STATOIL ASA 20-F 2005
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
For the Transaction period from _________ to ____________
Commission File No. 1-15200
(Exact name of registrant as specified in its charter)
(Jurisdiction of incorporation or organization)
Forusbeen 50, N-4035 Stavanger, Norway
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code + 47 51 99 00 00
Securities to be registered pursuant to Section 12(b) of the Exchange Act:
* Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission
Securities to be registered pursuant to Section 12(g) of the Exchange Act: None
Securities for which there is a reporting obligation pursuant to Section 15 (d) of the Exchange Act: None
Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the Annual Report:
Indicate by check mark whether the registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2), has been subject to such filing requirements for the past 90 days. Yes __X___ No ______
Indicate by check mark which statement item the registrant has elected to follow. Item 17 ______Item 18 ___X__
Table of contents
Item 3 Key Information
Item 4 Information on the Company
Item 5 Operating and Financial Review and Prospects
Item 6 Directors, Senior Management and Employees
Item 8 Financial Information
Item 10 Additional Information
Item 19 Exhibits
Terms and Measurements relating to the Oil and Gas Industry
Equivalent measurements are based upon:
- 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
Selected Financial Data
The following tables set forth selected consolidated financial and statistical data of Statoil.
You should read the following data together with Item 5-Operating and Financial Review and Prospects and Item 11-Quantitative and Qualitative Disclosures about Market Risk and our consolidated financial statements, including the notes to those financial statements included in this Annual Report on Form 20-F.
Solely for the convenience of the reader, the financial data at the twelve months ended December 31, 2004 has been translated into US dollars at the rate of NOK 6.0794 to USD 1.00, the noon buying rate on December 31, 2004. The financial data has been derived from our financial statements, which have been prepared in accordance with generally accepted accounting principles in the United States, or US GAAP. The financial, reserve, production and sales information in these tables reflects our acquisition of the Norwegian State's direct financial interest (SDFI) assets in 2001 and was prepared as if the SDFI assets acquired by us had been part of Statoil throughout the financial periods presented. Such information in these tables, however, assumes that our purchase of the SDFI assets was financed with equity and, therefore, does not reflect the impact of the actual financing of the purchase of the SDFI assets. The actual financing, including our transfer of pipeline and other assets, is reflected in the consolidated financial information as from and including the year ended December 31, 2001.
(1)The weighted average number of shares outstanding was 1,975,885,600 up to and including the year 2000, and 2,076,180,942, 2,165,422,239, 2,166,143,693 and 2,166,142,636 in 2001, 2002, 2003 and 2004, respectively.
(2)There is no notional impact on the number of shares resulting from the assumed equity financing of the SDFI transaction.
(3)See Item 8-Financial Information-Dividend Policy and Item 3-Key Information-Dividends below for a description of how dividends are determined.
(1)As calculated according to GAAP. Net debt to capital employed is the net debt divided by capital employed. Net debt is interest-bearing debt less cash and cash equivalents and short-term investments. Capital employed is net debt, shareholders' equity and minority interest.
(2)As adjusted. In order to calculate the net debt to capital employed ratio that our management makes use of internally and which we report to the market, we make adjustments to capital employed as it would be reported under GAAP to adjust for project financing exposure that does not correlate to the underlying exposure (adjustments amount to NOK 2,209 million in 2004, NOK 1,500 million in 2003 and NOK 1,567 million in 2002), and to add into the capital employed measure interest-bearing elements which are classified together with non-interest-bearing elements under GAAP of NOK 1,758 million in 2003 and NOK 2,295 million in 2004. See Item 5-Operating and Financial Review and Prospects-Use and reconciliation of Non-GAAP Financial Measures for a reconciliation of capital employed and a description of why we make use of this measure.
(3)As calculated in accordance with GAAP. After-tax return on average capital employed (ROACE) is equal to net income before minority interest and before after tax net financial items, divided by average capital employed over the last 12 months.
(4)As adjusted. This figure represents ROACE computed on the basis of capital employed, as adjusted as indicated in footnote 2 above. See Item 5-Operating and Financial Review and Prospects-Use and reconciliation of Non-GAAP Financial Measures for a reconciliation of return on average capital employed and a description of why we make use of this measure.
Summary Oil and Gas Production Information
The following table sets forth our Norwegian and international production of crude oil and natural gas for the periods indicated. The stated production volumes are the volumes that Statoil is entitled to in accordance with conditions laid down in concession agreements and production sharing agreements, or PSAs. The production volumes are net of royalty oil paid in kind and of gas used for fuel and flare. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian State's oil and natural gas.
(1) Crude oil includes NGL and condensate production.
Sales Volume Information
We have historically marketed and sold oil and gas owned by the Norwegian State through the Norwegian State's share in production licenses, known as the State's direct financial interest, or SDFI, together with our own production. The Norwegian State has elected to continue this arrangement. For additional information see Item 7-Major Shareholders and Related Party Transactions. The following table sets forth SDFI and Statoil sales volume information for crude oil and natural gas for the periods indicated. The SDFI volumes shown below include royalty oil we sell on behalf of the Norwegian State. The Statoil natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International E&P and ethane volumes.
(1)Sales volumes of crude oil include NGL and condensate.
(2)At a gross calorific value (GCV) of 40 MJ/scm.
(3)Third party volumes include third party LNG volumes related to our activities at the Cove Point regasification terminal in the USA.
(4)The 2003 SDFI volumes have been restated in order to include SDFI LNG volumes related to our activities at the Cove Point regasification terminal in the USA.
The table below shows the high, low, average and period end noon buying rates in The City of New York for cable transfers in foreign currencies as certified for customs purposes by the Federal Reserve Bank of New York for Norwegian kroner per USD 1.00. The average is computed using the noon buying rate on the last business day of each month during the period indicated.
The table below shows the high and low noon buying rates for each month during the six months prior to the date of this Annual Report on Form 20-F.
On March 25, 2005 the noon buying rate for Norwegian kroner was USD 1.00 = NOK 6.3352
Fluctuations in the exchange rate between the Norwegian kroner and the US dollar will affect the US dollar amounts received by holders of American Depositary Shares (ADSs) on conversion of dividends, if any, paid in Norwegian kroner on the ordinary shares and may affect the US dollar price of the ADSs on the New York Stock Exchange.
Dividends in respect of the fiscal year are declared at our annual general meeting in the following year. Under Norwegian law, dividends may only be paid in respect of a financial period as to which audited financial statements have been approved by the annual general meeting of shareholders, and any proposal to pay a dividend must be recommended by the board of directors, accepted by the corporate assembly and approved by the shareholders at a general meeting. The shareholders at the annual general meeting may vote to reduce, but may not increase, the dividend proposed by the board of directors.
Dividends may be paid in cash or in kind and are payable only out of our distributable reserves. The amount of our distributable reserves is defined by the Norwegian Public Limited Companies Act, which requires such reserves to be calculated under Norwegian GAAP and consist of:
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.
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.
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.
Item 4 Information on the Company
Statoil ASA is a public limited company organized under the laws of Norway with its registered office at Forusbeen 50, N-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Our registration number in the Norwegian Register of Business Enterprises is 923 609 016. Statoil ASA was incorporated on September 18, 1972 under the name Den norske stats oljeselskap a.s. At an extraordinary general meeting held on February 27, 2001, it was resolved to change our company name to Statoil ASA and convert into a public listed company, or ASA.
We are an integrated oil and gas company, headquartered in Stavanger, Norway. Based on both production and reserves we are a major international oil and gas company and the largest in Scandinavia. Our proved reserves as of December 31, 2004 consisted of 1,720 mmbbls of oil and 408 bcm (equivalent to 14.4 tcf) of natural gas, which represents an aggregate of 4,289 mmboe. Our operations commenced in 1972 with a primary focus on the exploration, development and production of oil and natural gas from the Norwegian Continental Shelf, or NCS. Since then, we have grown both domestically and internationally into a company with 23,899 employees and business operations in 29 countries as of December 31, 2004.
We review our petroleum reserves routinely in the course of business from time to time as new information becomes available. This information can relate to remaining reserves, existing production performance, decisions related to development, production, acquisition and divestment of reserves and changes in economic conditions. In addition, information on proved oil and gas reserves, standardized measure of discounted net cash flows relating to proved oil and gas reserves, and other information related to proved oil and gas reserves reported in the Supplementary Information on Oil and Gas Producing Activities is collected and checked for consistency and conformity with applicable standards by a central group that is independent of the E&P business units. Although this group reviews the information centrally, each asset is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Before presenting the aggregated results to the responsible management of the relevant business units and the Chief Executive Officer for approval, this central group asks DeGolyer and MacNaughton, independent petroleum engineering consultants, to perform an independent evaluation of proved reserves, which was performed as of December 31, 2004 for our properties. The results obtained by DeGolyer and MacNaughton do not differ materially from those reported by us when compared on the basis of net equivalent barrels of oil. DeGolyer and MacNaughton has delivered to us its summary letter report describing its procedures and conclusions, a copy of which appears as Appendix A hereto. Reserve engineering is a process of forecasting the recovery and sale of oil and gas from a reservoir and is in part subjective. It is clearly associated with considerable uncertainty, often positive, but also negative. The accuracy of any reserve information is a function of the quality of available data and of engineering and requires interpretation and judgment. The requirements of the SEC with respect to the calculation of proved reserves set a standard for estimating reserves, which results in amounts that are reasonably certain technically, and consistent with the economic, regulatory and operating conditions at the time the estimates are made. See Supplementary Information on Oil and Gas Producing Activities beginning on page F-33 for further details of our proved reserves.
We are the leading producer of crude oil and gas on the technologically demanding NCS and are well positioned internationally, having participated in a number of high-quality discoveries outside the NCS. We are the largest supplier of natural gas from the NCS (including sales we make on behalf of the Norwegian State) to the growing Western European gas market. We are one of the market leaders, with a market share of 23 per cent, in the retail gasoline business in Scandinavia. We are one of the largest net sellers of crude oil worldwide, including sales of crude oil purchased from the Norwegian State.
We divide our operations into four formal reporting business segments: Exploration and Production Norway, International Exploration and Production, Natural Gas, and Manufacturing and Marketing. We have established a new business area service unit, Technology and Projects (T&P), in order to develop distinct technology positions and strengthen our project execution. This centralized function will ensure effective project development and execution and will contribute to effective operations. The T&P unit will be responsible for the execution of new development projects from the date of provisional project sanction through to production start-up. In addition, as of January 1, 2005, the T&P unit is responsible for the execution of the following existing projects: Volve, Aldbrough Gas storage and Langeled. Descriptions of these projects are included below according to the business segment that will be responsible for the operation of these projects.
The statements contained in this Item 4 regarding exploration and development projects and production estimates are forward-looking and subject to significant risks and uncertainties. Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot assure you that our actual levels of activity, production or performance will meet these expectations. See Item 3-Key Information-Risk Factors.
The following table sets forth the income before financial items, income taxes and minority interest for each segment for the periods indicated.
The segment information included in this table and throughout this Annual Report on Form 20-F reflects the business segment split as at the date of filing. Prior periods have been adjusted for the transfer of Kollsnes from the E&P Norway business segment to the Natural Gas Business Segment and for other minor reorganizations that have taken place during 2004.
Further details on the financial results can be found in Item 5-Operating and Financial Review and Prospects-Operating Results.
Exploration and Production Norway. E&P Norway includes our exploration, development and production operations on the NCS. Our NCS operations are organized in four core areas, of which three are currently producing hydrocarbons: Troll/Sleipner, Halten-Nordland, Tampen, and one, Tromsøflaket, which is expected to begin production in 2006. We operate 22 developed fields in our three producing core areas. These fields produced a total of 2.6 mmboe per day in 2004, 58 per cent of total NCS daily production. Throughout 2004, our daily equity oil and NGL production was 625 mboe of oil and daily equity gas production was 58 mmcm (2.1 bcf), totaling 991 mboe per day, compared to 661 mbbls of oil and daily equity gas production of 52.5 mmcm (1.9 bcf), totaling 991 mboe per day in 2003. We are also well positioned in three promising but less mature areas: the Møre/Vøring and Lofoten areas of the Norwegian Sea and the Norwegian part of the Barents Sea. As of December 31, 2004, E&P Norway had proved reserves of 1,089 mmbbls of crude oil and 368 bcm (13.0 tcf) of natural gas, which represents an aggregate of 3,401 mmboe. Our experience over the last 30 years in the challenging NCS environment has helped us develop expertise in managing complex, integrated projects. We are continuously seeking to improve our returns through both cost efficiency and portfolio management.
International Exploration and Production. International E&P includes all of our exploration, development and production operations outside Norway. We have established positions in the following main producing areas: Caspian (Azerbaijan), North Africa (Algeria), Venezuela, Western Africa (comprising Angola along with Nigeria, which is not a producing area yet) and Western Europe. As of December 31, 2004, International E&P had proved reserves of 632 mmbbls of crude oil and 40.7 bcm (1.4 tcf) of natural gas, which represents an aggregate of 888 mmboe. In 2004 we produced 100 mbbls of oil and 2.4 mmcm (84 mmcf) of gas per day from our international operations, a total of 114.9 mboe per day, compared to 86 mmbbls of oil and 0.4 mmcm (14 mmcf) of gas, a total of 89.1 mboe per day for 2003. 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 business segment. This includes all midstream and commercial activities in Shah Deniz, Azerbaijan, downstream activities in Turkey, and our position in Cove Point in the U.S.
Natural Gas. The Natural Gas segment transports, processes and sells natural gas from our upstream positions on the NCS and certain assets abroad. We are one of the leading suppliers of natural gas to the European market and the largest corporate owner in the world's largest offshore pipeline network. This network, Gassled, allows us flexibility in the way we source, blend and deliver our natural gas to any one of four landing points in Europe and through to the European gas transmission system. We have a 21.133 per cent interest in the Gassled joint venture. As from February 1, 2004, the Kollsnes Gas Plant is included in Gassled. Given our upstream reserves, security of access to supply and access to a flexible transportation network, we believe that we can expand our sales and market share in the expected environment of increased demand and market deregulation. In 2004 we sold approximately 55.3 bcm (2.0 tcf) of natural gas (at a gross calorific value of 40 MJ/scm), which includes natural gas sold by us on behalf of the Norwegian State, compared to 47.0 bcm (1.7 tcf) in 2003.
Manufacturing and Marketing. The Manufacturing and Marketing segment comprises downstream activities including sales and trading of crude oil, NGL and petroleum products, refining, methanol production, retail and industrial marketing of oil products and petrochemical operations through our 50 per cent owned joint venture Borealis. In July, 2004 we repurchased the 50 per cent share in Statoil Detaljhandel Skandinavia AS (SDS) from 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.
Strategy and Opportunities
Our strategic objective as set out in 2001 remains intact. It is to exploit the profitable options as an integrated oil and gas company with emphasis on developing growth opportunities available to us on the NCS and internationally while maintaining strict capital discipline.
Factors crucial to our competitiveness include:
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
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.
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.
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.
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.
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.
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.
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
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.
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.
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.
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.
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.
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 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.
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.
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.
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.
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.
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.
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 Co2 from 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
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
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.
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.
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.
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.
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 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 CO2 allowances 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 CO2 allowances 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
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.
Technologies and expertise
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:
Our evolving environmental risk-based methodology is currently being tested on the highly complex discharge from our Mongstad refinery. If successful, the technique will be further developed and adapted for use at all of Statoil's land-based plants.
Exploration. New knowledge and technologies are continuously required to assist Statoil in its quest to replace reserves. Major exploration achievements over the years include the prize-winning seabed logging initiative, and an empirically verifiable theory showing that most of the world's hydrocarbons occur in reservoirs within a single, definable temperature zone.
Recent highlights include:
We have also been working closely with Landmark to develop an integrated interpretation and visualization tool designed to predict lithology and fluid variations from 3D pre-stack seismic and well data. 'Well seismic fusion' will enable asset teams to evaluate prospects more rapidly, improve reservoir property prediction and reduce uncertainty.
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:
A study of parts of the Middle Jurassic Brent Group has been made to reduce uncertainty, increase our understanding of the physical processes involved, and provide a high quality estimate of potential blow down recovery. The work was based on an adaptation of Statoil's proprietary pore-to-field modeling procedure, which is a state-of-the-art upscaling technique used to ensure that the effects of small-scale features on fluid flow are adequately accounted for in large-scale simulations of reservoir performance. Although this is the first time we have tested a designer 'blow down' pore-to-field modeling workflow, the results are promising and convincing enough to impact the final decision.
When certain types of microbes are stimulated in reservoir sandstone core samples in the laboratory, they increase oil production by mobilizing residual oil trapped in the pore space. The most likely reasons for this are that the bacteria induce changes in wettability and, more especially, the interfacial tension between oil and water. However, proving this experimentally on growing bacterial systems is difficult. Nevertheless, Statoil and SINTEF researchers have made a significant step forward in quantitatively monitoring a dramatic lowering in interfacial tension at a simple oil/water interface using an advanced laser-light scattering technique.
This technology is now being extended for subsea application to improve recovery from smaller stand-alone fields and satellites situated some distance away from major production centers. The Tyrihans field in the Norwegian Sea was selected as a test case. A technical specification concluded that an additional 22 mmbbls of economically attractive oil could potentially be produced by using a subsea raw seawater injection station. The proposal was approved by Statoil and its license partners in December 2004, and the station is scheduled to come into operation in late 2008 when Tyrihans comes on stream. AkerKværner and Framo Engineering are undertaking the construction work.
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:
The next candidate is the Veslefrikk field, where oil production is limited by high-pressure losses caused by two-phase (gas/liquid) slug flow in the wellstream transfer hoses between the Veslefrikk A and B platforms. Separating the wellstream into two phases and transferring them in separate hoses will decrease pressure losses and enable higher, prolonged, low-pressure production. A suitable prototype has been pre-qualified at K-lab.
The CDS-Statoil inline deliquidizer received the Spotlight on New Technology Award for 2004 at the Offshore Technology Conference (OTC) - Innovation Without Limits - held in the Reliant Center in Houston, Texas (USA).
Gas chain development. This embraces gas technologies such as pipeline-based gas solutions, LNG, GTL and methanol.
Recent achievements include:
The substantial size of the demonstration plant and its location in a genuine GTL plant ensures that further up-scaling will be relatively straightforward. Current operational experience has shown that the productivity and yield from the catalyst and reactor are not only excellent but also exceed laboratory test expectations.
Research has recently been focused on the early screening and feasibility phases of a planned capacity expansion (from about 2,550 to 3,450 tonnes of methanol per day), and the construction of a gas-fired power plant (about 860 MW) that will partly be fed by excess steam generated by the expanded plant.
The preferred synthesis gas solution is to install a new, parallel synthesis gas preparation unit with a conventional steam reformer. For the methanol synthesis concept the idea is to expand capacity by installing a new synthesis loop using a special process configuration to increase production from the existing loop. Scheduled to start up in early 2008, both facilities will potentially strengthen the plant's competitiveness in the years to come.
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 Pipeline-based gas transport
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.
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 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.
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.
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.
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.
Years ended December 31, 2004, 2003 and 2002
Sales. Statoil markets and sells the Norwegian State's share of oil and natural gas production from the NCS. All purchases and sales of SDFI oil production are recorded as Cost of goods sold and Sales, respectively.
All oil received by the Norwegian State as royalty in kind from fields on the NCS is purchased by Statoil. Statoil includes the costs of purchase and proceeds from the sale of this royalty oil in its Cost of goods sold and Sales respectively.
Our sales revenue totaled NOK 303.8 billion in 2004, compared to NOK 248.5 billion in 2003 and NOK 242.2 billion in 2002.
The 22 per cent increase in sales revenues from 2003 to 2004 was mainly due to 25 per cent increase in the average oil price measured in NOK and 8 per cent increased realized prices of our natural gas sold to the European markets measured in NOK, as well as increased sales of equity natural gas. The oil price of the group is a volume-weighted average of the segment prices of oil and NGL, including a margin for oil trading and sales of NOK 0.70 per boe. The increase in our ownership of SDS to 100 per cent contributed approximately NOK 5 billion in increased sales revenues. Increased prices and higher volumes in the downstream activity also contributed to the increased sales revenues in 2004 compared to 2003. The increase in sales revenues is partly offset by the reduction of oil volumes sold, reducing revenues by NOK 6.4 billion, mainly related to volumes sold on behalf of SDFI.
Our average daily oil production (lifting) decreased from 737,500 barrels in 2003 to 712,600 barrels in 2004. The 3 per cent decrease in average daily oil production from 2003 to 2004 was primarily due to lower production from declining fields including Statfjord, Norne and Lufeng. Some operational difficulties and the well incident at Snorre reduced regularity of production somewhat in 2004 compared to 2003. This reduction was partly offset by production from the Kizomba A field coming on stream in the fourth quarter of 2004. At the end of 2004, we were in an underlift position of approximately 12,000 boe per day compared to an underlift position of approximately 9,000 boe per day in 2003.
Our average daily oil production (lifting) decreased from 748,200 barrels in 2002 to 737,500 barrels in 2003. The 1 per cent decrease in average daily oil production from 2002 to 2003 was primarily due to lower production from declining fields including Statfjord, Sleipner Øst, Norne and Lufeng. Some operational difficulties at Snorre, Gullfaks, Visund and Åsgard reduced regularity of production somewhat in 2003 compared to 2002. This reduction was partly offset by production from new fields Xikomba, Jasmim and Fram Vest coming on stream in the fourth quarter of 2003, as well as increased production from the fields Sincor in Venezuela and Girassol in Angola and Sigyn coming on stream in the fourth quarter of 2002. At the end of 2003, we were in an underlift position of approximately 9,000 boe per day compared to a minor underlift position in 2002.
Our natural gas volumes sold of Statoil produced natural gas were 22.1 bcm (782 bcf) in 2004, 19.3 bcm (683 bcf) in 2003 and 18.8 bcm (666 bcf) in 2002. Natural gas volumes increased primarily due to an increase in long-term contracted natural gas volumes to continental Europe as well as an increase in short-term sales, mainly to the UK. Natural gas volumes in 2004 also include natural gas from the International E&P business segment mainly from the Algerian field In Salah, which commenced production in July 2004.
We record revenues from sales of production based on lifted volumes. The term "production" as used in this section means lifted volumes. The term "production" used in Item 4 -Information on the Company, means produced volumes, which include lifted volumes adjusted for under- and overlifting. Overlifting and underlifting positions are a result of Statoil lifting either a higher or a lower volume of oil within the period than that represented by our total production of entitlement volumes in that period.
Equity in net income (loss) of affiliates. Equity in net income (loss) of affiliates principally includes our 50 per cent equity interest in Borealis, our 50 per cent equity interest in Statoil Detaljhandel Skandinavia (SDS), which was increased to 100 per cent in July 2004, our 50 per cent equity interest in the drill ship West Navigator, which was sold in 2004 and miscellaneous other affiliates. Our share of Equity in net income of affiliates was NOK 1.2 billion in 2004, NOK 0.6 billion in 2003 and NOK 0.4 billion in 2002. The increase from 2003 to 2004 was primarily due to an increased contribution from Borealis, as a result of increased margins and volumes. The increase from 2002 to 2003 was mainly a result of the increased contribution from Borealis and miscellaneous interests related to the natural gas business.
Other income. Other income was NOK 1.3 billion in 2004, NOK 0.2 billion in 2003 and NOK 1.3 billion in 2002. The NOK 1.3 billion income in 2004 is mainly related to the sale of our shares in Verbundnetz Gas (VNG), sales of our shares in the technology companies Electro Magnetic Geo Services AS (EMGS) and Advanced Production and Loading AS (APL) and sales of a portion of our ownership interest in the fields Kristin and Mikkel on the NCS. The NOK 0.2 billion income in 2003 is mainly related to the sale of Navion. The NOK 1.3 billion income in 2002 is primarily related to the gain on the sale of the E&P operations off Denmark, including the Siri and Lulita fields.
Cost of goods sold. Our cost of goods sold includes the cost of the SDFI oil and NGL production that we purchase from the Norwegian State pursuant to the owner's instruction. See -Factors Affecting Our Results of Operations above for more information.
Cost of goods sold increased to NOK 188.2 billion in 2004 from NOK 149.6 billion in 2003 and NOK 147.9 billion in 2002.
The 26 per cent increase in 2004 compared to 2003 was mainly due to increased oil prices measured in NOK. This was partly offset by reduced oil volumes purchased from the SDFI.
The 1 per cent increase in 2003 compared to 2002 was mainly due to increased oil prices measured in NOK. This was partly offset by the 11 per cent weakening of the NOK/USD exchange rate, as well as reduced volumes purchased from the SDFI.
Operating expenses. Our operating expenses include production costs in fields and transport systems related to our share of oil and natural gas production. Operating expenses in 2004 were NOK 27.4 billion, as compared to NOK 26.7 billion in 2003 and NOK 28.3 billion in 2002. The increase from 2003 to 2004 was primarily due to the consolidation of SDS into Statoil's accounts, which affects comparisons between years. The 6 per cent decrease from 2002 to 2003 was mainly related to the absence of Navion shipping activities, which were sold in 2003, as well as reduced processing costs.
Selling, general and administrative expenses. Our selling, general and administrative expenses include costs related to the selling and marketing of our products, including business development costs, payroll and employee benefits. Our selling, general and administrative expenses were NOK 6.3 billion in 2004, compared to NOK 5.5 billion in 2003 and NOK 5.3 billion in 2002.
The increase from 2003 to 2004 was mainly due to SDS being consolidated into the group's accounts, which affects comparisons between years. Insurance premiums increased in 2004 compared to 2003, but were partly offset by reduced rig accruals.
The increase from 2002 to 2003 was primarily due to increased spending in the Manufacturing and Marketing businesses as compared to 2002, mainly due to expansion of the retail network into Poland and the Baltic states. This was partly offset by a reduction in business development spending in International E&P. The rig provisions increased by NOK 0.4 billion during 2003, most of which affected selling, general and administrative expenses. This is NOK 0.2 billion higher than the provisions made for such losses in 2002.
Over the period 1998-2004 we provided approximately NOK 1.4 billion for the anticipated reduction in market value of company exposed fixed-price mobile drilling rig contracts. At December 31, 2004, the remaining provision for these losses was approximately NOK 0.4 billion based on our assumptions regarding our own utilization of the rigs and the rate and duration at which we could sublet these rigs in the Norwegian market to third parties and the development of the NOK/USD exchange rate. These assumptions reflect management judgment and were reassessed based on the most current information as of the end of the year 2004. The provision for future losses has been reduced by NOK 1.0 billion, of which NOK 0.3 billion was a realized loss.
Depreciation, depletion and amortization expenses. Our depreciation, depletion and amortization expenses include depreciation of production installations and transport systems, depletion of fields in production, amortization of intangible assets and depreciation of capitalized exploration expenditures as well as write-down of impaired long-lived assets. Depreciation, depletion and amortization expenses were NOK 17.5 billion in 2004, compared to NOK 16.3 billion in 2003 and NOK 16.8 billion in 2002.
The increase from 2003 to 2004 was mainly related to new fields coming on stream both on the NCS and internationally, write-downs of NOK 0.3 billion on some fields, and increases due to changes in the depreciation related to retirement obligations and changes due to the repeal of the Removal Grants Act as described under Other items below.
The decrease from 2002 to 2003 was mainly related to the write-down of the LL652 field in Venezuela of NOK 0.8 billion in 2002, while the 2003 figure includes the NOK 0.2 billion write-down of the Dunlin field in the UK.
Exploration expenditures. Our exploration expenditure is capitalized to the extent our exploration efforts are deemed successful, or awaiting such determination, and is otherwise expensed. Our exploration expenses consist of the expensed portion of our current-period exploration expenditures and write-offs of exploration expenditures capitalized in prior periods. Exploration expenses were NOK 1.8 billion in 2004, NOK 2.4 billion in 2003 and NOK 2.4 billion in 2002.
The reduction of 23 per cent in exploration expense from 2003 to 2004 was mainly due to a NOK 0.4 billion increase in capitalization of the exploration activity. Exploration expenditure capitalized in previous years but written off in 2004 was NOK 0.1 billion lower than in 2003. A total of 12 exploration and appraisal wells were completed in 2004, of which nine resulted in discoveries.
The 2 per cent reduction in exploration expense from 2002 to 2003 was mainly due to a lower level of exploration activity within E&P Norway, partly offset by higher exploration activity within International E&P. Exploration expenditure capitalized in previous years but written off in 2003 was NOK 0.3 billion lower than in 2002. A total of 23 exploration and appraisal wells were completed in 2003, of which 17 resulted in discoveries.
Income before financial items, other items, income taxes and minority interest. Income before financial items, other items, income taxes and minority interest totaled NOK 65.1 billion in 2004, NOK 48.9 billion in 2003, and NOK 43.1 billion in 2002.
The 33 per cent increase from 2003 to 2004 was mainly due to a 25 per cent increase in oil prices measured in NOK, increased natural gas prices measured in NOK of 8 per cent, NOK 1.2 billion due to changes in the provisions relating to fixed price drilling rig contracts, as well as a 2 per cent increase in combined lifting of oil and natural gas. The gain from the sale of the shares in Verbundnetz Gas AG (VNG) in the first quarter of 2004 also contributed to an increase of NOK 0.6 billion in the results. Exploration costs were reduced by NOK 0.5 billion in 2004 compared to 2003, mainly because of increased capitalization of this year's exploration activity compared to last year. Among other factors high refinery and petrochemical margins contributed with NOK 1.3 billion in increased results in 2004 compared to 2003.
The increase in Income before financial items, other items, income taxes and minority interest in 2004 was partly offset by NOK 1.2 billion in increased depreciation and write-downs, mainly due to increased liftings, new fields coming on stream, and increased depreciation related to future removal expenditures. Accruals for increased insurance premium commitments related to damages occurred in the two mutual insurance companies in which Statoil participates and reduced results by NOK 0.4 billion. The increased contribution from downstream activities was somewhat reduced due to the loss of Navion income which amounted to NOK 0.5 billion in 2003, as well as NOK 0.3 billion in reduced contribution from Oil Sales, Trading and Supply (O&S) in 2004 compared to 2003, which was mainly due to currency effects. Statoil Detaljhandel Skandinavia AS (SDS) was consolidated into Statoil's accounts as of July 2004, and will therefore affect comparisons between periods.
The 13 per cent increase from 2002 to 2003 was mainly related to increased oil and natural gas prices measured in NOK and higher margins in the downstream segment. Oil prices in 2003 measured in USD increased by 18 per cent compared to 2002. Measured in NOK, however, the oil price increased by 5 per cent, and the natural gas prices measured in NOK increased by 7 per cent compared to 2002. Refining and petrochemical margins were also higher in 2003 compared to 2002, which contributed to increased contribution from downstream activities totaling NOK 1.9 billion.
Income before financial items, other items, income taxes and minority interest for 2002 included a gain of NOK 1.0 billion before tax related to the sale of the upstream activity in Denmark, partly offset by a write-down related to the LL652 field in Venezuela in 2002 of NOK 0.8 billion before tax.
In 2004, 2003 and 2002, our income before financial items, other items, income taxes and minority interest, measured as a percentage of revenues was approximately 21 per cent, 20 per cent and 18 per cent, respectively, and was impacted by the various factors described above.
Net financial items. In 2004 we reported net financial items of NOK 5.7 billion, compared to NOK 1.4 billion in 2003 and NOK 8.2 billion in 2002. The changes from year to year resulted principally from changes in currency gains and losses on the US dollar portions of our long-term debt outstanding due to changes in the NOK/USD exchange rate. The NOK strengthened by NOK 0.29 during 2003, and by NOK 0.64 during 2004.
The increase in net financial items from 2003 to 2004 is mainly related to fluctuations in the NOK/USD exchange rate on both the long-term debt and short-term NOK/US dollar balances. The debt portfolio including the effect of swaps was as at year-end 2004 nearly 100 per cent held in US dollars.
Interest income and other financial income amounted to NOK 1.0 billion in 2004, compared to NOK 1.2 billion in 2003 and NOK 1.8 billion in 2002. The reduction is mainly due to lower interest income following the general reduction in interest rates in 2004 compared to the two previous years.
Interest costs and other financial costs amounted to NOK 0.3 billion in 2004, compared to NOK 0.9 billion in 2003. The reduced costs are mainly due to lower USD interest rates, which reduced the interest charge on the group's long-term debt, as well as shorter interest reset profiles and a reduced average NOK/USD exchange rate in 2004 compared to 2003. In 2002 interest costs and other financial cost amounted to NOK 2.0 billion.
The result from management of the portfolio of security investments, mainly in equity securities and held by our insurance captive Statoil Forsikring AS, provided a gain in 2004 of NOK 0.5 billion in 2004, compared to a gain of NOK 0.9 billion in 2003 and a loss in 2002 of NOK 0.6 billion.
The Central Bank of Norway's closing rate for NOK/USD was 6.97 on December 31, 2002, 6.68 on December 31, 2003 and 6.04 on December 31, 2004. These exchange rates have been applied in Statoil's financial statements.
Other items. There are no Other items in 2004. The Norwegian parliament decided in June 2003 to replace grants for costs related to the removal of installations on the NCS with an equivalent tax deduction for such costs. Previously, removal costs were refunded by the Norwegian state based on a percentage of the taxes paid over the productive life of the removed installation. As a consequence of the changes in legislation, we charged the receivable of NOK 6.0 billion from the Norwegian State related to the refund of removal costs to income under Other items in the second quarter of 2003. Furthermore, the resulting deferred tax benefit of NOK 6.7 billion was recognized. As a result, the net effect on income in 2003 was NOK 0.7 billion.
Income taxes. Our effective tax rates were 64.1 per cent, 62.0 per cent and 66.9 per cent in 2004, 2003 and 2002, respectively. The tax rate in 2004 was strongly influenced by the positive tax effects due to the change in Norwegian tax legislation relating to dividends received by companies (The Exemption Method) of NOK 1.4 billion and the acceptance of our method of allocating office costs to be deductible under the offshore tax regime of NOK 0.4 billion. Adjusted for these non-recurring tax effects, the tax rate in 2004 would have been 66.7 per cent. In 2003, the repeal of the Removal Grants Act entailed NOK 6.7 billion being recorded as income tax and reduced deferred taxes, whereas NOK 6.0 billion was recorded as an expense under other items. Adjusted to exclude the effect of the repeal of the Removal Grants Act, the tax rate in 2003 was 67.9 per cent.
Our effective tax rate is calculated as income taxes divided by income before income taxes and minority interest. Fluctuations in the effective tax rates from year to year are principally a result of non-taxable items (permanent differences), changes in the components of income between Norwegian oil and gas production, taxed at a marginal rate of 78 per cent, other Norwegian income, including onshore portion of net financial items, taxed at 28 per cent, and income in other countries taxed at the applicable income tax rates.
Minority interest. Minority interest in net profit in 2004 was NOK 0.5 billion, compared to NOK 0.3 billion and NOK 0.2 billion in 2002. Minority interest consists primarily of Shell's 21 per cent interest in the Mongstad crude oil refinery.
Net income. Net income in 2004 was NOK 24.9 billion compared to NOK 16.6 billion in 2003 and NOK 16.8 billion in 2002 for the reasons discussed above.
Improvement program. In 2001 Statoil specified a set of improvement efforts which at the time were deemed necessary to reach its target of return on average capital employed in 2004 of 12 per cent, based on normalized assumptions. To meet this target, Statoil determined that, among other improvements, it would need to reduce certain costs and increase revenue items by a total of NOK 3.5 billion in 2004, compared to 2001.
A number of small improvements were targeted in a large number of areas. The more significant of these improvements are outlined by business segment below. In some cases the improvements were compared against the 2001 reported levels, e.g., lifted volumes or production unit cost. In other areas where improvements were targeted it was necessary to make assumptions about what the result may have been in 2004 if no actions had been taken, e.g., expected increase in water production by 2004. Efforts were then made to improve the performance against these base assumptions. In all cases the effect of the Algerian transaction in 2003, which was completed in 2004, has been excluded.
At the end of 2004, Statoil is satisfied that it has identified annual, sustainable improvements in both costs and revenues, which it estimates will contribute NOK 3.2 billion of improvements compared to a target of NOK 3.5 billion for 2004, and this has contributed to reaching the target of 12 per cent return on average capital employed. The main reason for not meeting the corporate target of NOK 3.5 billion relates to the fact that the International E&P segment did not achieve its targeted improvement.
The following table details certain financial information for our four business segments. In combining segment results, we eliminate inter-company sales. These include transactions recorded in connection with our oil and natural gas production in the E&P Norway or International E&P segments and also in connection with the sale, transport or refining of our oil and natural gas production in the Manufacturing and Marketing or Natural Gas segments. Our E&P Norway business segment produces oil, which it sells internally to Oil Sales, Trading and Supply (O&S) in the Manufacturing and Marketing business segment, which then sells the oil in the market. E&P Norway also produces natural gas, which it sells internally to our Natural Gas business segment, also to be sold in the market. As a result, we have established a market price-based transfer pricing policy whereby we set an internal price at which our E&P Norway business area sells oil and natural gas to the Manufacturing and Marketing and the Natural Gas business segments.
For sales of oil from E&P Norway to Manufacturing and Marketing, the transfer price of oil is the applicable market reflective price less a margin of NOK 0.70 per barrel. The transfer price of sales of natural gas from E&P Norway to Natural Gas is NOK 0.32 per scm adjusted quarterly by the average USD oil price over the last six months in proportion to USD 15 per barrel. The average transfer price for natural gas per standard cubic meter amounted to NOK 0.71 in 2004, NOK 0.59 in 2003 and to NOK 0.50 in 2002.
The table below sets forth certain financial information for our business segments, including inter-company eliminations for each of the years in the three-year period ending December 31, 2004.
The following table sets forth certain financial and operating data regarding our E&P Norway business segment and percentage change for each of the years in the three-year period ending December 31, 2004.
(1) Figures for 2002 and 2003 have been restated for the transfer of Kollsnes to Natural Gas. See Supplementary Information on Oil and Gas Producing Activities beginning on page F-33 for further details.
(2) In 2004 the oil price of the E&P Norway business segment is a volume-weighted average of the prices of oil and NGL received by the segment. For the years 2002 and 2003 the price does not include NGL.
(3) Our unit production (lifting) cost is calculated by dividing operating costs relating to the production of oil and natural gas by total production (lifting) of petroleum in a given year.
Years ended December 31, 2004, 2003 and 2002
E&P Norway generated total revenues of NOK 74.1 billion in 2004, compared to NOK 62.5 billion in 2003 and NOK 58.8 billion in 2002.
The 18 per cent increase in revenues from 2003 to 2004 resulted primarily from a 32 per cent increase in the average oil price in USD of oil sold from E&P Norway to Manufacturing and Marketing, a 20 per cent increase in the transfer price in NOK of natural gas sold from E&P Norway to Natural Gas, and an increase in lifted volumes of natural gas. This was partly offset by a 5 per cent decrease in the NOK/USD exchange rate and a 6 per cent reduction in lifted volumes of oil.
The 6 per cent increase in revenues from 2002 to 2003 resulted primarily from an 18 per cent increase in the average realized crude oil price in USD and a 19 per cent increase in the transfer price in NOK of natural gas sold from E&P Norway to Natural Gas. This was partly offset by a 13 per cent decrease in the NOK/USD exchange rate and a 2 per cent reduction in lifted volumes of oil.
Average daily oil production (lifting) in E&P Norway decreased to 612,800 barrels in 2004 from 651,900 barrels in 2003 and from 666,700 barrels in 2002.
The 6 per cent decrease in average daily oil production from 2003 to 2004 was primarily due to decline on Statfjord, Norne and Troll, technical problems at Glitne throughout the year, the rig strike and lockout, and an incident at Snorre which caused a shutdown in production from late November 2004 to late January 2005. The new fields Kvitebjørn and Sleipner Vest Alfa Nord, which started production in the fourth quarter of 2004, could not fully replace the production decline from mature fields.
The 2 per cent decrease in average daily oil production from 2002 to 2003 was primarily due to decline from large fields like Statfjord, Sleipner Øst and Norne being past production plateau. The new fields Mikkel, Fram Vest and Vigdis Extension, which started production in the fourth quarter of 2003, could not fully replace the production decline from the mature fields.
Average daily gas production was 58.1 mmcm (2,051 mmcf) in 2004, as compared to 52.6 mmcm (1,857 mmcf) in 2003, and 50.7 mmcm (1,784 mmcf) in 2002.
The 11 per cent increase between 2003 and 2004 was primarily due to an increase in long-term contracted gas volumes and high off take from existing contracts.
The 4 per cent increase between 2002 and 2003 was primarily due to an increase in long-term contracted gas volumes to continental Europe and an increase in short-term sales, mainly to the UK.
Unit production cost was USD 2.84 per boe in 2002, USD 3.10 per boe in 2003 and USD 3.34 per boe in 2004. The increase from 2003 to 2004 is due primarily to the effect of the weaker USD against the NOK since costs are primarily incurred in NOK, increased pension cost and increased cost of goods sold due to higher oil price. Production costs measured in NOK decreased from NOK 22.53 per boe in 2002 to NOK 21.93 per boe in 2003 with a slight increase to NOK 22.45 per boe in 2004.
As a part of the improvement program E&P Norway realized cost reductions and revenue improvements of NOK 1.1 billion in 2004 compared to 2001 against a target of NOK 1.2 billion. Planned measures included improvements of operations and regularity on the NCS, as well as improving efficiency in logistics and onshore support. Over the same period operating costs have also been reduced by NOK 600 million and total platform throughput (oil, water and gas) has increased significantly since 2001. Handling this volume increase at the achieved production costs has added another NOK 500 million to the improvement program.
Operating, general and administrative expenses were NOK 9.9 billion in 2004, NOK 11.3 billion in 2003 and NOK 11.4 billion in 2002. The 13 per cent decrease from 2003 to 2004 was mainly due to the reversal of rig accruals of NOK 1.0 billion in 2004 while these increased by NOK 0.4 billion in 2003, which was partly offset by a realized loss on rig accruals of NOK 0.3 billion. In addition, the platform costs were reduced by NOK 0.2 million in 2004.
Depreciation, depletion and amortization expenses were NOK 12.4 billion in 2004, NOK 12.0 billion in 2003 and NOK 11.7 billion in 2002. The increase from 2003 to 2004 was mainly due to write-down on Murchison, depreciation of assets related to retirement obligations pursuant to the new accounting principle for removal costs, and commencement of production from the new fields Kvitebjørn and Tune in late 2004 and Fram Vest, Mikkel and Vigdis Extension in late 2003. This was partly offset by increased reserves, which reduce the rate of depreciation, and lower lifted oil volumes. The increase from 2002 to 2003 is mainly due to depreciation of asset related to retirement obligations pursuant to the new removal accounting principle, which increased the depreciation base, and start of production from new fields in late 2002 and 2003, namely Sigyn, Mikkel, Fram Vest and Vigdis Extension. This was partly offset by increased reserves and lower lifted oil volumes.
Exploration expenditure (activity) decreased both from 2003 to 2004 and from 2002 to 2003. Exploration expenditure was NOK 1.1 billion in 2004, compared to NOK 1.2 billion in 2003 and NOK 1.4 billion in 2002. The 8 per cent decrease from 2003 to 2004 is mainly due to fewer wells drilled due to a lack of available rigs on the NCS. The decrease from 2002 to 2003 was mainly due to fewer identified drilling opportunities which we believed would be successful in some of the areas where we have interests in acreage, and lack of support for drilling of wells suggested by Statoil in the licenses. This resulted in fewer wells being drilled in 2003 than in 2002. Exploration expenditure is expected to increase in 2005.
Exploration expense in 2004 was NOK 0.8 billion, compared to NOK 1.4 billion in both 2003 and 2002. The reduced exploration expense from 2003 to 2004 is mainly due to higher capitalized exploration in 2004 than in 2003 and lower expenditure capitalized in previous years, but written off in 2003 and 2004. Exploration expense in 2004 included NOK 0.1 billion written off in 2004 relating to expenditures capitalized in previous years, compared to NOK 0.3 billion of expenditure written off in 2003 as compared to NOK 0.5 billion in 2002.
The difference in activity in 2003 and 2002 was offset by lower expenditure capitalized in previous years, but written off in 2003, compared to 2002. In 2004, six exploration and appraisal wells were completed, four of which resulted in discoveries. In addition, four extensions on production wells were completed in 2004, all of which resulted in discoveries. However these extensions were not funded by exploration expenditure. In comparison nine exploration and appraisal wells were completed in 2003, of which six resulted in discoveries. In 2002 15 exploration and appraisal wells were completed, of which 10 resulted in discoveries. In addition, five extensions on production wells were completed in 2002, of which four resulted in discoveries.
A reconciliation of exploration expenditure to exploration expenses is shown in the table below.
Income before financial items, other items, income taxes, and minority interestfor E&P Norway was NOK 51.0 billion in 2004, compared to NOK 37.9 billion in 2003 and NOK 34.2 billion in 2002. The 35 per cent increase in income from 2003 to 2004 was primarily the result of an increase in revenues due to the 26 per cent increase in the average oil price measured in NOK and a 20 per cent increase in the transfer price in NOK of natural gas. Operating expenses were reduced by 13 per cent and exploration expenses by 43 per cent, but these reductions were partly offset by a 3 per cent increase in depreciation, depletion and amortization expenses.
The 11 per cent increase in income before financial items, other items, income taxes and minority interest from 2002 to 2003 was primarily the result of an increase in revenues due to the 5 per cent increase in the average realized oil price measured in NOK and the 19 per cent increase in the transfer price of natural gas sold from E&P Norway to Natural Gas. Operating expenses were reduced by 2 per cent, but the reduction was offset by a 2 per cent increase in depreciation, depletion and amortization expenses.
The following table sets forth certain financial and operating data regarding our International E&P business segment and percentage change for each of the years in the three-year period ending December 31, 2004.
(1)Figures for 2002 and 2003 have been restated to exclude both revenues and costs from Cove Point and other international mid- and downstream natural gas activities, which were transferred from International E&P to Natural Gas as of January 1, 2004. See Supplementary Information on Oil and Gas Producing Activities beginning on page F-33 for further details.
(2)In 2004 the oil price for the International E&P business segment is a volume-weighted average of the prices of oil and NGL received by the segment. For the years 2002 and 2003 the price does not include NGL.
(3)Our unit production (lifting) cost is calculated by dividing operating costs relating to the production of oil and natural gas by total production (lifting) of petroleum in a given year.
Years ended December 31, 2004, 2003 and 2002
International E&P generated total revenues of NOK 9.8 billion in 2004 compared to NOK 6.6 billion in 2003 and NOK 6.8 billion in 2002.
The 48 per cent increase from 2003 to 2004 was mainly due to higher liftings contributing to an increase of NOK 1.9 billion and higher prices in USD for crude oil contributing to an increase of NOK 1.9 billion. The price effect was partly offset by an adverse currency effect of NOK 0.5 billion caused by the weakening of the USD measured against the NOK. The increase in oil prices in the International E&P segment was lower than for the group as a whole, due to negative quality price differentials compared to Brent Blend for some qualities of crude with high fuel content from International E&P assets such as Alba and Kizomba A.
The 2 per cent decrease from 2002 to 2003 was mainly due to the inclusion of proceeds of the NOK 1.0 billion divestment of the Denmark assets in 2002 revenues, substantially offset by higher prices for crude oil in 2003.
Average daily oil production (lifting) was 99,800 barrels per day in 2004, compared to 85,600 barrels per day in 2003 and 81,500 barrels per day in 2002. The 17 per cent increase in average daily production of oil from 2003 to 2004 came primarily from Angola, where the Kizomba A field started production in late 2004, while the Xikomba and Jasmim fields had the first full year of production during 2004. These increases were partly offset by the declining production of 4,000 boe per day from the Alba field and 1,600 boe per day from the Schiehallion field in the UK, and 1,900 boe per day from the Girassol field in Angola, due to the tie-back of Jasmim to Girassol. The Lufeng field was temporarily closed down in June 2004 but will start up again during the second quarter of 2005.
The 5 per cent increase in average daily production of oil from 2002 to 2003 resulted primarily from increased production of 6,500 boe per day from the Sincor field in Venezuela, 3,600 boe per day from the Girassol field in Angola and 3,000 boe per day from the Alba field in the UK. New fields coming into production in 2003 included the Caledonia field in the UK, and the Jasmim field and the Xikomba field in Angola. These increases in production were partly offset by the declining production of 1,400 boe per day from the Lufeng field in China and the sales of the Siri field and Lulita field in Denmark, which contributed production of 6,600 boe per day in 2002.
Average daily natural gas production in 2004 was 2.4 mmcm per day (84 mmcf per day) compared to 0.4 mmcm per day (14 mmcf per day) in 2003 and 0.9 mmcm per day (33 mmcf per day) in 2002. The large increase from 2003 to 2004 was due to the In Salah field in Algeria coming on stream in July 2004. The 58 per cent decrease from 2002 to 2003 resulted from the Jupiter natural gas field in the UK being in decline.
Unit production cost on a 12-month average increased by 21per cent from 2003 to 2004, primarily due to the increased operating costs on Lufeng, where the floating production vessel lease rate is linked to the oil price, and on Sincor due to a planned maintenance shutdown that takes place every third year. This compares to an increase of 2 per cent from 2002 to 2003, mainly due to cost increases on the UK fields measured in USD due to the changes in the GBP/USD exchange rate.
As a part of the improvement program International E&P realized NOK 0.4 billion in improvements by the end of 2004 compared to the target set in 2001 of NOK 0.85 billion. The improvement program was based on an improved portfolio, the main elements of which were higher production and lower unit cost of production. The increased production accounts for approximately half of the realized improvement. The unit cost of production is only marginally improved from 2001. However, in our calculations, we have excluded the cost for the Lufeng field. The Lufeng unit cost is linked to the oil price, and the field was not expected to be in production in 2004 at the time the targets were set in 2001. Statoil will continue to target production cost as an area for further improvement.
Depreciation, depletion and amortization expenses were NOK 2.2 billion in 2004, compared to NOK 1.8 billion in 2003 and NOK 2.4 billion in 2002. The 24 per cent increase in 2004 as compared to 2003 was due to increased liftings. The 24 per cent decrease in 2003 as compared to 2002 was primarily related to the NOK 0.8 billion impairment charge for writing down the LL652 field in Venezuela in 2002, partly offset by a NOK 0.2 billion write-down of the Dunlin field in the UK in 2003.
Operating, general and administrative expenses. Due to the higher lifting and higher average operating cost, operating costs increased by NOK 0.4 billion from 2003 to 2004. A NOK 0.3 billion decrease in operating costs from 2002 to 2003 was mainly due to lower administration costs and business development activities.
Exploration expenditure (activity) was NOK 1.4 billion in 2004, compared to NOK 1.2 billion in 2003 and NOK 1.2 billion in 2002. Exploration expenditure is expected to increase in 2005.
Exploration expense was NOK 1.1 billion in 2004 compared to NOK 1.0 billion in 2003 and NOK 1.0 billion in 2002. In total, six exploration and appraisal wells were completed in 2004, and as of year-end five were considered discoveries. In total, 14 exploration and appraisal wells were completed in 2003, of which 11 resulted in discoveries and remained capitalized. In total, eight exploration and appraisal wells were completed in 2002, of which seven resulted in discoveries and six remained capitalized at year-end 2003.
A reconciliation of exploration expenditure to exploration expenses is shown in the table below.
Income before financial items, other items, income taxes and minority interest for International E&P in 2004 was NOK 4.2 billion compared to NOK 1.8 billion in 2003 and NOK 1.1 billion in 2002. Increased revenues were caused by higher lifting and higher prices. Decreased business development costs in 2004 compared to 2003 and a NOK 0.2 billion write-down of the Dunlin oil field in the UK in 2003 contributed on the cost side. Operating costs in total increased and depreciation, depletion and amortization increased in 2004 compared to 2003 due to higher activity.
The oil and natural gas price development measured in USD contributed NOK 1.3 billion and decreased business development costs contributed NOK 0.1 billion in 2003 compared to 2002. In addition, there was a NOK 0.8 billion write-down of the LL652 oil field in Venezuela in 2002. The positive effects were partly offset by the net effect of asset divestments in 2002 of NOK 1.0 billion and the write-down of the Dunlin field in the UK in 2003 of NOK 0.2 billion.
The following table sets forth certain financial and operating data for our Natural Gas business segment and percentage change for each of the years in the three-year period ending December 31, 2004.
(1)The 2002 and 2003 income statement has been restated to include revenues and costs from Cove Point and other international mid- and downstream gas activities, which were transferred from International E&P to Natural Gas as of January 1, 2004, and costs from Kollsnes, which was transferred from E&P Norway as of January 1, 2004.
(2)Price excludes revenues from third party sales in the US.
(3)Revenue from sale of VNG-shares of NOK 0.6 billion is included in natural gas sales for 2004.
(4)Natural gas volumes for 2003 have been changed in order to include third party LNG volumes. All volumes measured assuming a gross calorific value of 40 MJ/scm
Years ended December 31, 2004, 2003 and 2002
Total revenues in the Natural Gas business consist mainly of gas sales derived from long-term gas sales contracts and tariff revenues from transportation and processing facilities. Natural Gas generated revenues of NOK 33.3 billion in 2004, compared to NOK 25.5 billion in 2003 and NOK 24.5 billion in 2002. The 31 per cent increase in 2004 over 2003 was mainly due to increased gas sales and higher natural gas prices measured in NOK, sale of shares in VNG, higher revenues from sales of ethane, and higher revenues from processing and transportation. The 4 per cent increase in 2003 over 2002 was mainly caused by a 24 per cent increase in processing and transportation revenues.
Natural gas sales were 25.0 bcm (881 bcf) in 2004, 21.1 bcm (744 bcf) in 2003 and 19.6 bcm (691 bcf) in 2002. The 18 per cent increase in gas volumes sold from 2003 to 2004 was mainly due to high customer off-take, an increase in the contracted gas sales portfolio and increased third party gas sales in the US. The 8 per cent increase in gas volumes sold from 2002 to 2003 was mainly caused by an increase in the gas sales contract portfolio, partially due to the start-up of delivery under the gas sales contract with the UK company Centrica. Of the total natural gas sales in 2004, Statoil produced 21.0 bcm (743 bcf). Average gas prices for our European gas sales were NOK 1.10 per scm in 2004 compared to NOK 1.02 per scm in 2003, an increase of 8 per cent. The increased price is mainly due to increased prices on oil products and other competing energy sources, higher gas prices on the National Balancing Point (NBP) in the UK, and the increase in the NOK/EUR exchange rate. Natural gas from In Salah is not sold by the Natural Gas business segment, and hence Statoil's sales volumes from this field are not included in the sales reported by Natural Gas.
Some of the UK trading volumes, which in 2004 and 2003 were accounted net, meaning that the sale of such volumes is accounted for by crediting natural gas sales with the margin or spread associated with the sale, were accounted gross in 2002, meaning that the costs of such volumes were included in costs of goods sold and the total revenue generated by selling such volumes were included in natural gas sales as if the volumes had been taken into inventory. The change has no effect on income before financial items, other items, income taxes and minority interest, but affects comparisons on revenues and costs between the years.
As a part of the improvement program, Natural Gas has realized cost reductions and revenue improvements of NOK 0.5 billion by the end of 2004 compared to 2001, in line with the targeted figure. The measures were related to additional gas sales, optimization and arbitration gains as well as improved efficiency in the transportation system. All of the improvements were based on comparisons with the expected 2004 level in 2001.
Cost of goods sold increased by 50 per cent from 2003 to 2004, mainly due to a higher transfer price to E&P Norway for natural gas, as well as higher volumes of both Statoil produced volumes and third party volumes, including third party volumes in the US. The 9 per cent increase in 2003 over 2002 was mainly caused by higher transfer price and higher Statoil produced volumes.
Operating, selling and administrative expenses increased by 11 per cent, in 2004 as compared to 2003, mainly due to higher transportation costs caused by increased natural gas sales volumes.
Income before financial items, other items, income taxes and minority interest for Natural Gas in 2004 was 6.8 billion, compared to NOK 6.0 billion in 2003 and NOK 6.1 billion in 2002. The 13 per cent increase from 2003 to 2004 was primarily a result of the sale of shares in VNG. Increased sales and an 8 per cent increased external gas sales price were offset by an increase in cost of goods sold due to a higher transfer price for gas and higher gas volumes.
The 2 per cent decrease in income before financial items, other items, income taxes and minority interest for Natural Gas from 2002 to 2003 was due to an increase in the cost of goods sold, primarily as a result of a higher transfer price of natural gas.
Manufacturing and Marketing
Years ended December 31, 2004, 2003 and 2002
Manufacturing and Marketing generated revenues of NOK 267.2 billion in 2004 compared to NOK 218.6 billion in 2003 and NOK 211.2 billion in 2002. The 22 per cent increase resulted mainly from higher prices in USD for crude oil, which includes revenues from the sales of equity, third party and SDFI volumes, which Manufacturing and Marketing sells on behalf of the group, but was partly offset by the strengthening of the NOK versus the USD and a decrease in total volumes of crude oil sold of 4 per cent. The 4 per cent increase in revenue in 2003 over 2002 resulted primarily from higher prices in USD for crude oil, but was partly offset by the strengthening of the NOK versus the USD and a decrease in total volumes of crude oil sold of 6 per cent.
On July 8, 2004 Statoil acquired the remaining 50 per cent of Statoil Detaljhandel Skandinavia AS (SDS) held by ICA/Ahold and the company is now 100 per cent owned by Statoil. The estimated increase in revenues due to the consolidation of SDS in the accounts is approximately NOK 5 billion.
As a part of the improvement program, Manufacturing and Marketing has realized cost reductions and revenue improvements of NOK 1.2 billion by the end of 2004 compared to 2001, exceeding the targeted 0.95 billion. The reduction of costs from the 2001 level through restructuring of sites and increased efficiency in logistics have been the major areas of improvement delivering approximately 65 per cent of the realized improvements. The balance of the improvements in the Manufacturing and Marketing business area was achieved through additional sales, assuming 2001 margins, in the retail area and new NGL volume sales to the USA.
Cost of goods sold increased from NOK 193.4 billion in 2002 to NOK 200.5 billion in 2003 and NOK 247.0 billion in 2004. The increase from 2003 to 2004 resulted primarily from higher prices in USD for crude oil. The consolidation of SDS into the group's accounts contributed an increase in cost of goods sold of 6 per cent.
Operating, selling and administrative expenses increased by 10 per cent in 2004 compared to 2003, mainly due to the consolidation of SDS into the group's accounts. The decrease from 2002 to 2003 is mainly due to the sale of Navion.
Depreciation, depletion and amortization totaled NOK 1.7 billion in 2004, compared to NOK 1.4 billion in 2003, and NOK 1.7 billion in 2002.
Income before financial items, income taxes and minority interest for Manufacturing and Marketing was NOK 3.9 billion in 2004, compared to NOK 3.6 billion in 2003 and NOK 1.6 billion in 2002. The contribution from Borealis and higher refining margins from the manufacturing activity were the main reasons for the increase in income. Navion was sold in 2003, and contributed NOK 0.5 billion to income in 2003, compared with NOK 0.4 billion for 2002.
Higher refining margins contributed to increased results in Manufacturing and Marketing of NOK 0.6 billion to the increase in result from 2003 to 2004. The average refining margin (FCC-margin) was 45 per cent higher, equivalent to USD 2.0 per barrel, in 2004 compared to 2003. The average contract price on methanol was about 6 per cent lower measured in NOK in 2004 than in 2003.
In Oil Sales, Trading and Supply (O&S), profits decreased by NOK 0.3 billion in 2004 compared with 2003, mainly due to currency effects and changes in the market value of economic hedge positions related to inventories. This was partially offset by the recording of a contingent compensation from the sale of the Melaka refinery, effective from the first quarter of 2001. The compensation is recorded as a derivative in the financial statements, and the income is contingent upon 12 months average market prices of certain crude and product qualities, and may change in future periods up until the first quarter of 2006.
The marketing profit decreased by NOK 0.2 billion in 2004 compared with 2003. The decrease was due to lower margins, in particular in Ireland, Poland and Denmark.
The contribution from Borealis to Manufacturing and Marketing's income before financial items, other items, income taxes and minority interest was an income of NOK 844 million in 2004, an income of NOK 106 million in 2003, and an income of NOK 53 million in 2002. The contribution from Borealis increased from 2003 to 2004 due to very high margins, increased volumes and improved operational performance, and is included in total revenues.
Other operationsYears ended December 31, 2004, 2003 and 2002
Our other operations consist of the activities of Corporate Services, Corporate Center, Group Finance and the corporate technical service provider Technology and Projects (T&P). In connection with our other operations, we recorded a loss before financial items, other items, income taxes and minority interest of NOK 815 million in 2004, compared to a loss before financial items, other items, income taxes and minority interest of NOK 280 million in 2003, and NOK 2 million in 2002.
Liquidity and Capital Resources
Cash Flows Provided by Operating Activities
Our primary source of cash flow is funds generated from operations. Net funds generated from operations for 2004 were NOK 38.8 billion, as compared to NOK 30.8 billion in 2003, and NOK 24.0 billion in 2002.
The increase of NOK 8.0 billion from 2003 to 2004 was primarily due to an increase of NOK 17.6 billion in cash flow due to higher prices and margins, which was partly offset by increased taxes paid of NOK 4.7 billion, as well as NOK 4.9 billion reduced cash flow due to changes in working capital items and long-term items (excluding taxes payable, short-term interest-bearing debt, short-term investments and cash) in 2004 as compared to 2003.
The increase of NOK 6.8 billion from 2002 to 2003 was primarily due to an increase of NOK 8.9 billion in cash flow before tax, mainly due to higher prices and margins, as well as increased working capital items of NOK 0.2 billion (excluding taxes payable, short-term debt and cash). Changes in working capital items resulting from the disposal of the subsidiary Navion in the second quarter of 2003 are excluded from cash flows provided by operating activities and classified as proceeds from sales of assets. This was partly offset by a NOK 2.3 billion increase in taxes payable. In 2003 a NOK 6.2 billion increase in deferred tax assets was recorded as income, of which the repeal of the Removal Grants Act represented NOK 6.7 billion. Deferred tax income was NOK 0.6 billion in 2002. As a result of the changes in legislation, Statoil's claim against the Norwegian state totaled NOK 6.0 billion. The amount recorded in income relating to the repeal of the Removal Grants Act in the second quarter of 2003 amounted to NOK 0.7 billion, which had no cash effect in the period.
Cash Flows used in Investing Activities
Net cash flows used in investing activities amounted to NOK 32.0 billion in 2004, as compared to NOK 23.2 billion in 2003, and NOK 16.8 billion in 2002.
Gross investments, defined as additions to property, plant and equipment and capitalized exploration expenditures, increased to NOK 42.8 billion in 2004 from NOK 24.1 billion in 2003 and NOK 20.1 billion in 2002. Gross investments also include investments in intangible assets and investments in affiliates. The increase from 2003 to 2004 was mainly related to increased investments in the E&P Norway and International E&P business segments as a result of an increased number of development projects.
The difference between cash flows used in investment activities and gross investments in 2004 is mainly related to the prepayment made in 2003 of USD 1.0 billion for the two assets in Algeria, In Salah and In Amenas, which is included in gross investments as of 2004. Additionally, cash flow used in investing activities was reduced by NOK 3.2 billion resulting from the sale of assets, which did not impact gross investments.
The 38 per cent increase in net cash flows used in investment activities from 2003 to 2004 was primarily related to higher investment levels in E&P Norway, International E&P and Manufacturing and Marketing.
Cash Flows used in Financing Activities
Net cash flows used in financing activities amounted to NOK 9.1 billion for 2004, as compared to NOK 7.9 billion for 2003 and NOK 4.6 billion in 2002. New long-term borrowing in 2004 increased by NOK 1.4 billion compared to 2003, while repayment of long-term debt increased by NOK 3.8 billion in 2004. The NOK 1.2 billion increase in cash flows used in financing activities from 2003 to 2004 is mainly due to changes in cash flows related to net short-term borrowings and bank overdrafts as well as the net amount of new long-term borrowings and repayment of borrowings on long-term debt. The amount reported in 2004 includes a dividend paid to shareholders of NOK 6.4 billion, while the dividend paid to shareholders in 2003 was NOK 6.3 billion and NOK 6.2 billion in 2002.
Working capital (total current assets less current liabilities) increased by NOK 2.3 billion from 2003 to 2004, from a positive working capital of NOK 1.7 billion as of December 31, 2003 to a positive working capital of NOK 3.9 billion as of December 31, 2004. Working capital as of December 31, 2002 was negative by NOK 1.3 billion. We believe that, taking into consideration Statoil's established liquidity reserves (including committed credit facilities), credit rating and access to capital markets, we have sufficient liquidity and working capital to meet our present and future requirements. Our sources of liquidity are described below.
Our cash flow from operations is highly dependent on oil and gas prices and our levels of production, and is only to a small degree influenced by seasonality. Fluctuations in oil and gas prices, which are outside of our control, will cause changes in our cash flows. We will use available liquidity to finance Norwegian petroleum tax payments (due April 1 and October 1 each year) and any dividend payment. Our investment program is spread across the year. The level of investments in the coming years is expected to remain approximately at the current level. There may be a gap between funds from operations and funds necessary to fund investments, depending on the level of oil and gas prices as well as levels of production. As a result, Statoil anticipates that it will access funding from external sources in 2005. However, it is our intention to keep the ratio of net debt to capital employed at levels consistent with our objective of maintaining our long-term credit rating in the A category (for current rating levels, see below). The absolute level of debt issued will depend highly on the oil and gas prices throughout the year, and their effect on available cash.
As of December 31, 2004, we had liquid assets of NOK 16.6 billion, including approximately NOK 11.6 billion of domestic and international capital market investments, primarily government bonds, but also other investment grade short-term debt securities, and NOK 5.0 billion in cash and cash equivalents. As of December 31, 2004, approximately 25 per cent of our cash and cash equivalents were held in NOK-denominated assets, 70 per cent in US dollars and 5 per cent in other currencies, before the effect of currency swaps and forward contracts. As part of our diversification into new investment alternatives like international commercial paper markets, the share of USD-denominated assets (swapped from NOK) has increased since 2003. Capital market investments increased by NOK 2.3 billion during 2004, as compared to year-end 2003. Cash and cash equivalents decreased by NOK 2.3 billion during 2004, as compared to year-end 2003.
As of December 31, 2003, we had liquid assets of NOK 16.6 billion, including approximately NOK 9.3 billion of domestic and international capital market investments, and NOK 7.3 billion in cash and cash equivalents. As of December 31, 2003, approximately 70 per cent of our cash and cash equivalents were held in NOK, 10 per cent in US dollars, 15 per cent in euro and 5 per cent in other currencies, before the effect of currency swaps and forward contracts.
As of December 31, 2002, we had liquid assets of NOK 12.0 billion, including approximately NOK 5.3 billion of domestic and international capital market investments, primarily government bonds, but also other investment grade short- and long-term debt securities, and NOK 6.7 billion in cash and cash equivalents. As of December 31, 2002, approximately 75 per cent of our cash and cash equivalents were held in NOK, 15 per cent in US dollars, 5 per cent in euro and 5 per cent in other currencies, before the effect of currency swaps and forward contracts.
Our general policy is to maintain a liquidity reserve in the form of cash and cash equivalents on our balance sheet, and committed, unused credit facilities and credit lines to ensure that we have sufficient financial resources to meet our short-term requirements. Long-term funding is raised when we identify a need for such financing based on our business activities and cash flows as well as when market conditions are considered favorable.
As of December 31, 2004, the group had available USD 2.0 billion in a committed revolving credit facility from international banks, including a USD 500 million swing-line facility. The facility was entered into by us in 2004, and is available for draw downs until December 2009. At year-end 2004 no amounts had been drawn under the facility. In addition, a EUR 200 million line of credit has been established in our favor on a bilateral basis by an international financial institution. This line of credit, which we may only utilize with at least 15 days notice, allows us to draw-down amounts in tranches and repay them in time periods ranging from 3 to 7 years. Our short- and long-term ratings from Moody's and Standard & Poor's, respectively, are P-1/A1 and A-1/A. In April 2004 Standard & Poor's revised their outlook on Statoil from negative to stable.
Interest-bearing debt. Gross interest-bearing debt was NOK 36.2 billion at the end of 2004 compared to NOK 37.3 billion at the end of 2003. Despite high investments, interest-bearing debt was reduced, mainly due to increased cash flow from operations, debt repayments exceeding the borrowing need and the reduced NOK/USD exchange rate. At December 31, 2002 gross interest-bearing debt was NOK 37.1 billion.
Net interest-bearing debt is calculated as interest-bearing debt excluding cash, cash equivalents and short-term investments. Net interest-bearing debt was NOK 20.3 billion as of December 31, 2004 compared to NOK 20.9 billion as of December 31, 2003. Net interest-bearing debt was reduced, mainly due to increased cash flow from operations, debt repayments exceeding the borrowing need and the reduced NOK/USD exchange rate. At December 31, 2002 net interest-bearing debt was NOK 23.6 billion. For a reconciliation of net interest-bearing debt to gross debt, see -Use and Reconciliation of Non-GAAP Financial Measures-Net debt to capital employed ratio below.
Net debt to capital employed ratio, defined as net interest-bearing debt to capital employed, was 19.0 per cent as of December 31, 2004, compared to 22.6 per cent as of December 31, 2003 and 28.7 per cent as of December 31, 2002. The decrease in the net debt to capital employed ratio is mainly due to increased shareholders' equity. Our methodology of calculating the net debt to capital employed ratio makes certain adjustments outlined below and may therefore be considered to be a Non-GAAP financial measure. Net debt to capital employed ratio without adjustments, was 18.4 per cent in 2004, compared to 22.4 per cent in 2003 and 30.2 per cent in 2002. See -Use and Reconciliation of Non-GAAP Financial Measures-Net debt to capital employed ratio below.
The group's borrowing needs are mainly covered through short-term and long-term securities issues, including utilization of a US Commercial Paper Program and a Euro Medium Term Note (EMTN) Program, and through draw-downs under committed credit facilities and credit lines. In 2004, USD 500 million of ten-year bonds was issued in the US 144A-market, equivalent to NOK 3.5 billion.
In February 2004, Statoil signed a project loan agreement amounting to USD 225 million, which includes a sponsor loan of USD 193 million from Statoil ASA, for the purposes of financing part of Statoil's obligations in respect of its participating share in the BTC pipeline project in Azerbaijan, Georgia and Turkey. This project loan is fully guaranteed by Statoil up to the time construction of the pipeline is complete and certain operational conditions have been fulfilled. The proceeds of the loan are made available to our wholly-owned subsidiary Statoil BTC Finance from the lender group through BTC Finance BV. Approximately USD 167 million was disbursed under this agreement in 2004. The project loan will be fully repaid by 2015.
After the effect of currency swaps, our borrowings are 100 per cent in US dollars. As of December 31, 2004, our long-term debt portfolio totaled NOK 31.5 billion, with a weighted average maturity of approximately 11 years and a weighted average interest rate of approximately 5.0 per cent per annum. As of December 31, 2003, our long-term debt portfolio totaled NOK 33.0 billion with a weighted average maturity of approximately 11 years and a weighted average interest rate of approximately 4.8 per cent per annum.
Our financing strategy considers funding sources, maturity profile, currency mix, interest rate risk management instruments and the liquidity reserve, and we use a multicurrency liability model (MLM) to manage debt-related risks. Accordingly, in general, we select the currencies of our debt obligations, either directly when borrowing or through currency swap agreements, in order to help hedge our foreign currency exposures with the objective of optimizing our debt portfolio based on underlying cash flow. Our borrowings are denominated in, or have been swapped into, US dollars, because the most significant part of our net cash flow is denominated in that currency. In addition, we hedge our interest rate exposures through the use of interest rate derivatives, primarily interest rate swaps, based on an approved range for the interest reset profile of our total loan portfolio.
New long-term borrowings totaled NOK 4.6 billion in 2004, NOK 3.2 billion in 2003 and NOK 5.4 billion in 2002. We repaid approximately NOK 6.6 billion in 2004, approximately NOK 2.8 billion in 2003 and approximately NOK 4.8 billion in 2002. At December 31, 2004, NOK 3.0 billion of our borrowings was due for repayment within one year, NOK 8.9 billion was due for repayment between two and five years and NOK 22.5 billion was due for repayment after five years. This compares to NOK 3.2 billion, NOK 9.3 billion and NOK 23.7 billion, respectively, as of December 31, 2003, and NOK 2.0 billion, NOK 8.5 billion and NOK 24.3 billion, respectively, as of December 31, 2002.
The treasury function provides a centralized service for overall funding activities, foreign exchange and interest rate management. Treasury operations are conducted within a framework of policies and guidelines authorized and reviewed regularly by our board of directors. Our debt portfolio is managed in cooperation with our corporate risk management department, and we use a number of derivative instruments. The internal control is reviewed regularly for risk assessment by our internal auditors. Further details regarding our risk management is provided in -Risk Management below.
Table of Principal Contractual Obligations and Other Commitments
The following table summarizes our principal contractual obligations and other commercial commitments as at December 31, 2004. The table below includes contractual obligations, but excludes derivatives and other hedging instruments. Obligations payable by Statoil to unconsolidated equity affiliates are included gross in the table below. Where Statoil, however, has both an ownership interest and transport capacity cost for a pipeline in the consolidated accounts, the amounts in the table include the transport commitments that exceed Statoil's ownership share. See also Item 11-Quantitative and Qualitative Disclosures about Market Risk.
Contractual obligations in respect of capital expenditure amount to NOK 20.8 billion of which payments of NOK 13.2 billion are due within one year.
The projected pension benefit obligation of the group is NOK 19 billion and the fair value of plan assets amounts to NOK 17.3 billion and total prepaid pensions net of unrealized losses and unrealized prior service cost amounts to NOK 1.3 billion as at December 31, 2004.
Impact of Inflation
Our results in recent years have not been substantially affected by inflation. Inflation in Norway as measured by the general consumer price index during the years ended December 31 2004, 2003 and 2002 was 1.1 per cent, 0.5 per cent and 2.8 per cent, respectively.
Critical Accounting Policies and Estimates
The consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States, which require Statoil to make estimates and assumptions. Statoil believes that of its significant accounting policies (see Note 2 to the consolidated financial statements), the following may involve a higher degree of judgment and complexity, which in turn could materially affect the net income if various assumptions were changed significantly.
Proved oil and gas reserves. Statoil's oil and gas reserves have been estimated by our experts in accordance with industry standards under the requirements of the US Securities and Exchange Commission (SEC). An independent third party has evaluated Statoil's proved reserves estimates and the results of such evaluation do not differ materially from Statoil's estimates. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions.
Proved reserves are used when calculating the unit of production rates used for depreciation, depletion, and amortization. Reserve estimates are also used when testing upstream assets for impairment. Future changes in proved oil and gas reserves, for instance as a result of changes in prices, could have a material impact on unit of production rates used for depreciation, depletion and amortization and for decommissioning and removal provisions, as well as for the impairment testing of upstream assets, which could have a material adverse effect on operating income as a result of increased deprecation, depletion and amortization or impairment charges.
Exploration and leasehold acquisition costs. In accordance with Statement of Financial Accounting Standards (FAS) No. 19, Statoil temporarily capitalizes the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. Statoil also capitalizes leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgments on whether these expenditures should remain capitalized or expensed in the period may materially affect the operating income for the period.
Unproved oil and gas properties are assessed quarterly and unsuccessful wells are expensed. Exploratory wells that have found reserves, but classification of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalized for more than one year. The main conditions are that either firm plans exist for future drilling in the license or a development decision is planned in the near future.
To illustrate the size of the applicable balance sheet items subject to the judgments described above and the recorded effects of our judgment on amounts capitalized in prior years, see the following table which provides a summary of capitalized exploration costs on assets in the exploration phase and the amount of previously capitalized exploration costs on assets in the exploration phase that have been expensed during the year:
Capitalized exploratory drilling expenditures that are pending the determination of proved reserves:
(1)In addition, in 2004 NOK 238 million in exploration expenditures related to unproved reserves was reclassified to construction in progress due to the fact that the development activity commenced prior to the expected determination of proved reserves in 2005.
(2)Capitalized exploration costs in suspense include signature bonuses and other acquired exploration rights of NOK 609 million, NOK 1,045 million and NOK 940 million as at the end of 2004, 2003 and 2002, respectively.
Impairment. Statoil has significant investments in long-lived assets such as property, plant and equipment and intangible assets, and changes in our expectations of future value from individual assets may result in some assets being impaired, and the book value written down to estimated fair value. Making judgments of whether an asset is impaired or not is a complex decision that rests on a high degree of judgment and a large extent of key assumptions.
Complexity is related to the modeling of relevant undiscounted future cash flows, to the determination of the extent of the asset for which impairment is to be measured, to consistent application throughout the group of relevant assumptions, and, in cases where the first test of undiscounted cash flows exceeding book value is not met, to establishing a fair value of the asset in question.
Impairment testing also requires long-term assumptions to be made concerning a number of often volatile economic factors such as future market prices, currency exchange rates, future output, etc. in order to establish relevant future cash flows. Long-term assumptions for major factors are made at group level, and there is a high degree of reasoned judgment involved in establishing these assumptions, in determining other relevant factors such as forward price curves or in estimating production outputs, and in determining the ultimate termination value of an asset. Likewise, establishing a fair value of the asset, when required, will require a high degree of judgment in many cases where there is no ready third party market in which to obtain the fair value of the asset in question.
The following is a summary of certain long-lived assets in Statoil's balance sheet at year-end and the cost of impairments recorded during the years 2002, 2003 and 2004 respectively:
Decommissioning and removal liabilities. Statoil has significant legal obligations to decommission and remove offshore installations at the end of the production period. Legal obligations associated with the retirement of long-lived assets are to be recognized at their fair value at the time that the obligations are incurred. Upon initial recognition of a liability, that cost is capitalized as part of the related long-lived asset and allocated to expense over the useful life of the asset.
It is difficult to estimate the costs of these decommissioning and removal activities, which are based on current regulations and technology. Most of the removal activities are many years into the future and the removal technology and costs are constantly changing. As a result, the initial recognition of the liability and the capitalized cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgment. As at year-end 2004, Statoil had recognized NOK 3.4 billion in increased assets, and liabilities related to asset retirement obligations amounting to NOK 18.6 billion.
Employee retirement plans. When estimating the present value of defined pension benefit obligations that represent a gross long-term liability in the Consolidated Balance Sheet, and indirectly, the period's net pension expense in the Consolidated Statement of Profit and Loss, Statoil makes a number of critical assumptions affecting these estimates. Most notably, assumptions made on the discount rate to be applied to future benefit payments, the expected return on plan assets and the annual rate of compensation increase have a direct and material impact on the amounts presented, and significant changes in these assumptions between periods can likewise have a material effect on the accounts.
Accumulated gains and losses in excess of 10 per cent of the greater of the projected benefit obligation (PBO) or the fair value of assets are amortized over the remaining service period of active plan participants. The implication of this is that although changes in balance sheet items may be significant due to changes in the assumptions described above, changes to the amounts amortized in the period are therefore not as significant.
Below is a specification of net losses not yet amortized, the annual amortizations of net losses due to assumptions made, and the key assumptions made for each year:
Derivative financial instruments and hedging activities. Statoil recognizes all derivatives on the balance sheet at fair value. Changes in fair value of derivatives that do not qualify as hedges are included in income.
The application of relevant rules requires extensive judgment and the choice of designation of individual contracts as qualifying hedges can impact the timing of recognition of gains and losses associated with the derivative contracts, which may or may not correspond to changes in the fair value of our corresponding physical positions, contracts and anticipated transactions, which are not required to be recorded at market value in accordance with Statement No. 133. Establishment of non-functional currency swaps in our debt portfolio to match expected underlying cash flows may result in gains or losses in the profit and loss statement as hedge accounting is not allowed, even if the associated economical risk of the transactions is considered.
When not directly observable in the market or available through broker quotes, the fair value of derivative contracts must be computed internally based on internal assumptions as well as directly observable market information, including forward and yield curves for commodities, currencies and interest. Although the use of models and assumptions are according to prevailing guidelines provided by FASB and best estimates, changes in internal assumptions and forward curves could have material effects on the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in corresponding income or loss in the statement of profit and loss.
See -Risk Management section below and Item 11-Quantitative and Qualitative Disclosures about Market Risk for details on the sensitivities of recognized assets and liabilities to market risks and the extent to which we assess market values of derivatives on sources other than quoted market prices.
Corporate income taxes. Statoil annually incurs significant amounts of corporate taxes payable to various jurisdictions around the world, and also recognizes significant changes to deferred tax assets and deferred tax liabilities, all according to our current interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon our ability to properly apply at times very complex sets of rules, to recognize changes in applicable rules and, in the case of certain valuation allowances, our ability to project future earnings from activities that may apply loss carry forward positions against future income taxes.
The following is a summary of income tax assets and liabilities recognized in the Consolidated Balance Sheet, as well as the annual tax expense recorded in the Consolidated Statement of Profit and Loss:
Off-Balance Sheet Arrangements
As a condition for being awarded oil and gas exploration and production licenses, participants may be committed to drill a certain number of wells. At the end of 2004, Statoil was committed to participate in 13 wells off Norway and 10 wells abroad, with an average ownership interest of approximately 50 per cent. Statoil's share of estimated expenditures to drill these wells amounts to approximately NOK 2.3 billion. Additional wells that Statoil may become committed to participating in depending on future discoveries in certain licenses are not included in these numbers.
Statoil has entered into agreements for pipeline transportation for most of its prospective gas sale contracts. These agreements ensure the right to transport the production of gas through the pipelines, but also impose an obligation to pay for booked capacity. In addition, the group has entered into certain obligations for entry capacity fees and terminal, processing, storage and vessel transport capacity commitments. The corresponding expense for 2004 was NOK 3,701 million.
In 2004, Statoil signed an agreement with the US-based energy company Dominion regarding additional capacity at the Cove Point liquefied natural gas (LNG) terminal in the USA. The agreement involves annual terminal capacity of approximately 7.7 billion cubic meters of gas for a 20-year period with planned start-up in 2008, and is subject to approval from US authorities. Pending such approval, no obligations related to the additional Cove Point capacity have been included in Liquidity and Capital Resources-Table of Principal Contractual Obligations and Other Commercial Commitments at year-end 2004.
Transport capacity and other minimum nominal obligations at December 31, 2004 are included in the above-mentioned table.
Overview. We are exposed to a number of different market risks arising from our normal business activities. Market risk is the possibility that changes in currency exchange rates, interest rates, refining margins, petrochemical margins and oil and natural gas prices will affect the value of our assets, liabilities or expected future cash flows. We are also exposed to operational risk, which is the possibility that we may experience, among others, a loss in oil and gas production or an offshore catastrophe. Accordingly, we use a "top-down" approach to risk management, which highlights our most important market and operational risks, and a sophisticated risk optimization model to manage these risks.
We have developed a comprehensive model, which encompasses our most significant market and operational risks and takes into account correlation, different tax regimes, capital allocation on various levels and value at risk, or VaR, figures on different levels, with the goal of optimizing risk exposure and return. Our model also utilizes Sharpe ratios, which provide a risk-adjusted return measure in the context of a specific risk taken, rather than an absolute rate of return, to measure the potential risks of various business activities. See details of our financing strategy above concerning the objective of our debt portfolio to mitigate currency exchange risks. Our Corporate Risk Committee, which is headed by our Chief Financial Officer and which includes, among others, representatives from our principal business segments, is responsible for reviewing, defining and developing our strategic market risk policies. The Corporate Risk Committee meets monthly to determine our risk management strategies, including hedging and trading strategies and valuation methodologies.
We divide risk management into insurable risks which are managed by our captive insurance company operating in the Norwegian and international insurance markets, tactical risks, which are short-term trading risks based on underlying exposures and which are managed by line management, and strategic risks, which are long-term fundamental risks and are monitored by our Corporate Risk Committee, which advises and recommends specific actions to our Executive Committee. To address our tactical and strategic risks, we have developed policies aimed at managing the volatility inherent in certain of these natural business exposures and in accordance with these policies we enter into various transactions using derivative financial and commodity instruments (derivatives). Derivatives are contracts whose value is derived from one or more underlying financial instruments, indices or prices, which are defined in the contract.
Strategic Market Risks. We are exposed to strategic risks, which we define as long-term risks fundamental to the operation of our business. Strategic market risks are reviewed by our Corporate Risk Committee with the objective of avoiding sub-optimization, reducing the likelihood of experiencing financial distress and supporting the group's ability to finance future growth even under adverse market conditions. Based on these objectives, we have implemented policies and procedures designed to reduce our overall exposure to strategic risks. For example, our multicurrency liability management model discussed under -Liquidity above seeks to optimize our debt portfolio based on expected future corporate cash flow and thereby serves as a significant strategic risk management tool. In addition, our downside protection program for crude oil price risk is intended to ensure that our business will remain robust even in the case of a drop in the price of crude oil.
Tactical Market Risks. All tactical risk management activities occur within and are continuously monitored against established mandates.
Commodity price risk. Commodity price risk constitutes our most important tactical risk. To minimize the commodities price volatility and match costs with revenues, we enter into commodity-based derivative contracts, which consist of futures, options, over-the-counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity.
Derivatives associated with crude oil and petroleum products are traded mainly on the International Petroleum Exchange (IPE) in London, the New York Mercantile Exchange (NYMEX), in the OTC Brent market, and in crude and refined products swaps markets. Derivatives associated with natural gas and electricity are mainly OTC physical forwards and options, Nordpool forwards, and futures traded on the NYMEX and IPE.
Foreign exchange and interest rate risk. We are also subject to interest rate risk and foreign exchange risk. Interest rate risk and currency risk are assessed against mandates based on a pre-defined scenario. In market risk management and in trading, we use only well-understood, conventional derivative instruments. These include futures and options traded on regulated exchanges, and OTC swaps, options and forward contracts.
Foreign exchange risk. Fluctuations in exchange rates can have significant effects on our results. Our cash flows are largely in currencies other than NOK, primarily US dollars. Cash receipts in connection with oil and gas sales are mainly in foreign currencies, while cash disbursements are to a large extent in NOK. Accordingly, our exposure to foreign currency rates exists primarily with US dollars versus Norwegian kroner, European euro, Danish kroner, Swedish kroner and UK pounds sterling. We enter into various types of foreign exchange contracts in managing our foreign exchange risk. We use forward foreign exchange contracts primarily to risk manage existing receivables and payables, including deposits and borrowing denominated in foreign currencies.
Interest rate risk. The existence of assets and liabilities earning or paying variable rates of interest expose us to the risk of interest rate fluctuations. We enter into various types of interest rate contracts in managing our interest rate risk. We enter into interest rate derivatives, particularly interest rate swaps, to alter interest rate exposures, to lower funding costs and to diversify sources of funding. Under interest rate swaps, we agree with other parties to exchange, at specified intervals, the difference between interest amounts calculated by reference to an agreed notional principal amount and agreed fixed or floating interest rates.
Fair market values of financial and commodity derivatives. Fair market values of commodity based futures and exchange traded option contracts are based on quoted market prices obtained from the New York Mercantile Exchange or the International Petroleum Exchange. The fair values of swaps and other commodity over-the-counter arrangements are established based on quoted market prices, estimates obtained from brokers, and other appropriate valuation techniques. Where Statoil records elements of long-term physical delivery commodity contracts at fair market value under the requirements of FAS 133, such fair market value estimates are based on quoted forward prices in the market, underlying indexes in the contracts, and assumptions of forward prices and margins where market prices are not available. Fair market values of interest and currency swaps and other instruments are estimated based on quoted market prices, estimates obtained from brokers, prices of comparable instruments, and other appropriate valuation techniques. The fair value estimates approximate the gain or loss that would have been realized if the contracts had been closed out at year-end, although actual results could vary due to assumptions used.
The following table contains the net fair market value of non-exchange traded (i.e., over-the-counter) commodity and financial derivatives as so accounted for under FAS 133, as at December 31, 2004, based on maturity of contracts and the source of determining the fair market value of contracts, respectively:
In the above table, other external sources for commodities mainly relate to broker quotes. The fair market values of interest and currency swaps and other financial derivatives are computed internally by means of standard financial system models and based consistently on quoted market yield and currency curves.
The following table contains a reconciliation of changes in the fair market values of all commodity and financial derivatives, including exchange traded derivatives in the books at either December 31, 2004, or December 31, 2003, net of margin calls. Derivatives entered into and subsequently terminated during the course of the year 2004 have not been included in the table.
For further information, see Item 11-Quantitative and Qualitative Disclosures about Market Risk.
Derivatives and Credit risk. Futures contracts have little credit risk because organized exchanges are the counter-parties. The credit risk from Statoil's OTC commodity-based derivative contracts derives from the counter-party to the transaction. Brent forwards, other forwards, swaps and all other OTC instruments are traded subject to internal assessment of creditworthiness of counter-parties, which are primarily oil and gas companies and trading companies.
Credit risk related to derivative instruments is managed by maintaining, reviewing and updating lists of authorized counter-parties by assessing their financial position, by monitoring credit exposure for counter-parties, by establishing internal credit lines for counter-parties, and by requiring collateral or guarantees when appropriate under contracts and required by internal policies. Collateral will typically be in the form of cash or bank guarantees from first class international banks. As at year-end 2004, we had called and received a total of NOK 3 billion in cash as collateral for unrealized gains on OTC derivatives.
Credit risk from interest rate swaps and currency swaps, which are OTC transactions, derive from the counter-parties to these transactions. Counter-parties are highly-rated financial institutions. The credit ratings are, at a minimum, reviewed annually and counter-party risk is monitored to ensure exposure does not exceed credit lines and complies with internal policies. Non-debt related foreign currency swaps usually have terms of less than one year, and the terms of debt related interest swaps and currency swaps are up to 25 years, in line with that of corresponding hedged or risk managed long-term loans.
The following table contains the fair market value of OTC commodity and financial derivative assets, net of netting agreements and collateral as at December 31, 2004, split by our assessment of the counter-party's credit risk:
Credit rating categories in the table above are based on the Statoil group's internal credit rating policies, and do not correspond directly with ratings issued by the major Credit Rating Agencies. Internal ratings are harmonized with external ratings where available, but could occasionally vary somewhat due to internal assessments. Consistent with Statoil policies, commodity derivative counter-parties have been assigned credit ratings corresponding to those of their respective parent companies, while there will not necessarily be a parent company guarantee from such parent companies if highly rated.
Operational Risks. We are also exposed to operational risks, including reservoir risk, risk of loss of oil and gas production and offshore catastrophe risk. All of our installations are insured, which means that replacement cost will be covered by our captive insurance company, which also has a reinsurance program. Under this reinsurance program, as of December 31, 2004, approximately 69 per cent of the approximately NOK 193 billion total insured amount was reinsured in the international reinsurance markets. Our captive insurance company also works with our corporate risk management department to manage other insurable operational risks.
Like any other licensee, Statoil has unlimited liability for possible compensation claims arising from its offshore operations, including transport systems. Statoil has taken out insurance to cover this liability up to approximately USD 0.8 billion (NOK 4.8 billion) for each incident, including liability for claims arising from pollution damage. Most of the group's production installations are covered through Statoil Forsikring a.s, which reinsures a major part of the risk in the international insurance market. Approximately 29 per cent of the risk is retained.
Statoil Forsikring a.s is a member of two mutual insurance companies, Oil Insurance Ltd and sEnergy Insurance Ltd. Membership of these companies means that Statoil Forsikring is liable for its proportionate share of any losses which might arise in connection with the business operations of the companies. Members of the mutual insurance companies have joint and several liability for any losses that arise in connection with the insured operations of the member companies.
Research and Development
In addition to the technology developed through field development projects, a substantial amount of our research is carried out at our research and technology development center in Trondheim, Norway. Our internal research and development is done in close cooperation with Norwegian universities, research institutions, other operators and the supplier industry.
Research expenditures were NOK 1,027 million, NOK 1,004 million and NOK 736 million in 2004, 2003 and 2002, respectively.
This section contains a discussion of our corporate targets. We use these targets in order to measure our progress in enhancing production, utilizing capital efficiently and enhancing operational efficiency. We have announced targets for the fiscal year 2004 for the measures normalized return on average capital employed (normalized ROACE), production, finding and development cost, normalized production cost and reserve replacement rate. In late 2004 the executive committee set forth new targets for the fiscal year 2007 for the measures normalized return on average capital employed (normalized ROACE), production and normalized production cost. This section contains a discussion of those target measures and reports the results of those measures for the current period. For a discussion of historical and projected gross investments, see -Trend Information below.
The following discussion of corporate targets uses several measures, which are "non-GAAP financial measures" as defined by the U.S. Securities and Exchange Commission. These are return on average capital employed (ROACE), normalized return on average capital employed (normalized ROACE), normalized production cost per barrel and net debt to capital ratio. For more information on these measures and for a reconciliation of these measures to measures calculated in accordance with US GAAP, see -Use and Reconciliation of Non-GAAP Financial Measures below.
Summary of targets -2004
We have been targeting:
Further, we had committed ourselves to pursuing the following objectives to enhance operational efficiency through 2004:
The 2004 targets (other than the reserve replacement rate target) were based on a continued organic development of Statoil and excluded possible effects related to major acquisitions and dispositions. For a discussion of performance against the targets, see below.
Summary of targets -2007
We are targeting:
Further, we are committed to enhancing operational efficiency through 2007 by:
The 2007 targets represent Statoil's assets as at the end of 2004. However, on a going-forward basis the 2007 targets are based on a continued organic development of Statoil and exclude possible effects related to any additional, but not known, major acquisitions or dispositions. Such major transactions may affect our targets materially and cause us to revise our targets as a result of the impact of such acquisitions or dispositions.
For the sake of comparability, the real figures for 2004 shown in the second column in the table below have been normalized based on the new set of assumptions:
The forecasted production growth to 2007 is based on the current understanding of our reservoirs, our planned investments and development projects. There are a number of factors that could cause actual results and developments to differ materially from the targets included here, 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. One of the main factors which could cause results to differ from our expectations would be possible delays in sanctioned development projects. For further discussion, see Item 3 -Risk factors.
Return on Average Capital Employed
Our business is capital intensive. Furthermore, our capital expenditures include several significant projects that are characterized by lead times of several years and expenditures that individually may involve large amounts. Given this capital intensity, we use Return on Average Capital Employed, or ROACE, as a key performance indicator to measure our success in utilizing capital. We define ROACE as follows:
Average capital employed reflects an average of capital employed at the beginning and the end of the financial period. In the calculation of average capital employed, Statoil makes certain adjustments to net interest-bearing debt, which makes the figure a Non-GAAP financial measure. For a reconciliation of the adjusted net interest-bearing debt to the most comparable GAAP measure, see -Use and Reconciliation of Non-GAAP Financial Measures below. Using average capital employed without these adjustments to net interest-bearing debt, our ROACE for 2004 was 23.6 per cent. Our historic ROACE using average capital employed with these adjustments for 2004, 2003 and 2002 was 14.9 per cent, 18.7 per cent and 23.5 per cent, respectively.
ROACE and normalized ROACE are non-GAAP financial measures. See -Use and Reconciliation of Non-GAAP Financial Measures.
For purposes of measuring our performance against our 2004 ROACE target, we have been assuming an average realized oil price of USD 16 per barrel, natural gas price of NOK 0.70 per scm, refining margin of USD 3.0 per barrel, Borealis margin of EUR 150 per tonne, and a NOK/USD exchange rate of 8.20. All prices and margins are adjusted for inflation from 2000. In the calculation of the normalized return, adjustments are made to exclude items of a non-frequent nature. These items are viewed as activities or events which management considers as being of such a nature that their inclusion into the ROACE calculation will not provide a meaningful indication of the company's underlying performance. The 2004 target is based on organic development and therefore the effects of the acquisition of the Algerian assets In Salah and In Amenas as well as the acquisition of 50 per cent of SDS from ICA/Ahold are excluded. Normalization is done in order to exclude factors that Statoil cannot influence from its performance targets. For reconciliation of the ROACE and normalized ROACE figures to items calculated in accordance with GAAP, see the table "ROACE calculation" in -Use and Reconciliation of Non-GAAP Financial Measures below. We were targeting a 12 per cent ROACE on a normalized basis.
Normalized ROACE was 10.8 per cent in 2002, 12.4 per cent in 2003 and 12.3 per cent in 2004.
In order to achieve our set of targets for 2007, including ROACE, and support our longer term ambitions, we continue to aim to allocate capital only to those projects that meet our financial return criteria.
Our ROACE in any financial period and our ability to meet our target ROACE will be affected by our ability to generate net income. Our level of net income is subject to numerous risks and uncertainties as described above. These risks include, among others, fluctuation in demand, retail margin, changes in our oil and gas production volumes and trends in the international oil industry.
As described above, Statoil introduced new targets for 2007, including a normalized ROACE of 13 per cent. When normalizing the reported ROACE we are now assuming an oil price of USD 22 per barrel, natural gas price of NOK 0.90 per scm, refining margin (FCC) of USD 5.0 per barrel, Borealis margin of EUR 140 per tonne and a NOK/USD exchange rate of 6.75. All prices and margins are adjusted for inflation from 2004. These changed assumptions for purposes of our 2007 targets reflect changes in the underlying prices and margins from the assumptions made when we set our targets for 2004. These assumptions do not reflect actual prices and margins at the time the assumptions were set or at any specific point in time and do not comprise our expectations with respect to the future movements of such prices and margins, but are based on movements over a broader time frame and function to allow comparability across periods.
Improvement program. In 2001, Statoil specified a set of improvement measures that at the time were deemed necessary to reach the target of return on average capital employed in 2004 of 12 per cent, based on normalized assumptions. To meet this target, Statoil determined that, among other improvements, it would need to reduce certain costs and increase revenue items by a total of NOK 3.5 billion in 2004, compared to 2001.
A number of small improvements were targeted in a large number of areas. In some cases the improvements were compared against the 2001 reported levels, e.g., lifted volumes or production unit cost. In other areas where improvements were targeted, it was necessary to make assumptions about what the result may have been in 2004 if no actions had been taken, e.g. assumptions regarding increased production unit costs due to expected increase in water production in 2004. Efforts were then made to improve the performance against these base assumptions. In any case the effect of the Algerian transaction in 2003, completed in 2004, has been excluded.
At the end of 2004, Statoil is satisfied with having identified annual, sustainable improvements in both costs and revenues, which it estimated will contribute NOK 3.2 billion of improvements compared to a target of NOK 3.5 billion for 2004, which has contributed to reaching the target of a normalized return on capital employed of 12 per cent for 2004. The main reason for not meeting the corporate target of NOK 3.5 billion relates to the fact that the International E&P business area did not achieve its targeted improvement, as described in the business segment section of International E&P in Item 5.
Production cost per boe for the last 12 months was USD 3.49 per boe for the year 2004, USD 3.17 per boe for the year 2003 and USD 2.9 per boe for the year 2002. Correspondingly, the production costs in NOK were NOK 23.5 per boe for the year 2004, NOK 22.4 per boe for the year 2003, and NOK 23.2 per boe in 2002. Normalized to a NOK/USD exchange rate of 8.20, in order to exclude currency effects, the production cost for 2004 was USD 2.96 per boe, compared to USD 2.77 per boe for 2003 and USD 2.84 per boe for 2002. Normalized production cost is a non-GAAP financial measure as a result of its normalization at a set NOK/USD exchange rate. See -Use and reconciliation of Non-GAAP Financial Measures.
The corporate target for normalized production cost was USD 2.7 per boe for 2004. Both the target and the reported production cost exclude all effects from production from the In Salah field in Algeria. The reason for not reaching the target for unit of production cost is partly due to the extension of the production from the Lufeng field, as well as lower total lifting for the group than assumed when the target was set in 2001.
Finding and development cost
Statoil's finding and development costs in 2004 were 13.7 per boe in 2004, compared to USD 7.7 per boe in 2003, and USD 5.3 per boe in 2002. The average finding and development cost for the last three years was USD 8.5 per boe in 2004, compared to USD 5.9 per boe in 2003 and USD 6.2 in 2002.
The target for 2004 was a finding and development cost below USD 6.0. The higher finding and development cost compared to the target is related to, among other factors, the effects on reserves booking under some Profit Sharing Agreement (PSA) contracts, due to the increased oil prices in 2004. Under PSA contracts the volumes of entitlement oil are reduced when oil prices rise, which in turn reduces the booking of reserves. Furthermore, the reduction in the NOK/USD exchange rate resulted in higher finding and development costs in USD for the upstream investments on the NCS than was assumed when the targets were set in 2001.
The finding and development cost per barrel is calculated using costs of exploration and development divided by new proved reserves, according to the SEC definition, excluding major reserves purchases and sales. A description of reserves booking and the limitations of financial measures that include reserves estimates, is provided under "Reserves Replacement Ratio" below. See also the supplementary information on Oil and Gas Production Activities starting on page F-33 for details regarding principles for reserves booking.
Reserve replacement ratio
Proved oil and gas reserves were estimated to be 4,289 million boe at the end of 2004, compared to 4,264 million boe at the end of 2003 and 4,267 million boe at the end of 2002.
Proved reserves and changes to proved reserves are estimated in accordance with SEC definitions. The reserve replacement ratio is defined as the sum of proved reserves additions and revisions, divided by produced volumes in any given period.
Changes in proved reserves estimates most commonly originate from revisions of estimates due to improved production performance, extensions of proved areas through drilling activities, or inclusion of proved reserves in new discoveries through sanctioning of development projects. These are sources of proved reserves additions that result from continuous business processes, and could be expected to continue to add reserves at some level in the future.
Proved reserves may also be added or subtracted through the acquisition or disposition of assets.
Changes in reserves may also originate from factors outside of management control, such as changes in oil and gas prices. While higher oil and gas prices normally allow more oil and gas to be recovered from the accumulations, Statoil's proved oil and gas reserves under PSAs and similar contracts will generally decrease as a result. This reflects the fact that we will receive smaller quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of the increased oil and gas prices. These changes are included in the revisions category in the table below.
Reserves in new discoveries are normally booked only when regulatory approval has been received, or when such approval is imminent. Most of the reserve additions are expected to be produced over the next 5-10 years, with some projects having time spans of up to 20-25 years.
Below is a table showing the reserves additions in each change category relating to the reserve replacement ratio for the period 2002-2004.
A total of 428 mmboe proved reserves was added during 2004, of which 305 mmboe were proved developed reserves. The remaining 123 mmboe were proved undeveloped reserves.
The reserve replacement rate was 106 per cent in 2004, compared to 99 per cent in 2003 and 98 per cent in 2002. The average replacement rate for the last three years was 101 per cent, including purchases and sales. The target for reserve replacement was an average of 100 per cent for the three years from 2002 to 2004.
(1)Reserve replacement rate for International E&P is adjusted for the sale of Statoil Energy Inc. in 2000.
Management has historically used the reserve replacement ratio and finding and development cost per barrel as target measures against which the company's progress is measured on an annual basis. These measures are no longer viewed by management as providing useful information to investors regarding Statoil's progress in enhancing operational efficiency, and are therefore not included in the set of targets for 2007. The usefulness of these measures is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity relating to the timing of project sanctions, and the time lag between exploration expenditures, booking of reserves and capital expenditures.
Total oil and natural gas production was 1,106,000 boe in 2004, compared to 1,080,000 boe per day in 2003, and 1,074,000 boe per day in 2002.
The production target for the group for 2004 was 1,120,000 boe per day, excluding the production contribution from In Salah, which in 2004 amounted to 13,000 boe per day. Statoil's production excluding In Salah was therefore 1,093,000 boe per day in 2004. The shut-down on Snorre and Vigdis and the rig strike contributed to the group not reaching its target.
Our expected production growth through 2007 is based on the current characteristics of our reservoirs, our planned investments and development projects. Including the acquisition of interests in the two Algerian assets In Salah and In Amenas, the production target for 2007 is set at 1,400,000 boe per day.
Achieving the targeted growth in the coming years will require an increase in investments from the current level which will consequently depress ROACE in 2005 and 2006. Of the projects expected to contribute to reaching this production target of 1,400,000 boe per day for 2007 nearly 100 per cent of these projects have already been sanctioned.
Set forth below are our capital expenditures in our four principal business segments for 2001-2004, including the allocation per segment as a percentage of gross investments.
Total investments in the period 2001-2004 amounted to NOK 92 billion (excluding major investments related to the acquisition of assets) compared to the NOK 95 billion level, which was the level communicated at the IPO in 2001.
Capital expenditures per segment in the years ended December 31, 2002-2004:
(1) 2002 and 2003 figures for the E&P Norway, International E&P and Natural Gas segments are restated due to reclassification of investments and due to the transfer of international mid- and downstream activities from International E&P to Natural Gas and Kollsnes from E&P Norway to Natural Gas.
Future capital expenditures are expected to amount to approximately NOK 100-105 billion over the three year period from 2005-2007, with an expected distribution of approximately 50 per cent in E&P Norway, 40 per cent in International E&P and 5 per cent each in Natural Gas and Manufacturing and Marketing.
The group is aiming for a step-up in exploration activities in coming years, and exploration expenditure in 2005 is expected to amount to NOK 4 billion, and is expected to stay at a level of approximately NOK 3.5 - 4 billion per year in 2006 and 2007. The group expects to participate in the drilling of 30-35 wells in 2005. However, no guarantees can be given with regards to the number of wells drilled, the cost per well and the results of drilling. Uncertainty related to the results of past and future drilling will influence the amount of exploration expenditure capitalized and expensed. See Critical Accounting Principles and Estimates - Exploration and leasehold acquisition costs above.
Statoil uses the "Successful efforts"- method of accounting for oil and natural gas producing activities. Expenditures to drill and equip exploratory wells are capitalized until it is clarified whether there are proved reserves. Expenditures to drill exploratory wells that do not find proved reserves, and geological and geophysical and other exploration expenditures are expensed. Unproved oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but classification of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalized for more than one year. The main conditions are that either firm plans exist for future drilling in the license or a development decision is planned in the near future.
Production cost per barrel is expected to increase on the NCS as a result of mature fields, if no measures are taken to reduce cost. The corporate initiatives introduced in 2004 are, among other things, expected to reduce cost levels. New international fields are expected in aggregate to reduce the group's production cost per barrel.
Production contribution from the international portfolio is expected to increase in the period up to 2007 to approximately 300,000 barrels per day, which is based on production from already sanctioned projects. Total production is expected to increase to 1,400,000 barrels per day, not necessarily as a result of the period's exploration activity.
This section describes our estimated capital expenditure for 2005 in respect of potential capital expenditure requirements for the principal investment opportunities available to us and other capital projects currently under consideration. The figure is based on an organic development of Statoil and excludes possible expenditures related to acquisitions. Therefore, the expenditure estimates and descriptions with respect to investments in the segment descriptions below could differ materially from the actual expenditures.
E&P Norway. A substantial portion of our 2005 capital expenditure is allocated to the ongoing development projects in Kristin, Snøhvit, Ormen Lange, Norne Satellites and the satellites Skinfaks and Rimfaks which will be tied back to Gullfaks C, as well as the late-life projects at Statfjord and Gullfaks and the Troll pre-compression. For more information on these projects, see Item 4-Information on the Company-Business Overview-Exploration and Production Norway.
International E&P. We currently estimate that a substantial portion of our 2005 capital expenditure will be allocated to the following ongoing and planned development projects: In Amenas, Azeri-Chirag-Gunashli including the Baku-Tbilisi-Ceyhan pipeline, Shah Deniz, Dalia and Kizomba. For more information on these projects, see Item 4-Information on the Company-Business Overview-International Exploration and Production.
Natural Gas Our main focus will be to increase the capacity and flexibility of our gas transportation and processing infrastructure. This will be done through expansion of the Kårstø processing plant, the development of a new pipeline to the UK, the Aldbrough gas storage project on the east coast of England and the South Caucasus pipeline related to the Shah Deniz field. For more information on these projects, see Item 4-Information on the Company-Business Overview-Natural Gas.
Manufacturing and Marketing We are focusing our capital expenditure on our retail network and upgrading of the refineries to increase flexibility and increase the value of the refined products.
Finally, it should be noted that we may alter the amount, timing or segmental or project allocation of our capital expenditures in anticipation or as a result of a number of factors outside our control including, but not limited to:
Use and Reconciliation of Non-GAAP Financial Measures
Statoil is subject to SEC regulations regarding the use of "Non-GAAP financial measures" in public disclosures. Non-GAAP financial measures are defined as numerical measures that either exclude or include amounts that are not excluded or included in the comparable measures calculated and presented in accordance with GAAP.
The following financial measures may be considered non-GAAP financial measures:
Statoil uses ROACE to measure the return on capital employed regardless of whether the financing is through equity or debt. This measure is viewed by the company as providing useful information, both for the company and investors, regarding performance for the period under evaluation. Statoil makes regular use of this measure to evaluate its operations. Statoil's use of ROACE should not be viewed as an alternative to income before financial items, other items, income taxes and minority interest, or to net income, which are the measures calculated in accordance with generally accepted accounting principles or ratios based on these figures.
Statoil uses normalized ROACE to measure the return on the capital employed, while excluding the effects of market developments over which Statoil has no control. Effects of changes in oil price, natural gas price, refining margin, Borealis margin and the NOK/USD exchange rate are therefore excluded from the normalized figure.
This measure is viewed by the company as providing a better understanding of Statoil's underlying performance over time and across periods, by excluding from the performance measure factors that Statoil cannot influence. Statoil management makes regular use of this measure to evaluate its operations.
The figures used for calculating the normalized ROACE towards the 2004 target were (each adjusted for inflation from 2000):
By keeping certain prices which are key value drivers, as well as the important NOK/USD exchange rate constant, Statoil is able to utilize this measure to focus on operating cost and efficiency improvements, and is able to measure performance on a comparable basis across periods. Such a focus would be more challenging to maintain in periods in which prices are high and exchange rates are favorable. In the period 2001 to the fourth quarter of 2004, during which Statoil has been using normalized ROACE as a tool of measuring performance, the normalization procedures have on average resulted in lower normalized earnings compared to the earnings based on realized prices. Normalized results, however, should not be seen as an alternative to measures calculated in accordance with GAAP when measuring financial performance. The company reviews both realized and normalized results, when measuring performance. However, the company finds the normalized results to be especially useful when realized prices, margins and exchange rates are above the normalized set of assumptions. Normalized ROACE is based on organic development and the figures for 2003 and 2004 exclude the effects related to the acquisition of the two Algerian assets, In Salah and In Amenas, as well as the 2004 acquisition of ICA/Ahold's 50 per cent share in SDS, as these major acquisitions were not known when the measures were set, and the company started reporting on progress made towards the 2004 target. In 2004, the gain related to the sale of the shares in VNG in the first quarter was excluded from the calculation of the normalized ROACE.
Statoil also defines certain items to be of such a nature that they will not provide a good indication of the company's underlying performance when included in the key indicators. These items are therefore excluded from calculations of adjusted and normalized ROACE.
The following table shows our ROACE calculation based on reported figures and normalized figures:
(1)Adjustments made in the 2002 figures consisted of the sale of the exploration and operations activity on the Danish continental shelf (profit NOK 1.0 billion before tax and NOK 0.7 billion after tax), as well as a write-down of the LL652 field in Venezuela of NOK 0.8 billion before tax (NOK 0.6 billion after tax). Adjustments made in the 2003 figures consisted of the positive effect of the change in the Removal Grants Act in the second quarter of 2003 of NOK 0.7 billion after tax.
(2)See Use and Reconciliation of Non-GAAP Financial Measures-Net debt to capital employed below for a reconciliation of average capital employed and adjusted average capital employed. Average capital employed used when calculating ROACE is the average of the opening and closing balance of a year.
(3)The adjustment corresponds to approximately 50 per cent of the capital employed effect. The capital employed related to these acquisitions was included in the closing balance of the period, but only to a limited extent in the opening balance, which entails an effect on average capital employed of approximately 50 per cent of this amount.
Normalized production cost per barrel in USD is used to evaluate the underlying development in the production cost. Statoil's production costs are mainly incurred in NOK. In order to exclude currency effects and to reflect the change in the underlying production cost, the NOK/USD exchange rate is held constant.
Normalized production costs per boe is in the table below reconciled to the most comparable GAAP measure, production cost per boe.
Net debt to capital employed ratio
The calculated net debt to capital employed ratio is viewed by the company as providing a more complete picture of the group's current debt situation than gross interest-bearing debt. The calculation uses balance sheet items related to total debt and adjusts for Cash, cash equivalents and short-term investments. Two additional adjustments are made for two different reasons:
The net interest-bearing debt adjusted for these two items is included in the average capital employed, which is also used in the calculation of ROACE and normalized ROACE.
The table below reconciles net interest-bearing debt, capital employed and net debt to capital employed ratio to the most directly comparable financial measure or measures calculated in accordance with GAAP.
(1)Adjustment for inter-company project financing through an external bank.
(2)Adjustment made for deposits received for financial derivatives. Although these deposits are classified as liquid assets, they are interest-bearing and are therefore not excluded from gross interest-bearing debt when calculating our net interest-bearing debt.
Item 6 Directors, Senior Management and Employees
Directors and Senior Management
Our management is vested in our board of directors and our Chief Executive Officer. The Chief Executive Officer is responsible for the day-to-day management of our company in accordance with the instructions, policies and operating guidelines set out by our board of directors.
The business address of the directors, executive officers and corporate assembly members is c/o Statoil at the corporate headquarters in Stavanger, Norway.
Board of Directors
Our articles of association require that our board of directors consists of a minimum of five and a maximum of 11 members. Currently, we have 9 directors. The members of the board have extensive and relevant experience from Norwegian and international business activities. Members of the board of directors serve two-year terms. The members of the board are primarily recruited from the Norwegian business community, and our executive management is not represented on the board. As required by Norwegian companies law, our employees are entitled to be represented by three board members. The corporate assembly has elected the current board of directors. The current term of office for all directors expires in May 2006. There are no directors' service contracts that provide for benefits upon termination of employment.
Our directors, their place of residence, age and their position are identified below.
(1) Elected by the employees.
Jannik Lindbæk was appointed Chairman of the board with effect from November 1, 2003. Mr. Lindbæk has extensive experience both as a business leader and from international activities, as well as knowledge of the oil and gas business. From 1976 to 1985 he was President and Chief Executive Officer in the Storebrand Group, a leading player in the Norwegian markets for general insurance, pensions, life and health insurance, banking and asset management. From 1986 to 1994 Mr. Lindbæk was Chief Executive Officer in Nordiska Investeringsbanken (Nordic Investment Bank), Helsinki, Finland and from 1994 to 1999 he was Executive Vice President of International Finance Corporation (World Bank Group), Washington D.C. He has been Chairman of the board of Gaz de France Norge, Saga Petroleum and Den norske Bank. He is at present Vice Chairman of DnB NOR ASA. Mr. Lindbæk is Chairman of the Board of Bergen International Festival, Transparency International, Norway and Transparency International Norge.
Kaci Kullmann Five was elected to the board of directors in August 2002. In the period September 29, 2003 to November 1, 2003 she was acting chairman of the board of directors and effective November 1, 2003, she was appointed Deputy Chairman of the board of directors. Ms. Five is a public affairs consultant. In the period 1981 to 1997 she was a member of the Norwegian Parliament and in the period 1989 to 1990 she was minister for Trade and Shipping in the Norwegian Government. Ms. Five was leader of the Norwegian Conservative Party from 1991 to 1994. Currently, Ms. Five is a director of the boards of NMD Grossisthandel, Vitus Apotek AS, Asker og Bærum Budstikke ASA and Bluewater Insurance ASA. She is also a member of the Norwegian Nobel Committee appointed by the Norwegian Parliament.
Finn A Hvistendahl was elected to the board of directors in April 1999 and re-elected in May 2002. Mr. Hvistendahl is a business development consultant in Oslo. Previously, he held senior positions in Norsk Hydro and was Chief Executive Officer of Den norske Bank ASA. Currently, he is Chairman of the board of directors of Kredittilsynet (The Financial Supervisory Authority of Norway) and director of Dyno Nobel AS. Mr. Hvistendahl has an engineering degree in industrial chemistry from The Norwegian University of Science and Technology.
Grace Reksten Skaugen was elected to the board of directors in June 2002. Ms. Skaugen is an independent consultant. She was a Director within Corporate Finance at Enskilda Securities, Oslo, from 1994 until she joined the board of Statoil in 2002. Previously she has worked in venture capital and shipping at Aircontactgruppen in Oslo and Fearnley Finance Ltd. in London. She did postdoctoral research in the field of microelectronics at Columbia University in New York. Ms. Skaugen has been a board member of Hilmar Rekstens Almennyttige Fond (Art Foundation), Geelmuyden-Kiese and a member of the Norwegian WWF Council and Fundraising Committee. Currently, Ms. Skaugen is chairman of the board of Entra Eiendom, a company directly owned by the Norwegian state, and is a board member of Tandberg ASA and Storebrand ASA, both listed on the Oslo Stock Exchange. She is also a board member of Atlas Copco AB, a listed Swedish company. Ms. Skaugen has a PhD in laser physics from Imperial College of Science and Technology, London University, and an MBA from BI Norwegian School of Management.
Eli Sætersmoen was elected to the board of directors in June 2002. Ms. Sætersmoen is an independent business development and strategy consultant. Previously, she was Chief Financial Officer and Executive Vice President in Selvaag Gruppen (Selvaag Group of Companies) in Oslo, and she has held positions in Cell Network ASA, Orkla Securities, GE-Capital, London, McKinsey & Company and in Norsk Hydro ASA. At McKinsey & Company her focus was strategic development for the oil industry. Ms. Sætersmoen has been a board member and Deputy Chairman of the board of SND (Government Organization for Regional Development). Currently, she serves as a non-executive director of several boards. Ms. Sætersmoen has an engineering degree in petroleum technology from The Norwegian University of Science and Technology and an MBA from Tuck School of Business, New Hampshire.
Knut Åm was elected to the board of directors in April 1999 and re-elected in June 2002. Mr. Åm is an independent technology and business development consultant located in Stavanger. He is a former Senior Vice President and head of Exploration and Production of Phillips Petroleum. Previously he has held positions with the Geological Survey of Norway, the Norwegian Petroleum Directorate and Statoil, and he has been adjunct professor of geophysics at the University of Bergen. He has also been Chairman of the board of the Norwegian Oil Industry Association, Christian Michelsen Research and Hitec ASA and President of the Norwegian Petroleum Society and the Norwegian Geological Council. He is presently Chairman of the Industrial Council of the Norwegian Academy of Technological Sciences, Chairman of the board of IOR-Chemco AS, EnVision AS and EnVision StreamLine AS, and board member of Badger AS and the Physics of Geological Processes-Center of Excellence at the University of Oslo. Mr. Åm has a degree in geological and geophysical engineering from The Norwegian University of Science and Technology in Trondheim.
Lill-Heidi Bakkerud was elected to the board of directors in April 2004 and serves as an employee-elected representative to the board. She has also served in this position previously. Ms. Bakkerud is the full-time union official for Statoil for the Norwegian Oil and Petrochemical Workers Union. She trained as a process/chemistry technician and worked at the petrochemical complex in Bamble and on the Gullfaks field. At present, Ms. Bakkerud is on leave from Gullfaks to carry out her union tasks.
Stein Bredal was elected to the board of directors in April 2000 and re-elected in June 2002 and serves as an employee elected representative to the board. He is Materials Coordinator on the Gullfaks field and has worked with Statoil since 1985. Mr. Bredal represents the Confederation of Vocational Unions where he is a full-time union official.
Morten Svaan was elected to the board of directors in June 2004 as an employee elected representative to the board. He has been a union official for NIF/Tekna from 2000 to 2004. Mr. Svaan has a PhD in chemistry from The Norwegian University of Science and Technology and has completed a one year Foundation Program in Business Administration at The Norwegian School of Management. He has worked with Statoil since 1985 in the Manufacturing and Marketing, Petrochemical and Research and Development units. Mr. Svaan is currently working as a project leader within HSE, with a focus on security in the Technology and Projects unit.
The board of directors established an audit committee in August 2003. A new instruction for the audit committee was adopted by the board of directors on February 11, 2005. The board elects up to four of its members to serve on the audit committee. The current members of the audit committee are Finn A Hvistendahl (chairman), Eli Sætersmoen and Morten Svaan. The audit committee is a sub-committee under the board of directors and its objective is to perform more thorough assessments of specific matters within the Statoil Group and report to the board of directors. The audit committee is instructed to assist the board's oversight of issues such as (1) the quality and integrity of the company's financial statements and related disclosure, (2) the external auditor's qualifications and independence, (3) the performance of the external auditor subject to the requirements of Norwegian law, (4) the performance of the company's internal audit function, internal controls and risk management and risk audit function, (5) the company's compliance with legal and regulatory requirements, including the requirements related to the listing on stock exchanges, and (6) the compliance with the group's ethical rules, including the group's compliance activities relating to corruption.
The internal audit function reports directly to the board of directors and to the Chief Executive Officer. The audit committee assists the board in overseeing this function. The audit committee also receives regular briefings and reports on internal control and ethical issues.
Under Norwegian law, our external auditor is elected by our shareholders at the Annual General Meeting. The audit committee makes a recommendation to the board of directors in respect of the appointment of the external auditor based upon its evaluation of the qualifications and independence of the auditor to be proposed for election or re-election. The audit committee meets at least six times a year, and meets separately with the internal auditor and the external auditor on a regular basis.
The audit committee is also charged with reviewing the scope of the audit and the nature of any non-audit services provided by external auditors. The external auditors report directly to the audit committee on a regular basis. The audit committee also maintains procedures for the receipt, retention and treatment of complaints received by the company regarding accounting, internal controls, or auditing matters and for the confidential, anonymous submission by employees of the company of concerns regarding accounting or auditing matters. The audit committee has the authority to engage independent advisers to assist it in carrying out its duties.
Statoil has established a compensation committee effective January 1, 2005. The compensation committee is a sub-committee under the board of directors and was established to assist the board in (1) the further development of Statoil's reward philosophy and strategy generally, and more specifically with regard to compensation of the CEO, (2) devising internally consistent and externally competitive total compensation programs in order to attract, retain and reward the CEO and key executives for performance related to achievements of financial goals, values and leadership approach, and (3) providing guidance, direction and monitoring of Statoil's compensation programs with respect to the long-term interest of the shareholders.
The Committee is comprised of three members from the Board. The Chairman of the Board is the Chairman of the Committee, and the two other members are Grace Reksten Skaugen and Knut Åm.
An executive committee is not required under Norwegian corporate law, but we established the committee as part of the overall organization of our company. Each member of the executive committee supervises separate business areas or staff units. Although the CEO is responsible for making decisions on important matters not requiring the decision of the board of directors, as well as all matters referred to him by the board, the executive committee has an advisory role. The board of directors has granted Helge Lund, Eldar Sætre and Erling Øverland the power of procuration, which under Norwegian law essentially empowers each of them to act on behalf of our company in all matters relating to our normal operations.
The members of our executive committee, their place of residence, age and position are identified below.
In addition to the executives listed above, Reidar Gjærum (44) was appointed Executive Vice President, Communication on March 17 and assumes his position in May.
Helge Lund was appointed President and Chief Executive Officer on March 7, 2004, and assumed his position on August 15, 2004. Mr. Lund came from the position of Chief Executive of Aker Kvaerner, and from 1999 until he joined Statoil, he held a number of positions in the Aker RGI system, among them the position as Deputy President and COO and Deputy Chairman of Aker Maritime. For a period, he was also appointed to the board of Kvaerner. Mr. Lund joined the Hafslund Nycomed industrial company in 1993, and from 1997, he was deputy managing director of Nycomed Pharma for a period of two years. Before then, Mr. Lund was a political adviser in the Conservative Party's parliamentary group and a consultant at McKinsey & Co. Mr. Lund graduated as a business economist from the Norwegian School of Economics and Business Administration in Bergen. He also has a master of business administration (MBA) from the Insead business school in France.
Eldar Sætre became Chief Financial Officer and Executive Vice President on September 1, 2004 after he had been acting in this position since September 30, 2003. Mr. Sætre was senior vice president for corporate control, planning and accounting since 1998 and senior vice president for corporate planning and control in the period from 1995 to 1998. Before then, his positions included controller for Gullfaks (1985-1989), commercial manager for Bergen Operations (1989-1992) and controller in E&P Norway (1992-1995). Mr. Sætre joined the group in 1980. He graduated with an MS degree in Business from the Norwegian School of Economics and Business Administration (NHH) in 1980.
Peter Mellbye took over as Executive Vice President, International Exploration & Production on September 1, 2004, after he had served as Executive Vice President of Natural Gas since 1992. Employed at Statoil since 1982, Mr. Mellbye has held numerous positions. Most recently, Mr. Mellbye served as President of the Natural Gas business segment from 1990 to 1992 and as Vice President of Natural Gas Marketing from 1982 to 1990. Currently, Mr. Mellbye is a member of the board of Siemens AS, Institut Francais du Pétrole in France, and of the Energy Policy Foundation of Norway. Mr. Mellbye graduated from the Universities of Oslo and Bergen with a degree in political science in 1977.
Terje Overvik has been Executive Vice President,
Exploration & Production Norway since September 1, 2004. He previously
served as Executive Vice President for Technology from August 19, 2002. Mr.
Overvik has held a number of different posts in Statoil, including platform
manager for the Statfjord A platform in the North Sea from 1992 to 2000, and Vice
President for Statfjord operations from 2000 to 2002. He holds a PhD from The Norwegian
University of Science and Technology in Trondheim, where he also worked there
as an associate professor and researcher before joining Statoil in 1983.
Rune Bjørnson was appointed Executive Vice President, Natural Gas on September 1, 2004. Mr. Bjørnson came from the position of Senior Vice President for Supply and Transport in Statoil's Natural Gas business area. Mr. Bjørnson was managing director of Statoil's operations in the UK from 2001 to 2003. Since 1990, he has held a number of executive positions in the natural gas area, and he also performed market analysis work for the group when he joined Statoil in 1985. From 1999 to 2001, Mr. Bjørnson was chair of the Gas Negotiating Committee (GFU). He has an MSc in Economics from the University of Bergen.
Jon Arnt Jacobsen has been Executive Vice President, Manufacturing & Marketing since September 1, 2004. He came from the position of Senior Vice President for group finance in Statoil, which he had held since 1998. He previously held the position of General Manager and head of the Singapore branch at Den norske Bank ASA. From 1992 to 1995, Mr. Jacobsen headed the industrial section of DnB's corporate customer division, having previously held a number of different positions in DnB's banking organization for the oil and gas industry over a seven-year period. He worked from 1983 to 1985 as a downstream market analyst for Esso Norge. Mr. Jacobsen has been a director of Mesta AS from 2002 to 2004. He has a business degree from the Norwegian School of Management and an MBA from the University of Wisconsin.
Margareth Øvrum was appointed Executive Vice President, Technology & Projects on March 30, 2005. She has earlier held the position of Executive Vice President for Health, Safety and the Environment since September 1, 2004. Before this, she was Senior Vice President for operations support in Exploration & Production Norway and head of Statoil's Bergen office. Before taking up her appointment in Bergen in 2000, Ms Øvrum held a number of supervisory posts offshore on Gulllfaks and Veslefrikk over a 10-year period, and was the group's first female platform manager. From 1987 to 1991, Ms Øvrum held various managerial posts on land linked to the start-up, operation and maintenance of Statoil's operations in the Tampen area. She joined Statoil in 1982, working on strategic analysis. Ms Øvrum is a member of the boards of Elkem and the University of Bergen, and a member of the committee of shareholders' representatives at Storebrand ASA. She was previously the chair of the board of directors of Helse Vest. She has a degree in engineering from The Norwegian University of Science and Technology (NTNU), specializing in technical physics.
Nina Udnes Tronstad was appointed Executive Vice President for Health, Safety and Environment on March 30, 2005. She came from the position as Vice President Production for the Kristin Field Development Project, a position she held since November 2001. From 2000 until 2001, she was Vice President Business Development in Exploration & Production Norway. In the four-year period 1996-2000 she was Senior Vice President Information Technology in Statoil. From 1994 until 1996 she was Vice President Supply and Logistics in Statoil's Swedish retail company. During her first years in Statoil, she held different professional and managerial positions within research and development and within Statoil's refinery operations. She joined Statoil in 1983 after finishing a degree in Chemical engineering from The Norwegian University of Science and Technology (NTNU).
Jens R Jensen became Executive Vice President, Human Resources on October 18, 2004. He came from the post of Senior Vice President for Human Resources at Aker Kvaerner ASA, a global provider of engineering and construction services, technology products and integrated solutions. He has held a number of senior positions in this area since 1991 in Aker AS, Aker Oil & Gas Technology and Aker Maritime ASA. From 1982 to 1986, Mr. Jenssen worked with human resources at Norwegian classification society Det Norske Veritas. He then spent several years - most recently in 2001 and 2002 - as an independent consultant to major companies in banking, finance and insurance, research, media, technology and manufacturing. Mr. Jensen holds a degree in psychology from the University of Oslo.
Our corporate assembly consists of 12 members. The general meeting elects eight members, and our employees elect an additional four members.
Our corporate assembly has a duty to control the board of directors and our Chief Executive Officer in their management of our company. Norwegian companies law imposes a fiduciary duty on the corporate assembly to our shareholders. The corporate assembly 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 corporate assembly renders decisions, based on the board's proposals, in matters related to substantial investments, measured in terms of the total resources of our company, and matters regarding rationalizations or restructurings of the operations of the company which will result in a major change or reorganization of the workforce. The corporate assembly is also responsible for electing and removing our board of directors. The term of office of the corporate assembly members is two years and the current term of office expires in May 2006.
Set forth below is a list of the current members of our corporate assembly, their place of residence, age and occupation.
Compensation to the Board of Directors, Executive
Committee and Corporate Assembly
Statoil's Chief Executive Officer Helge Lund was appointed on August 15, 2004. For the period from August 15 to December 31, 2004,
he was paid NOK 1,936,000, including pension premium paid. His annual
compensation consists of a base salary of NOK 4.4 million and a bonus element which the board may award at its discretion. The bonus cannot exceed 30 per cent of the base salary. The first bonus assessment will
take place in January 2006 for the year 2005. He is entitled, under specific
terms, to a pension amounting to 66 per cent of gross salary after 15 years as
CEO, and may retire at the age of 62.
Erling Øverland was acting Chief Executive Officer in the period from March 7 until August 15, 2004 and was paid a total of NOK 2,389,000 in this period, including performance pay for 2003, vacation pay and pension premium paid.
Inge K Hansen, who was acting Chief Executive Officer until March 7, 2004, received NOK 2,119,000 in salary and other remuneration from January 1 until March 7, 2004, including performance pay for 2003, vacation pay and pension premium paid.
The former Chief Executive Officer Olav Fjell, who left Statoil on September 22, 2003, was entitled to severance compensation, part of which was paid in 2004. The amount paid in 2004 was NOK 8,792,789. No further severance compensation is due to be paid by Statoil. There is an ongoing dispute about the pension arrangement between Olav Fjell and Statoil.
All members of the Statoil Executive committee are on a general basis entitled to 12 months of compensation, including terms of notice and severance pay, the latter if they should resign at the request of the company. Executive Vice President Peter Mellbye is entitled to severance pay including terms of notice equivalent to 24 months salary if resigning at the request of the company. He is also entitled, under specific terms, to a pension after reaching the age of 60. The pension will amount to 66 per cent of pensionable salaries.
A performance related remuneration system has been established for the members of the executive committee (excluding the CEO), senior vice presidents and vice presidents. This entails a variable remuneration based on pre-determined performance goals. For those employed in the parent company, the scheme allows for a bonus of 10 per cent of basic salary on achieving set goals, with a ceiling of 20 per cent for results that clearly exceed these goals.
We provide pension benefits to the majority of the group's employees entitling them to defined future pension benefits. The amounts of benefits provided are dependent on the number of years of their pensionable service, their final salary level, and the size of public insurance benefits.
Employees in the parent company, and the majority of Norwegian subsidiaries, are insured mainly through Statoil's pension funds. These funds are organized as independent trusts. The major part of their assets are invested in Norwegian and foreign bonds and shares, as well as in real estate in Norway. Employees in subsidiaries are partly insured through their own pension funds or through collective pension schemes in various insurance companies.
The projected benefit obligation at year-end 2004 was NOK 19,022 million, whereas the estimated fair value of plan assets at the end of the same period amounts to NOK 17,319 million.
Employee Incentive Plan
Statoil ASA has a common bonus scheme for its employees. This bonus scheme will have a maximum payment of 5 per cent, calculated on each employee's base salary.
In 2004 Statoil introduced a share saving plan for all permanent Statoil employees in both full and part time positions. The share saving plan gives the employees the opportunity to purchase Statoil shares though monthly salary deductions. If the shares are kept for two full calendar years of continued employment, employees participating in the share saving plan will be allocated one bonus share for each two they have bought.
In keeping with business practice in Norway, the board of directors of Statoil does not adopt its decisions through committees, but in the full board, even though Statoil has an audit committee and a compensation committee to prepare certain issues for the board of directors and support the board of directors in their responsibilities for management and control of the company.
As of December 31, 2004, we had 23,899 employees, of whom we employed 12,710 in Norway. The remaining 11,189 employees were employed outside of Norway, with more than 100 employees in each of Poland, Ireland, Denmark, Sweden, Lithuania, Latvia, Estonia, the UK, Russia and the Faroe Island s.
The tables below set forth the number of employees in each business area and the corporate technical service unit as at the end of 2002, 2003 and 2004, and the numbers of employees inside and outside of Norway. The table does not include employees of affiliated companies.
The main change from 2003 to 2004 is within Manufacturing and Marketing where 4,529 more employees have been added due to the acquisition of 50 per cent of Statoil Detaljhandel Skandinavia AS (SDS) from ICA/Ahold, which increased our ownership of SDS to 100 per cent.
As of January 1, 2005
Technology and Projects incorporates functions and employees that were reported
in prior years as part of Other Operations, E&P Norway, Natural Gas, and
International E&P, respectively.
We intend to limit our recruitment to growth areas and focus on young professionals and specific key competencies. We have a set of union/employer agreements at national, industry and local levels, which is the typical way of organizing union agreements in Norwegian industry. We take part in agreements at the national level as a member of the Norwegian Employers Association and at the industry level as a member of the Norwegian Oil Industry Association and the Federation of Norwegian Process Industry, both of which are branches of the Norwegian Employers Association.
At the local level, we have agreements with the trade unions. Our employees are represented by five trade unions: the Norwegian Oil and Petrochemical Workers Union, Confederation of Vocational Unions, Norwegian Association for Supervisors, Norwegian Society of Chartered Engineers and Norwegian Society of Engineers. Approximately 70 per cent of our employees are union members. The unions are entitled to appoint three members to our board of directors. Labor contracts with the unions were renewed in 2004 for a period of two years. Overall, we consider our relations with our employees as well as the unions to be good, and there are currently no major labor disputes.
We continually seek to improve the skills and development of our employees in each of our business units. Employees participate in various training programs. Our training organization provides different development programs, and we cooperate with selected colleges and universities as well as other educational and research institutions in Norway and abroad.
The number of Statoil shares owned by the members of the board of directors, the executive committee, and the corporate assembly is shown below. Board members and members of the executive committee, including closely related parties, who own Statoil shares are set forth below. Each owns less than one per cent of the Statoil shares outstanding.
Members of the corporate assembly owned as of March 18, 2005 a total of 750 shares.
The Norwegian State as a Shareholder
The following table shows the number of Statoil shares owned by the Norwegian State as of December 31, 2004. The State sold a total of 117,650,000 shares in the period from December 31, 2004 to March 18, 2005 as detailed below. We have not been notified of any other beneficial owner of five per cent or more of our ordinary shares as of March 18, 2005.
(1) Based upon 2,165,920,289 ordinary shares outstanding and 23,665,311 ordinary shares held in treasury as of March 18, 2005.
In June 2001, in connection with the initial public offering of our ordinary shares, we established a sponsored American Depositary Receipt facility with The Bank of New York as depositary pursuant to which American Depositary Receipts (ADRs) representing American Depositary Shares (ADSs) are issued. We have been informed by The Bank of New York that in the United States, as of March 24, 2005, there were 40,194,861 ADRs outstanding (representing approximately 1.86 per cent of the ordinary shares outstanding). As of March 24, 2005 there were 86 registered holders resident in the United States.
On April 26, 2001 the Storting (the Norwegian parliament) authorized the Ministry of Petroleum and Energy to reduce its shareholding in us by up to one-third of our value through the sale of its existing shares or the issuance by us of new shares to new investors. Following the initial public offering, the Norwegian State owned 80.84 per cent of the shares of Statoil. This percentage was calculated based on shares authorized and issued.
On July 6, 2004, the Norwegian Ministry of Petroleum and Energy sold 100 million Statoil shares through an off-exchange underwritten block sale. This represented 4.6 per cent of our shares. The shares were sold to a global investment bank and were passed on to institutional investors in Norway and abroad. In addition, 17.65 million shares were made available for sale to private investors, at the rate set in the institutional sale.
On February 16, 2005 the Norwegian Ministry of Petroleum and Energy sold 100 million Statoil shares through an off-exchange underwritten block sale. This represented 4.6 per cent of our shares. The shares were sold to a global investment bank and were passed on to institutional investors in Norway and abroad. In addition, 17.65 million shares were made available for sale to private investors, at the rate set in the institutional sale.
Following these sales, the Norwegian state now owns 70.1 per cent of the shares of Statoil.
The Norwegian State does not have any different voting rights from the rights of other ordinary shareholders as described in Item 10-Additional Information-Memorandum and Articles of Association. However, as the Norwegian State, acting through the Minister of Petroleum and Energy, continues to own in excess of two-thirds of the shares in us following completion of the initial public offering, it has the sole power to amend our articles of association. As long as the Norwegian State owns more than one-third of our shares, it will be able to prevent any amendments to our articles of association. In addition, as a majority shareholder, the Norwegian State has the power to control any decision at general meetings of our shareholders that requires a majority vote, including the election of the majority of the corporate assembly, which has the power to elect our board of directors and approve the dividend proposal by the board of directors.
The Norwegian State has stated that as one of our several shareholders, it will concentrate on issues relating to return on capital and dividend policy, emphasizing long-term profitable business development and the creation of value for all shareholders. The Norwegian State will exercise its ownership position based on a coordinated ownership strategy to maximize the value of the Norwegian State's aggregate holdings in Statoil and the SDFI.
The Norwegian State as a Regulatory Authority
As a corporation based in Norway, we are subject to the laws and regulations of the Kingdom of Norway. Changes to relevant laws and regulations could have a significant impact on our operations. Various agencies and departments of the Kingdom of Norway exercise regulatory functions over our activities. The Ministry of Petroleum and Energy also exercises important regulatory powers over all petroleum operations of the companies of the NCS, including those of Statoil. For additional information about the Ministry of Petroleum and Energy's role, see the section entitled Item 4-Information on the Company-Regulation. A number of other agencies and departments, such as the Norwegian Petroleum Directorate, the Ministry of Finance, the Ministry of Labor and Government Administration, the Ministry of the Environment and the Norwegian Pollution Control Authority, exercise regulatory powers which affect important parts of our operations.
A significant part of the taxes we pay are paid to the Norwegian State, see Item 4-Information on the Company-Business Overview-Regulation-Taxation of Statoil.
The Norwegian State's Direct Participation in Petroleum Operations on the NCS
The Norwegian State's policy as an owner has been, and continues to be, to ensure that petroleum activities create the highest possible value for the Norwegian State. Initially, the Norwegian State's participation in petroleum operations was organized mainly through us. In 1985, the Norwegian State established the State's direct financial interest, or SDFI, through which the Norwegian State has taken direct participating interests in licenses and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licenses and petroleum facilities in which we also hold interests. Until June 17, 2001, we acted as manager of the SDFI's interests in licenses and petroleum facilities.
As a result of changes in global markets and competitive conditions in the petroleum industry, the Norwegian State implemented a strategic review of its oil and gas policy in 2000. Based on the results of this strategic review, the Norwegian State prepared a plan to restructure its petroleum holdings on the NCS that was approved by the Storting on April 26, 2001. The key elements of the restructuring plan include:
Marketing and Sale of the SDFI's Oil and Gas
Introduction. We have historically marketed and sold the Norwegian State's oil and gas as a part of our own production. The Norwegian State has elected to continue this arrangement. Accordingly, at an extraordinary general meeting held on February 27, 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article which requires us to continue to market and sell the Norwegian State's oil and gas together with our own oil and gas in accordance with an instruction established in shareholder resolutions in effect from time to time. At an extraordinary general meeting held on May 25, 2001, the Norwegian State, as sole shareholder, approved a resolution containing the instructions referred to in the new article. This resolution is referred to as the owner's instruction.
The Norwegian State has a coordinated ownership strategy to maximize the aggregate value of its ownership interests in Statoil and the Norwegian State's oil and gas. This is reflected in the owner's instruction, which contains a general requirement that, in our activities on the NCS we are required to take account of these ownership interests in decisions that may affect the execution of this marketing arrangement.
The owner's instruction sets forth specific terms for the marketing and sale of the Norwegian State's oil and gas. The principal provisions of the owner's instruction are as set forth below.
Objectives. The overall objective of the marketing arrangement is to obtain the highest possible total value for our oil and gas and the Norwegian State's oil and gas and ensure an equitable distribution of the total value creation between the Norwegian State and us. In addition, the following considerations are important:
Our tasks. Our tasks under the owner's instruction are to market and sell the Norwegian State's oil and gas and to carry out all necessary tasks, other than those carried out jointly with other licensees under the production license, in relation to the marketing and sale of the Norwegian State's oil and gas, including, but not limited to, the responsibility for processing, transport and marketing. In the event that the owner's instruction is terminated, in whole or in part, by the Norwegian State, the owner's instruction provides a mechanism under which contracts for the marketing and sale of the Norwegian State's oil and gas to which we are a party may be assigned to the Norwegian State or its nominee. Alternatively, the Norwegian State may require that the contracts be continued in our name, but to the effect that in the underlying relationship between the Norwegian State and us, the Norwegian State receives all rights and obligations related to the Norwegian State's oil and gas.
Costs. The Norwegian State does not pay us specific consideration for executing these tasks, but the Norwegian State reimburses us for its proportionate share of certain costs, which under the owner's instruction may be our actual costs or an amount specifically agreed.
Price mechanisms. 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. We now purchase all of the Norwegian State's oil and NGL. 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.
Lifting mechanism. As part of the coordinated ownership strategy, a lifting mechanism for the Norwegian State's and our oil and gas is established in accordance with rules set out in the owner's instruction.
To ensure a neutral weighting between the Norwegian State's and our natural gas volumes, a list has been established for deciding the priority between each individual field. To decide the ranking, a mathematical optimization model is used which describes existing and planned production facilities, infrastructure and processing terminals where the Norwegian State and we have ownership interests. The list yields a result giving the highest total net present value for the Norwegian State's and our oil and gas. In the evaluation, the following objective criteria shall, among other things, apply:
The different fields are ranked in accordance with the assumed total value creation for the Norwegian State and us, assuming all of the fields meet our profitability requirements if we participate as a licensee, and the Norwegian State's profitability requirements if the State is a licensee. The list is updated annually or more frequently if incidents occur that may significantly influence the ranking. Within each individual field where both the Norwegian State and we are licensees, the Norwegian State and we will deliver volumes and share income in accordance with our respective participating interests.
The Norwegian State's oil and NGL are lifted together with our oil and NGL in accordance with applicable lifting procedures for each individual field and terminal.
Withdrawal or Amendment. The Norwegian State may utilize its position as majority shareholder of Statoil, at any time, to withdraw or amend the instruction requiring us to market and sell the SDFI oil and natural gas together with our own.
Petoro - The SDFI Management Company
Since the establishment of Statoil in 1972, the participation of the Norwegian State in production licenses and facilities for transport and utilization of petroleum took place entirely through us. As of January 1, 1985, the Norwegian State's participation was reorganized through the establishment of the SDFI. Through this reorganization the Norwegian State began taking a direct financial interest in production licenses. The establishment of the SDFI entailed a transfer of a substantial part of our participation in most of our then-existing licenses to the SDFI, although formally such licenses continued to be held wholly in our name. Since its establishment in 1985, the SDFI has taken shares in most licenses awarded. The SDFI also holds shares in a number of oil and gas pipelines and land-based terminal facilities.
We were, until June 17, 2001, registered as licensee for all SDFI shares in licenses. In accordance with a decision made in an extraordinary general meeting on May 10, 2001, we were until this time also the manager of the SDFI shares in these licenses on behalf of the Norwegian State. Where both the SDFI and we had an interest in the same license, the department managing our interest also managed the SDFI interest. In fields with SDFI interests only, the interests were managed by a separate unit that we established for this purpose. Our tasks as the manager of the SDFI's interests have included attending management committee meetings for both the SDFI's and our own share in licenses, and votes cast by us in management committee meetings have represented both the SDFI's and our own interests in the licenses. We have also been responsible for marketing the petroleum of which the Norwegian State becomes the owner through the SDFI shares in production licenses.
In connection with the restructuring, the Norwegian State on May 9, 2001 established a new State-owned company, Petoro AS, which took over responsibility for and the management of the SDFI assets as licensee, in accordance with a new chapter of the Petroleum Act. The Norwegian State continues to be the beneficial owner of these assets. We continue to market and sell the Norwegian State's oil and gas together with our own oil and gas, pursuant to the owner's instruction described under -Marketing and Sale of the SDFI's Oil and Gas above. One of the tasks of Petoro AS is to supervise our compliance with the owner's instruction.
Petoro AS does not own any of the oil and gas produced under the license interests it holds, does not receive any revenues from sales of the State's oil and gas, and is not permitted to obtain an operator role. However, Petoro AS may become a participant in new licenses awarded by the Norwegian State.
Gassco - The Gas Transportation Operating Company
In connection with the restructuring of the Norwegian State's oil and gas interests, on May 14, 2001 the Norwegian State established a separate company, Gassco AS, which on January 1, 2002 took over as operator of the natural gas transportation system previously operated by us. Gassco AS is wholly owned by the Norwegian State. The owners of the infrastructure systems appointed Gassco AS as the new operator.
The transfer of the operatorship to Gassco AS was made without consideration and does not affect existing arrangements with respect to ownership or access to the natural gas transportation system or tariffs for transport. However, in accordance with the joint venture agreements relating to each of the gas transportation assets, the operator is entitled to be reimbursed for its costs as operator. Accordingly, since Gassco AS was appointed as operator, we no longer receive such reimbursement, and we will, as will other users of the infrastructure, be required to pay our portion of Gassco AS's expenses associated with the operation of the natural gas pipelines in which we hold interests.
Gassco AS has entered into contracts with us for each infrastructure joint venture, pursuant to which we will carry out technical operating activities on behalf of Gassco AS, such as system maintenance, for which we will receive reimbursement of costs. Either Gassco or we may terminate without cause each of these contracts, except the contract for the Statpipe joint venture, after five years. Either Gassco or we may also terminate the part of the Statpipe contract, which refers to the offshore pipelines, after five years. Currently, Gassco may terminate the part of the Statpipe contract that refers to the Kårstø plant, at any time, provided that 2/3 of the owners, representing more than 2/3 of the ownership interests, have supported such termination.
As 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 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 interest in Zeepipe Terminal JV and Dunkerque Terminal DA will also be adjusted. Gassco AS is the operator of the Gassled joint venture.
Our initial direct ownership interest in Gassled is 20.379 per cent (21.133 per cent including our indirect interest through our 25 per cent holding in Norsea Gas AS), 10.35542 per cent in Zeepipe Terminal JV and 13.73678 per cent in Dunkerque Terminal DA. From January 1, 2011, our direct ownership interest in Gassled will be reduced to 17.662 per cent due to an increased ownership interest for SDFI. In addition, our ownership interest in Gassled may also change as a result of 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. For more information on the Gassled joint venture, see Item 4-Information on the Company-Business Overview-Natural Gas.
Related Party Transactions
Transactions with the Norwegian State
For a description of transactions with the Norwegian State, see -Major Shareholders-The Norwegian State as a Shareholder above.
Transactions with other entities in which the Norwegian State is a major shareholder
Norsk Hydro. In 2003, we purchased a 10 per cent interest in the Snøhvit field from Norsk Hydro, with such transaction being effective January 1, 2004. Further, a 2 per cent interest in the Kristin field was sold to Norsk Hydro effective from January 1, 2004. In addition, we hold interests in a number of the licenses and petroleum facilities in which Norsk Hydro also holds interests, and for many of these licenses and petroleum facilities Norsk Hydro or we serve as operator. Norsk Hydro has an indirect participating interest in the Gassled joint venture. Further, we from time to time engage in common drilling campaigns, exploration and development projects with Norsk Hydro. In addition, Norsk Hydro is a party to the 15-year agreement for the sale of ethane described below in -Transactions with associated companies. The Norwegian State owns 45.2 per cent of the total number of Norsk Hydro ASA shares outstanding.
Others. As a result of the substantial percentage of industry in Norway controlled by the Norwegian State, there are many state-controlled entities with which we do business. The financial value of most such transactions is relatively small, and the ownership interest of the Norwegian State of such counter parties has not had any effect on the arm's-length nature of the transactions. In particular, in respect of the goods and services that we purchase, we purchase telephone services from Telenor ASA, a telecommunications company in which the Norwegian State holds a 53.1 per cent interest. Such purchases are made pursuant to standard tariff rates applicable to public and private companies in Norway.
Transactions with associated companies
Borealis. On November 28, 2000, we entered into a long-term Sales and Purchase Agreement with Borealis for the sale of LPG derived from Statoil and SDFI's share of crude oil from the Oseberg field in which the combined participating interest is now 48.90 per cent. The LPG is made available after the crude oil from Oseberg has gone through the transportation, separation and storage processes in the Vestprosess facility at Mongstad, our refinery in Norway. The agreement provides for regular deliveries of LPG to Borealis's Rafnes plant. The price is based on the content of isobutane in the delivered LPG and is set in relation to the market price for naphtha. Certain quality specifications regulate the methanol, butane and isobutane content in the delivered product. The initial period for the contract is 15 years. In 2004, we sold 232,000 tonnes of LPG under this contract for an approximate consideration of NOK 629 million.
On March 3, 2005 Statoil entered into a 10-year agreement with Borealis for the sale of LPG from the Snøhvit field. Deliveries under the agreement are expected to commence following the start-up of production on the Snøhvit field, currently 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.
On June 2, 1997, we entered into a 15-year agreement for the sale of ethane between the participants in the Troll field, including us, as sellers and Borealis, Noretyl ANS and Norsk Hydro Produksjon AS as buyers. This contract provides for the purchase and sale of ethane feedstock for the Borealis plant in Stenungsund, Sweden, the Noretyl plant in Rafnes, Norway, and the Hydro Agri Ammonia plant at Herøya in Porsgrunn, Norway from the Gassled owned Kårstø plant. Currently, 50 per cent of production is delivered to Stenungsund and 50 per cent to Rafnes. At Rafnes, 50 per cent is delivered to Hydro Agri Ammonia plant, 25 per cent to Hydro Polymers and 25 per cent to Borealis. It is a take-or-pay contract whereby the buyers are obligated to pay for all ethane made available by the sellers under the contract. The price for the ethane is based on the market price of naphtha and is adjusted to reflect changes in the Norwegian consumer price index and the market price of marine fuel. Deliveries under the contract began in October 2000, and the initial term of the agreement lasts until October 1, 2015. In 2004, the seller group sold 493,000 tonnes of ethane under this contract for an approximate consideration of NOK 963 million.
Statoil Detaljhandel Skandinavia. On June 1, 1999, we entered into a Fuel Supply Agreement with SDS whereby we became the sole supplier of refined petroleum products to SDS for its retail petroleum activities in Scandinavia, which was renewed effective January 1, 2002. The agreement encompassed bulk products sold at SDS's service stations such as gasoline and automotive diesel oil, burning kerosene and LPG, as well as marginal bulk products such as RME, biogas and bioethanol. Prices paid by SDS were based on market prices for the different products, adjusted for changes that occurred to the products during transportation, storage and distribution. SDS also paid to us an amount to cover the cost of distribution per service station location. In July 2004 we repurchased the 50 per cent share in Statoil Detaljhandel Skandinavia AS (SDS) held by ICA/Ahold, which increased our ownership of SDS to 100 per cent. For the period from January 1 to July 7, 2004, we received NOK 10.0 billion, of which NOK 6.5 billion were excise taxes, pursuant to the Fuel Supply Agreement.
Other Transactions with the Norwegian State
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. The prices paid by Statoil for the oil purchased from the Norwegian State are estimated market prices. In addition, Statoil sells the Norwegian State's natural gas, in its own name, but for the account and risk of the Norwegian State.
The Norwegian State compensates Statoil for its relative share of the costs related to certain Statoil natural gas storage and terminal investments and related activities.
Some of our employees are eligible for an interest-free car loan. The loan is limited to the price of the car purchased, and is capped at NOK 250,000, NOK 375,000 or NOK 475,000, depending on the seniority of the employee.
Executive Vice Presidents Terje Overvik and Nina Udnes Tronstad have interest-free loans of NOK 201,500 and NOK 85,200, respectively. The loans has been approved with a repayment period of up to 10 years.
We have an arrangement with DnB NOR whereby DnB NOR makes available to each of our employees personal loans of up to NOK 150,000. The employees pay the "norm interest rate", which is set by the Norwegian State, and we pay the difference between the norm interest rate and the then-current market interest rate. We also guarantee these loans up to an aggregate maximum amount of NOK 10 million. The repayment period is up to eight years. Our obligations for paying the interest rate difference will be dependent on the loan volume, but based on current interest rates would not exceed NOK 5 million per year.
The three employee-elected members of the board of directors each entered into loan agreements under this facility prior to July 30, 2002, and had as of December 31, 2004, an aggregate total balance outstanding payable to DnB NOR under this loan facility of NOK 327,332.
Members of the executive committee, the board of directors and the corporate assembly may not renew existing loans or enter into new loans under the foregoing programs.
Transactions with chairman of the board
We have made an office in Oslo available to our Chairman, Mr. Jannik Lindbæk. The office is used both in relation to his work as Chairman and to his other business activities unrelated to Statoil. We have estimated that 40 per cent of the use of the office is related to his capacity as Chairman. For the remaining 60 per cent, Mr. Lindbæk pays a rent at normal market rate.
See Item 18-Financial Statements.
We are involved in a number of judicial, regulatory and arbitration proceedings concerning matters arising in connection with the conduct of our business. Except as set forth below, we are currently not aware of any legal proceedings or claims that we believe could have, individually or in the aggregate, significant effects on our financial position or profitability or our results of operations or liquidity.
The Horton Case
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. The consultancy agreement provided for the payment of USD 15.2
million for consultancy services to be rendered over the 11-year contract term.
Two payments totaling USD 5.2 million were made under the contract before the
payments were stopped. The contract was terminated in September 2003. On June 29,
2004, Økokrim informed Statoil that it had concluded that Statoil violated
section 276c, first paragraph (b) of the Norwegian Penal Code (which became
effective from July 4, 2003 and prohibits conferring on or offering to a
middleman an improper advantage in return for exercising his influence with a
decision-maker without the decision-maker receiving any advantage) 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.
Before agreeing to pay the fine imposed by Økokrim, Statoil had already
accepted that the Horton contract violated its own ethical policies and
standards. Statoil has taken a number of steps to prevent a similar situation
from arising in the future. Økokrim also informed Statoil that it issued a
penalty notice to former Statoil executive vice president Richard Hubbard on
the same legal basis, seeking to impose a penalty of NOK 200,000. Richard
Hubbard announced on October 18, 2004 that he had accepted the Økokrim fine of
In relation to the Horton case, Norwegian Tax Authorities have imposed a surcharge of NOK 6,115,630 on our corporate income tax bill for the financial year 2002 due to Statoil incorrectly having claimed deductions for the payments made under the consultancy agreement.
We currently intend to pay an annual, aggregate dividend to shareholders of an