UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 20-F

OR

For The Fiscal Year Ended December 31, 2003

OR

For the transition period from                                        to                                       

Commission file number: 1-9159

NORSK HYDRO ASA

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

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.

Indicate by check mark which financial statement item the registrant has elected to follow.

TABLE OF CONTENTS

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     In the following discussion, references to “Hydro” or the “Company” are to Norsk Hydro ASA or Norsk Hydro ASA and its consolidated subsidiaries, as the context requires. References to the “Group” are to Norsk Hydro ASA and its consolidated subsidiaries. References to the “Kingdom” are to the Kingdom of Norway. The glossary found immediately after the signature page of this annual report provides the definitions of certain other terms used throughout this annual report. In addition, the definitions of oil and gas terms, including terms defined in applicable regulations and Industry Guide 2 (“Disclosure of Oil and Gas Operations”) of the U.S. Securities and Exchange Commission (the “SEC”), can be found in Item 4.B. of this annual report at the end of the business description for the Exploration and Development sub-segment of Hydro Oil and Energy.

EXCHANGE RATE INFORMATION

     The Company publishes its consolidated financial statements in Norwegian kroner (“NOK”). In this annual report, references to “US dollar,” “US dollars,” “USD” “US$” or “$” are to United States dollars. The following tables set forth, for the periods indicated, certain information concerning the exchange rate of Norwegian kroner for USD 1.00, based on the noon buying rate in the City of New York for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York (the “Noon Buying Rate”):

     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.”

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PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

     In accordance with the instructions to Form 20-F, the Company does not need to provide the information called for by Item 1 if, as is the case in this instance, the Form 20-F is being filed as an annual report under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

     In accordance with the instructions to Form 20-F, the Company does not need to provide the information called for by Item 2 if, as is the case in this instance, the Form 20-F is being filed as an annual report under the Exchange Act.

ITEM 3. KEY INFORMATION

ITEM 3.A. SELECTED CONSOLIDATED FINANCIAL DATA

     The following financial information with respect to the five years ended 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.

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Income Statement Data ⁽¹⁾

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Balance Sheet Data ⁽¹⁾

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Segment Data

     The following table indicates the Group’s operating revenues, sales to unaffiliated customers and operating income (after eliminating inter-segment sales) by business segment for each of the three fiscal years in the period ended December 31, 2003.

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ITEM 3.B. CAPITALIZATION AND INDEBTEDNESS

     In accordance with the instructions to Form 20-F, the Company does not need to provide the information called for by Item 3.B. if, as is the case in this instance, the Form 20-F is being filed as an annual report under the Exchange Act.

ITEM 3.C. REASONS FOR THE OFFER AND USE OF PROCEEDS

     In accordance with the instructions to Form 20-F, the Company does not need to provide the information called for by Item 3.C. if, as is the case in this instance, the Form 20-F is being filed as an annual report under the Exchange Act.

ITEM 3.D. RISK FACTORS

     In order to utilize the “safe harbor” provisions of the United States Private Securities Litigation Reform Act of 1995, Hydro is providing the following cautionary statement:

     This annual report contains (and oral communications made by or on behalf of Hydro may contain) forecasts, projections, estimates, statements of management’s plans, objectives and strategies for Hydro, such as planned expansions, investments or other projects, targeted production volumes, capacities or rates, start-up costs, cost reductions, profit objectives, and various expectations about future developments in Hydro’s markets (particularly prices, supply and demand, and competition), results of operations, margins, risk management and so forth. These forward-looking statements are based on a number of assumptions and forecasts, including world economic growth and other economic indicators (including rates of inflation and industrial production), trends in Hydro’s key markets, and global oil and gas, and aluminium supply and demand conditions. By their nature, forward-looking statements involve risk and uncertainty and various factors could cause Hydro’s actual results to differ materially from those projected in a forward-looking statement or affect the extent to which a particular projection is realized. The following paragraphs address important factors that may cause actual results or developments to differ materially from those expressed or implied by the forward-looking statements.

Risks Relating to Hydro’s Oil and Energy Business

Hydro Oil and Energy’s future performance depends on the ability to find 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.”

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     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:

     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.

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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.

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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.

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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.

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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.

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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.

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ITEM 4. INFORMATION ON THE COMPANY

ITEM 4.A. HISTORY AND DEVELOPMENT OF THE COMPANY

Historical Overview

     Norsk Hydro ASA was organized under Norwegian law as a public company in 1905 to utilize Norway’s large hydroelectric energy resources for the industrial production of nitrogen fertilizers. In the years since, energy, in the form of hydroelectric power, natural gas and petroleum, has been the basis for Hydro’s growth and the common link among its core business activities.

     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

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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.

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     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.

     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.

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     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.

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     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

     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.

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“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:

     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 16^th Concession Round on the NCS, has resulted in high exploration budgets, reaching an all time high of around NOK 2.4 billion for 2002.

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     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.

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     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

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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.

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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

In Process Drilling Activities

     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.

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          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.

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Oil and Gas Reserves

          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.

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Development

Fields under Development⁽¹⁾

          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 Lange gas 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

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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 Kvitebjørn gas 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 Kristin oil 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 Snøhvit field 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 Skirne and Byggve gas 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

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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.

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          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⁾

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     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 field began 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 field began 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 field began 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 Øst and Sygna fields 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 Øst in late 1993 and from Sleipner Vest in the middle of 1996. Production from the satellite fields, Gungne, Loke Trias and 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.

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          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, Rimfaks and 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

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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 Girassol field 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 Jasmim field is a sub-sea satellite connected to the Girassol field. Production started in November 2003.

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          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 Hibernia field came on stream in November 1997. Hydro has a five percent interest in the field. The Terra Nova field is southeast of Hibernia and started production in January 2002. Hydro has a working interest of 15 percent.

          Russian Fields. The Kharyaga field is located in Northwest Russia. Production commenced in October 1999 under the Production Sharing Agreement (PSA) entered into with the Russian authorities. Hydro’s share in the PSA is 40 percent. Production from phase 2 of the project has been gradually phased in since May 2003. A third phase is planned to further increase the total production from 2007.

          Libyan Fields. Production from the Mabruk West field in the north of Libya 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.

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          The Sture terminal 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.

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Definitions of Oil and Gas Terms

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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:

          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

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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

          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.

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          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.

     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.

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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 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.

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     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.

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.

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          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.

          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.

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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:

          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 18^th was announced for application in December 2003) and through separate rounds covering a defined area.

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          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

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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.

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          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, 1^st 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.

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          On June 26, 2003, the European Parliament and the Council of the European Union adopted Directive 2003/55/EC (2^nd 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:

          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

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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:

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,

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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.

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          Under a tax/royalty regime, the companies are granted licenses by the government to extract petroleum, and the state may be entitled to royalties, in addition to income tax based on the contractor’s net income from the operations. The terms are, in general, not negotiable and are subject to legislative change.

          Canada. The fiscal regime consists of both royalty and provincial/federal tax systems. There are generic royalty regimes for the Grand Banks and Scotian Shelf areas; however, the Hibernia and Terra Nova fields have unique royalty systems. An allowance of 25 percent of operating income is deductible for income tax purposes, and replaces the actual royalty paid. This allowance will be phased out by 2007 and replaced by full deductibility of royalties paid for income tax purposes. The East Coast royalty regimes are progressive with the size of the royalty depending on the field’s economy and life cycle. Tax depreciation of facilities is 25 percent per year based on a declining balance method of depreciation. Exploration expenses may be fully written off. The combined Canadian federal and provincial tax rates are declining and will be reduced from the current 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

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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:

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          The graph below depicts Hydro Aluminium’s aluminium operations, in terms of 2003 tonnage along the value chain.

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.

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          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:

          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:

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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.

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          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.

          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.

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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).

          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).

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          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.

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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:

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

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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:

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          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

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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.

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     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:

          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

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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.

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          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.

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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.

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          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:

          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.

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          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: Technal^TM, Wicona^TM and Domal^TM.

          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.

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          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.

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          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

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“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.

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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.