reflected in the table include 100 percent of Hydro Texacos
volumes. In 2003, Hydros market share in the Swedish gasoline market declined by
0.7 percent 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 in 2003 entered into a deal with VW/Audi Sweden, allowing
holders of VW/Audi credit cards access to Hydro and Uno-X stations. Bankcards,
such as Eurocard and Visa, have also been introduced as valid means of payment
at Hydro and Uno-X stations during the year. 44




---



##### 



Market share (%) (2003) (1)
    
    Sweden
    
    Norway (2)
    
    Denmark (3)Gasoline
    
    
    9.9
    
    
    
    20.2
    
    
    
    16.8Gasoil
    
    
    14.3
    
    
    
    16.0
    
    
    
    17.5
  (1)
    
    Includes 100 percent of Hydro Texaco.(2)
    
    As of November 2003.(3)
    
    As of October 2003. 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
June 13, 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. 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. 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 announced for application in December 2003) and through separate
rounds covering a defined area. 45




---



##### 



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. For licenses granted after July 1, 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 July 1, 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 July
15, 1987 until the end of 1989, licensees were directed to curtail oil
production by 7.5 percent. Between January 1, 1990 and June 30, 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 July 1, 2000, this restriction was removed. By
a royal decree of December 19, 2001, the Norwegian government decided that
Norwegian oil production should be reduced by 150,000 boed from January 1, 2002
until June 30, 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 licensees 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. 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. 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 46




---



##### 



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 June 1, 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. From January 1, 2003, the ownership of the Zeepipe, Franpipe, Europipe,
Europipe II, Åsgard Transport, Statpipe, Oseberg Gas Transport and Vesterled
joint ventures, and Norpipe AS was transferred to Gassled. As of February 1,
2004, the Kollnes gas terminal is also included in Gassled. With the approval
of Gassled, Norwegian authorities have, by a royal decree of December 31, 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 January 1, 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 Government
Administration, 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 Government Administration may decide that
other parties should provide the necessary resources, or otherwise adopt
measures to obtain the necessary resources, to deal with the emergency for the
account of the licensees. 47




---



##### 



The Norwegian Petroleum Directorate has adopted a wide range of
regulations that set forth detailed requirements as to the HSE aspects of
petroleum operations. 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 The European Commission has adopted a directive (Directive 2003/87/EC)
that seeks to establish an internal emissions trading system by January 1,
2005. The system would 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. It is not
clear how the directive will be implemented within the EEA. 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 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. 48




---



##### 



On June 26, 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 July 1, 2004, with all customers to have
this right by July 1, 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, but in order for the proposal to be
adopted, the committee has to deliver a favorable opinion on the proposal. If
the opinion of the committee is negative, the proposal will be submitted to the
Council, which may either adopt or reject the Commissions proposal. On April 20, 2004, the EU Parliament in its first reading adopted the
proposal with a number of amendments stating that the regulation, as amended,
should be accepted without major amendments if more binding regulation is,
indeed, needed. Network operators and the gas industry consider the regulation
unnecessary, viewing the existing guidelines as sufficient to establish fair
and transparent network access. Nonetheless, on June 10, 2004, the Energy
Council reached a political agreement on the proposed regulation. Once the
agreed compromise text has been formally adopted in one of the 49




---



##### 



upcoming Council sessions, it will be transmitted as the Council Common
position to the European Parliament for second reading. The political
agreement reached by the Council suggests the entry into force of the
regulation on July 1, 2006 (one year before the EU gas market is scheduled to
be completely opened up), whereas the guidelines providing the minimum degree
of harmonization required to achieve the aim of the regulation may not be
implemented before January 1, 2007. 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.
    
    Regulation (EC) No. 1228/2003 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. Taxation of Oil and Gas Production Norway Ordinary Taxes.Profits from Norwegian oil production 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 is applied to relevant income 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, 50




---



##### 



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 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 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 which will be put forward
in the budget 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 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 a tax/royalty regime, and its 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. 51




---



##### 



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 43 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 field is 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 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 state
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. Surtax on hydroelectric power plants (Norway) In 1996, a tax law was enacted in Norway for hydroelectric power plants
effective from January 1, 1997. In addition to ordinary income tax, the major
provision of the law called for the introduction of a surtax. The surtax rate
is 27 percent. The surtax 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 52




---



##### 



annually by the authorities, essentially provides for a certain return on
capital that is not subject to surtax. The percentage used to calculate the
uplift for 2003 was 9.7 percent. Revenue for surtax purposes is based on market spot prices with certain
exceptions. 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 adjustments. As most of Hydros hydroelectric
production is used for its own 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. Losses can be carried forward indefinitely or until the plant reverts to
the Norwegian government. Losses carried forward are increased with interest. A natural resource tax related to hydro-generated electricity became
effective as of January 1, 1997. The rate for 2003 is NOK 0.013 per KWh. The
tax is fully deductible from the ordinary income tax of the company. HYDRO ALUMINIUM Introduction and Overview In March 2002, Hydro Aluminium solidified its position as one of the top
three integrated aluminium companies in the world, in terms of volume of
integrated aluminium products produced, by acquiring VAW, a major producer of
primary aluminium, rolled products and other fabricated aluminium products
based in Germany. Through this acquisition, Hydro Aluminium has become a full
range aluminium company, expanding its range of products and activities in
rolled products, extrusion and automotive offerings. In 2003, Hydro Aluminiums
total revenues were NOK 69.2 billion compared to NOK 65.1 billion in the prior
year. Hydro Aluminium initiated cost reduction and improvement programs in 2001
and 2002, to be fully achieved in 2004. The objective of the programs was to
achieve cost and earnings improvements of NOK 2.5 billion compared to the
base-line combined cost and earnings level of Hydro Aluminium and VAW in 2001.
The targeted accumulated cost savings and EBITDA improvements were achieved as
of the end of 2003. This means that the full year effect for 2004 will be in
line with the target of NOK 2.5 billion. The accumulated cost of the program
was lower than originally estimated. Hydro Aluminiums present organizational structure is as follows: (ORGANIZATION CHART) 53




---



##### 



The graph below depicts Hydro Aluminiums aluminium operations, in terms
of 2003 tonnage along the value chain. (ALUMINIUM OPERATION GRAPH) 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 a viable
material include its light weight, strength, recyclability, corrosion
resistance, durability, ductility and 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 Africa (Guinea), India, Jamaica,
South America (Brazil, Surinam, Venezuela, and Guyana) and Australia. Bauxite
is generally extracted by open cast mining. More than 100 million tonnes of
bauxite
are mined each year. Two to three tonnes of bauxite are required to
produce one tonne of alumina; approximately two tonnes of alumina are required
to produce one tonne of aluminium. Alumina is dissolved in an electrolyte within a carbon- or graphite-lined
steel container known as a pot. An electric current is passed through the
electrolyte at low voltage, but very high current, typically 150,000 amperes,
or as high as approximately 300,000 amperes with modern technology. The
electric current flows between a consumable carbon anode (positive) and a
cathode (negative), formed by the thick carbon or graphite lining of the pot.
This splits the alumina into molten aluminium and carbon dioxide. The molten
aluminium is periodically siphoned off into a holding furnace, then cleaned and
cast into metal products such as extrusion ingot, sheet ingot, cast wire rod,
primary foundry alloy, continuous cast coil, liquid metal and standard ingot.
The molten aluminium is often blended with other metals, including iron,
silicon, zinc, copper and magnesium, to form alloys with different properties. 54




---



##### 



On average around the world, it takes roughly 15.7 kilowatt-hours (kWh)
of electricity 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. Many smelters are located
in remote areas, where electricity is generated specifically for the aluminium
plant. More than 50 percent of the energy used to produce aluminium supplied to
the European market comes from hydro-electricity. The smelting process is continuous. A smelter cannot easily be stopped or
started. If production is interrupted by a power line failure of more than six
to eight hours, the metal in the pots will solidify, often requiring an
expensive rebuilding 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 rolling sheet ingot that typically is up to 600 millimeters
(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 mechanisms 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.  Extrusion Aluminium cylinders, referred to as extrusion ingots, which are
continuously 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:  
    
    window frames, door frames and facades;
    
    automotive applications like bumper beams, window and door frames and subframes;
    
    transport segments such as trucks, trains and airplanes; and
    
    machines, furniture and consumer durables. 55




---



##### 



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 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. Industry Trends and Developments Aluminium consumption in the Western World (i.e., the world, excluding
China, the Commonwealth of Independent States (CIS) and Eastern Europe) has
realized an average annual growth rate of approximately 2.7 percent over the
last two decades. Industry analysts, such as Brook, Hunt and CRU, 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. Weak global economic conditions over the past few years have contributed
to an oversupply situation. 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 aluminium. However, during 2002, Chinas capacity and
production increased by about 30 percent while consumption grew by roughly 20
percent, and the country became a net exporter (approximately 250,000 tonnes).
For 2003, net exports increased by an estimated 100,000 tonnes to a total
estimated 350,000 tonnes. Over the longer term, China is expected to devote
more or all of its aluminium production to internal consumption. However, if
consumption and production in China fail to develop in parallel, it will almost
certainly influence the metal pricing and the need for new capacity in the rest
of the world. However, China has few natural advantages for primary production.
China must import alumina, power sources are far into the country, and much of
its power is coal-based. If alumina spot prices remain at levels similar to
those in early 2004, this may reduce incentives for starting up additional new
capacity in China in the short run. In addition, Chinese authorities announced
a reduction of available credit for industrial development in China during the
first quarter of 2004. In 2003, growth in demand in Europe and in the United States, currently
the worlds largest aluminium consuming regions, was low to moderate. Total
shipments of primary aluminium in the Western World increased approximately 4.6
percent (or 900,000 tonnes) compared to the prior year. New capacity resulted
in increased production of about 540,000 tonnes. This was partially offset by
net capacity idled of about 20,000 tonnes in 2003. In addition, there was an
increase in net primary exports to the Western World from China of about
100,000 tonnes. CIS exports are estimated to have remained at the same level as
in 2002. As a result, total reported and unreported inventories are estimated
to have increased by approximately 300,000 tonnes. 56




---



##### 



Reported inventories of primary aluminium (defined to include London
Metals Exchange (LME), International Aluminium Institute (IAI), Japanese
merchant/consumer and other reported stocks) in the Western World increased
approximately 100,000 tonnes in 2003 to a level of approximately 3.5 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 thereafter were rapidly
reduced to approximately 2.6 million tonnes at the end of 1995. These changes
mainly were attributable to the export of Russian metal to the Western World,
and the subsequent production reduction implemented by producers. Since 1995,
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. (LINE GRAPH) 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 1981-2003 period. 57




---



##### 



(LINE GRAPH) During the 1981-2003 period, the nominal LME 3-month price has reflected
fluctuations based upon the factors described above and a marginal average
annual increase. However, adjusting for the U.S. producer price index (PPI),
the LME 3-month price, stated in real terms, declined at an average annual
rate of approximately 1.2 percent during this period. Industry sources expect a
decline in the real price of aluminium to continue in the long term. 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 2003, and the
historic annual growth rates for these industries over the period of 1997
through 2003 (2003 reflecting forecasted figures). Percentage of Western
    
    Annual Growth RatesIndustry
    
    World Consumption in 2003
    
    (1997-2003)Transport
    
    
    29
    %
    
    
    2.8
    %Building & Construction
    
    
    20
    %
    
    
    0.8
    %Packaging
    
    
    18
    %
    
    
    1.5
    %Electrical
    
    
    9
    %
    
    
    1.2
    %Consumer Durables
    
    
    8
    %
    
    
    1.7
    %Engineering
    
    
    8
    %
    
    
    0.7
    %Other
    
    
    8
    %
    
    
    1.6
    %
 Source: Brook Hunt Based on the historical data, the transport segment is expected to
experience the most significant growth rates in the foreseeable future. The
packaging, and building and construction, industries appear to be more mature
industries, in terms of aluminium consumption, particularly in the United
States and Western Europe. During the last two to three years, there has been a prolonged economic
downturn in the United States and Western Europe which has impacted the
downstream aluminium industry. The table below provides a breakdown of the 2003 production volumes in the
principal aluminium producing regions and the percentage of the estimated
percentage of total global production represented by each such region (2003
reflecting forecasted figures). 58




---



##### 



Production Volume
    
    Estimated Percentage ofRegion
    
    (in millions of tonnes)
    
    Total Global ProductionNorth America
    
    
    5.5
    
    
    
    19.6
    %South America
    
    
    2.3
    
    
    
    8.2
    %Western Europe
    
    
    4.1
    
    
    
    14.6
    %Eastern Europe (including Russia)
    
    
    4.3
    
    
    
    15.4
    %Asia
    
    
    8.2
    
    
    
    29.3
    %Oceania
    
    
    2.2
    
    
    
    7.9
    %Africa
    
    
    1.4
    
    
    
    5.0
    %Total
    
    
    28.0
    
    
    
    100.0
    %
 Source: Brook Hunt Industry Structure Aluminium competes with substitution materials like steel, polyvinyl
chloride (PVC), wood, glass, magnesium, etc. In addition, there is strong
competition among the various aluminium producers, which have 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 2003, approximately 2 million tonnes of capacity remained
idle in the Western World, 1.5 million tonnes of which was located in the
Northwest United States, due primarily to the high price of electricity in the
regions where the production capacity is located. The likelihood and timing of
the reactivation of any 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, though Alcan has recently
announced its intended spin-off of substantially all of the rolled products
businesses held by Alcan prior to its acquisition of Pechiney. 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 50
percent of the revenues of Alcoa and of a 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 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, through its
subsidiary, 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. 59




---



##### 



Hydro Aluminiums Competitive Position Hydros acquisition of VAW has provided a 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. For
example, Hydro Aluminium has evolved from a rather marginal to a leading
producer in the European rolled products business (annual sales of flat rolled
products expanded from 133,000 tonnes in 2001 to 893,000 tonnes in 2003).
According to the November 2003 edition of CRUs Aluminium FRP Quarterly report,
Hydro Aluminiums Rolled Products sub-segment is now the worlds third-largest
producer of flat rolled products, measured by volume. Hydro Aluminiums
management estimates that flat rolled products represent roughly half of the
global aluminium consumption. Hydro Aluminium now 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. As a result of Alcans acquisition
of Pechiney, the European Commission has required that Alcan divest, within a
year, a combination of assets including either Pechineys Neuf-Brisach rolling
mill in France or Alcans 50% share in AluNorf in Germany. In terms of
capacity, either divestment will represent between 13-14% of the consumption in
the European market. Alcans announced spin-off plan for substantially all of
the rolled products businesses held by Alcan prior to its acquisition of
Pechiney contemplates its interest in AluNorf being shifted to the new company
created in connection with the transaction. Alcan announced that the spin-off
would achieve its regulatory divestiture requirements from the European
Commission. 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 approximately 50 percent of the alumina needed to produce
aluminium through medium- to long-term contracts, rather than through
ownership interests;
    
    sourcing a similar tonnage of metal from scrap, other ingot sources
and alliance partners (see Strategy  Leverage Metal Supplier Concept
below) as Hydro Aluminium produces from its own electrolysis
production; and
    
    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. Strategy Hydro Aluminiums strategy has multiple components, reflecting its
integrated aluminium operations. Ensuring Alumina Supply Hydro Aluminium has, over the last decade, based its supply of alumina on
a combination of alumina production from facilities in which it has an equity
interest and a portfolio of medium- to long-term contracts. Through completion
in 2003 of the expansion (to approximately 2.4 million tonnes} of the Alunorte
alumina plant in Brazil, in which Hydro Aluminium holds a 34 percent interest,
the equity portion of its alumina supply has increased and now covers
approximately 50 percent of the needs of its smelter system. Hydro Aluminium
has never been an operator of alumina plants, but has instead prioritized its
capital and management resources in areas in the value chain where Hydro
Aluminium could add greater value. In general, over the last decade there has
been a favorable alumina supply 60




---



##### 



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 early 2004, the alumina market has been tight and spot
prices have risen. For Hydro Aluminium, this had little impact due to its
combination of supply from equity interests and 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. Restructure Smelter Portfolio; Improve Relative Cost Position 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
250,000 tonnes per year from 27 percent in 2002 to approximately 46 percent by
the end of 2006. The expansions in primary production are being made in plants
where the existing infrastructure supports a larger capacity. This can be done
at a lower investment level than a corresponding new or greenfield
investment. Expansion of an existing facility improves the operating cost
position of the plant, thereby improving the overall long-term cost position. Hydro Aluminium has taken active steps to increase its metal production
and improve its average cost position. The annual production capacities of the
Søral smelter (located in Norway; Hydros share is 49.9 percent) and the
Slovalco smelters (located in Slovakia; Hydros share is 20 percent) have been
expanded by approximately 32,000 tonnes and 34,000 tonnes, respectively, and
now have an annual primary aluminium capacity of approximately 160,000 tonnes
each. Hydros equity share of the increase in combined production due to the
expansions is approximately 20,000 tonnes. The fully owned Sunndal smelter (in
Norway) is in the process of being expanded to an annual primary aluminium
capacity of 330,000 tonnes. The expansion is scheduled to be completed in the
autumn of 2004. 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, these expansions of primary aluminium
production capacity will increase Hydro Aluminiums total annual primary
aluminium capacity to approximately 1.7 million tonnes by 2005, from the level
of nearly 1.5 million tonnes in 2003. 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 smelters, Hydros Norwegian
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 May 7,
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
will require a reduction of manning by about 800 employees in the Norwegian
plants. The reduction in manning is expected to be completed by the end of the
first quarter of 2005. Leverage Metal Supplier Concept In view of the high investment costs associated with new smelter capacity,
since the 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, has been based
on three primary components:  
    
    develop alternative metal sources through commercial alliances and other agreements;
    
    better utilize Hydro Aluminiums casthouse capacity; and
    
    expand Hydro Aluminiums remelt activities. 61




---



##### 



Hydro Aluminium has entered into several long-term commercial alliances
and agreements that further its strategy of developing and leveraging the metal
supplier concept with limited asset investment. Under one of these agreements,
Hydro Aluminium will participate in upgrading the aluminium casthouse at
Rusals Sayanogorsk smelter, located in southern Siberia. Upon completion of
the first stage of the construction, anticipated in the first half of 2004,
Hydro Aluminium will be 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 a few years later, will further increase casting
capacity to 160,000 tonnes. Hydro Aluminium has also entered into a new
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. Focused Growth in Selected Markets Downstream Rolled Products Following the acquisition of VAW, Hydro Aluminium is the number two
producer in the European rolling industry; management estimates that it has a
market share of approximately 18 percent. Hydro Aluminium has a strong product
portfolio including foil, lithographic and automotive sheet products. The
acquisition of VAW has improved Hydro Aluminiums asset base, bringing into
Hydro a high level of technical competence in the work force and a portfolio of
high quality products. Hydro Aluminiums rolled products strategy is to focus
on growth in selected segments (such as lithography, a product segment for
which management has recently approved an expansion of German capacity of
lithographic plate by approximately 75,000 tonnes), 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 will also be pursued to improve efficiency.
Following completion of a number of projects in 2003, the level of capital
expenditures is expected to go down somewhat and be at approximately the same
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 a leader in the
building systems market in Europe, with its position having been bolstered by
the acquisition of the French-based company, Technal, in 2002. 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 under challenging market
conditions in order to place itself in a better position 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 product refinements and value-added services to improve margins and
volume. 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 primary metal have been
ultimately destined for the automotive sector, either as customers of Hydro
Aluminiums own 62




---



##### 



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 in Europe includes primary foundry alloys,
precision tubing and crash management systems. Hydro Aluminium also engages in
the production of aluminium engine blocks and cylinder heads in Europe and
Mexico. In the United States, precision tubing products are an important part
of Hydro Aluminiums product offerings to the automotive industry. In 2003, 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 and
leverage the investments made to improve profitability. Improvement of Operational Performance throughout the Organization The VAW acquisition had the immediate benefit of expanding Hydro
Aluminiums portfolio of plants with relatively attractive costs given the
scale of several of the smelters and rolling mills acquired. Furthermore, it
provided opportunities to capture the synergies available from a larger scale
of operations. This included streamlining the sales, general and administration
processes, reducing manning, and sharing best production and other practices to
enhance productivity and reduce fixed and variable costs. Hydro Aluminium
dedicated significant time and attention in 2002 to the successful integration
and extraction of synergies from the acquisition. These efforts continued with
full force in 2003 to ensure that the entire potential was realized. Following the completion of the VAW acquisition, Hydro Aluminium undertook
the rapid integration of the two companies activities. To capture the
synergies associated with the acquisition, Hydro Aluminium launched a program
encompassing internal benchmarking to identify and implement cost savings
through the introduction of best practices work processes across the units and
the optimization of production systems. Together with the improvement programs
already in place, these programs contributed to cost reductions throughout the
system. Even before the VAW acquisition, Hydro Aluminium had initiated cost
reduction and improvement programs throughout its various segments. In 2002,
Hydro Aluminium achieved its combined cost and staff reduction targets for
these and the VAW-synergy programs. This resulted in aggregate savings of
approximately NOK 1 billion, compared to the base-line cost level in 2001 for
the combined Hydro Aluminium and VAW businesses. Closure of the primary
magnesium production in Norway yielded NOK 424 million of the total savings.
Additional programs resulted in the remaining savings. Staff reductions in 2002
totaled 534 employees in the primary magnesium operation and 708 employees
associated with other cost reduction initiatives. Hydro Aluminium increased its
total savings and improvements targets for its improvement programs in the
fourth quarter of 2002 by NOK 400 million to a total of NOK 2.5 billion by the
end of 2003, to be achieved with full effect for 2004. As of the end of 2003,
Hydro had achieved the cost saving and improvements targets, including an
aggregate manning reduction of over 1,700 employees compared to the 2001
base-line level. This means the full year effect for 2004 will be in line with
the target of NOK 2.5 billion. Accumulated restructuring and rationalization
costs related to these programs were NOK 1,166 million, NOK 397 million less
than originally estimated. In 2004, Hydro Aluminium will maintain a strong focus on identifying and
capturing additional cost reduction opportunities throughout the value chain. 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. Metals activities also
include the processing of scrap 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. 63




---



##### 



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 2003. Production at the smelters during the three most recent years are
reflected in the table below: Aluminium production (tonnes)
    
    2003
    
    2002(1)
    
    2001Primary AluminiumKarmøy
    
    
    271,000
    
    
    
    273,000
    
    
    
    272,000Årdal
    
    
    215,000
    
    
    
    206,000
    
    
    
    206,000Sunndal (2)
    
    
    210,000
    
    
    
    153,000
    
    
    
    156,000Høyanger
    
    
    74,000
    
    
    
    73,000
    
    
    
    71,000Søral (Hydros 49.9 percent share) (3)
    
    
    79,000
    
    
    
    67,000
    
    
    
    62,000Slovalco (20 percent share) (4)
    
    
    27,000
    
    
    
    22,000
    
    
    
    18,000Rheinwerk
    
    
    221,000
    
    
    
    173,000Elbewerk
    
    
    69,000
    
    
    
    48,000HAW (33.3 percent share)
    
    
    43,000
    
    
    
    33,000Kurri Kurri
    
    
    156,000
    
    
    
    122,000Tomago (12.4 percent share)
    
    
    59,000
    
    
    
    45,000Alouette (20 percent share)
    
    
    49,000
    
    
    
    38,000Total primary aluminium production
    
    
    1,473,000
    
    
    
    1,253,000
    
    
    
    785,000Average price primary aluminium (U.S.$/tonne per
LME 3-month price)
    
    
    1,428
    
    
    
    1,365
    
    
    
    1,454
  (1)
    
    Includes VAW volumes from the VAW acquisition date of March 15, 2002.(2)
    
    The Sunndal smelter is in the process of being expanded to an
annual primary aluminium capacity of 330,000 tonnes. The 2003
production volume reflects the partial completion of the expansion.(3)
    
    The annual production capacity of the Søral smelter has been
expanded by approximately 32,000 tonnes. The 2003 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. 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. Hydro has decided
that investments to replace this capacity will not be made. The resulting
closures will reduce Hydro Aluminiums annual primary aluminium production
capacity by 72,000 tonnes by, at the latest, 2007. 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
2003, following the expansion at Alunorte, a Brazilian alumina refinery,
approximately 50 percent of its alumina requirements for primary metal
production was provided by such investments. Hydro Aluminiums major alumina investment is its 34 percent participation
in Alunorte. After an expansion of the plant in 2003, its capacity has reached
approximately 2.4 million tonnes, enabling 64




---



##### 



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. On June 3, 2004, the US Bankruptcy Court for the District of
Delaware ordered that Kaiser proceeds with the sale of its interests in and
related to Alpart to Hydro. Immediately after this purchase has been
completed, Hydro will sell this 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 will change from being operated by a managing partner to having
independent management. Both Hydro and Glencore will be represented on
Alparts ultimate governing body, the Executive Committee. The agreement with
Glencore also contemplates optimization of bauxite mining activities between
Alpart and Windalco, an alumina refining company in Jamaica (with an annual
production capacity of approximately 1.35 million tonnes), which is 93%-owned
by Glencore. The changes in ownership of Alpart, as well as the optimization
of bauxite mining activities, are subject to approval by 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. 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 about 25 percent of the operating costs associated with
primary aluminium production. Hydro Aluminium has negotiated long-term
contracts for its Norwegian smelters. Much of this energy is purchased from or
through Hydro Energy. Hydro 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. More
than 95 percent of the electricity needed to operate the Norwegian smelters in
2004 is covered by medium to long-term supply 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. 65




---



##### 



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 current contracts for the German smelter system
are scheduled to expire at the end of 2005. New contracts will need to be
negotiated before that time. Hydro owns 33.33 percent of the German aluminium
smelter, Hamburger Werk GmbH (HAW). HAW has an electricity supply contract
through the end of 2005 with Hamburger Electricitätswerke AG (HEW). During the
fourth quarter of 2003, HEW gave notice of an early termination of the existing
electricity supply contract effective September 30, 2004. The current market
price for power is considerably higher than the contract price. Negotiations
for an acceptable settlement, including a new electricity price for the period
from the beginning of October 2004 to the end of December 2005, have not yet
reached a conclusion. If these negotiations do not reach a satisfactory
agreement, it is likely that litigation will be initiated. Should it not prove
possible to obtain power at an acceptable price, the ultimate consequence may
be the closure of HAW. 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. Remelt Activities Hydro Aluminium has established remelt plants for conversion of scrap
metal into extrusion ingot in all major European markets. Facilities are
located in Norway, Luxembourg, the United Kingdom, Germany, Spain 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. 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 mills, as well as foundries. The main consumer
areas are transportation, construction and packaging. The major consuming
countries in 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
logistics costs by sourcing both internally and externally from a variety of
sources. Aluminium trading activities consist of physical metal purchases and
sales, as well as trading on the LME. In 2003, Hydros metal traders sold
externally 705,000 tonnes of primary aluminium products, compared to 478,000
tonnes in 2002. The main trading product is standard aluminium ingot, which is
also the global aluminium product on which price quotations on the LME and
other metal exchanges are based. Hydro Aluminium has a small alumina trading
activity that has been profitable during the last five years. 66




---



##### 



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 As a result of the VAW acquisition, Hydro Aluminium produces and sells
high purity aluminium products which are mainly used in the electronics
industry in products like electrolytic capacitors or semiconductors. High
purity products have an aluminium content of between 99.98 to 99.9999 percent.
The producers of high purity aluminium are quite concentrated, with two
producers in Europe, four in Japan, two in China and one in Russia. Hydro
Aluminiums management has estimated that global production in 2003 was
approximately 70,000 tonnes. Through its three production sites in Japan,
Norway and Germany, Hydro Aluminium sold about 12,000 tonnes in 2003. Magnesium The magnesium industry in the Western World comprises only a few producers
of primary magnesium. The International Magnesium Association (IMA) predicted
that worldwide shipments for 2003 would reach approximately 388,000 tonnes
compared with its estimate of actual 2002 shipments of 365,000 tonnes. Based on
the latest statistics available (2002), China and CIS shipments represented
about 57 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. Hydro Aluminium has a primary (electrolytic) magnesium plant in Becancour,
Canada, that produced approximately 50,000 tonnes in 2003.In addition, it has
remelt operations in Norway, Canada, Germany and China with a combined
remelting 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 2003 provided almost 610,000 tonnes to Rolled Products.
Most of Hydro Aluminiums entitlement to the products from AluNorf is further
processed in the 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
    2003 Sales Volume (1)Site
    
    Percentage
    (in thousands of tonnes)Grevenbroich, Germany
    
    
    100
    
    
    
    506Hamburg, Germany
    
    
    100
    
    
    
    131Slim, Italy
    
    
    100
    
    
    
    78INASA, Spain
    
    
    100
    
    
    
    22AISB, Malaysia
    
    
    81
    
    
    
    18Karmøy, Norway
    
    
    100
    
    
    
    58Holmestrand (including Alucoat),
Norway
    
    
    100
    
    
    
    80Total, excluding internal sales
and wire rod
    
    
    
    
    
    
    893AluNorf, Germany
    
    
    50
    
    
    
    610
    (2)
  (1)
    
    Excludes intra-company shipments, except volume cited for
AluNorf.(2)
    
    100 percent of shipments from AluNorf are intra-company. 67




---



##### 



In 2003, Rolled Products had external shipments of 893,000 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. There
are large differences in margins between different products, with the most
attractive products limited in terms of demand. 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. Rolled Products consists of four business units serving different market
segments, which in 2003 had the following sales volumes to external customers: 2003 External Sales VolumesUnit
    
    (in tonnes)Lithography
    
    
    128,000Foil
    
    
    143,000Strip
    
    
    562,000Automotive
    
    
    60,000Total
    
    
    893,000
 In 2003, Rolled Products management estimates that the Lithography
business unit had an average annual growth in sales volume of about 14 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 is 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. Living standards in Asia are
rising, hence packaging needs are growing rapidly and foil is an important
packaging material. 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 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 (referred to as the body-in-white market) on a finished
manufactured vehicle. 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. 68




---



##### 



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 is, together with Rolled
Products own process scrap, remelted and casted to rolling ingots in the
casting facilities of Rolled 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 14 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. 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 2003,Hydro Aluminiums
total production of extruded products (i.e., from all sectors) was 569,000
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. 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) comprises all of Hydro Aluminiums
precision tubing, structures and shape-casting businesses worldwide. In the
last few years, Automotive has followed a strategy of continuous growth in
order to strengthen its position as a supplier to the highly demanding
automotive industry. Automotive is currently introducing several new products
with start-up of new production lines. Hydro Aluminiums management believes that Automotive is the leading
supplier of aluminium extrusion-based applications within crash management
(e.g., bumper beams, crash boxes, engine cradle components) in Europe.
Automotive is also involved in crash management in North America and has
increased its U.S. bumper production in 2003 based upon existing contracts. The
sector has received safety awards for crash management systems supplied to
several vehicles. 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 has announced that it will 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. Hydro will break ground in the first half of 2004.
The investment costs are estimated to be NOK 150 million, and will create about
140 new jobs in Suzhou. 69




---



##### 



Through the acquisition of VAW, Automotive became the owner of VAWs
casting business and technology. The sector is one of a few independent (i.e.,
not affiliated with an automotive manufacturer) suppliers in Europe of
aluminium cylinder heads, engine blocks and inlet manifolds. 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 toward the end of 2004 or
in early 2005. Production of turbo cylinder heads for GM will be relocated to
Hydros plant in Gyør, Hungary. Through its competence in technology and in cooperation with Daimler
Chrysler, Automotive has developed the first aluminium high performance, high
volume V6 diesel engine block. 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. The sector operates six remelters, including its new remelter in Commerce,
Texas (which started operations in 2002), representing one of the largest
remelting systems in the United States. The remelt network produces extrusion
ingot and offers cost-efficient remelt solutions to the North American sectors
customers. The U.S. market has proven to be more volatile than the Western European
market. The North American extrusion market fell by approximately 21 percent
from 2000 to 2001, and remained flat in 2002. In 2003, the American Aluminum
Association estimated that extrusion shipments fell by one percent compared to
2002. By comparison, estimated consumption in the Western European market
declined by about four percent from 2000 to 2001 and a further one percent in
2002. In 2003, estimated Western European consumption increased approximately
one percent compared with 2002. North Americas operations were particularly affected by the trailer
market segment, which experienced the largest decline, starting in 2001. The
North America unit took a number of actions to respond to the drop-off in
demand. In 2002, it closed the former VAW headquarters in Florida and an office
in Kentucky. In 2002, it also closed a Georgia extrusion plant, transferring
existing contracts to other facilities to improve press utilization and
profitability. 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. 70




---



##### 



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 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. In the European Union and other countries, 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 to be sufficient to pay the cost of
remediation under existing laws. Because of uncertainties inherent in making
such estimation, it is at least reasonably 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. 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 71




---



##### 



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. Climate Gases EU directive 2003/87/EC issued on October 13, 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 January 1, 2005. The intention with
the directive is to broaden it to include more gases and sectors as of January
1, 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
aluminium. The Eastern European countries that joined the EU on May 1, 2004
became subject to this duty, though inventories of aluminium located in these
countries prior to the date of accession are exempt from duty. The EEA, of
which Norway is a member, is not subject to 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 whether 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 2006 or 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, resisted a unilateral
reduction of the tariff. Energy Taxation An EU directive on the taxation of energy products became effective on
January 1, 2004. The directive will expand 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. 72




---



##### 



OTHER ACTIVITIES Other activities include Hydros petrochemicals operations (Hydro
Polymers), Treka AS, Hydro Pronova and Hydro Business Partner. Other
activities include products and businesses outside of Hydros core business
areas. Other activities are managed together with the objective of developing
their long-term business potential as part of Hydro or outside of the Hydro
Group. Other activities also includes Industriforsikring a.s., Hydros captive
insurance company. PETROCHEMICALS Since late 1996, the global petrochemicals industry has faced an
oversupply situation. Competitive pressures have led to alliances,
restructurings and mergers within Europe (e.g., the merger of Royal
Dutch/Shells and DEAs petrochemicals businesses in Germany and BPs purchase
of Veba Oel from E.On). The consolidation has been motivated, in large part, by
the objectives of achieving economies of scale, lowering operating costs and
increasing unit margins. The consolidation in the part of the petrochemical
industry in which Hydro is active, mainly PVC in Europe, has been less
extensive. Hydros petrochemicals business has responded to increased competition by
lowering fixed, recurring and variable costs and increasing asset productivity
through, among other things, de-bottlenecking and staff reductions of roughly
58 percent (including activities sold) compared to 1996 levels. In early 2004,
Hydro decided to discontinue the previously announced divestment of its
petrochemicals business. For the foreseeable future, the competitive environment for world
commodity petrochemicals and polymers is expected to be characterized by a
widening cost gap between the petrochemical/polymer producers that are
integrated into raw materials and those that are not backwards integrated. In
view of market conditions, Hydros petrochemicals business 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. Hydros petrochemicals business 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 70 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 capacity of 230,000 tonnes of VCM, 175,000 tonnes of ethylene
dichloride and 290,000 tonnes of caustic soda. 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. 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 73




---



##### 



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. Petrochemicals has a secure
supply for most of its remaining ethylene (44,100 tonnes). In June 2004, Hydro
decided to carry out a project to streamline the production process at Noretyl,
increasing total capacity to 557,000 tonnes of ethylene per year. The total
cost of the project is estimated to be NOK 600-700 million. Petrochemicals production (in tonnes) 2003
    
    2002
    
    2001Base ProductsVCM
    
    
    575,000
    
    
    
    540,000
    
    
    
    591,000Caustic Soda
    
    
    281,000
    
    
    
    262,000
    
    
    
    279,000PolymersS-PVC
    
    
    507,000
    
    
    
    458,000
    
    
    
    465,000P-PVC
    
    
    81,000
    
    
    
    70,000
    
    
    
    72,000Total Polymers
    
    
    588,000
    
    
    
    528,000
    
    
    
    537,000PVC Compounds
    
    
    129,000
    
    
    
    128,000
    
    
    
    143,000
 Average Market Quoted Prices in Northwest Europe 2003
    
    2002
    
    2001Ethylene  /tonne delivered
    
    
    522
    
    
    
    518
    
    
    
    616VCM  Spot export fob US$/tonne
    
    
    452
    
    
    
    451
    
    
    
    345S-PVC  /tonne delivered
    
    
    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. 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. Petrochemicals share of ethylene produced at Rafnes in 2003
was 220,000 tonnes. Hydro Polymers AS and Borealis entered into an agreement
with Statoil and Petoro, under which it will purchase their ethane production
at Kårstø, for a 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 2003 was approximately 250,000 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, at a cost of approximately NOK 1,000 million. The project is expected
to be completed in the autumn of 2005. 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. 74




---



##### 



Sales and Description 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. TREKA AS Treka AS is a publicly held Danish company listed on the Copenhagen stock
exchange, in which Hydro has a 68.8 percent interest. After the sale of major
parts of the former KFK throughout 2002 and 2003, the remaining operational
activities in Treka consist of the BioMar fish feed operations. Due to
difficult conditions in the fish farming industry, BioMar undertook write-downs
of goodwill, provisions for accounts receivable and bad debt in the total
amount of NOK 570 million in 2003. A potential divestment of the BioMar
activities was announced and initiated, but did not result in any offers on
acceptable terms. Trekas board has, therefore, decided to terminate the sales
process. PRONOVA Hydro Pronova was set up to develop and commercialize activities outside
of Hydros core areas. Through its subsidiary Biocare, Hydro Pronova has developed a highly
concentrated Omega-3 pharmaceutical product, Omacor, for treatment of
post-myocardial infarction (Post-MI) and hypertriglyceridemia. In the first
quarter of 2004, Hydro sold 80.1 percent of its interest in Biocare for NOK 165
million. Pronova sold its Swedish subsidiary, Carmeda AB, in 2003. Further, Hydro
Formates AS, which had also been part of Pronova, was transferred to Yara in
connection with the Demerger. Following these developments, the bulk of
Pronovas portfolio has been disposed of and Hydro intends to phase out the
unit. HYDRO BUSINESS PARTNER Hydro Business Partner (HBP) was formed as a sector for service and
support functions in the beginning of January 2000. HBP is organized in two
primary functional units: Production and Facility Services and IS Services and
Business Support Services. HBP has made substantial contributions to cost
reductions in the units it serves. Long-term agreements have been entered into
with Yara for the supply of maintenance and IS services, among others. 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 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. The
operations of Industriforsikring are not substantial to Hydros overall
business and the Companys exposure to uninsured risk is not material. 75




---



##### 



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: Proportion ofCompany Name
    
    Country of Incorporation
    
    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 8.7 TWh is operated under concessions from the
Norwegian government that will expire without compensation in the period
between 2018 and 2052. Hydros principal aluminium production facilities
abroad are located in Austria, Belgium, 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 and Norway 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 2003 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 2003. 76




---



##### 



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 December 31, 2003 and 2002, as well as
information regarding Hydros material commitments for capital expenditures as
of year-end 2003 and Hydros research and development policies for the
three-year period ended December 31, 2003 is included in the following
discussion. 2003 Compared with 2002 Financial review Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating revenues
    
    
    171,782
    
    
    
    167,040
    
    
    
    152,999Operating costs and expenses
    
    
    (147,524
    )
    
    
    (147,199
    )
    
    
    (131,916
    )Operating income before financial
items and other income
    
    
    24,258
    
    
    
    19,841
    
    
    
    21,083Non-consolidated investees
    
    
    1,229
    
    
    
    33
    
    
    
    566Financial income (expense), net
    
    
    201
    
    
    
    1,935
    
    
    
    (762
    )Other income (expense), net
    
    
    (1,212
    )
    
    
    219
    
    
    
    578Income before taxes and
minority interest
    
    
    24,476
    
    
    
    22,028
    
    
    
    21,465Income tax expense
    
    
    (13,937
    )
    
    
    (13,278
    )
    
    
    (13,750
    )Minority interest
    
    
    148
    
    
    
    15
    
    
    
    177Income before cumulative effect
of change in accounting principle
    
    
    10,687
    
    
    
    8,765
    
    
    
    7,892Cumulative effect of change in
accounting principle
    
    
    281
    
    
    
    
    
    
    
    Net income
    
    
    10,968
    
    
    
    8,765
    
    
    
    7,892Earnings per share before change
in accounting principle (NOK)
    
    
    41.50
    
    
    
    34.00
    
    
    
    30.50Earnings per share (NOK)
    
    
    42.60
    
    
    
    34.00
    
    
    
    30.50
 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. Summary of key developments in 2003 Hydros net income in 2003 was NOK 10,968
million (NOK 42.60 per share) compared with
NOK 8,765 million (NOK 34.00 per share) in
2002. The result reflects overall
improvements in Hydros main business areas
compared to the prior year. Market
conditions have been good for many of the
Companys products, although the weaker US
dollar had a negative influence on all
business areas. The positive developments
also reflected the efficient implementation of
improvement programs. The most substantial improvement
related to a significant increase in oil and
gas production, together with somewhat
higher oil and gas prices. For 2003, total
oil and gas production was 530,000 boe per
day representing an increase of 10 percent
compared with 2002. Improvement programs carried out by
Aluminium generated considerable savings for
the year. Programs initiated in 2001 and
2002 were completed and are expected to achieve
targeted reductions of annual costs of NOK
2.5 billion, with full effect from 2004,
compared to the combined cost level of the
VAW and Hydro Aluminium businesses in 2001.
The accumulated cost of the program was NOK
1,166 million (NOK 176 million for 2003)
which was NOK 397 million below the original
cost estimate. Markets for semi-fabricated
aluminium products were weak during the
year, but there are some signs of
improvement. The competitive position for
Hydros European aluminium smelters is
challenging and the Company plans to
continue working to improve the cost position of
these plants. The fertilizer business also improved
its results due to higher product prices
and productivity gains. A strong
development in nitrogen fertilizer prices
led to significantly higher results for
the year, despite negative currency
effects and higher energy costs. The Ormen Lange project is on schedule.
The Plan for Development and Operation (PDO)
was submitted to the Norwegian authorities
at the beginning of December 2003. The field
is expected to produce significant new
volumes of gas, which are planned for sale
in the UK gas market. The field is expected
to come on stream in autumn 2007. Hydros Extraordinary General Meeting
resolved January 15, 2004 to demerge Hydro Agri. The new company is
named Yara International ASA, and has been listed on the Oslo
Stock Exchange since March 25, 2004. Yara has approximately 7,600 employees and is
headquartered in Oslo. Yara has the right to use Hydros former viking ship logo, which is
an important fertilizer brand. Every Hydro shareholder as of the listing date received
one Yara share for each Hydro share held. In the demerger, 80 percent of the Yara shares
were distributed to Hydros shareholders. Hydro sold the remaining 20 percent of the Yara
shares in an offering following the completion of the demerger which occurred on March 24, 2004. 77




---



##### 



Operating Results The change in operating income and the
most important items affecting the change
follows: Amounts in NOK millionOperating income 2003
    
    
    24,258Operating income 2002
    
    
    19,841Change in Operating Income
    
    
    4,417Prices and currency, E & P1)
    
    
    1,870Margin including currency effects2)
    
    
    (695
    )Volume
    
    
    3,580Fixed costs
    
    
    (326
    )Depreciation
    
    
    (945
    )Production and exploration costs, E & P1)
    
    
    1,540Infrequent items and restructuring costs
    
    
    245Trading and unrealized LME effects, Aluminium
    
    
    475New / disposed business
    
    
    135Other
    
    
    (1,462
    )Total change in operating income
    
    
    4,417
  1)
    
    Exploration and Production2)
    
    Including negative variance for
elimination of unrealized gain/loss on
internal electricity contracts of NOK
729 million for 2003 Operating income for Oil and Energy in 2003
amounted to NOK 21,143 million,
approximately 33 percent higher than in
2002. Production of oil and gas increased by
10 percent compared to 2002. The positive
effect of higher oil prices in US dollars
during 2003 was offset somewhat by the
decline in the US dollar/Norwegian kroner
exchange rate. However, oil prices measured
in Norwegian kroner were
4 percent higher than in the previous year.
Exploration costs of NOK 1,577 million were
charged to income in 2003, a reduction of
approximately NOK 2 billion compared with
2002. Operating income for Aluminium in 2003
was NOK 2,456 million, approximately 45
percent higher than in 2002. However,
excluding new business and infrequent items,
operating income for Aluminium declined NOK
143 million. Margins, excluding the effect
of hedge programs, were approximately NOK
560 million lower compared with 2002.
Margins improved for Rolled Products and
Extrusion but were weaker for Metals and
Automotive. During 2003, aluminium prices
measured in Norwegian kroner fell by seven
percent compared with 2002. As a result,
margins were substantially weaker in Metals
compared to 2002 reducing results by
approximately NOK 760 million. The decline
was offset by contribution from hedges and
higher trading results. However, higher
fixed cost and depreciation from ramp up of
new production capacity and unrealized
losses on LME contracts, more than offset
the savings from improvement programs and
the contribution from increased volumes. Operating income for Agri was NOK 2,800
million, NOK 593 million higher than the
year before. Higher fertilizer prices
measured
in US dollars improved operating income by
approximately NOK 2,600 million. Price gains
were partly offset by the negative effect of
increased raw material and energy costs of
approximately NOK 1,200 million. The
strengthening of European currencies against
the US dollar affected operating income
negatively for 2003 by approximately NOK 750
million. Total sales volumes for Agri were
unchanged for the year as a whole. Sales of
own produced products were up six percent
for the year. Due to the strong increase in
prices, many customers made their purchases
early in the season. However, prices are
expected to decline somewhat and high
volumes sold in the first half of the
fertilizer season may impact sales volumes
negatively in the remainder of the season
(first half of 2004). Operating income relating to Other
Activities reflected losses on bad debts and
write downs of goodwill and intangible
assets amounting to approximately NOK 570
million relating to the fish feed
operations included in Treka. Corporate and Eliminations incurred an
operating loss of NOK 1,727 million in 2003
compared to a loss of NOK 24 million in the
previous year. The loss primarily reflected
higher pension costs and the elimination of
unrealized gains on internal power purchase
contracts. In addition, the 2003 result
included costs of NOK 130 million linked to
the demerger of Hydro Agri, charged during
the fourth quarter. Costs relating to pensions and related
employers social security costs, charged to
Corporate and Eliminations amounted to
approximately NOK 1,146 million compared to
NOK 312 million in 2002. The increase in
2003 primarily reflected increased pension
obligations and a reduction in plan assets
during 2002. The increase in 2003 also
included a non-recurring charge of roughly
NOK 230 million, including employers social
security costs, due to a settlement loss
incurred in connection with a reduction in
the number of members in certain pension
plans in Norway. The reduction in the number
of members resulted from workforce reductions
and early retirement programs. Hydro Energy is responsible for
ensuring the supply of electricity for the
companys own consumption, and has entered
into power purchase contracts in the market
and sales contracts with other units in the
Group.
These contracts are recognized at
market value in Hydro Energy. For other
Hydro units, the related internal purchase
contracts are regarded as normal purchase
contracts and are not recognized at market
value. During the year, the estimated market
value of the external power purchase
contracts decreased with a corresponding
increase in the contract value of internal
sales contracts for Hydro Energy. The
elimination of the unrealized gains 78




---



##### 



included
in Hydro Energys results relating to
internal sales contracts resulted in a
charge to Corporate and Eliminations of NOK
141 million compared with a gain of NOK 588
million in 2002. The total negative variance
relating to these contracts for 2003 was NOK
729 million. The power purchase contracts
have a duration of up to 10 years and can
result in significant unrealized gains and
losses, impacting the results in future
periods. This will depend on trends in
forward prices for electricity and changes
in the contract portfolio. Earnings from non-consolidated
investees amounted to NOK 1,229 million for
the year compared to NOK 33 million in 2002.
A currency loss of NOK 461 million relating
to alumina operations in Brazil influenced
the result in 2002, compared to a currency
gain of NOK 218 million in 2003. Excluding
these effects, earnings improved by NOK 517
million for the year primarily due to
stronger results from non-consolidated
investees which are part of the Agri
business area reflecting high ammonia and
urea prices. Other income (expense), net for 2003
reflected a loss of NOK 1,212 million. The
loss included a charge of NOK 2,207 million
resulting from new Norwegian tax regulations
relating to the removal costs for oil and
gas installations on the Norwegian
continental shelf. In accordance with
earlier regulations, removal costs could not
be deducted when calculating taxable income.
Instead, the Norwegian state assumed a
portion of the removal costs by means of a
special removal grant for each license
calculated on the basis of the average tax
rate incurred by the participating companies
over the license period. The new rules
permit removal costs to be deducted from
taxable income. The amendment resulted in a
charge in the second quarter representing
the estimated value of expected grants. The
charge had no cash effect. At the same time,
a deferred tax asset representing the value
of the new tax deductions (calculated at 78
percent of the accrued asset removal
obligation), was included as a reduction to
the tax provision for the second quarter in
the amount of NOK 2,380 million. Other
income also included a gain of NOK 490
million on the sale of Hydros share in
Skandinaviska Raffinaderi AB, the Scanraff
oil refinery and a gain of NOK 326 million
resulting from the disposal of Hydros
ownership interest in Sundsfjord Kraft ANS. Net financial income for 2003 was NOK
201 million, including a foreign exchange
gain of NOK 1,035 million. During the course
of 2003, the US dollar fell by four percent
against the Norwegian krone, and weakened
considerably against other currencies
(roughly 17 percent against the Euro, and 25
percent against the Australian dollar). The
US dollar movements have resulted in gains
on Hydros net US dollar denominated debt
for the year as a whole. The weakness of the
Norwegian krone has, however, resulted in
losses on Hydros net Euro denominated debt
for 2003. Financial
income for 2002 was NOK 1,935 million
including a net foreign currency exchange
gain of NOK 3,262 million. The provision for current and deferred
taxes for 2003 amounted to NOK 13,937
million, approximately 57 percent of pre-tax
income. The tax provision has been strongly
influenced by the effects of amendments to
the Norwegian tax regulations relating to
the future costs of removing oil and gas
installations on the Norwegian continental
shelf after
production has ceased. In addition, the
tax provision for the third quarter included
a one time positive effect of NOK 139
million relating to the final conclusion of
an outstanding tax ruling in Norway.
Excluding these effects, tax expense
amounted to 62 percent of pre-tax income for
2003. The high tax percent in both 2003 and
2002 results because oil and gas activities
in Norway, which account for a relatively
large part of earnings, are charged a
marginal tax rate of 78 percent. Non-GAAP Measures of Financial Performance Within this discussion, Hydro refers to
certain non-GAAP financial measures which
are an integral part of Hydros steering
model, Value Based Management, reflecting
Hydros focus on cash flow based indicators,
before and after taxes. These non-GAAP
financial measures are:  
    
    EBITDA
    
    Gross Cash Flow
    
    Gross Investment
    
    Cash Return on Gross Investment (CROGI) Hydros management makes regular use of
these cash flow-based indicators to measure
performance in its operating segments, both
in absolute terms and comparatively from
period to period. Management views these
measures as adding to the 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 79




---



##### 



A reconciliation of Operating income to EBITDA for each of Hydros operating
segments is presented in the following table: Operating income  EBIT  EBITDA 2003 SelectedOperating
    
    
    Non-cons.
    
    
    Interest
    
    
    financial
    
    
    Other
    
    
    
    
    
    
    Depr. andAmounts in NOK million
    
    income (loss)
    
    
    Investees
    
    
    Income
    
    
    income
    
    
    income
    
    
    EBIT
    
    
    amort.
    
    
    EBITDAExploration and Production
    
    
    18,500
    
    
    
    29
    
    
    
    32
    
    
    
    4
    
    
    
    
    
    
    
    18,565
    
    
    
    9,059
    
    
    
    27,624Energy and Oil Marketing
    
    
    2,668
    
    
    
    81
    
    
    
    35
    
    
    
    (24
    )
    
    
    816
    
    
    
    3,576
    
    
    
    650
    
    
    
    4,226Eliminations
    
    
    (25
    )
    
    
    (3
    )
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (28
    )
    
    
    4
    
    
    
    (24
    )Hydro Oil & Energy
    
    
    21,143
    
    
    
    107
    
    
    
    67
    
    
    
    (20
    )
    
    
    816
    
    
    
    22,113
    
    
    
    9,713
    
    
    
    31,826Metals
    
    
    2,293
    
    
    
    379
    
    
    
    3
    
    
    
    53
    
    
    
    
    
    
    
    2,728
    
    
    
    1,570
    
    
    
    4,298Rolled Products
    
    
    132
    
    
    
    (14
    )
    
    
    18
    
    
    
    (5
    )
    
    
    
    
    
    
    131
    
    
    
    704
    
    
    
    835Extrusion and Automotive
    
    
    98
    
    
    
    68
    
    
    
    22
    
    
    
    (8
    )
    
    
    
    
    
    
    180
    
    
    
    1,252
    
    
    
    1,432Other and eliminations
    
    
    (67
    )
    
    
    
    
    
    
    
    
    
    
    1
    
    
    
    
    
    
    
    (66
    )
    
    
    (1
    )
    
    
    (67
    )Hydro Aluminium
    
    
    2,456
    
    
    
    433
    
    
    
    43
    
    
    
    41
    
    
    
    
    
    
    
    2,973
    
    
    
    3,525
    
    
    
    6,498Hydro Agri
    
    
    2,800
    
    
    
    610
    
    
    
    192
    
    
    
    (8
    )
    
    
    
    
    
    
    3,594
    
    
    
    1,154
    
    
    
    4,748Other activities
    
    
    (414
    )
    
    
    83
    
    
    
    164
    
    
    
    245
    
    
    
    162
    
    
    
    240
    
    
    
    900
    
    
    
    1,140Corporate and eliminations
    
    
    (1,727
    )
    
    
    (4
    )
    
    
    723
    
    
    
    20
    
    
    
    (2,190
    )1)
    
    
    (3,178
    )
    
    
    2,219
    1)
    
    
    (959
    )Total
    
    
    24,258
    
    
    
    1,229
    
    
    
    1,189
    
    
    
    278
    
    
    
    (1,212
    )
    
    
    25,742
    
    
    
    17,511
    
    
    
    43,253
  1)
    
    Includes non-cash charge relating to an expected state grant pertaining to
an asset removal obligation of NOK 2,207 million. EBITDA and reconciliation to net income Hydro defines EBITDA as Income/(loss)
before tax, interest expense, depreciation,
amortization and write-downs. EBITDA is
intended to be an approximation of cash flow
from operations before tax. EBITDA is a
measure that includes in addition to
Operating income, Interest income and
other financial income, results from
non-consolidated investees and gains and
losses on sales of activities classified as
Other income, net in the income statement.
It excludes depreciation, write-downs and
amortization, as well as amortization of
excess values in non-consolidated investees.
Hydros definition of EBITDA may differ from
that of other companies. The EBITDA figures by core business
area are presented in the table below, in
addition to the reconciliation from EBITDA
to income before taxes and minority
interest. Reconciliation to net income Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Hydro Oil & Energy
    
    
    31,826
    
    
    
    25,340
    
    
    
    27,604Hydro Aluminium
    
    
    6,498
    
    
    
    4,334
    
    
    
    2,543Hydro Agri
    
    
    4,748
    
    
    
    3,945
    
    
    
    4,402Other Activities
    
    
    1,140
    
    
    
    1,044
    
    
    
    1,215Corporate and Eliminations
    
    
    (959
    )
    
    
    995
    
    
    
    1,993Total EBITDA1)
    
    
    43,253
    
    
    
    35,658
    
    
    
    37,757Depreciation, depletion and
amortization2)
    
    
    (15,093
    )
    
    
    (13,912
    )
    
    
    (12,534
    )Amortization of excess values in
non-consolidated investees
    
    
    (211
    )
    
    
    (235
    )
    
    
    (149
    )Other income (expense)
non-cash3)
    
    
    (2,207
    )
    
    
    
    
    
    
    Interest expense
    
    
    (2,912
    )
    
    
    (3,189
    )
    
    
    (3,721
    )Capitalized interest
    
    
    715
    
    
    
    607
    
    
    
    685Net foreign exchange gain/(loss)
    
    
    1,035
    
    
    
    3,262
    
    
    
    (416
    )Other financial items
    
    
    (104
    )
    
    
    (163
    )
    
    
    (157
    )Income before tax and minority
interest
    
    
    24,476
    
    
    
    22,028
    
    
    
    21,465Income tax expense
    
    
    (13,937
    )
    
    
    (13,278
    )
    
    
    (13,750
    )Minority interest
    
    
    148
    
    
    
    15
    
    
    
    177Income before cumulative effect
of change in accounting principle
    
    
    10,687
    
    
    
    8,765
    
    
    
    7,892Cumulative effect of change
in accounting principle
    
    
    281
    
    
    
    
    
    
    
    Net income
    
    
    10,968
    
    
    
    8,765
    
    
    
    7,892
  1)
    
    EBITDA: Earnings Before Interest,
Taxes, Depreciation and Amotization.
EBITDA information by segment in each
of the core business areas, as well as
explanation of the financial
performance of each segment, is
included in the presentation of the
business areas.2)
    
    Includes write-downs of property,
plant, and equipment included in
restructuring costs of NOK 261
million for 2001.3)
    
    The amount relates to the reversal of
an expected state grant pertaining to
an asset removal obligation. 80




---



##### 



Another cash flow based indicator used by
Hydro to measure its performance is cash
return on gross investment (CROGI). CROGI is
defined as gross cash flow after taxes,
divided by average gross investment. Gross
cash flow is defined as EBITDA less total
tax expense. Gross investment is defined
as total assets (exclusive of deferred tax
assets) plus accumulated depreciation and
amortization, less all short-term interest
free liabilities except deferred taxes.
CROGI has been Hydros main financial return
metric since 2000 and is used by management
to measure financial performance at the
operating segment
level and the Group level. In order to calculate Gross Cash Flow
per operating segment, tax is also
calculated for the operating segments. Tax
is calculated by dividing each operating
segment into the main tax regimes in which
the segment operates, and applying the
applicable statutory tax rates in those tax
regimes to the taxable income/loss included
in EBITDA. Taxable income/loss is typically
Operating income, Interest income and
other financial income and Other
income/(expense), net. This taxable
income for each operating segment is
multiplied with the applicable average tax
rate. For the sub-segment Exploration and
Production an average tax rate of 60 percent
is applied. An average tax rate of 50
percent is used for our Energy and Oil
Marketing sub-segment. An average tax rate
of 30 percent is being used for all other
operating segments. This method represents
an approximation to a tax expense for the
operating segment. It does not, however,
necessarily capture the effects of tax
consolidation across the operating segments,
which is permissible in certain countries
where Hydro operates. Such effects are
included at the Group level under the line
Corporate and Eliminations in Hydros
segment disclosures. The allocated tax
expense for the segments plus the tax
expense reported under Corporate and
Eliminations equals the total USGAAP tax
expense for the
Group as presented in the income statement.
As 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. In 2003, CROGI was 9.8 percent compared
with 8.5 percent in 2002. CROGI for Hydro in
total and each of the business areas is
presented in the table below: CROGI
    
    2003
    
    2002
    
    2001Hydro Oil & Energy
    
    
    13.0
    %
    
    
    12.1
    %
    
    
    13.2
    %Hydro Aluminium
    
    
    8.6
    %
    
    
    7.1
    %
    
    
    5.7
    %Hydro Agri
    
    
    11.7
    %
    
    
    9.4
    %
    
    
    9.6
    %Hydro
    
    
    9.8
    %
    
    
    8.5
    %
    
    
    9.4
    %
 EBITDA and Gross Cash Flow 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. Nor are
EBITDA and Gross Cash Flow an alternative
to cash flow from operating activities in
accordance with generally accepted
accounting principles. Hydros management
makes regular use of measures calculated
according to generally accepted accounting
principles in addition to non-GAAP financial
measures described above when measuring
financial performance. 81




---



##### 



The following tables present a calculation of gross cash flow and gross investment for the Group as a whole and for each of the Business Areas: Cash Return on Gross Investment  Hydro Year ended
    
    
    Year ended
    
    
    Year ended31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating income
    
    
    24,258
    
    
    
    19,841
    
    
    
    21,083Equity in net income of non-consolidated investees
    
    
    1,229
    
    
    
    33
    
    
    
    566Interest income and other financial income
    
    
    1,467
    
    
    
    1,418
    
    
    
    2,847Other income/expense, net
    
    
    (1,212
    )
    
    
    219
    
    
    
    578EBIT
    
    
    25,742
    
    
    
    21,511
    
    
    
    25,074Depreciation and amortization
    
    
    17,511
    
    
    
    14,147
    
    
    
    12,683EBITDA
    
    
    43,253
    
    
    
    35,658
    
    
    
    37,757Income tax expense
    
    
    (16,144
    )
    
    
    (13,278
    )
    
    
    (13,750
    )Gross Cash Flow
    
    
    27,109
    
    
    
    22,380
    
    
    
    24,007
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Current assets1)
    
    
    74,416
    
    
    
    64,179
    
    
    
    78,217
    
    
    
    80,113Non-consolidated investees
    
    
    12,711
    
    
    
    11,499
    
    
    
    9,687
    
    
    
    7,211Property, plant and equipment
    
    
    114,998
    
    
    
    112,342
    
    
    
    95,277
    
    
    
    95,025Prepaid pension, investments and other non-current assets
    
    
    14,387
    
    
    
    15,081
    
    
    
    11,636
    
    
    
    10,983Other current liabilities
    
    
    (42,890
    )
    
    
    (38,331
    )
    
    
    (32,245
    )
    
    
    (33,171
    )Accumulated depreciation and amortization
    
    
    115,197
    
    
    
    101,907
    
    
    
    97,930
    
    
    
    92,385Other
    
    
    (1,231
    )
    
    
    (1,281
    )
    
    
    (1,663
    )
    
    
    Gross Investment
    
    
    287,588
    
    
    
    265,396
    
    
    
    258,839
    
    
    
    252,546
 31 December
    
    
    31 December
    
    
    31 December2003
    
    
    2002
    
    
    2001Cash Return on Gross Investment (CROGI)
    
    
    9.8%
    
    
    
    8.5%
    
    
    
    9.4%
  1)
    
    Excluding current deferred tax assets Cash Return on Gross Investment  Oil & Energy Year ended
    
    
    Year ended
    
    
    Year ended31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating income
    
    
    21,143
    
    
    
    15,947
    
    
    
    19,177Equity in net income of non-consolidated investees
    
    
    107
    
    
    
    179
    
    
    
    65Interest income and other financial income
    
    
    47
    
    
    
    125
    
    
    
    144Other income/expense, net
    
    
    816
    
    
    
    77
    
    
    
    179EBIT
    
    
    22,113
    
    
    
    16,328
    
    
    
    19,565Depreciation and amortization
    
    
    9,713
    
    
    
    9,012
    
    
    
    8,039EBITDA
    
    
    31,826
    
    
    
    25,340
    
    
    
    27,604Income tax expense
    
    
    (12,911
    )
    
    
    (9,114
    )
    
    
    (11,202
    )Gross Cash Flow
    
    
    18,915
    
    
    
    16,226
    
    
    
    16,402
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Current assets1)
    
    
    15,564
    
    
    
    20,204
    
    
    
    11,473
    
    
    
    12,950Non-consolidated investees
    
    
    2,406
    
    
    
    1,991
    
    
    
    2,095
    
    
    
    1,402Property, plant and equipment
    
    
    74,460
    
    
    
    73,223
    
    
    
    70,146
    
    
    
    68,667Prepaid pension, investments and other non-current assets
    
    
    1,294
    
    
    
    1,362
    
    
    
    1,654
    
    
    
    1,362Other current liabilities
    
    
    (11,493
    )
    
    
    (16,589
    )
    
    
    (8,732
    )
    
    
    (9,133
    )Accumulated depreciation and amortization
    
    
    68,186
    
    
    
    59,928
    
    
    
    52,069
    
    
    
    45,360Gross Investment
    
    
    150,417
    
    
    
    140,119
    
    
    
    128,705
    
    
    
    120,608
 31 December
    
    
    31 December
    
    
    31 December2003
    
    
    2002
    
    
    2001Cash Return on Gross Investment (CROGI)
    
    
    13.0%
    
    
    
    12.1%
    
    
    
    13.2%
  1)
    
    Excluding current deferred tax assets 82




---



##### 



Cash Return on Gross Investment  Aluminium Year ended
    
    
    Year ended
    
    
    Year ended31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating income
    
    
    2,456
    
    
    
    1,698
    
    
    
    185Equity in net income of non-consolidated investees
    
    
    433
    
    
    
    (219
    )
    
    
    118Interest income and other financial income
    
    
    84
    
    
    
    129
    
    
    
    149Other income/expense, net
    
    
    
    
    
    
    
    
    
    
    (25
    )EBIT
    
    
    2,973
    
    
    
    1,608
    
    
    
    427Depreciation and amortization
    
    
    3,525
    
    
    
    2,726
    
    
    
    2,116EBITDA
    
    
    6,498
    
    
    
    4,334
    
    
    
    2,543Income tax expense
    
    
    (737
    )
    
    
    (522
    )
    
    
    (58
    )Gross Cash Flow
    
    
    5,761
    
    
    
    3,812
    
    
    
    2,485
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Current assets1)
    
    
    22,925
    
    
    
    21,362
    
    
    
    16,021
    
    
    
    17,868Non-consolidated investees
    
    
    5,787
    
    
    
    4,902
    
    
    
    3,288
    
    
    
    2,498Property, plant and equipment
    
    
    29,504
    
    
    
    26,496
    
    
    
    11,770
    
    
    
    11,206Prepaid pension, investments and other non-current assets
    
    
    3,880
    
    
    
    4,437
    
    
    
    2,958
    
    
    
    2,611Other current liabilities
    
    
    (11,666
    )
    
    
    (10,080
    )
    
    
    (8,610
    )
    
    
    (8,351
    )Accumulated depreciation and amortization
    
    
    21,158
    
    
    
    17,997
    
    
    
    19,055
    
    
    
    18,897Other
    
    
    (1,231
    )
    
    
    (1,281
    )
    
    
    (1,663
    )
    
    
    Gross Investment
    
    
    70,357
    
    
    
    63,833
    
    
    
    42,819
    
    
    
    44,729
 31 December
    
    
    31 December
    
    
    31 December2003
    
    
    2002
    
    
    2001Cash Return on Gross Investment (CROGI)
    
    
    8.6%
    
    
    
    7.1%
    
    
    
    5.7%
  1)
    
    Excluding current deferred tax assets Cash Return on Gross Investment  Agri Year ended
    
    
    Year ended
    
    
    Year ended31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating income
    
    
    2,800
    
    
    
    2,207
    
    
    
    2,114Equity in net income of non-consolidated investees
    
    
    610
    
    
    
    57
    
    
    
    330Interest income and other financial income
    
    
    184
    
    
    
    235
    
    
    
    422Other income/expense, net
    
    
    
    
    
    
    166
    
    
    
    (53
    )EBIT
    
    
    3,594
    
    
    
    2,665
    
    
    
    2,813Depreciation and amortization
    
    
    1,154
    
    
    
    1,280
    
    
    
    1,589EBITDA
    
    
    4,748
    
    
    
    3,945
    
    
    
    4,402Income tax expense
    
    
    (895
    )
    
    
    (771
    )
    
    
    (733
    )Gross Cash Flow
    
    
    3,853
    
    
    
    3,174
    
    
    
    3,669
 31 December
    
    
    31 December
    
    
    31 December
    
    
    31 DecemberAmounts in NOK million
    
    2003
    
    
    2002
    
    
    2001
    
    
    2000Current assets1)
    
    
    13,672
    
    
    
    11,355
    
    
    
    14,427
    
    
    
    16,047Non-consolidated investees
    
    
    2,498
    
    
    
    2,089
    
    
    
    2,519
    
    
    
    2,394Property, plant and equipment
    
    
    7,189
    
    
    
    7,006
    
    
    
    7,982
    
    
    
    9,294Prepaid pension, investments and other non-current assets
    
    
    960
    
    
    
    785
    
    
    
    748
    
    
    
    1,523Other current liabilities
    
    
    (6,872
    )
    
    
    (6,223
    )
    
    
    (6,385
    )
    
    
    (6,923
    )Accumulated depreciation and amortization
    
    
    17,602
    
    
    
    15,727
    
    
    
    17,222
    
    
    
    17,759Gross Investment
    
    
    35,049
    
    
    
    30,739
    
    
    
    36,513
    
    
    
    40,094
 31 December
    
    
    31 December
    
    
    31 December2003
    
    
    2002
    
    
    2001Cash Return on Gross Investment (CROGI)
    
    
    11.7%
    
    
    
    9.4%
    
    
    
    9.6%
  1)
    
    Excluding current deferred tax assets 83




---



##### 



Non-recurring or Infrequent Items Hydro also identifies items of a
non-recurring or infrequent nature in
discussing operating results. These items
reflect activities or events which
management believes are not indicative of
expected trends and outcomes arising from
normal, recurring business operations.
Generally such items arise as a result of
very substantial initiatives including major
turnarounds and other transforming events or
material events and transactions which are
not expected to occur often in the normal
course of business. Non-recurring or
infrequent items include but are not limited
to :  
    
    costs related to major improvement
programs (which will vary from period to
period and in certain periods may be
insignificant, but which are identified
nonetheless to enable investors to
understand the total impact of such
programs)
    
    material changes in the value of assets
or liabilities related to infrequent
events or major, unusual circumstances
    
    material gains or losses related to
infrequent or non-recurring events or
transactions In general, Hydro excludes these items from
financial measures calculated and presented
in accordance with GAAP. This is not done
with respect to other smaller, less
comprehensive cost reduction programs,
efficiency initiatives and business
expansion activities which are viewed as
normal, recurring activities and do not take
away from investors understanding of the
underlying business performance. Hydros Critical Accounting Policies In December 2001, the SEC issued Financial Reporting Release
No. 60, Cautionary Advice Regarding Disclosure About Critical
Accounting Policies, referred
to as FR 60, suggesting that companies provide additional
disclosure and commentary on those accounting policies considered most critical.
FR 60 considers an accounting policy to be critical if it
is important to a companys financial condition and results of
operations and requires significant judgment and estimates on the
part of management in its application. In December 2003,
the SEC issued FR 72 which included additional guidance
relating to critical accounting estimates. In this release,
the SEC indicated that companies should consider providing enhanced
discussion and analysis of critical accounting estimates that provides greater insight
into the quality and variability of information regarding
financial condition and operating performance. 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. Hydro believes that the following represents its critical accounting policies as contemplated by FR 60. 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 December 31, 2003, 2002 and 2001 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 several years 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 transferred to development cost, and subsequently amortized
to become part of the cost of the oil and gas produced. 84




---



##### 



A determination that proved reserves do not exist
can result in a reduction to 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 2003, exploration activity (expenditures) totaled NOK 1,609 million, of
which NOK 120 million was capitalized during the year. Including capitalized exploration
costs and acquisition costs from prior periods, NOK 1,577 million was expensed during
the year. At the end of 2003, NOK 1,023 million of such costs were
capitalized pending the evaluation of drilling results and planned development, of
which NOK 33 million related to acquisition costs. In connection with the review of
our 2002 Form 20-F, the staff of the SECs Division of Corporation Finance has raised questions
about our practice of deferring costs (i.e., continuing to carry
such costs as an asset on our balance sheet) related to certain exploratory
wells. The wells in question have all demonstrated commercial
quantities and the drilling of wells on the properties in
question has been completed. Work related to development concept optimization
and PDO submission /authority approval is ongoing. Capitalized exploration costs
net of property acquisition costs amounted to NOK 990 million
as of December 31, 2003. The capitalized exploration costs of the
wells in question represent approximately one-third of the net
capitalized exploration costs at the end of 2003. The vast majority
of these wells are located on the Norwegian Continental Shelf,
where the combined tax rate is 78% of income before taxes.
Therefore, in the event that it is determined that some or all of
these costs should be expensed, the accumulated effect on net income
would be reduced by the tax effect. 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 does 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 depreciation and
depletion expense in future periods. Conversely, upward revisions in
reserve estimates can result in lower future depreciation, depletion and
amortization. Depreciation, depletion and amortization related to oil and gas
producing activities in 2003, 2002 and 2001 were NOK 9,114 million,
NOK 8,553 million and NOK 7,423 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.
The historical volatility in these commodity prices materially
affects 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 instruments are deemed to be derivatives
under US GAAP and required to be recognized at fair value, with
changes in the fair value impacting earnings. 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 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 on page 107 . Asset Retirement Obligations Hydro has adopted as of January 1, 2003
SFAS 143, Accounting for Asset Retirement Obligations. Among
other things, SFAS 143 requires significant changes in the accounting treatment
for asset retirement obligations such as abandonment of oil and
gas production platforms, facilities and pipelines. Specifically, the
fair value of a liability for an asset retirement obligation
is required to be recorded when incurred. Furthermore,
the liability is to be accreted for the change
in its present value each reporting period. 85




---



##### 



Hydros asset retirement obligations consist
mainly of accruals for removal and decommissioning 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 the Storting (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 decommissioning
and removal costs based on an expected retirement concept and timing.
The timing of retirement activities is normally assumed to be the end of production.
Retirement activities relating to 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. Changes to technology, Norwegian regulations and
other factors may affect the timing and scope of
retirement activities. Such changes may substantially alter the book
value of property, plant and equipment, asset retirement
obligations and future operating costs. Classification of mineral interests in oil and gas properties A discussion is currently ongoing within the
oil industry regarding the classification of mineral interests
in oil and gas properties. Hydro has historically reported and currently reports
such interests as part of Property, Plant and Equipment. The
industrys
current practice as to the proper classification of acquisition of
contractual mineral interests under SFAS 141 Business
Combinations and
SFAS 142 Goodwill and Intangible Assets has been questioned.
The Financial Accounting Standards Board (FASB) has issued FASB Staff Position
Nos. FAS 141-1 and FAS 142-1, addressing certain aspects of this discussion.
In addition, Emerging Issues Task Force (EITF) 04-2
addresses a related issue, whether mineral rights are tangible or intangible
assets, concluding that such assets are tangible assets.
Furthermore, mineral rights are required to be separately
disclosed in reporting periods beginning after 31 March, 2004.
However, this statement applies only to mining entities, while
oil- and gas-producing entities within the
scope of SFAS 19 are excluded. The EITF has included
the topic for oil and gas-producing entities on its
agenda as Issue No. 03-S, stating that consideration of this issue
will be consistent with the approach taken with regard to mineral
rights related to mining enterprises. Thus further authoritative
guidance on the issue is expected. The majority of Hydros oil and gas producing fields
and fields under development are offshore fields in various parts of the world
and at various water depths. Development of these fields
involves installations and production facilities tailored to each development.
Hydro has not considered it beneficial to report acquired
mineral interests in oil and gas properties and assets related
to the development of these properties (e.g., offshore
production platforms, wells and equipment) separately. Hydro has made one significant acquisition of
mineral interests in oil and gas properties subsequent to
the implementation of SFAS 141 and SFAS 142 in 2001: the
acquisition in May 2002 of increased interests in certain oil and
gas producing fields and fields under development on the Norwegian Continental
Shelf (NCS) from the Norwegian State. Consistent with
Hydros historical practice, the acquired interests, including offshore
production platforms, wells and equipment, were recorded
as Property, Plant and Equipment in the consolidated balance sheet,
of which mineral interests in oil and gas properties were
NOK 1.5 billion, all of which was assigned to
proved reserves in producing fields and fields in development phase.
Should new accounting guidance require hydrocarbon reserves obtained in
acquisitions of oil and gas properties to be reported
separately, either as tangible or intangible assets, the
maximum amount Hydro would reclassify in
accordance with such guidance is approximately NOK 1.3
billion as of December 31, 2003, and NOK 1.4 billion
as of December 31, 2002. The determination of these amounts is based
on Hydros current understanding of this issue. A reclassification
would not be expected to change Hydro's result of operations or
cash flows. Hydro will continue to classify these assets as part of
Property, Plant and Equipment until authoritative guidance is provided. 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 require a write-down upon
determination of impairment for 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. Impairment charges result in a decrease to
Property, Plant and Equipment on the balance sheet and an increase in operating costs. Contingencies and Environmental Liabilities Contingencies and environmental liabilities are recorded when such
items are asserted, or are probable of assertion, and the amount of potential loss
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. Environmental liabilities require interpretation
of scientific and legal data, in addition to assumptions about probability
and future costs. Changes in these assumptions can affect the timing and
amounts of recorded liabilities and costs. 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. Purchase accounting is
subject to a number of assumptions including useful lives of assets,
discount rates in different environments, replacement costs and
timing of certain future cash flows. 86




---



##### 



Hydros most recent significant acquisition was the purchase of
VAW for a purchase price of EUR 1,911 million (NOK 14.9 billion). 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 and Intangible Assets Under SFAS 142, Goodwill and Other
Intangible Assets, implemented in 2002, goodwill and certain
intangible assets are no longer systematically amortized, but 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 assessed
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 were made
reflecting the sectors industry. Total goodwill evaluated for impairment during
2003 was approximately NOK 1,100 million. Intangible assets determined
to have indefinite useful lives are not amortized until a finite
life can be estimated. Such assessment requires management to look at
the legal, regulatory, competitive, and contractual factors to
determine whether the useful life of the asset acquired is considered to
be indefinite. Currently, Hydro has  intangible assets with a carrying
value of NOK 5 million deemed to have indefinite life.
Goodwill and intangible assets are 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. Managements judgment may change 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. As of December 31, 2003, the projected benefit obligation (PBO)
associated with Hydros defined benefit plans was NOK 29.2 billion. The fair value of
pension plan assets was NOK 18.7 billion, resulting in a net unfunded obligation relating
to the plans of NOK 10.5 billion. In addition, termination benefit obligations and
other pension obligations amounted to NOK 1.5 billion, resulting in a total net unfunded
pension obligation of NOK 12 billion. Hydro's net pension cost for 2003 amounted to
NOK 2.5 billion. Cash outflows from operating activities in 2003 regarding pensions
amounted to NOK 2 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 two-thirds of Hydro's
projected benefit obligation relates to Norway. The discount rate
applied for Norwegian plans as of December 31, 2003 is six 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, inflation, discount
rates, years of future service, and rate of return on plan assets.
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. 87




---



##### 



Business Segment Information Prior to the demerger of Agri, Hydro's operating segments consisted of the three core business areas Oil and Energy, Aluminium and Agri. Each business area is divided into sub-segments representing different parts of the value chain as follows: Oil and Energy:
    
    Exploration and ProductionEnergy and Oil MarketingAluminium:
    
    Metals (Primary Metals and Metal
Products)Rolled ProductsExtrusion and Automotive
(including the North America sector)Agri:
    
    Agri (Fertilizer and Industrial Gases
and Chemicals)
 In addition, Hydro is in the petrochemicals
business and is engaged in other activities.
A discussion of the operating results for
each of the sub-segments within Hydros core
business areas, as well as for Other
Activities, follows. Hydro Oil & Energy Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    59,959
    
    
    
    55,845
    
    
    
    52,180Operating Income
    
    
    21,143
    
    
    
    15,947
    
    
    
    19,177EBITDA
    
    
    31,826
    
    
    
    25,340
    
    
    
    27,604Gross Investment
    
    
    150,417
    
    
    
    140,119
    
    
    
    128,705CROGI
    
    
    13.0%
    
    
    
    12.1%
    
    
    
    13.2%Number of employees
    
    
    3,465
    
    
    
    4,039
    
    
    
    3,891
 Hydro Oil & Energy consists of the sub
segments Exploration and Production and
Energy and Oil Marketing. Summary of key developments in 2003 Hydro Oil & Energys operating income in 2003 was NOK 21,143 million, an increase of 33 percent compared to 2002. The most significant developments that influenced Hydro Oil and Energys operating income in 2003 were as follows: Oil and gas production
increased by 10 percent to an average of 530,000 boe per
day (boed). The increase came both from
Norwegian and international fields. During
2003 a number of new fields commenced
production, Grane being the most important. Oil
and gas prices were high
throughout the year. Oil prices increased in
2003 reaching an average realized oil price
of US dollar 28.7, up 16 percent from US
dollar 24.7 in 2002. However the
depreciation of the US dollar against NOK
offset much of the effect of the price
increase. Realized oil prices measured in
NOK increased by approximately 4 percent
compared to the previous year. Realized gas
prices increased by approximately 7 percent. Exploration costs in 2003 were NOK 1,577 million, a reduction of 56 percent compared to the previous year. The decline reflects a 32 percent reduction in the level of exploration activity for 2003 compared to the previous year in addition to a lower level of previously capitalized exploration and acquisition cost expensed in the period.
There were 13 exploration wells drilled and completed in 2003 resulting in three discoveries. In addition, two discoveries were announced in Angola during the first quarter of 2003 based on exploration activity in 2002. Hydros proved oil and gas
reserves were 2,288 million barrels of oil
equivalents (mboe) at the end of 2003,
compared to 2,225 mboe at the end of 2002.
Hydros reserve replacement ratio for 2003
was 133 percent, including reserves of 1.5
mboe relating to sold interests in the Brage
and Njord fields. The reserve replacement
ratio was 134 percent excluding purchases
and sales of license interests. The increase
in the reserves resulted from the inclusion
of new fields in Norway, in particular Ormen
Lange (SEC reserves; 234 mboe) and
Vestflanken, as well as revisions of
reserves relating to producing fields.
Reserve life (defined as the number of years
of production from proved reserves at the
present production level) was 12 years at
the end of 2003; comprised of 7 years for
oil and 27 years for gas. Hydro continued activities to optimize its license portfolio during
the year. In 2003, approval was received
from the Norwegian authorities for the sale
of interests in the Brage and Njord fields.
In addition, Hydro entered into an agreement
for the sale of its interest in the Gjøa
field. The sale was approved by the
authorities in January 2004 and resulted in a tax-free gain of NOK 280
million that was reflected in the
results in the first quarter of 2004. In
January 2004, the Company signed an
agreement to sell its 10 percent share in
the Snøhvit field to Statoil. The
transaction is
expected to result in an after tax gain of
roughly NOK 100 million. At the same time an
agreement was reached for the purchase of a
two percent share in the Kristin field increasing Hydros
interest in the field to 14 percent of the field,
improving its position in the Norwegian Sea
Area on the NCS. Both agreements reflect
Hydros strategy to optimize its oil and gas
portfolio. During 2003, Hydro sold its interest in
the company that owns the Scanraff refinery
in Sweden (Scandinaviske Raffinaderi AB).
The transaction resulted in a gain of NOK
490 million that is reflected in the results
of 2003. Operating cost per barrel for Hydros
oil and gas production was NOK 84 per boe in
2003 compared to NOK 100 per boe in 2002.
The main reason for the reduction was lower
exploration costs compared to 2002. In
addition, increased production resulted in
lower 88




---



##### 



costs per barrel due to greater
economies of scale. During 2003 Hydro
rationalized parts of its administrative and
exploration organizations including manning
reductions of approximately 60 people and a
substantial reduction in the use of external
consultants. This was in addition to the 535
employees that were transferred to Statoil
as of January 1, 2003 in connection with the
transfer of operatorship on the Tampen
fields. Operating costs excluding
exploration were NOK 76 per boe in 2003
compared to NOK 79 per boe in 2002, well
below the announced target of NOK 82 per
boe. Power production in 2003 was 27 percent
lower than 2002 and lower than normal from
hydro powered production plants. Prices in
the Nordic electric power market were NOK
0.29 per kWh, compared to NOK 0.20 in the
prior year. The
change in 2003 operating income
compared to the prior year and the most
important items affecting the change are
included in the table below. Amounts in NOK million
    
    2003Operating income 2003
    
    
    21,143Operating income 2002
    
    
    15,947Change in Operating Income
    
    
    5,196Prices and currency for E&P- oil
    
    
    4,110- gas
    
    
    485- currency
    
    
    (2,835
    )- put options
    
    
    1101,870Margin
    
    
    205Volume
    
    
    2,515Fixed costs
    
    
    10Depreciation
    
    
    (640
    )Production costs
    
    
    (440
    )Exploration costs
    
    
    1,980Other
    
    
    (304
    )Total change
in Operating Income
    
    
    5,196
 The main reasons underlying the material
variances are described in the summary
above. Exploration and Production Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    37,904
    
    
    
    32,970
    
    
    
    32,426Operating Income
    
    
    18,500
    
    
    
    13,137
    
    
    
    16,910EBITDA
    
    
    27,624
    
    
    
    21,593
    
    
    
    24,312Gross Investment
    
    
    124,655
    
    
    
    115,938
    
    
    
    106,382CROGI
    
    
    13.7%
    
    
    
    12.2%
    
    
    
    13.7%Number of employees
    
    
    2,800
    
    
    
    3,372
    
    
    
    3,213
 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. Effective January 1, 2003, Hydros gas transportation
assets were transferred from the Exploration
and Production sub-segment to the Energy and
Oil Marketing sub-segment. All prior periods
have been reclassified for comparative
purposes. Market Conditions Oil prices increased in 2003 reaching an
average realized oil price of US dollar
28.7, up 16 percent from US dollar 24.7 in
2002. The higher oil prices were mainly due
to political turmoil in Venezuela affecting
the oil industry in particular; the onset
of war in Iraq; a very cold winter in the
US; high US natural gas prices and the
beginning of a global economic recovery
creating increased demand for crude oil.
These circumstances were in addition to
OPEC actions to maintain high oil prices
levels. However the
depreciation of the US dollar against NOK
offset much of the effect of the price
increase. Expressed in Norwegian kroner the
oil price went up from NOK 194 in 2002 to
NOK 203 in 2003, an increase of 4 percent.
The average realized gas price in 2003 was
NOK 1.03 per standard cubic meter, up 7
percent from NOK 0.95 per standard cubic
meter in 2002. The increase 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). Revenues Operating revenues for E&P in 2003 were NOK
37,904 million, an increase of 15 percent
from the previous year. In addition to the
higher price levels experienced for oil and
gas, the increase reflected substantial
growth in total production volumes. During
2003, average production increased from
480,000 boed in 2002 to 530,000 boed. The
increase of approximately 10 percent was
well above the forecast for the year and in
line with a targeted 8 percent compound
annual growth rate for the 2001-2007 period.
Oil production increased by 7 percent and
accounted for 74 percent of the total
production compared to 77 percent in 2002.
Gas production increased to a total of 7.8
billion standard cubic meters, an increase
of 22 percent compared to 6.4 billion
standard cubic meters in 2002. Oil and gas
production reached a record level in the fourth
quarter with an average production of
596,000 boed. Hydro experienced production growth
both from Norwegian and international fields
in 2003. New fields coming on stream in
Norway included the Grane, Mikkel, Fram and
the satellite Vigdis extension. In addition,
Jasmim in Angola and the Murzuq A field in
Libya started production in the fourth quarter
of 2003. Production also increased from
fields coming on stream in recent years
including Tune, Snorre B, Åsgard, Oseberg
Sør, Girassol and Terra Nova.The increased
interests in Hydro operated Oseberg, Tune
and Grane fields pur- 89




---



##### 



chased from the
Norwegian State on May 10, 2002 also
contributed to the growth with a full year
effect in 2003. International production
outside the Norwegian Continental Shelf
(NCS) accounted for 11 percent of the total
production, up from 10 percent in 2002.
Planned maintenance stops caused a
production loss (or delayed production) of
12,000 boed compared to 9,000 boed in 2002. Because the Energy and Oil Marketing
sub-segment purchases and sells Hydros
Norwegian equity production of oil, about 68
percent of Exploration and Productions
revenues in 2003 resulted from internal
sales. Equity production of gas and
international oil production are sold by
Energy and Oil Marketing on behalf of
Exploration and Production and account for
the majority of the external revenues. Operating Costs Operating costs for E&P were NOK 19,404
million in 2003, a decrease of 2 percent
compared to the previous year. Hydros average production cost, defined as 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,
operating cost of transportation systems and
depreciation), was NOK 21 per boe in 2003,
compared to NOK 23 per boe in 2002. The main
reasons underlying the cost reduction were
increased production, better productivity
and the implementation of extensive cost
control measures within Hydros portfolio of
producing fields. Depreciation, including accruals for
abandonment and well closure costs and
write-downs (but excluding depreciation on
transportation systems), averaged NOK 46 per
boe, the same level as in 2002. However,
total depreciation costs increased in 2003
as a result of higher production levels.
Total exploration costs including appraisal
costs of discoveries amounted to NOK 1,577
million in 2003 compared to NOK 3,558
million in 2002. The decline compared to
2002 resulted from lower exploration
activity and a substantially lower level of
previously capitalized exploration and
acquisition cost expensed during the period.
Cost relating to exploration activity in
2003 was NOK 1,609 million, compared to NOK
2,376 million in the previous year.
Seventy-three percent of the exploration
activity was dedicated to areas outside the
NCS, mainly in Angola, Canada, Iran and the
Gulf of Mexico. Out of a total of 13
exploration wells drilled and completed
during 2003, one discovery was made in the Gulf
of Mexico and two discoveries were made in
Norway. In addition, two wells were in the
process of being drilled at year-end. Cost
of NOK 1,489 million relating to 2003
exploration activities was expensed due
to unsuccessful efforts in Angola, Canada
and Norway. NOK 88 million relating to costs
capitalized in previous years was also
expensed. Operating Income Operating income in 2003 was NOK 18,500
million, a 41 percent increase from the
previous year. As discussed above, the main
reasons underlying the increase were higher
production volumes, lower exploration costs
and higher oil and gas prices. EBITDA EBITDA in 2003 was NOK 27,624 million, an
increase of NOK 6,031 million compared to
2002. Outlook Hydro will continue to focus its exploration
and production strategy for the coming years
on growing Hydros exploration and
production
activities, balancing the portfolio and
continuing to focus on cost improvements to
improve profitability. Following a review of the extensive
drilling program completed during 2001-2003,
Hydro plans to take measures to reduce the
risk profile of its exploration activities.
Hydro will evaluate purchasing discovered
petroleum resources in areas where Hydros
particular strengths in drilling, reservoir
management and field development can add
greater value. For 2004 Hydro will scale
back exploration activity to a level of
around NOK 1 billion, and anticipates an
annual level of NOK 1.5 billion for 2005. Hydros objective is to maintain its
position as an efficient operator on the
NCS. Hydro has targeted production cost of
NOK 24 per boe for 2004. The increase of
about NOK 3 per boe compared to 2003
to a large extent results from the cost of
purchasing injection gas to increase the
oil production on the new Grane field. Hydro expects its oil and gas production to increase by approximately 8 percent as an annual average during the period 2001-2007 based on its current portfolio of fields in production, fields under development or fields considered for development.
The production target for 2004 is an average of 560,000 boed of which approximately 90 percent comes from fields with currently booked proved reserves. Increased production from the Grane field is expected to contribute strongly to the growth in 2004. A main focus for Hydro in 2004 is the development of the Ormen Lange gas field on the NCS. This is the largest undeveloped gas field on the NCS, at a water depth of 850 to 1,100 meters. The Plan for Development and Operation (PDO) was submitted to the authorities for approval on 4 December 2003 together with the plan for installation and operation of the Langeled gas export pipeline from the field to the United Kingdom.
Approval of the PDO occurred in April 2004. Hydro is the operator during the development phase of the field. Production is scheduled to begin in 2007. Total investments including the gas export pipeline is estimated to be NOK 66 billion excluding estimated inflation over the life of the project. Hydro holds an ownership interest in the field of 18.0728 percent. Crude oil prices have been high for the
last three years and current forward market prices indicate that prices will remain high in 2004. It is expected that OPEC will manage crude production to 90




---



##### 



maintain price
levels within their USD 22-28 price band
target for their basket of crude oil types for 2004. The growth in demand
resulting from global GDP growth and
increased demand for oil in new production
and transportation systems (refineries,
pipelines, terminals etc.) is expected to be
balanced by growth in non-OPEC production,
increased oil production from Iraq and
production cuts from the remaining OPEC
countries if needed. Energy and Oil Marketing Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    49,370
    
    
    
    45,915
    
    
    
    45,824Operating Income
    
    
    2,668
    
    
    
    2,784
    
    
    
    2,267EBITDA
    
    
    4,226
    
    
    
    3,721
    
    
    
    3,292Gross Investment
    
    
    25,734
    
    
    
    24,128
    
    
    
    22,366CROGI
    
    
    9.8%
    
    
    
    11.2%
    
    
    
    10.6%Number of employees
    
    
    665
    
    
    
    667
    
    
    
    678
 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. In
2003, Hydro sold its interest in the company
that owns the Scanraff refinery in Sweden
(Scandinaviske Raffinaderi AB). As a result, Hydro no
longer holds an interest in the refining
business. Results from the operation of
Scanraff are included until 17 December
2003. 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. Market Conditions As described under the caption Market
Conditions for the Exploration and
Production sub-segment, the price level for
oil, oil products and gas was higher
during 2003 and somewhat higher than in
2002. Nordic electricity prices were
high during 2003 as a result of unusually
low precipitation during autumn 2002
resulting in low reservoir levels. The
situation improved in Norway and Sweden
during 2003, but reservoir levels were
around 20 percent lower than normal at the
end of the year. Average spot prices for
2003 were NOK 0.29 per kWh, compared to NOK
0.20 per kWh in the prior year. Operating Revenues Energy and Oil Marketings operating
revenues for 2003 were NOK 49,370 million,
up NOK 3,455 million or 8 percent from the prior
year. Power production in 2003 was 7.5 TWh
compared with 10.3 TWh in 2002, a reduction
of 27 percent and below normal production
from the hydroelectric power plants. The
decrease in production from Hydros
hydroelectric power plants was expected due
to low reservoir levels at the beginning of
the year. In 2003, internal sales to other
business areas within Hydro amounted to NOK
5,062 million, including internal sales to
Hydro Agri and Hydro Aluminium Metals
sub-segment of NOK 1,596 million and NOK
1,776 million, respectively. Internal sales
in 2002 were NOK 3,986 million. Operating costs Energy and Oil Marketings operating
costs of NOK 46,702 million in 2003 were 8
percent higher than the prior year. As
described above, Energy and Oil Marketings
operating costs are mainly comprised of
purchases of crude oil, natural gas and
electricity. Operating costs also include
process costs relating to the operations of
power stations, gas infrastructure and other
fixed costs. There were no substantial
changes in these costs in 2003 compared to
the previous year. Operating income Energy and Oil Marketings operating income
in 2003 was NOK 2,668 million, a decrease of
4 percent compared to the prior year. The main
change in 2003 was a decrease in operating
income from power sourcing and
marketing activities which to a large extent
was offset by an increase in the operating
income from the gas activities. Operating income from power sourcing and
marketing activities was NOK 664 million in
2003, down NOK 521 million or 44 percent from
the prior year. The decrease in operating income
resulted primarily from lower production,
which was partly offset by higher average
spot prices. In addition, unrealized gains
relating to power purchase contracts
increased the results for 2002 by NOK 220
million. Energy and Oil Marketing secures
electricity in the market for Hydros own
consumption, for delivery to external parties
and to reduce the risk of price fluctuations
on its electricity portfolio. In 2002 Hydro
purchased electricity contracts in the
derivative market for deliveries in 2003 to
compensate for the low reservoir levels and
expected shortfalls in production. Spot and
forward electricity prices fell in the early
part of 2003 compared to an exceptionally
high level at the end of 2002. As a result, a
portion of the net unrealized gains relating
to these contracts that were included in the
results of 2002 were reversed in 2003 as
expected. 91




---



##### 



Operating income from oil trading and
refining activities was NOK 406 million in
2003, an increase of 5 percent from the
prior year. These activities include crude
oil trading, gas liquids trading, refining
activities and shipping. Strong refining
margins and good trading results in the
markets for gas liquids and crude oil were
offset by inventory losses related to
refining activity. Average refining margins
for 2003 were US dollar 4.4 per barrel,
compared to US dollar 2.2 per barrel in
2002. Operating income in 2003 included an
inventory loss of NOK 82 million compared to
an inventory gain of NOK 64 million in 2002. Operating income from gas activities was
NOK 1,795 million in 2003, up NOK 540 million
from the prior year (43 percent). Around NOK
190 million of the improved operating income
came from gas sourcing and marketing
activities, while the remaining improvement
related to gas infrastructure activities. The
improved results from gas infrastructure
activities were mainly due to higher tariff
revenues, and lower depreciation charges
resulting from the extension of license
periods for a number of gas pipelines
following the establishment of Gassled in
January 2003. Oil
Marketing incurred an operating
loss of NOK 16 million compared to operating
income of NOK 68 million in 2002. The
decline reflects lower margins and higher
inventory losses. EBITDA EBITDA for 2003 was NOK 4,226 million, an
increase of 14 percent compared to the prior
year. Hydros share of net income from Hydro
Texaco included in EBITDA was NOK 117
million in 2003, the same level as in the prior
year. In 2003, Hydro sold its interest in
Sundfjord Kraft ANS for 20.2 percent of the
shares of SKS Produksjon AS resulting in a
gain of NOK 326 million reflected in the
results. The sale of Hydros 25 percent ownership
interest in the Scanraff oil refinery in
Sweden resulted in a gain of NOK 490 million
reflected in the results for the year. Outlook Hydro power reservoir levels were below
average at year-end 2003 for Hydro-owned
power stations and for the Nordic market
area in general. As a result, the Companys hydro
power generation in 2004 is expected to be
approximately 12 percent below the normal
levels. The present reservoir deficit in the
Nordic market area results in an expected
price level above historic average. However,
this estimate is uncertain and depends on
precipitation levels during the next few
months. Spot and forward prices for 2004 are
below the 2003 levels at present, however,
the tighter Nordic power balance has
increased dependence on electricity imports
and energy from other sources. Lack of new
capacity to cover expected annual demand
growth of more than 1 percent is expected
to result in a tighter capacity balance in
the coming years. Prices in the Nordic
Region will be influenced by electricity
prices within the European continental
market that are high mainly due to record
high coal prices. Prices could increase
further in 2004 due to restrictions on
greenhouse gas emissions in the European
Union. The European continental gas market
continues to be dominated by long-term
contracts indexed to oil products. The
ongoing liberalization process of the
European gas market is expected to lead to a
more liquid and short-term gas market on the
continent similar to what has existed in the
UK for some time. New gas trading hubs are
emerging, in particular at Zeebrügge in
Belgium, in the Netherlands and at
Emden/Bunde at the German/Dutch border.
Hydro expects to be able to exploit business
opportunities resulting from these
developments. In 2003, Hydro strengthened
its position in the continental gas market
through the acquisition of Duke Energys
marketing activities in the Netherlands
(Duke Energy Europe Northwest B.V). Hydro
also established a joint venture,
HydroWingas Ltd, with German gas supplier
Wingas GmbH. HydroWingas will market gas in
the UK, focusing on wholesalers and large
end-users. In 2003, Hydro also signed an
agreement with A.P. Møller-Maersk A/S, a
Danish company, for the purchase of 0.6
billion cubic meters of gas per year during
the period 2005 to 2009 for delivery in the
Netherlands. Hydro believes that the
long-term fundamental conditions underlying
natural gas demand in Europe are strong in
part because natural gas continues to be the
preferred choice for new supplies due to
environmental benefits, competitive pricing
and convenience of use. Hydro will continue
to focus on profitable growth of its gas
portfolio both upstream and downstream to
capture the opportunities created by a more
flexible and liquid European gas market. Following the Scanraff sale in December
2003, Hydro no longer holds an interest in
the refining business. Operating income
relating to this activity was approximately
NOK 200 million in 2003. 92




---



##### 



Hydro Aluminium Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    69,152
    
    
    
    65,051
    
    
    
    51,083Operating Income
    
    
    2,456
    
    
    
    1,698
    
    
    
    185EBITDA
    
    
    6,498
    
    
    
    4,334
    
    
    
    2,543Gross Investment
    
    
    70,357
    
    
    
    63,833
    
    
    
    42,819CROGI
    
    
    8.6%
    
    
    
    7.1%
    
    
    
    5.7%Number of employees
    
    
    26,728
    
    
    
    27,110
    
    
    
    16,244
 The Aluminium business area is comprised of
the sub-segments Metals (Primary Metals and
Metal Products), Rolled Products, Extrusion
and Automotive (including the North America
activities). Summary of key developments in 2003 Aluminiums major strategic drive in the
last few years has been to improve
competitiveness by generating greater
economies of scale (through acquisitions and
expansions) and reducing costs. 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. Improvement programs were initiated in
2001 and 2002 to improve operating results,
including reductions of annual costs, by NOK
2.5 billion compared to the combined cost
level of VAW and Hydro Aluminium businesses
in 2001. The target was achieved at end of
the fourth quarter of 2003. This means the
full year effect for 2004 will be in line
with the target of NOK 2.5 billion. The
accumulated cost of the program was NOK
1,166 million (NOK 176 million for 2003)
which was NOK 397 million below the original
cost estimate. Since 2002, other improvement programs
have been instituted. For example, Rolled
Products established in 2003 an improvement
program for the Holmestrand, Norway plant to
reduce annual fixed costs by approximately
NOK 80 million. The program includes manning
reductions of 80 persons, representing
approximately 16 percent of the total work
force by the end of 2004. About 80 percent
of the reductions were completed at the end
of 2003. Emission standards established by the Norwegian Pollution Authority require production facilities using Søderberg technology in the Høyanger and Årdal primary aluminium plants to be closed or replaced by 2006. After an extensive assessment, Hydro determined that investments to replace this capacity will not be made.
The resulting closures will reduce the Companys annual primary aluminium production capacity by 72,000 tonnes. The affected parts of the facilities will be fully depreciated as of the closure date. A project to evaluate the impact of the closures on manning, restructuring and other sustainability issues relating to the locations was established. This work was expanded to look at the overall competitive position of Hydro Aluminiums European smelters and concluded upon subsequent to year end. For additional information see Outlook below. Investments:  Hydro Aluminiums brownfield expansion projects are all progressing according to plan and within budget. The expansion of the 50 percent-owned Søral primary aluminium plant was brought to full capacity in the first quarter of 2003. The expansion project for the aluminium plant in Sunndal, Norway, has completed the start up the first two sections of the new capacity and
will phase in the remainder, with completion expected in the autumn of 2004. As a result of the Sunndal and Søral expansions Hydros annual primary aluminium production will increase by approximately 190,000 tonnes per year in 2005 when both plants are at full production compared with 2001. The first expansion of Alunorte, a low
cost alumina refinery located in Brazil, was
completed in early April 2003. An important
strategic step for Hydro Aluminium in 2003
was the decision to participate in the
second expansion of Alunorte. The expansion
will provide Hydro with an additional
610,000 tonnes of alumina annually beginning
from the second quarter of 2006. The
expansion will increase Hydro Aluminiums
raw material supply secured by equity
investments. An investment in a greenfield plant for
Automotive precision tubing products was
approved. The plant will be built in the
strategically important market of China with
a start up in 2005. Total investment is
estimated to be NOK 150 million. Divestment: Aluminium disposed of its
interest in the aluminium recycling plant,
VAW-IMCO in Germany. The disposal had no
material income statement effect. Hydro has also entered into an agreement to sell its German based
alumina business including Aluminium Oxid Stade GmbH an alumina refinery
located in Stade, near Hamburg in Northern Germany. About half of
Hydros
share of alumina from this facility is chemical grade alumina used in a
variety of applications in the chemical and other industries, which are
non-core to Hydros aluminium activities. The transaction will not result
in any significant gain or loss for Hydro. Contracts: Hydro Aluminiums alumina balance
was strengthened with
a long-term supply contract with Comalco
Aluminium Limited, a wholly owned subsidiary
of Rio Tinto, entered into in 2003. Starting
in 2005, Comalco will supply 300,000 tonnes
of alumina annually to Hydros Australian
smelter operations. This increases to
500,000 tonnes annually from 2006 to 2030.
The contract improves Hydro Aluminiums
competitive position by securing the
long-term availability of alumina in line
with industrial long-term market prices. A new long-term agreement with Talum in
Slovenia will supply Hydro Aluminium with
70,000 tonnes of foundry alloy products per
year starting in 2004 through 2010. The
agreement enhances Hydro Aluminiums metal
supplier concept built on a combination of
equity primary aluminium production,
recycling and remelt facilities and third
party supply contracts. Aluminiums
Automotive segment
strengthened its position by concluding
important sales contracts. Beginning in
2006, rear
bumper components will be delivered for the
Citroen Picasso with 93




---



##### 



an expected volume of
300,000 parts annually. In addition, Hydro
will deliver an estimated volume of 1.2
million parts per year related to the front
and rear bumper beams, including crash boxes
on the rear bumper, for Audis redesigned A4
model starting in 2004. Technal, one of Extrusions three
primary building systems brands, has been
selected as the supplier of aluminium
building solutions for several new sports
stadiums in Portugal. Portugal is hosting
the 2004 European Football Championship and
is in process of building a number of
state-of-the-art football stadiums for the
event. The change in operating income for 2003
compared to the prior year and the most
important items affecting the change are
included in the table below: Amounts in NOK millionOperating income 2003
    
    
    2,456Operating income 2002
    
    
    1,698Change in Operating Income
    
    
    758Margin
    
    
    (560
    )Hedging
    
    
    325Volume
    
    
    860Fixed costs
    
    
    (345
    )Depreciation
    
    
    (515
    )Infrequent items and restructuring costs
    
    
    615Trading
    
    
    460Unrealized LME-effects
    
    
    (310
    )New / disposed business
    
    
    285Other
    
    
    (57
    )Total change
in Operating Income
    
    
    758
 Variance Analysis Aluminiums operating income for 2003 was
NOK 2,456 million compared to NOK 1,698
million in the prior year. The higher result
was due to the inclusion of VAW and Technal
(new business) for the entire first quarter
of 2003 and lower infrequent items compared
to 2002. Excluding the variance for new
business for the first quarter and
infrequent items, operating income declined
approximately NOK 143 million. The largest
single variable explaining the decrease was
lower aluminium prices measured in Norwegian
kroner. This was marginally offset by
translation effects on operating income of
the strengthening of subsidiary currencies
(mainly EUR) to Norwegian kroner. Margins, excluding the effect of hedge
programs, were lower and
negatively impacted results by
approximately NOK 560 million compared with
2002. Margins improved for Rolled Products
and Extrusion but were weaker for Metals and
Automotive. During 2003, aluminium prices
measured in Norwegian kroner fell by seven
percent compared with 2002 as a result of a
lower average USD to NOK exchange rate. As a
result, margins were substantially weaker in
Metals compared to 2002 reducing results by
approximately NOK 760 million. Realized
effects of hedge programs in Metals positively impacted the results by
NOK 323 million compared to 2002. Higher volumes contributed an
additional NOK 860 million to operating
income compared to 2002. With the exception
of North American activities, volumes
increased for all sub-segments. The ramp up
of new capacity in Metals, Automotive and,
to a lesser extent, in Rolled Products was
the fundamental reason for the improvement. During 2003, new production capacity
was also the major reason for higher fixed
cost and depreciation that more than offset
the savings from improvement programs. Fixed
costs measured in NOK for European
subsidiaries were negatively impacted by a
stronger EUR to NOK. However, for operating
income as a whole this currency translation
effect was positive. Metals realized results of trading
activities were higher mainly due to
currency gains on EUR denominated revenues
measured in NOK. This was largely offset by
lower unrealized results from the mark to
market adjustments on Aluminiums LME
derivative portfolio compared with 2002. In
order to better understand Hydro Aluminiums underlying performance, operating income has been adjusted for certain items referred to as infrequent items (see discussion under Non-recurring or infrequent items included in the Financial Review). Net infrequent charges1) (including
restructuring) impacting operating income
for 2003 were NOK 94 million compared with
NOK 708 million for 20022). EBITDA for 2003 was NOK 2,164 million
higher in the year
largely due to the inclusion of VAW for the
entire period of 2003 and due to lower
infrequent and restructuring items. Results
from non-consolidated investees included
unrealized currency gains on USD-denominated
loans held by a Brazilian company, Alunorte,
of NOK 218 million for 2003 compared to a
loss of NOK 461 million for 2002. Excluding
the new business, the currency effects on
Alunorte and infrequent items, EBITDA
increased NOK 288 million reflecting higher
pre-tax cash flows from new capacity and
higher trading results.  1)
    
    The major infrequent items for 2003 were NOK 140 million (USD 20 million)
related to the loan loss provision on a subordinated loan provided to
Goldendale Aluminium Inc., demanning and rationalization costs of
approximately NOK 90 million, the reversal of an environmental accrual of
NOK 59 million and the reversal of an accrual on a litigation settlement
of NOK 77 million. Infrequent charges split by segment for 2003 were:
Metals a gain of NOK 19 million; Rolled Products a charge of NOK 71
million; and Extrusion and Automotive a charge of NOK 42 million.2)
    
    Infrequent charges (including restructuring) for 2002 mainly relate to
manning reductions in connection with the improvement programs, VAW
integration cost and higher cost of goods sold from VAW inventories due to
the fair value adjustment as of the acquisition date. Metals downwardly
revised restructuring accruals related to Magnesium by NOK by 10 million.
Infrequent charges split by segment for 2002 were: Metals NOK 348 million;
Rolled Products NOK 223 million and Extrusion and Automotive NOK 137
million. 94




---



##### 



Outlook Economic indicators are increasingly positive for 2004, however, they continued to lead physical indicators (such as increased order and shipment levels) early in 2004. European market sentiment is positive but to a lesser degree than US indicators. The outlook for Asia remains strong. Hydros management expects that
Western World shipments of primary aluminium will increase about five percent, equivalent to an estimated 1,000,000 tonnes in 2004 compared to 2003. Western World production, net of announced closures, is expected to increase by 500,000 tonnes in 2004. This is expected to improve the market balance. In the beginning of 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. In addition, electricity prices in the North Western US also remain relatively high. Due to both of these factors, the likelihood of significant restarts in closed production in the North Western US is reduced. Furthermore, if alumina spot prices remain at levels similar to those in early 2004, this may reduce incentives for starting up additional new capacity in China. China is dependent upon imports of this raw material.
 In addition, Chinese authorities announced a reduction of available credit for industrial development in China during the first quarter of 2004. According to CRU International Ltd.
(CRU), consumption of flat rolled products,
extruded and automotive products is
expected to grow compared to 2003. Growth
projections for 2004 vary both by product
and market, but range between 2 to 3.5
percent for North America and Western
Europe. Hydro obtains most of its alumina from companies in which it has an equity investment and through long-term contracts, usually based upon an LME price formula. Kaiser Aluminum filed motions at the end of January, 2004 in a US bankruptcy court seeking to reject or nullify certain alumina supply agreements. Neither Hydro nor any of its subsidiaries were named in this process.
 However, one of Hydros Australian subsidiaries has an alumina supply agreement with Kaiser through 2005.
 Should Kaiser fail to deliver under contract terms, the alumina costs for the subsidiary could increase.
 In recent rulings by the US bankruptcy court, Kaiser has failed to obtain authorization for the rejection of certain alumina supply agreements. Accordingly, the risk of non-performance for Hydros agreement is perceived as limited.
 In order to retain and improve its competitive position, Hydros strategy has been to improve the
 relative cost position of its smelter system through continuous improvements and reduced cost within its existing capacity and expanding capacity at low cost smelters. Hydros Norwegian smelters face challenges in reaching acceptable cost levels. Approximately 30 percent of production cost relates 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 May 7, 2004, the 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 will require a reduction of manning by about 800 employees in the Norwegian plants. The total estimated cost of the program, including manning reductions, is expected to be approximately NOK 800 million. The reduction in manning is expected to be completed by the end of the first quarter of 2005. Due to low volume and declining profitability at the Casting plant in
Leeds, UK, Aluminiums automotive sector entered into a consultation period
starting September 18 with employees to evaluate a potential closure of the
plant. The consultation period ended in December with a conclusion that the
future of the plant was unlikely to be secured. A final decision was made
June 2004 to close the plant in late 2004 or early 2005 with resulting
closure costs of about NOK 265 million (GBP 22 million). This is net of
expected proceeds from the sale of property and equipment. In addition, the plant is
expected to show a negative EBITDA for 2004 of approximately NOK 44 million
(GBP 3.6 million). Most of the  plant staff of around 580 people will leave
during the second half of 2004. Production of turbo cylinder heads for GM will be relocated to
Hydros
plant in Gyør, Hungary. Metals Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    39,923
    
    
    
    39,646
    
    
    
    31,475Operating Income
    
    
    2,293
    
    
    
    1,690
    
    
    
    372EBITDA
    
    
    4,298
    
    
    
    2,703
    
    
    
    1,766Gross Investment
    
    
    38,896
    
    
    
    34,905
    
    
    
    26,330CROGI
    
    
    9.8%
    
    
    
    7.1%
    
    
    
    6.0%Number of employees
    
    
    6,276
    
    
    
    6,284
    
    
    
    4,561
 Market conditions Western World shipments of primary metal
grew an estimated 4.6 percent for 2003
compared to the same period of the prior year. This
was an increase from 2.6 percent in 2002
versus 2001 when industrial activity was at
a low level. For 2003, most of the shipment
growth is believed to have been attributable to
strong demand in Asia while growth in
Western Europe and North America were modest
for the year. Chinas internal consumption
continued to grow rapidly in 2003. However,
new Chinese capacity coming on stream
outpaced internal consumption. China
increased its net primary exports to the
Western World by an estimated 100,000 tonnes
in 2003 to a total of about 350,000 tonnes.
China continued to have net imports of
scrap, aluminium semi-finished products
(mainly rolled and extruded products) and
finished products of approximately 600,000
tonnes in 2003. Western World Production increased
approximately 3.0 percent (520,000 tonnes)
due to new capacity net of closures. In
2003, Alcoa reported the closure of 95,000
tonnes of production in its West Ferndale
smelter in the US. Reported inventories at the end of the
year were about three percent (100,000
tonnes) higher than at the end of 2002.
There is uncertainty in the trends for
unreported inventories, however, indica- 95




---



##### 



tions
are that they increased more than reported
inventories. The average market price for
aluminium (LME 3 monthly average) was USD
1,428 per tonne for 2003, which was USD 63
per tonne higher compared with 2002. Revenues Metals revenues were positively impacted by
the consolidation of VAW for the full first
quarter of 2003 compared with 15 days in the
first quarter of 2002. Volumes for Hydro
Aluminiums primary metal increased 18
percent to a total of 1,473,000 tonnes in
2003 compared to the same period of 2002.
This reflected both the inclusion of VAW for
the entire first quarter of 2003 as well as
new capacity from Sunndal. Excluding the variance for VAW for
the first quarter, operating revenues
declined approximately 10 percent or NOK 4
billion. Lower realized prices measured in Norwegian
kroner more than offset higher volumes from
the Sunndal expansion. Hydro realized an aluminium price of
USD 1,440 per tonne for 2003 compared to
USD 1,372 per tonne for the same period of
2002. Measured in Norwegian kroner,
however, the realized aluminium price
declined by over seven percent. The
realized NOK/USD exchange rate was NOK 7.25
for 2003 (NOK 8.21 in 2002). The realized
price includes the effect of hedges. Realized effects of hedge programs3),
which are comprised of LME future
contracts and US dollar forward contracts, positively impacted the results by
about NOK 476 million in 2003 (NOK 153
million in 2002) of which about NOK 240
million related to Sunndal in 2003. LME
future contracts relating to the Sunndal
program are spread evenly over the quarters
while the amount of US dollar forward
contracts vary by quarter. Product premiums (particularly for
extrusion ingot) were noticeably higher in
USD but less pronounced stated in Norwegian
kroner. Operating costs Excluding the VAW variance for the first
quarter, raw material and energy cost
(variable costs) declined in spite of higher
volumes from new capacity mainly due to the
effect of reduced alumina cost (measured in
NOK) and a one-off positive adjustment to
tolling fees for raw materials of NOK 34
million. Fixed cost4) and
depreciation rose compared to 2002
reflecting the new capacity. Depreciation
also included a write down of assets of NOK
20 million. Operating income Operating income for 2003 amounted to NOK
2,293 million compared to NOK 1,690 million
in the prior year. Excluding VAW activities
for the first quarter, restructuring and
infrequent items, operating income weakened
NOK 69 million. Changes in product prices
and currency rates resulted in a reduction
in margins of about NOK 760 million compared
with 2002. However, this was mitigated by
positive effects from certain hedge programs
(NOK 323 million) and improved trading
results (NOK 460 million). Trading results
improved mainly due to currency gains.
Improvement resulting from higher sales
volumes was offset by higher fixed cost and
depreciation. EBITDA EBITDA for 2003 was NOK 4,298 million.
Excluding VAW activities for the first
quarter, infrequent items and currency
effects for Alunorte, EBITDA was NOK 139
million higher than the corresponding period
of 2002. Improved volumes, results of hedging
programs and trading more than offset the
fall in margins and higher fixed cost.  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. Sunndal accounts for the largest
part of the hedge program. 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 do not qualify 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.4)
    
    Fixed cost excludes variable production inputs (such as raw materials & energy), depreciation and miscellaneous gains & losses on disposals of assets. 96




---



##### 



Rolled Products Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    18,377
    
    
    
    14,790
    
    
    
    4,228Operating Income
    
    
    132
    
    
    
    (295
    )
    
    
    58EBITDA
    
    
    835
    
    
    
    258
    
    
    
    162Gross Investment
    
    
    12,645
    
    
    
    11,937
    
    
    
    2,626CROGI
    
    
    6.4%
    
    
    
    3.5%
    
    
    
    5.8%Number of employees
    
    
    4,259
    
    
    
    4,306
    
    
    
    766
 Market conditions Difficult market conditions continued in
Europe in 2003. According to CRU, consumption of
flat rolled products in Europe was almost
unchanged compared to 2002. Average capacity
utilization for the European industry
improved marginally but remained relatively
low at about 83 percent. The North American market had an
increase in consumption of about one percent
for the year as a whole compared to 2002.
Capacity utilization for the US industry
improved about two percent to approximately
74 percent. The stronger EURO compared to
USD was a disadvantage to producers outside
the US for export sales. The EUR/USD
exchange rate impacts export pricing of flat
rolled products in Asia, South and North
America which are typically based on a USD
formula and put pressure on margins. Litho and foil are higher margin
products. Automotive flat rolled products,
especially body-in white parts, 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 Rolled Products revenues included
consolidation of VAW for an additional 21/2months in 2003 compared with 2002.
External shipments5), on a
proforma basis including comparable VAW
figures for the full year of 2002, increased
around seven percent to 893,000 tonnes.
Higher volumes were in part due to the ramp
up of new capacity. The total growth in
shipments for 2003 over 2002 was distributed
between Hydros product groups as follows:
Litho (2 percent), Foil (1 percent),
Automotive (1 percent) and Strip (3
percent). Operating revenues, excluding the VAW
variance for the first quarter, increased
approximately three percent or about NOK 450
million. This was mainly due to a volume
increase of around five percent that was
partially offset by the impact of lower EUR
revenues for USD denominated export sales.
Rolled Products exports about 19
percent of its sales to Asia, South and
North America. The EUR strengthened 20
percent to the USD in 2003. Rolled
Products major activities are
denominated in EUR and all sales revenues
are price hedged in terms of aluminium
prices and
foreign currency using commodity and
financial instruments. Realized gains
related to aluminium price hedges are
included in revenues while currency effects
are included in financial items. Operating costs Excluding the VAW variance for the first
quarter and infrequent items, Rolled
Products variable cost, fixed cost and
depreciation increased in 2003 primarily as a
result of increased volumes. Rolled Products cost structure varies
with changes in the aluminium price and its
product mix. On average, the metal price
comprised about 60 percent of total cost
while other materials and energy account for
about 20 percent of the total. Higher
variable costs due to increased sales
volumes were largely offset by lower
aluminium prices stated in EUR and lower
losses on inventory. Rolled Products sales prices are based
on a margin over the metal price. The production
process requires a long lead time of between
two to three months. Therefore, cost of
goods sold (and margins) are impacted by
variances in inventory values resulting from
changing aluminium prices. Falling prices in
EUR increase cost (reduce margins) while
increasing prices have the opposite effect.
In 2003, the loss on inventory was
approximately NOK 120 million compared with
approximately NOK 200 million in 2002. Fixed cost and depreciation rose
compared to 2002 reflecting the new
capacity (automotive line in Germany) and
investment in Malaysia) which more than
offset savings from improvement programs
and the reversal of an accrual for a
resolved claim of NOK 52 million. Operating income Operating income for 2003 was NOK 132
million compared to a loss of NOK 295
million in the previous year.
Approximately NOK 10 million of the increase
in operating income resulted from the
inclusion of the activities of the former VAW,
which were not consolidated for the entire
year of 2002. Excluding infrequent items,
operating income was NOK 203 million, an
improvement of NOK 275 million. Improved
margins positively impacted results by
approximately NOK 240 million compared with
2002. Increased shipments contributed around
NOK 195 million to results but this was
largely offset by increased fixed cost and
depreciation. EBITDA EBITDA for Rolled Products for 2003 was NOK
835 million compared to NOK 258 million for
2002. Excluding infrequent items, EBITDA
was NOK 906 million (NOK 481 million in
2002), an improvement of NOK 425 million.
Approximately NOK 112 million of this
improvement resulted from the inclusion of
the activities of the former VAW, which were
not consolidated for the entire period of
2002. The remainder of the improvement was
principally due to higher margins and
shipments.  5)
    
    Excludes wire rod shipments. 97




---



##### 



Extrusion and Automotive Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    24,529
    
    
    
    24,245
    
    
    
    22,487Operating Income
    
    
    98
    
    
    
    14
    
    
    
    (228
    )EBITDA
    
    
    1,432
    
    
    
    1,084
    
    
    
    632Gross Investment
    
    
    18,737
    
    
    
    16,846
    
    
    
    14,011CROGI
    
    
    7.9%
    
    
    
    7.0%
    
    
    
    4.5%Number of employees
    
    
    16,193
    
    
    
    16,520
    
    
    
    10,917
 Market conditions The overall market for general extrusion in
Europe showed improvement towards the end
of 2003 but apparent consumption was a
modest increase of one percent for 2003 as
a whole (CRU). The building and
construction market in Germany remained
difficult resulting in pressure on volumes.
For extruded products in North America, CRU
reported a reduction in apparent
consumption in 2003 of about one percent.
Global light vehicle sales were reported to
be approximately 0.5 percent higher than in
2002. However, Western European and North
American automotive markets, which are the
most relevant to Hydro, lagged behind the
global averages with a reduction
in light vehicle sales of two and one half
percent, respectively. Revenues Operating revenues included the
consolidation of VAW and Technal for the
full year of 2003 compared with the period
after the acquisition dates in the first
quarter of 2002. Excluding the variance in the first
quarter from VAW and Technal (new business),
revenues declined about three percent (NOK
700 million). This was due in part to
negative translation effects. North American
revenues fell in NOK as a result of the 12
percent lower NOK / USD exchange rate in
2003 compared to 2002. This was largely
offset by the opposite translation effect on
revenues of a stronger EUR to NOK for
European subsidiaries. Automotive revenues
and sales volumes increased compared to
2002, principally due to the ramp up of
shipments on new contracts. Higher volumes
offset the lower revenues from price
pressure on heat transfer and crash
management components, although margins were
negatively affected. Extrusions revenues
were somewhat lower. Although European
extrusion shipments were somewhat higher,
shipments declined for Hydros Building
systems operations due to low demand in the
European construction industry. In North
America, revenues fell as shipment volumes
declined from own production (lower demand)
and third party trading (which was largely
discontinued) in 2003 compared to the same
period last year. Operating costs Excluding new business and infrequent items,
variable costs declined while fixed cost and
depreciation increased. In total, cost
development in 2003 benefited from movement
in currencies in translation (the opposite
effect as variance for revenues) compared
with 2002. Variable costs increased for
Automotive, driven by higher volumes, but
declined for Extrusion and North America.
Fixed costs increased in 2003 due to higher
activity in Automotive and net translation effects that were partially offset
by cost reduction from improvement programs
in North America. Depreciation expense
increased due to start up of new automotive
production lines and North American remelt
operations and write downs of NOK 79
million relating to Automotive fixed assets. Operating income Operating income for 2003 was NOK 98 million
compared to NOK 14 million in the prior
year. Excluding the variance relating to VAW
and Technal, for the first quarter of 2003
and infrequent items, operating income was
NOK 148 million (NOK 151 million). Slightly
higher margins and improved volumes
contributed positively to results. This
positive effect was offset by the higher
fixed costs and depreciation expense.
Operating income benefited somewhat from
translation effects compared with 2002. Operating income for Extrusion improved
in a difficult market. North American
operations have made substantial
improvements in press productivity (11%
improvement compared to the previous year
from the transfer of best practices from the
European extrusion system), on time delivery
and cost control measures which have
compensated for the decline in results in 2003
from lower demand. Despite a substantial
contribution to operating income from new
volumes, Automotives operating income
declined in 2003 as a result of weaker
margins, higher
fixed cost and increased depreciation.
Programs are on-going to reduce costs and
improve or exit under-performing units (also
see Outlook). EBITDA EBITDA for Extrusion and Automotive for 2003
was NOK 1,432 million compared to NOK 1,084
million for 2002. Excluding new business in
the first quarter and infrequent items,
EBITDA was NOK 1,390 million an improvement
of NOK 191 million. Higher volumes and
margins more than offset the impact of
higher fixed cost. Extrusion activities and
higher cash flows from Automotives new
capacity were the main contributors. 98




---



##### 



Hydro Agri Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Operating Revenues
    
    
    38,174
    
    
    
    33,348
    
    
    
    37,407Operating Income
    
    
    2,800
    
    
    
    2,207
    
    
    
    2,114EBITDA
    
    
    4,748
    
    
    
    3,945
    
    
    
    4,402Gross Investment
    
    
    35,049
    
    
    
    30,739
    
    
    
    36,513CROGI
    
    
    11.7%
    
    
    
    9.4%
    
    
    
    9.6%Number of employees
    
    
    7,338
    
    
    
    7,371
    
    
    
    7,841
 Summary of Key Developments Agris operating income increased by
approximately 27 percent from 2002 to 2003.
Operating results were positively influenced
by substantial price increases on most
fertilizers products and ammonia. The
effects of higher prices more than
compensated for negative effects relating to
currency developments and high energy costs.
Both urea and ammonia prices increased,
reflecting an improved global market
balance. European fertilizer prices for all
major nitrogen products were strongly
influenced by a high international urea
price. In 2003, sales volumes were relatively
unchanged compared to the prior year,
despite the termination of the
Farmland/Hydro marketing agreement in
conjunction with the sale of Agris
interest in Farmland/Hydro. Sales volume in
Europe increased by 4 percent, while
volumes outside Europe improved slightly
excluding the effects of the divestment of
Farmland/Hydro. The industrial gas and chemicals
operations experienced volume growth in all
core segments in 2003. Strongest
improvements were achieved within technical
nitrates and nitrogen chemicals. As a result
of record high ammonia prices margins were
put under pressure and the operating result
decreased. Much of Agris business is denominated
in or heavily influenced by the USD. As a
result, currency changes have a direct
impact on revenues and costs. The pricing of
the majority of Agris products (including
its European operations) is directly linked
to the USD. Fixed costs in Europe are, to a
large extent, linked to NOK and the EUR.
Excluding cost saving and efficiency
programs, this implies that an appreciation
of the European currencies against the USD
could reduce the competitiveness of the
European fertilizer business. The analyses of variances between 2003 and 2002
discussed below, include certain assumptions with regard to currencies, prices, volumes, gas costs and
other factors, primarily to isolate effects of currency movements, and thereby, contribute to better understanding of the development in the business. These assumptions are actively used by management to follow up the business. Amounts in NOK millionOperating income 2003
    
    
    2,800Operating income 2002
    
    
    2,207Change in Operating Income
    
    
    593Margin
    
    
    645Volume
    
    
    150Fixed costs
    
    
    (190
    )Depreciation
    
    
    40Other
    
    
    (52
    )Total change in Operating income
    
    
    593Variance affecting EBITDA
    
    
    210Change in EBITDA
    
    
    803Currency effect1)
    
    
    850Total change in EBITDA calculated with stable currency rates
    
    
    1,653Volume
    
    
    150Prices/ Margins including effects on share of net
income of non-consolidated investees2)
    
    
    2,600Price effect from natural long position3)
    
    
    300Energy cost
    
    
    (1,200
    )Pension cost
    
    
    (100
    )Interest income and other financial items
    
    
    (50
    )Other
    
    
    (47
    )Total change in EBITDA calculated with stable currency rates
    
    
    1,653
 The strengthening of European currencies
against the US dollar affected operating
income negatively for 2003 by
approximately NOK 750 million and EBITDA
by approximately NOK 850 million compared
to the prior year. Increased nitrogen prices in US
dollars improved operating income by
approximately NOK 2600 million and EBITDA
by approximately NOK 2,900 million. Part of
the positive price effect on EBITDA and
operating income, estimated at NOK 300
million, resulted from Agris natural long
position (own produced products) in a
rising market. Price gains were partially offset by
the negative effects of increased raw
materials and energy costs of approximately
NOK 1,200 million and predominantly related
to operations in Europe. Higher oil prices
during the first several months of 2003
resulted in an increase of approximately 40
percent in the cost of ammonia production
for 2003 compared to the previous year.
Other raw material costs were stable.  1)
    
    Currency effects on all line items in
the table have been isolated by
applying constant exchange rates (i.e. 2003 exchange rates) on 2002 financial
figures2)
    
    Includes the net effect of price
fluctuations on non-consolidated
investees where the variable cost is
directly linked to the price
development for urea and ammonia3)
    
    Increased margins from long
positions and timing of trade related
to the natural long position in a
rising market 99




---



##### 



Market conditions Both urea and ammonia prices increased,
reflecting an improved global market
balance. The urea price increase was
supported by increasing global consumption,
continued production capacity cutbacks in
the United States because of high natural
gas prices, and production stoppages caused
by production problems in Indonesia,
Algeria, Venezuela and Alaska. The
increasing nitrogen fertilizer price trend
also affected European nitrate prices, which
continued to rise through the second half of
2003. The closure of manufacturing capacity
in Europe in 2000 and 2001, together with
European producers further capacity
reductions in 2002, contributed positively to the
supply/demand balance in key European
markets in 2003, resulting in improved
prices for key products in these markets. In 2003, the average price for ammonia
was USD 203 per tonne (fob Caribbean), up
approximately 85 percent compared to 2002.
Ammonia prices reached an average fourth
quarter price of USD 240 (fob Caribbean) an
historically high level, for many of the
same reasons as the urea price increase
discussed above. Total nitrogen deliveries from
industry and importers in West Europe were
up approximately 7 percent from 2002 to
2003. The annual increase in volumes for
2003 compared to 2002 should be viewed in
connection with low sales in the second
half of 2002, when some sales were delayed
into 2003. In addition, due to the strong
increase in prices at the end of 2003, many
customers made their purchases early in
2003/2004 season. West European fertilizer imports
increased as a result of the increased relative
attractiveness of the West European market.
The import market share in West Europe
reached a level of approximately 26 percent
close to the situation two years ago. Revenues Operating revenues increased by 14 percent
from 2002 to 2003, primarily as a result of
increased prices for most fertilizer
products and also as a result of increased
ammonia trading. An analysis of the operating revenues
for each of the principal geographical areas
and other key business units in Agri is
presented in the table below: Amounts in NOK million
    
    2003
    
    
    2002Fertilizer activitiesEurope
    
    
    13,654
    
    
    
    12,179Outside Europe
    
    
    14,843
    
    
    
    14,165Ammonia Trade and Shipping
    
    
    5,240
    
    
    
    2,926Industrial Gas and Chemicals
    
    
    4,437
    
    
    
    4,078Total
    
    
    38,174
    
    
    
    33,348
 Fertilizer Europe Total nitrogen deliveries in West Europe
were up approximately 6 percent for the full
year. There were positive sales volume
developments for Agri in the UK and Ireland,
helped by the closure of the IFI fertilizer
plant in Ireland (autumn 2002). Fertilizer outside Europe Outside Europe, Agris sales volume
increased slightly for the year as a whole
excluding the effect of the Farmland/Hydro
divestment in 2002. During 2003, Brazil
became, for the first time, Agris largest
country in terms of revenues and fertilizer
sales volume with sales of more than 2
million tonnes. Agris ability to import
products into the US market improved as a
result of increased gas costs for the
domestic industry. Africa experienced a
volume decline as a result of a difficult
political situation in some key markets. Sales of own produced products in
markets outside of Europe is important as it
allows for better capacity utilization of
Agris distribution and production system. It also
smoothens seasonal demands as overseas
markets often take products outside of the
European fertilizer season. This provides
optimization opportunities between
geographic markets enabling Agri to
prioritize markets based on overall
profitability. Growing Agris third party
product (TPP) business (including joint
ventures and blending operations) and the
continued positive development of key
strategic alliances enables Agri to better
utilize the capacity of its extensive
overseas marketing and distribution network. Ammonia trade and shipping Average ammonia prices increased by
approximately 85 percent from 2002
reflecting higher natural gas prices in the
US. Ammonia prices are strongly influenced
by the natural gas price in the US with
lower gas prices normally resulting in
higher production of ammonia. Agris ammonia
production and consumption in Europe is
largely balanced. However, significant
volumes are traded, partly to optimize
logistics and partly to benefit from market
opportunities. Price changes relating to
ammonia sold from Agris plants in Trinidad
and Qatar are not reflected in operating
revenues because these operations are
included in results from non-consolidated
investees. Volumes sold in these areas in
2003 were in line with 2002. Industrial gases and chemicals Revenues from industrial gas and chemicals
activities increased approximately 8 percent
in 2003. The main improvements were achieved
within activities related to environmental
products, nitrogen chemicals and technical
ammonium nitrates. Volumes of technical
ammonium nitrates for civil explosives
increased by approximately 19 percent
compared to the prior year mainly due to
increased market share in Europe and higher
sales in Africa and Latin America. Volumes
of environmental process chemicals (i.e.,
Nutriox for water treatment and Reduktan for removal of NOX emission)
increased by 100




---



##### 



approximately 10 percent. The
increase related primarily to higher coal
consumption for power generation in Europe,
increasing the demand for Reduktan and the
abnormal hot summer in Central and South
Europe growing the demand for Nutriox. Operating Costs Natural gas is the most important raw material used in the
production of ammonia, nitrogen fertilizer and technical products. Most of Agris natural gas
requirements in 2003 were purchased from external suppliers. A
significant part of the gas used was purchased
under long-term contracts with pricing mechanisms linked to the development in market prices for
gas. Natural gas prices are closely linked to developments of the crude oil price. However,
 due to contract terms and Agris distribution system, gas price changes in Europe are normally
reflected in reported earnings with a time lag of approximately 4-5 months. Higher oil prices during the
first several months of 2003 (and the consequent increase in gas and
oil product costs for Agris
ammonia plants) resulted in an increase of approximately 40 percent in the cost of raw materials for
ammonia production for 2003 compared to the prior year in U.S. dollar terms. In Norwegian kroner,
 the increase was in excess of 20 percent. Other raw material costs were stable. Productivity in Agri increased as a
result of improvements in the European
production system, increasing production by
almost 600 kilo tonnes of finished
fertilizers compared to 2002. The improvement contributed to a 6 percent reduction in
fixed costs per tonne for the year. Total
fixed costs for Agri were unchanged in
nominal terms on a comparable basis despite
a substantial increase in pension costs. An
increase in net operating capital in 2003 of
NOK 913 million resulted from significantly
higher prices. Net operating capital days
was reduced by approximately 13 percent
through completion of several improvement
projects in addition to an extraordinary low
level of stocks in Europe during the spring of 2003. Operating Income Operating income was NOK 2,800 million,
compared to NOK 2,207 million in 2002, an
increase of approximately 27 percent. The
positive development in nitrogen fertilizer
prices led to strong results despite
negative currency effects and higher energy
costs. EBITDA for 2003 was NOK 4,748
million compared to NOK 3,945 million in
the prior year Outlook Market indicators suggest a continued growth
in world demand for fertilizer in 2004. This
trend is expected to continue with growth
outside Europe, mainly in Asia and Latin
America. The fertilizer industry expects
consumption in West Europe to show a
moderate declining trend for the coming
years. This mainly relates to increased
efficiency in the application of fertilizer,
economic uncertainty relating to the
farmers economy, environmental pressure to
reduce the usage of mineral fertilizers and
developments with the European Unions (EU)
Common Agricultural Policy (CAP). Since
1999, changes in the CAP have led to reduced
price supports within the EU, but higher
area payments. The economic consequence of
this policy change may result in a reduction
of agricultural input factors such as
fertilizer. Other factors, such as increased
focus on the protein content of grain and
improved prices for agricultural products
may have positive effects. For nitrogen fertilizer, it is
difficult to estimate whether the
utilization rate will increase or decrease
in 2004 and 2005. More capacity will come on
stream, and higher than average consumption
growth rates are required to increase the
utilization rate. It is expected that oil
prices will remain at a high level,
resulting in high gas costs in Europe. Due
to the time lag discussed above, Agris
energy costs in the first half of 2004 is
expected to be on the same level as in the
first half of 2003. Ammonia prices correlated strongly with
US natural gas prices from 1999 through
first half of 2003. Since then, the
correlation ceased as continued production
curtailments in the USA have supported the
ammonia market. The correlation may be
restored if and when currently idle capacity
in the USA is brought back into production,
or if/when expected new ammonia capacity
begins production in 2005. The price level for nitrates and other
fertilizers in West Europe is expected to
continue to correlate strongly with the
movements in international fertilizer
prices. Grain prices, particularly in the USA,
but also elsewhere, increased substantially
through 2002 and 2003. Global production of
grain lags consumption and this may not yet
be fully reflected in
price developments. In 2003, grain
inventories were also reduced. The expected
need for increased grain production is
positive for the demand outlook for
fertilizer. Other activities Petrochemicals Petrochemicals operating revenues increased
by 3 percent in 2003 compared to 2002. The
increase was primarily due to somewhat
higher product prices in NOK and higher
volumes. Hydros average realized price for
caustic soda and S-PVC was approximately 3
and 7 percent higher, respectively, in 2003
than in 2002. In 2003, Petrochemicals incurred an
operating loss in the amount of NOK 8
million, representing an improvement of NOK
27 million compared with 2002. EBITDA was
NOK 401 million, an improvement of NOK 81
million compared to 2002. The positive
development mainly resulted from higher
volumes and somewhat improved product prices
in Norwegian kroner for S-PVC and caustic
soda, partly offset by higher purchased raw
material costs. Results from
non-consolidated investees were
approximately NOK 60 million higher compared
to the same period of 2002, mainly due to
higher 101




---



##### 



product prices in Asia, which is the
main market for the Qatar Vinyl Company. In March 2003 Norsk Hydros Board of
Directors approved the construction of a new
chlorine plant at Rafnes in Norway. The
investment is estimated to cost
approximately NOK 1 billion. The expansion
project started in May, and is progressing
according to plan. Start-up is expected in
the autumn of 2005. After seven years of poor financial
performance, the global petrochemical
industry is expected to improve. Poor
financial performance has resulted in a lack
of reinvestment in petrochemical facilities.
Additionally, significant industry
consolidation has occurred as producers
searched for ways to reduce cost, and
rationalize inefficient facilities. Global
economic recovery is in its early stages and
increased demand for petrochemicals is
expected to follow. The average growth rate
for the industry as a whole was around 4
percent at the beginning of 2004 which is
also the expected average growth for the
year. Growth in Europe is expected to be 2
percent for 2004. Growth in demand is
expected to improve the market balance and
result in higher prices and margins. Treka Treka consists solely of the fish feed
producer Biomar. Difficult conditions in the
fish farming industry resulted in losses on
bad debts during the year. During 2003
approximately NOK 570 million relating to
losses on bad debts and write downs of
goodwill and intangible assets were charged
to results. Pronova During 2003, Pronova sold their Swedish subsidiary Carmeda AB resulting in a gain of NOK 139 million. Pronova also signed an agreement in the fourth quarter to sell 80.1 percent in Pronova Biocare for NOK 165 million. The sale resulted in a gain of NOK 110 million which was included in Other items in the first quarter of 2004. Liquidity and capital resources Amounts in NOK million
    
    2003
    
    
    2002
    
    
    2001Cash flow provided by (used for):Operations
    
    
    24,578
    
    
    
    21,785
    
    
    
    26,172Investments
    
    
    (7,840
    )
    
    
    (36,446
    )
    
    
    (14,681
    )Financing
    
    
    (8,233
    )
    
    
    (5,995
    )
    
    
    (5,990
    )Increase (decrease) in cash and
cash equivalents
    
    
    9,284
    
    
    
    (21,183
    )
    
    
    5,382Return on Shareholders equity
    
    
    13.4%
    
    
    
    11.6%
    
    
    
    10.8%CROGI
    
    
    9.8%
    
    
    
    8.5%
    
    
    
    9.4%Net interest-bearing debt/equity ratio1)
    
    
    0.38
    
    
    
    0.60
    
    
    
    0.34
  1)
    
    Net interest-bearing debt divided by
shareholders equity plus minority
interest, adjusted for unfunded pension
obligation and present value of future
obligations on operating leases, both
after tax. Cash flow Hydro has historically financed its
operations primarily through cash generated
by operating activities. In 2003, net cash
generated by the Companys operations of
approximately NOK 24.6 billion was more than
sufficient to fund the net cash used in
investing activities of approximately NOK
7.8 billion. Of the residual, approximately
NOK 5 billion was used to repay interest
bearing debt and approximately NOK 3.2
billion was used for dividends and share
repurchases, leaving approximately NOK 9.3
billion (including foreign currency effects
on cash flows) to increase the Companys
cash balance reducing the Companys net
interest bearing debt. Cash from Operations Cash provided by operating activities of NOK
24,578 million for the year represented an
increase of 13 percent from 2002. The
improvement was mainly due to higher
earnings resulting from the significant
increase in oil and gas production together
with higher oil and gas prices. Higher
product prices in Agris fertilizer business as
well as productivity gains in both the
Aluminium and the Agri fertilizer businesses, also
contributed to the improvement in cash
generated from operating activities. Investing Activities Net cash used in investing activities in
2003 was NOK 7,840 million compared to NOK
36,446 million in 2002. The decline in cash
used for investing activities for the year
was primarily due to decreased spending on
purchases of other long-term investments of
NOK 17,087 million, lower purchases of
property, plant and equipment of NOK 4,106
million, and higher proceeds from the sale
of long-term assets of NOK 5,084 million.
The sizeable reduction in purchases of
long-term investments from 2002 to 2003
reflected the significant acquisitions that
took place in 2002, principally the VAW
and Technal acquisitions, and the purchase
of assets from the Norwegian States Direct
Financial Interest (SDFI). See the Capital
Expenditures section below for an analysis
of expenditures for property, plant and
equipment and long-term investments. Financing Activities In 2003, NOK 8,233 million was used in
financing activities, compared
to NOK 5,995 million in 2002. Principal
repayments of NOK 5,342 million in 2003,
including repayments of debt relating to VAW
and Treka, were NOK 1,146 million higher
than in 2002. In addition, repurchase of
ordinary shares of NOK 555 million and
dividends of NOK 2,711 million together were
NOK 690 million higher than in 2002. In
January 2004, an extraordinary General
Meeting approved a capital reduction by
cancellation of 1,484,300 treasury shares
acquired in 2003 as part of a share buyback
program approved by the 2003 Annual General
Meeting. The extraordinary General Meeting
also authorized the redemption of 1,157,922
shares owned by the Norwegian State for an
amount of NOK 445 million payable in 102




---



##### 



March 2004. There was no repurchase of shares in
2002. Cash and cash equivalents was NOK
15,249 million at the end of 2003 compared
to NOK 5,965 million for 2002. The main
reasons for the increase are described
above. Hydro anticipates that cash from
operations, its cash holdings and proceeds
from Yaras debt repayment will be sufficient
to meet its planned capital expenditures
and operational requirements in 2004.
Hydros capital expenditures for 2004 are
estimated to be approximately NOK 19
billion (excluding exploration activities). Short and long-term borrowings At year-end 2003, short-term bank loans and
the current portion of long-term debt in
Hydro amounted to NOK 6.8 billion, down from
the 2002 level of 9.3 billion. Hydros long-term interest bearing debt
at the end of 2003 was NOK 28.6 billion,
compared to NOK 30.9 billion at the end of
2002. During 2003, an early repayment of USD
195 million (NOK 1.4 billion) of long-term
debt was made and NOK 1.2 billion became
current and was reclassified to short-term
liabilities. Hydro repaid maturing loans of
GBP 100 million (NOK 1.2 billion) and NOK
500 million during the year. No new loans
were issued in 2003. As of December 31, 2003
the fair value of Hydros long-term debt,
including the current portion, was NOK 34.9
billion, and the carrying value was NOK 29.8
billion. Approximately two-thirds of Hydros
long-term debt as of year-end 2003 was
denominated in US dollars. Substantially
all of Hydros long-term debt carry fixed
interest rates. The weighted average
interest rate on all long-term debt was
approximately 6.9 percent at year-end 2003.
The average maturity of the Companys
outstanding long-term debt was
approximately 14 years, with approximately
13 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). Following the demerger of Agri, Hydro may consider some adjustments to its debt portfolio through early repayments or repurchases of parts of the outstanding loans. During the first quarter of 2004 Hydro has provided for the prepayment of loans with an original maturity in 2005 - 08 of approximately NOK 2 billion. 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 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 December 31, 2003, 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 aluminum 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. Hydro announced its intention to
demerge Hydro Agri in June 2003, which
resulted in Moodys amending Hydros rating
outlook from negative to stable. On November
28, 2003, following Hydros announcement
regarding the then proposed Agri transaction,
Moodys reaffirmed Hydros A2 rating with
stable outlook, and Standard & Poors stated
that the ratings and outlook on Hydro (A
with negative outlook) remained unchanged
following clarification of the Companys
plans to divest from its agricultural
business. 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 2003 was NOK 18.5 billion,
compared to NOK 31.5 billion at the end of
2002. The Companys net interest bearing
debt to equity (including minority
interests) ratio was 0.21 at year-end 2003.
Including net unfunded pension obligations,
after tax, and the present value of
operating leasing obligations, net interest
bearing debt divided by equity was 0.38,
which was well within the stated target of
0.5. As part of the demerger of the Agri business, Yara had assumed a liability to pay to Hydro a net interest bearing debt which at year end 2003 amounted to approximately NOK 7.5 billion. Yaras repay- 103




---



##### 



ment of this debt was made on completion of the demerger from the
proceeds of debt financing arranged through financial institutions prior to the consummation of the demerger.
In addition, Hydro also sold its 20 percent share holding in Yara, as part of the demerger process.
As a consequence of these transactions, Hydros net interest
bearing debt has been further reduced from the year-end 2003 level. As of December 31, 2003, Hydro had
unused short-term credit facilities totaling
approximately NOK 3.2 billion. The Company
also had committed agreements for long-term
stand-by credit facilities totaling
approximately USD 2 billion (NOK 13.5
billion). There were no borrowings under
these agreements as of December 31, 2003.
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. Employee retirement plans As of December 31, 2003, the projected
benefit obligation (PBO) associated with
Hydros defined benefit plans was NOK 29.2
billion. The fair value of pension plan
assets was NOK 18.7 billion, resulting in a
net unfunded obligation relating to the
plans of NOK 10.5 billion. In addition,
termination benefit obligations and other
pension obligations amounted to NOK 1.5
billion, resulting in a total net unfunded
pension obligation of NOK 12 billion. For
further information see note 20 included in
the notes to the Consolidated Financial
Statements. In 2003, the net unfunded pension
obligation increased by NOK 1.9 billion.
Unrecognized net losses and prior service
costs increased by NOK 1 billion from NOK
8.3 billion at the end of 2002 to NOK 9.3
billion at the end of 2003. The increase
included NOK 600 million relating to certain
plans reported in the line item Termination
benefits and other in prior periods. The
remaining increase was mainly attributable to
remeasurement of obligations at year-end
applying a lower discount rate. Hydros net pension cost for 2003
amounted to NOK 2.5 billion. Cash outflows
from operating activities in 2003 regarding
pensions amounted to NOK 2 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 two-thirds of Hydros
projected benefit obligation relates to
Norway. The discount rate applied for
Norwegian plans as of December 31, 2003 is
six percent. 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. Payments due by PeriodLessthan
    
    
    1-3
    
    
    4-5
    
    
    There-Amounts in NOK million
    
    Total
    
    
    1 year
    
    
    years
    
    
    years
    
    
    afterLong-term debt1)
    
    
    29,658
    
    
    
    1,201
    
    
    
    2,084
    
    
    
    1,087
    
    
    
    25,286Capital lease
obligations1)
    
    
    152
    
    
    
    40
    
    
    
    46
    
    
    
    20
    
    
    
    46Operating lease
obligations2)
    
    
    7,257
    
    
    
    1,188
    
    
    
    1,980
    
    
    
    1,573
    
    
    
    2,516Unconditional
purchase
obligations2)
    
    
    55,717
    
    
    
    7,310
    
    
    
    10,819
    
    
    
    7,900
    
    
    
    29,688Total contractual
cash obligations
    
    
    92,784
    
    
    
    9,739
    
    
    
    14,929
    
    
    
    10,580
    
    
    
    57,536
 Comprised of the following: 1)
    
    Liabilities recorded on the balance sheet
    
    NOK 29,810 million2)
    
    Commitments not recorded on the balance sheet
    
    NOK 62,974 million
 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 approximate 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 2003: Hydro
has guaranteed NOK 54 million of debt issued
on behalf of non-consolidated investees and
is contingently liable for NOK 85 million of
discounted bills. Hydro is also contingently liable to
various tax authorities for NOK 1,352
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 7,900 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 104




---



##### 



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 a 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 2003, the
remaining volume covered under the guarantee
was 1.2 million Sm3 of crude oil,
equivalent to approximately NOK 1,465
million calculated at current market prices. Outstanding commercial guarantees made
on behalf of subsidiaries amounted to NOK
10,545 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 performance 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 2003. Contractual commitments for investments
in property, plant and equipment, and other
future investments as of December 31, 2003
amounted to NOK 17.7 billion. Minority interest and Shareholders equity Minority interest decreased by approximately
42 percent to NOK 660 million in 2003. The
divestment of Flexible Packaging in 2003
contributed to a sizeable reduction in
minority interest. Shareholders equity was
NOK 88,080 million at the end of 2003, an
increase of around 16 percent compared to
2002. Net income in 2003 of NOK 10,968
million contributed substantially to higher
shareholders equity. Foreign currency
translation adjustments of NOK 4,856 million
in 2003 also contributed to higher
shareholders equity. The depreciation of
the Norwegian kroner against a majority of
currencies during 2003 resulted in
translation gains. Investments Investments in 2003 amounted to NOK 18.9
billion. The amount includes NOK 1.9 billion
resulting from Hydros adoption of Financial
Accounting Standard No. 143, relating to
asset retirement obligations. The amount has
no cash effect. Excluding this effect,
investments were NOK 17 billion for 2003.
Just over half of the investment amount
related to oil and gas operations.
Investments were slightly lower than planned
partly because of savings in development
projects. 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 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 14,074 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. Investments, including new and
existing fields, in Exploration and
Production in 2001 were NOK 9,533 million.
Grane, Tune, Snorre Phase 2 and Terra Nova
were the four most important development
projects for Exploration and Production in
2001. 105




---



##### 



Investments1) Amounts in NOK million
    
    20032)
    
    
    %
    
    
    2002
    
    
    %
    
    
    2001
    
    
    %Exploration and Production
    
    
    10,270
    
    
    
    54
    
    
    
    14,074
    
    
    
    31
    
    
    
    9,533
    
    
    
    58Energy and Oil Marketing
    
    
    989
    
    
    
    5
    
    
    
    622
    
    
    
    1
    
    
    
    557
    
    
    
    3Eliminations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydro Oil & Energy
    
    
    11,259
    
    
    
    60
    
    
    
    14,696
    
    
    
    32
    
    
    
    10,090
    
    
    
    62Metals
    
    
    3,572
    
    
    
    19
    
    
    
    12,728
    
    
    
    28
    
    
    
    1,872
    
    
    
    11Rolled Products
    
    
    466
    
    
    
    2
    
    
    
    7,437
    
    
    
    16
    
    
    
    201
    
    
    
    1Extrusion and Automotive
    
    
    1,543
    
    
    
    8
    
    
    
    5,153
    
    
    
    11
    
    
    
    1,454
    
    
    
    9Other and eliminations
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Hydro Aluminium
    
    
    5,581
    
    
    
    30
    
    
    
    25,318
    
    
    
    55
    
    
    
    3,527
    
    
    
    22Hydro Agri
    
    
    1,127
    
    
    
    6
    
    
    
    1,543
    
    
    
    3
    
    
    
    797
    
    
    
    5Other Activities
    
    
    852
    
    
    
    5
    
    
    
    3,115
    
    
    
    7
    
    
    
    1,372
    
    
    
    8Corporate and eliminations
    
    
    81
    
    
    
    0
    
    
    
    1,044
    
    
    
    2
    
    
    
    542
    
    
    
    3Total
    
    
    18,900
    
    
    
    100
    
    
    
    45,716
    
    
    
    100
    
    
    
    16,328
    
    
    
    100
  1)
    
    Additions to property, plant and equipment (capital expenditures) plus
long-term securities, intangibles, long-term advances and investments in
non-consolidated investees.2)
    
    Includes non-cash increase in investment from effect of change in
accounting principle (FAS143), of NOK 1,932 million. The largest investments for Metals in
2001 included the expansion activities
relating to the alumina refinery and
ownership interest in Alunorte in Brazil,
the construction activities related to the
remelt plant in Azuqueca, Spain and the
modernization and expansion activities
relating to the Companys aluminum smelter
in Sunndal. Investments for Extrusion and
Automotive related primarily to the acquisition of Aldural in Argentina and
rationalizing existing business activities
including a new press in Italy. 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 2003 were NOK 2,756 million and NOK
13,555 million, respectively. Additional
authorized future investments representing
projects formally approved by the Board of
Directors or management were NOK 1,908
million relating to land-based activities
and NOK 12,453 million relating to oil and
gas field activities and transport systems. Hydros long-term committed stand-by
facilities of approximately USD 2 billion as
well as cash holdings and expected cash flow
from operations are expected to provide
adequate reserves to fund these
expenditures. 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 850
million, NOK 815 million and NOK 796 million
during 2003, 2002 and 2001 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 379 as well as smaller
research groups in several other locations.
The Bergen facility 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 2003. Hydro Oil and Energy incurred R&D costs
in 2003 totaling approximately NOK 194
million compared to NOK 143 million in the
previous year. Exploration and Production
accounted for most of this amount. R&D
expenditures were primarily dedicated to
exploration technology, virtual reality,
increased oil recovery, multiphase
transportation, well technology, deepwater
technology, subsea solutions and health,
safety and environmental issues, all with
the purpose of reducing field development
and operating costs. Hydrogen as future
energy carrier, renewable energy and
reduction of emissions of carbon dioxide
were also part of Hydro Oil and Energys R&D
programs in 2003. Hydro Aluminiums R&D is oriented
toward the core activities of its business.
Hydro Aluminium incurred a total of NOK 459
million in 2003 in R&D cost compared with
NOK 408 million in R&D costs in 106




---



##### 



2002. Metals, Extrusion and Automotive, and Rolled
Products incurred NOK 168 million (NOK 99
million in 2002), NOK 240 million (NOK 265
million) and NOK 51 million ( NOK 44
million), respectively. R&D activities are
strongly focused on core products
and production processes. Hydro Aluminiums
R&D organization consists of an
international network covering Europe, North
America and Asia. Hydro Agri engages in R&D in order to
maintain its competitive position and to
develop new products and processes. Hydro
Agri spent approximately NOK 118 million in
2003 compared to NOK 152 million in the
prior year. R&D activities in 2003 relating
to fertilizer operations included process
and technology developments aimed at
optimization and cost reduction, and product
R&D targeting new, innovative products and
strategies for customers in selected
markets. R&D activities relating to
industrial products have focused on
application and product development,
including projects relating to environmental
issues. Risk management Indicative price and currency sensitivities The development of
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. For an
indication of the sensitivity regarding
prices and foreign currency fluctuation for
2004, please refer to the table below. The
sensitivity analysis is based on 2004
expected
production volumes as well as normalized
prices indicated below. The table
illustrates the Income Statements
sensitivity before and after tax.  
    
    Oil price 18 US dollar per barrel
    
    Aluminium price (London Metal
Exchange) 1,500 US dollar per tonne
    
    US dollar Norwegian kroner exchange rate 8.00
    
    Euro Norwegian kroner exchange rate 7.60 (8.00 from 2004) Indicative price and currency sensitivities Price sensitivity1)
    
    Pre tax
    
    
    After tax
    
    
    ChangeOil price (bbl)
    
    
    1,450
    
    
    
    390
    
    
    
    1USDAluminium price (tonne)
    
    
    875
    
    
    
    615
    
    
    
    100USDUSD sensitivity1)2)USD sensitivity Oil & Energy
    
    
    2,900
    
    
    
    785
    
    
    1 NOKUSD sensitivity Aluminium
    
    
    2,100
    
    
    
    1,475
    
    
    1 NOKUSD sensitivity before financial items
    
    
    5,000
    
    
    
    2,260
    
    
    1 NOKUSD sensitivity financial items3)
    
    
    (2,500
    )
    
    
    (1,400
    )
    
    1 NOKUSD sensitivity, NET
    
    
    2,500
    
    
    
    860
    
    
    1 NOK
  1)
    
    Reference prices: Oil 18 USD/bbl,
Aluminium 1,500 USD/tonne and
NOK/USD exchange rate 8.0.2)
    
    USD sensitivity estimates assuming
USD/NOK changes, all other currencies
fixed against NOK.3)
    
    Excluding cash flow and equity hedge
total exposure USD 1,100 million and
USD 350 million debt in USD-based
subsidiaries Risk Management Risk management in Hydro is based on the
principle that risk evaluation is an
integral part of all business activities.
Therefore responsibility for risk management
is placed within the Companys business
areas. Each business area has policies and
procedures in place for monitoring risks,
assessing appropriate risk levels, and
mitigating risk. However, overall and aggregated risk
positions are also assessed at the Group
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 impact on net
interest-bearing debt/equity ratio,
liquidity and credit rating; 
    
    Commercial Risks  mainly
comprising fluctuations in
commodity prices, currencies and
interest rates; 
    
    Operational and Human Resource Risks  comprises continuity risk and risks
related to non-performance of
employees; 
    
    Health, security, safety,
environmental issues and potential
impact on communities. The discussion below is limited to
financial and commercial risks with a
focus on commodity prices, foreign
exchange rates and
interest rates. Financial and Commercial Risk
Management  A Commercial Risk Board headed
by the Companys Chief Financial Officer
meets regularly to assess and monitor the
financial and commercial risks of the Group.
The execution of the management approach to
these risks includes establishing and
maintaining policies and procedures as well
as monitoring risk exposures and positions. 107




---



##### 



The overall objective of financial and
commercial risk management is to safeguard
Hydros ability to continuously meet its
cash commitments. 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 are monitored.
Simulations of cash flow scenarios, using a
3-year rolling horizon, are carried out for
this purpose. The outcome of this analysis
is reported to management on a quarterly
basis. The primary focus in managing
financial
and commercial risk 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. The overall management of Hydros
financial and commercial risk profile is
therefore to a large extent focused on
financial policies. This implies
prioritizing maintaining the financial
strength of the Group including establishing
a debt to equity ratio target of 0.5;
maintaining satisfactory liquid reserves,
and maintaining a good overall credit
standing. Use
of Derivatives  Mitigating
financial and commercial risk exposures
through the use of derivative instruments is
done only to a limited extent. For this
purpose, Hydro utilizes financial
derivatives
as well as commodity derivatives for crude
and other oil and gas products, aluminium,
and electricity. The most common use of
derivatives relates to currency and
aluminium forwards as part of day-to-day
operational hedging of the Companys
aluminium operations. Accounting
for Derivative Contracts  For accounting purposes, unless otherwise
indicated below, derivative financial and
commodity instruments are evaluated against
current market values (marked-to-market)
with the resulting gain or loss reflected in
earnings. This is because the manner in
which derivative instruments are used does
not meet the criteria for hedge accounting
treatment established by Statement of
Financial Accounting Standards (SFAS) No.
133 Accounting for Derivative Instruments
and Hedging Activities. 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 revenue 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. As described above, the Companys
main strategy to manage this exposure
relates to maintaining a strong financial
position to be able to meet fluctuations in
prices and 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. The following highlights Hydros
main commodity price risks. Oil Hydro produces and sells crude oil and gas
liquids. Hydro utilizes futures and swaps to
mitigate unwanted price exposure for a
portion of its crude oil portfolio
production. From time to time financial
options are used for the same purpose. For the purpose of protecting against
the risk of low oil prices, in 2002 Hydro
purchased average rate put options (Asian
options) to sell 10 million barrels of oil
in the first half of 2003 for an average
strike price of US dollar 17 per barrel. The
options expired on June 30, 2003. At the end
of 2003 Hydro had no hedging program in
place for the purpose of protecting against
the risk of low oil prices. Natural gas Hydro is a producer, consumer, buyer and
seller of natural gas. The internal
consumption of natural gas has decreased
significantly with the demerger of the Agri
activity. 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 prices. Hydro is also
participating in limited speculative
trading as described above. In order to reduce the risk in the natural gas portfolio against unfavorable fluctuations in gas and oil
prices, Hydro utilizes instruments such as
forwards and swaps to mitigate unwanted
price exposures for a portion of its
natural gas portfolio. 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 also engages in third
party trading by offering power portfolio
management services and participating in
limited speculative trading. Aluminium Hydro produces primary
aluminium and fabricated aluminium products.
The primary aluminium smelters are located
in Norway, Germany, Australia, Slovakia and
Canada. Downstream activities are 108




---



##### 



mainly
located in Europe, the Americas and Asia. To
support the metal supplier concept, Hydro
also engages in trading of aluminium and
related raw material. Aluminium Production is based on two
basic raw materials,
aluminium oxide (alumina) and
electricity. Hydro is producing alumina in
joint venture plants in Brazil and Jamaica,
covering approximately 50 % of required
volumes. The remaining needs are covered
through long-term contracts. Availability
of electricity is secured through own
production and contracts with external
suppliers. The main purpose of Hydros sourcing
and trading activity is to obtain raw
materials for Hydros smelters. A natural
extension of this is to also be an external
supplier of raw materials used in the
aluminium production process and aluminium
metal products. In addition the trading
contributes 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 also has considerable
activities relating to remelting and
long-term commercial agreements to secure
sourcing of casthouse products. When
considering the risk profile of Hydros
aluminium activities, the significant
external volumes of physical aluminium and
raw materials sourced and traded are also
taken into consideration. LME future contracts: Hydro enters
future contracts with the LME mainly for two
purposes. The first is to achieve an average
aluminium price on smelter production.
Secondly, because the Companys 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 majority of these contracts mature
within one year. Hydro manages these hedging
activities on a portfolio basis, taking LME
positions based upon net exposures.
Accordingly, it is difficult to meet certain
hedge accounting criteria. As a result,
aluminium price volatility can result in
significant fluctuations in the
marked-to-market adjustments for LME
positions recorded to operating income. Sunndal hedging program: The expansion
project at the Sunndal metal plant
increased Hydros exposure to commodity
prices and foreign currency exchange rates.
Accordingly, 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 for the period 2003 to 2007. This
hedging strategy meets certain hedging
criteria in accordance with SFAS 133, and
has therefore been designated as a cash flow
hedge. Hydro also has a commitment through
2009 with Aluvale to purchase a fixed
tonnage of remelt ingot per year. At the end
of 2002, Hydro entered into short positions
using LME futures to hedge against the
fluctuations in the fair value of the
purchase commitment due to changes in the
LME price of aluminium over the period of
2003  2006. Foreign currency exchange rate risk Prices of many of Hydros most important
products, mainly crude oil, aluminium,
natural gas and magnesium, are either
denominated in US dollars or are influenced
by movements in the value of other
currencies against the US dollar. The cost of raw materials, including
natural gas, NGLs and alumina, are affected
by the US dollar price of crude oil, 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 cost related to
production, distribution and marketing of
products in a number of different currencies
related to the
countries of operation. As a result,
the effects of changes in currency rates on
the translation of local currencies into
Norwegian kroner 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, 2003,
approximately two thirds of Hydros
long-term debt was denominated in US
dollars). When the dollar weakens, the
decline in operating income is offset by
unrealized currency gains and lower
interest expense relating to the dollar
denominated debt. Conversely, a stronger US
dollar improves operating income but also
results in unrealized currency losses and
higher interest expense. The remaining long-term debt was
denominated in Norwegian kroner, Euro,
Swedish kroner, and British pounds. Hydro also employs foreign currency
swaps and forward currency contracts to
modify the currency exposures for Hydros
long-term debt portfolio. Foreign currency swaps
allow Hydro to raise long-term borrowings in
one currency and swap them into another with
lower funding costs rather than borrowing
directly in the second currency. 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. Using short-term forward currency
swaps reduce funding costs, as it is
alternative to drawing a short-term loan in
one currency and investing short-term in
another. In order to reduce effects of foreign
exchange rate fluctuations on reported
results, Hydro has designated a portion of
its foreign denominated long-term debt,
including certain related balances in
currencies arising from foreign currency
swaps and forwards, as hedges of net
foreign investments in subsidiary
companies. The foreign exchange gains and
losses on this debt are recorded as a
separate component of shareholders equity.
The same applies to certain foreign
exchange contracts designated as cash flow
hedges. 109




---



##### 



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 Internal policies limit credit risk by
setting counterparty risk limits, requiring
insurance of risks, and establishing
procedures for monitoring exposures and
settlement of accounts. The overall risk
level of the Group is reduced through a
diversified customer base representing
various industries and geographic areas.
Follow-up of timely payments of accounts
receivables has been given high priority in
the Hydro
Group. 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. It is Hydros policy
to enter into derivative financial
instruments only with banks with
pre-approved exposure limits. Hydros policy
also requires pre-approved exposure limits
for financial institutions relating to
current accounts, deposits and other
obligations. Therefore, counter party risk
related to use of derivative financial
instruments and financial operations is
regarded as limited. Hydro also has exposure to credit risk
related to derivative commodity instruments.
However, this risk is substantially limited
since most instruments are settled through
commodity exchanges. Hydro limits credit
risks relating to derivative commodity
contracts that not traded on exchanges by
setting policies for credit ratings and
limits for counterparties. Sensitivity analysis The indicative income statement
sensitivities for Hydros main exposures are
included in the introduction to Risk
Management above. The sensitivities
presented for aluminium and crude oil, and
the US dollar sensitivity for the Business
areas exclude the effects of any hedges. The
sensitivity related to outstanding
derivatives as of December 31, 2003 is
analyzed in following section. 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. Such
disclosures are intended to express the
potential loss in fair values of market risk
sensitive instruments resulting from one or
more selected hypothetical changes in
interest rates, foreign currency exchange
rates, commodity prices and other relevant
market rates or prices over a selected
period of time. 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 December
31, 2003 and December 31, 2002,
respectively. Hydros management cautions
against relying on the information
presented. This is due to the arbitrary
nature of assumptions involved, the
inability of such a simple analysis to model
reality, continuous changes to Hydros
portfolio and the exclusion of certain of
Hydros positions necessary to reflect the
net market risk of the Group. Accordingly,
the information does not represent
managements expectations about probable
future effects on results. The most
significant limitations on the figures
provided are as follows:  
    
    The tables only include the effects of
the derivative instruments discussed
above and of certain financial
instruments (see Footnote 3 below). It
does not include any related physical
positions, contracts, and anticipated
transactions that many of the
derivatives 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 effects of these limitations on the estimates may be material. The overall use of derivatives related
to commodities has been relatively stable
compared to 2002 in the business areas.
Exceptions are the oil and gas area where
there is currently no hedging of oil prices.
However, other derivatives in oil and gas
trading are used more frequently. Use of
derivatives within the electricity area has
decreased from year end 2002 due to the
special market situation in the Nordic
region at that time. Use of financial derivatives, mainly
foreign exchange forward contracts has been
stable. The reduced negative fair value of
finan- 110




---



##### 



cial instruments includes the effects
of increased cash positions and reduction of
long-term debt in various currencies. The year-end fair values and sensitivities of
derivatives are influenced by the price at which contracts are
entered into and the market prices at
year-end. As commodity markets, currency
markets and interest rates are volatile,
effects on the value of derivatives measured
at year-end may be substantial. However, as
explained above the underlying positions
offset the effects of derivatives. When
evaluating fair value and sensitivity
effects on financial instruments, the
long-term nature and the underlying values
and exposures must be taken into
consideration ( see note 3 to the table
below). 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, 20031)
    
    
    rates
    
    
    exchange rates
    
    
    prices
    
    
    Volatility
    
    
    OtherDerivative instruments related to:Commodities
    
    
    719
    
    
    
    3
    
    
    
    79
    
    
    
    264
    
    
    
    
    
    
    
    Other2)
    
    
    2,410
    
    
    
    30
    
    
    
    823
    
    
    
    
    
    
    
    
    
    
    
    Financial instruments3)
    
    
    (19,880
    )
    
    
    1,870
    
    
    
    2,261
    
    
    
    
    
    
    
    
    
    
    
    57
 As of 31 December, 2002 Hypothetical loss from +/- 10% change in: Fair value as of
    
    
    Interest
    
    
    Foreign currency
    
    
    CommodityNOK million (unaudited)
    
    31 December, 20021)
    
    
    rates
    
    
    exchange rates
    
    
    prices
    
    
    Volatility
    
    
    OtherDerivative instruments related to:Commodities
    
    
    1,419
    
    
    
    4
    
    
    
    123
    
    
    
    684
    
    
    
    6
    
    
    
    Other2)
    
    
    1,520
    
    
    
    59
    
    
    
    705
    
    
    
    
    
    
    
    7
    
    
    
    Financial instruments3)
    
    
    (32,155
    )
    
    
    1,353
    
    
    
    3,197
    
    
    
    
    
    
    
    
    
    
    
    57
  1.
    
    The change in fair value due to price changes is calculated based 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 used vary as appropriate for
the individual instruments.2.
    
    Other mainly includes forward currency contracts and currency swaps.3.
    
    Financial instruments 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 not be expected to affect
earnings. 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.
Information related to the fair values for
the commodity and financial instruments and
hedge accounting strategies as of December
31, 2003 can be found in Note 24 in Notes to
the Consolidated Financial Statements. The methods used by Hydro to analyze
risks discussed above should not be
considered projections of future events or
losses. 111




---



##### 



2002 Compared with 2001 Summary Hydros net income after tax was NOK 8,765 million (NOK 34 per share) in
2002, an improvement of approximately 11 percent compared to the previous year.
The improvement was primarily due to the significant increase in Hydros oil
and gas production, Hydros more extensive aluminium operations (following the
acquisition of VAW in the first quarter of 2002), unrealized gains in
connection with energy contracts and unrealized gains associated with the
Companys debt due to changes in currency exchange rates. Lower oil and gas
prices, stated in Norwegian kroner (NOK), difficult market conditions for the
aluminium industry, and the strengthening of the Norwegian kroner against the
US dollar (USD) negatively impacted the operating results. Operating Results Operating revenues in 2002 were NOK 167,040 million, an increase of
approximately 9 percent compared to the previous year. The increase mainly
reflected the effect of the VAW acquisition. Operating income of NOK 19,841 million in 2002 reflected a decline of NOK
1,242 million (approximately 6%) compared to NOK 21,083 million in the prior
year. The decline primarily resulted from the higher level of oil and gas
exploration costs expensed in 2002 compared to the previous year. This was
partly offset by the increased operating income resulting from the inclusion of
the VAW activities in the consolidated results as of March 15, 2002. Earnings from non-consolidated investees were NOK 33 million in 2002
compared to NOK 566 million in 2001. Currency losses of NOK 460 million in a
non-consolidated investee in Brazil, which produces alumina, were expensed in
2002, compared to NOK 159 million in 2001. Net financial income for 2002 was NOK 1,935 million compared to net
financial expense of NOK 762 in the previous year. During 2002, the US dollar
and currencies closely linked to the US dollar, such as the Canadian dollar,
weakened considerably against the Norwegian kroner, the euro and the Australian
dollar, resulting in unrealized currency gains on loans and currency forwards,
but also currency losses on receivables. Net unrealized currency gains included
in 2002 amounted to NOK 3,262 million. In addition, Hydro started the year with
an unusually high cash level that was subsequently used for funding the VAW
acquisition early in the year. As a result, interest income was lower in 2002
than in the preceding year. 112




---



##### 



The provision for current and deferred taxes for 2002 amounted to NOK
13,278 million, approximately 60 percent of income before tax. This amount was
mainly comprised of current taxes. The equivalent figures for 2001 were NOK
13,750 million and 64 percent. HYDRO OIL AND ENERGY From 2003, Hydros gas transportation activities are reported as part of
Hydro Oil and Energys Energy and Oil Marketing sub-segment. Such activities
had previously been included within the Exploration and Production sub-segment.
Prior period figures have been reclassified for comparative purposes. Revenues and Market Conditions Operating revenues in 2002 were NOK 55,845 million compared to NOK 52,180
million in the previous year. Exploration and Productions operating revenues in 2002 were NOK 32,970
million compared to NOK 32,426 million in 2001. Average total production of oil
and gas in 2002 was 480,000 boed, an increase of approximately 14% over the
prior year level of 421,000 boed. Hydro experienced strong production growth
from both Norwegian and international fields in 2002. Production from Norwegian
fields increased partly as a result of the purchase of SDFI assets, which
increased Hydros interests in the Hydro-operated Oseberg, Tune and Grane
fields, and partly due to increased production from the Snorre B and Åsgard
fields. Outside the NCS, increased production came from the Girassol field in
Angola (production started in December 2001) and the Terra Nova field in Canada
(production started in January 2002). Oil production accounted for 77 percent
of the total production in 2002, approximately the same percentage as in 2001. The effect of the increased production on 2002 operating revenues and
income was offset, to a large extent, by the lower oil prices, stated in
Norwegian kroner, as a result of the appreciation of the Norwegian kroner
against the US dollar. In addition, realized gas prices were lower in 2002
compared to 2001. The average realized oil price in Norwegian kroner was NOK
194 (USD 24.70) per barrel in 2002, compared with NOK 217 (USD 24.20) in 2001.
Hydro realized an average gas price in 2002 of NOK 0.95 per standard cubic
meter, compared to an average realized gas price in 2001 of NOK 1.21 per
standard cubic meter. Energy and Oil Marketings operating revenues in 2002 were NOK 45,915
million, compared to NOK 45,824 million in 2001. Operating revenues from oil
trading and refining and oil marketing declined primarily as a result of a
reduction in refined product prices. Higher revenues from gas sourcing and
marketing activities reflected increased gas trading volumes. Revenues from
power sourcing and marketing activities declined due to the unusual situation
in the Nordic electricity market, described below under Operating Income. Operating Costs Operating costs relating to exploration and production activities
increased in 2002 primarily as a result of increased exploration costs. Hydros
total exploration costs and cost of appraisal of discoveries amounted to NOK
3,558 million in 2002, compared to NOK 1,400 million in 2001. In 2002, a major
part (74 percent) of Hydros exploration activity was dedicated to areas
outside the NCS, mainly in Angola, Canada, Iran and the US Gulf of Mexico. In
2002, total exploration costs were higher than the cost relating to exploration
activity due to expensing of previously capitalized costs of exploration wells
and acquisition costs in the amount of NOK 1,492 million. This included
acquisition costs paid for accessing prospective exploration areas such as
Block 34 in Angola and in the US Gulf of Mexico that were capitalized in 2001.
As a result of disappointing exploration results, mainly in Angola and the US
Gulf of Mexico, such costs totaling NOK 1,118 million, together with the well
costs, were expensed during 2002. 113




---



##### 



Hydros average production cost was NOK 23 per boe in 2002, compared to
NOK 24 per boe in 2001. Total depreciation cost increased in 2002 as a result
of the higher production levels. Depreciation, including accruals for
abandonment and well closure costs and write-downs (but excluding depreciation
on transportation systems), averaged NOK 46 per boe in 2002, the same level as
in 2001. Net transportation costs were NOK 9 per boe in 2002, the same level
as in 2001. Energy and Oil Marketings operating costs in 2002 were 10% lower than in
2001, primarily reflecting the unusual situation in the Nordic electricity
market experienced at the end of 2002. Refining costs per barrel, comprised of
both fixed and variable processing costs, decreased to NOK 11.4 in 2002 from
NOK 13.0 in 2001. Power plant operating costs of NOK 610 million in 2002
remained virtually unchanged compared to the prior year. Energys fixed costs
in 2002 increased by NOK 88 million compared to the prior year, primarily as a
result of planned organizational development to better position Hydro to
capture business opportunities in the changing, increasingly liberalized
European gas market. Operating Income Operating income of NOK 15,947 million in 2002 declined by NOK 3,230
million (approximately 17%) from NOK 19,177 million in the prior year. Exploration and Productions operating income of NOK 13,137 million in
2002 reflected a decrease of NOK 3,773 million (or 22%) from the prior year.
The main contributor to the decrease was the high exploration cost expensed in
2002. The effect of lower oil and gas prices in Norwegian kroner was offset by
higher oil and gas production. Energy and Oil Marketings operating income was NOK 2,784 million, an
increase of NOK 517 million (or 23%) compared to the prior year operating
income of NOK 2,267 million. Operating income from the power sourcing and
marketing activities was NOK 1,185 million in 2002, an increase of
approximately 48% compared to the prior year. The increase reflected, to a
large extent, the substantial net increase in the fair value of the derivative
electricity contracts portfolio at year-end 2002 due to unusually high prices
in the Nordic electricity market as a result of very low reservoir levels
resulting from exceptionally low precipitation and increased consumption due to
cold weather. Operating income for the oil trading and refining activities was
NOK 388 million in 2002, a decline of 32% from the previous year. Average
refining margins in 2002 were US$ 2.21 per barrel, approximately 41% lower than
in 2001, as a result of lower global demand for refined products in 2002.
Operating income from the gas sourcing and marketing activities decreased to
NOK 81 million in 2002, primarily as a result of costs related to planned
organizational developments to capture business opportunities in the changing
European gas market. Operating income for the oil marketing activities
increased to NOK 68 million in 2002 from a loss of NOK 32 million in 2001,
reflecting improved margins mainly due to lower inventory losses. HYDRO ALUMINIUM Revenues and Market Conditions Operating revenues in 2002 were NOK 65,051 million, an increase of
approximately 27% over thee prior year figure of NOK 51,083 million. During the
first quarter of 2002, Hydro acquired VAW and the French building systems
company, Technal. Hydros consolidated results included the operating results
of VAW as of March 15, 2002, and Technal, as of January 26, 2002. Excluding the
VAW and Technal contributions, operating revenues declined. Hydro Aluminiums
results reflected the difficult market conditions that affected all of its
sub-segments during 2002. In response to the economic conditions, customers, in
general, reduced their inventories, leading to a decline in demand for metal
products. As a result, overcapacity put pressure on both LME prices and
product margins. In 2002, the average LME three-month price for primary
aluminium declined approximately 6 percent compared to the prior year. The US
dollar  Norwegian kroner exchange rate declined approximately 11 percent. 114




---



##### 



Metals operating revenues increased by NOK 8,171 million (26%) in 2002
compared to the prior year, mainly as a result of the VAW acquisition. VAWs
contribution to 2002 operating revenues amounted to NOK 12,919 million.
Excluding the revenues generated from VAWs smelter and remelting production,
there was a year over year decrease in operating revenues, attributable
primarily to a decline of more than 15 percent in realized prices, measured in
Norwegian kroner, for the smelters sales volumes. Rolled Products operating revenues in 2002 were NOK 14.8 billion,
compared to NOK 4.2 billion in 2001. The increase resulted mainly from the
inclusion of VAW in the consolidated results from March 15, 2002. Rolled
Products increased its sales volume in 2002 by over 5% for flat rolled products
in 2002 while maintaining a stable average product margin compared to the prior
year. Although industry shipments increased by 4% in 2002 for foil and were
stable for the litho market, Rolled Products 2002 sales volume in the West
European market increased by 11% and 8% for foil and litho products,
respectively, compared to 2001. Extrusion and Automotives operating revenues in 2002 increased 8 percent
to NOK 24,245 million, compared to NOK 22,487 million in the previous year.
Excluding the contributions of the new businesses acquired, operating revenues
were NOK 18,657 million in 2002. A breakdown of the percentage of 2002
operating revenues generated by each sector within the Extrusion and Automotive
sub-segment is as follows:  Extrusion
    49
    %Automotive
    28
    %North America
    23
    %
 Operating revenues from European activities reflected a 2 percent increase
in shipments of general extrusions, while the shipments in building systems
increased by 4 percent. Despite a relatively flat demand for extrusion products
in Europe, Hydros extrusion activities increased sales volumes while
maintaining margins stated in euro. Operating revenues from the extrusion
(including remelting) activities in North America declined from 2001, due to
lower demand in the general extrusion and trucking sectors. Automotive
revenues grew slightly due to the start up of a new production line for crash
management, but this effect was more than offset by the reduction in revenues

due to lower prices in precision tubing. North Americas activities were
affected by poor economic conditions, which weakened demand throughout the
entire year. However, margins for extruded products remained relatively
stable. Operating Costs Hydro Aluminiums cost and manning reduction targets related to
improvement programs were met in 2002, resulting in cost savings of
approximately NOK 1 billion compared to the combined cost level of the Hydro
Aluminium and VAW businesses in 2001. Cumulative costs incurred related to the
implementation of the improvement programs amounted to approximately NOK 990
million at the end of 2002. Total costs incurred during 2002 related to these
programs amounted to approximately NOK 300 million. For the Metals sub-segment, total operating costs in 2002 reflected an
increase of more than 25 percent compared to the prior year, mainly due to the
VAW acquisition. Excluding VAW activities, operating costs were down
approximately 14 percent due to lower variable costs principally for raw
materials and energy for the primary aluminium production. During 2002,
electricity prices remained more or less unchanged for the Norwegian smelters
as a result of long-term fixed price contracts. For the former VAW smelters,
electricity costs decreased since power prices of the German and Canadian
smelters are linked to the LME price. Cast house costs per tonne for the
Norwegian smelters and remelter costs decreased approximately 11 percent and 7
percent, respectively, in 2002 from the prior year. This was due to a 3 percent
higher output, lower alloy costs, and the successful implementation of the
improvement programs. Fixed costs (excluding higher fixed costs due to the VAW
acquisition and integration) decreased by approximately 5 percent in 2002
compared to the prior year. The closure of 115




---



##### 



the magnesium plant in Norway and fixed costs reductions related to the smelter
improvement programs were the reason for the lower fixed costs. This more than
offset additional fixed costs related the new remelter in Spain and start-up
costs for the new potline in Sunndal. Rolled Products cost structures vary with the aluminium price and its
product mix. The metal price comprises about 60 percent of total costs.
Compared with 2001, metal prices were lower reflecting the lower LME price. For Extrusion and Automotive, operating cost development was affected by
the acquisition of VAW and Technal, a lower LME, the change in the US
dollarNorwegian kroner exchange rate, and productivity and cost improvements.
Operating cost per tonne declined for the Extrusion sector as a result of
higher productivity, while for the Automotive sector it was due to higher
volumes in 2002 compared to 2001. In the North America sector, higher operating
cost per tonne followed the lower production volume and increased costs from
the start up of the new greenfield remelter. In total, there was a reduction
in staffing of about 430 employees within the Extrusion and Automotive
sub-segment in 2002. This was the main reason for the reduction of fixed costs
of approximately NOK 85 million in 2002 compared to 2001. Operating Income Hydro Aluminiums operating income for 2002 was NOK 1,698 million, an
increase of NOK 1,513 million compared with 2001. Operating income for 2001
included restructuring charges for magnesium of NOK 921 million, of which NOK
261 million related to an impairment loss on plant facilities, and losses on
aluminium options and futures of NOK 545 million. The contribution of VAW and
Technal to Hydro Aluminiums operating income in 2002 was NOK 1,159 million.
Excluding these items, Hydro Aluminiums operating income declined by NOK 1,152
million. Metals operating income in 2002 was NOK 1,690 million, compared to NOK
372 million in the prior year, including NOK 1,015 million for the VAW
activities. Results for 2001 were negatively influenced by the accrual of NOK
660 million for the closure of the Norwegian magnesium plant. Operating income
in 2001 was also impacted by magnesium impairment write-downs of NOK 261
million. Operating income, adjusted for the results from the VAW activities
(including fair value of inventory and integration costs), restructuring costs
and impairment write-downs, decreased by NOK 508 million from 2001. Results
fell mainly due to lower LME prices and a strong Norwegian kroner exchange
rate. In addition, the market premiums, especially for billets used for
extrusion products, were down approximately 20 percent (in US dollars) due to
the weak market situation. Operating income benefited from lower depreciation
of approximately NOK 115 million principally due to the closure of the
magnesium plant. Rolled Products operating income in 2002 decreased by NOK 353 million
from a profit of NOK 58 million in 2001 to a loss of NOK 295 million in 2002.
Adjusting for one-time items (fair value of inventory and
integration/improvement costs), the restated operating level results would have
been an operating loss of NOK 72 million. Weak results were attributable in
part to the negative impact on margins of approximately NOK 200 million due to
the variance in inventory values resulting from falling metal prices. In
addition, Rolled Products results were significantly influenced by the loss in
2002 in the Norwegian rolling mill in Holmestrand, Norway. Holmestrands major
source of aluminium is the European scrap market, which historically has
provided the plant with a margin comparable to that of primary metal. In 2002,
European scrap prices increased relative to the LME price, reducing the scrap
margin in Holmestrand. Furthermore, the ongoing ramp-up of the new thin gauge
mill resulted in low productivity in 2002. Due to the strengthening of the
Norwegian kroner against the euro, revenues declined since Holmestand exports
most of its production to other European countries. Extrusion and Automotives operating income in 2002 was NOK 14 million,
compared with a loss of NOK 228 million in the prior year. Adjusted for the
contribution made by VAW and Technal, operating income was NOK 108 million
higher than the prior year. The main reasons for the improvement were lower
depreciation and amortization and lower impairment costs than in 2001. 116




---



##### 



Starting in 2002, amortization of goodwill was discontinued, which positively
impacted amortization between the periods. The Extrusion and Automotive
business units improved their performance in 2002. Improvements in Extrusions
results were principally due to higher volumes and improved productivity. For
Automotive, the better results were largely attributable to slightly higher
volumes and cost reduction programs. HYDRO AGRI Revenues and Market Conditions Agris total operating revenues were NOK 33,348 million in 2002,
representing a decline of approximately 11 percent compared to the prior year.
The decline primarily resulted from the significant weakening of the US dollar
relative to the Norwegian kroner and the euro during 2002. Much of Agris
business is denominated in or heavily influenced by the US dollar. As a result,
currency changes have a direct impact on revenues and costs. The pricing of the
majority of Agris products (including its European operations) is directly
linked to the US dollar. The depreciation of the US dollar in 2002 had
significant negative effects on revenues. At the same time, variable cost in
the European plants (mainly energy) also declined as a result of the weak US
dollar partly offsetting the reduction in revenues. However, fixed costs in
Europe are, to a large extent, linked to the Norwegian kroner and the euro.
Excluding cost savings and efficiency programs, this implies that an
appreciation of the European currencies against the USD tends to reduce the
competitiveness of the European fertilizer business. The global fertilizer industry continued to experience difficult markets
throughout most of 2002 as a result of low international prices of commodity
products such as urea. In 2002, European fertilizer prices for all major
nitrogen products were strongly influenced by a low international urea price.
Average prices for 2002 remained at USD 109 per metric tonne (fob Middle East),
considered low on a historical basis. European nitrate prices decreased by
approximately 7% in 2002, reducing the nitrate margin to a more normal
historical level. The average price for ammonia was USD 110 per metric tonne
(fob Caribbean), down approximately 20% compared to 2001, reflecting the lower
natural gas prices in the U.S. Total sales of fertilizer increased by 1.2
million tonnes in 2002, an increase of approximately 6% compared to the
previous year. Revenues from industrial gases and chemicals activities declined by
approximately 11% in 2002 due to the strengthening of the Norwegian kroner and
divestment of low performing, non-core activities. Nearly all core activities
experienced volume growth and improvement in 2002. Strong improvements were
achieved within activities relating to environmental products, nitrogen
chemicals and technical ammonium nitrates. Volume of technical ammonium
nitrates for civil explosives increased by approximately 7% compared to the
prior year. Lower global coal production, which represents approximately 70% of
the technical ammonium nitrate market, reduced the demand for explosives.
However, this was offset by increased market share and growth in demand from
other mining industries. Volumes of environmental process chemicals (i.e.,
Nutriox for water treatment and Reduktan for removal of NOX emission) increased
by approximately 9%. The increase related primarily to higher coal consumption
for power generation in Europe (due to lower coal prices), increasing the
demand for Reduktan and new installations at existing customers both for
Nutriox and Reduktan. Sales volumes for industrial gases, a regional business
focusing mainly on Europe, increased approximately 3 percent due to higher
sales of CO2 to the end user and wholesale markets for food processing. Operating Costs Total energy costs declined by approximately NOK 400 million (excluding
currency effects) in 2002 compared to the previous year. Natural gas is the
most important raw material used in the production of ammonia, nitrogen
fertilizer and technical products. Most of Agris natural gas requirements are
purchased from external suppliers. A significant part of the gas used is
purchased under long-term contracts with pricing mechanisms linked to the
development in market prices for gas. Natural gas prices are closely linked to
developments in the crude oil price. However, due to contract
terms and Agris distribution system, gas price changes in Europe are normally
reflected in reported earnings with a time lag of approximately 4-5 months. 117




---



##### 



After the completion of the Agri turnaround program in 2001 (which yielded
manning and fixed cost reductions of approximately 35 percent), efforts to
achieve further productivity improvements continued. In addition to the
approximately NOK 2,400 million in fixed cost reductions realized through this
program, further cost savings (excluding the effects of exchange rates)
amounted to approximately NOK 350 million in 2002. Operating Income Operating income was NOK 2,207 in 2002 compared to NOK 2,114 in the
previous year, an increase of approximately 4 percent. The increase was
primarily the result of lower depreciation charges in 2002, as well as the
charges associated with the write-down of assets in 2001. OTHER
ACTIVITIES Petrochemicals Petrochemicals operating revenues decreased by 21 percent in 2002
compared to 2001. The reduction was primarily due to lower average product
prices, particularly caustic soda and suspension polyvinyl chloride (S-PVC)
prices. Hydros average realized price for caustic soda and S-PVC was
approximately 49 and 6 percent lower, respectively, in 2002 than in 2001.
Operating revenues in 2002 decreased by approximately NOK 290 million as a
result of the sale of Hydros share in Singapore Polymer Corporation (SPC) in
October 2001. Petrochemicals operating loss for 2002 was NOK 35 million compared with
an operating loss of NOK 101 million in 2001. Contributing to the lower
operating loss in 2002 compared to the prior year was the lower purchased raw
material costs, particularly natural gas liquids and ethylene. 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). In addition, the employees have elected alternates and three
observers. 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. 118




---



##### 



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 four times in 2003. Each member or deputy
member and observer of the Corporate Assembly was paid NOK 4,000 per meeting
attended. The Chairperson and the Vice Chairperson of the Corporate Assembly
were paid an additional NOK 65,000 and NOK 32,500, respectively, for serving in
such capacities in 2003. 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. 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 eight meetings in 2003. 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
thirteen meetings in 2003. 119




---



##### 



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
    
    59
    
    Chairperson
    
    2006Borger A. Lenth
    
    Koppang, Norway
    
    66
    
    Deputy Chairperson
    
    2006Elisabeth Grieg
    
    Oslo, Norway
    
    45
    
    Director
    
    2006Håkan Mogren
    
    Stockholm, Sweden
    
    59
    
    Director
    
    2006Ingvild R. Myhre
    
    Oslo, Norway
    
    46
    
    Director
    
    2006Kurt Anker Nielsen(4)
    
    Copenhagen, Denmark
    
    58
    
    Director
    
    2006Geir Nilsen(2)
    
    Skien, Norway
    
    48
    
    Director
    
    2005Odd Semstrøm(2)
    
    Øvre Årdal, Norway
    
    59
    
    Director
    
    2005Terje Friestad(2),(3)
    
    Skudeneshavn, Norway
    
    51
    
    Director
    
    2005
  (1)
    
    The Corporate Assembly elected Mr. Reinås to the Board and
appointed him as Chairperson on March 16, 2004, with effect from March
25, 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 employee representatives in the Corporate Assembly.(3)
    
    The Corporate Assembly elected Mr. Friestad to the Board on March 16,
2004, with effect from March 25, 2004. Mr. Friestad succeeded Steinar
Skarstein, who stepped down from the Board at the time of completion of the
Demerger.(4)
    
    Elected by the Corporate Assembly May 13, 2004 to succeed Anne
Cathrine Høeg Rasmussen. Jan Reinås. Mr. Reinås has served as Chairperson of the Board since March
25, 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 May 2, 2001. Mr. Lenth practices as a lawyer in Oslo, Norway.
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 Naeringsbanken 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 and 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
is also Chairman of Affibody AB and the Swedish-American Foundation, Deputy
Chairman of AstraZeneca PLC, and of Gambro AB, a member of the Board of
Directors of Investor AB, Remy/Cointreau and the Group Danone and a director
for the Marianne and Marcus Wallenberg Foundation. 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 Chief Executive Officer 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, and the business newspaper, Dagens
Naeringsliv. Ms. Myhre serves on the Boards Compensation Committee. 120




---



##### 



Kurt Anker Nielsen. Mr. Nielsen has served as a director since May 13,
2004. Mr. Nielsen served as co-Chief Executive Officer of Novo Nordisk A/S, a
focused healthcare company and a world leader in diabetes care, and Novo A/S
from 2000 to 2003 and as Chief Financial Officer 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. Terje Friestad.Mr. Friestad has served as a director since March 25,
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 June 7, 2004, 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
    
    
    54
    
    
    Executive Vice President and Chief
Financial OfficerAlexandra Bech Gjørv
    
    Oslo, Norway
    
    
    38
    
    
    Executive Vice PresidentTore Torvund
    
    Oslo, Norway
    
    
    52
    
    
    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 May 2, 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, 121




---



##### 



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 March 1, 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
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 January 15, 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 is admitted to the bar in the State of New
York, United States. 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 in
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 February 15, 2001. 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 2003, total remuneration of NOK 2,557,000 was paid to the members of
Hydros Board of Directors, NOK 457,500 to the members of the Corporate
Assembly, NOK 60,000 to the members of the Nomination Committee, NOK 50,000 to
the members of the Boards Compensation Committee and NOK 167,000 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. 122




---



##### 



Director Compensation Arrangements Compensation for Employee Directors In 2003, each of the employee directors (other than Mr. Myklebust)
received, in addition to compensation as an employee, fees of NOK 220,000 for
serving on the Board. Mr. Myklebust, who served as Chairperson of the Board,
received NOK 430,000 for serving on the Board and his salary from Hydro was
reduced correspondingly. Mr. Myklebust received total compensation in 2003 of
NOK 3,792,000. In May 2001, Mr. Myklebust retired as President and Chief
Executive Officer of Hydro and continued to be employed by Hydro in accordance
with his employment contract of 1991. General Compensation Rules for Non-Employee Directors In 2003, each of the directors who are not employees of Hydro received
fees of NOK 220,000 for serving on the Board, except the Deputy Chairperson,
who received NOK 330,000. Compensation of the Chief Executive Officer Mr. Reiten, Hydros President and Chief Executive Officer, received a
salary and other remuneration of NOK 5,123,000 in 2003, including a bonus for
2002 in the amount of NOK 630,000. The Board of Directors decided in its
meeting on June 17, 2004 to increase Mr. Reitens base salary to NOK 4,330,000
effective January 1, 2004. 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 June 17, 2004, that Mr. Reiten was
entitled to a bonus for 2003 of NOK 1,190,000 in accordance with the bonus plan
and targets established earlier. Under Mr. Reitens current employment contract, he
is entitled to retire at 62 years
of age with a pension benefit representing 65 percent of his salary. In the
event his employment terminates, he has the right to salary and the accrual of
pension rights for a three-year period. Hydros obligation can be reduced by
salary received or pension rights accrued from other sources. Mr. Reitens
employment can, under certain conditions, continue after his retirement as
President and Chief Executive Officer. 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 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 those plans may be exercised within a five-year
period, but not before the expiry of three years from the date of grant, their
exercise being conditional on the development of the price of the underlying
shares (including dividends paid) in the three-year period from the date of
grant. 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 either of the
Executive Share Option Plans, the Company fulfills its obligation toward the
option holder by way of a cash bonus 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 undertake to acquire and hold a set number of the Companys
shares from this bonus payment. Eligible participants have been granted options relating to a total of
99,500 Company shares with an exercise price of NOK 351.50 per share under the
2003 Executive Share Option Plan, and a total of 111,000 shares with an
exercise price of NOK 361.90 per share under the 2002 Executive Share Option
Plan. The exercise prices of the options granted under each of the plans have
been adjusted downward by 8.5% (to NOK 321.62 per share under the 2003 plan and
NOK 331.14 per share under the 2002 plan) as a result of the Demerger. 123




---



##### 



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 GrantsPresident and Chief Executive Officer
    
    
    10,000Other members of the Corporate Management Board
    
    
    7,000Other Plan participants
    
    
    2,000-3,500
 Options for all the shares authorized under each of the 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 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 (i.e., March 24, 2004). An option holder may exercise his or her options within six months if such
holders employing company or unit exits the Hydro Group. In connection with
the Demerger, the Compensation Committee decided that options held by employees
being transferred to Yara may be exercised within 6 months from the Completion
Date (i.e., March 24, 2004). On March 24, 2004, members of Yaras management
exercised 20.1% of their options under the now terminated 2001 Executive Share
Option Plan, 76.1% of their options granted under the 2002 Executive Share
Option Plan and 100% of their options granted under the 2003 Executive Share
Option Plan. 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 January 1 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. ITEM 6.C. BOARD PRACTICES The Company adheres to requirements applicable 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. 124




---



##### 



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). 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 30 percent of the ownership of Aon Grieg.
Aon Grieg provided agent services in relation to offshore insurance for Hydro
in 2003 and received NOK 7,415,000 in broker 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 October 12, 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. 125




---



##### 



The Compensation Committee held six meetings in 2003. As of June 17, 2004
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. Audit Committee On November 1, 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 nine meetings in 2003. As of June 17, 2004 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 March 16, 2004, with effect from March
25, 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 May 13, 2004, is an audit committee financial expert, as that
term is defined in SEC rules. The Audit Committee operates in accordance with a mandate approved by the
entire Board. The mandate was revised in June 2003 to meet the new requirements
under the SECs rules to implement relevant provisions of the Sarbanes-Oxley
Act and the then-proposed 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 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. 126




---



##### 



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. In addition, the Audit Committee also reviewed and discussed with
the Companys external
auditors the matters required by Statement on Auditing Standards No. 61
(Codification of Statements on Auditing Standards, AU §380), as amended
(Communication with Audit Committees). The Companys external auditors provided the Audit Committee with the
written disclosures and the letter required by Independence Standards Board
Standard No. 1 (Independence Discussions with Audit Committee). Independence
Standards Board Standard No. 1 requires auditors annually to disclose in
writing all relationships that in their professional opinion may reasonably be
thought to bear on independence, to confirm their independence and to engage in
a discussion of independence. The Audit Committee did, in fact, discuss 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 December 31,
2003 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. In accordance with the SEC rules to implement Section 202 of the
Sarbanes-Oxley Act, an Audit Committee pre-approval policy was prepared during
March-April 2003 and communicated to the Companys external auditors on May 2,
2003. The policy was subsequently approved by the Audit Committee. As
explained more fully below, the pre-approval policy governs 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. 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. 127




---



##### 



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 an annual 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% 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. 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. 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 December 31, 2003, the Group employed approximately 42,900 people,
compared with approximately 49,700 people in 2002, and approximately 35,600
people in 2001. Approximately 29,200 of the Groups employees were located
outside Norway as of December 31, 2003, compared to approximately 35,100 at the
end of 2002 and 20,000 at the end of 2001. The number of people employed in
each segment as of December 31, 2003 is as follows: Business Segment
    
    Number of EmployeesExploration & Production
    
    
    2,800Energy and Oil Marketing
    
    
    665Metals
    
    
    6,276Rolled Products
    
    
    4,259Extrusion and Automotive
    
    
    16,193Agri (1)
    
    
    7,338Other Activities (2)
    
    
    5,380
  (1)
    
    The Agri employees have since been transferred to Yara in
connection with the Demerger.(2)
    
    Other Activities consists of the following: Petrochemicals, Treka
AS (previously A/S Korn- og Foderstof Kompagniet, or KFK), Pronova, the
industrial insurance company, Industriforsikring, Hydro Business
Partner, 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. Generally, Hydro seeks to achieve terms of employment comparable to
that negotiated with the Norwegian employee organizations. 128




---



##### 



ITEM 6.E. SHARE OWNERSHIP The following table sets forth the beneficial ownership of ordinary shares
as of June 11, 2004 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. Name of Beneficial Owner
    
    Shares Beneficially OwnedJan Reinås
    

    NoneBorger A. Lenth
    
    
    144Elisabeth Grieg
    
    
    6,080Håkan Mogren
    
    
    0Ingvild R. Myhre
    
    
    0Kurt Anker Nielsen
    
    
    0Geir Nilsen
    
    
    55Odd Semstrøm
    
    
    129Terje Friestad
    
    
    236Eivind Reiten
    
    
    7,841
    (1)Alexandra Bech Gjørv
    
    
    900John Ove Ottestad
    
    
    8,238Jon-Harald Nilsen
    
    
    270Tore Torvund
    
    
    3,640
    (2)Total number of ordinary shares owned
by all directors and members of
Corporate Management Board as a group
(consisting of 14 persons)
    
    
    27,533
  (1)
    
    Includes 200 shares held by a close family member.(2)
    
    Includes 360 shares held by a close family member. The total number of authorized and issued ordinary shares of the Company
as of December 31, 2003 was 266,596,650. Excluding shares held in treasury as
of December 31, 2003 of 9,884,650, the total number of issued and outstanding
shares was 256,712,000. 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 0.011%. The percentage of outstanding shares held by residents of different
countries as of June 11, 2004, are presented below: Norway
    
    
    65.5
    %United Kingdom
    
    
    13.7
    %United States
    
    
    12.8
    %Other
    
    
    8.0
    %
 129




---



##### 



Option Ownership The following table sets forth the beneficial ownership of options to
acquire ordinary shares as of June 7, 2004 by (i) each director and member of
Corporate Management Board who has served in either of such capacities at any
time since January 1, 2003, and (ii) all such directors and members of the
Corporate Management Board as a group: Number of SharesUnderlying Options
    
    Exercise PriceName
    
    Granted
    
    (NOK/Share)
    
    Expiration Date2002
    
    2003
    
    2002
    
    2003
    
    2002
    
    2003Eivind Reiten
    
    
    10,000
    
    
    
    10,000
    
    
    
    331.14
    
    
    
    321.62
    
    
    June 30, 2007
    
    June 30, 2008John Ove Ottestad(1)
    
    
    7,000
    
    
    
    7,000
    
    
    
    331.14
    
    
    
    321.62
    
    
    June 30, 2007
    
    June 30, 2008Tore Torvund
    
    
    7,000
    
    
    
    7,000
    
    
    
    331.14
    
    
    
    321.62
    
    
    June 30, 2007
    
    June 30, 2008Jon-Harald Nilsen
    
    
    7,000
    
    
    
    7,000
    
    
    
    331.14
    
    
    
    321.62
    
    
    June 30, 2007
    
    June 30, 2008Alexandra Bech Gjørv
    
    
    7,000
    
    
    
    7,000
    
    
    
    331.14
    
    
    
    321.62
    
    
    June 30, 2007
    
    June 30, 2008All directors and
members of the
Corporate Management
Board as a group
    
    
    38,000
    
    
    
    38,000
  (1)
    
    John Ove Ottestad assumed the position of Executive Vice President
and Chief Financial Officer on March 1, 2002. 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 June 11, 2004, the Kingdom owned 115,674,848 ordinary
shares, representing 45.2 percent of the total number of ordinary shares issued
and outstanding as of such date. There are no different voting rights
associated with the ordinary shares held by the Kingdom. As of June 11, 2004,
there were a total of 40,700 registered holders of Hydros shares resident in
Norway. 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 June 11, 2004, JPMorgan Chase Bank, as depositary of the ADSs (the
"Depositary), through its nominee company, Morgan Guaranty Nominees Limited,
held interests in 15,834,815 ordinary shares (approximately 6.2 percent of the
issued and outstanding ordinary shares as of such date) on behalf of 568
registered and an estimated 6,600 beneficial holders of American depositary
receipts (ADRs), evidencing ADSs. There were 330 holders of ordinary shares
with addresses in the United States (not including the Depositary) as of the
same date. These shareholders held 16,915,102 ordinary shares, equal to
approximately 6.6 percent of the issued and outstanding ordinary shares. 130




---



##### 



ITEM 7.B. RELATED PARTY TRANSACTIONS The following table sets forth information regarding loans extended by
Hydro to individuals who have served on the Board of Directors or the Corporate
Management Board since January 1, 2003: Largest Amount
    
    Amount OutstandingOutstanding
    
    as of April 23,During 2003
    
    2004
    
    
    
    
    
    
    
    Remaining(in thousands of
    
    (in thousands of
    
    
    
    
    
    
    
    RepaymentName of Loan Recipient
    
    NOK)
    
    NOK)
    
    Nature of Loan
    
    Interest Rate(1)
    
    Term(2)Odd Semstrøm(3)
    
    
    53
    
    
    
    44
    
    
    Consumer
    
    
    4.0
    %
    
    3 years-Upon terminationGeir Nilsen
    
    
    162
    
    
    
    107
    
    
    Consumer
    
    
    4.0
    %
    
    3 yearsJohn O. Ottestad
    
    
    667
    
    
    
    566
    
    
    Consumer/Mortgage
    
    
    3.25-4.00
    %
    
    3  13 yearsTore Torvund
    
    
    460
    
    
    
    398
    
    
    Consumer/Mortgage
    
    
    3.25-4.00
    %
    
    4  13 yearsJon-Harald Nilsen
    
    
    227
    
    
    
    188
    
    
    Mortgage
    
    
    3.25
    %
    
    8 yearsAlexandra Bech
Gjørv
    
    
    269
    
    
    
    0
    
    
    Consumer/Mortgage
    
    
    
    
    
    Egil Myklebust(4)
    
    
    4,596
    
    
    
    4,562
    
    
    Mortgage
    
    
    2.75-3.25
    %
    
    26.5 years  Upon terminationThorleif Enger
    
    
    690
    
    
    
    0
    
    
    Consumer
    
    
    
    
    
    Terje Friestad
    
    
    17
    
    
    
    6
    
    
    Consumer
    
    
    4.0
    %
    
    8 months
  (1)
    
    Interest rate as of April 23, 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)
    
    As of April 23, 2004, Mr. Myklebust had several mortgage loans,
including an interest-only loan of NOK 2,200,000 bearing interest at
2.75 percent and repayable upon his leaving the Company, a mortgage
loan of NOK 2,115,000 bearing interest at 3.25 percent with a remaining
payment period of 26.5 years and other mortgage loans totaling NOK
247,000 bearing interest at 3.25 percent repayable upon his leaving the
Company. All of these loans are secured by Mr. Myklebusts principal
residence. 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 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. 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. 131




---



##### 



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 Total, the operator for the Kharyaga field located in Northwest Russia,
has received from the Ministry of Taxes and Revenues of the Russian Federation,
a claim for tax and the Russian States share of the revenues from oil
extracted under the Petroleum Sharing Agreement for this field. Hydros share
of the claim is approximately USD 30 million. The claim stems from the
unwillingness of the joint committee for the Kharyaga project 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. 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 has 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. See Item 4.B. Business Overview  Hydro Oil
and Energy  Production, for a description of Hydros interest in the Kharyaga
field. Zero-Rate Electricity Tax The European Free Trade Association (EFTA) Surveillance Authority (ESA)
has commenced a formal investigation procedure against the Norwegian State to
determine if the former zero-rate electricity tax applicable to Norwegian
industry is in accordance with state aid rules included in the European Area
Agreement (the EEA Agreement). The zero-rate tax was extended to all Norwegian
businesses from January 1, 2004. ESA has advised the Norwegian government that
the Norwegian government may be required to recover asserted state aid from
recipient companies if the rules are determined to be incompatible with the EEA
Agreement. The Norwegian government has claimed that the electricity tax system
is of a general nature and not covered by the EEA state aid rules. A decision
by the ESA to require the Norwegian government to recover the value of the
zero-rate tax for the years in question may be appealed to the EFTA court.
Hydro will vigorously oppose any unfavorable decision related to past years and
believes that the Norwegian government will also vigorously oppose such a
decision. Hydro intends to make use of all remedies available, both at the EFTA
and the Norwegian national level. Although no assurances can be provided as to
the ultimate outcome of this matter, Hydros management does not believe that
resolution will have a material adverse effect on results of operations or
financial position. Joint Sale of Natural Gas by NCS Producers In 2001, the European Union competition authorities issued a statement of
objections to Hydro and all other gas producers on the Norwegian Continental
Shelf. The authorities claimed that the joint sale of natural gas by producers
on the Norwegian Continental Shelf, through the Gas Negotiating Committee
(GFU), contravened EU legislation related to competition. The GFU system was
abolished by the Norwegian government on June 1, 2001. Effective July 17, 2002,
Hydro and the European Commission settled the dispute related to the previous
marketing of gas through the GFU. 132




---



##### 



The settlement of the case did not involve any monetary consideration but
required that Hydro make available on commercially competitive terms a total of
2.2 bcm of gas to new customers in the period from June 1, 2001 to September
30, 2005. This is in accordance with the Companys commercial policy and does
not have any adverse affect on operating results. Compliance with the terms of
this settlement arrangement is supervised by an external auditor. Statements
issued by the auditor for the period June 1, 2001  September 30, 2002
demonstrate that the Company sold at least 0.9 bcm of gas to new customers and
an additional 1.2 bcm in the period October 1, 2002  September 30, 2003. In
total, the Company has now fulfilled most of its settlement obligations. All of
the gas has been sold at current market prices. The effective date for closing the case was July 17, 2002. There is no
court ruling of the settlement. European Union law does not require a
settlement in competition cases to be approved by a court in order to be valid.
The Commission simply decides to close a case on the basis of undertakings
agreed by the companies involved. The fact that the case was settled did not
amount to an admittance that Hydro actually had infringed on any EC competition
rules. Dispute as to Allocation of Pension Liabilities As of January 1, 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
January 1, 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. However, on February 17, 2004, the companies with which Hydro was not
able to reach an agreement notified Hydro of the initiation of 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 the negotiations that
preceded the initiation of the arbitration proceeding, these companies agreed
to cover a portion of this amount. Their primary basis for not accepting the
total charge is their interpretation of guidelines adopted by the Norwegian Oil
Industry Association (referred to as the OLF), which have been effective since
January 1, 2001. Hydro disagrees with their interpretation of these guidelines.
Further, Hydro position is that the OLF guidelines cannot alter the
accounting provisions in the joint ventures and accounting agreements between
and among Hydro and the other companies who are parties to the agreements.
Hydro believes that its charging of pension costs to these other companies is
in accordance with the no gain/no loss principle in such accounting agreements. Although no assurance can be provided as to the ultimate outcome of this
matter, Hydros management does not believe that it 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. 133




---



##### 



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. Hydro pays a dividend once a year. The dividend is linked to the previous
years results of operations and is paid to those who are registered as
shareholders at the time of the annual general meeting, usually held in May.
Payment is made approximately two weeks later. 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 December 31, 2003, 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 net interest-bearing debt over time to be equivalent to
half of the Companys equity capital, including minority interests. When
calculating this ratio, consideration is given to off-balance sheet pension
obligations and operational leasing commitments. Share Repurchases In periods of high earnings, the Company will consider a share buy-back in
addition to ordinary dividend payments. Such consideration will be made in
light of alternative investment opportunities available to the Company and its
financial situation. On the basis of these considerations, the Board may
propose to the Corporate Assembly that authorization be given for a repurchase
of shares. An agreement has been signed with the Norwegian State, represented
by the Ministry of Trade and Industry, to take appropriate action ensuring that
the States ownership interest will remain unchanged if the aim of a repurchase
is to cancel the shares. In 2003, the annual general meeting authorized the buy-back of up to
2,808,810 of the Companys shares in the market with the intention to cancel
the shares through a capital reduction. The Norwegian State agreed to
participate in the redemption and cancellation of a proportional number of
shares. During 2003, the Company purchased 1,484,300 of its shares at an
average price of NOK 373.85 per share. In January of 2004, an extraordinary
general meeting approved a capital reduction by cancellation of the 1,484,300
treasury shares acquired in 2003. The extraordinary general meeting also
authorized the redemption of 1,157,922 shares owned by the Norwegian State for
an aggregate amount of approximately NOK 445 million, corresponding to
approximately NOK 374 per share. These shares were redeemed and cancelled on
March 17, 2004. The per share redemption price was based on the
volume-weighted average of the price paid for the 1,484,300 shares purchased in
the market. The Company also paid the Norwegian State an interest equivalent
of NIBOR plus one percent to compensate the State for receiving payment for its
shares at a later date than those selling shares in the market. 134




---



##### 



The annual general meeting held in May 2004 approved the Boards proposal
to replace the remaining part of the existing share buy-back authorization with
a new authorization (such authorization being effective for a period of 18
months) to buy-back up to 2,808,810 of the Companys shares in the market, with
the intention to cancel the shares through a capital reduction. The Norwegian
State has agreed to participate in the redemption and cancellation of a
proportional number of shares on the same basis as agreed in 2003. The States
ownership share will, therefore, remain unaffected by the buyback and
cancellation. In total, up to 5 million shares may be cancelled, equivalent to
approximately two 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. In accordance with
the new authorization Hydro initiated the share buy-back program and, on June
8, 2004, purchased 80,000 of its shares at an average price of NOK 431.72 per
share. 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. At the end of 2003, the Company held 8,400,350 of
such shares in treasury. The total number of treasury shares at the end of
2003, including the shares bought with the purpose of cancellation, was
9,884,650. Following the purchase of 653,000 shares during June 2004, Hydro
holds 8,768,198 treasury shares. ITEM 8.B. SIGNIFICANT CHANGES There have been no significant changes in Hydros results of operations,
financial condition or business prospects since December 31, 2003, other than
as a result of the Demerger. 135




---



##### 



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  Composite Tape. Five Most Recent Fiscal Years Oslo Stock Exchange
    
    New York Stock ExchangeHigh
    
    Low
    
    High
    
    LowYear
    
    (in NOK)
    
    (in NOK)
    
    (in US Dollars)
    
    (in US Dollars)1999
    
    
    371.00
    
    
    
    245.00
    
    
    
    465/8
    
    
    
    323/42000
    
    
    415.00
    
    
    
    296.50
    
    
    
    453/8
    
    
    
    351/22001
    
    
    404.00
    
    
    
    310.00
    
    
    
    44.90
    
    
    
    35.002002
    
    
    441.00
    
    
    
    273.00
    
    
    
    52.30
    
    
    
    37.052003
    
    
    415.00
    
    
    
    262.00
    
    
    
    62.09
    
    
    
    35.90
 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 2002
    
    
    432.00
    
    
    
    364.00
    
    
    
    48.50
    
    
    
    40.60Second quarter 2002
    
    
    441.00
    
    
    
    346.00
    
    
    
    52.30
    
    
    
    46.60Third quarter 2002
    
    
    367.00
    
    
    
    276.00
    
    
    
    48.54
    
    
    
    37.10Fourth quarter 2002
    
    
    316.00
    
    
    
    273.00
    
    
    
    45.25
    
    
    
    37.05First quarter 2003
    
    
    317.50
    
    
    
    262.00
    
    
    
    45.83
    
    
    
    35.90Second quarter 2003
    
    
    376.00
    
    
    
    270.00
    
    
    
    51.90
    
    
    
    37.55Third quarter 2003
    
    
    397.50
    
    
    
    339.00
    
    
    
    53.94
    
    
    
    45.90Fourth quarter 2003
    
    
    415.00
    
    
    
    359.50
    
    
    
    62.09
    
    
    
    52.10First quarter 2004
    
    
    472.65
    
    
    
    367.71
    
    
    
    66.84
    
    
    
    54.19
 Most Recent Six Months Oslo Stock Exchange
    
    New York Stock ExchangeHigh
    
    Low
    
    High
    
    LowMonth
    
    (in NOK)
    
    (in NOK)
    
    (in US Dollars)
    
    (in US Dollars)December 2003
    
    
    415.00
    
    
    
    384.50
    
    
    
    62.09
    
    
    
    57.13January 2004
    
    
    456.50
    
    
    
    410.00
    
    
    
    67.85
    
    
    
    61.07February 2004
    
    
    506.50
    
    
    
    427.50
    
    
    
    73.73
    
    
    
    60.61March 2004
    
    
    527.00
    
    
    
    429.50
    
    
    
    74.75
    
    
    
    68.32April 2004
    
    
    467.00
    
    
    
    402.50
    
    
    
    70.67
    
    
    
    54.92May 2004
    
    
    426.00
    
    
    
    395.00
    
    
    
    63.08
    
    
    
    56.11
 Source: Bloomberg There were 330 holders of ordinary shares with addresses in the United
States (not including the Depositary) as of June 11, 2004. These shareholders
held 16,915,102 ordinary shares, equal to approximately 6.6 percent of the
issued and outstanding ordinary shares. As of June 11, 2004, a total of
15,834,815 ADSs (representing approximately 6.2 percent of the issued and
outstanding ordinary shares) were held by 568 registered and approximately
6,600 beneficial holders of ADSs. 136




---



##### 



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,
Düsseldorf, Frankfurt, Hamburg, London and Paris. The Board of Directors
approved delisting of the Companys shares from the Stockholm stock exchange
effective March 25, 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. 137




---



##### 



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 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. 138




---



##### 



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: 266,596,650 ordinary shares, nominal value NOK 20 per share, of which
256,712,000 ordinary shares were outstanding as of December 31, 2003. All
outstanding ordinary shares are validly issued, fully paid and nonassessable.
In January 2004, an extraordinary General Meeting approved a capital reduction
by cancellation of 1,484,300 treasury shares acquired in 2003 as part of a
buy-back program approved by the 2003 annual general meeting. The general
meeting also authorized the redemption of 1,157,922 shares owned by the
Norwegian State. The cancellation of the shares took place on March 17, 2004.
See Item 8.A. Consolidated Financial Statements and Other Financial
Information  Share Repurchases. In addition, the general meeting approved the Demerger Plan for the
separation of the Agri business. The Demerger was accomplished on March 24,
2004, which resulted in a reduction of the nominal share value to NOK 18.30 per
share. 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. 139




---



##### 



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 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. 140




---



##### 



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 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. 141




---



##### 



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.
    
    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. 142




---



##### 



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. 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 rata
basis 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. 143




---



##### 



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 stock repurchase plan by the company; 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. 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 or 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 144




---



##### 



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. 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 October 1, 1987, as amended by
Amendment No. 1, dated May 27, 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. 145




---



##### 



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 146




---



##### 



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
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 147




---



##### 



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. 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 148




---



##### 



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. 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 149




---



##### 



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 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. Hydro is of the view that,
with the exception of the Demerger Plan, all material contracts entered into by
the Company or any member of the Group during this time period have been
entered into in the ordinary course of business. 150




---



##### 



ITEM 10.D. EXCHANGE CONTROLS Under Norwegian foreign exchange controls currently in effect, transfers
of capital to and from Norway are not subject to prior government approval
except for the physical transfer of payments in currency, which is restricted
to licensed banks. Thus, non-Norwegian resident shareholders may receive
dividend payments without a Norwegian exchange control consent as long as the
payments are made through a licensed bank. 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 151




---



##### 



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. 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 December 31, 2002, and before January 1,
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 in the current or future taxable years. 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. The U.S. Department of the Treasury and the Internal Revenue Service
expect to issue regulations providing procedures for a foreign corporation to
certify that it is a qualified foreign corporation. 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. The Company anticipates certifying that it is a qualified foreign
corporation for the year ending December 31, 2004. 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. 152




---



##### 



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. 153




---



##### 



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
December 31, 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 Internal Revenue Service Form
8621. Backup Withholding and Information Reporting Dividend payments, or other taxable distributions, made within the United
States to a noncorporate 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 Internal Revenue Service 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. 154




---



##### 



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 Internal Revenue Service 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 U.S. Internal Revenue Service. 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. 155




---



##### 



ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Quantitative and qualitative information about market risk as of December
31, 2003 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. 156




---



##### 



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. 157




---



##### 



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 SEC rules define an audit
committee financial expert as a person who has the following attributes:  
    
    an understanding of generally accepted accounting principles (in
the Companys case, this refers to US GAAP) and financial statements;
    
    the ability to assess the general application of such principles in
connection with the accounting for estimates, accruals and reserves;
    
    experience preparing, auditing, analyzing or evaluating financial
statements that present a breadth and level of complexity of accounting
issues that are generally comparable to the breadth and complexity of
issues that can reasonably be expected to be raised by the registrants
financial statements, or experience actively supervising one or more
persons engaged in such activities;
    
    an understanding of internal controls over financial reporting; and
    
    an understanding of audit committee functions. The SECs rules provides that an audit committee financial expert shall
have acquired the above attributes through, among other things, education and
experience as a principal financial officer, principal accounting officer,
controller, public accountant or experience in one or more positions that
involve the performance of similar functions. As noted in Mr. Nielsens
biographical information included in Item 6.A, Mr. Nielsen served as the Chief
Financial Officer of Novo Nordisk A/S and Novo A/S from 1989 to 2000. 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 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 filed as Exhibit 11 to this annual report. In addition, the
Code of Conduct has been posted on Hydros website (www.hydro.com). 158




---



##### 



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 December 31, 2003 and 2002. Year ended December 31, 2003 Audit
    
    Otherrelated
    
    non-auditAmounts in NOK thousand
    
    Audit fees
    
    Fees(2)
    
    Fees(3)
    
    Tax fees(4)
    
    TotalDeloitte Norway(1)
    
    
    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
    
    
    16,998
    
    
    
    1,797
    
    
    
    7,808
    
    
    
    5,198
    
    
    
    31,801Others
    
    
    11,096
    
    
    
    2,941
    
    
    
    1,296
    
    
    
    2,677
    
    
    
    18,010Total fees
    
    
    87,079
    
    
    
    9,488
    
    
    
    19,036
    
    
    
    12,103
    
    
    
    127,706
 Year ended December 31, 2002 Audit
    
    Otherrelated
    
    non-auditAmounts in NOK thousand
    
    Audit fees
    
    Fees(2)
    
    Fees(3)
    
    Tax fees(4)
    
    TotalDeloitte Norway
    
    
    19,366
    
    
    
    5,092
    
    
    
    10,157
    
    
    
    485
    
    
    
    35,100Deloitte Abroad
    
    
    27,588
    
    
    
    9,505
    
    
    
    14,419
    
    
    
    8,915
    
    
    
    60,427Total Deloitte
    
    
    46,954
    
    
    
    14,597
    
    
    
    24,576
    
    
    
    9,400
    
    
    
    95,527Ernst & Young
    
    
    15,682
    
    
    
    405
    
    
    
    4,213
    
    
    
    842
    
    
    
    21,142Others
    
    
    3,735
    
    
    
    6,812
    
    
    
    554
    
    
    
    200
    
    
    
    11,301Total fees
    
    
    66,371
    
    
    
    21,814
    
    
    
    29,343
    
    
    
    10,442
    
    
    
    127,970
  (1)
    
    Approximately NOK 4 million related to the Demerger.(2)
    
    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.(3)
    
    Other non-audit fees primarily consist of consulting projects that
were covered under the grandfather clauses of the relevant SEC
regulations and agreed-upon procedures associated with the Companys
environmental and sustainability reporting.(4)
    
    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. 159




---



##### 



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 December 31, 2003 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 Statements The following are filed as part of this annual report onForm 20-F: Schedule VIII  Valuation and qualifying accounts and reserves  page
162 The following is included in Exhibit 10 to this annual report on Form
20-F: Pages *Independent
Auditors ReportConsolidated income statements for the years ended
December 31, 2003, 2002, and 2001
    
    88Consolidated statements of comprehensive income for the
years ended December 31, 2003, 2002, and 2001
    
    88Consolidated balance sheets at December 31, 2003 and 2002
    

    89Consolidated statements of cash flows for the years ended
December 31, 2003, 2002, and 2001
    
    90Notes to the Consolidated Financial Statements
    
    93-128
 * Page references are to the page numbering in Exhibit 10 160




---



##### 



b. Exhibits Exhibit No.
    
    Description1.
    
    The Companys Articles of Association (as amended and currently in
effect)8.
    
    Significant Subsidiaries of the Company10.
    
    Consolidated Financial Statements (including the notes thereto)11.
    
    Code of Conduct12.1
    
    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)
 161




---



##### 



Norsk Hydro ASA and Subsidiaries Schedule VIII  Valuation and Qualifying Accounts and Reserves
 (Amount in NOK million) AdditionsBalance at
    
    Charged tobeginning of
    
    costs and
    
    Charged to
    
    
    
    
    
    Balance at endDescription
    
    period
    
    expenses
    
    other accounts
1)
    
    Deductions 2)
    
    of periodYear-end December 31, 2003Allowance for doubtful accounts
    
    
    1,102
    
    
    
    909
    
    
    
    165
    
    
    
    (692
    )
    
    
    1,484Restructuring allowance
    
    
    304
    
    
    
    
    
    
    
    1
    
    
    
    (157
    )
    
    
    148Environment
accruals 3)
    
    
    5,344
    
    
    
    654
    
    
    
    127
    
    
    
    (414
    )
    
    
    5,711Year-end December 31, 2002Allowance for doubtful accounts
    
    
    1,138
    
    
    
    463
    
    
    
    (131
    )
    
    
    (368
    )
    
    
    1,102Restructuring allowance
    
    
    724
    
    
    
    (10
    )
    
    
    (36
    )
    
    
    (374
    )
    
    
    304Environment accruals
    
    
    2,379
    
    
    
    348
    
    
    
    497
    
    
    
    (298
    )
    
    
    2,926Year-end December 31, 2001
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,138Allowance for doubtful accounts
    
    
    970
    
    
    
    413
    
    
    
    (31
    )
    
    
    (214
    )
    
    
    1,138Restructuring allowance
    
    
    117
    
    
    
    700
    
    
    
    (3
    )
    
    
    (90
    )
    
    
    724Environment accruals
    
    
    2,228
    
    
    
    424
    
    
    
    (12
    )
    
    
    (261
    )
    
    
    2,379
  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 restructuring allowances and environmental accruals.3)
    
    Hydro implemented the new accounting standard for asset retirement
obligations, such as decommissioning and abandonment of oil and gas
production platforms, facilities and pipelines [SFAS 143] beginning
January 1, 2003. The new accounting standard requires that the fair value
of future asset retirement obligations be recorded in Hydro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. As a result of the new
accounting standard, a positive after-tax effect of NOK 310 million was
recorded as cumulative effect of change in accounting principles in
Hydros results for the first quarter of 2003. The changes also resulted
in an increase in the capitalized value of fixed assets by NOK 1,101
million. The increase in the original cost of fixed assets was NOK 1,932
million and related accumulated depreciation was NOK 831 million. In
addition, liabilities for asset retirement obligations increased NOK 2,418
million to NOK 4,549 million, and the deferred tax obligation increased
NOK 465 million. The Norwegian States share of abandonment costs is
equivalent to the corresponding taxation rate during the assets
production period. This was accounted for as a long-term receivable of NOK
2,092 million. Provision for abandonment obligations in previous periods
was recorded net of the Norwegian States share. In accordance with SFAS
143, the abandonment obligation is recorded on a gross basis, and the
Norwegian States share is recorded as a receivable in the balance sheet. 162




---



##### 



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: June 30, 2004
    
    /s/ John O. OttestadJohn O. OttestadExecutive Vice President andChief Financial Officer
 163




---



##### 



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Completion Date
    
    The date the Demerger was consummated by registration in the
Register of Business Enterprises (i.e., March 24, 2004)Consolidated Financial
Statements
    
    The consolidated financial statements and notes included in the
Companys annual report to shareholders for the year ended
December 31, 2003, 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Demerger
    
    The Companys demerger of its Agri business
 164




---



##### 



Term
    
    DefinitionDemerger Plan
    
    The plan approved by the Boards of Directors of Norsk Hydro ASA
and Yara International ASA on November 28, 2003 relating to the
demerger by the Company of its Agri businessDeposit Agreement
    
    Deposit Agreement, dated as of January 3, 1986, as amended and
restated as of October 1, 1987, and as further amended by
Amendment No. 1 thereto, dated May 27, 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 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)Global Offering
    
    The Companys offering of half of the Yara shares held by the
Company following the completion of the Demerger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 Agri
    
    That part of Hydros business that was a core business area prior
to the transfer to Yara International ASA of the assets, rights
and liabilities primarily related to Hydros fertilizer activities
in the DemergerHydro Aluminium
    
    The aluminium business of Hydro, comprising the sub-segments
Metals, Rolled Products, and Extrusion and Automotive
 165




---



##### 



Term
    
    Definition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Offer Price
    
    The offer price for the Yara shares offered in the Global Offering
(i.e., NOK 41 per share)OPEC
    
    Organization of the Petroleum Exporting CountriesOver-Allotment Option
    
    The option, granted by the Company to the managers of the Global
Offering, to purchase some or all of the remaining shares of Yara
held by the Company following the completion of the Demergerordinary share
    
    Ordinary share, par value NOK 18.30 per share, of the Company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
 166




---



##### 



Term
    
    DefinitionSarbanes-Oxley Act
    
    The U.S. Sarbanes-Oxley Act of 2002SDFI
    
    The Norwegian States Direct Financial Interest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
 167