Equivalent measurements are based upon:

Miscellaneous terms:

- lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and

- wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure

after deduction for uncovered losses, book value of research and development, goodwill and net deferred tax assets as recorded in the balance sheet for the preceding financial year, and the aggregate value of treasury shares that we have purchased or been granted security in and of credit and security given by us pursuant to sections 8-7 to 8-9 of the Norwegian Public Limited Companies Act during preceding financial years.

We cannot distribute any dividends if our equity, according to the Statoil ASA unconsolidated balance sheet, amounts to less than 10 per cent of the total assets reflected on our unconsolidated balance sheet without following a creditor notice procedure as required for reducing the share capital. Furthermore, we can only distribute dividends to the extent compatible with good and careful business practice with due regard to any losses which we may have incurred after the last balance sheet date or which we may expect to incur. Finally, the amount of dividends we can distribute is calculated on the basis of our unconsolidated financial statements. Retained earnings available for distribution is based on Norwegian accounting principles and legal regulations and amounts to NOK 65,589 million (before provisions for dividend for the year ended December 31, 2004 of NOK 11,481 million) at December 31, 2004.

Although we currently intend to pay annual dividends on our ordinary shares, we cannot assure you that dividends will be paid or as to the amount of any dividends. Future dividends will depend on a number of factors prevailing at the time our board of directors considers any dividend payment.

Dividends paid historically are not representative of dividends to be paid in the future. Dividends paid prior to 2002 include 100 per cent of the cash flows from the SDFI assets transferred from the Norwegian State, and a percentage of net income after tax (calculated on a Norwegian GAAP basis) for all other activities. The following table shows the amounts paid to the Norwegian State prior to 2002 and to all shareholders since 2002 on a per share basis and in the aggregate, as well as dividends to be paid in 2005 on our ordinary shares for the fiscal year 2004.

(1)Based on 2,166,142,636 shares in 2004, 2,166,143,693 shares in 2003, 2,165,422,239 shares in 2002, 2,076,180,942 shares in 2001 and 1,975,885,600 shares prior to 2001, being the weighted average number of ordinary shares for each year.

(2)The USD amounts are based on the noon buying rate for Norwegian kroner on December 31, 2004, which was NOK 6.0794 to USD 1.00.

(3)Total dividends paid in 2001 include a cash settlement for the SDFI assets amounting to NOK 19.65 (USD 2.83) per share. An ordinary dividend for 2001 of NOK 2.85 was declared on May 7, 2002 and paid to shareholders registered in the Norwegian Central Securities Depository as of that date on May 28, 2002.

The increases in dividends for 2000 and 2001 were due to increase in cash flows generated from SDFI properties transferred from the Norwegian State and increased net income after tax for all other activities.

Dividends we paid in periods prior to 2002 reflected our status as wholly owned by the Norwegian State and should not be considered indicative of our future dividend policy.

Since we will only pay dividends in Norwegian kroner, exchange rate fluctuations will affect the US dollar amounts received by holders of ADSs after the ADR depositary converts cash dividends into US dollars.

Risk Factors

Risks Related to Our Business

A substantial or extended decline in oil or natural gas prices would have a material adverse effect on us.

Historically, prices for oil and natural gas have fluctuated widely in response to changes in many factors. We do not and will not have control over the factors affecting prices for oil and natural gas. These factors include:

It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices will adversely affect our business, results of operations and financial condition, liquidity and our ability to finance planned capital expenditures. For an analysis of the impact on income before financial items, taxes and minority interest from changes in oil and gas prices, see Item 5-Operating and Financial Review and Prospects-Operating Results-Factors Affecting Our Results of Operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that we can produce economically or reduce the economic viability of projects planned or in development.

Exploratory drilling involves numerous risks, including the risk that we will encounter no commercially productive oil or natural gas reservoirs, which could materially adversely affect our results.

We are exploring in various geographic areas, including new resource provinces such as the Norwegian Sea, the Barents Sea and deepwater offshore Angola, where environmental conditions are challenging and costs can be high. We are also considering exploration activities in additional international areas where costs may be high. In addition, our use of advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies. The cost of drilling, completing and operating wells is often uncertain. As a result, we may incur cost overruns or may be required to curtail, delay, or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. For example, we have entered into long-term leases on drilling rigs which are not required for the originally intended operations and we cannot be certain that these rigs will be re-employed or at what rate they will be re-employed. Our overall drilling activity or drilling activity within a particular project area may be unsuccessful. Such failure will have a material adverse effect on our results of operations and financial condition.

If we fail to acquire or find and develop additional reserves, our reserves and production will decline materially from their current levels.

The majority of our proved reserves are on the Norwegian Continental Shelf (NCS), a maturing resource province. Except to the extent we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. In addition, the volume of production from oil and natural gas properties generally declines as reserves are depleted. For example, two of our major fields, Statfjord and Gullfaks, are dependent on satellite fields to maintain production, and, unless efforts to improve the development of satellite fields are successful, production will gradually decline. Our future production is highly dependent upon our success in finding or acquiring and developing additional reserves. If we are unsuccessful, we may not meet our long-term ambitions for growth in production, and our future total proved reserves and production will decline and adversely affect our results of operations and financial condition.

We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of licenses, exploratory prospects and producing properties.

The oil and gas industry is extremely competitive, especially with regard to exploration for, and exploitation and development of new sources of oil and natural gas.

Some of our competitors are much larger, well-established companies with substantially greater resources, and in many instances they have been engaged in the oil and gas business for much longer than we have. These larger companies are developing strong market power through a combination of different factors, including:

These companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects, including operatorships and licenses, than our financial or human resources permit. For more information on the competitive environment, see Item 4-Information on the Company-Business Overview.

As we face a variety of challenges in executing our strategic objective of successfully exploiting growth opportunities available to us, the growth of our business may be compromised if we are unable to execute on our strategy and our financial and production targets may be revised as a result of acquisitions made in accordance with our strategy.

An important element of our strategy is to continue to pursue attractive growth opportunities available to us, both in enhancing our asset portfolio and expanding into new markets. The opportunities that we are actively pursuing may involve acquisitions of businesses or properties that complement or expand our existing portfolio. Our ability to implement this strategy successfully will depend upon a variety of factors, including our ability to:

As we pursue business opportunities in new and existing markets, we anticipate that significant investments and costs will be related to the development of such opportunities. We may incur or assume unanticipated liabilities, losses or costs associated with assets or businesses acquired. Any failure by us to pursue and execute new business opportunities successfully could result in financial losses, and could inhibit growth.

If we are successful in the pursuit of our strategy and the making of such acquisitions, and no assurances can be given that we will be, our ability to achieve our financial, capital expenditure and production targets may be materially affected. Any such new projects we acquire will require additional capital expenditure and will increase our finding and development expenditure. It is likely that such acquisitions will be in the exploratory or development phase and not in the production phase, which will have a material adverse effect on our net return in proportion to our average capital employed. These projects may also have different risk profiles than our existing portfolio. These and other effects of such acquisitions could result in us having to revise some or all of our targets with respect to ROACE, capital expenditure amounts and allocations, unit production costs, finding and development costs, reserves replacement rate and production.

In addition, the pursuit of acquisitions or new business opportunities could divert financial and management resources away from our day-to-day operations to the integration of acquired operations or properties. We have no current intention to issue additional equity; we may, however, require additional debt or equity financing to undertake or consummate future acquisitions or projects, which financing may not be available on terms satisfactory to us, if at all, and may, in the case of equity, be dilutive to our earnings per share.

Our development projects involve many uncertainties and operating risks that can prevent us from realizing profits and can cause substantial losses.

Our development projects may be delayed or unsuccessful for many reasons, including cost overruns, lower oil and gas prices, equipment shortages, mechanical and technical difficulties and industrial action. These projects will also often require the use of new and advanced technologies, which can be expensive to develop, purchase and implement, and may not function as expected. In addition, some of our development projects will be located in deepwater or other hostile environments, such as the Barents Sea, or produced from challenging reservoirs, which can exacerbate such problems. There is a risk that development projects that we undertake may suffer from such problems, such as the Snøhvit project where we have encountered cost overruns and face a challenging timetable for the assembly and transportation of the LNG plant, and the Kristin development, where we are facing difficult drilling conditions.

Our development projects on the NCS also face the challenge of remaining profitable where we are increasingly developing smaller satellite fields in mature areas and our projects are subject to the Norwegian State's relatively high taxes on offshore activities. Our other development projects in mature fields in Western Europe also face potentially higher operating costs. In addition, our development projects, particularly those in remote areas, could become less profitable, or unprofitable, if we experience a prolonged period of low oil or gas prices.

Many of our mature fields are producing increasing quantities of water with oil and gas. Our ability to dispose of this water in acceptable ways may impact our oil and gas production.

We may not be able to produce some of our oil and gas economically due to a lack of necessary transportation infrastructure when a field is in a remote location.

Our ability to exploit economically any discovered petroleum resources beyond our proved reserves will be dependent upon, among other factors, the availability of the necessary infrastructure to transport oil and gas to potential buyers at a commercially acceptable price. Oil is usually transported by tankers to refineries, and gas is usually transported by pipeline to processing plants and end-users. We may not be successful in our efforts to secure transportation and markets for all of our potential production.

Some of our international interests are located in politically, economically and socially unstable areas, which could disrupt our operations.

We have assets located in unstable regions around the world. For example, there was war and civil strife in the Caspian region through much of the 1990s. In addition, the states bordering the Caspian Sea dispute ownership and distribution of proceeds from the Caspian's seabed and subsoil resources. Our activities in the Persian Gulf may be subject to disruption due to, for example, war and terrorism. Other countries, such as Venezuela, Nigeria and Angola, where we also have operations, have experienced expropriation or nationalization of property, civil strife, strikes, acts of war, guerrilla activities and insurrections. The occurrence of incidents related to political, economic or social instability could disrupt our operations in any of these regions, causing a decline in production that could have a material adverse effect on our results of operations or financial condition.

Our activities in Iran could lead to US sanctions.

In August 1996, the United States adopted the Iran and Libya Sanctions Act, referred to as ILSA, which authorizes the President of the United States to impose sanctions (from a list that includes denial of financing by the export-import bank and limitations on the amount of loans or credits available from US financial institutions) against persons found by the President to have knowingly made investments in Iran of USD 20 million or more that directly and significantly contribute to the enhancement of such countries' ability to develop their petroleum resources. We take part in certain exploration projects or study activities with respect to Iran. In October 2002, we signed a participation agreement with Petropars of Iran, pursuant to which we assumed the operatorship for the offshore part of phases six, seven and eight of the South Pars gas development project in the Persian Gulf. At the end of 2004, we had invested USD 219 million in connection with the project. We cannot predict interpretations of or the implementation policy of the US Government under ILSA with respect to our current or future activities in Iran or other areas. It is possible that the United States may determine that these or other activities will constitute activity covered by ILSA and will subject us to sanctions.

We are exposed to potentially adverse changes in the tax regimes of each jurisdiction in which we operate.

We operate in 29 countries around the world, and any of these countries could modify its tax laws in ways that would adversely affect us. Most of our operations are subject to changes in tax regimes in a similar manner as other companies in our industry. In addition, in the long-term, the marginal tax rate in the oil and gas industry tends to change in correlation with the price of crude oil. Significant changes in the tax regimes of countries in which we operate could have a material adverse affect on our liquidity and results of operation.

We are not insured against all potential losses and could be seriously harmed by natural disasters or operational catastrophes.

Exploration for and production of oil and natural gas is hazardous, and natural disasters, operator error or other occurrences can result in oil spills, blowouts, cratering, fires, equipment failure, and loss of well control, which can injure or kill people, damage or destroy wells and production facilities, and damage property and the environment. Offshore operations are subject to marine perils, including severe storms and other adverse weather conditions, vessel collisions, and governmental regulations, as well as interruptions or termination by governmental authorities based on environmental and other considerations. Losses and liabilities arising from such events would significantly reduce our revenues or increase our costs and have a material adverse effect on our operations or financial condition.

The crude oil and natural gas reserve data in this Annual Report on Form 20-F are only estimates, and our future production, revenues and expenditures with respect to our reserves may differ materially from these estimates.

The reliability of proved reserve estimates depends on:

Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. Results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserve data. Any downward adjustment could lead to lower future production and thus adversely affect our financial condition, future prospects and market value.

We face foreign exchange risks that could adversely affect our results of operations.

Our business faces foreign exchange risks because a large percentage of our revenues and cash receipts are denominated in US dollars while a significant portion of our operating expenses and income taxes accrue in Norwegian kroner, reflecting our operations on the NCS. Movements between the US dollar and Norwegian kroner may adversely affect our business. While an increase in the value of the US dollar against the Norwegian kroner can be expected to increase our reported earnings, such an increase would also be expected to increase our operating expenses and the value of our debt, which would be recorded as a financial expense, and, accordingly, would adversely affect our net income. See Item 5-Operating and Financial Review and Prospects-Liquidity and Capital Resources-Risk Management.

Public authorities in the United States are conducting investigations into a consultancy arrangement we entered into with respect to business development in Iran, which, if proceedings are brought and determined against us, could result in fines, penalties, sanctions or other restrictions that could have a material adverse effect on our business.

The Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime (Økokrim) conducted an investigation concerning an agreement which Statoil entered into in 2002 with Horton Investments Ltd., a Turks & Caicos Island company, for consultancy services in Iran. On June 29, 2004, Økokrim informed Statoil that it had concluded that Statoil violated section 276c, first paragraph (b) of the Norwegian Penal Code and imposed a penalty on Statoil of NOK 20 million. Statoil's board decided on October 14, 2004 to accept the penalty without admitting or denying the charges by Økokrim. The U.S. Securities and Exchange Commission is conducting a formal investigation into this consultancy arrangement to determine if there have been any violations of U.S. federal securities laws, including the Foreign Corrupt Practices Act. The U.S. Department of Justice is also conducting a criminal investigation of the Horton matter jointly with the Office of the United States Attorney for the Southern District of New York. The SEC staff informed Statoil on September 24, 2004 that it is considering recommending that the SEC authorize a civil enforcement action in federal court against Statoil for violations of various U.S. federal securities laws, including the anti-bribery and books and records provisions of the Foreign Corrupt Practices Act. See Item 8-Financial Information-Legal Proceedings.

We continue to provide information to the U.S. authorities in order to assist them with their ongoing investigations. Responding to the requests of the public authorities and cooperating with their investigations continues to divert management's attention and resources, and any developments or requests by the authorities for additional information will engage more of management's attention and resources. We cannot predict the outcome of these inquiries being conducted by public authorities in the United States or the resulting effect that they might have on our business. If proceedings are brought and determined against us in the United States this may result in fines, penalties, sanctions or restrictions that could have a material adverse effect on our business or financial results.

Risks Related to the Regulatory Regime

Competition is expected to increase in the European gas market, currently our main market for gas sales, as a result of new European Union, or EU, directives which could adversely affect our ability to expand or even maintain our current market position or result in reduction in prices in our gas sales contracts.

Fundamental changes are now taking place in the organization and operation of the European gas market, with the objective of opening national markets to competition and integrating them into a single market for natural gas. This process started with the EU Gas Directive, which became effective in August 2000. The Directive was included into the EEA Agreement in June 2002, and all necessary changes in order to implement the Directive into Norwegian legislation were made during 2002. The Directive requires EEA states to take certain minimum steps to open their gas markets to greater competition. Each state must specify annually the wholesale and final gas customers inside its territory that have the legal capacity to contract for or be sold natural gas by the gas supplier of their choice.

The Directive also requires that eligible customers be given the right to negotiate agreements for using gas transport systems directly or rights of access based on tariffs or other mechanisms. A new Gas Directive is now approved by the EU. The new Gas Directive provides for accelerated requirements for market opening, which means that both large users and households will now be free to choose their supplier earlier than previously allowed.

Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that will be affected by changes in EU regulations. As a result of the Directive, our ability to expand or even maintain our current market position could be materially adversely affected and quantities sold under our gas sales contracts may be subject to a material reduction in gas prices.

We may incur material costs to comply with, or as a result of, health, safety and environmental laws and regulations.

Compliance with environmental laws and regulations in Norway and abroad could materially increase our costs. We incur and expect to continue to incur, substantial capital and operating costs to comply with increasingly complex laws and regulations covering the protection of the environment and human health and safety, including costs to reduce certain types of air emissions and discharges to the sea and to remediate contamination at various owned and previously-owned facilities and at third-party sites where our products or wastes have been handled or disposed. The new Petroleum Safety Authority Norway (PSA) was established on January 1, 2004, with the regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. Although existing regulations relating to HSE in petroleum activities continue with the PSA as the responsible authority, the PSA's sphere of responsibility has been expanded. see item 4-information on the company-regulation.

In our capacity as holder of licenses on the NCS under the Norwegian Petroleum Act of November 29, 1996, we are subject to statutory strict 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 our licenses. This means that anyone who suffers losses or damages as a result of pollution caused by operations at any of our NCS license areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part.

Whether in Norway or abroad, new laws and regulations, the imposition of tougher requirements in licenses, increasingly strict enforcement of or new interpretations of existing laws and regulations, or the discovery of previously unknown contamination may require future expenditures to:

In particular, we may be required to incur significant costs to comply with the 1997 Kyoto Protocol to the United Nations Framework Convention on Climate Change, known as the Kyoto Protocol, and other pending EU laws and directives. In addition, increasingly strict environmental requirements, including those relating to gasoline sulphur levels and diesel quality, affect product specifications and operational practices. Future expenditures to meet such specifications could have a material adverse effect on our operations or financial condition.

Political and economic policies of the Norwegian State could affect our business.

The Norwegian State plays an active role in the management of NCS hydrocarbon resources. In addition to its direct participation in petroleum activities through the SDFI and its indirect impact through tax and environmental laws and regulations, the Norwegian State awards licenses for reconnaissance, production and transportation and approves, among other things, exploration and development projects, gas sales contracts and applications for (gas) production rates for individual fields. The Norwegian State may also, if important public interests are at stake, direct us and other oil companies to reduce production of petroleum. Reductions of up to 7.5 per cent have been imposed in the past. By a royal decree of December 19, 2001, the Norwegian government decided that Norwegian oil production should be reduced by 150,000 barrels per day from January 1, 2002 until June 30, 2002. This amounted to roughly a 5 per cent reduction in output. Further, in the production licenses in which the SDFI holds an interest, the Norwegian State retains the ability to direct petroleum licensees' actions in certain circumstances.

If the Norwegian State were to take additional action pursuant to its extensive powers over activities on the NCS or to change laws, regulations, policies or practices relating to the oil and gas industry, our NCS exploration, development and production activities and results of operations could be materially and adversely affected. For more information about the Norwegian State's regulatory powers, see Item 4-Information on the Company-Regulation.

Risks Related to Our Ownership by the Norwegian State

The interests of our majority shareholder, the Norwegian State, may not always be aligned with the interests of our other shareholders, which may affect our decisions relating to the NCS.

The Norwegian Parliament, known as the Storting, and the Norwegian State have resolved that the Norwegian State's shares in Statoil and the SDFI's interests in NCS licenses must be managed pursuant to a coordinated ownership strategy for the Norwegian State's oil and gas interests. Under this strategy, the Norwegian State has required us to continue to market the Norwegian State's oil and gas together with our own as a single economic unit.

Pursuant to the coordinated ownership strategy for the Norwegian State's shares in us and the SDFI, the Norwegian State requires us in our activities on the NCS to take account of the Norwegian State's interests in all decisions which may affect the development and marketing of our own and the Norwegian State's oil and gas.

The Norwegian State holds more than a two-thirds majority of our shares. Accordingly, the Norwegian State has the power to determine matters submitted for a vote of shareholders, including amending our articles of association and electing all of the members of the corporate assembly except employee representatives. The employees may claim the right to be represented by up to one-third of the members of the board of directors as well as the corporate assembly. The corporate assembly is responsible for electing our board of directors and communicates its recommendations concerning the board of directors' proposals about the annual accounts, balance sheets, allocation of profits and coverage of losses of our company to the general meeting. The interests of the Norwegian State in deciding these and other matters and the factors it considers in exercising its votes, especially pursuant to the coordinated ownership strategy for the SDFI and our shares held by the Norwegian State, could be different from the interests of our other shareholders. Accordingly, when making commercial decisions relating to the NCS, we have to take into account the Norwegian State's coordinated ownership strategy and we may not be able to fully pursue our own commercial interests, including those relating to our strategy on development, production and marketing of oil and gas.

If the Norwegian State's coordinated ownership strategy is not implemented and pursued in the future, then our mandate to continue to sell the Norwegian State's oil and gas together with our own as a single economic unit is likely to be prejudiced. Loss of the mandate to sell the SDFI's oil and gas could have an adverse effect on our position in our markets. For further information about the Norwegian State's coordinated ownership strategy, see Item 7-Major Shareholders and Related Party Transactions-Major Shareholders.

Forward-Looking Statements

This Annual Report on Form 20-F contains forward-looking statements that involve risks and uncertainties, in particular under Item 4-Information on the Company and Item 5-Operating and Financial Review and Prospects. In some cases, we use words such as "believe", "intend", "expect", "anticipate", "plan", "target" and similar expressions to identify forward-looking statements. All statements other than statements of historical facts, including, among others, statements regarding our future financial position, business strategy, budgets, reserve information, reserve replacement rates, reserve recovery factors, projected levels of capacity, production growth, projected operating costs, finding and development costs, exploration expenditure, estimates of capital expenditure, expected exploration and development activities and plans, start-up dates for upstream and downstream activities, HSE goals and objectives of management for future operations, are forward-looking statements. You should not place undue reliance on these forward-looking statements. Our actual results could differ materially from those anticipated in the forward-looking statements for many reasons, including the risks described above in Item 3-Key Information, below in Item 5-Operating and Financial Review and Prospects, and elsewhere in this Annual Report on Form 20-F.

These forward-looking statements reflect current views with respect to future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. There are a number of factors that could cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements, including levels of industry product supply, demand and pricing; currency exchange rates; political and economic policies of Norway and other oil-producing countries; general economic conditions; political stability and economic growth in relevant areas of the world; global political events and actions, including war, terrorism and sanctions; the timing of bringing new fields on stream; material differences from reserves estimates; inability to find and develop reserves; adverse changes in tax regimes; development and use of new technology; geological or technical difficulties; the actions of competitors; the actions of field partners; natural disasters and other changes to business conditions; and other factors discussed elsewhere in this report.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot assure you that our future results, level of activity, performance or achievements will meet these expectations. Moreover, neither we nor any other person assumes responsibility for the accuracy and completeness of the forward-looking statements. Unless we are required by law to update these statements, we will not necessarily update any of these statements after the date of this Annual Report, either to conform them to actual results or to changes in our expectations.

Statements Regarding Competitive Position

Statements made in Item 4-Information on the Company, referring to Statoil's competitive position, are based on our belief, and in some cases rely on a range of sources, including investment analysts'reports, independent market studies and our internal assessments of market share based on publicly available information about the financial results and performance of market participants.

In pursuit of our strategic objectives, we intend to:

Deliver growth and performance. We believe that we enjoy a strong position both strategically and financially having shown significant improvements since the IPO in 2001. We have developed specific strategies and plans that underpin our ambitions of long-term profitable growth. Our efforts to deliver on these ambitions are supported by a set of corporate initiatives that will support delivery on our 2007 targets and lay the basis for long-term growth. The corporate initiatives cut across the business areas and are intended to continue the development of the group's strategic foundation. Ten of the corporate initiatives, together with associated ambitions, have been communicated externally, and fall into short-term and long-term categories. Additional initiatives are likely to be added at a later stage. In addition a number of improvement measures have been implemented by the business areas.

Those initiatives intended to take effect in the immediate future include:

Initiatives intended to yield long-term results include:

All of these initiatives, which have not been set as formal targets, have been set at a level that we believe will stretch the organization. Failure to meet one or two of these initiatives will not negate the improvement efforts.

See Item 5-Operating Review and Prospects for a review of our 2004 performance. Specific details regarding our 2007 corporate targets can be found in Item 5-Operating Review and Prospects-Corporate Targets.

Driving new growth in E&P Norway. We are the leading operator and producer of oil and gas on the NCS, a region with significant remaining resources. We have increased our production target by 10 per cent to 1.1 mmboe per day in 2007. Our portfolio of producing fields and new projects allows us to fulfill this target without being dependant on additional discoveries. Our long-term ambition is to sustain a level of 1 mmboe per day beyond 2010. Fulfillment of this longer term ambition will require new discoveries through focused exploration efforts on the NCS.

To realize the increased production target in 2007, and at the same time manage the production decline of mature fields, we will intensify our effort to increase recovery and realize new projects. The most important new projects that will contribute to achieving the increased production target in 2007 are Snøhvit, Ormen Lange, Kristin and the pre-compression project on Troll. All of these projects are sanctioned.

We have initiated a new drive for improvements, targeting both income and cost factors in our activity. Two important improvement initiatives are a revised maintenance strategy and implementation of integrated operations. Both initiatives provide a better framework for more efficient operations of the producing fields on the NCS.

In order to fulfill the long-term production ambitions beyond 2010 we will continue our efforts to increase recovery, realize production from current opportunities and actively pursue exploration opportunities. We also expect a significant contribution to our production from projects under evaluation, primarily after 2007. Constraints from developing these projects so far have been access to infrastructure, reservoir uncertainties and optimum field development concepts. Going forward, we will continue our efforts to pursue innovative solutions and profitable concepts.

Most of the undiscovered resources on the NCS are expected to be located in the Norwegian Sea and in the Barents Sea. Large volumes of undiscovered resources are also expected to be found in the North Sea. We foresee a substantial increase in drilling activity in the years to come, both in areas close to existing infrastructure and in frontier areas. The most important frontier areas are the deepwater areas of the Norwegian Sea and the Barents Sea. In 2005 we plan to participate in three exploration wells in both the deepwater areas of the Norwegian Sea and the Barents Sea; five of these six wells are Statoil operated. In the Barents Sea we plan to start production from the Snøhvit LNG field during the second half of 2006. We expect regular production during the first half of 2007. The Snøhvit LNG project is our initial step in developing the Barents Sea region.

Accelerate International E&P production growth. Having targeted and concentrated our international exploration and production activities in selected areas we are focusing our efforts on establishing significant production and increasing our influence in our producing areas:Caspian, North Africa, Venezuela, Western Africa, and Western Europe. We are also exploring additional opportunities in other areas that support our strategy and leverage our skills and competence from the NCS. Future potential areas include the Middle East and Russia. We will pursue attractive opportunities as they arise and as our capital budgets permit. These opportunities may include acquisitions of oil or gas assets in development phase or production phase that complement or expand our existing portfolio. We will also continue to manage our portfolio of assets to seek to further increase profitability and secure operating influence and, where beneficial, operatorships.

Increase profits in the gas value chain. As a leading supplier of gas to Europe, we are well positioned to benefit from growing demand for gas and the deregulation of gas markets, and will adapt to new commercial opportunities. We intend to actively manage our upstream portfolio and transportation capacities to maximize the income from existing long-term natural gas contracts. We aim to exploit economies of scale in marketing of gas, and in particular, we intend to capitalize on the trading and optimization opportunities that will arise with the anticipated increase in demand for imports of gas in the United Kingdom, a market we are well positioned to supply. We will also increase our ability to realize additional margin and optimize synergies by extracting and commercializing NGL streams to meet internal and external demand for NGL. Moreover, we aim to build gas value chains from supply areas other than the Norwegian Continental Shelf into Europe, and proceed from our positions in the Caspian and in the Barents Sea (the Snøhvit LNG project). Our position in the Cove Point LNG terminal will enable us to build an Atlantic LNG business and a US gas marketing business. We may also leverage our natural gas value chain and marketing expertise to capture exploration and development opportunities elsewhere.

Strengthen our downstream performance and position. Emphasis will be put on integration with our upstream businesses, and more efficient distribution of our products to the end user. We are the largest retailer of gasoline in Scandinavia and we expect to be able to strengthen our position further with the integration of our Scandinavian and international retail operations. In refining, partially through our joint ventures with the Shell group at Mongstad and Pernis, we intend to continue with our cost reductions and productivity improvements to increase utilization and efficiency of existing capacity. In addition we continuously need to develop the refineries in order to meet future product specification requirements and Borealis plans to improve its position in petrochemicals based on cost improvement programs and site restructuring.

Exploration and Production Norway

Introduction

E&P Norway is the cornerstone of our business, consisting of exploration, development and production operations on the NCS. We participate in the majority of the 47 producing oil and gas fields on the NCS and as of December 31, 2004, we were the operator for 22 of these. We are the sole operator in the Tampen area. We are also the operator of the Troll gas field in the Troll/Sleipner area. Other major oil and gas fields in the Troll/Sleipner area include Sleipner, where we are operator, and Oseberg. The main producing fields in the Halten/Nordland area include Heidrun, Åsgard and Norne, all of which we operate. E&P Norway reported income before financial items, income taxes and minority interest of NOK 51,029 million, an increase of 35 per cent compared to 2003. In the year ended December 31, 2004, we produced 991 mboe per day compared with 991 mboe per day in 2003.

The following table presents key financial information about this business segment.

Further details on the financial results can be found in Item 5-Operating and Financial Review and Prospects-Operating Results.

The NCS. We are the leading exploration, production and transport company on the NCS. We currently hold production and exploration licenses covering a total area of approximately 61,510 square kilometers, and production licenses in respect of approximately 3,401 mmboe of proved reserves as of December 31, 2004, compared to 3,560 mmboe as of December 31, 2003.

Commercial petroleum deposits were first proved on the NCS in the late 1960's. Norwegian oil production began in 1971 and accounted for most of the production growth until the late 1990's. Since then, the growth has been in gas production. Our production from the NCS is expected to remain at the present level over the next five to ten years before going into a gradual decline. In order to counteract this in coming years, our recovery rate must continue to be improved, resources not presently covered by development plans must be brought on stream and new oil and gas discoveries must be made. We believe that significant opportunities remain on the NCS. In addition to the possibility of large discoveries, production will come from a large number of smaller fields, many of which will be characterized by complex geology. These fields will require the innovative application of advanced technologies, for which we have a proven record of success. The map to the right indicates the location of the areas referred to within this section.

Core Producing Areas. We have three core producing areas on the NCS: Troll/Sleipner, Halten/Nordland and Tampen. The fields in each area use common infrastructure, such as production installations, and oil and gas transport facilities where possible, which together reduce the investment necessary to develop new fields. Our efforts in the core areas will also focus on developing smaller fields through the use of existing infrastructure and enhancing production by improving recovery factors. We are working actively to extend the production from our fields through improved reservoir management and application of new technology. Key elements in our improved recovery efforts include:

We believe that much of the improvement in expected ultimate recovery factors that we have seen over the last decade can be attributed to our systematic reservoir and production management and the use of improved oil recovery methods.

Potential Producing Areas

In addition to our three producing core areas, we are well positioned in the central and southern parts of the North Sea, in the Møre/Vøring (Norwegian Sea) and the Lofoten areas of Norwegian Sea and in the Barents Sea, all of which we believe to have significant hydrocarbon resource potential.

North Sea. Total licensed acreage in the North Sea covers approximately 23,690 square kilometers, of which we are the operator of 7,110 square kilometers. Within this region, two exploration wells were drilled in 2004 of which one was within our producing core area Tampen. The Tampen well, called Topas, was drilled from the Gullfaks C platform and was an oil discovery. The well will be converted to a production well and test production started in February 2005. In addition one dry well was drilled as an extension of a production well from the Snorre B platform. In the central and southern parts of the North Sea one well was drilled by ExxonMobil in 2004. The well resulted in an oil discovery. Evaluation of the discovery will continue in 2005. Two licenses were relinquished in the central and southern area in 2004. Eight new licenses, including additional acreage close to existing acreage, were awarded to us in the North Sea in 2004. In 2004 we took over the operatorship for the development phase of PL153 Gjøa. Gaz De France will be the operator for this license from the start of production. In addition, we acquired an interest in one existing license, obtained approval from the Ministry of Petroleum and Energy (OED) to carve out acreage in one license and relinquished all our interests in one other license.

Norwegian Sea. We have interests in approximately 28,630 square kilometers of licensed acreage in the Norwegian Sea of which we are the operator for 12,660 square kilometers. Four exploration wells were drilled in 2004 in this area. One dry well was drilled by Chevron Texaco in Halten/Nordland area, west of the Norne field. We were the operator for three exploration wells in our producing core area Halten/Nordland, which in 2004 resulted in two discoveries. The third well, close to the Heidrun area was dry. Oil was discovered in a well located northeast of the Norne field. The discovery is in an area with several other oil discoveries and prospects. Exploration and evaluation of the area will continue in 2005. An appraisal well confirmed and increased the discovery in Alve and further development studies will be considered in 2005. In the Møre/Vøring region, which is the deepwater part of the area with depths ranging from 400 meters to 2,000 meters, we have interests in licenses covering approximately 13,650 square kilometers. No wells were drilled in this area in 2004. The Lofoten area, in which we have interests in 250 square kilometers of licensed acreage, is one of several major oil provinces left to explore on the NCS. The Norwegian Government decided late in 2003 not to allow further petroleum activity in the area due to its special character as a spawning ground for important fish stocks and as a fishing ground. The Government has found that, at present, it has not been demonstrated that adequate protection of the fisheries and the environment can be maintained if petroleum activities are allowed in the area. This entails that the two production licenses which have been awarded in the area cannot resume their activities, and that no new awards will be given. Commencement of all-year petroleum activity in the Lofoten area will be considered again when the integrated management plan for the Barents Sea is completed in 2005. Eleven new licenses, including additional acreage to existing acreage, were awarded to us in the Norwegian Sea in 2004. In addition we acquired interests in one existing license and obtained approval from the OED to carve out acreage in two licenses.

Barents Sea Our fourth core area, Tromsøflaket, includes our gas discovery Snøhvit, which is currently under development and is scheduled to be on stream in 2006. In addition to acreage of 950 square kilometers in this core area, we have further interests in 8,210 square kilometers of licensed acreage and 13,500 square kilometers consisting of three seismic option areas. Under the terms of the seismic option agreement, the license group is committed to perform specified seismic evaluation of the area and at any time prior to May 15, 2007, the license group has the right to obtain a production license with the obligation to drill exploration wells. The Government has decided to allow for further all-year petroleum activity in the South Barents Sea, except for some areas. This implies that all existing licenses in the Barents Sea can now resume their activities. Preparations have been made for a common drilling campaign in the area from January through March 2005. Three exploration wells are included in the campaign, operated by Norsk Hydro and Statoil.

Although most companies active on the NCS have interests in licenses and seismic areas in the Barents Sea, activity and competition have been modest for some years. As new petroleum reserves are discovered, we expect competition for new licenses to increase. The development of the Snøhvit field, described below in Exploration and Development, could serve as a cornerstone for the area's future development. One new license was awarded as additional acreage to the existing Snøhvit acreage in the Barents Sea in 2004. The awarded acreage near Snøhvit includes a previous discovery named Tornerose. The International E&P business segment is now responsible for ensuring a coordinated effort throughout the Barents Sea region.

Portfolio Management

In 2004 we have continued to focus our strategy on long-term production. The most important transactions were the acquisition of 10 per cent share in the Snøhvit field from Norsk Hydro, which included a transfer of a 2 per cent share in Kristin to Norsk Hydro as part payment. The agreement for the transaction was signed in January 2004 and completed in December 2004.

We completed a swap transaction with Shell (Enterprise Oil Norge AS) on February 3, 2005 in which Statoil acquired a 1.18 per cent share in Snorre, a 6 per cent share in Norne, a 10 per cent share in acreage outside the Norne field but within the license and a 25 per cent share in the Alve license in exchange for a 6.45 per cent share in Kvitebjørn. We expect completion of the transaction during the second quarter of 2005.These transactions are intended to add long-term production and reserves to our portfolio.

In an effort to align the participating interests in our core areas, Statoil and Total agreed in June 2004 a swap transaction where Total received a 7.65 per cent share in Mikkel and a 3 per cent share in the Kristin field (Halten Area) in exchange for Statoil receiving, as part payment, a 10 per cent interest in the Tune field near Oseberg. The transaction was completed in November 2004.

Statoil bought a 48.13 per cent share of the new license PL037E from ExxonMobil, Shell and ConocoPhillips and sold a 9 per cent share of Skinfaks (PL152, 277 and 037E) to Norsk Hydro in order to obtain ownership alignment for Skinfaks with the Gullfaks field (where Skinfaks will be tied in). We expect the transaction to be completed in the first quarter 2005.

Our exploration portfolio has been optimized through several transactions and relinquishment of low priority acreage.

Exploration and Development

We have been engaged in exploration and drilling on the NCS since 1975 and have drilled a total of 292 exploration and appraisal wells as of December 31, 2004. Approximately 69 per cent of all exploration and appraisal wells that we drilled in the last three years have yielded discoveries or positive appraisals that have confirmed our assessments regarding hydrocarbons in place.

Our exploration and development program is designed to strengthen our position on the NCS through increasing reserves and leveraging of existing infrastructure and to enable the development of new core areas. We coordinate the development of new fields so as to minimize required new investments in infrastructure. In the Tampen area, new fields were developed on a schedule to allow existing infrastructure to be used continuously at near peak capacity, thereby limiting the need for new infrastructure.

In 2004, we participated in six exploration and appraisal wells. We were the operator for four of these wells. In addition one exploration extension on a production well was drilled. In 2003 we participated in nine exploration and appraisal wells, of which we were the operator of six. Of the four Statoil-operated wells in 2004, three were successful, and of the two partner-operated wells, one was successful. Our exploration expenditure on the NCS in 2004, including expenditure in respect of field development studies for the Halten/Nordland prospects, totaled NOK 1,093 million, of which NOK 376 million was capitalized. The corresponding figures for 2003 were NOK 1,215 million and NOK 106 million respectively. The reduction in exploration expenditure from 2003 was due to a lack of available rigs to drill our prospects and the strike affecting one rig designated to exploration activity. Additionally, exploration expenditure of NOK 61 million, which was capitalized in earlier years, was expensed in 2004 compared to NOK 256 million in 2003.

Of our 2004 NCS exploration expenditures, approximately 58 per cent was spent in our three core producing areas and the remainder mostly in our potential production areas in the North Sea and Norwegian Sea. Our expenditure on development on the NCS totaled NOK 15.4 billion in 2004 and NOK 13.3 billion in 2003. In 2004 we participated in 94 development wells, and in 2003 we participated in 99 development wells. Of our 2004 NCS development budget, approximately 75 per cent was spent in our three core producing areas and the remainder in our potential production areas in the Barents and Norwegian Seas. The allocation of our exploration and development budgets among the areas may be revised to reflect the results of our exploration activities.

Of our 2005 NCS development budget, approximately 78 per cent will be spent in our three core producing areas and the remainder in our new core area Tromsøflaket and potential producing areas in the Barents Sea and the Norwegian Sea.

The following table sets forth our exploratory and development wells drilled on the NCS, including a breakdown of successful or productive wells and dry wells, drilled by core area for the three years ended 2002, 2003 and 2004.

We are currently the operator of seven ongoing field development projects on the NCS, which are in order of scheduled production:Kristin, Visund Gas, Norne Satellites (Urd), Snøhvit, Skinfaks/Rimfaks IOR (Increased Oil Recovery), Volve and Statfjord Late Life. We also have interests in the Ormen Lange deepwater gas field, currently operated by Norsk Hydro with Norske Shell as operator in the production phase. In addition we have interests in ConocoPhillips' Ekofisk Area Growth (EAG) project and Norsk Hydro's Oseberg Vestflanken and Fram East.

Kristin. Kristin, in which we hold a 41.6 per cent interest, is a gas condensate field in the southwestern part of the Halten/Nordland area, about 20 km southwest of Åsgard's Smørbukk field. The Kristin development, approved by the Storting (the Norwegian Parliament) in 2001, will drain a reservoir almost 5,000 meters beneath the seabed through the use of 12 subsea production wells. The reservoir is characterized by very high temperature and pressure. The Kristin project will be the first high temperature and pressure field developed with subsea installations. To reduce the pressure, the well stream is choked down at the subsea production stations before transportation through infield pipelines and flexible risers to a floating processing platform. The stabilized condensate will be exported to a joint Åsgard and Kristin storage vessel and the rich gas will be transported to shore via the Åsgard transportation pipeline to the gas processing facility at Kårstø. Commercial gas deliveries are scheduled to start in October 2005. Taking into account the challenging nature of the reservoir it was necessary to implement a new drilling strategy during 2004 through drilling of horizontal wells in order to maintain the field's recovery factor. In addition, the investment estimate was increased in March 2005 to NOK 20.8 billion, including an extraordinary project reserve of NOK 0.5 billion. A total of NOK 14.7 billion has been invested as of December 31, 2004. In connection with the Kristin development, we have decided to develop Tofte, which is a discovery that we made in the same license as Kristin with a single well tied back to the Kristin platform. The estimated cost for this is NOK 655 million. The maximum production capacity on Kristin is expected to reach 18 mmcm (636 mmcf) of natural gas per day and 126 mbbls condensate per day by 2006. A possible development of the other discoveries in the area using the Kristin processing facilities as a field center is under evaluation.

Visund Gas. The Visund field, in which we hold a 32.9 per cent interest, is in the Tampen area. The development of the Visund field was separated into an oil production phase, which came on stream in 1999, and a later gas production phase, Visund Gas, which was approved by the Ministry of Petroleum and Energy (OED) in October 2002. Gas export will be made possible by modifying the platform with new gas-compressor and export facilities to allow gas export and at the same time keeping the initial gas injection rate. In addition, a new pipeline will be laid from Visund to the Kvitebjørn pipeline in order to transport the gas to the treatment plant at Kollsnes for final processing. Commercial gas deliveries are scheduled to start in October 2005, and a gas production level of about 6 mmcm (208 mmcf) gas per day is forecasted for 2006. The gas export capacity can be increased when gas injection is reduced and more gas compression capacity becomes available, which is currently expected to occur in 2011. Total development costs are estimated to be NOK 1.9 billion, of which NOK 1.1 billion has been invested as of December 31, 2004.

Urd (Norne Satellites). The Urd development, in which Statoil holds an interest of 40.45 per cent, was approved by the OED in July 2004. The two reservoirs, Svale and Stær, are located approximately 10 km and 5 km north of the Norne field, respectively, and will be produced through subsea facilities with well stream tied back to the Norne FPSO. Production is scheduled to commence in October 2005. The total development cost is estimated to be NOK 3.5 billion, of which NOK 1.2 billion has been invested as of December 31, 2004.

Snøhvit. Snøhvit is the largest gas field in the Norwegian sector of the Barents Sea. After the acquisition of the 10 per cent interest from Norsk Hydro and 1.24 per cent interest from Svenska Petroleum, both with effect as of January 1, 2004, our interest in Snøhvit is 33.53 per cent. We are the operator of all the unitized licenses in the field. The unitization agreement for the area was approved by the OED in July 2000. The field is being developed with subsea production installations connected to an onshore gas liquefaction plant. The main product, LNG, will be shipped to customers in purpose-built vessels. CO₂ separated from the gas will be piped back to the field and reinjected. Some LPG and condensate will also be produced. Long-term sales contracts for the LNG were entered into in October 2001 and the Storting approved the plan for development and operation (PDO) in March 2002. The total development costs for the project are estimated to be NOK 51.3 billion for all phases, of which NOK 22.3 billion has been invested as of December 31, 2004. Statoil increased the estimated development cost by NOK 6 billion in 2004 after a detailed assessment of cost and progress. The updated estimate takes into consideration cost and schedule consequences of delays due to test failure of compressors, late delivery of drawings and materials and productivity below expectation. In addition, four new vessels will be purpose built for transportation of the LNG from the field. Statoil will lease capacity and be a part owner in three of the vessels. Our commitment as charterer will be equal to title to the gas to be transported, while our ownership share will, on average, be 32 per cent. The present value of the lease rentals for our share is about NOK 2.5 billion. Initial gas deliveries will start in October 2006. Due to progress behind schedule, as mentioned above, the estimated start of regular gas deliveries is the first quarter 2007. The PDO called for regular production to start in 2006. The production capacity is expected to reach about 17 mmcm (614 mmcf) of LNG per day by 2007. The field will be further developed with more wells and compression facilities from 2011 and onwards. All phases are included in the PDO/Plan for Installation and Operation (PIO) and investment estimates.

Volve. The oil field Volve, in which we hold an interest of 49.6 per cent, is located in the same license as the Sleipner field. The PDO was submitted to the authorities in February 2005 and approval by the OED is expected spring 2005. Volve will be developed through use of a leased drilling and production rig to be supplied and operated by Mærsk Contractors Norge and facilities for oil storage, offloading and transportation. Associated rich gas produced will be transported to the Sleipner A platform for further processing and exportation. Total investments are estimated to be NOK 2.0 billion. Subject to Government approval of the PDO, the planned date for production start-up is during the second quarter of 2007. Oil production from Volve is expected to reach a plateau production of 38 mbbls per day in 2008. Development responsibility for this asset has been transferred to the T&P unit.

Skinfaks/Rimfaks IOR. The Skinfaks/Rimfaks IOR development in which we hold an interest of 61per cent is located in the Tampen Area, approximately 20 km south west of the Gullfaks C platform. Skinfaks, which consists of a number of oil/condensate segments, and Rimfaks IOR, which is an enhanced recovery opportunity of the Rimfaks field that came on stream in year 2000, are developed through the use of subsea facilities connected to the Gullfaks C platform for processing and offloading. The PDO was submitted to the authorities in December, 2004, and is expected to be approved by the OED in the first half of 2005. Production is scheduled to start in November 2006, with total development costs estimated to be NOK 3.4 billion. An insignificant amount had been invested as of December 31, 2004.

Statfjord Late Life (SFLL). The Statfjord field (Statoil interest 44.34 per cent), which has been in production since 1979, submitted a new PDO in February 2005 for a late life production period on Statfjord. The reservoir concept for the Statfjord Late Life project is to change the drainage strategy which implies a transition from the current reservoir pressure maintenance strategy to a significant reduction in reservoir pressure, resulting in gas being released from the remaining oil and converting Statfjord to a mainly gas producing field. The gas export to the UK through a new pipeline connected to the existing pipelines to Flags and St. Fergus is scheduled to start in October 2007. The lifetime of Statfjord is expected to increase by about 10 years with a production plateau expected to reach 11 mmcm (394 mmcf) of gas per day in 2008. The PL 037 licensees have been granted an extended concession until 2026 provided that the SFLL project is approved. Total investments for the project are estimated to be NOK 14.5 billion, which implies incremental investments of about NOK 10.6 billion compared with a scenario with no late life development. In addition the estimated pipeline investment is NOK 1.4 billion. As of December 31, 2004, the license partners have invested a total of NOK 0.35 billion in the project.

Partner operated projects

We are also a partner with a 15.3 per cent interest in the Oseberg Vestflanken development project, operated by Norsk Hydro. The PDO for Oseberg Vestflanken was approved by the OED in December 2003. The project is a subsea oil and gas development with tieback to the Oseberg Field Center. The expected start of production is September 2005 and the oil/condensate production capacity is expected to reach 30 mbbls per day. The investment cost is estimated to be NOK 2.2 billion. In addition, Statoil has a 0.95 per cent share in the ConocoPhillips operated Ekofisk, where the OED in June 2003 approved a PDO for the EAG project. Total investments, which include a new wellhead and processing platform, and large scale modifications on several of the existing platforms, are estimated to be NOK 8.2 billion and the expected start up is in October 2005. The project will increase the production on Ekofisk by up to 70 mbbls of oil per day. In February 2005, Norsk Hydro submitted a PDO for a Fram East development to the OED. The Fram East field, in which Statoil holds an interest of 20 per cent, will be developed through use of subsea facilities connected existing infrastructure at Troll C. Total investment is estimated to be NOK 4 billion. Expected start up of production is October 2006 and production is expected to reach 37 mbbls per day in 2007.

Ormen Lange, which is a deepwater gas field in the Halten/Nordland area and the second largest gas field on the NCS, had the PDO approved by the Norwegian government in April 2004. Statoil holds an interest of 10.8441 per cent with Norsk Hydro acting as the operator for the development phase. Norske Shell will act as operator in the production phase. Ormen Lange extends across three production licenses. The selected development concept is an extensive seabed development at depths ranging from 800 to 1,000 meters. The well stream will be transported to an onshore processing and export plant on Nyhamna. Sales gas will then be transported through a dry gas pipeline, named Langeled, which is currently under construction, via Sleipner to Easington in the UK. Total investments are estimated to be NOK 52.7 billion (excluding Langeled), of which NOK 4.1 billion had been invested by the project partners as of December 31, 2004. Current plans expect production to start in October 2007 with a daily plateau production estimated at 70 mmcm of gas per day, while condensate production is expected to plateau at approximately 32 mbbls per day. All major contracts have been awarded during 2004.

Major modification projects

In addition to the field development projects described above, a major modification at Troll A is ongoing where pre-compression facilities are being installed with planned start-up in October 2005. The cost estimate is approximately NOK 3.6 billion, of which NOK 3.2 billion has been invested as of December 31, 2004.

Other development projects

Åsgard Q-project is a new satellite tieback to the Åsgard A platform based on a revised IOR strategy for the Smørbukk South field in Åsgard Unit. The estimated investment cost for the project is NOK 1.8 billion. The expected start of production has been postponed from January 2005 to June 2005 due to a strike among the rig companies on the NCS during autumn 2004 and necessary replacement of damaged umbilical and service lines.

A long reach well is going to be drilled from the Gullfaks A-platform to develop the Gulltopp field, which is located in the Gullfaks license 8 km west of Gullfaks A. Gulltopp was discovered in 2002 and is a small oil field. It is expected that oil production will commence in September 2005.

Oil and Gas Reserves

As of the end of 2004, we had a total of 1,089 mmbbls of proved oil reserves and 368 bcm (13.0 tcf) of proved natural gas reserves in Norway. Based on boe, our proved reserves consist of 32 per cent oil and 68 per cent natural gas, based on total proved reserves in Norway of 3,401 mmboe.

The following table sets forth our Norwegian crude oil and natural gas proved reserves as of the end of the periods indicated. The data are stated net of royalties in kind, but including reserves attributable to our account based on our proportionate participation in fields with multiple participants. Royalty obligations from Statfjord were abolished effective January 1, 2003, and royalty obligations from Gullfaks and Oseberg will be abolished by 2006. Further details are given below under -Regulation-Taxation of Statoil-Royalty. No major discovery or other favorable or adverse event has occurred since December 31, 2004 that would cause a significant change in the estimated proved reserves as of that date. Further information on reserves can be found in the Financial Statements-Supplementary Information on Oil and Gas Producing Activities.

Production

In Norway in 2004, our total equity oil production was 229 mmbbls, after deductions for royalty oil in kind, and gas production for our own account was 21.3 bcm (751 bcf), which represents an aggregate 363 mmboe (991 mboe per day). Currently, our production is in our three core producing areas of Troll/Sleipner, Halten/Nordland and Tampen. We participate in the majority of the 47 producing fields in the NCS. As of December 31, 2004, we were the operator for 22 of them. Kvitebjørn, in which we hold a 50 per cent interest, came on stream as planned at the end of September this year. A new satellite field, Sleipner West Alfa North, started production October 11, 2004, while the Sleipner West Compression project was finalized in December 2004. We are responsible, as operator, for approximately 48 per cent of Norway's current oil output and approximately 81 per cent of current gas output.

The following table shows the NCS production fields and field areas in which we currently participate. Amounts are stated net of royalties in kind. Field areas are groups of fields operated as a single entity.

(1)Equity interest as at December 31, 2004.

(2)The PL 037 licensees have been granted an extended concession from 2009 to 2026 provided that the SFLL project is approved.

The following table sets forth our average daily equity production for oil, including NGL and condensates, and natural gas for the years ended December 31, 2002, 2003 and 2004.

Troll/Sleipner

The Troll, Sleipner and Oseberg fields are the main oil and gas fields within this area. Statoil's share of the area's production in 2004 was 203 mbbls of oil and 38 mmcm (1,341 mmcf) of gas per day, or 442 mboe in total per day. In September 2004 the Kvitebjørn platform started production.

Troll. Troll lies in the North Sea and has large gas and oil reserves. Troll is the primary source of supply for gas sales from the NCS to Europe. Our interest in Troll is 20.80 per cent. The Troll field comprises two main structures: Troll East and Troll West. An oil layer underlies the whole Troll area but is substantial enough for commercial recovery in the Troll West region only. A staged development has therefore 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 Norsk Hydro is the operator of the Troll Phase 2 oil production in Troll West.

The Troll East development comprises the Troll A platform, the gas processing plant at Kollsnes, and the 60 km pipelines linking the Troll A platform with the onshore processing plant at Kollsnes. As of the beginning of 2005, the Troll A gas production capacity is expected to be approximately 120 mmcm (4.2 bcf).

Troll was one of the first major installations to transfer multiphase product streams (rich gas and condensate) from offshore to an onshore facility for processing. The Troll A gas is processed at Kollsnes, where the gas is dried and compressed for pipeline export to continental Europe. The rich gas is transported to the Mongstad refinery.

Norsk Hydro is the operator for the oil production of Troll Phase 2 in Troll West. The Troll West development comprises the Troll B and Troll C floating production platforms. Crude oil is produced from the oil province with horizontal wells tied back to the two platforms. The oil produced from Troll B and Troll C is transported through Troll Oil Pipeline I and Troll Oil Pipeline II to the oil terminal at Mongstad. The associated gas from Troll B and Troll C is exported via Troll A to Kollsnes.

In connection with the decision to land the rich gas from the Kvitebjørn field at the Troll facilities at Kollsnes, the Troll owners decided to build a new NGL fractionation plant at Kollsnes. This plant came on stream as planned at the end of September 2004. Processing capacity for the plant is 26 mmcm (918 mmcf) of gas per day.

Kvitebjørn. Kvitebjørn, in which we hold a 50 per cent interest, came on stream at the end of September 2004. The field has been developed with a fixed steel platform for production, drilling and living quarters. There are plans for drilling 11 production wells and the drilling period will continue until the middle of 2006. Initial processed gas and condensate are transported in separate pipelines to receiving facilities for final processing and transport. Gas is transported through a pipeline to the NGL fractionation plant at Kollsnes. In addition, a new oil pipeline is connecting Kvitebjørn, to the Mongstad refinery in the same region. Total investment is estimated to be NOK 10.1 billion, which is in line with the PDO.

Sleipner. Sleipner includes Sleipner West, Sleipner East and Gungne and our interests are 49.50 per cent, 49.60 per cent and 52.60 per cent, respectively. We are the operator of all fields. Condensate from the Sleipner fields is transported to the gas processing plant at Kårstø. Sleipner East and Gungne are produced through the Sleipner A platform. Sleipner West is produced through two installations: the Sleipner B wellhead platform and the Sleipner T gas treatment facility. Unprocessed well streams from Sleipner B are piped 12 km to Sleipner T, which is linked by a bridge to Sleipner A. Sleipner West has large reserves of CO₂-rich gas. We extract the CO₂ at the field and re-inject it into a sand layer that lies underneath the seabed, thereby reducing the CO₂ emissions into the air, which has environmental benefits and, insofar as it reduces environmental taxes, financial benefits. A new satellite field, Sleipner West Alfa North, came on stream in October 2004 and the Sleipner West Compression project was finalized in December 2004.

Oseberg. Oseberg, the third main field in the Troll/Sleipner area, is operated by Norsk Hydro. We have a 15.30 per cent interest in all Oseberg licenses.

Glitne. Glitne is the smallest field development on the NCS using a stand-alone floating production system. Our interest in this field is 58.9 per cent.

Huldra. Our interest in Huldra, a high temperature and high-pressure gas and condensate field, as of January 1, 2004, is 19.88 per cent. The development concept for the field includes an unmanned platform in 125 meters of water, tied back to processing facilities for condensate and gas at Veslefrikk and Heimdal, respectively.

Veslefrikk. Our interest in Veslefrikk is 18 per cent. Oil is exported to the Sture terminal via the OTS oil transportation system while gas is exported to Kårstø. Since November 2001, Veslefrikk has been processing condensate from the Huldra field for further export through the OTS oil transportation system. Veslefrikk is preparing for the tail production phase and we are at present implementing several actions to obtain significant reductions in yearly costs and to enhance the oil production. The target for the actions is to sustain economic production until 2010-2014.

Sigyn. Sigyn, operated by ExxonMobil, is a gas/condensate field located 12 km southeast of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered at Kårstø. Our interest is 50 per cent. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform.

Fram West. Our interest in the Fram oil field, operated by Norsk Hydro, is 20 per cent. The Fram field development is a subsea tie-in to existing infrastructure (Troll C) for processing and transport.

Halten/Nordland

Our producing fields in the Halten/Nordland area are Åsgard, Heidrun, Norne and Mikkel, all of which we operate. Statoil's share of the area's production in 2004 was 110 mbbls per day of oil and 10 mmcm per day (368 mmcf per day) of gas, or 175 mboe per day in total.

This region is characterized by petroleum reserves located at water depths reaching between 250 and 500 meters. The reserves are to some extent under high pressure and at high temperatures. These conditions may make development and production more difficult and have challenged the participants to develop new kinds of platforms and new technology, such as floating processing systems with subsea production templates. We plan to increase efficiency by further coordinating our operations in the area and by stemming the declining production from the mature fields by increasing seismic activity and well maintenance. In addition, we will expand our activities by utilizing our installed production and transportation capacity before building new infrastructure.

Åsgard.The Åsgard field contains the three reservoirs: Smørbukk, Smørbukk South and Midgard. Our interest in the Åsgard development is 25 per cent. The field was developed with the Åsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the Åsgard C storage vessel. The subsea production installations on the field are the most extensive in the world, with a total of 52 wells grouped in 17 seabed templates. Further, the Åsgard B platform is the largest floating gas processing center, and Åsgard A is one of the largest floating production ships ever built.

The Åsgard development links the Haltenbank area to Norway's gas transport system in the North Sea. Gas from the field is piped through the Åsgard Transport pipeline to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the Åsgard A vessel and condensate from the Åsgard C storage vessel is shipped from the field by shuttle tanker. Åsgard B has had stable production during 2004, including production from the Mikkel satellite field, which is tied-in to the Åsgard B sub-sea installation at Midgard.

Heidrun. The Heidrun platform is the largest concrete tension leg platform ever built. Our interest in this field is 12.41 per cent. The field is producing from 21 platform and 7 sub-sea wells. Water injection is also done from both platform and sub-sea wells. Most of the oil from Heidrun is shipped by shuttle tankers to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden, Norway. Additional gas volumes are exported through the Åsgard Transport pipeline. Produced water and sulphate reduced water is injected to maintain pressure in the scale prone lower reservoirs.

Norne. The Norne field lies about 80 km north of the Heidrun field and roughly 200 km from the Norwegian coast. Our interest in this field is 25 per cent. The field has been developed with a production and storage ship tied to subsea templates. Flexible risers carry the reservoir's output to the vessel, which swivels around a cylindrical turret moored to the seabed. This ship carries processing facilities on its deck and storage tanks for oil. Processed crude oil can be transferred over the stern to shuttle tankers. Like Heidrun, Norne is connected to gas markets in continental Europe through a link with the Åsgard Transport system. The Norne production vessel (FPSO) underwent minor modifications in 2004 to cater for tie-in of the Urd field.

Mikkel. This gas and condensate field lies about 40 km away from both Åsgard's Midgard deposit and Draugen. Our interest in this field is 33.97 per cent. Production commenced in October 2003. Production from two seabed templates is tied to the sub-sea installation at Midgard for onward transport to the Åsgard B gas-processing platform.

Tampen

The Tampen area offers rich petroleum resources in a compact geographic area where Statoil is the sole operator of all the Tampen fields. The main producing fields in the Tampen area are Statfjord, Gullfaks and Snorre. Statoil's share of the area's production in 2004 was 313 mbbls of oil and 10 mmcm (342 mmcf) of gas, or 374 mboe per day. Tampen is the leading oil producing area on the NCS, and even after twenty years of production we believe substantial opportunities for increased value creation are still remaining.

Several of the production facilities will be closed down before 2010 unless changes are made to the way the facilities are operated. We have taken several initiatives to identify and implement measures to increase and prolong production from the Tampen area. These initiatives have resulted in a prolonged planned production from 2013 to 2017 for the Gullfaks field. At Statfjord a change of drainage strategy to commence "blowdown" - starting pressure depletion on the field by stopping water and gas injection in order to liberate gas from the remaining oil - is currently being developed by the Statfjord Late Life project. Given that the Statfjord Late Life strategy is sanctioned, the production will be extended from 2009 to 2018 for two out of three platforms. Statfjord A production will end in 2012. Snorre will continue to produce until 2028, six years longer than originally planned. The prolonged planned production for the Tampen area is due to a combination of cost reduction and IOR. There are also identified opportunities for synergy of operations, such as better utilization of drilling completion units, common contracts and common logistics and transportation services. Taking over as operator from Norsk Hydro in January 2003 for Snorre, Visund and PL089 was an important step in an area optimization of the production operations in the area. We are also looking at introducing new drainage strategies for producing field and area solutions starting with the Statfjord Late Life project and continuing with increased IOR efforts on Snorre and Gullfaks.

Statfjord. Our interest in the Statfjord Unit is 44.34 per cent. Statfjord has been developed with three fully integrated platforms supported by gravity base structures featuring concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Three satellite fields (Statfjord North, Statfjord East and Sygna) have been developed and are each tied back to the Statfjord C platform. In November 2004 the Norwegian Oil and Energy Department granted a license extension for the Statfjord area from 2009 to 2026 conditional upon the realization of the Statfjord Late Life project.

Gullfaks. Gullfaks has been developed with three large concrete production platforms. Our interest in the field is 61 per cent. Oil is loaded directly into shuttle tankers on the field, while associated gas is piped to our Kårstø gas processing plant and then on to continental Europe. Three satellite fields, Gullfaks South, Rimfaks and Gullveig, have been developed with subsea wells remotely controlled from the Gullfaks A and C platforms.

Snorre. The field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A). Oil and gas is exported to Statfjord for final processing, storage and loading. Our interest in the field is 14.4 per cent. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A. Production from the new development, Vigdis Extension, connected to Snorre A, started in October 2003. Production on Snorre A and Vigdis has been closed down since November 28, 2004, due to an incident on Snorre A. Estimated delayed production in 2004 was 45 mboe per day (Statoil share). Production restarted mid to late January, 2005. The total deferred volume in 2004 for both fields during the shutdown period was 1.4 mmboe.

Visund. The field has been developed with one platform and two subsea satellite wells. The oil is exported to Gullfaks A for storage and loading. The gas produced is now injected in the reservoir. Our interest in Visund is 32.9 per cent. Gas export will be made possible by increasing the compressor capacity and by installing gas metering equipment and an exporting pipeline. The gas will be exported to Kollsnes via the Kvitebjørn pipeline. Gas export is planned to start in October 2005. The project is further described in 'Exploration and Development' above.

PL089. The asset includes the Vigdis field and the fields in the Tordis Area, Tordis, Tordis East, Tordis Southeast and Borg. The Vigdis field is developed with three subsea templates with well stream through pipelines connected to Snorre A where the oil is stabilized and exported to Gullfaks for storage and loading. The Tordis area is developed with seven subsea satellites and two templates tied back to Gullfaks C where the oil and gas is processed and stored for offshore loading and export. Our interest in the PL089 asset is 28.22 per cent. The Vigdis extension started production in October 2003 and is based on a cluster of small oil discoveries located in the central part of the Tampen area, 7 km southwest of the Snorre A platform. The water depth in the area is 220-300 meters. The Vigdis extension is developed by subsea stations and satellites tied into the Snorre A via existing subsea production facilities at the Vigdis field. The oil is exported to Gullfaks A for storage and loading.

Decommissioning

The Norwegian government has set forth strict procedures for the removal and disposal of offshore oil and gas installations under the Convention for the Protection of the Marine Environment of the Northeast Atlantic, or the OSPAR Convention. There has been no decommissioning of fields in which Statoil holds an interest during the last 3 years.

Domestic Production Costs Data

Production costs are influenced by the distribution between new and mature fields in the portfolio and the cost effectiveness of the different installations. We calculate this indicator as annual production-related costs compared with the volume of oil and gas produced in the same period. As the figures below show, we continue to reduce cost per barrel in NOK and, based on industry benchmarks, we believe that we are one of the lowest cost producers on the NCS.

The following table sets forth our average production costs per boe consistent with FASB statement 69, our average sales price per barrel of oil, and average sales price by Statoil per scm of gas sold for the years ended December 31, 2002, 2003 and 2004.

Oil and Gas Transportation

Most of our oil production is lifted offshore by shuttle tankers and transported to oil terminals in Norway and abroad. Troll and Oseberg crude oil is transported by pipeline to the Mongstad and Sture terminals, respectively, and Ekofisk production is transferred by pipeline to Teesside, UK. We transport gas through the gas pipeline system established on the NCS.

We, together with other Norwegian oil and gas producers, have built an extensive transportation infrastructure network to transport crude oil and gas produced on the Norwegian Continental Shelf to terminals in Norway, the UK and the continental Europe. For information about our interests in gas pipelines held through Gassled, see Natural Gas-Norwegian Gas Transportation System and other Facilities below.

The following are oil pipelines in which E&P Norway has an ownership interest:

Troll Oil Pipelines I & II. The Troll Oil Pipeline I transports oil from the Troll B platform to the terminal at Mongstad near Bergen. The Troll Oil Pipeline II carries oil from Troll C to the terminal at Mongstad. The Troll Oil Pipelines I & II have a transport capacity of 265 and 300 mbbls per day, respectively. We are the operator and 20.85 per cent owner of Troll Oil Pipelines I & II.

Kvitebjørn oil pipeline.The Kvitebjørn oil pipeline is a separate joint venture which runs from the Kvitebjørn platform to the Troll Oil Pipeline II. The pipeline, in which we hold a 50 per cent interest, has identical participation interests and voting rules as the Kvitebjørn field. Statoil is the operator of the pipeline, which has a capacity of 10 mcm per day. The pipeline has been designed at both ends to accept future connections.

Norpipe Oil AS. We own 20 per cent of the ConocoPhillips operated Norpipe oil pipeline, which starts at Ekofisk Center and crosses the UK continental shelf to come ashore at Teesside in the UK. The Norpipe oil pipeline has a transport capacity of 900 mbbls per day. By October 2005 Statoil's ownership will be reduced to 15 per cent, when 5 per cent is handed over to the SDFI.

Oseberg Transportation System. The Oseberg Transportation System transports oil from Veslefrikk, Brage, Oseberg Unit, Oseberg South, Oseberg East, Tune and Huldra via Oseberg A to Sture. The Grane field has a separate pipeline to the onshore facilities. Our interest in the Oseberg Transportation System is 14 per cent. The Oseberg Transportation System has a capacity of 765 mbbls per day.

Frostpipe. Frostpipe, operated by Total, had been used to transport oil and condensate from Frigg to Oseberg where it links to the Oseberg Transport System. Frostpipe, in which we hold a 20 per cent interest, has not been in use since March 2001.

International Exploration and Production

Introduction

International E&P consists of exploration, development and production operations outside of Norway. We are focusing our efforts on establishing significant production and increasing our influence in our main producing areas. We are also actively pursuing additional opportunities in other areas to expand our international portfolio, which support our strategy and leverage our skills and competence from the NCS. We hold interests in 15 producing fields in the Caspian (Azerbaijan), North Africa (Algeria), Venezuela, Western Africa (Angola), Western Europe (UK) and China. In addition, we are the operator of a development project in Iran and exploration projects in Venezuela, Algeria, Brazil, and the Faroes. We are joint operators in the In Salah and In Amenas projects in Algeria. In addition to exploration licenses that we hold in the areas mentioned above, we also have exploration licenses in Ireland and Nigeria.

As part of a reorganization effective January 1, 2004, all midstream and downstream gas projects associated with our international activities were transferred from International E&P to the Natural Gas division. This includes midstream and commercial activities in Shah Deniz, Azerbaijan, downstream activities in Turkey, and our position in Cove Point in the U.S. The International E&P business segment is now responsible for coordinating further development efforts across all our activities in the Barents region.

International E&P reported income before financial items, income taxes and minority interest of NOK 4,188 million in 2004 compared to NOK 1,781 million in 2003. In the year ended December 31, 2004, we produced 115 mboe per day compared with 89 mboe per day in 2003.

The following table presents key financial information about this business segment. The changes from 2003 to 2004 are primarily a result of higher realized oil and gas prices and increased production.

(1)The amount in 2001 includes reclassification of the geological and geophysical costs from business development activities of NOK 218 million.

(2)The amount in 2004 includes the expenditures related to our acquisition of In Salah and In Amenas. The increase in capital expenditure from 2003 to 2004 is primarily attributable to this acquisition.

Further details on the financial results can be found in Item 5-Operating and Financial Review and Prospects-Operating Results.

We believe that the group's technology and expertise developed on the NCS, especially in such areas as improved oil recovery techniques, subsea solutions and conversion of GTL, will allow us to continue to secure attractive international investment projects.

Portfolio Management

Through asset swaps, sales and acquisitions, we have been restructuring our international interests in order to focus on areas where we own quality assets, develop new attractive commercial opportunities, and optimize our capital employed.

In June 2003 Statoil agreed to acquire direct ownership interests in two Algerian assets, In Salah (31.85 per cent) and In Amenas (50 per cent). Both transactions were approved by the Algerian Council of Ministers during 2004.

Reserves

In 2004, we increased our proved reserves by 26 per cent. The change principally reflects booking of new reserves in Algeria related to the In Salah and In Amenas fields, as well as an increase in Shah Deniz in Azerbaijan. Additions to proved reserves in 2004 were partially offset by the effects on proved reserves under Production Sharing Agreement (PSA) contracts in some of our international fields, where applying year-end prices had the effect of decreasing proved reserves. Under PSA contracts, the volumes of entitlement oil are reduced when oil prices increase, which in turn reduces the booking of reserves. At the end of 2004, our international proved oil and NGL reserves were 632 mmbbls of oil, and we had 40.7 bcm (1.4 tcf) of proved natural gas reserves, a total of 888 mmboe.

The following table sets forth our total international proved reserves as at December 31 of each of the last three years. Further information on reserves can be found in the Supplementary Information on Oil and Gas Producing Activities contained in our consolidated financial statements beginning on page F-1.

Production

Our petroleum production outside Norway amounted to an average of 115 mboe per day in 2004. Total annual production in 2004 was approximately 42 mmboe compared to 33 mmboe in 2003. The following table sets forth our total international production for each of the last three years. In October 2004, the Sincor upgrader was shut down for 48 days in order to conduct a planned Debottlenecking and Plant Turn Around project. The tri-annual shutdown was completed successfully within the planned period. New fields that came on stream in 2004 are In Salah in Algeria, Kizomba A in Angola and the Alba Extreme South Phase 2 project in the UK.

The following table shows the producing fields in which we currently participate and the producing wells as at, and production for the year ended, December 31, 2004.

(1)  Production figures are after deductions for royalties, production sharing and profit sharing.

(2)  Including production from the extreme south area of the Alba field, which started in October 2004.

(3)  Production from Kizomba A commenced in August 2004.

(4)  Initial production commenced in January 2001 and commercial production started in March 2002. The 2004 production has been reduced due to a planned 48 day shutdown of the Sincor upgrader in order to conduct a Debottlenecking and Plant Turn Around project.

(5)  Production from In Salah commenced in July 2004.

(6)  Production from Lufeng was suspended in June 2004 in order to carry out a sidetrack drilling project and is expected to restart in the second quarter of 2005.

Main Activity Areas

We are currently active in the following producing areas:Caspian (Azerbaijan), North Africa (Algeria), Venezuela, Western Africa (comprising Angola, which is already producing, and Nigeria, which is not a producing area yet) and Western Europe. Our international portfolio, with the exception of some fields in Western Europe, the Lufeng field in China and LL652 in Venezuela, consists primarily of new and developing areas that have either not yet commenced production or are in early stages. Accordingly, we describe all of our operations by area as opposed to stage of development.

Caspian

We established a presence as one of the first international oil companies in the Caspian Sea in 1992. Since then, we have entered into three PSAs in Azerbaijan, and we are among the largest foreign oil companies in the country in terms of proved reserves and production. At present, we hold interests in three PSAs offshore in the Azeri sector of the Caspian Sea: the Azeri-Chirag-Gunashli, or ACG, oil field, the Shah Deniz gas and condensate field and the Alov, Araz and Sharg prospects. We are the commercial operator of the South Caucasus Pipeline, managed by the Natural Gas division as of January 1, 2004, as well as being a partner in the Baku-Tbilisi-Ceyhan (BTC) Pipeline. We are also operator of the Azerbaijan Gas Supply Company managed by the Natural Gas division and are heading the Gas Commercial Committee.

The Caspian region has long been viewed as an area with substantial risks for increased economic, social and political instability. Although the general situation has improved in 2004, in both Azerbaijan and Georgia there are still political disputes that remain unsolved, and the existing risks cannot be underestimated.

Ongoing negotiations over the Caspian. A binding legal regime governing the division of the Caspian Sea among the five border states of Azerbaijan, Iran, Kazakhstan, Turkmenistan and Russia is yet to be found. This has on occasion led to disputes over rights to hydrocarbon resources between Azerbaijan and Iran and between Turkmenistan and Azerbaijan. There are currently bilateral agreements in place between Russia and Azerbaijan, between Russia and Kazakhstan and between Kazakhstan and Azerbaijan. Turkmenistan and Iran have to date been unwilling to enter into similar agreements.

Technical studies of the Alov field, which is located in a disputed area, are continuing in accordance with obligations under the relevant production sharing agreements.

Export of hydrocarbons. The Caspian Sea is landlocked without direct access to open sea. The export of oil is therefore dependent on onshore pipelines. Currently, crude oil from ACG is transported through a pipeline from Azerbaijan through Georgia to the Black Sea Port at Supsa, with an alternative route to Novorossiysk in Russia. The export capacity of the current infrastructure will be insufficient as the production volumes increase from the next stages of development on ACG and other fields. To secure transportation capacity, we are participating in the BTC Pipeline with an 8.71 per cent share. Development of the 1,760 kilometer BTC Pipeline will ensure export flexibility through multiple pipelines, and thereby diversify risk involved in commercializing the land-locked upstream resources. The BTC Pipeline was sanctioned in 2002. The majority of the pipe laying and pump station construction work is to be completed by the end of the second quarter of 2005. The line fill of 10.5 mmbbls is planned to commence during the second quarter of 2005. The pipeline is estimated to cost USD 4 billion including line fill and loan interest during construction, with about 30 per cent of this total covered by equity contributions from the BTC sponsors and the remainder by third-party debt funding and debt funding from sponsors. In February 2004, the consortium of partners sponsoring the BTC project, together with the governments of Azerbaijan, Georgia and Turkey, signed agreements covering third-party financing for the pipeline totaling USD 2.6 billion.

Azeri-Chirag-Gunashli. Statoil is a partner with an 8.56 per cent share in the BP operated ACG PSA. ACG is currently in the early oil production phase from the Chirag field. The current Chirag platform facilities include a Soviet-era built jacket, replaced topsides and a 24-inch oil pipeline to a newly built oil terminal at Sangachal. Oil is currently transported through a dedicated 850-kilometer pipeline, the Western Route, from the Sangachal processing and storage facility to Supsa for tanker shipment through the Bosphorous Straits and the Mediterranean to the international markets. Current focus is to increase productivity through prudent reservoir management and optimal well placement. In 2004, the annual average production exceeded 130 mbbls per day. The ACG field will be further developed in three phases.

The partnership sanctioned ACG Phase I in August 2001. The development plan comprises a new production, drilling and quarter platform in the Central Azeri part of the ACG field with a design capacity of 420 mbbls per day, a bridge-linked gas compression and water injection platform, as well as additional pipelines for oil and gas to Sangachal and oil terminal expansion. The production platform was installed offshore and topsides infrastructure commissioned during 2004. Production from Central Azeri commenced on February 12, 2005 during the first quarter of 2005 and the injection/compression platform to be operational by the end of 2005.

ACG Phase II development was sanctioned in September 2002. Construction activities continued during 2004 and we expect that the development will be completed by 2006, including a new 30-inch oil pipeline to shore and a production capacity of up to an additional 450 mbbls of oil per day. This development will focus on the West Azeri and East Azeri reservoirs, including development drilling and processing capacity upgrades with a total investment estimate of USD 5 billion. The ACG Phase I and ACG Phase II projects are now managed jointly as the Azeri Development Project.

ACG Phase III, sanctioned by the partners and the Government of Azerbaijan in September 2004, will develop the deepwater Gunashli field and complete the ACG full field development. After completion, we expect overall daily production from the ACG field to exceed 1 mmbbls per day from seven platforms by 2010.

We estimate overall investments for the ACG full field development to be approximately USD 15 billion, of which over USD 7 billion had been spent by December 31, 2004. This estimate covers all three phases of upstream development and early oil production, but excludes the BTC Pipeline.

Shah Deniz. The Shah Deniz area covers 860 square kilometers and lies in a water depth between 50 and 500 meters. We have completed a four-year exploration phase involving a three-dimensional seismic survey and the drilling of three wells. Gas and condensate were encountered in the first exploration well drilled in 1999. The partnership submitted a Notification of Discovery and its Commerciality in March 2001 and entered into a 30-year development and production period. We are the commercial operator of the development, responsible for gas sales, contract administration and business development for the South Caucasus Pipeline, and hold a 25.5 per cent interest in Shah Deniz. BP is the field operator. The field will be developed in stages.

The Stage 1 development on the east flank of the reservoir and a 680 km 42" pipeline, from the landing terminal through Azerbaijan and Georgia to the Turkish border (the South Caucasus Pipeline - SCP), was sanctioned by the partnership in February 2003, and Statoil was appointed as commercial operator of the pipeline. The Natural Gas business segment is responsible for the midstream and commercial activities related to this project. For further details on the SCP pipeline and marketing activities for Shah Deniz gas, see Natural Gas-Gas Sales and Marketing below.

During 2003 and 2004, a three well pre-drill program was successfully completed. Construction works for the Shah Deniz Stage 1 project are progressing according to schedule to meet the target of delivering gas to the market before winter 2006. The plateau production level of Stage 1 is expected to be approximately 8.5 bcm (300 bcf) per year and will be reached after two to three years of production. The SCP system will be prepared for expanded capacity to facilitate future development stages. The sanction cost for Shah Deniz Stage 1 was USD 2.3 billion. The projects have been under upward cost pressure, partly due to oil-field price inflation and currency exchange rate movements, as well as the fact that the detailed design concept was not fully reflected in the original sanctioned cost of the development. The partnership is currently reviewing the cost estimate.

Alov, Araz and Sharg. We signed an exploration, development and production sharing agreement, with BP as operator, covering the structures Alov, Araz and Sharg in July 1998. We have a 15 per cent interest in this PSA, which is located roughly 150 km southeast of the Azeri capital of Baku. The contract area covers about 1,400 square kilometers and is located at water depths of 450 to 800 meters. The structures are located in the area of the Caspian Sea that is disputed between Azerbaijan and Iran, and Iran has claimed parts of the area to be in Iranian waters since the contract was signed. Work has ceased following an Iranian naval intervention in 2001. The first well out of three in the area is planned to be drilled within 12 to 18 months after settlement of the border issue. Negotiations with SOCAR have granted an extension of the exploration period until six months after the completion of the third well.

North Africa

Statoil's current asset portfolio in North Africa comprises three projects in Algeria: In Salah, In Amenas and Hassi Mouina.

Algeria. Statoil's position as a significant gas seller in Europe, our ambition to serve this market from multiple sources, and the short distance to the southern European gas market makes Algeria an attractive country to pursue new opportunities. The decision to enter into Algeria is, by nature, based on a long-term perspective and includes an assessment of both the security and political situation. Statoil recognizes the need for a different level of protection for personnel and property compared with many European countries. To reduce the risk of injury and serious incidents, it is considered necessary to make additional security arrangements in line with those of other international companies. Statoil evaluates the risk level as acceptable, subject to the precautions that have been taken, and we remain committed to conducting our business in accordance with our core values.

In Salah. In June 2003, Statoil and BP signed an agreement whereby Statoil acquired a 31.85 per cent interest in the In Salah gas project - Algeria's third largest gas project. A Contract of Association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. A joint marketing company sells the gas produced in the project, and all gas produced until 2017 has been sold under long-term contracts. Production started in July 2004, with Statoil's entitlement plateau production estimated to reach approximately 44 mboe per day assuming 2004 year-end prices. Statoil's investment in the project, excluding the acquisition price, is approximately USD 277 million up until the end of 2004.

In Amenas. The In Amenas development project is the fourth largest gas development in Algeria containing significant liquid volumes. Statoil acquired a 50 per cent interest in the In Amenas project pursuant to the same agreement with BP in June 2003 regarding In Salah. This project is also built and operated through a joint operatorship between Sonatrach, BP and Statoil. The rights and obligations are governed by a production-sharing contract, giving the contractors access to liquid volumes only. Production is expected to begin in late 2005 to early 2006, with Statoil's entitlement plateau production estimated to reach approximately 28 mboe per day assuming 2004 year-end prices. Statoil's investment in the project, excluding the acquisition price, is approximately USD 427 million up until the end of 2004.

Final approval (gazettal) from the Algerian Ministry of Energy and Mining, the Algerian petroleum industry regulator, and the Council of Ministers, was published for both fields during 2004. This gazettal was the final condition for considering Statoil as an adequate partner in both licenses.

Hassi Mouina. On July 28, 2004 Statoil was awarded operatorship for the Hassi Mouina exploration acreage. The contract was officially signed on September 26, 2004. Statoil has a 75 per cent share in the block (Sonatrach 25 per cent), which is approximately 22,990 square kilometers. The work program is two wells (one exploration and one appraisal) and 400 kilometers of two-dimensional seismic during a 3-year exploration period. In January 2005, the Algerian Council of Ministers approved the Hassi Mouina license, and the final approval (gazettal) was issued in February 2005.

Venezuela

Venezuela has the largest oil reserves in the western hemisphere and has traditionally been one of the most important oil provinces in the Americas. Considerable exploration potential is thought to remain, especially offshore.

The country was opened to foreign investments during the period of 1994 to 1997 in order to give new impetus to the development of the oil industry. This resulted in a number of large new projects, mainly in heavy oil (Orinoco belt). The former political establishment was replaced by a new coalition in 1998, led by President Hugo Chávez. The political situation in the country resulted in a general strike at the end of 2002 and early 2003 that caused serious disruptions in the production and shipment of oil. In August 2004, a referendum on the continuance of Hugo Chavez as President resulted in confirmation of his mandate until the next presidential election in December 2006.

The new Hydrocarbon Law was introduced on January 1, 2002 to define the legal framework for liquid hydrocarbon and associated gas activities. It prescribes higher royalties and taxes for oil producing activities, as well as a minimum 51 per cent national participation in traditional upstream activities. There is ongoing dialogue with the authorities with respect to the specifics and the ramifications of the new law. In October 2004, the Venezuelan Government announced the early termination of the grace period during which the royalty rate for projects in the Orinoco belt had been reduced from 16.67 per cent to 1 per cent. The arguments provided by the government to justify this measure include higher oil prices, good acceptance of the synthetic crude qualities in the international markets, and technological developments that allow higher-than planned production rates per well.

LL652. Statoil has a 27 per cent interest in the ChevronTexaco operated LL652 oil field located in Venezuela's Lake Maracaibo. In 2001 and 2002, the LL652 book value was written down based on a new geological assessment performed after a lower than anticipated response to water and gas injection projects and development wells. The LL652 field is currently producing around 9 mbbls of oil per day.

Sincor. The Sincor project involves producing heavy crude oil in the Orinoco Belt, transporting the crude to the coast and upgrading it into a light, low-sulphur syncrude. Statoil holds a 15 per cent interest in the project, which is a strategic joint venture with PDVSA and Total. Sincor is the operator and is responsible for development, operation, upgrading and oil marketing of its products. The project is expected to reach plateau production by 2006 at a level of 180 mboe per stream day of 30-32 degree API, low sulphur syncrude, which Sincor markets under the name of Zuata Sweet. In addition, Sincor produces sulphur and petroleum coke, known as petcoke, for sale on the international market.

Sincor started normal production in March 2002. In 2003, Sincor successfully passed the First Stage Completion Test according to the provisions established in the Project Financing Agreement thereby releasing the USD 1,200 million Senior Debt Guarantee provided by the Sincor partners. This was replaced by a USD 43 million Debt Guarantee. In October 2004, the upgrader was shut down in order to conduct a debottlenecking and plant turn around project. The shutdown was successfully completed within the planned 48 days.

Statoil has expressed interest to the Venezuelan Government in expanding the Sincor operation. Early phase negotiations have started to evaluate feasibility of an expansion.

Plataforma Deltana. In February 2003, Statoil was awarded the operatorship for Block 4 in Plataforma Deltana off the eastern coast of Venezuela. Statoil committed to drill three exploration wells during the four-year license period to establish the resource potential in the block. The first well Ballena x-1 was spudded on January 1, 2005. The remaining two wells of the work program are planned to be drilled in the fourth quarter of 2005 through the first quarter of 2006.

In January 2005, a farm-in agreement was signed between Statoil and Total for Block 4, giving Total a 49 per cent interest. Statoil will remain operator, with 51 per cent. The agreement is subject to the approval of the Venezuelan Ministry of Energy and Mines.

Western Africa

Angola. Statoil's current asset portfolio in Angola comprises fields in three blocks: 15, 17 and 31.

Block 15. This block, operated by ExxonMobil, is approximately 4,000 square kilometers and includes developments at Kizomba A, B and Xikomba. The water depth varies between 250 and 1,600 meters. The first discovery was made in 1997. A total of 19 exploration wells and 11 appraisal wells have been drilled to date and 17 discoveries have been announced. Statoil has a 13.33 per cent interest in the block.

Xikomba is a small isolated discovery being developed and produced by a leased floating production, storage and off take facility (FPSO). The first oil was produced in November 2003. The average production for Xikomba during 2004 was approximately 80 mbbls per day. Statoil's investment in the project, up until the end of 2004, is approximately USD 63 million, in line with the expected investment costs.

Kizomba A was declared commercial in February 2001 and sanctioned for development in June 2001. The production license expires in 2026. The development plan is based on a tension leg wellhead platform with a nearby moored FPSO. Production started on August 7, 2004, and we expect peak production of 250 mbbls of oil per day by the third quarter of 2005. We estimate total investment for the field to be approximately USD 3.7 billion. Statoil's investment up until the end of 2004 is approximately USD 430 million.

Kizomba B was sanctioned in December 2002. The field encompasses the Kissanje and Dikanza discoveries, which will be co-developed with a floating wellhead platform on Kissanje, with a nearby moored FPSO. Dikanza will be a subsea installation, tied back to Kissanje. The FPSO and wellhead platform are to a large extent identical to the Kizomba A facilities. Production is expected to start in the third quarter of 2005, with peak production of 250 mbbls per day by end of 2006. We estimate total investments for the field at USD 3 billion. Statoil's investment at end 2004 is approximately USD 280 million.

In 2003, four successful exploration wildcats and three appraisal/segment wells were drilled. The three appraisal wells confirmed the Saxi, Batuque and Mondo discoveries. These three discoveries may form the basis for a possible Kizomba C development. The Block 15 partnership is now working towards sanctioning of the Marimba North (discovered in 1998) and Mondo developments in 2005. Marimba North will be developed as a tie-in to Kizomba A, and Mondo will be developed as the first stage of the Kizomba C development.

Block 17. Exploration started in 1994. A total of 26 exploration and appraisal wells have been drilled. Of these, only one well was dry. All exploration commitments in the PSA have been met, and the exploration license expired December 31, 2002. All the discoveries so far have been made in water depths deeper than 750 meters. We have a 13.33 per cent interest in this block, which is operated by Total.

Girassol was the first development project in this block. The production license expires in 2023. The development includes an FPSO and a planned total of 32 subsea wells.

Jasmim, a subsea tieback to the Girassol FPSO came on stream in November 2003. The production license expires in 2026. Production is expected to peak at 60 mbbls of oil per day by 2005 from 5 subsea producers. Girassol and Jasmim combined currently have a capacity of approximately 240 mbbls of oil per day.

The Dalia field was sanctioned in April 2003. A total of 67 subsea wells are currently planned. First oil from Dalia is expected in the third quarter of 2006. Dalia is scheduled to reach plateau production of 225 mbbls of oil per day by 2007. The estimated total investment for the field is approximately USD 3.7 billion, of which USD 1.2 billion was invested by December 31, 2004.

Rosa is to be developed as a subsea tieback to the Girassol FPSO, and the field development plan was approved by Sonangol on July 30, 2004. A total of 25 subsea wells are planned. First oil is expected in the middle of 2007 and production is scheduled to reach plateau production of 150 mbbls per day during 2008. The estimated investment for the field is approximately USD 2 billion, of which USD 254 million was invested by December 31, 2004.

The Acacia-2 well, spudded in April 2004 and completed in June 2004, was a discovery. The Perpetua-2 well was completed in February 2005. The Block 17 partnership is evaluating the numerous discoveries in Acacia/UM East and Cravo/Lirio UM West.

Block 31. This ultra deepwater block is located west of Block 15 at the northern end of Angola's continental shelf and covers approximately 5,350 square kilometers. The water depth is between 1,600 and 2,500 meters. We hold a 13.33 per cent interest in Block 31. The block was awarded in 1999, and three-dimensional seismic surveys were performed in 2000. The first commitment well of a four well commitment was drilled in 2001 with disappointing results. The second commitment well, Plutao-1, completed in August 2002, was the first discovery in ultra deep water off Angola. Two additional exploration wells were drilled in 2003, Saturno-1 and Marte-1, both of which produced discoveries. Sonangol has approved a two-year extension of the exploration period. We hold a 13.33 per cent interest in Block 31. Three wells were drilled in 2004. The Venus-1 well, completed in February 2004, was a discovery. The Palas-1 well was spudded in October 2004 and completed in November 2004. The well resulted in a discovery. The Ceres-1 well was spudded in December 2004 and was completed in February 2005. The well results are currently being evaluated. The licensees are considering a potential cluster development.

Gas utilization. All discoveries in Angola contain significant volumes of associated gas. The gas can be used for gas injection or stored for a limited period. Sonangol has rights to the associated gas not required for the production facilities.

Nigeria. Nigeria's political development has been affected in the past by political unrest and violence, which have led to difficulties and disruptions for the oil industry in the Delta area. Projects on the Nigerian continental shelf may also be influenced by potential political instability. All of our activities are in the deepwater areas off Nigeria.

We operate two exploration licenses, in Blocks 217 and 218, with an interest of 53.85 per cent in each. The exploration licenses were granted for a period of ten years, and expired in mid-2003. We have submitted an application to convert each exploration license to an oil mining license (i.e., production license). The Nigerian National Petroleum Corporation and the office of the President have recommended and endorsed the application, and formal approval by the Department of Petroleum Resources was issued in February 2005. The production licenses will be valid for 20 years. We have drilled a total of seven exploration wells in the two license areas, resulting in one oil discovery, Ekoli in Block 217, one gas discovery, Nnwa, and one condensate discovery, Bilah in Block 218.

The Ekoli 1 well proved oil and confirmed the extension of ChevronTexaco's adjacent Agbami discovery in Block 216. The field is currently being unitized between the two licenses and field development work continues as planned. The Unit Agreement was signed by all parties. Agbami will be brought on stream from subsea production facilities tied back to a production and storage ship. Agbami is scheduled to come on stream in the second quarter of 2008, reaching plateau production of 250 mbbls of oil per day in the fourth quarter of 2008.

The Nnwa-2 well, drilled in 2002, proved a significant gas discovery and small amounts of oil in Block 218. The discovery extends into the Shell operated Block 219 (known as the Doro structure), as confirmed by the Doro-1 exploration well drilled in 2000. Under an MOU with Shell, the Nigerian Government and other companies, a feasibility study for floating LNG was completed in 2003. Future plans for NnwaDoro include seismic reprocessing and evaluation. The plan is for Shell as operator of Block 219 to drill the Doro 2 well in 2005 or 2006 on the basis of this evaluation. The Nigerian Government has recently submitted for review fiscal terms for the development of gas in Nigeria. These terms are currently being discussed and negotiated between the oil industry and the Government.

In December 2003, Statoil was awarded a 25 per cent interest in Block 324 deep water Nigeria. Erinmi1-X well was spudded on the block in October 2004. The well was completed in December 2004 and the results are currently being evaluated.

Western Europe

We have interests in Ireland, the Faroes and the UK. The Rosebank / Lochnagar discovery in the UK confirmed our view that there is a potential for future oil and gas discoveries on the Atlantic Margin, the outer part of the continental shelf running from Norway's Lofoten Islands to west of Ireland. We have an exploration portfolio of licenses on the Atlantic Margin with gross acreage exceeding 20,000 square kilometers.

Ireland. In Ireland, we have interests in two exploration licenses, including operatorship of one large exploration license, 5/94 (Slyne-Erris), with an interest of 49.9 per cent, immediately north of the Corrib field development in which we are a partner. Following the drilling of well 19/11-1A in 2003 in this license, which was dry, a large area of three-dimensional seismic data was processed and is currently being interpreted prior to making a drill or drop decision. A decision will be taken by the end of 2006.

Corrib. The Corrib gas field, in which we have a 36.5 per cent interest, lies on the Atlantic Margin north west of Ireland. It was discovered in 1996 and was the first significant discovery offshore Ireland since Kinsale Head in 1973. The Corrib field development, operated by Shell, was sanctioned in February 2001, and the production license was granted in late 2001 with a 30-year duration.

The development will incorporate seven subsea wells and the unprocessed gas will be transported through a pipeline to an onshore gas terminal. This receiving facility will be constructed on the coast of County Mayo. The Corrib project was sanctioned for scheduled production start-up in October 2003. Due to the rejection of the application for planning permission for the gas terminal, the start-up has been delayed until 2007. The Irish Planning Authorities granted planning permission for the gas terminal on October 22, 2004. The development cost of the Corrib project is estimated at EUR 0.9 billion, of which approximately EUR 0.4 billion has been spent by December 31, 2004.

Faroes. We were awarded the operatorships for two exploration licenses in the first licensing round on the Faroes Shelf in the North Atlantic in 2000. A total of seven licenses were granted to 12 oil companies organized in five groups. We have been evaluating the potential of the Faroes area of the continental shelf since the early 1990s. The area presents technical challenges, primarily seismic imaging, as much of the area has been covered by thick layers of basalt.

The Statoil operated License 003, in which we have a 35 per cent interest, lies in the Foinaven sub-basin and was granted in 2000 for a period of six years. The terms of the license require us to drill two exploration wells. We drilled the first well in late summer 2001, at a location about 180 km south of Torshavn and 60 km northwest of the producing UK oil field Schiehallion, with disappointing results. Three-dimensional seismic data were acquired on the license towards the end of 2002 and processed in 2003. Remaining prospectivity in this license is poor and the Group is currently deciding where to drill the remaining well. A clear option may be to transfer the well elsewhere if the authorities agree to Statoil's proposal.

The Statoil operated License 006 lies on the East Faroe Ridge, and was awarded during 2000 for a period of nine years. Statoil hold a 37.5 per cent interest. The license obligation requires us to perform seismic surveys. In 2003, we negotiated a two-year extension to the first phase of the license and acquired a three-dimensional survey over the crestal areas of the Brugdan prospect, a large four-way dip-closed feature lying beneath thick basalts. We believe this prospect is a promising candidate for a well.

On January 17, 2005, through the 2nd Licensing Round in the Faroes, Statoil was awarded Licenses 010 and 011 (where it is a sole licensee), License 009 (Statoil is operator with a 50 per cent interest), and License 008 (Statoil has a 30 per cent interest, with ChevronTexaco as operator with a 40 per cent interest).

United Kingdom. We are a partner in several producing licenses on the UK continental shelf, and our exploration focus is on the less explored Atlantic Margin. In January 2004, Statoil made a decision to farm-in to a ChevronTexaco license west of the Shetlands in the UK taking a 30 per cent interest. ChevronTexaco drilled a well on this license on the Rosebank / Lochnagar prospect during the summer and made a significant oil and gas discovery. Additional wells are planned to appraise the discovery. In September 2004, during the UK 22nd Round, the partnership was awarded three licenses comprising five blocks surrounding the prospect. Statoil has a 30 per cent interest in all three licenses, which are Blocks 213/22, 23 and 38, Block 205/1 and Block 213/21.

Schiehallion. This field currently produces approximately 110 mboe per day. The Schiehallion license will expire in August 2017. We have a 5.88 per cent interest in the field. The Schiehallion field has been developed as a subsea development tied back to a new FPSO, which is owned by the field participants. The FPSO also acts as the host facility for the BP and Shell-owned Loyal field, which is located north of Schiehallion. The original sanctioned development drilling was completed in 2000; however, additional phases are planned which are expected to increase reserve volumes. Oil is exported by a dedicated shuttle tanker to the Sullom Voe terminal. Associated gas is currently used for power generation with the residual being exported via a pipeline to Sullom Voe and onto the BP-operated Magnus field where it is used for enhanced oil recovery.

Alba. The Alba license, in which we hold a 17 per cent interest, expires in March 2018. The field is undergoing a multi-phased development, the third phase being the sub-sea development of the extreme south area of the field. This phase was successfully completed in October 2004 and increased daily production from Alba to over 80 mboe per day. The annual average production for Alba during 2004 was over 67 mbbls of oil per day. The forward work plan for 2005 will focus on exploiting infill drilling targets and improving plant uptime performance. Potential opportunities for enhanced oil recovery within the field will also be examined.

Caledonia. The Caledonia field is located immediately north of the Alba field and contained within the same block. The single horizontal production well was drilled in the third quarter of 2002 and tied back via a subsea template and pipeline to the Britannia platform where the fluids are processed and oil exported through the Forties Pipeline. Production commenced in February 2003 at approximately 11 mbbls of oil per day, and has declined to an annual average of less than 5 mbbls per day during 2004. We have a 21.32 per cent interest in the ChevronTexaco operated field.

Dunlin. The Shell operated field is currently in tail-end production with an average daily rate in 2004 of less than 5 mbbls of oil. Production was lower than expected, due to an unplanned shutdown of the platform during the third quarter of the year. The shutdown was necessary due to a hydrocarbon leak into a platform leg. Production was shut down until December 2, 2004, while the source of the leak was identified and the necessary repairs made. The Dunlin license in which we hold a 28.76 per cent interest expires in August 2017. The platform receives tariff income from processing satellite Merlin and Osprey oil accumulations. The co-mingled production stream is exported via the Brent System Pipeline to the Sullom Voe Terminal located on the Shetland Islands. Production is scheduled to cease at the end of 2008 (based on economic cut-off). The total cost of abandonment is estimated to be USD 236 million.

Merlin. The Shell operated field, in which we hold a 2.35 per cent interest, is now in decline. Production during 2004 was less than 2 mbbls of oil per day due to a series of unplanned production shutdowns linked to the shutdown on Dunlin. No further appraisal of the accumulation is envisaged. The Merlin license will expire in August 2017. Production is expected to cease in 2008. The cost of shutdown is included in the estimates for Dunlin above.

Jupiter. The Jupiter field, operated by ConocoPhillips, consists of six gas accumulations: Ganymede, Callisto South, Callisto North, Europa, Sinope North and Bell. Perenco's interest in the Bell field will also be produced via Jupiter facilities. Current production is approximately 7 mboe per day. A new well is currently being drilled on Ganymede. The Jupiter license, in which we hold a 30 per cent interest, will expire in 2010.

New Areas

We are also exploring additional opportunities outside our main producing areas. We have been focusing our efforts on the Middle East and Russia (including the Barents region) and considering opportunities in the Caspian Region, Latin America, and the U.S.

Middle East

Statoil is actively pursuing business development options in the Middle East region, and has representative offices in Tehran (Iran), Riyadh (Saudi Arabia), Abu Dhabi, Dubai (both UAE) and Doha (Qatar).

Iran. We consider Iran to be a promising country for business opportunities given the large undeveloped reserves and the large estimated remaining undiscovered hydrocarbon resources.

See Item 8-Financial Information-Legal Proceedings for information on the penalty imposed by the Norwegian National Authority for Investigation and Prosecution of Economic and Environmental Crime (Økokrim) and the investigations by the Securities and Exchange Commission, the Department of Justice, and other regulatory bodies into the consulting agreement that Statoil entered into in 2002 with Horton Investments Ltd. See also Item 3-Key Information-Risk Factors.

All our activities in Iran are in accordance with Norwegian foreign policy of increased trade relations with Iran. See Item 3-Key Information-Risk Factors for additional information concerning the risk of US sanctions because of our activities in Iran.

In November 2000, Statoil signed a non-binding protocol with NIOC to evaluate several projects in Iran within the areas of increased oil recovery, GTL processing and field developments. During 2001 we entered into three agreements with NIOC for increased oil recovery project activities for the Ahwaz, the Marun and the Bibi Hakimeh fields. Together these fields currently produce around 1.5 mmbbls of oil per day. The increased oil recovery study phases for the three fields were completed and approved by NIOC during 2004. Statoil and NIOC are currently discussing the basis and framework for continuing this partnership into the implementation phase.

In 2003 Statoil, together with South African PetroSA, signed an agreement defining the commercial framework for investing in a GTL processing plant in Iran with NIOC. A plant has been constructed with PetroSA in South Africa to test the Statoil technology of GTL with an aim to build a 60 mbbls per day plant in Iran. Testing of the technology is ongoing.

South Pars phases 6, 7 and 8. On December 12, 2002, Statoil became operator for the development of the offshore part of the South Pars 6, 7 and 8 project with up to a 40 per cent share during the development phase. Statoil's share of total investment in the project was originally planned to be USD 335 million, of which USD 219 million was invested by the end of 2004. The South Pars phase 6, 7 and 8 offshore project's scope consists of three wellhead platforms with three pipelines, condensate loading line and associated single buoy mooring, drilling of 27 production wells, hook-up of 3 pre-drilled wells, and required reservoir management. The project is managed from Tehran. All three jackets were installed during the first part of 2004 in a water depth of 65 meters in the Persian Gulf. Drilling is ahead of schedule, and the well tests indicate productivity above original plans. The condensate line and two pipelines were coated and loaded out by Sadra, an Iranian company, and laid by Allseas, a Swiss company, during the second half of 2004. Sadra continues to work with coating of pipes for the third pipeline and completion of the third pipe laying barge. Fabrication of topsides, also done by Sadra, is behind schedule due to a shortage of material on site. Completion of the offshore development project is expected in the second half of 2006. Commencement of production is dependent on completion of the South Pars onshore plant by Petropars. At the end of 2004, the South Pars 6, 7 and 8 project was 58 per cent completed.

Russia. Statoil has been present in Russia since the early 1990s with a representation office in Moscow in addition to the petrol station business in the Murmansk area. Business development activity in Russia has grown in 2004, focusing on access to both exploration acreage and existing fields. Statoil considers Russia a natural long-term potential core area and believes that there are significant resources still to be discovered in the Barents Sea which it views as a natural growth area as an extension of its present position on the NCS.

On September 8, 2004, Statoil signed a Memorandum of Understanding with the Russian gas company Gazprom and the Russian State oil company Rosneft on the possible cooperation in development of the Shtokman field. Following the decision by the Norwegian Government to reopen exploration activities in the Barents Sea, Statoil will drill two exploration wells in the Norwegian sector of the Barents Sea in the second quarter of 2005. In order to strengthen the work on realizing our business opportunities, a new unit responsible for the Barents Region has been established.

Kazakhstan. In May 2004, Norwegian Prime Minister Kjell Magne Bondevik officially opened Statoil's office in Astana, the capital of Kazakhstan, demonstrating official support to Statoil's efforts to assess future business opportunities in the country.

During 2004, few new offshore exploration deals were entered into by the Kazakh authorities or KazMunayGaz (KMG), the newly organized national oil and gas company. In 2004 Statoil continued to promote future cooperation with KMG. The industry is closely monitoring to see if the 2005 proposed changes to the petroleum sector taxation will be sufficient to attract foreign investment.

Brazil. In 2001 we acquired a 25 per cent interest in two Santos Basin blocks in the 3rd Licensing Round: BM-S-17, operated by Petrobras, and BM-S-19, operated by Repsol. Three-dimensional seismic surveys have been acquired in both blocks, and in 2004, at the end of the first exploration phase of the licenses, Statoil withdrew from both.

In 2002, through the 4th Licensing Round, we acquired a 40 per cent interest in Block BM-J-3 with Petrobras as operator. A 3D seismic survey was acquired and processed in 2004. Our fourth license was acquired in 2002 through a 30 per cent farm-in to the ConocoPhillips operated block BM-ES-11 in the Espirito Santo Basin. Statoil has now acquired the outstanding 70 per cent of the equity in the block (increasing the holding to 100 per cent) and taken over the operatorship. A decision is due in 2005 whether to relinquish the block or to enter the next exploration phase, which carries a drilling commitment.

During 2003, Statoil participated in an exploration well on Block BM-C-10 under a farm-in with the operator Shell. As the well was not successful, the block was relinquished.

In 2004, through the 6th Licensing Round, Statoil was awarded three exploration licenses comprising six blocks in the Camamu-Alamada basin offshore Brazil. These are BM-CAL-8 (where Statoil is the sole licensee), BM-CAL-10 (Statoil is operator with a 60 per cent interest) and BM-CAL-7 (Statoil has a 40 per cent interest in this license, with Petrobras as operator holding the remaining 60 per cent). The awards commit Statoil to carrying out a seismic survey program, due to start in 2005, and to drilling at least two exploration wells.

U.S. In December 2003, Statoil signed an agreement with ChevronTexaco that enabled it to secure up to 25 per cent equity in a small number of selected deepwater exploration opportunities in the Gulf of Mexico. This led to Statoil's participation in the Tiger exploration well during the first quarter of 2004. The well was successful. Statoil's interest is 25 per cent. Through participation in this well Statoil earned equity in two prospects in the same area: Canaan (12.5 per cent) and Ontario (12.5 per cent). These prospects are planned to be drilled in 2006.

Mexico. Since March 2001, Statoil has cooperated with Pemex regarding the possibility for future exploration and production operation.

Libya. We are currently assessing opportunities for participating in exploration and development activities in Libya.

Other Existing Areas

China. We operate the Lufeng oil field and hold a 75 per cent interest in the project. Our partner is the China National Offshore Oil Company (25 per cent). Lufeng suspended production on June 28, 2004 after six and a half years of production in order to carry out a sidetrack drilling project. Cumulative production from the field since first oil is 33 mmbbls. FPSO "Munin" will be used as a temporary replacement for the FPSO at the ConocoPhillips' Xijiang oil field in the South China Sea. The partnership has approved the plan for the sidetracking project on Lufeng to extend the production period and further increase the oil recovery from the field. Production is expected to restart in the second quarter of 2005.

Natural Gas

Introduction

Our Natural Gas business segment transports, processes and sells natural gas from production fields to customers. In 2004, we sold on our own behalf 25.0 bcm (881 bcf) of natural gas (at a gross calorific value of 40 MJ/scm), as well as approximately 30.3 bcm (1,069 bcf) on behalf of the Norwegian State, including both equity and third party gas. We are the largest exporter and marketer of Norwegian natural gas. Our volumes and volumes sold on behalf of the Norwegian State represent approximately two-thirds of the entire NCS contract portfolio.

We have a significant interest in the world's largest offshore gas pipeline transportation system that extends more than 5,000 kilometers. This extensive network links Norway's offshore gas fields with gas treatment plants on the Norwegian mainland and to terminals at four landing points located in France, Germany, Belgium and the United Kingdom, providing us with flexible access to customers throughout Europe.

Effective January 1, 2003, the ownership of all of these transportation and processing facilities with third party access was unitized into a single joint venture: Gassled. The technical operation of most of the natural gas transport system (including the Kårstø Gas Treatment Plant), such as system maintenance, is still carried out by us on a cost-recovery basis. As from February 1, 2004 the Kollsnes Gas Plant was included in Gassled. See below under Regulation-The Norwegian Gas Sales Organization.

Nearly all midstream and downstream gas projects associated with our international activities are organized in the Natural Gas division. This includes midstream and commercial activities in Shah Deniz, downstream activities in Turkey and our position in Cove Point in the U.S.

Statoil has a large long-term gas sales contract portfolio, described below, and is currently evaluating midstream and downstream opportunities to take further advantage of our existing infrastructure, large supply and experience in marketing natural gas. Our downstream strategies may differ from region to region depending on our particular position in the area. In Europe, we intend to extract greater efficiency from our existing infrastructure in order to deliver larger volumes and to enter into a wider range of sales arrangements in order to reach a broader customer base. The Natural Gas business segment intends to focus on supplying the commercial, industrial and wholesale markets and currently have no plans to enter the residential gas market.

The following table sets forth key financial information about this business segment.

Further details on the financial results can be found in Item 5-Operating and Financial Review and Prospects-Operating Results.

European Gas Market

According to the International Energy Agency (IEA) annual natural gas consumption in OECD-Europe was 510 bcm (18 tcf) in 2003. Preliminary figures from IEA for the first eight months of 2004 show an estimated growth of 3.4 per cent for 2004 as compared to the same period in 2003. The estimated annual growth in gas consumption in the period 2000-2010 is 3 per cent. The gas share of total primary energy consumption is approaching 25 per cent in Europe. Around 60 per cent of the growth in gas consumption in the period 2000-2010 is assumed to come from the electricity sector. OECD Europe includes Austria, Belgium, the Czech Republic, Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, the Netherlands, Norway, Poland, Portugal, the Slovak Republic, Spain, Sweden, Switzerland, Turkey and the United Kingdom. The IEA expects a growth in demand for all sub sectors of the OECD Europe natural gas market.

Statoil markets and sells its gas together with the Norwegian State's natural gas, and taken together, we are one of the four major suppliers to the European market. The other major suppliers are Gazprom from Russia, Sonatrach from Algeria and Gasunie from the Netherlands. We believe that the Norwegian natural gas we market is competitive because of its reliability, access to the transportation infrastructure and proximity to the European market.

As the European energy market undergoes deregulation and structural changes, we believe that natural gas will play an increasingly important role. In particular, the use of natural gas as a source for electricity generation is growing.

Our analysis, based on data released by Wood Mackenzie, an industry consultant, and National Grid Transco (NGT), the UK gas transportation company, suggests that the United Kingdom's own natural gas supply, excluding exports, will fall short of annual domestic demand, starting in 2005. This analysis indicates that the significant and sustained drop in indigenous supplies will trigger the need for new imports. Given our current and planned infrastructure, we believe that we are well positioned to take advantage of the UK's increased demand for imported natural gas and to participate in Europe's largest and most liberalized natural gas markets. A joint venture has been created to build a new export pipeline, Langeled, from the NCS to Easington in the UK of which Statoil and the Norwegian state will have approximately 48 per cent of the capacity. Langeled is scheduled to be operational from the fourth quarter of 2006. Other UK import projects, in which we do not take part, are the Bacton Zeebrugge Interconnector enhancement, the new Balgzand-Bacton pipeline from Holland, an LNG import terminal at the Isle of Grain (close to London) and two LNG terminals at Milford Haven (South Wales).

Although we expect to face a more competitive downstream natural gas market in continental Europe as the EU Gas Directive concerning deregulation and market liberalization takes increased effect, we believe that our established market positions, long-term relationships with large customers, experience in the marketing of natural gas and established points of entry will place us in a strong competitive position. For more information about the EU Gas Directive, please refer to -Regulation below.

Gas Sales and Marketing

Our major export markets for NCS gas are Germany, France, the United Kingdom, Belgium, Italy and the Netherlands. Our customers are mainly large national or regional gas companies, such as E.ON Ruhrgas, Gaz de France, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), Distrigaz and Gasunie. In addition, we sell to large end-users. Natural gas is sold to these customers mostly under long-term, take-or-pay contracts. Our long-term contract portfolio, including sales of SDFI gas, will increase by approximately 17 per cent from 2004 to 2009. In 2005, we have contracted to sell approximately 52 bcm (1.8 tcf) on our behalf and for the Norwegian State, of which approximately 47 per cent will be for our own account. In 2004, our three largest customers, with contracts that expire between 2025 and 2029, represented almost half of our total sales volumes.

Statoil carries out gas sales and marketing activities of NCS gas for the benefit of Statoil and the SDFI. In addition, Statoil markets gas sourced from other producing areas than the NCS, both towards markets already penetrated by Statoil and the SDFI and towards new markets.

In February 2004 Statoil signed a medium-term gas contract with Essent, a large Dutch gas and electricity retailer, for the sales of 6.5 bcm natural gas over a 5-year period, with deliveries commencing late 2004. In 2004, Statoil also concluded a further gas sales agreement with Centrica, the largest marketer of gas in the UK. The 1 bcm deal is for one year and deliveries started on October 1, 2004 at the UK's liquid trading hub (national balancing point). The deal is priced to a UK market gas price index. Statoil now sells a total of 5 bcm per annum to Centrica.

In the United Kingdom, we market our gas towards large industrial customers, power generators and wholesalers, and participate in the UK spot market. Our group-wide gas trading activity is mainly focused around the UK gas market which is a significant market in terms of size and one of the most progressive in terms of deregulation when compared with other European markets. Our UK trading activities were focused on optimizing NCS volumes to the UK and Europe by profiling NCS deliveries to match the highest priced spot market periods. This strategy leads to additional value above and beyond average sales contract profit. However, as the Vesterled pipeline capacity will likely become fully utilized in 2005, optimization opportunities in the UK will become more limited until the fourth quarter of 2006 when Langeled is due to become operational. Nevertheless, the UK Trading function will still work closely with upstream operations and European marketing units to add value to Statoil's sales portfolio.

On February 13, 2004 Statoil and Scottish and Southern Energy (SSE) signed a Joint Participation Agreement and entered into a Joint Venture for the development, operation and maintenance of a salt cavern gas storage facility near Aldbrough, on the east coast of Yorkshire. On completion the storage facility will comprise nine underground caverns. Statoil owns one third of the storage capacity being developed, of which a proportionate share is being used and paid for by the SDFI. The facility brings together two sets of Planning Consents granted to the parties in 2000 and will be developed and operated by SSE. Construction work started in the first quarter of 2004 and all site work preparations have been completed. By the end of 2004, the majority of the major contracts were awarded. According to the work schedule, the storage facility will begin commercial operation by the fourth quarter of 2007 with full commercial operation of the nine cavern facility, with a capacity of 200 mcm, in 2009. Statoil's share of the total development cost is estimated to be NOK 1.6 billion, of which a proportionate share will be covered by the SDFI. Development responsibility for this asset has been transferred to the Technology and Projects business area.

In Germany, we hold a 21.8 per cent stake in the Norddeutsche Erdgas-Transversale, or Netra, overland gas transmission pipeline, and a 20.1 per cent stake in Etzel Gas Storage. Our share in EuroHub GmbH (formerly HubCo North West European Hub Service Company) was reduced from 25 per cent to 16.6 per cent due to the accession of N.V. Nederlandse Gasunie to the partnership. The 5.26 per cent stake in VNG Verbundnetz Gas AG, a German gas merchant company, was sold to EWE AG in December 2003. This divestment was made in connection with the major changes of the ownership structure of VNG as a result of the Ruhrgas/E.ON merger conditions. The sale was completed in January 2004.

The Natural Gas business segment is responsible for the midstream and commercial activities related to the Shah Deniz project in Azerbaijan. Turkey is the main market for gas from Stage 1 of the Shah Deniz development. A Gas Sales and Purchase Agreement (SPA) was signed between SOCAR and the Turkish gas company Botas in March 2001, covering a contractual level of 6.6 bcm annually. At the time of project sanction, the Turkish SPA, together with gas sales agreements to Georgia and Azerbaijan, were assigned to the Stage 1 sales company, Azerbaijan Gas Supply Company (AGSC). AGSC is fully operated by Statoil, with the Shah Deniz partners and the Azeri state as owners. The gas sales agreements with Azerbaijan and Georgia cover annual contractual levels of 1.7 bcm and 0.5 bcm respectively. The sanction cost for the SCP was USD 0.9 billion. As discussed above in International E&P, the projects have been under upward cost pressure and the partnership is currently reviewing the cost estimate.

During the fall of 2001, intergovernmental and host governmental agreements between Turkey, Georgia and Azerbaijan were signed. In order to further secure a long-term market for our Shah Deniz gas, we have, together with the Turkish KOÇ group, opened a gas marketing office in Turkey.

In the U.S. we market gas towards local distribution companies, industrial customers and power generators. LNG is imported from Algeria and Trinidad and regasified through Cove Point LNG terminal in Maryland, where we have entered in to a long term contract (20 years) with the operator Dominion Resources Inc., securing us capacity rights of 2.4 bcm/year, of which a proportionate share is being used and paid for by the SDFI. We source some gas domestically, mainly for optimization purposes. When Snøhvit comes on stream, we will be marketing NCS gas. The Cove Point Pipeline interconnects with 3 interstate pipelines, allowing natural gas to be directed to the mid-Atlantic and North East markets.

Statoil has signed a new contract with Dominion Resources Inc. that secures access to additional import capacity of 7.7 bcm per year at the Cove Point LNG terminal, for a 20-year period from November 2008. The transaction is subject to approval by the Federal Energy Regulatory Committee. Statoil has secured further pipeline transportation and storage capacity that will extend the current market area in order to maximize the benefit of the higher import capacity realized through the Cove Point Expansion.

The Natural Gas business segment has been reorganized with implementation of a new organization structure as of January 1, 2005. The new organization, which has moved from a geographical to a functional organizational structure, underpins the strategic priorities for Natural Gas with emphasis on:

Norwegian Gas Transportation System and Other Facilities

In order to transport Norwegian natural gas to European customers, we and other Norwegian gas producers have built an extensive gas pipeline system, connecting gas fields to gas processing plants on the Norwegian mainland and to receiving terminals in Europe.

As from January 1, 2003 the ownership interests of the Zeepipe, Franpipe, Europipe II, Åsgard Transport, Statpipe, Oseberg Gas Transport and Vesterled joint ventures and Norpipe AS were transferred to a new joint venture called Gassled. This also includes the terminals in Statpipe and Vesterled, the Europipe Receiving Facilities and the Europipe Metering Station. The ownership interests in Zeepipe Terminal JV and Dunkerque Terminal DA have been adjusted. As from February 1, 2004 the Kollsnes Gas Plant was included in Gassled. Our interests in Gassled and other pipelines and terminals are listed in the tables below.

From January 1, 2011, our ownership interest in Gassled will be reduced due to an increased ownership interest for the SDFI. Similar adjustments of the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA will also be made. In addition, our ownership interest in Gassled may change as a result of the inclusion of existing or new infrastructure or if Gassled undertakes further investments without participation from its owners in the same ratio as their ownership interests in Gassled. Gassled has a license period up to 2028.

The Gassled-system is operated by Gassco AS. Gassco is wholly owned by the Norwegian State, and holds no ownership in Gassled or in gas production. In 2004, the system transported 73.1 bcm (2.6 tcf) of Norwegian gas and has additional capacity to transport 14 to 18.5 bcm (0.5 to 0.6 tcf) per year.

In December 2004 Statoil and ConocoPhillips agreed to establish a joint operating company, GasPort KG, for the receiving terminals and the metering station in Emden and Dornum in Germany, with effect from January 1, 2005. Gassco AS operates these facilities, with Statoil and ConocoPhillips as TSPs.

Gassco has entered into contracts with us pursuant to which we act as Technical Service Provider (TSP) on behalf of Gassco on a cost recovery basis. With certain exceptions, these contracts may be terminated by either Gassco or us at any time without cause. In January 2005, Gassco proposed to take over the technical management of the Emden, Zeebrugge and Dunkerque terminals and related facilities. Gassco's proposal is currently being considered by the Ministry of Petroleum and Energy. For more information, see Item 7-Major Shareholders and Related Party Transactions-Major Shareholders-Gassco-The Gas Transportation Operating Company.

To cater for existing commitments and expected new gas sales to the UK, increased transportation capacity will be required. The construction of a new dry gas pipeline, Langeled, from the Ormen Lange field via Sleipner to Easington in UK, commenced in 2004. The development of the Langeled pipeline and terminal facilities will be performed by Statoil, on assignment from the field development operator Norsk Hydro. Ormen Lange will account for approximately 20 per cent of Norwegian gas export capacity in 2010 bringing the capacity to a level of approximately 115 bcm/year. The southern leg (Sleipner to Easington) is due to be completed during the fourth quarter of 2006 and the northern leg (Nyhamna to Sleipner) is due to be completed during the fourth quarter of 2007. Development responsibility for this asset has been transferred to the T&P unit. Total investments are estimated to be NOK 18.0 billion, of which NOK 3.8 billion has been invested as of December 31, 2004. Our ownership in this pipeline is 15 per cent. On completion it is expected that the ownership for Langeled will be transferred into Gassled.

Gassled is divided into five areas; area A is the Statfjord - Kårstø pipeline, area B is the Åsgard - Kårstø Pipeline, area C is the Kårstø Gas Treatment Plant, area D is all the dry gas pipelines and area E is the Kollsnes Gas Plant, as illustrated in the figure below.

Gassled area A, B, C, D, and E

Our ability to transport our own supply of natural gas from our various field interests enables us to provide regular and reliable gas deliveries to our customers. The pipelines intersect at platforms, tie-in locations and processing plants, providing a flexible network to transport natural gas from various fields and gas processing plants to our entry points into the European market, depending on our customers' contracted daily and annual natural gas sales requirements. Each field operates with an account system, permitting fields to borrow and repay gas volumes as needed to meet their supply needs. If, for instance, one platform is forced to shut down production temporarily, another field can increase production to temporarily cover the supply shortfall, thereby providing the end user with uninterrupted supply. This supply and source flexibility is also advantageous since it permits us to blend natural gas from different fields to modulate natural gas quality.

The major costs associated with running a pipeline system are maintenance and compression costs that result from operating compression facilities to increase gas throughput. Most transport agreements are based on a tariff per unit transported which covers the operating cost of the transport system and provides a return on the capital invested. The Ministry of Petroleum and Energy sets such tariffs. The pipelines are maintained under an annual maintenance plan approved by the Norwegian Petroleum Directorate.

The following table sets out the major NCS gas transportation systems in which we have an interest, the transportation routes and capacities. All of the pipelines and terminals are operated by Gassco AS.

Transportation systems included in Gassled

(1)We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries.

Terminals included in Gassled

(1)Included as from February 1, 2004

Pipelines not included in Gassled

(1)Owned by E&P Norway.

Terminals not included in Gassled ^{(1) (2)}

(1)  These interests include Statoil's 25 per cent interest in Norsea Gas AS.

(2)  The changes in ownership structure over time are caused by changes in the underlying ownership in Gassled.

(3)  This change is effective from October 1, 2005.

(4)  This interest is held through our ownership in Gassled. Gassled owns 49 per cent of the terminal.

(5)  This interest is held through our ownership in Gassled. Gassled owns 65 per cent of the terminal.

Ownership structure Gassled

(1)There will be some minor adjustments in the Gassled ownership structure when the Kårstø Expansion Project is finished in 2005. Langeled joint venture and Etanor DA are not included in the above ownership structure for 2005 - 2010. The inclusion will have some reducing effect on Statoil's share when agreed upon late 2006.

(2)Petoro holds the participating interest on behalf of the SDFI.

Kårstø Gas Treatment Plant (Area C)

Statoil, as TSP, is responsible for the technical aspects of the operation of the Kårstø gas treatment plant, on behalf of the operator Gassco. Kårstø processes rich gas and condensate, or light oil, from the NCS received via the Statfjord - Kårstø pipeline (area A) pipe, the Åsgard - Kårstø pipeline (area B) and the Sleipner condensate pipeline. Products produced at Kårstø include ethane, propane, iso-butane, normal butane and naphtha and stabilized condensate. In 2004, Kårstø produced 0.5 million tonnes of ethane, 5.3 million tonnes of LPG and 3.3 million tonnes of condensate/naphtha exported to customers worldwide.

The Kårstø Expansion Project is being carried out primarily to accommodate gas from the Kristin field from October 1, 2005. The expansion increases extraction capacity by 13.5 mmcm/day, removes Co₂from sales gas, and increases ethane recovery.

After the expansion in 2000, which entailed taking in gas from the Åsgard field, the Norwegian Pollution Control Authority (SFT) required Kårstø to reduce its NOx emissions. The final permit was received in January 2004 and requires a reduction of 189 tonnes of NOx per year (from 1,220 tonnes per year to 1,031 tonnes per year) starting in October 2005. The permit requires a further reduction of 291 tonnes of NOx per year (from 1,031 tonnes per year to 740 tonnes per year) from November 2007. Alternative initiatives to meet this requirement have been identified and applications have been submitted to the SFT. The estimated installation costs are between NOK 100 million and NOK 150 million.

Kollsnes Gas Treatment Plant (Area E)

Statoil, as TSP, is responsible for the technical aspects of the operation of the Kollsnes gas treatment plant, on behalf of the operator Gassco. The plant was built to receive gas landed from the Troll field through two 36-inch pipelines. The current gas processing capacity is approximately 120 mmcm per day. At Kollsnes, the Troll gas is dried and compressed for export to Europe. NGLs extracted are transported through a pipeline to the Mongstad refinery for further processing.

Gas Sales Agreements

In 1987, the Norwegian State established the Gas Negotiation Committee, known as the GFU, as an integrated resource management instrument. In the period from 1987 to 2001, the GFU, chaired by Statoil, was given the task to negotiate all NCS gas sales contracts.

The structural changes in the European gas market prompted the Norwegian State to abolish the GFU gas resource management system in June 2001 and allowed the individual oil and gas companies on the NCS to market and sell their own gas, regardless of which field the gas originated from. Necessary changes have thus been made to the institutional, legal and commercial arrangements, including existing license, supply and transportation agreements, and were made effective as of October 1, 2002. As a part of this restructuring the Troll Commercial Model, which distributed rights and obligations under the Troll gas sales agreement, has been abandoned. In addition, the licensees have established new lifting arrangements in the individual licenses. The Ministry of Petroleum and Energy still has the right to approve all new gas sales from the NCS, but no longer has the right to decide the allocation of new agreement to fields as each company now negotiates these agreements individually. (See also-Regulation-The Norwegian Gas Sales Organization).

Statoil is instructed by the Norwegian State to manage, transport and sell the gas owned by the SDFI, resulting in Statoil managing, transporting and marketing about two-thirds of all NCS gas.

Due to the relatively large size of NCS gas fields and the extensive cost in developing new fields and gas transportation pipelines, virtually all NCS gas sales contracts are long-term supply contracts in which the purchasers agree to take daily and annual quantities of gas and, if the gas is not taken, are obliged to pay for the contracted quantity. This applies to the initial depletion contracts, Troll and GFU contracts and generally applies to the new individual company sales contracts.

Our long-term contracts generally run for 10 to 20 years or more. A significant portion of our current long-term sales contracts reach plateau level between 2005 and 2008.

Prices in these contracts are generally tied to a formula based on prevailing prices of a customer's principal alternative fuels to natural gas, mainly heavy fuel oil and gas oil. Consequently, there can be significant price fluctuations during the life of the contract. Prices in these contracts are generally adjusted quarterly and are calculated on the basis of prices prevailing in the three to nine months prior to the date of adjustment as published in reference indices. By contrast, recent long-term gas sales contracts in the UK are priced with reference to a daily UK market gas price index. The price formula, calling for monthly or quarterly adjustment, however, is not able to capture all trends in the market place in either the gas or competing fuel markets, i.e., changes in taxation of gas and competing fuels imposed by national governments. Therefore, most of our long-term gas contracts contain contractual price adjustment mechanisms that can be triggered at regular intervals by either the buyer or the seller. Under our long-term sales contracts either party has the right to initiate a price review process under certain circumstances as set forth in these contracts.

Several price reviews have occurred since 1992. In past price reviews, price formulas have been adjusted without materially altering the commercial value of the contracts. Approximately 60 per cent of the quantities of our long-term sales contracts were eligible for potential price review in 2004. These reviews have yet to be concluded. In 2005 approximately 10 per cent of the quantities of our long-term sales contracts are eligible for potential price review.

Manufacturing and Marketing

Introduction

The Manufacturing and Marketing business segment comprises our downstream activities, including sales and trading of crude oil and refined products, refining and methanol production, retail and industrial marketing of oil products as well as petrochemical operations through our 50 per cent interest in Borealis. In July 2004, we repurchased the 50 per cent share in Statoil Detaljhandel Skandinavia AS (SDS) from ICA/Ahold. The company (SDS) is now 100 per cent owned by Statoil.

The following table sets forth key financial information about this business unit.

Further details on the financial results can be found in Item 5-Operating and Financial Review and Prospects-Operating Results.

Oil Sales, Trading and Supply

We are one of the largest net sellers of crude oil in the world, operating out of sales offices in Stavanger, London, Singapore and Stamford, Connecticut, selling and trading crude oil, NGL and refined products. We market and sell the Norwegian State's crude oil together with our own. In 2004, we sold 709 mmbbls of crude, or above 1.9 mmbbls per day, including sales to our own refineries and other internal divisions. Crude oil sales in 2004 were 10 per cent lower than sales in 2003 as a result of lower production on the NCS. Our main crude oil market is in northwest Europe, and we also sell large volumes into North America and Asia. Most of our crude oil volumes are sold on spot market terms, based on worldwide prices and quotations. Of the volumes we sold in 2004, approximately 31 per cent were our own volumes. We purchase crude oil from third parties in order to obtain other qualities of oil for sale and blending, and to increase our flexibility with respect to shipping and storage.

The main markets for our refined products, NGLs and condensate are in northwest Europe and the countries around the Baltic Sea rim. We are a large supplier of condensate in Europe, providing this very light crude oil to refiners and the petrochemical industry. In addition, condensate cargoes are sold in the US and Far East markets. In 2004, we sold approximately 28.8 million tonnes of refined oil products, the majority of which was refined at our refineries at Mongstad and Kalundborg, and approximately 10.9 million tonnes of NGL, including condensate.

Manufacturing

We are majority owner (79 per cent) and operator of the Mongstad refinery in Norway, which has a crude oil distillation capacity of 179 mbbls per day, and owner (100 per cent) and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbls per day. In addition, we have the right to 10 per cent of the production capacity at the Shell-operated refinery in Pernis, the Netherlands, which has a crude oil distillation capacity of 400 mbbls per day. Our methanol operations consist of our 81.7 per cent stake in Europe's newest gas-based methanol plant at Tjeldbergodden, Norway, which came into production in 1997 and has a design capacity of 946,000 tonnes per year.

The following table gives operating characteristics of the plants at Mongstad, Kalundborg and Tjeldbergodden. We had planned turnarounds (major maintenance shutdowns) at Mongstad in 2002 and 2004, in Kalundborg in 2002, and at Tjeldbergodden in 2002 and 2004.

All data for year ended December 31,

(1)  Actual throughput of crude oils, condensates, feed and blendstock, measured in million tonnes.

(2)  Nominal crude oil and condensate distillation capacity, and methanol production capacity.

(3)  Composite factor for all processing units, excluding turnarounds.

(4)  Composite rate for all processing units, stream day utilization.

Mongstad. The Mongstad refinery is directly linked to offshore fields through two crude oil pipelines and indirectly linked through an NGL/condensate pipeline from the crude oil terminal at Sture and the gas terminal at Kollsnes, making Mongstad an attractive site for landing and processing hydrocarbons and for further development of our oil and gas reserves. The main facilities at Mongstad, in addition to the refinery, are a crude oil terminal, owned 65 per cent by Statoil and an NGL terminal, owned by Vestprosess, in which Statoil has an ownership share of 17 per cent.

Effective January 1, 2000, we swapped 21 per cent of our holding in Mongstad with Shell for a 10 per cent interest in its refinery capacity at Pernis in the Netherlands. As a result of this transaction, we have access to products in Rotterdam, and Shell is able to supply the Norwegian market. In addition, we have a service agreement with Shell Global Solutions, Shell's subsidiary, which provides technical operational support, project development support and general technical advice for Mongstad. Through this agreement, we can access support from a world-leading refiner.

The Mongstad refinery, built in 1975 and significantly expanded and upgraded in the late 1980s, is a medium-sized, modern and sophisticated refinery. The products are principally high value light products such as naphtha, gasoline, jet fuel, diesel and light heating oil. The refinery does not produce low value residue because this crude oil component is upgraded to gasoline and gasoils in the residue cracker and the delayed coker. More recent upgrading projects include an NGL/condensate project involving a pipeline to Mongstad plus NGL terminal and refinery expansion and revamp at Mongstad and a cracker naphtha desulphurization project that started production in March 2003. In 2004 the NGL/condensate plant (Vestprosess) capacity was doubled and more efficient stream boilers were installed. Tie-ins and modifications were completed during the 2004 maintenance shutdown.

Approximately 40 per cent of Mongstad's total production is delivered to the Scandinavian markets and 60 per cent is exported to northwest Europe and the United States. Although the transportation costs are higher than those of refineries located closer to these markets, Mongstad's overall competitive position benefits from its proximity to feedstock supplies, which results in lower transportation costs included in the cost of feedstock.

The following table sets forth approximate quantities of refined products (million tonnes) manufactured by Mongstad for the periods indicated. In addition to crude, as shown below, the Mongstad refinery upgrades large volumes of fuel feedstock (up to one million tonnes per year) and Oseberg NGL and Troll condensate.

Note: Changes in throughput and yields are partly due to maintenance shutdowns. There was a planned maintenance shutdown in the cracker unit in 2002 and in the rest of the refinery in 2004. The cracker unit also had to shut down during the 2004 turnaround due to work on the utility systems.

The Mongstad refinery is geared for efficient production of commodity fuels and has considerable flexibility in producing products to different specifications through its ability to do in-line blending during ship loading. Given stricter EU and US product specifications expected to be implemented in 2005, we decided to invest significantly in improvements at Mongstad. The costs incurred in bringing the facilities up to the 2005 requirements were approximately NOK 1 billion. This work was completed in 2004. We are currently assessing whether a new diesel desulphurization project will be required in order to meet expected future requirements.

We have a cost improvement program in place, which focuses on maintenance, procurement and cost management. We are also identifying measures in order to improve energy efficiency. The refinery reliability in 2003 was the highest ever, since it was upgraded in the 1980s. The 2004 reliability was lower than the 2003 level, mainly due to three unplanned maintenance shutdowns, one of which was caused by a fire.

Kalundborg. Kalundborg produces products such as gasoline, jet fuel, diesel oil, propane, and fuel oil to supply markets in Denmark and Sweden. The refinery is connected through a pipeline to our terminal at Hedehusene close to Copenhagen. Kalundborg's refined products are also supplied to the northwest European market, mainly Germany and France.

The following table gives approximate quantities of refined products (in million tonnes) manufactured by Kalundborg for the periods indicated.

Note: Changes in throughput and yields are partly due to maintenance shutdowns and expansions. A maintenance shutdown occurred in the old part of the refinery in 2002. There were also some longer, unplanned shutdowns during 2002. In 2003 there was a longer shutdown in September/October in the crude unit due to consequential damages after power failure in Sweden and Denmark late September. In 2004 there were unplanned maintenance shutdowns and a planned shutdown to complete the diesel/jet project.

Although it is a relatively small and simple refinery, Kalundborg is a plant with high-energy efficiency and relatively low cash operating costs for a plant of its size and configuration. The refinery has improved its performance significantly in the last years through several small investment projects to increase flexibility and improve yield/product quality. It produces high quality products including low sulphur gasoline in accordance with EU specifications. In addition, we invested a total of NOK 400 million in 2001 and 2002 to upgrade the refinery in order to increase our feedstock flexibility and to enable us to produce refined products that meet the EU requirements for low sulphur diesel expected to become effective in 2005. The new unit started production in June 2002. In 2004 we increased the capacity for low sulphur diesel and jet fuel, with start-up in December 2004, 5 months ahead of plan.

Tjeldbergodden. Our methanol operations at Tjeldbergodden, Norway, of which we own 81.7 per cent, has a maximum proven capacity of 0.95 mmtpa and actual output during 2004 was 0.85 mmtpa compared with 0.81 mmtpa in 2002, both turnaround years. The output in 2003 was 0.92 mmtpa. The increase in production compared with 2002 is partly due to high plant reliability (97.5 per cent) and capacity utilization (106.2 tonnes per hour) in 2004. Actual output in 2004 equaled approximately 14 per cent of Western European consumption.

We also hold 50.9 per cent of Tjeldbergodden Luftgassfabrikk DA, the largest Air Separation Unit (ASU) in Scandinavia, which also owns the first Norwegian natural gas liquefaction plant located at Tjeldbergodden with an annual gas (methane) capacity of 36 mmcm (1.3 bcf). Our partners are AGA (37.8 per cent) and ConocoPhillips (11.3 per cent). The ASU supplies oxygen to the methanol plant and AGA markets and sells industrial gases produced.

Nordic Energy

Our Nordic Energy unit, with approximately 1,300 employees, consists of three national sales organizations for refined products to consumer and industrial markets in Scandinavia. Nordic Energy sells Statoil-branded refined products for heating, such as fuel oil, LPG, wood pellets, transportation fuel, such as diesel, jet fuel, marine fuel and lubricants. We also have operations for lubricants and LPG in Poland and the Baltic States. In addition, we manage the logistics of petrol delivery for Statoil-branded service stations in Scandinavia. We have a strong market position in Scandinavia based on our approximately 350,000 customers and annual sales of six billion liters. In the LPG market, we have approximately 40 per cent of the Scandinavian market share. Our portfolio also includes ownership interests in gas distribution companies. We are a significant provider of wood pellets in Scandinavia with a production capacity of 200,000 tonnes.

Nordic Energy has significantly improved profitability in the last 4 years, after a period of low heating oil demand and reduced margins in the late 1990's. This has been the result of a renewed focus on business areas where we can utilize Statoil's resources and brand name, and improved cost efficiency in our existing business. We are continuously evaluating opportunities to expand our energy product offerings, to be able to meet the needs of customers for flexible and sustainable energy products and solutions.

In March 2003 we announced that we had entered into a joint venture with Naturgas Fyn of Denmark. We now own 30 per cent of the joint venture, named Statoil Gazelle, and have an option to increase our share. Statoil Gazelle is now the second largest provider of natural gas in the Danish market.

Retailing

Our retail distribution network consists of almost 2,000 Statoil-branded service stations in nine countries. We are market leaders in Norway, Sweden, Ireland, Latvia and Estonia. The full service stations provide automotive fuels, car accessories and simple vehicle service, and nearly all offer goods as well as fast food, convenience products and basic groceries. In 2004, these stations sold approximately 5.8 billion liters of gasoline and diesel.

The following table lists these retail outlets by region or country as of December 31, 2004, and our volume of automotive fuel sales for the year ended December 31, 2004.

Scandinavia is our home retail market, where Statoil-branded stations have a gasoline market share of approximately 23 per cent, according to data from the petroleum institutes in each country. On July 8, 2004 we purchased the 50 per cent of Statoil Detaljhandel Skandinavia AS (SDS), operating 1,400 stations in Scandinavia, which was previously owned by ICA/Ahold. The company is now 100 per cent owned by Statoil. The internal retail unit has been reorganized, integrating all of our retail operations in nine countries under unified management with the objective of optimizing the contribution from Retail and identifying synergies both within the Retail Group and the rest of Statoil. Statoil will continue to maintain a relationship with ICA/Ahold for the provision of products and services for the shops in Scandinavia through June 2006. We have also entered into a contract that grants Statoil the right to use the ICA Express brand for two years, until June 2006.

The Retail result in 2004 has been severely affected by strong price pressure on fuel particularly in Denmark and Ireland. Petrol market share in Scandinavia has improved from 22.1 per cent in 2003 to 22.9 per cent in 2004, partly thanks to further investments in an Automated Petrol Chain, branded 1-2-3. On December 31, 2004, we had 176 1-2-3 stations in Scandinavia. We are continuing to roll out convenience stores, which aim to meet a wider range of customer needs, in particular on fast food, than the more limited convenience supplies offered at other service stations. There were 495 convenience stores as of December 31, 2004, compared with 414 at December 31, 2003.

Statoil's other service stations are located in Ireland, Poland, Russia and the Baltics, which includes Estonia, Lithuania and Latvia. We rank as a market leader, measured by fuel volumes sold, in Ireland, Estonia and Latvia with approximately 20 per cent, 30 per cent and 22 per cent, respectively, of the retail gasoline market in 2004. As of December 31, 2004, 65 of the Irish stations included our Fareplay concept stores. We have introduced automated, unmanned stations under the name 1-2-3 in the Baltics. As of December 31, 2004, we have 13 automated stations in the Baltics. In Poland we have a market share of 5 per cent, but we believe that Poland has significant growth potential.

We are focusing on increasing profitability and earnings in our existing network by maintaining market leadership in petrol, increasing non-fuel sales, lowering costs and using customer loyalty schemes in all countries.

Borealis

Borealis was established in 1994 by merging our petrochemical operations with those of the Finnish company, Neste. We own 50 per cent of Borealis, with the remaining interests held equally by our partners OMV, the Austrian oil and gas company, and the International Petroleum Investment Company (IPIC), Abu Dhabi's national company for foreign investment in the petroleum business. At December 31, 2004, Borealis had 4,500 employees and operations in 10 countries. In 2004, Borealis's gross sales were EUR 4.6 billion (NOK 38 billion), in 2003 EUR 3.7 billion (NOK 29 billion at the exchange rate as of the end of the period), and in 2002 EUR 3.5 billion (NOK 26 billion at the exchange rate as of the end of the period).

Borealis is a stand-alone company, managed independently by its own supervisory board, executive board and management. It conducts all of its business with Statoil on a commercial, arm's-length basis.

The following table shows Borealis's total annual production volumes (in million tonnes) for major products for 2002, 2003 and 2004.

Borealis's production capacity for 2004 was 1.5 million tonnes of ethylene, 1.1 million tonnes of propylene, 2.2 million tonnes of polyethylene and 1.4 million tonnes of polypropylene. In addition Borealis has 0.3 million tonnes of production capacity of compounded products, which is a further processing of polyolefins. Borealis has five main production areas in Norway, Sweden, Finland, Belgium and Austria, and additional production facilities in Germany, Italy, Brazil and the US. Borealis' production facilities in Portugal were sold in November 2004.

In Abu Dhabi, Borealis and the Abu Dhabi National Oil Company, ADNOC, have established a joint venture, Borouge, which includes an ethylene plant and two polyethylene facilities. The polyethylene plants are based on Borealis' proprietary Borstar technology. Borouge benefits from locally-sourced, lower cost feedstock. All three facilities started production at the end of 2001, and in 2003 it was decided to expand the polyethylene capacity by 30 per cent. The expansion capacity is expected to come into effect during the second quarter of 2005.

Statoil and Borealis collaborate to exploit feedstock opportunities based on geographical proximity to gas extraction facilities in which we hold interests. In 2003 an expansion of the ethane supply agreement at Kårstø was agreed, allowing for increased deliveries beginning in 2005 to support expansion of Borealis' 50 per cent owned olefin plant in Norway. The increase in supply to Borealis will be approximately 40-45 per cent, starting during the fourth quarter of 2005. Statoil and Borealis are currently evaluating further possible feedstock supply options.

On March 3, 2005 Statoil entered into a 10-year agreement with Borealis for the sale of LPG from the Snøhvit field. Start-up of the deliveries will be when the Snøhvit field starts production, scheduled for October 2006. Expected volume will be approximately 150,000 tonnes per year. The LPG will be used by Borealis as feedstock in their 50 per cent owned olefin plant (Noretyl) at Rafnes, Norway, which is now undergoing an expansion project.

Health, Safety and Environment

Our operations are subject to a number of environmental laws and regulations in each of the jurisdictions in which we operate, governing, among other things, air emissions, wastewater discharges and discharges to the sea, the use, handling and disposal of hazardous substances and wastes, soil and groundwater contamination and employee health and safety. As with our competitors, liability risks are inherent in our operations. Requirements under environmental laws and regulations can be expected to increase in the future. We also have long-term obligations concerning the decommissioning of operational facilities and the remediation of soil or groundwater at certain of our facilities and liability for waste disposal or contamination on properties owned by others. We have established financial reserves for estimated environmental liabilities based on our current information with respect to those liabilities. We have also made significant expenditures to comply with environmental regulations. However, significant additional financial reserves or compliance expenditures could be required in the future due to changes in law, new information on environmental conditions or other events, and those expenditures could have a material adverse effect on our financial condition or results of operations.

Health, safety and the environment, or HSE, comprises health and working environment, safety and emergency preparedness, the environment and security. Statoil's management system for HSE forms an integrated part of the group's total management system. Statoil's management system relating to corporate governance is certified to the international ISO 9001 standard. In addition, all central operating units (with exception of Kalundborg refinery which will be ready by mid-2005) are during 2004 certified according to the same standard, and also to the environmental standard ISO 14001 (an updated list is available at www.statoil.com). Statoil is listed in the Dow Jones sustainability index (DJSI) and the FTSE4Good Index. In August 2004, Statoil was ranked as the world's best energy company in terms of sustainability by the Dow Jones Sustainability World Index (DJSI World). Statoil has been part of the Dow Jones Sustainability Index (top 10 per cent in each sector in terms of sustainability) for three years. In previous years Statoil has been ranked fifth (2003) and third (2004).

Our approach to HSE is risk-based, which means that risks are identified, appropriate criteria are established and measures are implemented in order to meet these criteria. We aim to carry out our operations without harm to the environment and according to the principles for sustainable development.

Our corporate indicators for environmental performance include:

The EU Directive on Sulphur (99/32/EC) is intended to reduce emissions of sulphur dioxide resulting from the combustion of certain types of liquid fuels (heavy fuel oil and heating oil). The EU member states must ensure that the use of heavy fuel and gas oil falls below specific levels of sulphur content within their territory. Lower levels of sulphur content than stipulated in the Directive for heavy fuel and gas oil may be imposed by the EU member states separately.

The EU is also imposing stricter requirements for automotive fuels. The Fuels Directive 98/70/EC specifies a set of emissions reducing parameters in gasoline and auto diesel (olefins, aromatics, benzene etc.), to limit air pollution from road traffic. The Fuels Directive became effective January 1, 2000. The Directive is specifically stricter than the previous regulatory regime with respect to sulphur, and the limit has been set to a maximum of 50 ppm in both gasoline and automotive diesel, but products with less then 10 ppm should also be available from 2005. Beginning in 2009 the maximum emissions limit allowed under the Directive will be 10 ppm. Although Norway is not an EU member, as a result of Norway's participation in the EEA and our sales of products to EU member states, our business activities are subject to this Directive. For more information, see Regulation-EU Regulation below. We have made the required investments at our two refineries during the last years to meet the new stricter EU regulations on product quality specifications. Statoil will deliver products with a maximum of 10 ppm from January 1, 2005, and intends to fulfill the EU requirements that will become effective in 2009.

Our CO₂ emissions (from Statoil operations) totaled 9.8 million tonnes in 2004 compared to 10.0 million tonnes emitted in 2003. Our NOx emissions were 31,100 tonnes in 2004, against 29,800 tonnes in 2003. Historically, our NCS emissions of CO₂ and NOx, measured in tonnes per delivered quantity, have been below the NCS average. Compared to other oil regions in the world the NCS is the area with the lowest relative emissions, with an average of 6.9 kg CO₂/boe compared to an industry average of 14.6 kg CO₂/boe produced. Changes in laws regulating greenhouse gas emissions could cause us to incur additional expenditures for pollution control equipment.

Emissions trading is the trading between companies of CO₂allowances with the intention of reducing emissions cost effectively. Installations with low emissions will sell allowances to installations with high emissions costs. A new Norwegian law introducing emissions trading was approved in the Parliament in 2004. In addition an EU Directive will be applicable from 2005. Three Statoil operated installations in Norway and Denmark are exposed to the regulations and will have obligations to provide CO₂allowances according to emissions from 2005.Statoil has established an emissions trading function in 2004 and is prepared to handle this exposure.

Our industry is working closely with the Norwegian authorities with the goal of preventing harmful discharges to the sea caused by operations by 2005. Plans for meeting this ambition were submitted to the authorities in June 2003, committing to implementation of measures leading to a planned reduction of 80 per cent in environmental risk by 2005. This target has been met during 2004.

The total number of unintentional oil spills in the Statoil group in 2004 amounts to 487 with a corresponding volume of 186 cubic meters. For 2003 the corresponding numbers were 542 spills and 288 cubic meters for the group.

Our corporate indicators within safety are currently:

Three fatalities were suffered by contractors working for Statoil in 2004. The number of serious incidents (undesirable events of a very serious nature) in 2004 was 340, up from 299 in 2003. However, the serious incident frequency (the number of incidents per million working hours) was 3.2, the same as 2003. The total recordable injury frequency (the number of injuries per million working hours) is 5.9 in 2004, which is a decrease from 6.0 in 2003. The lost-time injury frequency (the number of total recordable injuries causing loss of time at work per million working hours) was 2.3 in 2004 against 2.6 in 2003. Our safety indicators include both Statoil employees and contractors working for Statoil.

Through the technical safety review project, completed in 2001, where all major Statoil-operated plants and facilities were reviewed, Statoil has been a leader in developing a systematic approach to reviewing and monitoring the condition of technical safety barriers. The developed methodology is in compliance with the latest regulations issued by the Petroleum Safety Authority Norway. The systematic review will continue on a regular basis such that no review will be older than five years.

Within the health and working environment area, our principal objective is to secure a sound, challenging and rewarding working environment for the benefit of both the employee and Statoil. The corporate indicator within the health and working environment is the percentage of sickness absences, which, for the Statoil group, came to 3.2 per cent in 2004, against 3.5 per cent in 2003 (including self certification and medical certificate of sickness). The general level in Norway averaged 7.3 per cent according to official statistics for the first three quarters of 2004. We also carry out regular health and working environment and organization surveys to track our working environment.

No penalties were incurred in 2004 for violations within the HSE area. A penalty of NOK 1.0 million was imposed in January 2004 for an environmental offence that occurred in 2000.

Technology, Research and Development

Background

The success of our business is closely related to our access to and application of advanced technological expertise, largely developed through exploration and production activities on the NCS. Many major challenges have been overcome, not least operating under the harsh weather and environmentally sensitive conditions in the Norwegian Sea, transporting oil and gas across the deep Norwegian trench, and draining complex petroleum reservoirs with high pressures and high temperatures.

The greater majority of Statoil's technology needs are met by the newly established T&P business unit, which incorporates the former Technology unit. In addition to taking on the responsibility for the execution of new, complex development projects from the date of provisional sanction through to production start-up, T&P undertakes R&D and specialist technical services to the business segments. As the development projects are covered in this report under the business segments responsible for their operation, this section will concentrate on Statoil's latest R&D achievements.

The department within the T&P unit responsible for research and development is primarily based at the group's research center in Trondheim, although some of its activities are also carried out in Stavanger and at K-lab (Statoil's Gas Metering and Technology Laboratory at Kårstø). The unit's explicit objectives are to carry out R&D projects tailored to prioritized business needs and help realize long-term business opportunities and sustainable development. Implicit objectives are to contribute to Statoil's profitability, help promote the company as an environmentally responsible player and further its image as a leading exponent of new technology.

Corporate R&D expenditure amounted to NOK 736 million in 2002, NOK 1,004 million in 2003 and NOK 1,027 million in 2004. R&D expenditures are partly financed by partners of Statoil-operated activities. When these figures are expressed as a percentage of annual production volumes, Statoil emerges as a leading R&D investor in the petroleum industry. However, in absolute terms our annual R&D expenditures are significantly less than several of the major oil and gas companies with whom we are competing. Even so, we are widely recognized by the industry as a 'technology company' that continues to deliver innovative solutions.

To further improve our competitiveness, we have recently revised our technology strategy (2003) and developed a more explicit technology cooperation model. In contrast to the traditional single source approach, the model focuses on extended cooperation between Statoil researchers and the best external sources, be they academia, the supplier industry or other oil companies. Our patent portfolio reflects the range of our technological innovations, and we actively manage our portfolio to ensure that our proprietary technology is protected.

Our investment in knowledge, technology and expertise is to support Statoil's short- and long-term business development plans. Brief descriptions of our positions and some of our more recent attainments are given below.

Health, Safety and the Environment. Our overarching ambition is to contribute knowledge and technology to meet Statoil's HSE goals of zero accidents or losses and no harm to people or the environment. Our environmental research is focused on: gaining more knowledge about the impact of our activities and products on the natural environment; developing risk assessment tools; developing technology to reduce the risk of environmental harm; developing clean automotive fuel; and providing energy-efficient alternatives.

Significant achievements have already been made in offshore produced water management, where Statoil is a front runner in assessing the potential environmental effects of discharging produced water over the Norwegian continental shelf. Operators are provided with the latest knowledge, tools and procedures for selecting the best and most cost-effective ways of eliminating potential harm. We have also gained international recognition in the area of carbon dioxide capture and storage.

Some recent advances include:

Reservoir management. Statoil has gained a good reputation in improved oil recovery by merging its capabilities in geological reservoir characterization, reservoir simulation and modeling, time-lapse seismic (4D), recovery processes, and drilling and well production technology. Two ongoing flagship projects will contribute towards Statoil achieving its ambition of an average recovery factor of up to 70 per cent for platform based fields in decline and up to 55 per cent for its subsea fields.

Some recent highlights are as follows:

Offshore technology. Statoil has considerable experience with platform-based production systems and is one of the world's largest, innovative subsea field operators (e.g. Åsgard). We are also regarded as one of the leading exponents in flow assurance (e.g. Åsgard and Snøhvit) and are making significant progress in separation technology.

Examples of recent advances are as follows:

Gas chain development. This embraces gas technologies such as pipeline-based gas solutions, LNG, GTL and methanol.

Recent achievements include:

Future technology

Statoil's technology strategy is designed to help meet corporate business targets. Our technology ambitions are:

Statoil is focusing on the following technical areas in pursuit of these ambitious goals:

o  Floating LNG and larger LNG trains

o  GTL

o  Pipeline-based gas transport

Regulation

Introduction

The principal Norwegian legislation applying to petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of November 29, 1996, and a number of regulations promulgated thereunder, as well as the Petroleum Taxation Act of June 13, 1975. The Petroleum Act states the principle that the Norwegian State is the owner of all subsea petroleum on the NCS, that the exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is authorized to award licenses concerning the petroleum activities.

Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible for resource management and for administering petroleum activities on the NCS. The main task of the Ministry of Petroleum and Energy is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Storting, and relevant decisions of the Norwegian State. The Ministry of Petroleum and Energy primarily implements petroleum policy through its power to administer the award of licenses and approve operators' field and pipeline development plans, as well as petroleum transport and gas sales contracts. Only those plans that conform to the policies and regulations set by the Storting are approved. As set forth in the Petroleum Act, if a plan involves an important principle or will have a significant economic or social impact, it must also be submitted to the Storting for acceptance before being approved by the Ministry of Petroleum and Energy.

We are not required to submit any decisions relating to our operations to the Storting. However, the Storting's role with respect to major policy issues in the petroleum sector may affect us in two ways: first, when the Norwegian State acts in the capacity as the majority owner of our shares and second, when the Norwegian State acts in its capacity as regulator:

Although Norway is not a member of the European Union, or EU, it is a member of the European Free Trade Association (EFTA). The EU and its member states have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, with the members of EFTA (except Switzerland).

The EEA Agreement makes certain provisions of EU law binding as between the states of the EU and the EFTA states, and also as between the EFTA states themselves. An increasing volume of regulation affecting us is adopted within the EU and is then applied to Norway under the EEA Agreement. As a Norwegian company operating both within EFTA and the EU, our business activities are regulated by both EU law and EEA law to the extent that EU law has been accepted into EEA law under the EEA Agreement.

The Norwegian Licensing System

The most important type of license awarded under the Petroleum Act is the production license. The Ministry of Petroleum and Energy holds executive discretionary power to award a production license and to determine the terms of that license. In exercising this power, the Ministry of Petroleum and Energy is obliged to implement the policy and objectives of the relevant Storting reports. The Government is not entitled to award a license in an area until the Storting has decided to open the area in question for exploration. A company refusing to abide by the terms of the Ministry of Petroleum and Energy's decision, the Petroleum Act or the license conditions may face severe consequences, including a refusal by the Ministry of Petroleum and Energy to grant a production license or the revocation of a license already granted.

A production license grants the holders an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the license. Notwithstanding the exclusive rights granted under a production license, the Ministry of Petroleum and Energy has the power to, in exceptional cases, permit third parties to carry out exploration in the area covered by a production license. For a list of our shares in production licenses, see - -Business Overview-Operations-Exploration and Production Norway above.

Production licenses are normally awarded through licensing rounds. The first licensing round for NCS production licenses was announced in 1965. Licenses under the 17th licensing round were awarded in May 2002. In recent years, the principal licensing rounds have mainly included licenses in the Norwegian Sea. Licenses in the North Sea area have been awarded in separate yearly rounds. The Ministry of Petroleum and Energy has announced that this policy will continue in a report to the Storting.

Traditionally, the Norwegian State only accepted license applications from individual companies, and, therefore, companies were not able to choose their partners in an individual block. In recent years, however, the Norwegian State has, to a larger degree, permitted group applications, enabling us to choose our exploration and development partners.

Production licenses are awarded to joint ventures consisting of several companies. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the license. Once a production license is awarded, the licensees are required to enter into a joint operating agreement and an accounting agreement which regulate the relationship between the partners. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.

The governing body of the joint venture is the management committee. Each member is entitled to one seat on the management committee. The management committee's tasks are set out in the joint operating agreement and include setting guidelines for the operator of the field, exercising control over the activities of the operator, and making decisions on the activities of the joint venture. Votes in the management committee are counted by a combination of the number of members in the joint venture and their ownership interest. The number of votes required to make a decision varies from license to license, but a decision is normally reached when a certain number of the members and a percentage of the ownership interests, specified individually in each license, have voted in favor of a proposal. The voting rules are structured so that a licensee holding more than 50 per cent of a license normally cannot vote through a proposal on its own, but will need the support of one or more of the other licensees. In licenses awarded since 1996 where the SDFI holds an interest, the Norwegian State, acting through the SDFI management company, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the license as to the Norwegian State's exploitation policies or financial interests. This veto right has never been used.

Under the joint operating agreements covering licenses awarded prior to 1996, the management company that supervises the Norwegian State's SDFI interest, Petoro AS, has the power, with certain exceptions, to make decisions unilaterally in matters which are assumed to be of political or principal importance, or which may have significant social or socio-economic consequences, if Petoro AS is acting under the direction of its shareholder. Prior to the establishment of the SDFI management company, Statoil held this right, which was exercised three times, most recently in 1988. In autumn 2002, the Storting approved that the individual license groups may substitute this special voting rule for the SDFI with a veto rule similar to the veto rules which have applied to licenses awarded since 1996. Such a substitution is subject to approval from the Ministry of Petroleum and Energy.

The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. The operator is in practice always a member of the joint venture holding the production license, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement. Under the joint operating agreement, an operator may normally terminate its engagement upon six months' notice. The management committee may, however, with the consent of the Ministry of Petroleum and Energy, instruct the operator to continue performing its duties until a new operator has been appointed. The management committee can terminate the operator's engagement upon six months' notice on an affirmative vote by all members of the management committee other than the operator. A change of operator requires the consent of the Ministry of Petroleum and Energy. In special cases the Ministry of Petroleum and Energy can order a change of operator.

Licensees are required to submit a plan for development and operation, or PDO, to the Ministry of Petroleum and Energy for approval. In respect of fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Until the PDO has been approved by the Ministry of Petroleum and Energy, the licensees cannot, without the prior consent of the Ministry of Petroleum and Energy, undertake material contractual obligations or commence construction work.

Production licenses are normally awarded for an initial exploration period which is typically six years, but which can be either for a shorter period or for a maximum period 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 set out in the production license, they are entitled to require that the license be prolonged for a period specified at the time when the license is awarded, typically 30 years. The right to prolong the license does not apply as a main rule to the whole of the geographical area covered by the initial license, but only to a percentage, typically 50 per cent. The size of the area which must be relinquished is determined at the time the license is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production license.

If natural resources other than petroleum are discovered in the area covered by a production license, the Norwegian State may decide to delay petroleum production in the area. If such a delay is imposed, the licensees are, with certain exceptions, entitled to a corresponding extension of the period of the license. To date, such a delay has never been imposed.

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

Licensees may buy or sell interests in production licenses subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of interest in a license, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. There are in most licenses no pre-emption rights in favor of the other licensees. The SDFI, or the Norwegian State, as appropriate, however, still holds pre-emption rights in all licenses.

A license from the Ministry of Petroleum and Energy is also required in order to establish facilities for transport and utilization of petroleum. When applying for such licenses, the owners, which are in practice licensees under a production license, must prepare a plan for installation and operation. Licenses to establish facilities for transport and utilization of petroleum will normally be awarded subject to certain conditions. Typically, these conditions require the facility owners to enter into a participants'agreement. The ownership of most facilities for transport and utilization of petroleum in Norway and on the NCS are organized as a 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 joint ventures 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 of Petroleum and Energy no sooner than five and no later than two years prior to the expiry of the license or the cessation of the use of the facility, and must include a proposal for the disposal of facilities on the field. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.

The Norwegian State is entitled to take over the fixed facilities of the licensees when a production license expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with expropriation of private property apply.

Licenses for the establishment of facilities for transport and utilization of petroleum typically include a clause whereby the Norwegian State can require that the facilities be transferred to it free of charge at the expiration of the license period.

The Norwegian Gas Sales Organization

Until recently, 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 or GFU.

The structural changes taking place in the European gas market prompted the Norwegian State to consider whether changes to the gas resource management system on the NCS could contribute to further enhancing the efficiency for Norwegian gas producers. Accordingly, the Norwegian State by royal decree dated June 1, 2001, abandoned the GFU system and put in place a system whereby the individual licensees can manage the disposal of their own gas. Necessary adjustments in legislation, license agreements and other existing contracts in order to implement the new system were finalized during 2002. For more information, see above under -Business Overview-Operations-Gas Sales Agreements.

From January 1, 2003 the ownership of the Zeepipe, Franpipe, Europipe II, Åsgard Transport, Statpipe, Oseberg Gas Transport and Vesterled joint ventures and Norpipe AS was transferred to a new joint venture called Gassled. As from February 1, 2004, the Kollsnes Plant has also been included in Gassled.

Together with the approval of Gassled, Norwegian authorities have by a royal decree of December 20, 2002 issued regulations for access to and tariffs for capacity in the upstream gas transportation system. There are three main considerations behind the regulations. Firstly it shall, together with the law adopted by the Storting in June 2002, implement the Gas Directive of the European Union. Further, it shall establish a system for access to the upstream gas transportation system that is compatible with company based gas sales from the Norwegian Continental Shelf. Thirdly, it provided for the new ownership structure of the upstream gas transportation system (Gassled).

Parts of the regulations have a general application and parts - including the tariffs - are applicable only to the upstream gas transportation system owned by the Gassled joint venture.

The new regulations set the main principles for access to the upstream gas transportation system. The access regime consists of a regulated primary market where the right to book free capacity, in accordance with regulations, is allocated to users with a duly substantiated reasonable need for transportation of natural gas. Further, the access regime consists of a secondary market where the capacity can be transferred between the users after the allocation in the primary market if the need for transportation changes.

The capacity in the primary market will be released and booked through Gassco AS on the internet. Spare capacity will be released for pre-defined time periods at announced points in time and with specific time limits for reservations. If the reservations exceed the spare capacity, the spare capacity will be allocated based on a distribution formula. However, consideration shall in case of spare capacity first be given to the owners'duly substantiated needs for capacity, which is limited to twice the owner's equity interest in the upstream pipeline network in question.

Based upon an authorization given under the new regulation, tariffs for use of capacity in Gassled are determined by the Ministry of Petroleum and Energy. The Ministry's policy for determining the tariffs is to avoid excessive returns being created on the capital invested in the transportation system, allowing the return on the Norwegian petroleum activity to be taken out on the fields instead of in the transportation systems. The tariffs are to be paid for booked capacity and not in respect of the actually transported volume.

HSE Regulation

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

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

The new Petroleum Safety Authority Norway (PSA) was established on January 1, 2004 as a consequence of the Storting process surrounding the Storting White Paper No.17 (2002-2003) on State supervision bodies. The PSA has the regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. This responsibility was transferred from the Norwegian Petroleum Directorate (NPD) effective January 1, 2004. With the establishment of the PSA, regulations relating to HSE in petroleum activities continue with the PSA as the responsible authority. In addition, the PSA's sphere of responsibility has been expanded to include supervision of safety, emergency preparedness and the working environment at the petroleum facilities and connected pipeline systems on land such as Kårstø, Kollsnes, Tjeldbergodden, Mongstad, and Melkøya, as well as potential future integrated petroleum facilities.

In our capacity as a holder of licenses under the Petroleum Act, we are 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 our licenses. This means that anyone who suffers losses or damages as a result of pollution caused by any of our NCS license areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our 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.

Taxation of Statoil

We are subject to ordinary Norwegian corporate income tax as well as to a special petroleum tax relating to our offshore activities. We are also subject to a special carbon dioxide emissions tax. Under our production licenses we are obligated to pay royalties and an area fee to the Norwegian State. Set forth below is a summary of certain key aspects of the Norwegian tax rules that apply to our operations.

Corporate income tax. Our profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. The corporate income tax rate is currently 28 per cent. Our profits are computed in accordance with ordinary Norwegian corporate income tax rules, subject to certain modifications that apply to companies engaged in petroleum operations. Gross revenue from oil production and the value of lifted stocks of oil are determined on the basis of norm prices which are decided on a monthly basis by the Petroleum Price Board, a body whose members are appointed by the Ministry of Petroleum and Energy, and published quarterly. The Petroleum Taxation Act provides that the norm prices shall correspond to the prices that could have been obtained in case of a sale of petroleum between independent parties in a free market. When adopting norm prices, the Petroleum Price Board takes into consideration a number of factors, including spot market prices and contract prices within the industry.

The maximum rate for depreciation of development costs related to offshore production installations and pipelines is 16 2/3 per cent per year. The depreciation starts when the expense is incurred. Exploration costs may be deducted in the year in which they are incurred. Most financial items are allocated to onshore and offshore activities in proportion to the remaining tax balances of assets related to onshore and offshore activities, respectively. There is an adjustment factor allowing companies with an equity ratio of more than 0.2 to allocate a higher share of net financial items to the offshore tax regime.

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

By use of group contributions between Norwegian companies in which we hold more than 90 per cent of the shares and the votes, tax losses and taxable income can, to a great extent, be offset. Group distributions are not deductible in our offshore income.

From January 1, 2004, dividends received are not subject to tax in Norway. Exemptions exist for dividends from low-tax countries or portfolio investments outside the EEA. Further information on the one off accounting effects as a result of this change can be found in Item 5-Operating and Financial Review and Prospects-Operating Results-Combined Results of Operations-Income taxes.

From March 26, 2004, capital gains on realization of shares will not be taxable and losses will not be deductible. Exemptions exist for shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA. A transitional rule for 2004 exists allowing a deduction for losses incurred in the period March 26 to December 31 against gains obtained in the period January 1 to March 26.

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 per cent. The special tax is applied to relevant income in addition to the standard 28 per cent income tax, resulting in a 78 per cent marginal tax rate on income subject to 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, is granted at a rate of 5 per cent per year. The uplift is computed on the basis of the original capitalized cost of offshore production installations. The uplift may be deducted from taxable income for a period of six years, starting in the year in which the capital expenditures are incurred. From 2005 the uplift will be 7.5 per cent for 4 years. Unused uplift may be carried forward indefinitely. Special provisions apply to investments made prior to 1992.

Abandonment costs. In June 2003 the taxation treatment of abandonment costs was changed from a system with Government grant to a system with tax deduction. Abandonment costs incurred after June 19, 2003 can be deducted as operating expenditures. Provisions for abandonment costs are not tax deductible.

Carbon dioxide emissions tax. A special CO₂ emissions tax applies to petroleum activities on the NCS. The tax is NOK 0.76 in year 2004 and NOK 0.78 in year 2005 per standard cubic meter of gas burned or directly released, and per liter of oil burned.

Area fee. After the expiration of the initial exploration period, the holders of production licenses are required to pay an area fee. The amount of the area fee is set out in regulations promulgated under the Petroleum Act. In respect of most of the production licenses, the initial annual area fee is currently NOK 7,000 per square kilometer. The annual area fee is increased yearly by NOK 7,000 until it reaches NOK 70,000 per square kilometer.

Royalty. We and other oil companies have an obligation to pay a royalty to the Norwegian State for oil produced on fields for which a plan for development and operation was approved prior to January 1, 1986. The royalty varies from 8 per cent to 16 per cent of the gross production value, and increases with the level of production. The Ministry of Petroleum and Energy may, on six months' notice, require that the royalty be paid in kind by delivery of petroleum. The Ministry of Petroleum and Energy has exercised this right so that we are currently required to pay royalty by delivering oil. Such royalty oil is repurchased by us at a calculated market price. No royalty is charged on natural gas or NGL production.

In a 1999 Government proposal, the Norwegian State announced that the remaining royalty obligations would be gradually abolished. The obligation to pay royalty currently only remains for the Gullfaks and Oseberg fields and will be abolished completely by the end of 2005.

EU Regulation

EU Gas Directive

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 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 was included in the EEA Agreement in June 2002 and was incorporated into Norwegian legislation in 2002.

On June 26, 2003, the EU approved a new Gas Directive, Directive 2003/55/EC. The Directive is not yet incorporated into Norwegian legislation.

The new Directive provides for accelerated requirements for market opening, which imply that both large users and households will now be free to choose their supplier earlier than before. Large users are free to choose their supplier from July 2004, and households from July 2007.

Competition

In the oil and gas industry there is intense competition for customers, production licenses, operatorships, capital and experienced human resources. In recent years, the oil and gas industry has experienced consolidation, as well as increased deregulation and integration in strategic markets. Statoil competes with major integrated oil and gas companies, as well as independent and government-owned companies for the acquisition of assets and licenses for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas prices, demand, the cost of exploration and production, global production levels, alternative fuels and governmental and environmental regulations. Statoil's ability to remain competitive will require, among other things, management's continued focus on reducing unit costs and improving efficiency, maintaining long-term growth in our reserves and production through continued technological innovation and our ability to capture international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. The company believes that it is in a position to compete effectively in each of its business segments.

Organizational Structure

The following table sets forth our significant subsidiaries in alphabetical order, equity interest and the subsidiaries'country of incorporation. In all cases our voting interest is equivalent to our equity interest.

(1)The remaining shares are owned by SDS Holding AS

Property, Plants and Equipment

Our principal executive offices are located at Forusbeen 50, N-4035, Stavanger, Norway, and comprise 103,000 square meters of office space, and are owned by Statoil.

We have interests in real estate in numerous countries throughout the world, but no one individual property is significant to us as a whole. We have no significant ongoing construction projects or plans to add new office space. See Item 4-Information on the Company for a description of our significant reserves and sources of oil and natural gas.

Item 5 Operating and Financial Review and Prospects

You should read the following discussion of our financial condition and results of operations in connection with our audited financial statements and relevant notes and the other information contained elsewhere in this Annual Report on Form 20-F.

Operating Results

Overview of Our Results of Operations

In the year ended December 31, 2004, we had total revenues of NOK 306.2 billion and net income of NOK 24.9 billion. In the year ended December 31, 2004, we produced 263 million barrels of oil and 22.1 bcm (782 bcf) of natural gas, resulting in a total production of 402 million boe. Our proved reserves as of December 31, 2004, consisted of approximately 1.7 billion barrels of crude oil and NGL and 408 bcm (14.4 tcf) of natural gas, resulting in a total of approximately 4.3 billion boe.

We divide our operations into the following four business segments:

Portfolio changes. We engage in portfolio management in order to optimize the value of our asset portfolio. This has resulted in the restructuring of our asset portfolio both in Norway and internationally. The list below summarizes important acquisitions and dispositions that have taken place in the past years. For further details see Item 4-Information on the Company-Business Overview under each of the business segment sections.

Factors Affecting Our Results of Operations

Our results of operations substantially depend on:

Our results will also be affected by trends in the international oil industry, including:

The following table shows the yearly average crude oil trading prices, natural gas contract prices and NOK/USD exchange rates for 2002, 2003 and 2004.

(1)  From the Norwegian Continental Shelf.

The following table illustrates how certain changes in the crude oil price, natural gas contract prices, refining margins and the NOK/USD exchange rate may impact our income before financial items, other items, income taxes and minority interest and our net income assuming activity at levels achieved in 2004.

Sensitivities on 2004 results

(1)The US dollar exchange rate impact on financial debt has an opposite effect on net income than the US dollar exchange rate impact on revenues and costs.

The sensitivities on our financial results shown in the table above would differ from those that would actually appear in our consolidated financial statements because our consolidated financial statements would also reflect the effect on proved reserves, and consequently on depreciation, depletion and amortization, trading margins in the Natural Gas and Manufacturing and Marketing business segments, our exploration expenditures, development and exploration success rate, inflation, potential tax system changes, and the effect of any hedging programs in place.

Our oil and gas price hedging activities are designed to assist our long-term strategic development and attainment of targets by protecting financial flexibility and cash flow, allowing the corporation to be able to undertake profitable projects and acquisitions and avoiding forced divestments during periods of adverse market conditions. For the oil price, we entered into a downside protection structure for some of our production, reducing price risk below USD 18 per barrel for 2002 and below USD 16 per barrel for 2003. No such protection was entered into for 2004, but we have entered into downside protection for prices below USD 18 per barrel for some of our production for the last three quarters of 2005. For 2005, approximately 20 per cent of the refining margin has been hedged to reflect our view of the markets.

Fluctuating foreign exchange rates can have a significant impact on our operating results. Our revenues and cash flows are mainly denominated in or driven by US dollars, while our operating expenses and income taxes payable accrue to a large extent in NOK. We seek to manage this currency mismatch by issuing or swapping long-term debt into US dollars. This debt policy is an integrated part of our total risk management program. We are also engaging in foreign currency hedging to cover our non-USD needs, which are primarily in NOK. We manage the risk arising from our interest rate exposures through the use of interest rate derivatives, primarily interest rate swaps, based on a benchmark for the interest reset profile of our long-term debt portfolio. See -Liquidity and Capital Resources-Risk Management and Item 11-Quantitative and Qualitative Disclosures about Market Risk. In general, an increase in the value of the US dollar against the NOK can be expected to increase our reported earnings. However, because currently our debt outstanding is in US dollars, the benefit to Statoil would be offset in the near term by an increase in the value of our debt, which would be recorded as a financial expense and, accordingly, would adversely affect our net income. A decrease in the exchange rate would have an opposite effect, and hence cause decreased earnings, which would be offset by financial income in the near term. See -Liquidity and Capital Resources-Risk Management and Item 11-Quantitative and Qualitative Disclosures about Market Risk.

Statoil markets and sells the Norwegian State's share of oil and natural gas production from the Norwegian Continental Shelf (NCS). Amounts payable to the Norwegian State for these purchases are included as Accounts payable - related parties in the consolidated balance sheets. Pricing of the crude oil is based on market reflective prices. NGL prices are based on either achieved prices, market value or market reflective prices.

Statoil is, in its own name, but for the Norwegian State's account and risk, selling the State's natural gas production. This sale, as well as related expenses refunded by the State, are shown net in Statoil's financial statements. Refunds include expenses incurred related to activities and investments necessary to obtain market access and to optimize the profit from sale of natural gas. For sales of the Norwegian State's natural gas, both to us and to third parties, the payment to the Norwegian State is based on either achieved prices, a net back formula or market value. However, Statoil purchases a small share of the Norwegian State's gas. For further details see item 7-Major shareholders and Related Party Transactions-Major Shareholders-Marketing and Sale of the SDFI's Oil and Gas.

Total purchases of oil and NGL from the Norwegian State by Statoil amounted to NOK 81,487 million (319 mmboe), NOK 68,479 million (336 mmboe), and NOK 72,298 million (374 mmboe), in 2004, 2003 and 2002, respectively. Purchases of natural gas from the Norwegian State amounted to NOK 237 million, NOK 255 million and NOK 119 million in 2004, 2003 and 2002, respectively. See Item 7-Major Shareholders and Related Party Transactions-Major Shareholders-Marketing and Sale of the SDFI's Oil and Gas.

Like all producers on the NCS, we pay a royalty to the Norwegian State for NCS oil produced from fields approved for development prior to January 1, 1986. Oil fields in our portfolio that paid royalty in 2004 are Gullfaks and Oseberg. Statfjord paid royalty until the end of 2002. The fields from which royalty was paid together represented approximately 24 per cent, 16 per cent and 13 per cent of our total NCS production in 2002, 2003 and 2004 respectively. The royalty is paid in kind by delivery of petroleum or purchased at a calculated market price, which varied in 2004 from 2 per cent to 3 per cent of the total oil production from the fields. We include the costs of purchase and the proceeds from the sale of the royalty oil, which we resell or refine, in our Cost of goods sold and Sales revenue, respectively. No royalty is paid from fields approved for development on or after January 1, 1986. Royalty obligations from Gullfaks and Oseberg will be abolished by the end of 2005.

Historically, our revenues have largely been generated from the production of oil and natural gas from the NCS. Norway imposes a 78 per cent marginal tax rate on income from offshore oil and natural gas activities. See Item 4-Information on the Company-Business Overview-Regulation-Taxation of Statoil-Corporate income tax. Our earnings volatility is moderated as a result of the significant amount of our Norwegian offshore income that is subject to a 78 per cent tax rate in profitable periods and the significant tax assets generated by our Norwegian offshore operations in any loss-making periods. A prevailing part of the taxes we pay are paid to the Norwegian State. In June 2001, the Storting (The Norwegian Parliament) enacted certain changes in the taxation of petroleum operations. From January 1, 2004, dividends received are not subject to tax in Norway. Exemptions exist for dividends from low-tax countries or portfolio investments outside the EEA. For details, see Item 4-Information on the Company-Business Overview-Regulation-Taxation of Statoil.

Combined Results of Operations

The following table shows certain income statement data, expressed in each case as a percentage of total revenues.