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 14 March 2005 was NOK 6.12 = $1.00.

     Fluctuations in the exchange rate between the Norwegian kroner and the US dollar will affect the US dollar equivalent of the Norwegian kroner price of the Company’s ordinary shares on the Oslo Stock Exchange and, as a result, are likely to affect the market price of the Company’s ordinary shares represented by American depositary shares (“ADSs”) in the United States. Such fluctuations could also affect the US dollar amounts received by holders of ADSs on conversion of cash dividends, paid by the Company in Norwegian kroner, on the ordinary shares represented by the ADSs. See Item 3.A. “Selected Consolidated Financial Data” and Item 10.B. “Articles of Association – Description of American Depositary Receipts – Dividends and Other Distributions.”

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PART I

ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

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

ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE

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

ITEM 3. KEY INFORMATION

ITEM 3.A. SELECTED CONSOLIDATED FINANCIAL DATA

     The following financial information with respect to the five years ended 31 December 2004, 2003, 2002, 2001 and 2000 has been derived from Hydro’s audited consolidated financial statements prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The financial information for the three years ended 31 December 2004, 2003 and 2002 should be read in conjunction with and is qualified in its entirety by reference to the consolidated financial statements and notes included in the Company’s annual report to shareholders for the year ended 31 December 2004 (the “Consolidated Financial Statements”), included in Exhibit 10 to this annual report on Form 20-F.

     The Company’s agri business was transferred to Yara International ASA on 24 March 2004 in a demerger transaction. Results, assets and liabilities of the transferred operations relating to periods prior to demerger are reported respectively under “Income from discontinued operations”, “Assets of discontinued operations” and “Liabilities of discontinued operations”.

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Segment Data

     The following table indicates the Group’s operating revenues, sales to unaffiliated customers and operating income (after eliminating inter-segment sales) by business segment for each of the three fiscal years in the period ended 31 December 2004.

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ITEM 3.B. CAPITALIZATION AND INDEBTEDNESS

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

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

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

ITEM 3.D. RISK FACTORS

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

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

Risks Relating to Hydro’s Oil and Energy Business

Hydro Oil and Energy’s future performance depends on the ability to find or gain access to additional oil and gas reserves that are economically recoverable.

     The majority of Hydro Oil and Energy’s proved reserves (92 percent as of 31 December 2004) are located on the Norwegian Continental Shelf (the “NCS”). The southern part of the NCS (the location of the most easily accessible and exploitable fields offshore Norway) is a maturing resource province from which reserve additions have been low in recent years. Norway’s oil production has been declining for the last two years. See the discussion in Item 4.B. “Business Overview – Hydro Oil and Energy – Exploration and Production – Oil Industry Trends – Reduced Exploration Results Worldwide and Maturing Areas in the Developed World –the NCS”

     Unless Hydro Oil and Energy conducts successful exploration and development activities or acquires properties containing proved reserves, or both, its proved reserves will decline as reserves are produced. Because of limited access to major new exploration provinces, and increased price expectations, the bidding for available properties and prospects has intensified. In addition, Hydro Oil and Energy may not succeed in exploiting competencies and skills developed on the NCS in more remote areas. Hydro Oil and Energy’s future production is dependent upon its success in finding or acquiring, and developing, additional reserves.

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Hydro Oil and Energy’s development projects and operations involve many uncertainties and operating risks that can prevent Hydro from realizing profits and can cause substantial losses.

     As fields on the NCS mature and demonstrate a decline in production, Hydro Oil and Energy is seeking to get more production from NCS fields in which it already has an interest and increasingly developing smaller satellite fields. Other Hydro Oil and Energy development projects are in remote locations with limited operational histories and, consequently, the success of these projects is less predictable. In addition, some of Hydro Oil and Energy’s development projects are located in deep-water or other hostile environments, such as areas on the NCS, the US Gulf of Mexico and Angola, or produced from challenging reservoirs. Planning and development of the Ormen Lange field, for example, has been described as one of the most challenging assignments any oil company has tackled, not just in Norway but in a global context, given the combination of deep-water, harsh weather conditions, freezing water temperatures and the need to transport gas for processing over long distances and a very uneven seabed.

     The production of oil and natural gas is vulnerable to weather conditions, operator error or other incidents, which can result in oil spills, gas leakages, equipment failure, unplanned maintenance stops, loss of well control or other occurrences disrupting the production and potentially causing harm to the environment.

     As a result, Hydro Oil and Energy may face increased challenges maintaining targeted levels of production and production growth in future years. This could negatively affect Hydro’s results of operations and financial condition.

A substantial or extended decline in oil or natural gas prices would have a material adverse effect on Hydro Oil and Energy’s business.

     Historically, prices for oil and natural gas have fluctuated widely in response to changes in many factors, including:

     Notwithstanding current high oil prices, it is impossible to predict future oil and natural gas price movements. Declines in oil and natural gas prices will reduce Hydro Oil and Energy’s financial results. Based on Hydro’s analysis of indicative price and currency sensitivities included in this annual report (see Item 5. “Operating and Financial Review and Prospects – Risk Management”), a USD 1 decline in oil prices will reduce Hydro Oil and Energy’s pre-tax income and after-tax income by approximately NOK 1,150 million and NOK 310 million, respectively.

Hydro Oil and Energy is exposed to foreign currency exchange rate fluctuations.

     Oil prices are denominated in US dollars while operating results are reported in Norwegian kroner. Accordingly, operating results will, in general, decline when the Norwegian kroner strengthens against the U.S. dollar. Based on Hydro’s analysis of indicative price and currency sensitivities included in this annual report (see Item 5. “Operating and Financial Review and Prospects – Risk Management”), a strengthening of the Norwegian kroner against the US dollar of NOK 1 per US$1.00 will reduce Hydro Oil and Energy’s pre-tax income and after-tax income by approximately NOK 7,250 million and NOK 1,960 million, respectively.

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Hydro Oil and Energy’s oil and gas reserves are only estimates and may prove inaccurate.

     There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond the control of the producer. The reserve data included in this annual report represent only Hydro’s estimates; the estimates of other companies with interests in the same oil and gas field or fields may differ and the magnitude of the differences may be substantial. This reflects the degree to which reservoir engineering is a subjective and inexact process, requiring the estimate of underground accumulations of oil and natural gas that cannot be measured in an exact manner. Evaluating properties for their recoverable reserves of oil and natural gas entails the assessment of geological, engineering and production data, some or all of which may prove to be unreliable. Accordingly, reserve estimates may be subject to downward or upward adjustment. See the discussion in Item 5. “Operating and Financial Review and Prospects – Hydro’s Critical Accounting Policies – Proved Oil and Gas Reserves.” Actual production, revenues and expenditures with respect to Hydro Oil and Energy’s reserves will likely vary from estimates, and those variances may be material. Any downward adjustment in Hydro Oil and Energy’s reserve data could lead to lower future production, which would negatively affect Hydro’s results of operations and financial condition.

Hydro may be subject to the imposition of sanctions by the U.S. government in connection with its activities in Iran and/or Libya.

     Hydro Oil and Energy is engaged in certain activities in Iran and has an interest in oil and gas exploration licenses in Libya, where exploratory and appraisal wells are in the process of being drilled and limited production has commenced. In August 1996, the United States adopted the Iran and Libya Sanctions Act of 1996 (the “Sanctions Act”) with the objective of denying Iran and Libya the ability to support acts of international terrorism and fund the development and acquisition of weapons of mass destruction. The Sanctions Act provides that the President of the United States is to impose two or more sanctions against any person, regardless of nationality, if the President determines that the person, with actual knowledge, made an investment of US$ 20 million or more in any 12-month period in Iran or Libya that “directly and significantly” contributed to the enhancement of Iran’s or Libya’s ability to develop its petroleum resources.

     In April 2004, the Bush administration announced the termination of application of the Sanctions Act with respect to Libya, though it is unclear whether the waiver has retroactive effect. The Sanctions Act continues in force with respect to Iran. Hydro presently has no assets under development or in production in Iran, suggesting that there may be minimal risk of application of the Sanctions Act with respect to Hydro’s existing activities in Iran. However, no sanctions have ever been imposed against any person or entity under the Sanctions Act. This makes it difficult for Hydro to predict the political and other policy considerations that would prompt the U.S. government to apply the Sanctions Act. Should the U.S. government determine that a violation of the Sanctions Act exists or has occurred, the Sanctions Act provides for sanctions that include a ban on the issuance of a license to export goods or technology to a sanctioned person, the prohibition of loans or extensions of credit by U.S. financial institutions to a sanctioned person, and restrictions on imports into the United States from a sanctioned person.

Hydro Oil and Energy’s expansion of business in emerging and transitioning markets presents a higher degree of financial, political, economic and business risk

     Hydro Oil and Energy is exposed to general financial, political, economic and business risks in connection with its international exploration, development and production activities, with the degree of risk being generally higher in emerging and transitioning markets such as Angola and Russia.

     For example, the government of Angola is in the process of enacting a new foreign exchange law to supersede the current regime that Hydro and other foreign oil companies are operating under. The proposed law would require foreign oil companies to remit their revenues back to Angola to be held in local accounts for extended periods until approvals could be obtained to use them outside Angola. Oil companies and other interested parties strongly objected this initial proposal. The Angolan government

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is in process of revising the proposed law. This process is expected to be finalized during the second quarter of 2005 for implementation before the end of the year. Depending on the outcome of this process, a new law could have material adverse effects on Hydro’s current and future operations in Angola.

     In Russia, Western oil companies continue to assess the impact of the Russian government’s recent actions relating to what had been Russia’s second-largest oil concern, Yukos.

Risks Relating to Hydro Aluminium’s Business

Hydro Aluminium’s results of operations are affected by fluctuations in LME prices

     The aluminium industry is highly cyclical. Virtually all aluminium end-use markets, including the building, transportation and packaging industries, are also cyclical. In addition, there is uncertainty concerning developments in supply and demand, in particular, regarding the overall economic developments in China as well as potential further restructuring within the aluminium industry as a whole.

     Price developments within the London Metal Exchange (“LME”), which represents the main reference price for the industry, reflects the cyclicality and uncertainties discussed above. For more information, see Item 4.B “Hydro Aluminium – Long Term Market Developments”.

     Fluctuations in prevailing aluminium prices, could negatively affect the financial results of Hydro Aluminium’s business areas. Based on Hydro’s analysis of indicative price and currency sensitivities included in this annual report (see Item 5. “Operating and Financial Review and Prospects – Risk Management”), a USD 100 decline in the LME price per tonne will reduce Hydro Aluminium’s pre-tax income and after-tax income by approximately NOK 800 million and NOK 560 million, respectively.

     Hydro’s extensive use of derivatives in managing its aluminium price exposure may result in additional volatility of its financial results from period to period.

Hydro Aluminium is exposed to foreign exchange rate fluctuations.

     Because Hydro Aluminium’s smelters are located predominately in Norway and Germany, a substantial portion of fixed costs are denominated in NOK and Euro. The weakening US dollar has resulted in a decline in the competitive position of Hydro Aluminium’s smelter system. In addition, Hydro Aluminium’s downstream operations are negatively impacted by the increasing euro compared to US based competitors.

Hydro Aluminium’s operations are dependent on substantial amounts of energy and, as a result, its profitability may decline if energy costs rise or if energy supplies are interrupted.

     Hydro Aluminium’s operations consume large volumes of energy, mainly electricity, in producing primary aluminium. Most of Hydro Aluminium’s smelters in Norway, Canada and Australia have electricity supply contracts with terms ranging from approximately 10 to 15 years. The electricity supply contracts for Hydro Aluminium’s German smelters, scheduled to expire at the end of 2005, will need to be extended or alternative supply arrangements made. Hydro Aluminium may not be able to renew or replace these contracts on comparable terms following the expiry of these contracts. As a result of increasing energy costs, as well as weakened competitiveness due to the strengthened Euro compared to the US dollar, Hydro has written down the value of the German smelter system by approximately NOK 2.3 billion. See the discussion in Item 4.B. “Business Overview – Hydro Aluminium – Hydro Aluminium’s Operating Sub-Segments – Metals – Raw Materials – Energy.”

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     Hydro Aluminium is particularly exposed to energy tax regimes in Norway and Germany because of its substantial electricity consumption in these countries. If electricity costs rise as a result of market or other factors such as new taxes, or if electricity supplies or supply arrangements are disrupted, Hydro Aluminium’s operating results could decline. For further information see Item 4.B. “Business Overview – Hydro Aluminium – Government Regulation.”

Hydro Aluminium is subject to a broad range of environmental laws and regulations in the jurisdictions in which it operates.

     Hydro Aluminium is subject to a broad range of environmental laws and regulations in each of the jurisdictions in which it operates. See Item 4.B. “Business Overview – Hydro Aluminium – Environmental Matters.” These laws and regulations, as interpreted by relevant agencies and courts, impose increasingly stringent environmental protection standards regarding, among other things, air emissions, the storage, treatment and discharge of waste waters, the use and handling of hazardous or toxic materials, waste disposal practices, and the remediation of environmental contamination. The costs of complying with these laws and regulations, including participation in assessments and remediation of sites, could be significant. In addition, these laws and regulations create the risk of substantial environmental liabilities, including liabilities associated with divested assets and past activities.

Hydro Aluminium’s expansion of business in emerging and transitioning markets presents a higher degree of financial, political, economic and business risks.

     Hydro Aluminium is increasing its business operations in emerging and transitioning markets. Such markets present a higher degree of risk than more developed markets. In addition to the business risks inherent in developing and servicing new markets, economic conditions may be more volatile, legal systems less developed and predictable and the possibility of various types of adverse governmental action more pronounced.

Hydro Aluminium is exposed to the non performance of its contracts partners

     Hydro Aluminium enters into various contracts to secure the price and availability of raw material and products for its manufacturing and remelt operations. These activities contain the risk that one or more counter parties will default on their obligations to Hydro resulting in direct financial losses, unexpected increased market exposure or higher operating costs. Poor or deteriorating economic conditions on a global, regional or industry sector level increase the risk of counter party default.

Hydro Aluminium could be adversely affected by disruptions of its operations.

     Many of Hydro Aluminium’s customers are, to varying degrees, dependent on planned deliveries from Hydro Aluminium’s plants located in various parts of the world. Breakdown of equipment or other events leading to production interruptions in Hydro Aluminium’s plants could lead to financial losses. Interruption in the energy supply to a smelter for more than six to eight hours could lead to the metal solidifying in the pots (see Item 4.B. “Business Overview – Hydro Aluminium – Overview of the Aluminium Industry – Aluminium Smelting”), which would result in Hydro Aluminium incurring significant costs to restore the smelter to normal operations. Reduced production, itself, could result in reduced income. Further, customers may have to reschedule their own production due to Hydro Aluminium’s missed deliveries, which may result in customers’ pursuing financial claims against Hydro Aluminium. For example, Hydro Aluminium supplies many of the automotive manufacturers in the world and, in a number of cases, is a sole supplier for special products. The automotive industry is particularly dependent on regular, on-time supplies. The consequences of not meeting scheduled deliveries or quality standards might be costly. Hydro Aluminium may incur costs to correct any of such problems, in addition to facing claims from customers. Further, Hydro Aluminium’s reputation among actual and potential customers may be harmed, potentially resulting in a loss of business. While Hydro Aluminium maintains insurance policies covering, among other things, physical damage, business interruptions, product liability and transportation, these policies may not cover all of Hydro Aluminium’s losses.

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Hydro Aluminium could be subject to unusual or significant litigation arising out of alleged defects in products

     Hydro Aluminium is a leading supplier of extrusion based application within crash management (ie. bumper beams) in Europe and has crash management operations in the United States. Hydro Aluminium could be subject to class action suits in the event of failure of such systems or be subject to claims or litigation relating to recall campaigns by automobile manufactures deemed necessary as a result of defects within such systems.

Risks Relating to Hydro’s Shares

Preferential rights may not be available to U.S. holders of Hydro’s shares.

     Under Norwegian law, prior to Hydro’s issuance of any new shares against consideration in cash, Hydro must offer holders of its then-outstanding shares preferential rights to subscribe and pay for a sufficient number of shares to maintain their existing ownership percentages, unless these rights are waived at a general meeting of Hydro’s shareholders. These preferential rights are generally transferable during the subscription period for the related offering and may be quoted on the Oslo Stock Exchange (the “OSE”).

     U.S. holders of Hydro’s shares may not be able to receive, trade or exercise preferential rights for new shares unless a registration statement under the U.S. Securities Act of 1933, as amended (the “Securities Act”) is effective with respect to such rights or an exemption from the registration requirements of the Securities Act is available. If U.S. holders of Hydro’s shares are not able to receive, trade or exercise preferential rights granted in respect of their shares in any rights offering by Hydro, then they may not receive the economic benefit of such rights. In addition, their proportional ownership interests in Hydro will be diluted.

Holders of Hydro’s shares that are registered in a nominee account may not be able to exercise voting rights as readily as shareholders whose shares are registered in their own names with the VPS.

     Beneficial owners of Hydro’s shares that are registered in a nominee account (e.g., through brokers, dealers or other third parties) may not be able to vote such shares unless their ownership is re-registered in their names with the Norwegian Central Securities Depository, Verdipapirsentralen (the “VPS”), prior to Hydro general meetings. Hydro cannot guarantee that beneficial owners of its shares will receive the notice for a general meeting in time to instruct their nominees to either effect a re-registration of their shares or otherwise vote their shares in the manner desired by such beneficial owners. See the discussion in Item 10.B “Articles of Association – Description of Ordinary Shares – Voting Rights.”

It may be difficult for investors based in the United States to enforce civil liabilities predicated on U.S. securities laws against Hydro, its Norwegian affiliates, or Hydro’s directors and executive officers.

     Hydro is organized under the laws of the Kingdom of Norway. All of Hydro’s directors and executive officers reside outside the United States. Further, a significant portion of Hydro’s assets, and those of its directors and executive officers, are located in Norway and other Western European countries. As a result, it may be difficult for investors in the United States to effect service of process within the United States upon Hydro or its directors and executive officers or to enforce against Hydro or its directors and executive officers judgments obtained in U.S. courts predicated on the civil liability

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

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Historical Overview

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

     Following the end of the Second World War, Hydro expanded into a number of new businesses. In 1951, Hydro began to produce magnesium metal and polyvinyl chloride at Porsgrunn, Norway. In 1967, Hydro opened an aluminium reduction plant and semi-fabricating facilities at Karmøy, Norway, and built the Røldal-Suldal hydroelectric power project to provide energy to the Karmøy facilities.

     In 1965 and 1967, Hydro commenced production of ammonia at two large ammonia plants in Norway, one of which made use of naphtha and the other, heavy fuel oil, as feedstocks (i.e., sources of hydrogen) in the ammonia production process. Hydro had previously depended on the electrolysis of water to provide the hydrogen needed to produce ammonia used in nitrogen-based fertilizers. The discovery of natural gas in the Netherlands and on the continental shelf off England in the North Sea created a new and competing source of feedstock for ammonia in Europe. Consequently, Hydro began to take steps to ensure that it could continue to compete with other European producers of ammonia that were obtaining access to these relatively inexpensive natural gas supplies. As a result, Hydro began to investigate various opportunities to participate in oil and gas production. In 1965, Hydro obtained concessions from the Norwegian State to explore for petroleum on the NCS.

     Hydro and its partners discovered oil and gas in the Ekofisk field in 1969 and in the Frigg field in 1971. Exploration of these discoveries ensured Hydro a source of feedstock for its fertilizer plants and also brought Hydro into the petroleum refining and marketing business. In 1975, Hydro began oil refining operations at Mongstad, Norway.

     Norway’s natural gas liquids resources and Hydro’s experience in the chemical process industry served as the foundation for its investments in the petrochemicals industry in Norway, and in 1978, Hydro commenced production of ethylene and vinyl chloride monomer.

     In the 1980s, Hydro acquired a number of businesses, both in Norway and in other areas. Hydro’s expansion of its fertilizer operations resulted in Hydro becoming one of the leading suppliers of fertilizer in Europe. Hydro also entered a new era as an oil company, becoming operator of the Oseberg offshore oil field. Hydro also developed or tested new technologies for deep-water oil and gas production and horizontal drilling, which Hydro subsequently put to commercial use in developing the Troll oil project. In 1986-87, Hydro acquired the Norwegian State-owned aluminium company, Årdal og Sunndal Verk, and several European aluminium extrusion plants from Alcan and Alcoa, thus establishing Hydro Aluminium as a major business within Hydro and an important player in the European aluminium industry.

     In recent years, each of Hydro’s Oil and Energy and Aluminium businesses has grown as a result of substantial investments, including several acquisitions. In 1999, Hydro acquired Saga Petroleum a.s, a Norwegian-based oil company, merging Saga’s operations into Hydro Oil and Energy. In 2002, Hydro acquired interests in eight oil and gas licenses on the NCS from the Norwegian State. This acquisition increased Hydro’s interests in the Oseberg, Tune and Grane fields, where Hydro is the operator. Hydro paid NOK 3.45 billion (US$415 million) for the license interests which expire between 2015 and 2032. In March 2002, Hydro acquired all the outstanding shares of VAW for a total purchase price, including indirect acquisition costs, of euro 1,911 million (NOK 14.8 billion; US$1.7 billion).

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Earlier in that same year, Hydro acquired the French building systems supplier, Technal. A significant portion of the expansion of these two core business areas has been financed through the sale of non-core businesses.

     In March of 2004, Hydro completed the demerger of its Agri business transferring all assets, rights, liabilities and obligations primarily relating to the Agri business to Yara International ASA.

     Today, Hydro is a Fortune 500 energy and aluminium supplier operating in more than 40 countries. Hydro’s other activities include: its petrochemicals business; a 68.8 percent interest in BioMar Holding AS (formerly Treka AS), whose activities consist of fish feed operations; the Company’s service and support operations including Hydro Business Partner, Hydro IS Partner and Hydro Production Partner; and Industriforsikring a.s, a captive insurance company.

General Information

     As a public limited company organized under Norwegian law, the Company is subject to the provisions of the Norwegian act relating to public limited liability companies (i.e., the Norwegian Public Limited Companies Act). See the disclosure under Item 10.B. “– Articles of Association – Description of Ordinary Shares” for a more complete discussion of certain provisions of the Norwegian Public Limited Companies Act.

     The Company’s principal executive offices are located at Drammensveien 264, Vækerø, N-0240 Oslo, Norway; telephone number: 47-22-53-81-00. The Company’s registered agent in the United States is Trygve Faksvåg, whose address is c/o Norsk Hydro Americas, Inc., 100 North Tampa Street, Suite 3300, Tampa, Florida 33802; telephone number: (813) 222-5700. Hydro’s internet site is www.hydro.com. The information on Hydro’s website is not incorporated by reference to this annual report on Form 20F and should not be considered part of this report.

ITEM 4. B. BUSINESS OVERVIEW

HYDRO OIL AND ENERGY

     Hydro Oil and Energy consists of two sub-segments, Exploration and Production and Energy and Oil Marketing.

     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.

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     Hydro has a significant position on the Norwegian Continental Shelf (NCS), where it is the third-largest producer of equity (i.e., owned) oil and natural gas. In 2004, approximately 90 percent of Hydro’s average daily production of 572,000 barrels of oil equivalents (“boe”) was from the NCS. As an operator of 11 producing fields on the NCS with a total production in 2004 of approximately 979,000 boe per day (“boed”), Hydro is a relatively large operator of oil and gas fields, in particular, offshore fields.

     Internationally, Hydro’s main producing fields are in Canada and Angola. Hydro also has producing fields in Russia and Libya. In addition to these countries, Hydro is involved in exploration activities in other countries, including the United States (Gulf of Mexico) and Iran.

     Hydro has a history of delivering strong production growth. From 1998 to 2004, Hydro has more than doubled its total equity production of oil and gas.

Oil Industry Trends

     The main trends in the oil industry affecting Hydro’s Exploration and Production activities are described below. Trends affecting the energy market are described under the “Energy” business description.

High Crude Oil Price Levels

     Spot Brent prices have increased from about USD 20 per barrel to roughly USD 40 per barrel during the latest three years. Most of the price increase has occurred since the summer of 2003. Spot Brent averaged USD 38.2 per barrel in 2004, almost USD 10 per barrel higher than the 2003 average at USD 28.8 per barrel. There are primarily two main factors underlying the significant price increase over the last 18 months.

     First, there has been a tremendous growth in oil demand in particular in China and also in North America as a result of substantial economic growth. According to the International Energy Agency (IEA), Chinese demand grew by 850,000 barrels per day in 2004 while demand in North America grew by 550,000 barrels per day. Most of the increase in demand related to light oil products such as gasoline and other distillates. However, growth in global refining capacity has not kept pace with the growth in demand, resulting in high margins for light oil products and a corresponding oversupply of heavy products. This, in turn, created large incentives for refiners to purchase light sweet crude oils like Brent and West Texas Intermediate (WTI). OPEC reacted by increasing production, however, the additional OPEC crude oil was not of the quality refiners were demanding. Second, there has been increasing political unrest in key oil producing countries, in particular, Iraq and Saudi Arabia. Acts of terror and sabotage in these countries have escalated throughout 2004.

     OPEC aims to function as a stabilizing force in the market. Its long-term price target has been considered to be USD 25 per barrel. However, many analysts believe that the cartel will raise its price target in 2005 to above USD 30 per barrel. Increasing finding and development costs outside OPEC and few indications of declines in consumption resulting from oil prices over USD 30 per barrel are factors underlying a higher target price for OPEC. Analysts believe that a higher target price may increase exploration activity outside OPEC, as more projects become economical to develop. However, notwithstanding an increase in target price, crude oil prices could continue to reflect cyclical periods of high and low prices from the interplay between market forces and actions taken by OPEC.

Exploration activity –changing expenditure trends

     The IHS Energy’s 2004 report on world petroleum trends shows that while total expenditures increased from 1994 to 2003, exploration expenditures as a proportion of total exploration and development expenditures has decreased from 26.8 percent in 1998 to 18.7 percent in 2003. However, there is a time-lagged correlation between higher oil prices and exploration activity, which indicates that there could be an upturn in strategic exploration investment.

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Reduced Exploration Results Worldwide

     Based on preliminary data from IHS Energy, worldwide oil and gas exploration activity during 2004 resulted in significantly smaller discoveries and lower amounts of hydrocarbons discovered compared to the previous two years. Based on the top two hundred discoveries world wide, average discovery sizes dropped significantly from 2003/2002 to 2004.

     It is becoming increasingly difficult to replace oil production by new discoveries. As a result, advances in reservoir management technology to increase recovery are becoming more important. Fewer major discoveries has also increased the focus on developing viable solutions for exploiting smaller oil fields.

Deepwater Dominates Major Finds

     Advances in deep water technology have opened up new areas for exploration and development. According to IHS Energy data, the trend observed in 2003 of the dominance of deep-water discoveries continued in 2004. During the year, 12 of the 20 largest discoveries originated from deep-water explorations. Areas with significant discoveries were India, Brazil, Angola, Egypt, Vietnam, Mauritania, as well as parts of West Africa. Overall exploration results offshore Canada, Norway and the UK continued to be disappointing.

Maturing Areas in the Developed World –the NCS

     The NCS, where 92 percent of Hydro’s proven reserves are located, is maturing. Norway’s oil production continued to decline in 2004, with total oil production reduced by about 1.6 percent compared to 2003. Oil production from new development is not keeping pace with production declines from maturing fields.

     Increasing gas production offset to some extent the negative trends in oil production. In 2004 approximately 78 billion cubic metres of gas were sold from the NCS, an increase of more than 7 percent compared to 2003. Combined with increased condensate and natural gas liquids (NGL) production, total petroleum production for 2004 resulted in a marginal increase of 0.5 percent compared to 2003.

     The increased price assumptions mentioned above are believed to have a positive impact on Hydro’s investment opportunities in Norway and internationally over time. A permanent increase in NCS exploration and development activity will, however, be dependent on more than just high prices. Two major factors that will also affect long-term activity on the NCS are whether the Norwegian authorities will allow increased access to attractive acreage and whether the Norwegian tax system will be revised to increase the international competitiveness of the petroleum industry in Norway.

     As part of the Revised National Budget, passed in June 2004, the Norwegian government made certain changes to the Petroleum Tax Act, which will be put forward in the budget for 2005. These changes are described more in detail under the caption “Taxation of Oil and Gas Production.” Hydro believes that the changes are moderately positive.

Strategy and Competitive Position

     Hydro’s goal is to position itself as one of the most profitable players in the upstream oil and gas business by exploiting its core competencies, underlying all elements of the value chain including exploration, design, execution and operations. In addition, Hydro is determined to maintain a strong commercial attitude in all its endeavors to create value. To achieve its goals, Hydro intends to focus its exploration and production activities on:

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Delivering Strong Production Growth

     Growth is important for business performance but also for the development of an organization’s capabilities. Hydro has a history of delivering strong production growth. From 1998 to 2004, Hydro more than doubled its total equity production of oil and gas. The increase included organic growth on the NCS, start-up of production from Hydro’s international activities, and the acquisition in 1999 of Saga Petroleum. In addition, during 2002, Hydro acquired increased ownership interests on the NCS from the Norwegian State in the Hydro-operated fields Oseberg, Tune and Grane.

     Total oil and gas production in 2004 was 572,000 boed, representing an increase of almost 8 percent over the prior year. This increase reflected the first full year of production from the Grane field and the Fram field, both of which came on-stream in the fall of 2003, as well as the start-up of new fields in 2004, when Skirne came on-stream in May and Kvitebjørn started producing in the end of September. The positive effects of these developments were partly offset due to the Snorre, Vigdis and Terra Nova shutdowns caused by oil- and gas leakages and the declining production from maturing fields.

     Hydro had previously announced a targeted average compound annual growth rate for production of 8 percent for the 2001-2007 period. Hydro has extended this target to 2008, and expects that this production growth will be achieved within its existing portfolio based on producing fields, fields under development and fields planned for development. More than 60 percent of the production in 2008 is expected to come from currently booked proved reserves. Hydro has targeted an average daily production of 575,000 boe for 2005, of which approximately 85 percent is expected to come from currently booked proved reserves. For further information regarding currently booked proved reserves, see the table of proved reserves included in Note 27 to the Consolidated Financial Statements. See, also, the description of fields underlying the growth projections within the disclosure under Item 4B “Business Overview – Hydro Oil and Energy – Exploration and Development – Development” within this annual report.

     In 2004, approximately 10 percent of Hydro’s total oil and gas production came from outside the NCS, mainly Canada and Angola. Total international oil production was approximately 58,000 boed.

Building the Basis for Future Production

     In 2004, Hydro evolved its strategy for upstream growth in each geographical area it operates in based on the following key elements:

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     As a consequence of the high crude oil levels, Hydro has decided to increase the price assumptions used for oil and gas investment decisions to 25 USD/boe for Brent Blend equivalent quality for oil-related investments. Similar adjustments have been made for gas-related investments. However, all investment decisions will be evaluated for robustness using 20 USD/boe for Brent Blend equivalent. Investment proposals failing to meet this test will be subject to a more in-depth risk assessment prior to investment decisions. Hydro believes that the changed price assumptions will result in new business opportunities that were previously deemed uneconomic.

     Hydro’s international expansion has been based on alliances with regional producers and international partners with a focus mainly on oil prospects. Hydro is also pursuing exploration and production opportunities in gas prospects within close proximity for piped transportation to the European market (see also “Energy and Oil Marketing” – “Energy” – “Strategy and Competitive Position” - “Enhancing the Value of Hydro’s Natural Gas Portfolio”).

     Hydro’s strategy for international expansion has been to concentrate its efforts in areas with sufficient potential to create economic scale. Hydro’s technological competence, including the application of leading-edge reservoir and development solutions developed through its experience as an operator of oil and gas producing fields in the harsh Norwegian offshore environment, has provided a solid basis for Hydro’s international expansion.

     Over time Hydro has been working to increase its local geological knowledge in focused areas. The combination of expertise in all parts of the value chain gained on the NCS with an understanding of complex local geological, political and other business factors is proving valuable in Hydro’s increased focus on internationalization of its oil and gas business.

Improving the Profitability of Existing Assets

     Hydro continues to pursue cost improvements in its exploration and production activities. As fields on the NCS mature and demonstrate a decline in production, high priority will be given to reducing costs and implementing measures to increase production on existing fields, including development of satellite fields that may be time critical with respect to utilizing existing infrastructure. Hydro’s objective is to maintain and improve its status as an efficient operator.

     Hydro has announced a targeted production cost¹ in 2005 of NOK 24/boe. Hydro’s actual cost was NOK 20.7 in 2004. The difference between actual and target results from expected cost for gas injection into the Grane field. Hydro plans to continue its efforts to drive down costs on operated facilities despite the underlying maturing nature of the portfolio.

Strong Position on the NCS

     The NCS has been the most important area for Hydro’s oil and energy business, and this is expected to continue to be the case for the foreseeable future. The following reflects Hydro’s view regarding potential opportunities on the NCS:

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               In recent years frontier exploration in Norway has yielded disappointing results. Licenses awarded in the 17th and 18th rounds, however, in addition to the re-opening for exploration of the Barents Sea, have provided acreage with interesting high-risk/high-reward prospects for Hydro. Hydro plans to drill between 5 to 10 wells on this acreage in the coming years. In December 2003, the Norwegian government decided to allow further petroleum activities within areas already open for exploration in the southern part of the Barents Sea with some exceptions. The Norwegian government also intends to reevaluate the re-opening of Nordland VI as part of an integrated management plan for the Barents Sea, which is expected to be finalized in the spring of 2006.

               In total, Hydro has a sizeable and balanced exploration portfolio on the NCS comprising acreage extending from the southernmost Farsund Basin to the Barents Sea, both near infrastructure and in frontier areas. In 2004, Hydro’s strong position on the NCS was reflected through awards of high equities and operatorships in all prioritized blocks made available in both the 18^th Concession Round and the Awards in Predefined Areas.

               Hydro is the third-largest producer on the NCS, trailing Petoro (the Norwegian State oil and gas holding company) and the majority State-controlled Statoil. In 2004, approximately 90 percent of Hydro’s average daily equity production of 572,000 boe came from the NCS.

               As of 31 December 2004, Hydro had interests in 104 licenses on the NCS, of which it was operator of 54 licenses. In total, the licenses cover a gross offshore area of around 38,710 square kilometers (km) in the North Sea, the Norwegian Sea and the Barents Sea. The corresponding net offshore area (Hydro’s share) is around 13,790 square km. Hydro also has interests in four exploration areas with a total of 9 optional licenses on the NCS, of which it is operator of one area. Each of the optional licenses may turn into a license under normal conditions if the partners commit to an exploration well following seismic evaluations. These four exploration areas cover an additional gross area of more than 14,000 square km and a net area of about 4,480 square km.

               Hydro is the operator of 11 producing oil and gas fields on the NCS: Oseberg, Oseberg Øst (East), Oseberg Sør (South), Brage, Tune, Njord, Troll Oil (Troll B and C), Heimdal, Vale, Grane and Fram Vest. Hydro is also the operator of the development phase of the large Ormen Lange gas field, for which the Plan for Development and Operation (“PDO”) was approved by the authorities in April 2004. Hydro also submitted a PDO for the Vilje field on the NCS in 2004, which is planned to be developed as a subsea tie-back solution to the Marathon-operated Alvheim facilities. In November 2004, Hydro submitted a PDO for gas export from the Njord Field to the authorities, which was approved in January 2005.

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     The total average daily production in 2004 from Hydro-operated fields was approximately 979,000 boe, which demonstrates that Hydro is a relatively large operator of oil and gas fields, in particular offshore fields. Measured in terms of equity production, however, Hydro is a medium-sized upstream oil and gas company. This is partly due to the Norwegian licensing system, under which a relatively low equity interest historically has been awarded to the operators.

     Hydro has an equity interest in most of the main producing oil and gas fields on the NCS. The most important producing fields for Hydro in 2004 were the fields in the Oseberg area, the Troll field and the Snorre fields. The Grane oil field, which started production in 2003 and is expected to reach plateau production at the end of 2005, is now a large contributor to Hydro’s Norwegian oil production. Other important fields were Åsgard, Tune, the Sleipner fields, the Gullfaks fields, and the Ekofisk fields. The Ormen Lange field is the largest field presently under development on the NCS and Hydro expects that Ormen Lange will be an important part of Hydro’s production after start-up in 2007.

     Hydro will continuously evaluate opportunities to optimize its portfolio on the NCS. In January 2004, Hydro signed an agreement with Statoil for the sale of Hydro’s equity share in the Snøhvit field. The sale was approved by the Norwegian authorities and completed in 2004. In 2003, Hydro also entered into an agreement to sell its interest in the Gjøa field, which is presently in the pre-development phase. The sale was completed in the first quarter of 2004.

     In January 2004, Hydro agreed to purchase an additional 2 percent equity interest in the Kristin field from Statoil in order to improve Hydro’s position in the Norwegian Sea. In the second quarter of 2004 Hydro also signed an agreement for the purchase of ExxonMobil’s 20 percent equity share in license PL 248 including gas-condensate discoveries. Hydro is the operator of PL 248 with an equity share of 40 percent after the acquisition. In order to ensure a cost effective development of Skinfaks/Rimfaks fields, Hydro acquired a 9 percent share in licenses PL 152, PL 277 and PL 037 E. After this transaction Hydro has 9 percent in all licensees involved in the Skinfaks/Rimfaks development.

Interesting International Positions

     In 2004, Hydro’s international oil production represented approximately 10 percent of its total oil and gas production. The main producing fields are in Canada and Angola. Hydro also has producing fields in Russia and Libya. In addition to these countries, Hydro is involved in exploration or exploration-related activity in other countries, including the United States (Gulf of Mexico), Iran, Denmark, Madagascar and Morocco.

     Angola: Hydro has participated in Angola’s oil and gas industry since 1991. Hydro’s main asset is its 10 percent interest in the deep water offshore Block 17, where a total of 15 discoveries have been made as of 31 December 2004. This includes Girassol and Jasmim, which contributed to Hydro an average of almost 22,000 boed of oil production in 2004. The development of the Dalia project is progressing and is expected to come on stream in 2006. The development of the Rosa field was approved in 2004 as a tie-back to the Girassol field. Rosa is expected to come on stream in 2007. The process of selecting a development solution is ongoing for the Cravo and Lirio discoveries, as well as for the Acacia, Zinia, Perpetua and Hortenzia discoveries. Development of a third production hub in Block 17 has been targeted as a potential concept.

     Hydro also holds a 30 percent interest and is the technical assistant to the Angolan national oil company, Sonangol, the field operator, on Block 34. The first well, drilled in April 2002, did not result in the discovery of hydrocarbons. A second exploratory well, drilled in December 2003, discovered gas, but was considered a non-commercial well. Technical evaluations are continuing and are focusing on new exploration models for a third exploratory well.

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     As of 31 December 2004, Hydro holds shares in a total acreage of around 9,000 square km, mainly deep-water or ultra deep-water acreage with water depths down to 2,600 meters. Of this acreage, about 5,900 square km is exploration acreage where Hydro has a 30 percent interest.

     Canada: In 1996 Hydro entered into a strategic alliance with Petro-Canada which included a swap of certain Hydro interests in licenses on the NCS in exchange for the right to participate in oil production from proven fields and explore for further oil discoveries on the Grand Banks of Newfoundland. Hydro has maintained its ownership position in the ongoing projects acquired in 1996. Hydro has ownership in two producing fields, Hibernia and Terra Nova, and is presently focusing on optimization of these two fields. Hydro holds a 5 percent interest in the Hibernia field and a 15 percent interest in the Terra Nova field. These fields contributed a total average oil production of approximately 27,000 boed in 2004. Hydro is also working together with the operator, ChevronTexaco, to develop the Hebron field in the same area.

     Hydro’s strategy in Canada includes infrastructure led exploration, maturing the existing exploration license portfolio and assessing risks and volumes in immature basins on the Grand Banks and on the Scotian Shelf. At present, Hydro is working with its partners in evaluating the Annapolis discovery located offshore Nova Scotia. As of 31 December 2004, Hydro’s 11 exploration licenses cover a gross exploration area of approximately 18,000 square km and a net exploration area of approximately 6,200 square km, including shelf and deep-water acreage with water depths ranging from 50 to 3,100 meters.

     Russia: Hydro has been present in Russia for 15 years and has equity production from the onshore Kharyaga field, which covers about 350 square kilometers of acreage in the Timan Pechora basin. Hydro is a 40 percent co-owner. This field started production in 1999 and phase two came on stream in 2003. In 2004, average equity production was 6,700 boed, which was less than expected partly due to lack of access to transportation. Hydro believes that this problem will be solved in 2005. Hydro is also pursuing new business opportunities in Russia. In December 2004, Hydro signed a Memorandum of Understanding (MoU) with Gazprom for the evaluation of the giant Shtokman gas field, which is located in the deep water continental shelf on the Russian side of the Barents Sea. The MoU outlines a joint work program between the two companies covering technical, marketing and commercial aspects of the project.

     Libya: Hydro is a partner in the onshore Mabruk field, which lies in the northern part of the country. Hydro holds a 25 percent interest in Mabruk. In addition, Hydro has taken part in oil exploration in the Murzuq Basin, in the Sahara Desert, since 1998. Production in the Murzuq Basin started in the autumn of 2003 from the A-field and in June 2004 from the D-field. Hydro’s equity share of the fields in the Murzuq basin is 20 percent in the exploration phase, 10 percent in the development phase and 8 percent in the production phase. Total average daily equity production from Hydro’s Libyan fields was around 2,800 boed (net after royalties and profit oil) in 2004. Libya represents an interesting resource potential. Hydro will continue to pursue new opportunities in Libya in light of the currently improving general political situation in the country. As of 31 December 2004, Hydro’s four licenses in Libya cover a gross onshore area of around 37,000 square km. The net exploration acreage is around 7,400 square km.

     In 2004, Hydro and Wintershall formed a consortium for the purpose of evaluating and negotiating new business opportunities in Libya in 2004 - 2006, and possibly beyond. Wintershall, a crude oil and natural gas producer based in Germany, has been active in Libya since 1958.

     Iran: Hydro established an office in Tehran, Iran during November 1999. Hydro currently has no assets under development or in production in Iran. In April 2000, Hydro entered into a contract with the National Iranian Oil Company for the exploration of the Anaran Block close to the Iraqi border. The Anaran Block covers an area of approximately 3,200 square kilometers, of which Hydro will acquire 1,000 square km of 2D seismic and drill 5 wells. The contract has a term of 4.5 years with an option for a one-year extension. In July 2004, Hydro was granted a one-year extension until October 2005. The agreement provides Hydro with the right to enter into negotiations for a buy-back agreement to develop

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reserves in the event of a commercial discovery. The Anaran block is considered challenging to explore, with a difficult geological environment. After clearing seismic tracks for mines, Hydro completed the seismic acquisition program. The first well (Azar 1) was spudded in the spring of 2003, but drilling proved to be more difficult than anticipated, and the well was abandoned in January 2004. Azar 2 was spudded in May 2004 with the same target as Azar 1, and is estimated to be completed in the second quarter of 2005. Pending the results from this well, Hydro plans to drill a third well on the block (the Changuleh West well) during the second half of 2005. Hydro’s farm-out of 25 percent of the interest in the Anaran contract to the Russian company, Lukoil, was approved by the Iranian authorities in 2003, leaving Hydro with an equity share of 75 percent.

     Hydro’s prime objective in Iran is to focus on completion of the exploration program on the Anaran Block. A successful completion of the activity in Anaran could better position Hydro for new opportunities in Iran. Hydro has submitted a bid for a new exploration contract on the Khoramabad block in the Lurestan area. Awards are expected to be announced in the summer/fall of 2005. In September 2004, Hydro submitted a bid for negotiating a contract for developing the Yadavaran field. Awards for companies to enter into negotiations are expected to occur during the first half of 2005.

     US Gulf of Mexico: Hydro entered into a joint venture agreement with ConocoPhillips in September 2001. The agreement provided Hydro with a 25 percent working interest in five firm and three contingent exploratory wells in the US Gulf of Mexico. An obligation to participate in the fifth firm well was later eliminated and the joint venture agreement amended to provide for Hydro’s participation in the Lorien prospect, which at the time was operated by ConocoPhillips. The Lorien prospect was drilled in 2003 and resulted in a discovery. The other four firm wells did not result in commercial discoveries. In 2004, Hydro increased its working interest in the Lorien discovery from 10 to 30 percent. An appraisal well was drilled in 2004 and an integrated project team is working on plans for developing the Lorien discovery, which is now operated by Noble Energy. Hydro also acquired a 57.5 percent interest in the Champlain discovery in 2004. In January 2005, Hydro was approved by the Minerals Management Service — Gulf of Mexico Region, as operator of the Champlain field. As the new operator, Hydro has renamed the field “Telemark”. In total, Hydro’s 72 exploration leases as of 31 December 2004 in the US Gulf of Mexico, of which Hydro is the operator of 27 leases, cover a gross exploration area of around 1,700 square km, and a net exploration area of around 790 square km, in deep-water. Hydro has concentrated its efforts in the Central US Gulf of Mexico to establish a good geological knowledge base in the area. In the lease sale in April 2004, Hydro was awarded seven new exploration blocks, all in these areas.

     In addition, Hydro has two exploration licenses in Denmark. Hydro had one exploratory license in Trinidad and Tobago, which was relinquished in December 2004. During 2004 Hydro also commenced evaluation of frontier acreage offshore Madagascar in the Majunga basin together with ExxonMobil and Vanco Energy, an oil and gas company based in the US. The gross exploration acreage is almost 18,000 square kilometers, and Hydro has a 30 percent equity share while Vanco is operator of the project. Acquisition of seismic information was finalized in 2004, and limited financial exposure exists at present. Drilling alternatives will be evaluated during 2005 prior to potential exploration decisions. A similar approach was taken relating to the NW Safi offshore basin in Morocco during 2004. Hydro signed an investigation contract for the license in April 2004. The gross exploration acreage is about 6,500 square km. Hydro is the operator of the project , and plans to develop possible drilling prospects prior to seeking potential partners to reduce its financial exposure prior to actual drilling.

Exploration

     The following tables reflect the number of exploratory oil and gas wells drilled by Hydro as of 31 December 2004. The first table reflects all of the gross exploratory wells drilled and completed during the years indicated. The second table reflects the exploratory wells in the process of being drilled as of 31 December 2004. A total of 17 wells were drilled and completed in 2004, of which 11 were considered productive. In addition, 3 wells were in the process of being drilled at year-end.

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Drilling Activity

In Process Drilling Activities

     As part of its exploration program in 2005, Hydro plans to participate in approximately 30 exploration and appraisal wells. Around 20 of these wells are planned on the NCS and the remaining wells are planned internationally, mainly in Libya and Angola.

Norway

     In 2004, Hydro participated in 6 exploratory wells and was operator for one of the wells. Two of the wells resulted in commercial discoveries: the Linerle well, located north of the Norne field, and the Topas well, located between the Gullfaks and Visund fields. The Linerle discovery, in which Hydro holds a 13.5 percent interest, will be evaluated through one or two appraisal wells in 2005. The Hydro-operated exploratory well, Brontes, which is located south of the Oseberg field, was dry. In 2004, Hydro also participated in drilling activity in connection with producing wells that resulted in three additional commercial discoveries: the Vigdis extension well, the Brage 31/4-A-30 B well, and an extension of the first production well on the Kristin field that proved a new reservoir zone, the Tofte formation.

     Several of the wells planned for 2004 were postponed due to operational problems and a labor dispute relating to floating rigs on the NCS. These wells include the Obelix well in the Barents Sea, the Stetind well located in the deepwater Norwegian Sea, as well as the Hejre appraisal well located in Denmark.

     In 2004 Hydro was awarded a total of 12 new licenses. Four of the licenses were awarded as part of the 18^th Concession Round initiated in December 2003, and 8 related to licenses offered in the Awards in Predefined Areas initiated in January 2004. Several of the licenses awarded to Hydro have the potential for large discoveries and new, stand-alone developments. These include the award in the Farsund Basin blocks 11/5 and 11/6 and the award in block 35/2, where Hydro was chosen as operator and awarded a 60 percent equity interest.

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     In October 2004, the government requested the nomination of blocks for the 19^th Concession Round covering the Norwegian Sea and the Southern Barents Sea. The deadline for submission of nominations was 23 February 2005. The deadline for submission of license applications is expected to be the fourth quarter of 2005, with awards of new licenses taking place early in 2006. In January 2005, the government announced the Awards in Predefined Areas 2005. The deadline for submission of applications is 30 September 2005 and the awards are planned to take place in December 2005.

     Hydro is the operator of PL 248 located in the northern part of the North Sea and intends to submit a PDO of these gas-condensate discoveries during 2005. Production is planned to begin during 2008, but the actual start date is highly dependent upon the development concept selected. The current plan is to develop the discoveries as subsea tie-backs to existing or new infrastructure in the area. In 2004, Hydro acquired an additional 20 percent equity share in PL 248 from ExxonMobil and now holds a 40 percent equity interest.

International

     In 2004, Hydro’s international exploration activities encompassed Angola, Canada, Libya, Iran, the United States (Gulf of Mexico), and Denmark. Hydro participated in 11 exploratory and appraisal wells that were completed during 2004.

     In Angola, one appraisal well was successfully drilled and completed on Block 17 during 2004. A second appraisal well was spudded in December and is scheduled to be completed in the first quarter of 2005. The appraisal wells are expected to confirm the reserve estimates as a basis for selecting a development concept during 2005 for the UM area in Block 17. Appraisal of the Lirio discovery in Block 17 is planned for 2005. One exploration well remains to be drilled in Block 34 and alternative exploration models will be evaluated for the well. In 2004, Sonangol P&P found oil in Block 4 in cooperation with Hydro. Sonangol P&P and Hydro have signed a letter of intent with the objective to commercialize the discovery.

     In Canada, one well was drilled relating to a new prospect in the Annapolis license. The well did not result in a commercial discovery.

     In Libya, two exploration wells and six appraisal wells relating to license NC-186 in the Murzuq basin were drilled during 2004. Three appraisal wells were drilled on the B-structure of NC-186 and a Field Development Plan (“FDP”) was submitted to Libyan authorities in December. A new commercial discovery was made on the H-structure in NC-186 and 3 appraisal wells were drilled. By year end, production testing was taking place in well H4 in the NC-186 license. The exploration and appraisal program in Libya will continue in 2005 with the planned drilling of further wells relating to the Murzuq licenses.

     In Iran, the Azar 1 well on the Anaran block was spudded in the spring of 2003 and was abandoned in January 2004 due to technical difficulties. Azar 2 was spudded in May 2004 with the same target as Azar 1. Completion is estimated during the second quarter of 2005.

     In the US Gulf of Mexico, Hydro participated in a successful appraisal well relating to the Lorien discovery.

     In Denmark, Hydro has a 25 percent interest in license 6/98 covering the Hejre discovery. An appraisal well was completed at the end of February. The well discovered hydrocarbons, and the results will now be further evaluated before a decision can be taken regarding possible development and production on Hejre.

Reserve Information

     At the end of 2004, Hydro’s share of proved developed reserves of oil and gas was estimated to be 1,447 million boe. Hydro’s share of proved undeveloped reserves accounted for an additional 629 million boe. Total developed and undeveloped proved reserves amounted to 2,076 million boe, of which gas reserves represented approximately 56 percent.

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     Reserve life, defined as the number of years of production from proved reserves at the present production level, was approximately 10 years at the end of 2004, with approximately 6 years for oil and approximately 21 years for gas.

     The following table summarizes Hydro’s net quantities of proved oil and gas reserves as of 31 December 2004, 2003 and 2002.

Oil and Gas Reserves

     Proved reserves are estimates and are expected to be revised as oil and gas are produced and additional data become available. Accordingly, recoverable reserves are subject to upward and downward adjustments from time to time. Please see the discussion in Item 5. “Operating and Financial Review and Prospects — Hydro’s Critical Accounting Policies — Proved Oil and Gas Reserves.”

     An analysis of changes to proved developed and proved undeveloped reserves of oil and gas as of and for the three years ended 31 December 2004, 2003 and 2002 is included in the table in Note 27 to the Consolidated Financial Statements. Estimates of the proved reserves, presented on an individual field basis, as of 31 December 2004, can be found in Exhibit 99.2 “Operational Data” to this annual report.

Development

     In 2004, Hydro invested² NOK 10,678 million in the development of new and existing fields and transportation systems compared to NOK 8,487 million and NOK 8,222 million in 2003 and 2002, respectively. The implementation of SFAS 143 relating to asset retirement obligations resulted in an additional charge of NOK 1,089 million for 2003, which is not included in the above amount. For more information on Hydro’s adoption of SFAS 143, see Note 1 to the Consolidated Financial Statements. Hydro’s most important exploration and production development projects in 2004 were the Snøhvit, Kristin, Ormen Lange, and Dalia fields. Hydro’s sale of its equity share in Snøhvit was finalized 31 December 2004.

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          A summary of the fields under development as of 31 December 2004 is included in the following table. Only the main fields are presented in the table. Development projects in connection with fields under production and smaller satellite developments relating to fields in production are described under the caption “Production” below.

Fields under Development

          In connection with the development projects described in this section, Hydro has invested (excluding internal costs) NOK 0.2 billion, NOK 1.1 billion and NOK 2.6 billion for the years 2002, 2003 and 2004, respectively. Estimated investments for the same projects for 2005, 2006 and 2007 are NOK 4.1 billion, NOK 3.7 billion and NOK 1.7 billion, respectively.

     Norway

          The PDO for the Ormen Lange gas field was submitted to the Ministry of Petroleum and Energy on 4 December 2003, together with the Plan for Installation and Operation (“PIO”) for the new gas export pipeline, Langeled. The authorities approved both the PDO and the PIO in the beginning of April 2004. Ormen Lange is situated in water depths of 850 to 1,100 meters in the Norwegian Sea, 100 km off the northwest coast of Norway. Based on seismic and other data, Ormen Lange is believed to be the second-largest gas field and the largest field presently under development in Norway. Given Hydro’s estimate of the total proved reserves for the field, Hydro’s share is 234 million boe including 35.0 billion cubic meters (bcm) of gas. The field development is planned as a sub-sea installation linked to the Nyhamna onshore processing plant not far from the city of Molde in Norway. Gas is to be exported from the plant through a new pipeline (Langeled) via the Sleipner riser platform to Easington

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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, is estimated at NOK 72.9 billion, including NOK 52.9 billion for field and plant development and NOK 20 billion for the pipeline. Hydro’s equity share is 18.0728 percent. Hydro is the operator during the development phase of the field.

          The 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. Hydro entered into an agreement with Statoil in 2004 to increase its interest in the Kristin field from 12 to 14 percent. The Norwegian authorities approved the transaction during the second quarter of 2004. The transaction was finalized in December 2004. Given Hydro’s estimate of the total proved reserves for the field, Hydro’s share is 43 million boe including 2.8 bcm of gas.

          The Vilje oil field (formerly called Klegg) will be developed as a 2-well subsea tie-back to the Alvheim Floating Production, Storage and Offloading unit (“FPSO”) situated 18 km away. The PDO is expected to be approved in March 2005. The total investment, in nominal terms, is estimated at NOK 2.2 billion. Hydro’s equity share in the Vilje field is 28.8 percent. Production is expected to commence in February 2007, dependent upon production start of the Alvheim FPSO, which is currently under construction. Hydro has no equity interest in the Alvheim development.

          In January 2004, Hydro announced that it had entered into an agreement to sell its equity share in licenses relating to the Snøhvit field to Statoil. The Norwegian authorities approved the transaction during the second quarter of 2004. The transaction was finalized in December 2004.

     International

          Angola: The Dalia field is the third development on Block 17 and was sanctioned by the Angolan government at the end of April 2003. The development concept comprises a sub-sea production system linked to a FPSO with an average production capacity of 225,000 boed. Production is expected to commence in October 2006. The total proved reserves for the Dalia field are 31 million boe. Hydro’s equity share is 10 percent. The Rosa field was sanctioned by the Angolan government in August 2004. The Rosa field will be developed as a tie-back to the Girassol FPSO. Production is expected to commence in April of 2007 and is expected to reach a plateau production of 130,000 boed. The total proved reserves for the Rosa field are 9 million boe. Hydro’s equity share is 10 percent.

Production

          The following table includes the number of gross and net productive oil and gas wells in which Hydro had interests as of 31 December 2004.

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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 2004 and 2003. Information regarding the total production of oil and gas in 2004, the remaining production period of the producing fields and the license period for such fields can be found in the table included in Exhibit 99.2 “Operational Data” to this annual report.

Hydro’s Share of Average Daily Production ⁽¹⁾

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Norway

          Oseberg Fields. Hydro is operator and has a 34 percent equity share in the Oseberg fields. The Oseberg fields are core areas for Hydro on the NCS, contributing 22 percent of Hydro’s total NCS production in 2004. The Oseberg Fields include the main Oseberg field (the Field Center installations and the Oseberg C production platform) and the two satellite fields, Oseberg Øst (East) and Oseberg Sør (South). Oil and gas from the satellites are piped to the Oseberg Field Center for processing and transportation. Oil is brought ashore through the Oseberg Transport System pipeline to the Sture terminal in Norway. Gas is exported through the Oseberg Gas Transport pipeline to the Heimdal field and further through the Gassled pipeline system. Oil production from the Oseberg Field Center and the Oseberg C platform are currently in the decline phase. Natural gas export from the Oseberg Field Center and Oseberg Øst and Oseberg Sør began in 2000 and 2001, respectively. A revised PDO for the development of the Oseberg Sør field was approved by the authorities in May 2003. The revised PDO covers the J-structure that will be developed with a separate sub-sea installation with production start-up in the early part of 2005. The total cost for the J-development is estimated at NOK 1.6 billion, of which NOK 0.87 billion was invested as of 31 December 2004. The PDO of the Oseberg Vestflanken (West flank) was submitted to the authorities in October 2003 and approved in December 2003. Production start-up is planned for December 2005. Oseberg Vestflanken is planned to be developed by a sub-sea installation tied into the Oseberg Field Center platforms. Total investments are estimated at NOK 2.3 billion, of which NOK 396 million was invested as of 31 December 2004. In 2004, partners in the Oseberg license and the Norwegian authorities approved a plan for upgrading the Oseberg Øst platform to achieve a profitable solution for further drilling and well activities, and the drilling of seven new wells. Total project costs are expected to be NOK 1.9 billion, of which NOK 25 million was invested as of 31 December 2004. Production from the new wells is planned to commence early in 2007. In June 2004 the “Agreement relating to Unitization and Operation of the Oseberg Area” was signed, establishing the Oseberg Area Unit. The agreement established the foundation for a coordinated and long-term view on the development of the resources in the Oseberg area through balanced ownership, a prolonged license period and the establishment of the Oseberg Area Unit. Hydro is currently preparing a PDO for the Delta and G-Sentral structures in the Oseberg region, scheduled for submittal to the Norwegian authorities in June 2005.

          Troll Field. The Troll field is the largest gas field on the NCS. Hydro holds a 9.78 percent interest in the Troll field, which comprises two main structures: Troll East and Troll West. A staged development has taken place with Phase 1 covering gas reserves in Troll East and Phase 2 focusing on the oil reserves in Troll West. Statoil is the operator of the Troll East facilities and Hydro is the operator of the Troll West. Gas from the Troll field represents a major part of Hydro’s current developed gas reserves and gas production. In 2004, approximately 30 percent of Hydro’s gas production came from the field. The gas development consists of a platform linked to the Kollsnes gas terminal. The gas is exported from Kollsnes through the Gassled system. Gas production started in 1996. Troll is also a major oil field. The oil development on the western part of Troll consists of two floating production units linked by two oil pipelines to the Mongstad terminal. Oil production started in 1995.

          Snorre Fields. The Snorre fields, operated by Statoil, are located in the Tampen area and include the Snorre, Tordis, Vigdis, Statfjord Øst and Sygna fields. Hydro’s interest in the Snorre field is 17.65 percent. Production of oil and associated gas from the Snorre 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. Hydro’s interest in the Tordis field is 13.28 percent. Oil from the Tordis field is processed on the Gullfaks C platform. Production from the field peaked in 1996 and is currently in the decline phase. Since the Tordis field started declining, several satellite structures have been connected to the field including Tordis Øst in 1998, Borg in 1999 and Tordis Sørøst in 2001. In 1999, water injection was implemented to increase the recoverable reserves from the field. Production of oil and gas from the Vigdis field began in early 1997. Hydro’s interest in the Vigdis field is 13.28 percent. Production began declining in 2000. To maintain production levels, a PDO for the Vigdis Extension was submitted to and approved by the government in 2002 with production start-up in October 2003. Oil from the Vigdis field is processed on the Snorre platform and piped to Gullfaks A for storage and transportation. In order to

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maintain production levels, several projects for “increased oil recovery” (IOR) have been initiated in the Snorre area during 2004. This applies for the Snorre A, Vigdis and Tordis fields. If approved by the partnerships, these projects are expected to commence with a 2007 to 2009 time frame. The Statfjord Øst and Sygna fields started production in 1994 and 2000, respectively. Hydro’s interest in the Statfjord Øst field is 6.64 percent and in the Sygna field 5.98 percent. Both fields are linked to the Statfjord C platform. Due to technical problems related to a gas leak from a gas injector underneath the Snorre A platform, both the Snorre and Vigdis fields were closed down on 28 November 2004. Production from both fields started up again in January 2005.

          Grane Field. The Grane field is located in the North Sea and is developed with an integrated production and drilling platform. Hydro is operator of Grane and has a 38 percent equity share. Production from the field started September 2003. Oil from the field is exported in a new pipeline from the Grane platform to the Sture terminal in Øygarden, Norway. Gas for injection into the field is imported through a 50 km pipeline from the Heimdal Gas Center to ensure optimum production of oil. The Grane field contains heavier oil than what is normally found on the NCS.

          Åsgard Field. The Åsgard field, operated by Statoil, is situated in the Norwegian Sea. Hydro’s interest in the Åsgard field is 9.6 percent. The Åsgard Unit covers the three fields, Midgard, Smørbukk and Smørbukk Sør. The field is developed with a production ship (Åsgard A) for oil and condensate production and a floating production platform (Åsgard B) for condensate and gas production and a storage vessel (Åsgard C). Oil production started in May 1999 and gas export commenced in October 2000. The gas is transported through the Åsgard Transport pipeline to the Kårstø gas terminal for processing.

          Sleipner Fields. Production of gas and condensate began at Sleipner Øst in late 1993 and from Sleipner Vest in the middle of 1996. Statoil is operator of both fields, and Hydro’s interest in the fields is 10 percent and 8.85 percent respectively. Production from the satellite fields, Gungne, Loke 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 four sub-sea wells. These wells came on stream in October 2004.

          Tune Field. The Tune gas and condensate field (phase 1), operated by Hydro, is developed as a sub-sea satellite to Oseberg. Hydro’s interest in the Tune field is 40 percent. The Tune field came on stream in November 2002, using spare processing capacity at the Oseberg Field Center and was a major contributor to Hydro’s growth in production in 2003. A decision to develop Tune phase 2 was made in June 2004, with start up of a single well planned for October 2005. Tune Phase 2 exploration well was determined to be dry in February 2005. Further evaluation on the use of subsea equipment for Tune Phase 3 is ongoing. Under considerations for Tune phase 3, is a 4-slot satellite with a potential production start-up late 2005 or spring 2006 depending on rig availability.

          Gullfaks Fields. The Gullfaks fields, where Hydro has a 9 equity share, are situated in the Tampen area. Statoil is the operator of Gullfaks. The main Gullfaks field consists of three integrated platforms, where production started in 1986. The satellite fields, Gullfaks Vest, Gullveig, Rimfaks and Gullfaks Sør, are linked to the main field. Tankers transport the oil from the fields while gas is transported by pipeline to the Kårstø terminal in Norway. The Gulltopp satellite is under development (one long-reach well) and is expected to start production in August 2005. A PDO relating to the Skinfaks/Rimfaks Increased Oil Recovery (IOR) satellite project was submitted to the Norwegian authorities in December 2004 and approved in February 2005. Production is planned to start in December 2006. Recovery from Rimfaks will be improved by drilling supplementary wells. The development solution for the Skinfaks discovery is based on a subsea production system tied back to the Gullfaks C platform. The total project investment is estimated at approximately NOK 3.4 billion.

          Ekofisk Fields. Ekofisk, operated by ConocoPhillips, is situated in the southern part of the North Sea and is the oldest operating field complex within Hydro’s portfolio, having commenced production in 1971. Oil is exported through the Norpipe oil pipeline to Teesside in England, while gas is

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exported through the Gassled system. The Ekofisk Area Growth project includes installing of a new wellhead platform tied in to the Ekofisk II process platform. The platform jacket was installed in August 2004 and pre-drilling of production wells started in November 2004. The platform deck will be installed during second quarter of 2005 with potential first production in the third quarter of 2005. Total investments for the Ekofisk Area Growth project are estimated at NOK 8.5 billion, of which NOK 3.6 billion was invested as of 31 December 2004. Hydro’s equity share is 6.65 percent. Alternatives for further development of the Eldfisk and Tor fields are being discussed among the owners. A delineation well in the satellite field Embla is planned to be drilled during the summer of 2005 with the potential of increasing the reserves in Embla considerably.

          Fram Field. The Fram field is located approximately 22 km from the Troll field. Hydro is operator and has a 25 percent equity share in the Fram field. The first phase of the field, Fram Vest that comprises the H structure, is developed by a sub-sea installation linked to the Troll C platform for processing. Production commenced in October 2003. Processed oil is transported to the Mongstad terminal while gas will be used for re-injection for a period of approximately six years to facilitate oil recovery. After this period, gas will be transported to the Kollsnes gas terminal. The second phase of the Fram field, Fram Øst, comprises the F-East Upper Sognefjord, the F-East Lower Sognefjord, the C-West Sognefjord and the C-West Etive reservoirs. Fram Øst, is in the final stages of development planning, and is expected to include 5 horizontal oil production wells and 2 multilateral (branched) water injection wells, drilled from two 4-slot subsea templates. Investments are estimated at NOK 4.4 billion. The Sognefjord well streams will be routed via a new production pipeline to the existing Fram and Troll facilities on the Troll C Platform for processing, while the Etive well stream will be routed through the existing Fram Vest production flowline. Water produced from Troll and Fram will be re-injected through a new flowline into the Sognefjord reservoirs for pressure support. Processed oil will be transported to the Mongstad terminal, while gas will be sent to the Kollsnes gas terminal. Production is expected to start in October 2006. The drilling program on Fram Øst includes appraisal aspects, which could lead to a third phase of Fram field development in the future. Facilities designed for Fram Øst incorporate flexibility to add two more subsea templates. Hydro submitted a PDO for the Fram Øst Field to the Norwegian Authorities in February 2005.

          Norne Field. The Norne field, operated by Statoil, is located in the Norwegian Sea. Oil production started in late 1997. Gas production started in February 2001. The installation consists of a combined production and storage vessel with gas handling facilities and a gas transportation pipeline. The gas is transported via the Åsgard transportation pipeline to the Kårstø gas terminal in Norway. Hydro’s equity share in the Norne field is 8.1 percent. In May 2004, the PDO for Urd (also known as Norne satellites) was submitted to the Norwegian authorities. The PDO was approved by the authorities in July. The two discoveries will be developed with sub-sea installations tied back to the Norne Field installation. Total investments are estimated to be NOK 3.5 billion. Hydro’s equity share in Urd is 13.5 percent.

          Visund Field. The Visund field, operated by Statoil, is situated in the Tampen area. The field is developed with a floating production unit that came on stream in early 1999. Oil produced from Visund is stored in and shipped from Gullfaks A. A sub-sea installation for developing the northern reservoir of Visund was put on stream in early 2002. In October 2002, the authorities approved the PDO of the Visund Gas Extension, which covers development of the gas volumes. The project includes increased gas treatment and injection capacity and a gas export pipeline connected to the Kvitebjørn gas pipeline for transport to the Kollsnes terminal. Gas export is expected to start in October 2005. The total investment is estimated at NOK 2.0 billion, of which approximately NOK 1.1 billion was invested as of 31 December 2004. Hydro’s equity share is 20.3 percent.

          Brage Field. The Brage field is located in the North Sea, approximately 13 km east of the Oseberg Field Center. Production began in 1993. Hydro is operator and has a 20 percent equity share in the Brage field. Oil from the field is transported to the Sture terminal via the Oseberg Field Center. Production from the field is currently in the decline phase.

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          Njord Field. The Njord field, operated by Hydro, is located in the Norwegian Sea. Hydro’s equity share in the Njord field is 20 percent. Production from the field began in late 1997. The installation consists of a floating production unit (Njord A) combined with a tanker, Njord Bravo, for storage and loading of oil. Gas produced is re-injected into the field to maintain reservoir pressure. In November 2004, Hydro submitted a PDO for gas export from the Njord Field to the authorities for approval. The PDO was approved in January 2005. Investments are estimated to be NOK 1.1 billion. Gas exports are planned to commence late in 2007. The gas will be exported through the Åsgard gas transportation system to Kårstø.

          Mikkel Field. The Mikkel field, operated by Statoil, is located in the Norwegian Sea and started production in October 2003. Hydro has a 10 percent interest in the Mikkel field. The development concept consists of sub-sea installations linked to the Åsgard B platform for processing. The condensate will be exported from Åsgard C for offshore loading. The gas will be transported to the Kårstø terminal through the Åsgard transport system.

          Frigg Field. The Frigg gas field was permanently shut down in October 2004. A removal and abandonment project relating to the field installations and wells is scheduled to be completed 2010.

          Kvitebjørn Field. The Kvitebjørn gas and condensate field, operated by Statoil, is situated southeast of the Gullfaks field. Hydro’s equity share is 15 percent. The field is developed with a fixed production platform. Rich gas is transported through a new pipeline to the Kollsnes gas terminal for processing and export. Condensate is transported through the new Kvitebjørn oil pipeline, which is connected to the Troll2 pipeline and further to the Mongstad terminal. Production commenced in the end of September 2004. Drilling of production wells will continue through year 2005.

          Skirne Field. The Skirne gas and condensate field, operated by Total, is situated approximately 20 km east of the Heimdal field. Hydro’s equity share is 10 percent. The field consists of the Skirne and Byggve structures, which have each been developed with one single subsea well and tied back to the Heimdal gas center. Production started in March 2004. A booster compressor module will be installed at the Heimdal gas center in 2005.

          Vale Field. Hydro is operator and has a 28.9 percent interest in the Vale field. The Vale field was developed by one satellite well that is tied to the Heimdal Gas Center. Production started in May 2002. In June 2005, the production will be suspended due to drilling of a new sidetrack well. Production is expected to start up again in September 2005.

          Heimdal Field. Hydro is operator and has a 19.44 percent equity share in the Heimdal field. The Heimdal gas and condensate field is currently operated as a gas processing and distribution center after reconstruction of the platform in 2000 and 2001. Production of remaining reserves began in August 2001 after a temporary shut down during the construction period. This tail-end production is expected to last until early 2005. In March 2004, production started from the small Skirne field, which is connected to the Heimdal Gas Center.

International

          Angolan Fields. The Girassol field, operated by Total, is an offshore field located on Block 17 in Angola. Hydro has a working interest of 10 percent. Oil production started in December 2001. The installation consists of a production and storage-offloading vessel. The processing capacity is above 250,000 boed and the storage capacity is two million barrels. The Jasmim field is a sub-sea satellite connected to the Girassol FPSO. Production started in November 2003.

          Canadian Fields. Both of Hydro’s producing fields in Canada are located in the Grand Banks area off the east coast of Newfoundland. Oil production from the Hibernia field, operated by HMDC³,

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came on stream in November 1997. Hydro has a five percent interest in the field. The Terra Nova field, operated by Petro-Canada, is southeast of Hibernia and started production in January 2002. Hydro has a working interest of 15 percent. The Terra Nova field was shut down from the end of November to mid December 2004 due to an oil spill.

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

          Libyan Fields. Production from the Mabruk West field in the north of Libya, operated by Total, started in 1995. Hydro became owner of a 25 percent interest in the license through the acquisition of Saga in 1999. A FDP for Mabruk Phase IV (Mabruk Central and East) was approved by the Libyan authorities in July 2004. The development includes construction of new facilities and drilling of additional development wells in East and West Mabruk. The total estimated investment is USD 20 million. As of 31 December 2004, the incurred investment amounted to USD 25.3 million. Production from the Murzuq A-field in the south of Libya started in October 2003 and from the Murzuq D-field in June 2004. The Murzuq A- and D-fields are being developed as an integrated unit. A FDP for Murzuq B was sent to the Libyan authorities for approval on 9 December 2004. Approval is expected in the first half of 2005. The total estimated investment is USD 67.8 million. The NC 186 B-field will also be integrated with the NC 186 A-field. Oil from the A, B and D-fields will be transported from the NC 186 A gas oil separation plant to the El-Sharara field 29 km away, where it will be blended with oil from NC 115 and NC 174 and transported by pipeline 726 km to the As Zawiyah terminal west of Tripoli. Hydro’s equity share of the fields in the Murzuq basin is 20 percent in the exploration phase, 10 percent in the development phase and 8 percent in the production phase.

Transportation of Oil and Gas

     Norway

          All the main gas pipelines and terminals in Norway are owned and operated by a joint venture called Gassled. Gassled is described in more detail in the business description for Energy and Oil Marketing, which includes more comprehensive information regarding Hydro’s ownership share in Gassled than is reflected in the table below.

          The information in the following table reflects Hydro’s interest in the major pipelines for the transportation of oil and gas from the NCS and in the corresponding land terminals as of 31 December 2004.

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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 either directly to market or to a terminal located at Whiffen Head, Newfoundland in dedicated offshore loading tankers. Hydro has an ownership interest in two of the tankers of 14.9 percent and 12.7 percent, respectively, and a 5 percent interest in the terminal. In addition, Hydro has long-term contracts for use of storage capacity at the terminal.

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Definitions of Oil and Gas Terms

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     ENERGY AND OIL MARKETING

ENERGY

Overview

                    Hydro has an established position in the Northern European natural gas and power markets as a producer of natural gas and power, a holder of an equity interest in the natural gas transportation systems and as an active trader in the markets. By combining all commercial activities for energy products and services in one operating segment, Hydro leverages its commercial skills and contacts in each of the energy sectors. Hydro’s experience in the Nordic region contributes to Hydro’s knowledge base in pursuing opportunities in other markets.

Industry Trends

     Liberalization of European Electricity and Gas Markets

                    In Europe, both the electricity and gas markets are undergoing liberalization as a result of European Union (“EU”) policy. For more information on the EU’s regulatory initiatives to further the liberalization of EU energy markets, see “ — Oil and Energy Government Regulation - Liberalization of European Electricity Markets” and “ — Oil and Energy Government Regulation — EU Gas Directives and Related Regulatory Developments.”

                    In October 2004, the European Commission announced that 18 member states have failed to correctly transpose the new generation of electricity liberalization directives (Directive 2003/54/EC) and/or gas liberalization directives (Directive 2003/55/EC) into national law.

                    The European Commission is of the view that the main problem for electricity in coming years will be the issues of market dominance at the national level and the inadequate level of interconnection between member states.

                    Significant political, structural and transactional barriers still must be overcome before a sustained gas wholesale liquidity can support a competitive gas end-customer market. Harmonizing transmission and transport networks, tariffs, and accounting methods and breaking the strangle hold of dominant producers is proving a challenging task. The 25 gas markets in the EU are at widely differing stages of development and maturity, a factor that has long been acknowledged as one of the key barriers to bringing about a truly liberalized and competitive single European gas market. However, competition has increased in some markets. One example, the recent decision by the Dutch government to acquire full ownership of the Dutch gas grid, is viewed as a catalyst toward a more liberalized Dutch market.

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                    To be successful, exploration and production companies, traders, resellers and even major industrial gas users need to be present at the international and regional European market hubs.

     Growth in European Natural Gas Demand

                    It is anticipated that natural gas demand growth in Europe over the coming years will lead to a shortfall in terms of current committed contracts of approximately 50 billion cubic meters (bcm) by 2010. By 2010, all European countries, except Norway, are predicted to become net importers of gas; Russia, Algeria and Norway are predicted to be key suppliers of Europe’s gas in 2010.

                    Analysts indicate that demand for natural gas in Europe is expected to grow significantly from the 2003 level of approximately 528 bcm. Electricity generation is the key to growing demand for gas. Approximately 42 percent of EU power generation in 2030 is expected to come from gas-fired plants, up from 40 percent in 2020, 29 percent in 2010 and 17 percent in 2000.

                    In 2003, Norway supplied approximately 13 percent of the total consumption of natural gas in Europe. This percentage is expected to rise in future years based on existing contract commitments and remaining reserves. The United Kingdom, in particular, is an attractive market for Norwegian gas due to the declining UK gas reserves. It is estimated that by around 2006 the UK will no longer be self-sufficient in gas production. By 2010, it is estimated that the UK will be 50 percent dependent on imported gas, rising to 80 percent by 2020.

     Integration of Energy Markets

                    Along with the liberalization of the energy markets in Europe, there is a trend towards integration of the electricity and gas markets because the business models are, to a large degree, based on the same competence and types of customers. One of the main trends in the development of the European energy market is the enlargement of companies that want to control more energy sectors.

     Increased Focus on Renewable Energy and Hydrogen

                    There is an increasing interest in renewable energy and the utilization of hydrogen in the energy market in developed economies throughout the world. The major political drive and basis for a number of public support schemes is driven by concerns about the security of energy supply and environmental considerations. The International Energy Agency (IEA) expects the dependence on oil imports in the EU to grow from 50 percent to 70 percent from 2002 to 2030. The IEA further predicts a higher CO2 emission increase compared to energy demand in the same period, because the rise in use of fossil fuels is higher than that of renewables.

                    The European Union has adopted a directive (Directive 2001/77/EC) that seeks to promote the production of electricity from renewable energy sources, including wind and hydropower. EU member states have set an indicative target of 22 percent share of electricity to be produced from renewable energy sources by 2010. The Norwegian Ministry of Oil and Energy has announced that Norway wishes to implement the RES-E Directive and has also put forward a proposal for legislation on a Norwegian mandatory green certificate market. The certificate market will be linked to the existing Swedish certificate market and the plan for start-up of the common market is 1 January 2007. This is expected to increase focus on wind energy in an area characterized by having strong and consistent wind conditions.

Strategy and Competitive Position

                    Hydro’s strategy is to further enhance its position in the Northern European energy market, based on increasing gas production and commercial competence gained from the European gas market and the liberalized Nordic power market. Focus areas comprise:

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     Enhancing the Value of Hydro’s Crude Oil Portfolio

                    The focus of Hydro’s marketing efforts with respect to its North Sea and international crude oil production is to achieve optimal prices by marketing fewer grades of crude oil, in larger volumes, while minimizing logistical costs. Swap arrangements result in savings in logistical costs, particularly with respect to production from Hydro’s international crude oil portfolio.

                    Trading activities include the sale of Hydro’s crude oil and NGL production. The volumes of these activities have increased partly due to increased equity oil and gas production over the past years. Furthermore, Hydro Oil and Energy supplies NGL feedstock to Hydro’s petrochemical plants, as well as the former Hydro Agri (now Yara) fertilizer plants. Following the demerger of Agri, Hydro has continued to supply the Yara fertilizer plants under arm’s-length agreements.

                    The tables below reflect the volumes of Hydro’s sales and refining activities, respectively, in the last three years.

     Enhancing the Value of Hydro’s Natural Gas Portfolio

                    Hydro is increasingly becoming a key gas supplier for Europe. Because of location, transportation infrastructure and substantial reserves, Norwegian natural gas is competitive in the European region. Both the NBP (National Balancing Point in the UK) forward prices and German import price estimates up to 2008 are well above the expected cost of the Ormen Lange gas to the UK.

                    Hydro is the third-largest producer on the NCS, with a strong expected increase in equity gas production. Hydro has an interest in all the major natural gas fields and in Gassled. Hydro also holds capacity rights in Gassled, enabling access to five landing points for natural gas in Europe. This offers a flexible and favorable position with respect to capturing value in the market. In the European continental market, Hydro has achieved an attractive position through its flexible portfolio based on a combination of long-term sales contracts, long-term supply contracts and access to transportation.

                    Hydro’s strategy is to combine its role as a natural gas producer with that of a wholesaler and trader to increase its market share in the developing liberalized European natural gas market. The main geographic focus is Northwest Europe. Hydro wants to develop a strong and balanced customer portfolio, including a mix of long-term contracts with wholesalers, end-user sales to the power and industrial segments, and spot sales, in order to optimize its natural gas portfolio.

                    It is a continuous focus for Hydro to increase the value of Hydro’s natural gas portfolio through, among other things, more optimal utilization of Hydro’s production and transportation capacity. These upstream positions, combined with Hydro’s market presence across Europe, provide Hydro with an opportunity to create business further down the gas value chain in Northwest Europe. Further development will be based on both increased access to natural gas from fields in which Hydro has an equity interest, and sourcing natural gas in the market. In line with this strategy, Hydro has throughout

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2004 focused on integrating into its activities the portfolio acquired in late 2003 through the purchase of Duke Energy’s gas sales and marketing organization in the Netherlands (Duke Energy Europe Northwest B.V.), consisting of sourcing, sales, transportation and storage agreements.

                    Another main activity in realizing the strategy has been the successful start-up of the activities of HydroWingas, the UK joint venture between Hydro and Wingas GmbH, the German gas transportation and supply company. The main goal in pursuing this joint venture is to establish a competitive and effective UK gas marketing channel by combining Wingas’ and Hydro’s gas positions and marketing skills. HydroWingas will focus on large industrial customers, power producers and the wholesale segment. Marketing activities started in 2004, resulting in several signed contracts and initial gas deliveries in the market.

                    The table below reflects Hydro’s equity gas production and downstream non-equity gas sales and sourcing in the last three years.

                    In 2004, Hydro’s equity natural gas production from the NCS amounted to 8.8 bcm, an increase of 13 percent compared to the previous year.

                    In addition to its equity gas, during 2004 Hydro supplied 3.9 bcm in the downstream market , including 1.9 bcm supplied to the former Hydro Agri, now Yara, fertilizer activities.

                    Natural gas produced from fields in which Hydro has an equity interest is mainly sold under long-term contracts. Pricing under long-term contracts is generally based on a price formula whereby the natural gas price is indexed to oil product prices in the end-user market, mainly gas oil and low sulphur fuel oil. These contracts typically have provisions for price reviews based on changes in certain market conditions.

                    In the future, Hydro expects that an increasing volume of its natural gas will be sold under contracts indexed to liquid European gas hubs such as NBP or Zeebrügge. Physical positions are still necessary in order to gain increased margins by optimizing logistics and trading. Liquidity within the UK NBP market has increased, and is now considered to be a viable, short-term market. There is less liquidity on the European continent, however, but liquidity is increasing at several emerging hubs, in particular at Zeebrugge in Belgium. Hydro’s presence at these major hubs enables it to optimize its equity gas positions, both short- and long-term.

                    Hydro has made substantial investments in natural gas export capacity from the Oseberg and Troll fields, together comprising a major portion of its proved reserves of natural gas. This capacity will enable Hydro to increase exports of gas significantly in the coming years as reservoir conditions allow higher natural gas production. The start-up of the Ormen Lange gas field will further increase Hydro’s gas production and the development of the connected Langeled transportation system will further increase transportation flexibility on the NCS. The gas will be transported by the world’s longest subsea export pipeline approximately 1200 kilometres from the west coast of Norway via Sleipner in the North Sea to Easington in UK.

                    Gassled, the natural gas transportation infrastructure joint venture on the NCS, has been in operation since 1 January 2003. The NCS natural gas pipelines and associated terminals had previously been organized as several different joint ventures owned by oil companies and the Norwegian State. Gassled consists of the following systems: Europipe, Europipe II, Norpipe gas pipeline, Zeepipe, Franpipe, Vesterled, Statpipe, Oseberg Gas Transport, Åsgard Transport and the Kårstø terminal. The Kollsnes gas terminal is included in Gassled from 1 February 2004. Currently Hydro holds a direct ownership interest of 11.134 percent in Gassled. Hydro’s participation in future capacity expansions such as Langeled will initially result in a moderate increase in Hydro’s ownership interest before it is expected to be reduced to about 10 percent in 2011 in accordance with the agreed redistribution of ownership shares.

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     Optimizing Hydro’s Power Activities

                    Hydro is one of the largest producers of electric power in Norway, with a normal annual production from hydroelectric facilities in Telemark, Røldal/Suldal and Sogn of approximately 8.5 terrawatt hours (“TWh”). Hydro has been engaged in a large development project to expand the Tyin hydropower plant in Sogn at a cost of approximately NOK 1.3 billion. The new Tyin power plant has been in operation since fall 2004. Revitalization of the power plant has increased production by 15 percent based on the existing water reservoirs.

                    Hydro has title concessions that will never revert to the Norwegian government for hydroelectric power plants with an average generating capacity of 2.7 TWh per year. This represents approximately 32 percent of Hydro’s normal production capacity. The remaining hydroelectric production capacity, 5.8 TWh, or approximately 68 percent of Hydro’s normal production capacity, will under the present legislation⁴ revert to the Norwegian government without compensation at the expiration date of each concession. Separate concessions apply to each power plant. The year of expiration of the individual concessions ranges from 2022 to 2051.

                    In addition to its hydroelectric power stations, Hydro is a partial owner (44 percent) of the Havøygavlen wind power plant with a potential annual production of about 105 gigawatt hours (GWh).

                    Hydro is, as a 50 percent owner of the company Naturkraft AS, evaluating the possibility of building a new gas fired power plant at Kårstø, Norway. The final investment decision regarding the project is expected to be taken by the summer of 2005. The power plant is planned to be in operation during the fall of 2007. Hydro’s share of the expected annual production of the plant is roughly 1.5 TWh.

                    Since the liberalization of the Norwegian electricity market in 1991, Hydro has developed its power trading and marketing activities, along with analysis, portfolio and risk management systems. Hydro’s Nordic electricity portfolio includes owned generation facilities, long-term supply contracts, internal and external sales contracts and short-term optimization contracts.

                    The table below reflects Hydro’s power production and the volumes acquired under long-term purchase contracts for the last three years.

                    As reflected in the table above, power production in 2004 was lower than normal due to low precipitation during the early winter of 2004, and the residual effect of low precipitation in Norway during the autumn and winter of 2002/03.

                    Hydro Oil and Energy supplies electric power to Hydro’s industrial plants in Norway. To meet those needs, Hydro has entered into long-term purchase contracts, the majority of which are with the Norwegian State-owned power company, Statkraft. These long-term contracts provide assurance of the availability of and predictable prices for a certain quantity of power to Hydro’s power intensive industries. In 1997, Hydro entered into an agreement with Statkraft to purchase electricity from 2000 to 2020. The agreement replaces supplies under existing contracts, which terminate during the 2006-2010 period.

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                    From 2005 and onwards, Hydro Oil and Energy will focus its power activities on management of the Nordic electricity portfolio and sourcing of power to Hydro’s larger consuming plants in the Nordic area and continental Europe.

     Pursuit of Hydrogen and Renewable Energy Opportunities

                    Hydro has extensive experience within the traditional industrial hydrogen markets as well as with renewable hydroelectric energy production. Hydro is seeking to leverage its experience to position itself in renewable energy and new energy markets for hydrogen.

                    Hydro views wind power generation as the most important part of the renewable energy market and is making selective investments in this market. In 2002, Hydro completed the Havøygavlen wind park, located in northern Norway. Havøygavlen is one of the largest wind power projects in Norway, with a potential annual output of around 105 GWh. Further Norwegian and European projects are continuously evaluated, in Norway pending the framework for production and sale of renewable energy.

                    Hydro is presently involved in several hydrogen projects. These include partially owned filling stations for hydrogen-fueled vehicles in Iceland and Germany, and combining hydrogen and wind power to form a demonstration project of a sustainable energy society on the Norwegian island of Utsira.

OIL MARKETING

                    Oil Marketing markets and sells refined petroleum products (gasoline, diesel and heating oil) and electricity to customers in Scandinavia and the Baltic countries. Hydro owns 100 percent of its oil marketing unit in Sweden and 50 percent of Hydro Texaco, an oil marketing company with retail outlets in Norway, Denmark and the Baltic countries. Hydro markets a range of complementary energy products in addition to refined petroleum products, such as electricity, natural gas, biogas for cars and bioenergy for heating purposes, as well as convenience store goods.

                    At the end of 2004, Hydro’s retail network in Sweden comprised 539 gasoline stations and 130 Hydro Diesel service stations. Hydro operates both Hydro and the Uno-X branded stations in the Swedish gasoline market. Approximately 50 percent of the station network is Hydro-branded. As of year-end 2004, Hydro Texaco operated 405 gasoline outlets and 46 diesel sites in Norway, 408 gasoline outlets and 102 diesel sites in Denmark, and 49 gasoline outlets and 10 diesel sites in the Baltic countries with Hydro Texaco or Uno-X brands. Hydro’s strategy is to maximize its return on investments already made in its gasoline station chains by focusing on the most profitable stations and closing smaller and unprofitable outlets, building strong brand recognition and expanding on profitable segments of the market.

                    Hydro has a strong brand and market position in the most profitable segments of the industrial and residential heating oil markets. Its large customer base offers a platform for the sale of electricity to residential and industrial customers. Also, Hydro’s and Hydro Texaco’s large customer bases provide a potential for cross-sales. Sales of electricity have, to date, been relatively modest compared to Hydro’s sale of gasoline and gasoil, but are growing.

                    Gasoline is sold through service stations and unmanned, automated stations in Scandinavia and the Baltic countries. Gasoils are sold through automated diesel stations and through direct deliveries from depots to end consumers.

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                    In 2004, Hydro’s market share in the Swedish gasoline market declined by 0.3 percentage points mainly as a result of the discontinuation of agreements with Volvo dealers and their customers. These agreements are being phased out over a period of 5 years, from 2001 to 2005. To compensate for the loss in market share, Oil Marketing has entered into a deal with VW/Audi Sweden, allowing holders of VW/Audi credit cards access to Hydro and Uno-X stations.

Oil and Energy Government Regulation

                    The principal Norwegian legislation applicable to petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of 1996, a number of regulations issued under that Act, and the Petroleum Taxation Act of 13 June 1975.

                    Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy (the “Ministry”) has been delegated responsibility for resource management and administering petroleum activities on the NCS. The Ministry primarily implements petroleum policy through its power to award licenses, to approve operators’ field and pipeline development plans, and to approve gas sales contracts.

     Norwegian Licensing System

                    Hydro normally participates in exploration and production activities with other parties, including private and state-owned oil and gas companies and other government entities. Contractual arrangements among partners are generally governed by an operating agreement, which provides that costs, production entitlements and liabilities are allocated according to each partner’s respective percentage interest in a particular field or license area. Normally, one party is appointed as operator by the Ministry. Field activities are conducted under the overall supervision and control of an operating committee consisting of representatives from each participant in the field. This enables each of the non-operator partners to be involved in field development and operations.

                    The Petroleum Act and related regulations contain the main legal basis for the license system, which regulates Norwegian petroleum activity. The most important type of license award under the Petroleum Act is the production license. A production license grants the holder an exclusive right to explore for and produce petroleum within a specified geographical area. The licensee becomes the owner of the petroleum produced from the field covered by the license, and, together with any partners, is jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the license. Notwithstanding the exclusive rights granted under the production license, the Ministry has the power to, in exceptional cases, permit third parties to carry out exploration in the area covered by a production license.

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                    Production licenses are normally awarded through licensing rounds. The first licensing round for NCS production licenses was announced in 1965. Awards of licenses take place both through the principal licensing rounds (of which the 18^th was awarded in June 2004) and through separate rounds covering a defined area.

                    Prior to the development of a field, licensees are required to submit a PDO to the Ministry for approval. In respect of fields of a certain size, the Norwegian Parliament (Storting) must accept the PDO before it is formally approved by the Ministry.

                    Production licenses are normally awarded for an initial exploration period, which is typically six years but can be for a shorter period or for a period of a maximum of ten years. During this exploration period, the licensees must meet a specified work obligation set out in the license. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfill the obligations under the production license, they are entitled to extend the license for a period specified at the time when the license is awarded, typically 30 years. The licensees are, however, normally not entitled to require that the license is extended for more than half of the originally awarded license area.

                    For licenses granted after 1 July 1985, the Norwegian governmental authorities can delay development of a field indefinitely under the Norwegian Petroleum Act. Should development be delayed, licensees can apply for an automatic extension of the license term corresponding to the delay period. For licenses granted before 1 July 1985, the conditions in the specific license apply.

                    The Norwegian State may, if important public interests are at stake, direct licensees on the NCS to reduce their production of petroleum. From 15 July 1987 until the end of 1989, licensees were directed to curtail oil production by 7.5 percent. Between 1 January 1990 and 30 June 1990, licensees were directed to curtail oil production by 5 percent. In 1998, the Norwegian State resolved to reduce Norwegian oil production by about 3 percent, or 100,000 boed. In March 1999, the Norwegian State decided to further decrease production by 200,000 boed. In the second quarter of 2000, the reduction was brought back to 100,000 boed. On 1 July 2000, this restriction was removed. By a royal decree of 19 December 2001, the Norwegian government decided that Norwegian oil production should be reduced by 150,000 boed from 1 January 2002 until 30 June 2002. This amounted to roughly a 5 percent reduction in output.

                    Licensees may buy or sell interests in production licenses subject to the consent of the Ministry and the approval of the Ministry of Finance of the tax treatment. The Ministries must also approve direct or indirect transfers of interests in a license, including change of control of a licensee, if it would result in a new entity obtaining a decisive influence over the licensee. In most licenses there are no pre-emption rights in favor of the other licensees. The State’s Direct Financial Interest (“SDFI”), or the Norwegian State, as appropriate, however, still holds pre-emption rights in most licenses.

                    A license from the Ministry is also required in order to establish facilities for transport and utilization of petroleum. When applying for such licenses, the owners, which are in practice licensees under a production license, must prepare a plan for installation and operation. Licenses to establish facilities for transport and utilization of petroleum will normally be awarded subject to certain conditions. Typically, these conditions require the facility owners to enter into a participants’ agreement. For major new gas infrastructure, the Ministry will typically require that the new facilities shall be included in Gassled when operational. The ownership of most facilities for transport and utilization of petroleum in Norway and on the NCS is organized as a partnership or joint venture of a group of license holders, and the participants’ agreements are similar to the joint operating agreements entered into among the members of the partnership holding production licenses.

                    Licensees are required to prepare a decommissioning plan before a production license or a license to establish and use facilities for transportation and utilization of petroleum expires or is relinquished, or the use of a facility ceases. The decommissioning plan must be submitted to the Ministry no sooner than five and no later than two years prior to the expiry of the license or the cessation of the use of the facility, and must include a proposal for the disposal of facilities on the field.

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On the basis of the decommissioning plan, the Ministry makes a decision as to the disposal of the facilities.

                    The Norwegian government can require that licensees participate in the removal of offshore oil and gas installations (platforms, pipelines, etc.) on the NCS when production ceases or at the expiration of the concessions, whichever occurs first. The Norwegian government has the option to take ownership of a permanent offshore installation at no cost to it when a license expires, is surrendered or revoked or when the use of such installation has been terminated permanently. For onshore installations, compensation for expropriation has to be paid. In such cases, the Norwegian government would assume total responsibility for any well closure and decommissioning costs after this time, as well as removal costs of the installation. As a basis for estimating Hydro’s future liabilities related to well closures, decommissioning and removal costs of the installation, Hydro’s management evaluates Norwegian and international laws, treaties and practices, and the estimated value of recoverable oil and gas reserves that are expected to exist at the end of the various concession periods. See the discussion in Item 5. “Operating and Financial Review and Prospects — Hydro’s Critical Accounting Policies — Asset Retirement Obligations.” The regulations allow for full deductibility in taxable income of dismantlement and removal costs.

     Organization of Norwegian Gas Sales and Transportation

                    Until June 2001, gas sales contracts with buyers for the supply of Norwegian gas were required by Norwegian authorities to be concluded with the Gas Negotiation Committee, known as the Gassforhandlingsutvalget (“GFU”).

                    The structural changes taking place in the European gas market (see the discussion under “ — EU Regulation — EU Gas Directives and Related Regulatory Developments” below) prompted the Norwegian State to consider whether changes to the gas resource management system on the NCS could contribute to further enhancing the efficiency of Norwegian gas producers. Accordingly, the Norwegian State, by a royal decree dated 1 June 2001, determined to abandon the GFU system and put in place a system whereby the individual licensees manage the disposal of their own gas. Adjustments in legislation, license agreements and other existing contracts necessary to implement the new system were finalized during 2002.

                    With the approval of Gassled, Norwegian authorities have, by a royal decree of 31 December 2002, issued regulations for access to and tariffs for capacity in the upstream gas transportation system. Gassled has a uniform access regime, giving all natural gas undertakings and eligible customers who have a duly substantiated reasonable need of transportation a right to access the system under non-discriminatory, objective and transparent conditions. Access to the system is based on long-term and short-term transportation agreements. Gassled tariffs have been established through regulations established by the Ministry of Petroleum and Energy with effect from 1 January 2003.

     Health, Safety and Environment Regulations

                    Petroleum operations in Norway are subject to extensive regulation with regard to health, safety and the environment (“HSE”). Under the Petroleum Act, which is in this respect administered by the Ministry of Labor and Social Affairs, all petroleum operations must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of employees, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained and developed in accordance with technological developments.

                    Licensees and other persons engaged in petroleum operations are required to maintain at all times a plan to deal with emergency situations. During an emergency, the Ministry of Labor and Social Affairs may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, in order to deal with the emergency on the part of the licensees.

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                    In the HSE area, the Norwegian Pollution Control Authority, the Norwegian Social and Health Directorate and the Petroleum Safety Authority Norway ( separated from the Norwegian Petroleum Directorate as of 1 January 2004) have adopted joint, total regulations relating to health, environment and safety on the NCS. The Ministry of Labor and Social Affairs and the Ministry of Environment administer these regulations. In addition, a number of regulations adopted under other acts, such as the Working Environment Act of 1977 and the Pollution Act of 1981, apply to Hydro’s operations. Violations of such regulations can lead to fines.

                    In Hydro’s capacity as a holder of licenses under the Petroleum Act, it is subject to strict statutory liability in respect of losses or damages suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of its licenses. This means that anyone who suffers losses or damages as a result of pollution caused by any of Hydro’s NCS license areas can claim compensation from Hydro without needing to demonstrate that the damage is due to any fault on Hydro’s part. If the pollution is caused by a force majeure event, a Norwegian court may reduce the level of damages to the extent it considers reasonable.

     EU Regulation

                    Although Norway is not a member of the EU, it is a member of the European Free Trade Association (“EFTA”). The European Union and its Member States have entered into the Agreement on the European Economic Area (the “EEA Agreement”) with the members of the EFTA other than Switzerland. The main purpose of the EEA Agreement is to include the EFTA countries in the European Common Market. The EEA Agreement makes relevant provisions of EU legislation binding for the EFTA states other than Switzerland. Regulations and directives affecting Hydro are being adopted, in an increasing number, within the EU and then implemented in Norway under the EEA Agreement.

                    EU Emissions Trading Directive

                    In January 2005, the Union Greenhouse Gas Emission Trading Scheme (EU ETS) commenced operation. The scheme is based on Directive 2003/87/EC, which became effective in October 2003. The scheme will limit carbon dioxide emissions from a broad range of industries, including power generation, and place them within a regulatory framework. Under the directive, all producers with significant emissions of climate gases will be given an emissions permit for each year of production. Each member state will develop a national allocation plan for such permits. The emissions trading system will increase a producer’s costs if that producer does not achieve its targets. Additional costs would also be associated with the development of emissions reduction technology and trading tools. Norway considers the directive to fall outside the scope of the EEA Agreement and has passed an act establishing its own national emissions trading scheme with effect from 1 January 2005. Offshore oil and gas production is currently not included in this scheme.

                    EU Gas Directives and Related Regulatory Developments

                    Fundamental changes are now taking place in the organization and operation of the European gas market, with the objective of opening up national markets to competition and integrating them into a single EU internal market for natural gas. It is difficult to predict the effect of liberalization measures on the evolution of gas prices, but the main objective of the single gas market is to bring greater choice and reduced prices for customers through increased competition.

                    The EU Gas Directive of 1998 (Directive 98/30/EC, 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

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authorizations for transmission, distribution, supply and storage of natural gas. The directive imposed a series of obligations on EU member states and other states implementing the directive. In June 2002, the Norwegian Parliament (Storting) agreed to incorporate the directive into its legislation as part of the EEA Agreement.

                    On 26 June 2003, the European Parliament and the Council of the European Union adopted Directive 2003/55/EC (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. On April 20, 2004, the EU Parliament in its first reading adopted the proposal with a number of amendments, and on 15 November 2004, the Energy Council adopted a common position on the draft regulation. The common position is based on the Commission’s proposal, but is more limited with regard to subjects that are covered by the Commission’s authority to propose implementing guidelines.

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The Energy Council agreed that the date for applying the regulation should be moved from 1 July 2005 to 1 July 2006.

     Liberalization of European Electricity Markets

     The EU electricity liberalization directive of 1996, to a large extent, left implementation of the deregulation process to the EU member states. As a result, each country designed its own national market structure. These structures are not entirely compatible. The European Commission has acknowledged this problem on a number of occasions, indicating that action will be taken to remedy the situation. In 2003, the European Union enacted a number of provisions bearing on the European electricity market:

Taxation of Oil and Gas Production

Norway

     Ordinary Taxes. Profits from petroleum production and pipeline transportation are subject to Norwegian income tax at the rate of 28 percent. Revenue for tax purposes is based on market norm prices (as determined by a government-appointed board, normally on a quarterly basis but in recent years with large price fluctuations, on a monthly basis) for crude oil and on realized prices for gas and other primary products. The taxation of a company’s income associated with its exploration and production activities on the NCS is assessed on a consolidated basis.

     Investments in oil and gas production facilities are, in general, depreciated for tax purposes over six years using a straight-line method of depreciation (i.e., 16.66 percent per year). However, there is an exception for certain large-scale gas liquefaction facilities; such investments are depreciated over three years (i.e., 33.33 percent per year). Depreciation commences when expenditures are incurred. Deductions for exploration and other costs can be taken in the year such costs are incurred.

     Any NCS losses may be carried forward indefinitely against subsequent income earned. Any onshore losses may be carried forward for 10 years. Half of the losses relating to activity conducted onshore in Norway may be deducted from NCS income subject to the 28 percent tax rate. Losses from foreign activities may not be deducted against NCS income. Losses from offshore activities are fully deductible against onshore income.

     Special Petroleum Tax. A special petroleum tax is levied on profits derived from petroleum production and pipeline transportation on the NCS. The special petroleum tax is currently levied at a rate of 50 percent. The special petroleum tax comes in addition to the standard 28 percent income tax, resulting in a 78 percent marginal tax rate on income subject to the petroleum tax. The basis for computing the special petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible against the special petroleum tax, and a tax-free allowance, or uplift, has been granted at a rate of 5 percent of capital expenditures per year over a period of a

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minimum of six years (equal to a maximum total of 30 percent of the capital expenditures). The uplift is computed on the basis of the original capitalized cost, including capitalized interest, of offshore production installations. The uplift may be deducted from taxable income for a period of six years beginning in the year in which the capital expenditures are incurred. Unused uplift may be carried forward indefinitely. Special provisions apply to investments made prior to 1992. Deficits relating to NCS exploration and production activities can be carried forward indefinitely, both for ordinary and special petroleum tax purposes. Deficits incurred in 2002 and later can for both tax categories be carried forward with interest. The Ministry of Finance is authorized to issue guidelines on the interest rate.

     As part of Revised National Budget passed in June 2004, the Norwegian government adopted changes to the Petroleum Tax Act effective for 2005. The tax-free allowance, or uplift, will be accelerated to 7.5 percent of capital expenditures per year over a period of four years. Furthermore, if in a non-taxpaying position, the State will pay in cash the tax value of deficits connected to exploration in connection with the yearly tax assessment. The State will also pay in cash the tax value of deficits if a company ceases its activities on the Norwegian Continental Shelf. Changes also include simplification of tax-related conditions in relation to transfer of licenses, and changes in regulations regarding depreciation of investments in fields with life spans of less than six years. Larger flexibility in contracts between oil companies and contractors will be allowed.

Taxation Outside Norway

     Hydro’s international petroleum activities are covered by local tax legislation. The following provides a brief description of the relevant tax systems of the countries where Hydro has production. Hydro’s Canadian production is covered by the corporate income tax regime, which is not project specific. Royalties apply to both producing projects and the terms are project specific. Hydro’s remaining international production is regulated by production sharing agreements (PSAs). Under a PSA, the host government typically retains the right to the hydrocarbons in place. The contractor under a PSA normally receives a share of the oil produced to recover its cost, and is entitled to an agreed share of the oil as profit in addition. Normally, the contractors carry the exploration costs and risk prior to a commercial discovery. Provisions are, to a large extent, negotiable and are unique to each block. All negotiated and bilateral provisions in the PSAs are subject to a confidentiality clause. The presentation of the taxation as such is, therefore, limited to the structure of the PSAs and to the official information involved.

     Under some PSAs, all government take will be in the form of royalty and/or profit oil allocated to the state, whereas other PSAs also include an income tax element. Income is split between a cost oil share for the recovery of costs, and a profit oil pool for further split between the state and the contractors. Allocation of profit oil between the state and the contractor group may depend on many factors, for example, the development of the internal rate of the return of the project, the production rate or the accumulated production. As a result, a larger share will normally be allocated to the state during the life of the production period. Linear depreciation over the first four to five years in production is commonly used. Some PSAs allow for an uplift of the investments, which is included as an additional depreciation in the investment costs and thereby increases the cost recovery entitlement. Most PSAs allow unrecovered costs in one year to be carried forward for recovery in later years. The direct state participation in PSAs has varied, but seems to be more frequent in recently awarded blocks. Different variations as to financing of the direct state share are seen.

     Some PSA regimes allow for consolidation of income from different developments in a block; other PSAs set a “ring fence” for tax purposes around each development. A ring fence around a development area means that the area is defined as a separate entity for tax calculation purposes, meaning that all development and production costs related to a development can only be recovered through income from the same development. One development may also consist of more development areas, all of which are ring fenced for tax purposes. The term “development area” in this respect may be a defined geological structure that may be produced from a common production facility.

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

     Canada. The fiscal regime consists of both royalty and provincial/federal tax systems. There are generic royalty regimes for the Grand Banks and Scotian Shelf areas; however, the Hibernia and Terra Nova fields have unique royalty systems. An allowance of 25 percent of operating income is deductible for income tax purposes, and replaces the actual royalty paid. This allowance will be phased out by 2007 and replaced by full deductibility of royalties paid for income tax purposes. The East Coast royalty regimes are progressive with the size of the royalty depending on the field’s economy and life cycle. Tax depreciation of facilities is 25 percent per year based on a declining balance method of depreciation. Exploration expenses may be fully written off. The combined Canadian federal and provincial tax rates are declining and will be reduced from the current 40 percent to 36 percent by 2007. Consolidation for tax purposes across all Canadian income is allowed within one legal entity (corporation); however, it is not allowed between separate legal entities.

     Russia. The Kharyaga field is taxed based on a PSA. Gross income after deduction of the royalty is split in cost oil and a profit oil share. A 35 percent income tax is levied on the contractor share of the profit oil. The profit oil split is based on the project’s cumulative internal rate of return.

     Libya. The Mabruk field is taxed based on a PSA. Gross income after deduction of royalty is eligible as cost oil, and any surplus oil is allocated as profit oil. The profit oil is divided between the state and the contractors based on a sliding scale which is related to the daily production rate and a cumulative income to cost ratio. No further income tax is levied on the contractors’ share of the profit oil. The Murzuq fields are taxed based on a PSA. The Libyan national company (“NOC”) is carried through the exploration phase and partly through the development phase, and then takes a certain ownership share of total production. The net income, after deduction of NOC`s direct share, is used for cost recovery. Any surplus is split as profit oil between the NOC and the contractors, with a sharing principle as for the Mabruk development. No further income tax is levied. Consolidation of operations within the Murzuq blocks is allowed.

     Angola. The producing fields, Girassol and Jasmim, are taxed based on the Block 17 PSA. Gross income is split in cost oil and a profit oil share. The contractor’s share of the profit oil is based on the project’s cumulative internal rate of return. A 50 percent income tax is levied on the contractors’ share of the profit oil. A ring fence around each development area in the block applies for tax purposes. Exploration costs, however, can be recovered from the entire block.

Taxation of Electricity

Ordinary Taxes (Norway)

     Profits from hydroelectric power production are subject to ordinary Norwegian income taxation at a rate of 28 percent. Fixed assets are depreciated for tax purposes over 67 years or the concession period, if shorter (dams and tunnels); 40 years (machinery); and at a 5 percent declining balance (transmission and other electrical equipment).

     A company’s ordinary income tax for hydroelectric power plants is assessed on an aggregate basis and may be tax consolidated with other activities in Norway.

     A natural resource tax of NOK 0.013 per KWh is leveled on hydro-generated electricity. The tax is fully deductible from the ordinary income tax of the company.

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Resource rent tax on hydroelectric power plants (Norway)

     The resource rent tax on hydroelectric power production in Norway is a tax on profits above a certain level and is additional to the ordinary tax. The tax rate is 27 percent and it is assessed individually for each hydroelectric power plant (i.e., ring-fenced taxation). Unlike the ordinary income tax, finance costs are not deductible. Uplift is a special deduction in the net income computed as a percentage of the average tax basis of fixed assets (including intangible assets and goodwill) for a given year. The percentage, which is determined annually by the authorities, essentially provides for a certain return on fixed assets that is not subject to surtax. The percentage used to calculate the uplift for 2004 was 8.5 percent.

     Revenue for resource rent tax is, with certain exceptions, calculated on the plant’s production, hour by hour, multiplied by the area spot price in the corresponding hour. Revenues from power supplies used for a company’s own industrial production facilities and from sales under certain long-term contracts are not subject to market spot price assessment. As most of Hydro’s hydroelectric production is used for its own industrial production or sold under qualifying contracts, only a minor portion of the production is subject to taxation based on spot prices at the time of production. The resource rent price for power production supplied to the corporation’s own industrial use in Norway is 170 NOK/MWh in 2004.

     Losses in the resource rent assessment can be carried forward indefinitely or until the plant reverts to the Norwegian government. Losses carried forward are increased with interest.

HYDRO ALUMINIUM

Introduction and Overview

     Hydro Aluminium is one of the top three integrated aluminium suppliers in the world, in terms of volume of integrated aluminium products produced. Hydro Aluminium is a full range aluminium supplier including primary aluminium, rolled products, extruded and other fabricated products. In 2004, Hydro Aluminium’s total revenues were NOK 79.7 billion compared to NOK 69.2 billion in the prior year.

Over the past few years, Hydro Aluminium has focused on improving performance through:

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     The graph below depicts Hydro Aluminium’s aluminium operations, in terms of 2004 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 an attractive material include its light weight, strength, recyclability, corrosion resistance, durability, ductility and electrical conductivity. Because of aluminium’s unique combination of properties, the variety of aluminium products continues to grow.

Aluminium Smelting

     The primary raw material for aluminium smelting is alumina, which is refined from bauxite. Bauxite deposits are most commonly found in tropical and subtropical regions of the world, such as West-Africa, India, Jamaica, South America (Brazil, Surinam, Venezuela, and Guyana) and Australia. Bauxite is generally extracted by open pit mining. More than 100 million tonnes of bauxite are mined each year. Approximately two tonnes of bauxite are required to produce one tonne of alumina; and approximately two tonnes of alumina are required to produce one tonne of aluminium.

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     Alumina is dissolved in an electrolyte, which is contained in a silicon carbide and graphite lined steel container known as a “pot.” An electric current is passed through the electrolyte at low voltage, but at very high current, typically 150,000 amperes, or as high as 300,000 amperes with modern technology. By means of electricity and carbon (anode), the alumina is reduced into liquid aluminium metal and carbon dioxide gas . Various technologies can be used for the process. Some production lines are based on the Søderberg technology, which will be phased out of Hydro’s Norwegian smelters due to environmental legislation (see discussion under “Metals – Primary Aluminium Production” below). Newer and more efficient is the so-called “prebake” cell technology. Hydro’s own prebake cell technology, HAL 275, combines low investment costs with high productivity, low energy consumption and reduced emissions. The technology is compact, economical and environmentally friendly.

     The molten aluminium is periodically siphoned off into a holding furnace, then cleaned and cast into metal products, such as extrusion ingot, sheet ingot, wire rod, primary foundry alloy, continuous cast coil and standard ingot. The molten aluminium is often alloyed with other metals, including iron, silicon, zinc, copper and magnesium, to form alloys with different properties.

     It takes roughly 14 kilowatt-hours (“kWh”) of electricity (industry average) to produce one kilogram of aluminium from alumina. Design and process improvements have progressively reduced this figure from about 21 kWh in the 1950s. In a modern smelter, the electricity consumption could be approximately 13 kWh per kilogram. Nonetheless, aluminium smelting remains an energy-intensive process, which is why the world’s smelters are located in areas that have access to abundant power resources. High energy prices have reinforced this trend with more smelters being located in remote, low energy cost areas, where electricity is generated specifically for the aluminium plant. A significant part of the energy used to produce aluminium is supplied to the European market from hydro-electricity.

     The reduction process is continuous. A metal plant cannot easily be stopped or started. If production is interrupted by a power failure of more than three to five hours, the metal in the pots will solidify, often requiring an expensive restarting process.

Processing of Aluminium

     Rolled Products

     The aluminium rolling process changes the characteristics of the metal, making it less brittle and more ductile. Prior to rolling, the aluminium is in the form of a continuous cast coil or rolling sheet ingot that typically is up to 600 millimetres (“mm”) thick. The rolling sheet ingot is then heated to around 500 degrees Celsius and passed several times through a hot rolling mill. This gradually reduces the thickness of the metal to around 3-13 mm. The thinner aluminium is then cooled and transported to a cold rolling mill for further processing. There are various types of cold rolling mills, producing various types of rolled product with thicknesses as low as 0.006 mm in the case of foil. In general, the type of product depends on the alloy used, the rolling deformation and the thermal treatment used in the process. Rolling mills are controlled by very precise instruments and measuring systems. Rolled products include:

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     Extrusion

     Aluminium cylinders, referred to as extrusion ingots, which are cast from molten aluminium, can be extruded by heating the aluminium to around 450-500 degrees Celsius and pushing it through a die at great pressure to form intricate shapes and sections. The primary applications for extrusions include:

Extruded products are sold in various forms, such as long lengths (e.g., six meters), cut to length, machined, formed, assembled in a component or module or as systems.

     Casting

     Aluminium can be cast into an infinite variety of shapes. Cast parts are used in a variety of applications including: light weight components for vehicles, aircraft, ships and spacecraft; general engineering components; architectural fittings; and high-tech products for office and home. Cast products can be produced using either sand casting (used for high production volume processing) or die casting.

     Recycling

     Anything made of aluminium can be recycled repeatedly. The recycling of aluminium requires only about five percent of the energy needed to produce primary metal. Scrap aluminium has significant value and commands good market prices. Many aluminium companies, including Hydro Aluminium, have invested in dedicated state-of-the-art secondary metal processing or “remelt” plants to recycle aluminium.

Long-term Market Developments

     Growth in Aluminium Consumption

     Aluminium consumption in the Western World (i.e., the world, excluding China, the Commonwealth of Independent States (CIS), North Korea and Eastern Europe) has realized an average annual growth rate of approximately 2.5 percent over the last two decades. Industry analysts, such as Brook Hunt, predict future growth in the Western World’s consumption of aluminium in the next decade to be approximately three percent per year. On a global basis, the growth rate is expected to be about four percent, mainly due to increasing consumption in China and the CIS. World consumption of primary aluminium in 2004 was approximately 30 million tonnes.

     Asia’s, and in particular China’s influence on the aluminium market has increased over the last years. China’s rapid increase in aluminium production has created increased uncertainty around the potential oversupply situation that could negatively affect international prices. China has traditionally been a net importer of primary aluminium. However, during 2002, China’s capacity and production increased by about 30 percent while consumption grew by about 17 percent, and the country became a net exporter (approximately 200,000 tonnes). For 2003, net exports increased by an estimated 150,000 tonnes to a total estimated 350,000 tonnes. Production in China increased significantly during the last quarter of 2004, leading to a growth rate of roughly 20 percent in 2004 compared with 2003. Consumption increased by an estimated 17 percent for 2004 as a whole. Net exports of primary

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aluminium surged during the fourth quarter of 2004, to a total accumulated 2004 volume of about 650,000 tonnes. This development was apparently triggered by an announcement by the Chinese authorities of the abolition of an eight percent export subsidy by year end, together with the imposition of a five percent export tax. However, including scrap, semi-fabricated and other aluminium products, China imported an estimated 350,000 tonnes on a net basis in 2004 according to Chinese trade statistics. Over the longer term, China is expected to devote more or all of its aluminium production to domestic consumption. However, if consumption and production in China fail to develop in parallel, it will likely influence the metal pricing and the need for new capacity in the rest of the world. China has few natural advantages for primary production. The country must import alumina and power sources are located far inland. In addition, Chinese authorities announced a reduction of available credit for industrial development in China during the first quarter of 2004.

     In 2004, growth in demand in the United States, the world’s largest aluminium consuming region, was high, while growth in Europe was moderate. Total shipments of primary aluminium in the Western World increased approximately 7.5 percent (or 1.6 million tonnes) compared to the prior year. New capacity, adjusted for idled capacity, resulted in increased production of about 550,000 tonnes. In the world’s third largest consuming region, China, the increase in consumption was estimated at 17 percent. There was an increase in net primary exports to the Western World from China of about 300,000 tonnes. In addition, the CIS and Eastern Europe are estimated to have increased their net exports to the Western World by about 150,000 tonnes in 2004 compared to 2003. According to CRU International (CRU), total reported and unreported stocks are estimated to have decreased by about 200,000 tonnes in 2004, compared with an increase of about 400,000 tonnes in 2003.

     Development in aluminium inventories

     In 2004, reported inventories of primary aluminium (defined to include London Metal Exchange (LME), International Aluminium Institute (IAI), Japanese merchant/consumer and other reported stocks) in the Western World decreased significantly by approximately 700,000 tonnes to a level of approximately 2.9 million tonnes.

     Historically, stocks in the Western World have fluctuated considerably. From a level of approximately 1.5 million tonnes in the late 1980s, stocks peaked in 1993 at approximately 4.5 million tonnes and were thereafter rapidly reduced to approximately 2.6 million tonnes at the end of 1995. These changes were mainly attributable to the export of Russian metal to the Western World, and the subsequent production reduction implemented by producers. Since 1995 and until 2004, the annual fluctuations have been less than 500,000 tonnes. High and increasing stocks historically have had a downward impact on the aluminium price as illustrated in the following graph showing the LME 3-month price (i.e., the price quotation on the LME for delivery of metal three months from the date of quotation) and reported stocks estimated in days of consumption since 1994.

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     Aluminium price development

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

     The graph below illustrates the annual average LME 3-month price of aluminium during the 1981-2004 period.

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During the 1981-2004 period, the nominal LME 3-month price has reflected fluctuations based upon the factors described above while increasing marginally on an average annual basis. Seen over a long period (1960 – 2003) and adjusting for the U.S. GDP deflator, the LME 3-month price, stated in “real” terms, declined at an average annual rate of approximately one percent. Industry sources, like CRU, expect a decline in the real price of aluminium to continue in the long term.

     However, the increases in the prices of input factors (including alumina and energy) have contributed to high LME prices throughout 2004. According to independent market analysts alumina prices are expected to remain high in 2005, while a softening in the alumina market is expected from 2006 and onwards due to the introduction of new capacity. Average energy prices are expected to increase in real terms. An additional factor affecting the aluminium price is an expected favorable aluminium market balance in the short-term.

     Development in downstream consumption

     Aluminium is used in a variety of applications in several industries. The table below reflects a percentage breakdown of the estimated levels of Western World consumption by the principal consuming industries in 2004, and the historic annual growth rates for these industries over the period of 1998 through 2004 (2004 reflects forecasted figures).

     Regarding major applications, the transport segment is expected to experience the most significant growth rates in the foreseeable future. The packaging, as well as building and construction industries, appear to be more mature industries in terms of aluminium consumption.

     During 2004, there was a significant economic recovery in the United States, which has impacted the downstream aluminium industry, while the economy in Europe has experienced only a moderate improvement.

     Geographical production and market balance

     The table below provides a breakdown of the 2004 production volumes in the principal aluminium producing regions and the estimated percentage of total global production represented by each such region.

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