Commission File No. 1-15200
StatoilHydroStatoil ASA
(Exact Name of Registrant as Specified in Its Charter)
N/A
(Translation of Registrant's Name Into English)
Norway
(Jurisdiction of Incorporation or Organization)
Forusbeen 50, N-4035 Stavanger, Norway
(Address of Principal Executive Offices)
Eldar Sætre
Chief Financial Officer
StatoilHydroStatoil ASA
Forusbeen 50, N-4035
Stavanger, Norway
Telephone No.: 011-47-5199-0000
Fax No.: 011-47-5199-0050
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Securities registered or to be registered pursuant to Section 12(b) of the Act:

Securities registered or to be registered pursuant to Section 12(g) of the Act: None

Securities for which there is a reporting obligation pursuant to Section 15 (d) of the Act: 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:

Ordinary shares of NOK 2.50 each          3,184,865,894
3,183,873,643

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities
Act Yes_X_ No__

If this report in an annual or transition report, indicate by check mark if the registrant is not required to file reports
pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes__ No_X_

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 whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated nonaccelerated
filer. See definition of 'accelerated“accelerated filer and large accelerated filer'filer” in Rule 12b-2 of the Exchange Act. (Check
(Check one):

Large accelerated filer_X_ Accelerated filer__ Non-accelerated filer__

Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements
included in this filing:

U.S. GAAP __ International Financial Reporting Standards as issued by the International Accounting Standards
Board _X_Other__
_X_ Other __

If 'Other'“Other” has been checked in response to the previous question, indicate by check mark which financial
statement item the registrant has elected to follow.

Item 17 __ Item 18 __

If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act). Yes__ No _X_

Annual report on Form 20-F 20082009

Table of content

1 Introduction

1.1 FrontpageCover page

1.2 Key figures

Key figures is a presentation of our performance in important areas: income, return, cash flow, oil production and price, gas production and price, proved reserves, total recordable injuries, serious incidents, and carbon dioxide emissions.

1.3 About the report

StatoilHydro'sStatoil's Annual Report on Form 20-F for the year ended 31 December 20082009 ("Annual Report on Form 20-F") is available online at www.statoilhydro.com. StatoilHydrowww.statoil.com.

Statoil is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, StatoilHydroStatoil files its Annual Report on Form 20-F and other related documents with the Securities and Exchange Commission, the SEC. It is also possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C. 20549, USA. You may also call the SEC at 1-800-SEC-0330 for further information about the public reference rooms and their copy charges, or you may log on to www.sec.gov. The report can also be downloaded from the SEC website at www.sec.gov.

StatoilHydroStatoil discloses on its website at www.statoilhydro.com/www.statoil.com/en/aboutstatoilhydro/aboutStatoil/corporategovernance/norwegiancodeofpractice/pages/statementofdifference.aspx,default.aspx, and in its Annual Report on Form 20-F (Item 16B) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under the New York Stock Exchange (the "NYSE") listing standards.

1.4 Financial highlights

The financial downturn has been challenging for everyone, including the oil and gas industry. In such an uncertain business environment, the best protection comes from solid deliveries. In 2009 we delivered on our targets, both operationally and financially.

StatoilHydro

Statoil publishes financial data in accordance with IFRS. StatoilHydroStatoil did not publish financial data in accordance with IFRS in 2006 as we previously presented financial data in accordance with US GAAP. For this reason, we have not provided selected financial data for 2005 and 2004 in this Annual Report and Form 20-F 2008.Report. Selected financial data for those yearsthat year presented in accordance with US GAAP is included in our 2006 Annual Report on Form 20-F.

1.5 Important events in 2008A glance at 2009

Business development
On 21 February, Gazprom, Total

2009 was a year of uncertainty, with the threat of the financial crisis, falling oil and StatoilHydro signed a Shareholder Agreementgas prices and more unpredictable demand. Nevertheless, we delivered on our production targets and are well positioned for the creationfuture. This is a brief review of Shtokman Development AG2009.

The year at a glance

In January, we revealed our intent to merge land-based organisations and offshore installations in an over-arching production system designed to run the business more safely and predictably. The restructuring process proceeds as planned. The latest milestone is the opening of a new operations support centre at Sandsli.

Also in January, gas flowed from the Yttergryta subsea field on Åsgard in the Norwegian Sea. The field progressed from discovery to production in just 18 months. The average lead time for phaseoffshore oil and gas field developments in Norway is 15 years.

In March, we made a discovery at the Asterix gas prospect in the Norwegian Sea, which was deemed one of the Shtokman field.larger finds offshore Norway in recent years.

StatoilHydro ASAIn April, we joined forces with Norwegian power utility Statkraft to develop the 315 MW Sheringham Shoal Offshore Wind Farm off the coast of Norfolk, UK. The wind farm will have 88 turbines and Det norske oljeselskap ASA signedis planned to start production in 2011. When fully operational, its annual electricity production will be about 1.1 TWh, enough to power some 220,000 UK homes.

Also in April, we announced the acquisition of a sales and purchase agreement on 12 October for the transfer of Det norske oljeselskap's 15% interest40% stake in 50 blocks from BHP Billiton in the Goliat field to StatoilHydro ASA. The transaction has effect from 1 January 2008. Also on 12 October, StatoilHydro Petroleum AS and Det norske oljeselskap ASA agreed on a swap of minor interests in three other licences.

On 21 October, the European Commission announced that StatoilHydro has been granted permission to take over the bulkfrontier DeSoto Canyon area of the Jet retail chainUS Gulf of Mexico. DeSoto Canyon is located east of Statoil's current production operation at Independence Hub. The area has water depths of about 1,000 metres, and is a mostly unexplored region in Scandinavia currently owned and operated by ConocoPhillips.

On 12 November StatoilHydro formed a strategic alliance with Chesapeake Energy Corporation to jointly explore unconventional gas opportunities worldwide. Under this agreement we will initially acquire a 32.5% interest in Chesapeake's Marcellus shale gas acreage.

On 11 December StatoilHydro completed the full acquisitioneastern part of the Peregrino heavy-oil field offshore Brazil, after closing the deal to acquire the additional 50% stake from Anadarko and making StatoilHydro the operator.

AccessGulf of Mexico (GoM), offering advantageous early access to new areasplays.

In May
Internationally, StatoilHydro, first oil was tapped on the high bidder on 16 leases, of which 14 were joint bids with ENI Petroleum, in the Chukchi Sea Lease Sale 193 in Alaska announced on 6 February. StatoilHydro will be the operator of all 16 leases. In total, the group gained access to 20 new exploration licences during the yearTahiti field in the Gulf of Mexico, Alaska, Brazil, CanadaMexico.

An offshore worker died on 7 May after an accidental fall on the North Sea Oseberg B platform operated by Statoil, in connection with the removal of scaffolding from the drilling area on the B platform. The victim was an employee of scaffolding contractor STS. In direct response to the accident, Statoil and contractors Aibel and STS took the Faroe Islands.initiative to introduce improvements throughout the entire scaffolding industry.

In Norway, StatoilHydro was offered interests in 12June, production licenceson the Lufeng 22-1 field in the AwardsSouth China Sea was shut down. We operated the field together with partner CNOOC from 1997. Under an agreement between CNOOC and Statoil, CNOOC has taken over full responsibility for the abandonment of Predefined Areas 2007 (APA 2007)phases two and three of the field. Our Shekou operations office was closed at the end of 2009, and our activities in China are currently centred around R&D cooperation and business development.

On June 1, we were devastated by the news that three colleagues from our Rio de Janeiro office were on Air France flight 447 that disappeared over the Atlantic. Geologist Marcela Pellizzon, 29, and lawyer Gustavo Peretti, 30, both Brazilian citizens, and Norwegian lawyer Kristian Berg Andersen, 37, perished in the accident. A memorial service was held in Rio in June.

In July, first oil was tapped on the Thunder Hawk field in the Gulf of Mexico.

Also in July, the Tyrihans field in the Norwegian Continental Shelf (NCS). The company will beSea came on stream using the operator of nine ofworld's longest directly heated pipeline - some 43 kilometres long.

During the licences

Exploration activities
StatoilHydro delivered an extensive exploration programmesummer, some 30 vessels took part in 2008. Of a total of 79 exploration wells completed before 31 December 2008, 40 were drilled outside the NCS. Thirty-five wells were discoveries, of which eight are located outside the NCS. An additional eight wells have been completed since 31 December 2008.

Project development
StatoilHydro maintained a high activity level in progressing projects into production. On 18 January, the plan for development and operation (PDO) of Yttergryta was submitted, only six months after the discovery was made. In 2008, StatoilHydro delivered three PDOs (Plan for Development and Operation)marine operations on the NCS: Yttergryta (18 January), Morvin (15 February)Gjøa and Vega fields in the Troll FieldNorth Sea. Gjøa is our largest project (27 June).

Production from Gamma Main Statfjord on the Oseberg fieldunder construction in the North Sea commencedtoday and expected to start producing in 2010. The field's semi-sub platform is Statoil's first floating installation to source electricity from the mainland, reducing CO2 emissions by about 210,000 tonnes per year. The smaller Vega deposit will tie in to Gjøa and also start producing in 2010.

In August, we set a world record on 12 April,the Ormen Lange field in the Norwegian Sea when the world's deepest remotely controlled "hot-tap" operation was completed at a sea depth of 860 metres.

In September, our Hywind pilot project - the world's first full-scale floating wind turbine - was officially inaugurated off the coast of western Norway for two years of testing. A still immature technology facing a long road to commercialisation and full-scale wind farm construction, Hywind can help floating wind turbines make a long-term contribution to meeting the world's soaring demand for energy.

Statoil CEO Helge Lund took part in a preliminary meeting at the UN headquarters in New York, in connection with preparations for the international climate summit in Copenhagen, after being appointed a member of the UN expert group for climate and energy. Statoil was the only oil company represented in the group, which consists of approximately 20 persons from different countries.

In October, we announced the nineteenth oil find on Angola's offshore Block 31. We hold a 13.3% stake in the acreage. Sonangol is concessionaire and BP operator. We are partner in nine producing Angolan fields, which contribute more than 200,000 barrels of equity production per day to our portfolio.

In November, we changed our name to Statoil and introduced our new brand identity. The Horton case - concerning Statoil's contract with Horton Investment Ltd, related to business development in Iran - was formally closed by the US authorities in November. Statoil fulfilled the conditions of agreements signed in 2006 with the US authorities to substantially strengthen our ethics and anti-corruption practices. Offshore installation of the first wellhead platform on the Statoil-operated Peregrino field in Brazil started.

In December, Statoil and Lukoil won the technical service contract from Iraq's Ministry of Oil to develop the sizeable West Qurna 2 field in the southern part of the country. West Qurna 2 is estimated to hold 12.9 billion barrels of recoverable reserves.

We signed memorandums of understanding (MoU's) with Gazprom to import LNG into the US and trade it there. The MoU's include Gazprom getting re-gasification capacity at the Cove Point, Maryland, LNG receiving terminal. Statoil will also sell natural gas to Gazprom at various US locations, while purchasing LNG from Gazprom at Cove Point.
 

Finally, it was announced on 18 months afterDecember that Statoil and Chinese oil giant Sinopec will carry out joint geological studies on two deep-water blocks in the South China Sea. The agreement makes Statoil the first foreign company to work with Sinopec off the coast of China.

The year as a whole

Our total equity output both in and outside Norway increased to some 1,950,000 barrels of oil deposit was proved. Production started from seven fieldsequivalents per day.

We carried out an extensive exploration drilling campaign on the NCS during 2008: Volve (12 February), Gulltopp (7 April), Oseberg Gamma Main Statfjord (12 April), Vigdis East (15 April), Theta Cook (26 June), Oseberg Delta (27 June)in 2009, completing 39 exploration wells, 30 wildcat wells to test new prospects and Vilje (1 August)nine appraisal wells to establish the extent and size of previous discoveries. We proved 22 new discoveries, resulting in a discovery rate of more than 70%. Most of the finds are relatively small and close to producing fields in the North Sea and Norwegian Sea, making later tie-ins possible. The most important discoveries in 2009 were Asterix, Gro, Katla and Beta West; all except Gro being Statoil-operated.

Internationally, our average daily production commenced on Mondo in Angola (1 January), Deep Water Gunashli in Azerbaijan (22 April), Saxi and Batuque offshore Angola (1 July),surpassed 500,000 boe for the Agbami in Nigeria (29 July) and South Pars in Iran (1 October).

Production
Total equityfirst time. Equity production increased by 5%10% from 20072008, to 1,925 mboe512 mboe/day, and production from three new fields started during the year. We had a high level of exploration activity: six of the 29 exploration wells drilled in 2009 have been announced as discoveries, with several interesting discoveries in the US Gulf of Mexico, Canada and Angola.

Looking ahead

The Leismer oil sands development project in Canada is well underway with production start up expected in autumn 2010. The Leismer Commercial Demonstration Plant is stage one of our total field development plan for several bitumen hubs upstream.

Our Peregrino project now towers over the surface of the sea in the Campos basin off Brazil. First oil is expected in early 2011 and production should reach its plateau of 100,000 barrels of oil equivalents per day in 2008. Total liquids andwithin the first year.

The onshore Marcellus shale gas entitlement production increased by 2% from 1.724 mboe per day in 2007 to 1,751 mboe per day in 2008.

Market
The first cargo of gas from the NCS arrivedleases in the strategically important marketseastern US are in the USA on 21 Februaryearly stages of production and in Japan on 22 March.growing steadily.

Gas filling into the storage caverns in the Aldbrough project in the UK started in August. This is a cooperation project for natural gas storage between the British company SSE Hornsea Limited (SSEHL) and StatoilHydro.

Technology and new energy
StatoilHydro established a a research and development centre in Alberta, Canada to support the group's heavy oil business world-wide. In creating the Heavy Oil Technology Centre (HOTC), StatoilHydro will explore academic partnerships and work with government and industry institutions, just as it has done in its operations in Norway and around the world.

The most complicated well in StatoilHydro's history was successfully completed and hydrocarbons were flowing up through the well at 9910 metres. This is thus the longest producing well in the world drilled from an offshore platform. The well provides the company with valuable knowhow.

Social responsibility and sustainable development
StatoilHydro decided to build the world's first full scale floating wind turbine, and test it over a two-year period offshore Karmøy.

Production resumed on the Statfjord A platform 28 May, after four days of shutdown due to an oil leak Saturday 24 May. For safety reasons, a total of around 1,200 cubic metres of oil-containing water were pumped to sea. This was done to ensure safety on board the platform following a leak in a pipe inside one of the shafts of the installation. Oil protection equipment and oil booms were deployed to collect a thin oil film around the Statfjord A platform.

StatoilHydro submitted an external investigation report on the Libya matter to Norwegian and US authorities on 7 October. Consultancy agreements related to Norsk Hydro's earlier activities in Libya contain issues which could be problematic in relation to Norwegian and US anti-corruption legislation. The report has been submitted to the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim), to the US Department of Justice (DoJ), the US Securities and Exchange Commission (SEC) and to the relevant Libyan authorities.

StatoilHydro and Indian oil company ONGC agreed on 6 February to jointly explore the potential of developing Carbon Capture and Storage (CCS), and CDM (clean development mechanism) projects in India.

Carbon injection and storage on the Snøhvit field started on 22 April. Instead of emitting the carbon dioxide (CO2) resulting from the well stream that comes from the Snøhvit field to the air, the CO2 is reinjected into the ground and stored in a formation which lies somewhat beneath the gas-bearing formations on the Snøhvit field.

StatoilHydro submitted a plan for carbon capture at Mongstad to the Ministry of Petroleum and Energy and the Ministry of the Environment. The plan addresses the most important challenges and sums up key issues associated with the technical feasibility of carbon capture at Mongstad. This is the first step along the way towards full-scale carbon capture at Mongstad.��

2 Business overview

2.1 Our business

StatoilHydro

Statoil is an integrated oil and gasenergy company based in Norway andNorway. The company is present in approximately 40 other countries worldwide. We are the leading operator on the NCS and are also enjoyingexperiencing strong growth in our international production.

.

StatoilHydroStatoil ASA is a public limited company organised under the laws of Norway and is subject to the provisions of the Norwegian act relating to public limited liability companies (the Norwegian Public Limited Companies Act).

Entitlement oil and gas production outside Norway represented 17%accounted for 20% of our total output,production, which averaged 1.7511.806 mmboe per day in 2008.
 2009.

As of 31 December 2008,2009, we had proved reserves (including our share of reserves in affiliated companies of 127 mmbbl of oil) of 22012 174 mmbbl of oil and 537.8514 bcm (equivalent to 19.018.1 tcf) of natural gas, corresponding to aggregate proved reserves of 5584.5 408 mmboe.

We are represented in approximately 40 countries and are engaged in exploration and production activities in 2422 of them. As of 31 December 2008,2009, we had approximately 29,50029,000 employees.

We rankare among the world's largest net sellers of crude oil and condensate and we are the second largest supplier of natural gas to the European market.

We have substantial processing and refining activities and approximately 23002000 service stations in Scandinavia, Poland, the Baltic States and Russia.

We are contributing to developingthe development of new energy resources, have ongoing activities in the fields of wind power and biofuels and are at the forefront in implementingof implementation of technologies for carbon capture and storage (CCS).

In further developing our international business, we intend to utilise our core expertise in areas such as deep waters,water, heavy oil, harsh environmentenvironments and gas value chains in order to exploit new opportunities and executedevelop high quality projects.

Business address

Our business address is Forusbeen 50, NO-4035N-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Our largest office locations in terms of the number of employees are in Stavanger, Bergen and Oslo.Oslo, Norway.

The StatoilHydroStatoil group and the main business and functionalfunction areas are presented in the following sections.

 sections of this report.

The figures below provide an overview of the geographical reach of Statoil's business and the organisational structure of our business areas and staff functions.

2.2 Our history

Statoil was foundedformed in 1972 and merged with Hydro's oil and energy business in 2007. We changed our name to StatoilHydro on 1 October, 2007. 

Statoil ASA (Statoil) was founded by a decision of the Norwegian Storting (parliament) and was listed on the Oslo and New York stock exchanges in 1972. As a result of Statoil's merger with the oil and energy business of Hydro (formerly Norsk Hydro), we have roots in the oil industry dating back to the 1960s when Hydro took part in the exploration of the NCS.

2001.

Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap a.s. Wholly-owned by the Norwegian State, the company's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway. In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and changed its name to Statoil ASA.

On 1 October 2007, the oil and energy assetsdivision of Hydro were(formerly Norsk Hydro) was merged with Statoil, and the company was given the temporary name of StatoilHydro ASA. On 1 November 2009, the company changed its name back to StatoilHydroStatoil ASA. Through this merger, our ability to fully realise

We have grown in parallel with the potential of the NCS was strengthened and our chances of succeeding as an international player improved. As a result of the merger, we are the largest international oil and gas company operating in water deeper than 100 metres. The financial and other information in this report reflects the development of the former Statoil and Hydro on a carry over or combined basis for all periods presented.

Our history of involvement in theNorwegian oil and gas industry, began in earnest in 1965, when we were awarded licences bywhich dates back to the late 1960s. The commencement of our operations focused primarily on the exploration, production and development of oil and gas on the Norwegian State to explore for petroleum on the NCS. We participated in the discovery of the Ekofisk field in 1969 and the Frigg field in 1971. The development of these discoveries brought us into the petroleum refining and marketing business.continental shelf (NCS) as partner.

In 1975,the 1970s, we commenced our own operations, made important discoveries and entered into oil refining operations, began at Mongstad in Norway, and in 1974, Mobil discovered the Statfjord field in the North Sea, which washave been of great significance forimportance to the further development of the Norwegian Continental Shelf (NCS). During the development of Statfjord, one of the world's largest offshore oilfields, we encountered great challenges. Statfjord came on stream in 1979 and we took over as operator eight years later. Today, we have a 44% interest in the field.NCS.

In the 1980s, both Statoilwe saw substantial growth through the development of major fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and Hydroothers). We also became a major playersplayer in the European gas market by obtainingsecuring large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, we were heavily involved in manufacturing and marketing in Scandinavia, and we established a comprehensive network of service stations. We acquired Esso's service stations, refineries and petrochemical facilities in Denmark and Sweden.

The 1990s were characterised by substantial improvements in the production performance of our large fields, resulting from intense technological development on the NCS. Both Statoil and Hydro becameWe laid the base for future improvements by becoming a leading companiescompany in the fields of floating production facilities and subsea developments. Wedevelopment. The company grew strongly, expanded in new product markets and increased ourits commitment to international exploration and production through our alliance with BP. The foundations for the today's merged company were also laid with Hydro's acquisition of Saga Petroleum in 1999, and several major acquisitions in the Gulf of Mexico.production.

Since 1 October 2007,2000, our business has grown as a result of substantial investments on the NCS and acquisitions includinginternationally. Our ability to fully realise the acquisitions of oil sand leases in Canada in 2007, and the acquisitionpotential of the remaining shareNCS was strengthened through the merger with Hydro's oil and gas division, which also bolstered our global competitiveness. In recent years we have taken advantage of our competence to design and manage operations that function correctly in the Peregrino fieldenvironments they face, in Brazil completedorder to grow our upstream activities by means of other than traditional offshore production, for example threough the development of heavy oil and shale gas projects.

Although petroleum related activities on the NCS and internationally have formed the main part of our business, we have increasingly participated in 2008, for which field we also became the operator. Since October 2007 we also have had a 24% ownership shareprojects focusing on other forms of energy project, such as wind power and carbon capture and storage, in Shtokman Development AG which is responsible for phase Ianticipation of the Shtokman development a natural gas field located in the central part of the Russian sector of the Barents Sea.need to expand energy production, strengthen energy security and fight adverse climate change.

Our most recent transaction involves a strategic agreement to jointly explore unconventional gas opportunities worldwide with Chesapeake Energy Corporation, the largest US producer of natural gas. Under these agreements StatoilHydro acquired an initial 32.5% interest in Chesapeake's Marcellus shale gas acreage covering 1.8 million net acres (7300 square kilometres) in the Appalachia region of the northeastern USA. For more information of this acquisition, see report section 3.2 Operational review-International E&P.

2.3 Statements on competitive position

Statements referring to StatoilHydro'sStatoil's competitive position rely on a range of sources, including analysts' reports, independent market studies and our internal assessments of our market share.

Statements referring to StatoilHydro'sStatoil's competitive position in the Business Overview and Operational Review sections are based on what we believe to be true and, in some cases, they rely on a range of sources, including investment analysts' reports, independent market studies and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.

2.4 Strategy

Statoil's long-term strategy builds on the company's vision: 'Crossing Energy Frontiers'. It continues the current strategic direction of creating shareholder value as an upstream-oriented, and technology-based energy company.

In StatoilHydroOur strategy of long-term value creation, starts with our short-term deliveries on operations and HSE. As we are working towards our goals of continuing our strategy for profitable growth and upholding our ambition to increase equity production of oil and gas to 2012 and beyond, despite great uncertainty in the global economy and oil market.

In workingwork towards our ambition to realiseof realising the full value potential of the NCS,Norwegian Continental Shelf (NCS), we are simultaneously developing international platforms for long-term growth and we are gradually building a position within new energy. The company is well positioned to manage through the global economic downturn. A strong balance sheet and active cost management will enable the company to pursue this long term strategic direction.in renewable energy production.

2.4.1.Business environment

In 2009 the world economy experienced the most severe recession since the Great Depression of the 1930s. There is still significant uncertainty as to the health of the world economy.

The global economy entered into recession has led to a significant reduction in energy demand in most regions. Energy prices fell significantly in the first part of the 2009, and caused a large reduction in revenues for the players in the industry. The corresponding falls in suppliers' costs have been much smaller. Thus, the industry's profitability has weakened significantly. Most energy commodity prices have showed a partial rebound during the second half of 2008. Nevertheless, energy2009 contributing to a more positive outlook for 2010.

Macroeconomic outlook
After growing by more than 3% on an annual average basis during 2000-2008, the world economy in 2009 experienced the most severe recession since the Great Depression of the 1930s. Following the turbulence in the international financial system in the autumn of 2008, plunging business confidence and demand retrenchments led to a sharp contraction in global industrial production and international trade. In the first quarter of 2009 world economic activity fell by almost 4%. However, resolute and strong policy responses in all major economies stabilised the financial markets, restored general market confidence and from mid-2009 put the world economy on a moderate recovery path. China and other emerging economies in Asia provided an important stimulus to developed economies. For the year as a whole, there was a negative GDP growth of 3.4% and 1.9% for the OECD economies and the world economy, respectively.

At the beginning of 2010, the recovery of all major economies is still in progress. The rate of improvement does, however, vary across sectors and regions, as does the uncertainty of the outlook. Asia Pacific, less affected by the financial crisis and debt financed consumption, continues to grow relatively strongly, while the expansion in the United States and especially the European economies is more hesitant. This is mainly due to the household sectors' need for debt deleveraging, the high unemployment rate and the low rate of capacity utilisation in most industries. Furthermore, although the balance sheets of the financial institutions have improved during 2009, the planned banking reforms and the banks' own consolidation suggest that bank lending will continue to be restricted for some time. Overall, these forces indicate that the recovery of the world economy is expected to pickcontinue during 2010, but with a less vigorous upturn than was typical for previous business cycles.

The governments' economic rescue packages, which successfully contributed to the stabilisation and recovery in 2009, have led to severe deterioration of public finances in most OECD countries. The federal deficits of the main economies, excluding Germany, have increased from pre-crisis levels of about 1.0-2.0% of gross domestic products to an estimated 9-12% for 2010. Since these levels of public deficit are not sustainable, the outlook beyond 2010 implies a more contractive fiscal policy. This is likely to restrain the pace of economic growth beyond 2011-2012. The underlying structural global imbalances, which were among the underlying causes of the recession of 2008-2009, have been corrected only partly and temporarily. Overall, these imbalances suggest that the medium-term outlook for the world economy is still marked by uncertainty.

Energy markets and price developments
The sharp fall in world economic activity in 2008-2009 led to large reductions in energy demand in most regions of the world. Driven by a 2.1 mbd reduction in OECD oil demand, global oil demand fell by about 1.3 mbd (1.5%) from 2008 to 2009. The demand for natural gas also fell significantly in North America and Europe by 1.1 % and 6.3% (estimate), respectively. Helped by the relatively short-lived economic downturn, oil and gas demand held up reasonably well in China and non-OECD Asia. The weakness in energy demand has pushed energy prices are expecteddown to increaselevels not seen since the early 2000s.

After the historical high of USD 144 per barrel (dated Brent) in the longer term.

Macroeconomic outlook
The global economy entered into recession inmid-2008, crude oil prices plunged by about USD 100 per barrel during the second half of 2008, before levelling out in the USD 40-45 per barrel range in the first quarter of 2009. The stabilisation was helped by large cuts in Opec production, which stabilised the physical markets and signsprevented oil stocks from building further. Despite the high oil stocks and comfortable spare Opec production capacity, crude oil prices started to recover in the second quarter, triggered by expectations of an emerging world economic recovery and the prospect of a cyclical downturnweaker US dollar. The upward trend in oil prices lasted throughout the year, supported by constructive macroeconomic data and relatively strong demand growth in Asian markets. By the end of 2009, prices were around USD 75 per bbl. Financial players' perceptions, portfolio optimisation and market positions were important drivers behind the 2009 oil price recovery. The average price of date d Brent in 2009 was USD 61.6 per bbl, down from USD 97.3 per bbl in 2008.

The Atlantic products' markets have also been severely hit by the economic recession. Total demand for products in the real economyUS and OECD European markets both fell by close to 0.8 million barrels per day, or more than 4%, from 2008 to 2009. Reduction in the demand for distillates, including diesel oil, gas oil and jet/kerosene accounted for about half of the total, while gasoline demand kept up relatively well in both regional markets. Lower demand for oil products led to high products stocks and downward pressure on the price differentials between oil products and crude oil. However, the relative stability of the gasoline markets led to less depressed gasoline differentials (margins), while distillate margins were evidentat their lowest since 2003-04. Thus, refineries with a high gasoline yield were somewhat sheltered from the recession, led market developments of 2008-09.

Natural gas prices (spot) in North America and Europe, which also peaked in mid-2008, fell continuously until September 2009 on the prospect of significant oversupply. This was driven by the outlook for recession-induced demand reductions, sustained US domestic production and prospects for a steep growth in the imports of LNG into the Atlantic Basic markets. Especially in the United States, market gas prices came under downward pressure due to a concern that the need for storage capacity could exceed the actual storage capacity. Prices reached a low of about USD 2.5-3.0 per million BTU in September 2009 - the lowest level since 2002-2004. Gradually, however, it became clear that as US domestic production began to slide, natural gas captured market shares from coal in power generation, the storage surplus was not growing and significant volumes of Middle East LNG supplies were directed to Asian and European markets. The reduced supply pressure put gas prices in both markets on a moderate recov ery path, and by the end of the year US prices were back at about USD 5.70 per million BTU, close to the price levels at the beginning of the year. Although US conventional production slid further through 2009, the expansion of unconventional gas production, especially the production of shale gas, continued its sharply rising trend through the year. The European market has also been affected by lower gas demand and increased supply pressure, primarily from higher volumes of NGL and European spot prices (NBP) followed a similar pattern as US spot prices. The average NBP spot prices were reduced from USD 11.43 per million BTU in 2008 to USD 4.94 per million BTU in 2009.

European electricity prices fluctuated around a level of EUR 50-60 per MWh during 2005-08 and reached a peak of almost EUR 100 per MWh immediately after the break-out of the crisis in the financial markets in the autumn of 2008. Following the sharp decline in European economic activity during the winter of 2008-09, power demand contracted by more than 6 % (estimate) relative to the year ledbefore and pushed electricity prices to a low of EUR 30-40 per MWh. Power demand recovered during the second half of the year and pulled prices up into the EUR 40-50 per MWh range.

Prices in the European carbon dioxide market, the EU Emission Trading Scheme, tend to follow the same pattern as electricity prices as that market shares the same demand-side drivers. Carbon prices have, however, been relatively stable around EUR 13-15 per tonne during 2009. The lack of a clear direction following the Copenhagen meeting on future global and regional climate policies pushed carbon prices moderately downwards in December 2009.

The outlook for energy prices over the next few years is basically linked to the prospects for a moderate recovery of the world economy. The oil market is likely to resume the pre-crisis trends of moderate demand growth, modest to stagnant growth in non-Opec production and some expansion in Opec NGL/condensate production. This also suggests that Opec's spare production capacity will gradually be reduced. However, since oil price formation is strongly influenced by falling housingfinancial players, the uncertain outlook for financial markets, geopolitical developments and the US dollar will continue to be important additional drivers. The short-term outlook for the Atlantic Basin products markets is driven by a modest demand growth and the potential for products imports from several export refineries in the Middle East and Far East. The outlook for a sustained overcapacity in refining in the Atlantic Basin may at some point lead to capacity closures in Europe.

Prospects for a rebalancing of the European and North American gas markets are related to the strength of economic recovery. On the demand side, the price-driven competition with coal will continue to be important. The outlook for a further rise in US conventional gas production at relatively low costs has reduced the potential for imports to the North American markets. The prospects for increased LNG supplies into the Atlantic Basin are expected to cap significant natural gas price increases.

Industry context
Restricted upstream access, increasingly complex resources, the climate challenge and tougher financial terms have become more evident as strategic challenges for the oil and gas industry over the last 10 years. Access to resources restricts the growth potential of oil and gas companies, with a large share of the world's remaining conventional resources held by countries with limited access for international oil companies (IOCs). National oil companies have also entered the industry contest for international resources, resulting in an industry arena that is more competitive than ever. IOCs are therefore gradually being pushed to grow their asset base by accessing hydrocarbons in more remote areas, in deeper waters and in more technologically challenging environments. As a result, the contribution made by unconventional and deepwater hydrocarbons has increased by more than 10 percentage points during the last decade to make up nearly 30% of global production capacity in 2009. There are reasons to expect this trend to continue. Another key point is the global climate challenge. Climate regulation still remains uncertain post-Copenhagen, but a potential cost impact related to future policy adjustments remains a likely outcome. In addition to the access and climate challenge, industry profitability has tightened both through increasingly stringent government terms, but recently also through the margin squeeze following the financial turmoil.

The fall in oil and gas prices in the USautumn of 2008 in the aftermath of the banking crisis took its toll on the industry in general. With average oil prices down by almost 40% in 2009 compared to 2008, revenues were severely hit. At the same time, suppliers' costs did not show a corresponding decrease. Data suggest that the cost level fell by 20-25% within capital intensive categories, while labour intensive supplies were reduced about 10%. Thus, overall industry profitability has significantly declined compared to 2008.

As a result of the margin squeeze, many companies have had to increase their borrowing, adjust their capital expenditure plans, re-evaluate their dividend policies, reduce their share buyback programmes and several European countries. The downturnincrease their focus on cost control and capital deployment efficiency through tighter prioritisation of exploration and development opportunities.

During the fourth quarter of 2008, most sources of funding dried up, and corporations with weak credit ratings had limited access to the bond market. However, the bond market recovered in 2009, especially for high-quality borrowers like the IOCs, which led to a large number of bond issues. Most of the money raised was reinforcedused to finance existing operations and capital expenditure commitments rather than merger and aquisitions activities. Global E&P spending fell by some 15 - 20% in 2009. On the NCS on the other hand, the investment level grew by 14% mainly led by new field developments which are more challenging and require more resources due to their complexity and smaller size. With a more positive market sentiment and the jump in oil prices since the second quarter of last year, there is also an expectation of increased E&P spending for next year. Industry surveys indicate that global E&P expenditures will increase by approximately 10% this year. Statistics Norway suggests that th e 2010 investment level on the NCS will be slightly lower than that of 2009. Consistent with the overall themes in the industry of cost control and capital discipline, disposals of non-core assets are back on the agenda. Several assets are currently being marketed among major oil and gas companies.

Following the financial turmoil, the drop in demand has led to refinery overcapacity and pressure on margins. This is exacerbated by the financial crisis that escalatedstart up of several export refineries in September. A vast deleveragingthe Far East and Mid-East. In the longer term, refining overcapacity in both household and corporate sector will lead to slowing growth rates in consumer spending and investments in all regions.

Global GDP growth is currently expected to be negative in 2009. Within two to three years we expect global growth to return to the long term trend, within the range of 2.5 to 4%. The impact of the policy measures and government stimulus packages is unknown and intended positive effects therefore represent considerable uncertainties for these forecasts.

Crude oil price developments

Dated Brent entered into 2008 on a strong upward trend extending from 2007, and accelerated as financial investors increased positions in a search for more favourable yields. Strong support from a tight gasoil/diesel market and declining crude oil inventories led to an increasingly tight oil market, and the Brent dated reached a record high level of 144 USD/bbl in July 2008.

At this point an underlying tendency of slower global GDP growth and weakening product demand started to discourage investors. With a shift of both sentiment and outlook during 2008, crude oil prices were fundamentally different from the first half to the second and traded between 33 and 40 USD/bbl in December. Brent dated averaged 97.26 USD per barrel in 2008. The gas, power and EU ETS (Emission Trading Scheme) prices have broadly followed oil prices through 2008.

With the global economy deteriorating, the energy markets are expected to stay relatively weak in 2009 and possibly into 2010 and 2011. Over time as the macro economic situation improves, energy demandAtlantic basin is expected to pick uplead to capacity closures in Europe.

The increased concerns for energy security and climate change have continued to fortify policy and long-term market drivers for commercial growth in renewables. While most renewable energy pricesforms are more costly than fossil fuels are today, the competitive landscape is expected to rise.

High cost environment

In recent years, the oil industry has focused largely on growingshift as production and the resource base. Ascosts for renewable energy prices soared and the competition for resources intensified,decline, while the cost of buildingcarbon emissions is reflected in power and fuel prices. Significant amounts of public and private funding are currently going into research, development and expansion of new technologies in order to make renewables and Carbon Capture and Storage (CCS) more competitive.

Wind power is the largest single market for new energy, with prospects of increasingly higher production capacity increased steeply. The tighteninggrowth over time. Offshore wind is expected to take a significant share of the suppliertotal wind market intensifiedif several of the cost push. With reduced oil demand and falling oil prices, this high cost environment is not seen as sustainable. If the oil price remains at current low levels, we expect costsmajor countries are to be reduced going forward.achieve their renewable energy goals.

 Top 

2.4.2 A strategy for value creation and growth

StatoilHydro

Statoil's strategy is continuingto profitably grow its strategy for value creation and growth and upholding its ambition to increase the equity production oflong term oil and gas up to 2012, despite great uncertaintyproduction while gradually building a position in the global economy and the oil market.

renewable energy production.

Overall strategic direction
Our overall long-term strategy remains unchanged, and we are taking firm action to manoeuvre through the current turmoil. StatoilHydro's strategy is to create shareholder value as an upstream-oriented, and technology-based energy company. This strategy can be summarised as:

• Maximising long-term value creationbuilds on the NCSfollowing key components:
  • Utilise our technology and management capabilities to capture the full potential of our positions on the Norwegian continental shelf (NCS).
  • Building and deliveringDeliver profitable international growth in the short and medium term from existing positions, whilst creating new opportunities for long-term value creation.
  • DevelopingUse exploration as a key growth tool to secure long-term production capacity.
  • Develop profitable midstream and downstream positions in support of our upstream activities.
  • CreatingPursue selected business opportunities for renewable energy production and CCS.
  • Apply technology and innovate in order to create value and accelerate asset developments.
  • Minimise carbon emissions from, and the general environmental impact of, our upstream and midstream activities.
  • Utilise organisational capabilities as a platform for newglobal energy solutions and productioncompany.

  InShort term priorities are to conduct safe and efficient operations and to deliver production growth in line with our guidance. We are transforming the short term,way we work on the NCS in order to realise the full value potential of our main focus will be on delivering on our production targets and managingpositions there. We continue tight management of our cost base. This means delivering high operational performance, with a strong focus on HSE.Retaining financial flexibility remains important for us. In the longer term, our focus ispriorities are to developoptimise, mature and execute the current project portfolio, with qualitytaking into account the dynamic economic environment, the globalisation of gas markets and the politically imposed framework and regulatory measures aimed at a competitive cost to enable us to grow profitably.mitigating the risk of adjustment costs induced by climate change.

  LeveragingUtilising our capabilities
  Gaining access to sufficient petroleum resources is increasingly challenging. We are seeking new opportunities in demanding areas requiring the full use of our legacy competence in technology and capabilities
  management. We also realise that mastering the most demanding areas qualifies us for succeeding in less demanding areas. There are four demanding areas of high potential in which StatoilHydroStatoil has experience and competitive advantages and the experience to face challenges and capture opportunities:advantage:

  • Deep waters: We already have a relatively significant exposure towater: we are active in six of the most interesting deep waterdeepwater basins in the world - the Gulf of Mexico, Brazil, Angola, Nigeria, Norway and Indonesia.
  • Harsh environments: Examples are Shtokman, Goliat, and Snøhvit. Wewe see the resource potential of the Arctic as particularly interesting, although it is a region that is not expected to deliver substantial results until the medium to longer term due to the technical and environmental challenges.challenges .
  • Heavy oil: For example the Grane fieldwe have positions in Norway, the oil sands position in Canada, heavy oil in Venezuela, and more conventional offshore heavy oil projects in Brazil and the United Kingdom.
  • Gas value chain: This categorywe are active in finding and delivering gas in many countries and have an extensive portfolio that includes liqueifiedLiquefied Natural Gas (LNG) and unconventional gas, from thee.g. US shale gas transaction.gas.

  Responding to the climate challenge
  Our ambition is to be an industry leader in carbon efficiency in terms of having a low climate impact in each of the activities in which we are engaged. We aim to create value by seeking low-carbon and energy-efficient competitive solutions in all areas of our business. Responding to the climate challenge in an effective manner will give our company a competitive advantage in the future.

  Maximising value creation from upstream access opportunities
  We will use exploration as a key growth tool to secure long term growth of reserves, production and value. This is consistent with maximising the long-term value of the NCS and with leveraging our core competencies to build, mature and deliver profitable growth outside Norway. We will continue to optimise our exploration portfolio, balancing frontier-, growth- and infrastructure led exploration.

  We will continue selective business development activities to optimise the portfolio.

  Maximising long-term value creation on the NCSNorwegian continental shelf (NCS)
  StatoilHydro has a unique position on the NCS, where we operate 39 fields and produce more than three mmboe per day of production. We have a strong presence in all NCS regions and operate around one-third of the NCS's expected reserves. We expect that our asset base, experience and technical leadership will enable us to fully utilise these resources. We anticipate the NCS portfolio will continue to be a core activity area, income generator and technology base for many years to come. We believe that significant exploration potential remains and we aim to maintain our position as the main industrial architect.industry player on the NCS.

  We are focused on improvingcontinuously work to improve our HSE performance regularity and drillingour cost and operational efficiency and we planas well as implementing measures for improved hydrocarbon recovery (IHR). We see a structural shift in our non-sanctioned project portfolio from a few large, complex projects to use Improved Oil Recovery (IOR) measures and other operational best practices to maximise the potentiala high number of our assets. We intend to highgrade our portfolio, through acquisitions and divestments.mainly smaller projects or sub-sea tie-backs. This demands a high level of standardised technical concepts as well as simplified development processes.

  Building and delivering profitable international growth
  Our strategy is to deliver profitable international growth in the short and medium term from existing positions, while creating new opportunities for long-term value creation. We will utilise our core expertise in areas such as deep waters, harsh environments, heavy oil and the gas value chain to pursue attractive business opportunities around the world. Statoil's history as a state oil company gives us a competitive advantage in understanding host countries' needs and requirements and in working with them to develop the resource base to their benefit while creating value for our shareholders.

  We anticipate that StatoilHydro'sStatoil's future growth beyond 2012mainly will take place mainly outside the NCS. Our short-short to medium-term focus is on delivering and maturing a high qualityhigh-quality project portfolio to a high quality and on time and within budget. After the merger, we are a stronger company with increased capacity and a larger resource pool of finances and employees, well positioned to pursue further international growth. In the longer term, we expect that our international asset base will transform the structure and profile of our company, allowingallow us to grow and become more diversified, both in geographical terms and in types of production.

  We will use our core expertise in areas such as deep waters, harsh environments and heavy oil and gas value chains to pursue new business opportunities around the world. We have already demonstrated this through our acquisition of the oil sands position in Canada, the Peregrino field in Brazil, and the US shale gas position - all of which represent new challenges and opportunities for us to apply our technology and experience. For a description of these acquisitions see Section 3.2 Operational Review - International E&P.

  We will continously seek to high grade our portfolio, for instance as we have done in our long term partnership with Sonatrach on Cove Point, and our acquisition of the remaining 50% of Peregrino and its operatorship. StatoilHydro's history as a national oil company (NOC) also gives us a competitive advantage in developing new cooperative models with other NOCs that are seeking partners for developing their resource bases.

  Developing profitable midstream and downstream positions
  StatoilHydro's ambitionStatoil's strategy is to develop projects and production into produce oil and gas where we see a potential for attractive returns and value added to the upstream positions. Compared with many of our peers, wevalue. We have a strong upstream focus in terms of our total value and asset base. Furthermore, we also havebase, complemented by a sizeable mid-midstream and downstream portfolio in relationrelated to the marketing, trading, refining and storage of oil and gas products. We seek to capture synergies from our upstream positions and the market characteristics.

  We anticipate further globalisation of the gas markets, and changes in the location of our oil and gas production. We also expect changes in consumption patterns in the aftermath of the financial crisis and as a result of the introduction of greenhouse gas mitigation measures by the authorities. We will monitor our midstream and downstream activities and adjust in a timely manner to meet the needs of markets and of our upstream positions to optimise our portfolio and maintain shareholder value.

  Creating a platform for newrenewable energy solutionsproduction and productioncarbon capture and storage
  Our ambition in this areastrategy for renewable energy production and carbon management is to utilise existing core capabilities and current business positions to create profitable positions in renewable energy, prioritising offshore wind projects while keeping track of opportunities in other other areas through technology and selective investments.

  We are building a profitable businessportfolio of near-shore and off-shore wind farms and we are developing technology for large-scale deep water offshore wind power generation. In this context, our participation in Sheringham Shoal UK wind farm was an important milestone achieved in 2009 as was the preparation for the Forewind consortium on the Dogger Bank development to which we were awarded rights in 2010. Off the south-west coast of Norway we are piloting a prototype of the world's first full-scale floating wind turbine, Hywind, which is designed to be placed at water depths between 120 and 700 metres.

  In addition, we reduce emissions of greenhouse gases from our production. StatoilHydro is a leading industry player infossil energy production through carbon capture and storage. We are looking for opportunities for commercially sound investments in renewable energy, particularly in wind and sustainable biofuels, where we can exploit our offshore experience and fuel marketing know-how. We aim to build a portfolio of near-shore wind parks and develop technology for large scale offshore wind power generation.

  Using exploration as a key enabler for value creation
  Consistent with the strategies for maximising the long-term value of the NCS as well as building and delivering profitable international growth, StatoilHydro's ambition is to develop upstream projects and production in oil and gas where we see attractive returns, both in Norway and internationally. Our exploration strategy is key to this and is based on gaining access to high-potential basins globally and targeting multiple blocks in high-focus areas.

  Our exploration strategy can be divided into three categories:

  Frontier exploration aims at proving new fields in areas where the petroleum system remains unproven.

  Growth exploration involves exploring for fields with stand-alone potential in areas where the petroleum system is known. We have a strong strategic focus on being an active operator with a view to shaping the future direction of our business.

  Infrastructure-led exploration seeks to provide resources to existing infrastructure in a timely manner.storage (CCS).

  Using technological innovation and implementation as a key business enabler
  StatoilHydro aims to build even stronger industry positions, and technologyTechnology is a key enabler for achieving this goal and forin terms of Statoil realising our key strategies. The merger strengthened us significantly in the area of technology, providing us with a platform to further exploit our technical base. One example is the world class technology used on Troll and Gullfaks, where extended, multilateral and smart wells drain previously unrecoverable resources.

  its goals as an internationally competitive energy company. Our ambition is to attain distinctiveness and industrial leadership in six specific technologies:

  • Exploration seismic imagingby aligning our technology and interpretation
  • Geophysical reservoir monitoring
  • Oil sand reservoir characterizationR&D efforts with our portfolio of activities and recovery
  • Intelligent drilling
  • Subsea processingvice versa.

    Based on our history of technological achievements, we actively seek to master demanding and long-range multiphase transport

  • Carbon dioxide management
  critical developments within our priority activity areas. We prioritise technology efforts that add value to resources, and that allow us to develop smarter solutions for energy exploration and production, that are cost-effective and environmentally benign. We refine and standardise our technical requirements and work processes.

  Technology makes a decisive contributioninnovation and implementation is critical to success in allmany of our activities, such as inenabling field development in frontier deep waters and Arctic areas, the production of heavy oil, production, subsalt exploration for hydrocarbons trapped below salt, and managing environmental and climateclimate-related issues. Our ambition is alsoIn addition, to stayenable sustainable energy provision in the long term, we aim to remain competitive in a broad range of core and emerging technologies, along the energy provision value chain, including offshore wind and sustainable biofuel.

  We aim to maintain the right course to capture future business opportunities and to develop smarter solutions to explore for and to produce energy in cost effective and environmentally friendly ways.

   Top 

  2.5 E&P Norway

  2.5.1 Introduction to E&P

  Exploration & Production Norway (EPN) consists of our exploration, field development and production operations on the NCS.

  EPNExploration & Production Norway (EPN) is the operator of 42 developed fields that collectively produced more than threeon the NCS. Statoil's equity and entitlement production on the NCS was 1,450 mmboe per day in 2008,2009, which representedwas about 80%75% of theStatoil's total production. Acting as an operator, EPN is responsible for approximately 75% of all oil and gas production fromat the NCS. . In 2008,2009, our average daily production of oil and natural gas liquids (NGL) production was 824784 mboe and our average daily gas production was 101.3105.9 mmcm (37.1(3.7 bcf), totalling 1.461 mmboe per day..

  We have ownership interests in exploration acreage throughout the licensed parts of the NCS, both within and outside our core production areas. We participate in 346219 licences on the NCS and are an operator for 174162 of them.

  As of 31 December 2008,2009, EPN had proved reserves of 1,3961,351 mmbbl of crude oil and 498480 bcm (17.58(16,9 tcf) of natural gas, which represents an aggregate of 4,5294,369 mmboe.

  .

   Top 

  2.5.2 StrategyE&P strategy

  Several factors are expected

  E&P Norway's strategy is to contribute to StatoilHydro's equity production on the NCS, including increased production and drilling efficiency, more cost-effective operations, and improved recovery from existing fields.

  Other important measures include development of new discoveries, the proving of new resources through intensive exploration activity, increased access to new licences, enhanced focus on health, safety and the environment (HSE), and optimal use of existing infrastructure.

  Our overall strategy on the NCS is defined as:

  • Safe, efficient and reliable operations
  • Capturingrealise the full potential of the NCS in terms of developing profitable oilthrough exploration, new developments, improved operational and gas resources

  Maintaining current production level
  As several fields on the NCS are maturing and production declines, high priority will be given to the implementation of measures to increase productiondrilling cost-efficiency, increased recovery from existing fields. The main measures in this context are more efficient drilling, increased regularityfields and improved oil recovery (IOR).

  Higher regularity is expected to be achieved through improved well work, better reservoir management, de-bottleneckingthe optimal use of export infrastructure, improved planning of turnarounds and fewer topside plant failures.

  Additional production is expected to be achieved by means of new capacity, including ramp-ups on Ormen Lange and Snøhvit, new field developments and implementation of IOR measures.

  Tie-ins to existing infrastructure on fields that are in decline and/or have reached a critical point in their technical life will also have high priority. A well-balanced asset portfolio on the NCS with respect to regions and maturity is necessary to sustain total oil and gas production at current levels.

  infrastructure.

  We need to achieve optimal development and exploitation of our existing portfolio in order to secure a solid foundation for future growth through continued high exploration activity. Active infrastructure-led exploration is a key factor in extending the life of the infrastructure in the tail-end production phase. However, access to new, prospective acreage is also necessary to maintain a high production level in the longer term.

  One of our ambitions is to become one of the leading players in the Arctic by 2020. Considering the long lead times of field developments, a near-term opening of new acreage is imperative. Succeeding in new field developments in the northern areas of the NCS is a priority for StatoilHydro. Important efforts are currently underway to maintain stable operations in the Snøhvit LNG project, and to support a timely and robust development of the Goliat oil field. However, new high-quality exploration acreage remains a critical prerequisite for long-term success. To meet our ambitions in the northern area, we have to feasibly mitigate challenges in a range of areas - including geology and technology.
  
  Gas position
  The proportion of natural gas from our NCS portfolio is increasing. We have a flexible transportation system, with six different landing points on the European Continent / UK and flexibility in terms of gas deliveries from large gas producing fields such as Troll and Oseberg.

  Safe and efficient operations are essential to our business
  All activities in StatoilHydroStatoil are conducted with higha great focus on HSE in order to prevent harm to people and the environment. The implementation of Integrated Operations (IO) is expected to enhanceincrease economic value through higher production, higher regularity and cost reductions. Upgrading and modification programmes for offshore installations are also planned with a view to maintaining safe and efficient operations.

  OurThrough our ongoing efforts to introduce one common operating modelfinalise the implementation of integrated operations and common work processes on all our installations on the NCS will enable uswe aim to utilizeutilise best practices and optimise usagethe use of our total resources to ensure safe and efficient operation.

  UnitMaintaining a high production costslevel
  Several fields on the NCS are maturing and production is declining. High priority will therefore be given to more efficient drilling operations, improved regularity and increased hydrocarbon recovery (IHR).

  High regularity is expected to be achieved through efficient well work, better reservoir management, de-bottlenecking of export infrastructure and efficient turnarounds.

  It is important to utilise unused capacity in existing infrastructure. Active near-field exploration is a key factor in extending fields' lifetime and initiating cost-effective tail-end production on fields that are in decline and/or have been onreached a rising trendcritical point with respect to profitability.

  Optimal development and exploitation of our existing portfolio is necessary in recent years,order to secure a solid foundation for future activities through continued active maturation of the project portfolio and high exploration level. New field developments are in line withgeneral more challenging than before either in terms of complexity, smaller size or profitability. Hence these projects require more resources per barrel than before.

  Access to new, prospective acreage is also necessary in order to maintain a high production level in the industry development. StatoilHydro's managementlonger term. One of our ambitions is implementing measures to contain future cost inflation.become one of the leading players in the Arctic by 2020. Considering the long lead times for field developments, it is a pre-requisite in the near term to open new acreage. Succeeding in new field developments in the northern areas of the NCS is a priority for Statoil. Important efforts are currently under way to maintain stable operations in the Snøhvit LNG project, and to support timely and robust development of the Goliat oilfield. However, new high-quality exploration acreage remains a critical prerequisite for long-term success. To meet our ambitions in the far north, we have to address challenges in a range of areas - including geology and technology.

  Gas position
  The climate challengeproportion of natural gas from our NCS portfolio is increasing. We have a flexible transportation system, with six different landing points on the European Continent/UK and flexibility in terms of gas deliveries from large gas-producing fields such as Troll and Oseberg.

  Energy efficiency and carbon emissions
  E&P Norway aims to maintain and strengthen the NCS's position as the most energy-efficient petroleum region in the world. We intend to push for energy efficiency in our dailyday-to-day operations and evaluate new field developments fromin a long termlong-term perspective with regard to energy and the environment. E&P Norway also plans to also put more effortseffort into developing a more energy efficientenergy-efficient supply chain with a life cycle perspective.

  Industrial architect forIndustry leader on the NCS
  We seek towill maintain a stable relationship with suppliers, competitors, government and other stakeholders. The NCS is an arena for world-class innovation and technological development. StatoilHydroStatoil is a leader in the deployment of new technology, including drilling and subsea technology, new solutions for reducing costs and the use of new technology for developing discoveries. As the largest operator on the NCS, we are leaders in the development of optimal area solutions and the overall development of the NCS.

   Top 

  2.5.3 KeyE&P key events in 20082009

  In 2009, Exploration & Production increased by 3% from 2007 to 1461 mmboe/day.

  Norway had a high level of exploration activity, and discoveries were made in 31 of 39 exploration wells.

  • KvitebjørnTotal entitlement liquids and gas pipeline shut down asprodution in 2009 was 1,450 mboe per day.
  • Started implementation of August 2008.
  • Turnaround at Snøhvit to enhance plant regularity.
  • Offshore integration : Our Corporate Executive Committee (CEC) decided in December 2008 on a new operating model for our offshore organisation.organisation in mid-2009.
  • Several turnarounds completed in 2009.
  • High exploration activity: 2731 discoveries out of 39 exploration wells.
  • New projects sanctioned:
    • YttergrytaGoliat
    • MorvinEkofisk 2/4 V-A
    • Norne M-templateVega South Oil
    • Troll Field projectsSnorre Export
    • Troll C Low pressure production projectÅsgard Gas Transfer
  • Production from sevenfour new fields added a total capacity of approximately 7045 mboe per day:
    • VolveYttergryta
    • GulltoppAlve
    • Gamma Main StatfjordTyrihans
    • Vigdis Øst
    • Theta Cook (Oseberg)
    • Oseberg Delta
    • ViljeTune South
  • Acquisitions: We aquired a 15% ownership interest in Goliat.

   Top 

  2.6 International E&P

  2.6.1 Introduction to International E&P

  Statoil is present in several of the most important oil and gas provinces in the world and International Exploration & Production will provide most of Statoil's future production growth.

  International Exploration & Production (INT) is responsible for exploration, development and production of oil and gas outside the Norwegian Continental Shelf. INT will provide a major part of StatoilHydro's future production growth.continental shelf.

  In 20082009, the business area hadwas engaged in production fromin 12 countries: Canada, the USA, Venezuela, Algeria, Angola, Libya, Nigeria, the UK, Azerbaijan, Russia, Iran and China. In 20082009, INT produced 24%26% of StatoilHydro'sStatoil's total equity production of oil and gas, and INT's share is expected to increase significantly in the future.

  We have exploration licences in North America (Canada and the USA), Latin America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Morocco, Mozambique, Nigeria and Tanzania), the European and Caspian and Russian area (Denmark, the(the Faroes, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia).

  The main sanctioned development projects in which we are involved are in Canada, the USA, Brazil Angola and Ireland,Angola, and we believe we are well positioned for further growth through a substantial pre-sanctioned project portfolio that remains to be sanctioned.including the latest addition, the West Qurna 2 in Iraq. In January 2010 Statoil and Lukoil signed the development and production contract for West Qurna 2 with Iraqi authorities.

  The map shows our exploration and production areas.

  

  

   Top 

  2.6.2.Strategy2.6.2.International E&P strategy

  Our long-term upstream growth ambition will mainly be achieved by growing internationally. Growth is being pursued throughdeveloping our international portfolio of assets into profitable growth.

  Our four focus areas - deep waters, harsh environments, gas value chains and heavy oil.are:

  • Deep waters- weWe will further develop our position as a leading deepwater operator. Transfer ofNew technology made it possible to develop the Ormen Lange field with subsea installations only. We will also build on the experience withingained on the Tordis field, where subsea separation and water injection is used. This experience transfer is expected to significantly increase the final recovery factors significantly in some of the most challenging reservoirs in deepwaterdeep waters that we work with, such asare working on, for example in the Gulf of Mexico.
  • Harsh environmentsGas value chains - StatoilHydroStatoil has long and valuable experience in gas value chains and has demonstrated its capabilities in the monetisation of significant, often remote, gas resources. This experience will be a valuable contribution to future projects, such as Shah Deniz II and the large Marcellus shale gas accumulation.
  • Harsh environments - Statoil has the ability to deliver cutting edge field developments in harsh conditions under the strictest environmental regulations. With 30 yearsour long experience of experience from development and operations offshoreoff the coast of Norway, StatoilHydro haswe have a competitive advantage on which to capitalise.
  • Gas value chains - StatoilHydro has developed a comprehensive tool kit on gas value chains and demonstrated leading capabilitiesbuild on. The Sn øhvit field in the monetisationBarents Sea is a project that brings natural gas to land for liquefaction and export. The onshore plant is the first of major, often remote, gas resources. This experience will be a valuable contribution into future projects, such as Shtokman and Shah Deniz II, NnwaDoroits kind in Europe and the major Marcellus shaleworld's northernmost liquefied natural gas accumulation.facility.
  • Heavy oil- weWe are well positioned through operatorships and ownership stakesinterests in several key heavy oil projects. In the Peregrino field offshoreoff the coast of Brazil and the Bressay and Mariner fields offshoreoff the coast of the UK, we will draw uponutilise our experience from fields such as Grane in the North Sea. For our large, long termlong-term resource base in Canadian oil sands, we will draw on our experienceexperiences from our involvement in the subsurface aspects of the Venezuelan SincorPetrocede ño project. The development will take advantage ofbenefit from technological advances deriving from the research and development efforts performedwork at the StatoilHydroStatoil heavy oil technology centre in Canada. The research centre is among other tasks working on improving energy efficiency, reducing emissions, and thus also reducing operating costs related to the production of heavy oil.
    

  
   
  These focus areas all draw upon our existingon the strong technical and project execution skills we have acquired through our experience fromon the NCS.Norwegian continental shelf. We access resources by establishing new resourcesgrowth platforms with the potential of becoming new focus areas; through advanced exploration activities and high-grading of exploration prospects, focused business development and long-term partnerships with national oilenergy companies.

Iraq is our latest new platform and we have succeeded in establishing a foothold in competition with other companies. It is one of the countries in the world with the highest remaining hydrocarbon production potential, and it has been closed for foreign investment for more than 30 years. Statoil has entered into a partnership with Lukoil, one of the largest onshore operators in the world.

Our international access strategy has increased the scale of our operations in terms of produced volumes, reserves and technological and geographical breadth. We aim to build a robust, diverse and long-life portfolio with significant optionality and flexibility.

INT's near-term focus is on delivering on the production targets for 2012 communicated to the financial markets. Recent acquisitions have also given us significant operatorships that arewhich can increase our opportunities in the exploration and planning phases, as well as the major Peregrino development project.future.

Major efforts are being made on making the transition from being a mainly North Sea player towards becoming a world class international operator. Over the last few years, StatoilHydro has built up a large resource base. We are working continuously to develop our inventory of projects into producing assets by looking at innovative technical and commercial solutions.

2.6.3 KeyInternational E&P key events in 20082009

International E&P's average daily production exceeded 500,000 boe in 2009.  

• Equity production increased by 10% from 20072008, to 465 mmboe/512 mboe/day.
• Production from three new fields started during the year.
• High Exploration activity, eight discoveries outexploration activity: six of 40the 29 exploration wells drilled in 2008,2009 have been announced as discoveries, with several interesting discoveries in Algeria, Angola, UK and the US Gulf of Mexico.Mexico (GoM), Canada and Angola. Nine wells were under evaluation at year end 2009.
• PSVM developmentOn 12 December, Statoil and Lukoil entered a winning bid for the West Qurna 2 field in Block 31the second licensing round in AngolaIraq. Statoil's equity share will be 18.75%.
• The Ceasar Tonga project in GoM was sanctioned by Sonangol on 28 July 2008.the partnership.
• Production from fourthree new fields added a total capacity of approximately 10050 mboe per day:day (Statoil equity):
  • MondoTahiti in GoM
  • Thunder Hawk in GoM
  • Gimboa test production in Angola
  • Saxi Batuque in Angola
  • Agbami in Nigeria
  • ACG phase 3 in Azerbaijan
• Acquisitions:
  • We have made a strategically important entry into unconventional gas through the acquisition of a 32.5% interest in Chesapeake's Marcellus shale gas acreage in the Appalachian region in the USA.
  • Our position as an international operator has been strengthened through handover of project responsibility for the Peregrino development offshore Brazil, following the acquisitionOffshore installation of the remaining 50% interestfirst wellhead platform on the Statoil-operated Peregrino field in this field.Brazil started in late 2009.

2.7 Natural Gas

2.7.1 Introduction to Natural Gas

The Natural Gas (NG) business area is responsible for StatoilHydro'sStatoil's transportation, processing and marketing of pipeline gas and LNG worldwide, including the development of additional processing, transportation and storage capacity.

NGNatural Gas (NG) is also responsible for marketing gas supplies originating from the Norwegian State'sstate's direct financial interest (SDFI). In total, we account for approximately 80% of all Norwegian gas exports and are responsible for the technical operationoperations of the majority of the export pipelines and onshore plants in the processing and transportation systemssystem for Norwegian gas (Gassled)(Gassled*).

NG's business is conducted from three locations in Norway (Stavanger, Kårstø and Kollsnes) and from offices in Belgium, the UK, Germany, Turkey, Singapore, Azerbaijan and the US.USA (Houston and Stamford).

In 2008,2009, we sold 37.038.7 bcm (1.31(1.37 tcf) of natural gas from the NCSNorwegian Continental Shelf (NCS) on our own behalf, in addition to approximately 32.035.3 bcm (1.13(1.25 tcf) of NCS gas on behalf of the Norwegian State. StatoilHydro'sstate. Statoil's total European gas sales, including third party gas, were 76.8amounted to 79.5 bcm (2.71(2.81 tcf) in 2008.2009. That makes us the second largest gas supplier into Europe, with a market share of around 15% inof the European gas market.

From our international positions, (mainlymainly Azerbaijan and the US),USA, we sold 4.15.3 bcm (0.4(0.19 tcf) of gas in 2008,2009, 3.2 bcm (0.11 tcf) of which 2.3 bcm (0.1 tcf) was entitlement gas.

We have a significant interest in the NCS pipeline system owned by Gassled, which is the world's largest offshore gas pipeline transportation system, totalling approximately 7800 kilometres. This network links gas fields on the NCS with processing plants on the Norwegian mainland, as well as terminals at six landing points located in France, Germany, Belgium and the United Kingdom, providing us with flexible access to customers throughout Europe.

*This system is owned by Gassled where Statoil has a 32.1% ownership.

2.7.2 StrategyNatural Gas strategy

NG's strategy is to maximise the value of our long-term sales business, improve ourincrease value creation through portfolio optimisation and trading activities, and to establish new gas value chains.

NG's main task is to maximise value creation in markets that are constantly changing and deregulating, the European market in particular, by making active use of the new opportunities offered and managing risk within acceptable parameters.

We have a large European long-term gas sales contract portfolio and are continuously evaluatingevaluate midstream and downstream opportunities in order to take further advantage of our existing infrastructure, access to supplies, and experience innatural gas marketing of natural gas.experience. Our downstream strategies may differ from region to region depending on our particular position in the area and the nature of the market in question.

In Europe, we endeavourare endeavouring to achieve greater efficiency fromin our existing supply portfolio, to update and refine our commercial relationshipsrelations with key customers, and to establish new positions that will improve thedelivery flexibility ofin our operations. Through balancing, optimisation andfrom field to customer, trading activities, and sales directly to large industrial customers, we plan towill continue to create additional value on top of our long-term sales business.

Natural gas is the focus of many exploration and business development activities carried out by both INT and EPN. A large proportion of the exploration activities on the NCS are focused on gas, and a number of INT projects focus on accessing international gas reserves.

StatoilHydro aimsWe aim to further develop itsour position on the NCS and internationally through increased production and investmentsinvestment in existing and new fields and infrastructure aimed at serving the European and US gas markets. NG plans to strengthen established market positions in Europe with gas from the NCS, the Caspian Sea and North Africa. We plan to further develop the market position at the Cove Point terminal on the East Coast of the US. Our aquisition of a 32.5% share in the Marcellus gas deposit in the Appalachian basin is expected to significantly strengthen our US natural gas business in terms of production, reserves and marketing.

The main objective of NG's strategy is to improve our growth opportunities in all parts of the natural gas business and fully exploit the opportunities that changing market conditions provide us. This means increased focus on extracting value from the existing contracts and asset portfolio and increasing the value added from trading and optimisation activities beyond the landing point. It also entails increased internationalisation of the gas business, including activities in North America, LNG growth and the addition of new markets.

The main task for NG is to maximise value creation in markets that are constantly changing and deregulating, particularly Europe, making active use of the new opportunities offered and managing risks within acceptable parameters.

A necessary lever toin support of this strategy is to continue to develop, maintainthe continued development, maintenance and operateoperation of the upstream and midstream (transport and processing) infrastructure required to safely and reliably deliver gas volumes where and when required. Efforts aimed at ensuring the safety, integrity and regularity of the infrastructure, while simultaneously upgrading and expanding the existing processing plants at Kårstø and Kollsnes, is expected to beare of key importance in Norway.

The acquisition of a 32.5% interest in Chesapeake Energy's Marcellus shale gas acreage in the Appalachian basin in November 2008 will significantly strengthen our US natural gas business in terms of production, reserves and marketing (For more information, see Exploration & Production International). We will further develop our market position at the Cove Point LNG terminal on the East Coast of the USA. New midstream positions will be established in the USA in order to maximise value creation from this INT position in Marcellus. NG also plans to strengthen established market positions in Europe with gas from the NCS, the Caspian Sea and North Africa.

The main objective of NG's strategy is to utilise growth opportunities in all parts of the natural gas business and fully exploit the opportunities that changing market conditions provide. This means an increased focus on extracting value from the existing contracts and asset portfolio and on increasing the value added from trading and optimisation activities beyond the landing point. It also entails increased internationalisation of the gas business, including activities in North America, the Caspian region, LNG growth and the addition of new markets.

2.7.3 KeyNatural Gas key events in 20082009

Natural Gas delivered record operating income under challenging market conditions

• RecordStrong Marketing & Trading results. NG delivered a record high trading result in 2009 due to our downstream positions and our ability to capitalise on price volatility. In addition we concluded approximately 8 bcm of new sales for the period 2009-2012.
• We maintained the value of our contract portfolio and were able to take advantage of volatile prices.
• Aldbrough gas sales at record prices. In 2008 we sold 39.3 bcm entitlement gas, approximately 10% increase from 2007. The European piped gas price increased by 42% from 2007 to 240 øre/sm3 in 2008.
• The Chesapeake agreement is a major building block in StatoilHydro's US gas value chain. The company gets access to reserves produced close to the highest paying marketstorage in the US and is buildingUK. The facility began partial commercial operations in two caverns on our existing Cove Point LNG position and our well-established9 June 2009 .
• Naturkraft gas marketing and trading organisation.
• An agreement to join Swiss EGL Group was signed 13power plant at Kårstø. Naturkraft commenced commercial operation on 26 February to establish a joint venture to develop, build and operate the Trans Adriatic Pipeline (TAP) potentially supplying the European market with gas from the Caspian Sea and Middle East regions. A final investment decision is linked to the Shah Deniz Stage 2 development.
• Diversion of LNG cargoes. For the first time, we sold a cargo of Liquefied Natural Gas (LNG) from the Snøhvit field to Japan. The vessel arrived at the Ohgishima terminal in Tokyo Bay on 22 March. Price differences between continents give us added value by diverting LNG cargoes to the most profitable markets. Eight Snøhvit cargoes originally destined for Cove Point were diverted to other locations in 2008.2009.

2.8 Manufacturing and Marketing

2.8.1 Introduction

to Manufacturing & Marketing (M&M)

Manufacturing & Marketing adds value through the processing and sale of the group's and the Norwegian State'sstate's production of crude oil and natural gas liquids (NGL).

liquids.

M&MManufacturing & Marketing (M&M) is responsible for the group's combined operations in the transportation of oil, processing, the sale of crude oil and refined products, retail activities and marketing of natural gas in Scandinavia. We operate in approximately 1213 countries, haverun two refineries, one methanol plant and twothree crude oil terminals, and haveterminals. Our international trading activities and an extensive distribution network for businesses and private customers.make Statoil one of the world's largest crude oil traders. Over one million customers visit our approximately 21002000 service stations daily.daily, and we operate an international lubricants and aviation fuel business.

More thanApproximately 13,000 people representing overfrom 30 nationalities are employed bynations work for M&M. Approximately 10,500 of them work&M, around 10,000 outside Norway. In 2008,2009, we had trading activity of 717traded 721 mmbbl of crude oil and condensate, approximately 3025 million tonnes of refined oil products and 11.811.7 million tonnes of NGL.natural gas liquids (NGL). The refinery throughput was 15.215.0 million tonnes. Tjelbergodden produced approximately 10% of the European market's demand for methanol. In the energy and retail market, we sold approximately 1312 billion litres in 2008,2009, including eight8 billion litres of petrol and diesel. Aviation fuelled over 70 airports worldwide and lubricant was distributed to 40 countries.

2.8.2 StrategyManufacturing & Marketing strategy

M&M's strategy is to contribute to the&M creates efficient, integrated oil value chain by selectively buildingchains with competitive midstream and downstream positions.

This strategy aimsM&M's main task is to maximise value of our crude oil production and to strengthen and support the value of the group'sStatoil's upstream portfolio. Continued focus onproduction of crude oil and natural gas liquids (NGL) through professional refining and marketing. For this purpose, M&M has established efficient, integrated value chains with competitive midstream and downstream assets.

M&M's goal of safe, reliable and efficientcost-efficient operations is the basis for future growth in this segment.further development of our market position. We will focuscontinue to pursue improvement opportunities and conduct necessary restructuring of our activities.

We will ensure high value creation based on further developing ourStatoil's legacy assets on the Norwegian continental shelf, and a strong market position in North AmericaWest Europe will continue to maximise the value creation from the group's crudebe a high priority.

Based on growing international upstream production, in the Gulf of Mexico, future production of extraM&M will further develop regional trading hubs, with special emphasis on heavy oil fromactivities. Statoil's heavy oil production in Canada and Brazil as well asand our production importedterminal asset on the Bahamas are important stepping stones.

M&M will continue to North America from other regions.develop business-critical expertise and establish best practise in our work processes. We have developed a framework for deploying expertise throughout the organisation, with special emphasis on value chain expertise.

Oil Sales,sales, trading and supply (OTS)
OTS will continue strengtheningto strengthen our global trading position, for crude and natural gas liquids, with an increased presence and activity in selectedstrategic regions such as well as sustainingthe Americas and Asia, while maintaining our established market position in North West Europe. StatoilHydro equity production is the backbone of ourWe will continue to develop business and growth ambitions, and we will focus strongly on delivering business development and infrastructure projects to secure market access and competitive pricing for our equity volumes world wide. Physical tradingworldwide. Trading infrastructure and solidsound logistical solutions give our business a competitive edge.

The acquisition of the South Riding Point Terminal in the Bahamas in 2009 will form the competitive edge forenable us to develop our business. Wetrading around both equity and third party volumes sourced globally. OTS will increase flexibilitycontinue to market Statoil's increasingly global upstream production both in marketing of NCS volumes and also evaluate infrastructure assets independently of our own equity production to support increased trading activity.conventional grades but even more importantly in extra heavy oils.

Manufacturing
Main focus for our manufacturing activityManufacturing's ambition is to contribute to maximising the value of StatoilHydro'sStatoil's feedstocks from field to end user and to be an active downstream partner in the internationalisation of StatoilHydro.Statoil.

Manufacturing is preparing for the challenging market outlook that the European refining industry is facing. We are seeking to improve Mongstad and Kalundborg's competitive position by improving product yields, reliability and energy efficiency and by reducing costs while maintaining HSE performance.

Our ambition is to maintainstrengthen the competitiveness of Mongstad, Kalundborgvalue chain between our manufacturing and Pernis by exploiting technology in order to improve reliability, energy efficiency, maintenancetrading units and HSE performance. Our focus will be to increase the robustnessadd value through more proactive integration of the sites, whilst adapting to changes inoperation of the Mongstad and Kalundborg refineries. This creates synergies through crude feedstock optimisation, greater flexibility and market variations. Such changes may well includeexchange of products between the increased upgrading of gasoils and heavy oils to diesel, and production and supply of Biofuels. The new combined heat and power (CHP) unit at Mongstad will improve energy efficiency when it starts up in 2010, and also lay a foundation for future improvements.

We will implement cost efficient and flexible liquid transportation solutions. The logistics solution will add value by allowing the possibility to combine cargoes and crude qualities, to enable a reduction in refinery feedstock costs and give flexibility to handle high tan and heavy crude oil. It will also be important to develop business concepts and related technology that are feasible across the Arctic area.refineries.

Energy and retail
OurTransportation fuel is the core of our energy and retail business will be increasingly focused on(E&R), delivering 60% of gross income. Scandinavia and the transportation fuel sector, asBaltic region including Poland are the key geographical areas. In these markets, E&R is number one or two in terms of market share, with the exception of Poland where we expectare among the top five. In addition, we have a few stations in Murmansk and St Petersburg. Our engagement in the sale of heating oils and other stationary energy sector to gradually replace oil with other non carbon-based energy carriers.products is being reduced.

Our ambition is to consolidateimprove profitability from our downstream positionsleading position in Scandinavia focusingand to grow further on increasing profitability and establishing StatoilHydro as a leading supplier of bio fuels in selected markets. In Eastern Europe, we plan to buildthe eastern axis, building on our strong Baltic and Polish positions, and continue topositions. We continually evaluate market opportunities based on the Scandinavian marketing concept. Acquisitions have recently been made in the automat sector and our ambition is to develop this market sector in parallel with our full-service offering. An important building block in realising this ambition is to be the environmental leader in our markets, with a first mover position in biofuels.

Statoil's Board of Directors has approved a proposal to create a stand-alone Energy & Retail business through an initial public offering (IPO) on the Oslo Stock Exchange. The IPO will take place at the earliest in the fourth quarter of 2010 or at a time when the capital market is deemed favourable for such an offering. Statoil intends to remain a majority shareholder of Energy & Retail at the time of the initial public offering and listing. The size and time horizon of Statoil's future ownership in Energy & Retail will be tailored to support and develop company value both for Energy & Retail and for the Statoil Group. The introduction of the new ownership structure is not expected to have a significant impact on the financial statements.

2.8.3 Key events in 2008

M&M experienced a challenging trading market in 2008, but were well positioned to cope with the unprecedented market conditions and volatile crude oil prices. These are theManufacturing & Marketing key events 2009

Significantly lower margins in 2009 were challenging for the refining industry. The South Riding Point oil terminal lease boosted our international trading activities, while the JET business was successfully integrated into Scandinavian Energy and Retail.

• A challenging refining market, with a drop of 2008.
  from USD 8.3 to USD 4.3 per barrel in FCC refining margins.
  • We experienced a challenging trading market during 2008, dueImpairment write-down of refineries reflecting the refining margin outlook.
  • The combined heat and power (CHP) plant at Mongstad produced its first power for delivery to the extreme unpredictabilitygrid in October 2009, with commissioning planned to continue into 2010.
  • The sale or closure of crude oil pricesall Hydro-branded stations in Sweden was completed in 2009. Closure of more than 400 stations.
  • Restructuring and portfolio optimisation in stationary energy:
    • Sold, or agreed to sell our downstream interests in gas companies located in Norway, Denmark and Sweden.
    • The heating pellets, bottled gas and electricity businesses in Scandinavia sold.
    • The international lubricants production will be centralised to Sweden, and the oil products markets.plant at Fagerstrand in Norway will be closed.
    • Increased diesel production capacity at Kalundborg refineryStatoil's board of directors decided in Denmark after start upMarch 2010 to change the ownership structure for the energy & retail business through a partial listing on the Oslo Stock Exchange.
  • Acquisitions:
    • The long-term lease of the modified fuelSouth Riding Point oil conversion unitterminal in March 2008.
    • Reduced emissions to air at Mongstad when the volatile organic compounds (VOC) recovery unit went on stream on 13 June 2008.
    • Our largest ever turnaround (shut-down for inspection and maintenance) took place at the Mongstad refinery from September to November 2008.
    • Major on-going restructuringBahamas acquired in Sweden, where we have converted 82 manned stations to unmanned and closed down 251 stationsOctober 2009.
    • Acquisitions:
      • Our energy and retail business received approval fromcompleted the European Commission forintegration of the acquisition of 274 JET stations in Scandinavia on 21 October 2008.during 2009.

     Top 

    2.9 Technology and New Energy

     Top 

    2.9.1 Introduction

    to Technology & New Energy (TNE)

    Technology & New Energy is responsible for the development of technology and renewable energy, thereby contributing to global business success.

    This meanssolutions that TNEcross energy frontiers.

    Technology & New Energy (TNE) is responsible for ensuring capacity and competenceexpertise in the field of technology in addition to creating distinct technological solutions for global growth. This includes delivering innovative and competitive technological solutions for exploration, increased recovery, field development and safe, efficient and environmentally-friendlyenvironmentally friendly operations. The research and development department,division, which has research centres in Trondheim, Bergen and Porsgrunn in Norway and in Calgary in Canada, is engaged in research and development as well as the piloting implementation and commercialisation of new technology.

    Climate change, supply security of supply and a growing demand for clean energy are opening up new business opportunities. StatoilHydroopportunities for Statoil, particularly in Carbon Capture and Storage (CCS) and offshore wind. Statoil is in a position to seize these opportunities by utilising long-standing core capabilities from the oil and gas industry. StatoilHydro'sStatoil's New Energy business unitentity is responsible for the company's business effort withinefforts in renewable energy. The activities are grouped under renewable energy production, sustainable fuels,new options and carbon dioxide management and technology development.management.

    

    

     Top 

    2.9.2 StrategyTechnology & New Energy strategy

    StatoilHydro's

    Statoil's technology strategy focuses on generating long-term business value throughby identifying, developing and applying technologies that will securefor securing maximum value from the company's long termNorwegian continental shelf (NCS), as well as establishing a position as an internationally competitive organization.

    within renewables.

    Technology strategy
    StatoilHydro'sStatoil's strategy is to maximise value as an upstream oriented, technology basedinternational technology-based energy company. The objectives of the corporate technology strategy are to: (i) identify those technologies that will help the company to develop as a profitable, performance-driven, internationally competitive organization;organisation; and (ii) guide itsthe company's future growth in certain areas that can lead to substantial technology differentiation.

    The strategy is therefore focused on generating long-term business value through leading technology application. Its realizationrealisation will demand a response fromrequire the entirecombined efforts of our technical communitystaff to increase the value of existing business, secure and develop platforms for further growth and operate in new and more challenging environments. The strategy is upstream-motivated, although some weight is placed on energy diversification. Operational excellence and industry-leadingan HSE performance that is at the forefront in the industry underpin all our activities.

    The corporate technology strategy is driven by the central business challenges aimingand aims to build even stronger industry positions. Technology is a key enabler in relation to achieving this, and it will make significant contributions to field development in frontier deep waters (for example the Gulf of Mexico and Brazil) and Arctic areas,, heavy oil production subsalt exploration,(for example Canadian oil sands, Venezuela and environmentalPeregrino in Brazil), and climate issues. Thein arctic and sub-arctic regions with the focus on minimising risk to the environment and using our experience of operating in harsh weather conditions. Our ambition is to achieve distinctiveness and industry leadership in selected technologies and to stay competitive in a broad range of core and emerging technologies along the energy provision value chain, such as offshore wind and sustainable biofuels.marine biofuel.

    Efforts to standardise technology, secure fast track resource maturation and cost-efficient development solutions for mature resource areas contribute to the continued development of breakthrough and enabling technologies for frontier areas.

    Furthermore, IORimproved oil recovery (IOR) and improved drilling and well solutions are important in order to successfully growinggrow our business. StatoilHydroStatoil has achieved some of the petroleum industry's highest recovery factors on the NCS by combining scientific and engineering capabilities and boldly introducing new technology. We intend to further advance the most important technologies to meet forthcoming Improved oil recovery (IOR)IOR ambitions on the NCS and internationally. Drilling and well technology plays a key role in increasing production and ensuring regular delivery, and through its application we intend to achieve faster operations, reduced downtime and improved well flow, whilstwhile improving safety during operations. Supplier cooperation and venture activities will remain important. We are also reviewing our intellectual property rights policy and clarifying our policy on technology acquisition in terms of proprietary

    Technology development and deployment are carried out in close cooperation as opposed to off-the-shelf purchasing.

    Although the selected technologies are dealt with separately, itnational and international universities, research institutes, vendors and contractors. The split between external and internal research and development spending is important to note that leading industrial solutions depend on their successful combination.around 50/50.

    New Energy
    To StatoilHydro, climate changeStatoil's strategy for New Energy and carbon management is both a challengeto utilise our core capabilities and acurrent business opportunity. Our focus is on buildingpositions to build a business with significant economicsubstantial value creation in the short and long term, with particular emphasis onlonger term. We will emphasise technologies where we can add value as a result of our offshore oil and gas expertise and experience. The main focus areas are offshore wind sustainable bio-fuels and CO2carbon management. However, with the new energy industry still being in an early phase of development, it difficultis too early to "pick all the winners" of the future, so we are developingconsidering additional options in selected areas.areas, such as second generation marine biofuels, geothermal, solar, hydrogen and other offshore renewables like wave and tidal energy. We also believe that our involvement has the potential to add value to certain oil and gas activities withinin the company, particularly within CO2in carbon management.

     Top 

    2.9.3 KeyTechnology & New Energy key events in 20082009

    This is an overview of key events related to TNE in 2009.

    Technology

    • The world's first remote operateddeepest hot tap system was successfully completed, connecting Tampen Link and SIPS (Statfjord Interfield Pipeline System)
    • Production and sub surface support centresoperations on a pressurised pipeline were established
    • The first test of Drilltronics, an early version of automated drilling, was successfully completedcarried out on Statfjord Cthe Ormen Lange field in the first quarterNorwegian Sea during early August.
    • New drilling and well technology developed by Statoil and FMC Technologies has been successfully tested on the Åsgard field in the Norwegian Sea. The new technology, called "Through tubing rotary drilling" (TTRD), enables old wells to be reused in a much simpler and more inexpensive way than previously.
    • Statoil has introduced light well intervention (LWI) vessels on a large scale, with two such ships in operation all year round on the NCS. Compared with the use of 2008.traditional drilling rigs, these units cut the cost of well intervention work.
    • Science education for the younger generation is part of Statoil's Academia programme. This June, a pilot - Newton energy room - financed by Statoil opened in Trondheim.
    • Steerable line drilling pilot was a success. It will improve ability to drill in depleted reservoirs and unstable formations.
      

    New Energy

    • The UK government gave consentStatoil and Statkraft have decided to develop our 88-turbinethe 315MW Sheringham Shoal offshore wind park
    • We investedOffshore Wind Farm in Brightsource Energy, a company developing concentrated solar thermal technology
    • New projects sanctioned:the UK, providing energy to 220,000 British homes.
    • Hywind, the world's first full scalefull-scale floating offshore wind turbine, was sanctioned and is now under construction.started operation in autumn 2009 - enabling testing of the next generation of offshore wind technology.
    • We entered intoConstruction of the Icelandic Deep Drilling Project for deep geothermal energy.European CO2 Technology Centre Mongstad (TCM) started in June 2009.
     Top 

    2.10 Projects & Procurement

     Top 

    2.10.1 Introduction

    to Projects (PRO)& Procurement

    Projects & Procurement is responsible for planning and executing all major development and modification projects, , as well as for project and operational procurement,procurements within Statoil, including securing rig capacity based on athe corporate rig strategy.

    Our goal is to be world-class in terms of project execution and to deliver on time and within budget, in accordance with high HSE standards and agreed quality standards. To become a truly global energy player, it is essential that StatoilHydroStatoil is able to execute projects at the very highest level, and thereby strengthen the company's international competitiveness.

    Our current portfolio consists of more than 120 modification and development projects in the execution phase, with an expected total investment cost of more than NOK 200 billion. A majorlarge part of the portfolio consists of activities related to ongoing redevelopment efforts aimed at maximising production from the NCS.

     Top 

    2.10.2 StrategyProjects & Procurement strategy

    Our strategy is to develop high qualityhigh-quality, efficient projects, as planned, and in a safe and reliable manner.

    OurThe ability to utilise the company's world-leading technology, execute projects in complex surroundings and demonstrate our core expertise in new markets is of vital importance forin terms of opening up new business opportunities. The fight for global resources is fierce, but one Statoil is familiar to StatoilHydro.with. The real challenge is inflicted bylies in local market,markets, local practices, new standards and new cultures. These unfamiliar settings impactaffect price, availability, quality and lead times for deliveries.

    We have great diversity in our project portfolio. On the NCS, many of our projects are related to redeveloping and upgrading existing fields and installations. These types of projects are often very complex, but the reward is a growing portfolioprolonged lifetime and increased recovery rates for our installations.

    Moreover, a number of internationalsmall satellite fields are being tied in to existing hubs. These projects such as the In Salah gas compression project in Algeria, the developmentare often part of the Iranian gas field South Pars phases 6, 7group's fast track programme, whose aim is to significantly shorten the time from discovery to production. Industrial standardisation is a key element in achieving this.

    Internationally, our portfolio consists of fairly few, but large projects. Success relies on our ability to utilise our expertise and 8 andexperience from the NCS. Our flagship is the Peregrino project off the coast of Brazil, Statoil's first operated mega project outside Norway. Furthermore, we are gaining valuable experience in Canada, where the Leismer demonstration project for heavy oil recovery is being developed.

    Within renewable energy, the world first floating windmill was successfully completed in Canada2009 - as well as the major heavy oil project offshore Brazil, Peregrino, which is 100% StatoilHydro owned and operated.

    OnHywind project. In addition to this, 88 windmills are being built off the NCS, there is a growing needeast coast of England for the redevelopment of existing fields and installations. As fields mature, production equipment needs upgrading. In the years ahead, an increasing number of fields will need upgrading or renewal of drilling units, control systems, hydrocarbon processing systems, cranes and other major redevelopment efforts.

    Developing sustainable solutions for clean renewable energy with a sound financial rationale is a key elementSheringham Shoal project, thus gaining expertise in the group's strategy. We anticipate an increased focus on new energyexecution of large projects in offshore wind.

    A technology centre for carbon capture and storage is being built at Mongstad, the years to come. In this context, the pre-sanctioning of two offshore wind projects, namely Hywind and Sheringham Shoal, serves as important milestones for PROfirst step in 2008.

    In order to handle our projects in the most efficient way, we intend to use inter-field project organisations to standardise tasks and continuously search for synergies between projects and contracts.developing a groundbreaking full-scale carbon capture plant.

    We are dependent on the cooperation of a highly professional supply industry. Therefore weWe therefore seek to secureensure a high degree of diversity among our suppliers, and are continuously on the lookout for innovative solutions and access to the best qualified expertise and external resources.resources.

    Securing sufficient flexibility in changing market conditions is a key focus area, and we expect our suppliers to adjust accordingly. We have seen increasing expenditureOur activity level has remained high despite the world economic and financial situation having been very volatile in the recent past butyear. Although price reductions have been evident across most of our procurement segments, it is still a challenge to reduce market prices sufficiently to develop marginal fields. We therefore continue to seek cost optimisation, improvement in the current worldwide economic situation, the time has come to optimize cost while improving quality, productivity and efficiency in collaboration with our suppliers. As an outcome, we expect that supplier costs will be reduced going forward.

     Top 

    2.10.3 Projects key events in 2009

    Key events in 2008

    Projects & Procurement in 2009 include the successful start ups on Alve and Tyrihans, and completion of Hywind and the final platform at South Pars.
    • The operatorshiphull for the Gjøa semi platform has been transported from the Samsung yard in Korea to Stord. Mating of the hull and the platform topside was completed successfully on 27 December.
    • Development of the Peregrino development offshorefield off the coast of Brazil has proceeded according to plan. The substructure for the first drilling and wellhead platform was handed over from Anadarko to StatoilHydrosuccessfully installed on 2 June.
    • Oseberg Delta started production on 30 June.the seabed in November 2009, and the platform deck and modules were installed in January 2010.
    • Production from the firstYttergryta field on Haltenbanken started on 5 January 2009, only seven months after government approval of the PDO.
    • Production from the Alve field started on 19 March.
    • Production from the Tyrihans field started on 8 July.
    • Production from the third and final platform on the South Pars phase 6-8 field (SPD9) was started on 24 August. 11 October.
    • Major modifications of the Snøhvit LNG facilities were completed and production recommenced on 17 December.
    • The second platform (SPD7)world's first floating offshore windmill, Hywind, has been installed off the coast of Karmøy, Norway. Power production started production on 21 December.
    • September. Development of the Sheringham Shoal offshore wind park off the east coast of UK was sanctioned in March 2009. The new Kollsnes Flash Gas and Compressor facilities commenced operation just before year end.
    • The Site Safety initiative, a cooperation between the leading advisors construction management and HSE management, was launched.
    • Through its strategic and operational sectors, Procurement has contributedwind farm, consisting of 88 windmills, is scheduled to a successful "all time high" operation of 17 mobile drilling unitsstart power production in parallel on the NCS.
    • Drilling rigs and associated services were secured in 2008 for new prospects in UK, Ireland, Canada and Libya.2011.

    3 Operational review

    Statoil's operational review is in accordance with the organisation of its operations, whereas certain disclosures about oil and gas reserves are based on geographical areas as required by the SEC.

    Statoil prepares its operational review in accordance with its segment (business area) structure. Each business area is presented individually, and includes underlying business clusters according to how the business area organises its operations.

    For further information on extractive activities, refer to sections 3.1 Operational review - E&P Norway and 3.2 Operational review - International E&P for descriptions of Exploration and Production Norway and International Exploration and Production, respectively.

    Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures based upon geographical areas as required by the SEC. The geographical areas are defined by continent, and consist of Eurasia, Africa and the Americas. Relevant information is further split into Norway and Eurasia excluding Norway.

    For further information on disclosures for oil and gas reserves and certain other supplemental disclosures based upon geographical areas as required by the SEC, refer to section 3.8 Operational review - Production volumes and price information and section 3.9 Operational review - Proved oil and gas reserves.

     Top 

    3.1 E&P Norway

    3.1.1 Industry overview

    While oil production on the NCS shows a falling trend, improved oil recovery will fight the decline. Production of natural gas is expected to increase and constitute a larger share of total production in the future.

    In 2008 the total production from the NCS was 4.16 mmboe per day. Improved oil recovery from existing fields is an important factor in maintaining the current production level, and most of the IOR activities are related to the drilling of new wells. Natural gas production is increasing and we expect production of natural gas to constitute a larger share of total production in the future.

    A major challenge for the industry has been to secure rig capacity, which is vital to increasing the recovery factor. A tight supplier market on the back of recent years' oil price increases has put upward pressure on rig rates, as well as overall oil service expenses.

    The global financial crisis that escalated in September will probably have an impact on this situation. However, much of the rig fleet is on longer term contracts, so a considerable change is not likely to be seen before 2010 or 2011. The recent turmoil in the financial and commodity markets has sharpened the focus on capital efficiency and cost control. Investment plans have been prioritized, and our portfolio of field projects and exploration prospects has been trimmed and high graded. However, short-term IOR efforts are fairly robust.

    Another challenge facing the companies on the NCS is that future production is expected to come from smaller and more complicated fields. New field development projects typically have more complex reservoirs and are technically more challenging than before. They will therefore demand more resources per barrel than the older and larger fields. As the NCS matures, the investment level is expected to remain at a high level.

    We believe there is still a large undiscovered resource potential on the NCS, both in mature and frontier areas. According to estimates published by the Norwegian Petroleum Directorate, approximately one-third of the resources on the NCS are undiscovered. Existing infrastructure ensures profitability for small discoveries in mature areas that would not otherwise justify a stand alone development. The majority of the remaining large discoveries are expected to be located in the frontier areas.

    Access to attractive acreage is an important factor in realising the potential of the NCS. In January 2009, 40 companies were awarded 34 new licences in the North Sea, the Norwegian Sea and the Barents Sea through Awards in Predefined Areas(APA) 2009. The annual APA concession system offers previously relinquished acreage and unawarded blocks offered in previous licensing rounds located in specific mature parts of the NCS. The APA system ensures that large areas close to existing and planned infrastructure are made available to the industry, and the APA area will be expanded as new exploration areas are matured.

    The deadline for applications in the 20th licensing round expired on 7 November 2008 with a total of 46 companies submitting applications. According to a press release from the Norwegian Petroleum Directorate, this was one of the largest licensing rounds ever, and the oil companies' interest demonstrated "that new exploration areas on the Norwegian Shelf are competitive in an international perspective." Awards are planned for March/April 2009.

    Ensuring safe and stable operation with no harm to people or the environment is an essential aspect of operating on the NCS, and there has been increased focus on this issue in recent years.

     Top 

    3.1.2 The NCS portfolio

    3.1.2.1 3.1.1.1 Core production areas

    StatoilHydro's

    Statoil's NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.

    We have organised our production operations into four business clusters - Operations West, Operations North Sea, Operations North and Partner Operated Fields. The Operations West and Operations North Sea clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea. Partner Operated Fields cover the whole NCS.

    The fields in each area use common infrastructure, such as production installations and oil and gas transport facilities where possible. This reduces the investment required to develop new fields. Our efforts in these core areas will also focus on finding and developing smaller fields through the use of existing infrastructure and on increasing production by improving the recovery factor.

    We are making active efforts to extend production from our existing fields through improved reservoir management and the application of new technology.

     Top 

    3.1.2.2 3.1.1.2 Potential producing areas

    In addition to the producing areas, we operate a significant number of exploration licenses.licences. The exploration acreage is located both in undeveloped frontier areas as well asand close to infrastructure and producing fields.
    

    NCS

    At the end of 2009, the total licensed acreage on the Norwegian continental shelf (NCS) covers an area of 130,142 square kilometres split between 413 licences - an increase of 27 licences from 2008. Statoil had interests in 219 licences covering an area of 59,107 square kilometres and was operator for 162 of the 219 licences. Compared with 2008, the total number of licences in which we have interests has increased by one.

    

    North Sea.
    The total licensed acreage in the North Sea covers 74,841 square kilometres. We operate 21,31863,591 square kilometres split between 240 licenses. We have interests in 22,507 square kilometres split between 113 licences, and are partner in 12,229 square kilometres. Followingwe operate 86 of the execution113 licences. Seven licences have been relinquished as a result of completion of committed work programme andprogrammes for licences, prospectivity evaluation one licence has beenand portfolio high-grading. Furthermore, we have partly relinquished acreage in the North Seaeight licences in 2008. In addition, sixorder to minimise area fee costs. Three new licences were partly relinquishedfarmed into in 2009, and two licences were relinquished through farm-out in 2008. Three licenceswe were awarded to us in the Awards in Predefined Areas 2007 (APA 2007) and we became operator of two of these. In addition, one licence was awarded as licence extension. Four licenses were awarded to usthree licences in the Awards in Predefined Areas 2008 (APA 2008) and we. We became operator of twoone of these.them. In addition, we were awarded one licences extension as operator. One new licence and five licence extensions were awarded to us in the APA 2009. We became operator of the new licence and three of the licence extensions.

    Norwegian Sea. Total
    The total licensed acreage in the Norwegian Sea covers 37,033 square kilometres. We operate 13,58746,790 square kilometres split between 131 licences. We have interests in 23,794 square kilometres split between 79 licences, and are partner in 7,384 square kilometres.we operate 54 of the 79 licences. In the deepwater region, we have interests in licences covering approximately 10,00012,300 square kilometres. Following execution of work programme and prospectivity evaluation, sixThree licences were relinquished in the Norwegian Sea2009 as a result of completion of committed work programmes, prospectivity evaluation and portfolio high-grading. Furthermore, we have partly relinquished acreage in 2008; threefour licences in order to minimise area fee costs. We were awarded one new licence in the deep water regionAPA 2008 where we became operator. In addition, we were awarded three licences extension and we are operator of two of these. We were awarded three licences in the shallow water region. In addition, four licences were partly relinquished in 2008. Four licences20th Round, and we became operator of two of them. One new licence and one licence extension were awarded to us in the APA 2007,2009, and we became operator for both of all of these. In addition, we acquired one new licence through farm-in in 2008. Two licenses were awarded to us in the Awards in Predefined Areas 2008 (APA 2008) and we became operator of one of these. In addition, two licenses were awarded as license extensions.
    
    those.

    Barents Sea. Total
    The total licensed acreage in the Barents Sea covers 17,710 square kilometres. We operate 13,34819,761 square kilometres split between 42 licences. We have interests in 12,806 square kilometres split between 27 licences, and are partners for 1,698 square kilometres. Following executionwe operate 22 of the 27 licences. Four licences were relinquished and eight licences partly relinquished in 2009 as a result of completion of committed work programmes, and prospectivity evaluation one licence has been relinquishedand portfolio high-grading. We were awarded three licenses in the 20th Round, and we became operator of two of them. Statoil did not apply for acreage in the Barents Sea in 2008. In addition two licences were partly relinquishedthe APA 2008 or the APA 2009 as we are well positioned in 2008. Three licences were awarded to usacreage in the APA 2007, andHammerfest Basin that we became operator of one of these. In addition, one licencebelieve is more prospective than the acreage that was awarded as a licence extension.announced.

     Top 

    3.1.2.33.1.1.3 Portfolio management

    Through

    The licence portfolio is continuously optimised, and our core areas and strategies will be strengthened and supported through active portfolio management we seek to optimise our licence portfolio, and strengthen our core areas.

    management.

    During 2008, we signed aA sales and purchase agreement was signed with Lundin Norway AS in 2009 for Statoil to aquire Det Norske's 15% sharefarm in Goliatto three of its licences. Statoil acquired 30% of PL359 and 30% of PL410 in the Barents Sea and a swap involving aUtsira High Area, as well as 10% share of Det Norske's participating interest in the Ragnarrock discovery onPL409 south of the Utsira HeightHigh Area. Several interesting discoveries have recently been made in exchange for interests in two exploration licences in the Grane and Heimdal areas. this area.

    Furthermore, several exploration licence transactions have been performed.carried out involving the farming-in and farming-out of exploration licences.

     Top 

    3.1.33.1.2 Exploration on the NCS

    StatoilHydro

    Statoil has deliveredcarried out an extensive exploration programmedrilling campaign on the NCS in 2008. We participated2009 by completing 39 exploration wells; 30 wildcat wells to test new prospects and nine appraisal wells to establish the extent and size of previous discoveries.

    By drilling the untested prospects we proved 22 new discoveries, resulting in a discovery rate of more than 70% for the 30 wildcat wells.

    The presence of hydrocarbons was affirmed by all the nine appraisal wells, so the total result for exploration drilling in 2009 shows that 31 of the 39 exploration wells resulting in 27 discoveries. This implies a success rate approaching 70%.

    successfully proved or confirmed the presence of hydrocarbons. We operated 34 of the 39 exploration wells including 24 of the 27 discoveries.wells. In addition, we operated ninetwo exploration extensions where sixthat resulted in two new discoveries.

    The most important discoveries in 20082009 were Dagny/Ermintrude (PL048/PL303) near Sleipner in the North Sea which has opened a new oil play in a mature gas province,Asterix, Gro, Katla and Snefrid South and Haklang (PL218) near the Luva discovery inBeta West, all except Gro are Statoil-operated. In the Norwegian Sea, that could providethe Asterix (PL327) gas discovery, located approximately 80 kilometres west of Luva, is strategically important in relation to building the basis for newa potential deepwater gas infrastructure. The five wildcat exploration wells completeddevelopment in the Barents Sea were all discoveries. AlthoughVøring Basin. The Gro (PL326) gas discovery located approximately 50 kilometres south-west of Asterix is promising, but needs further evaluation and appraising before concluding on the proven volumes in these wells have not met our most optimistic expectations, they have enhanced our understanding ofresource potential. In the hydrocarbon potentialNorth Seas, the Katla (PL104) oil/gas discovery opens the prolific Oseberg Area to the south, and, in the area and will be important guides for our continuedSleipner Area, the Beta West (PL046) gas/condensate discovery broadens this area's exploration activity inpotential already proven by the Barents Sea. Nearly half of the discoveries proven in 2008 are located near existing infrastructure and are of small to medium size. These discoveries are critical to maximise the take-out in and around existing fields and most of them already have a planned tie-back solution.Dagny/Ermitrude finds.

    The table below shows our exploration and development wells drilled on the NCS during the last three years.

    	2008	2007	2006
    				2009	2008	2007
    North Sea
    StatoilHydro operated exploratory	13	11	5
    Statoil operated exploratory				23	13	11
    Successful	8	9	3	18	8	9
    Dry	5	2		5	5	2
    StatoilHydro operated development	75	87	53
    Statoil operated development				72	75	87
    Partner operated exploratory	4	0	2	1	4	0
    Successful	2	0		1	2	0
    Dry	2	0	2	0	2	0
    Partner operated development	13	16	15	17	13	16
    Norwegian Sea
    StatoilHydro operated exploratory	14	6	5
    Statoil operated exploratory				10	14	6
    Successful	11	3	2	8	11	3
    Dry	3			2	3
    StatoilHydro operated development	13	12	17
    Statoil operated development				19	13	12
    Partner operated exploratory	1	3	0	4	1	3
    Successful	1		0	3	1
    Dry	0	2	0	1	0	2
    Partner operated development	3	2		1	3	2
    Barents Sea
    StatoilHydro operated exploratory	7	3	2
    Statoil operated exploratory				1	7	3
    Successful	5	2	1	1	5	2
    Dry	2	1		0	2	1
    StatoilHydro operated development	0		2
    Statoil operated development				0	0
    Partner operated exploratory	0	1	4	0	0	1
    Successful	0	1	2	0	0	1
    Dry	0		2	0	0
    Partner operated development	0			0	0
    Totals
    Exploratory	39	24	18	39	39	24
    Successful	27	16	8	31	27	16
    Dry	12	8	10	8	12	8
    Development	104	117	89	109	104	117

     

     Top 

    3.1.4 3.1.3 Oil and gas reserves on the NCS

     forAt

    At the end of 2008,2009, we had a total of 13961,351 mmbbl of proved oil reserves and 498480 bcm (17.6(16.9 tcf) of proved natural gas reserves on the NCS.

    

    Measured in barrels of oil equivalentequivalents (boe), our NCS proved reserves consist of 31% oil and 69% natural gas, based on total NCS proved reserves of 4,369 mmboe.

    One project on the NCS, the Goliat field in the Barents Sea, was sanctioned in 2009 and contributed positively to the reserves balance. In addition, approval of 4529 mmboe.future development plans for several of our producing fields contributed positively. Future extension of the license period is now assumed reasonably certain on the NCS, increasing the proved reserves for certain fields.

    The share of developed reserves at year end is 3,548 mmboe, which is 81% of the proved reserves. Of the 2009 proved developed reserves, 1,028 mmboe are oil and 401 bcm (14.1 tcf) are natural gas.

    The following table shows our proved reserves oftotal NCS crude oil and natural gas as of the end of the periods indicated. The data is net of royalties in kind, but includes reserves attributable to our account based on our proportionate participation in fields with multiple participants. No major discoveries or other favourable or adverse events have occurred since 31 December 2008 that would mean a significant change in the estimated proved reserves as of that date.

    31 December for each of the last three years. Further information on reserves can be found in section 3.9 Operational review - Proved oil and gas reserves and in note 3435 - Supplementary oil and gas information - to our Consolidated Financial Statements.
     Statements, which also explains revisions to the methodology for reserve etsimation for 2009 compared with earlier years.

    		Oil/NGL	Natural gas		Total		Oil/NGL	Natural gas		Total
    Year		mmbbls	bcm	bcf	mmboe		mmbbls	bcm	bcf	mmboe
    2009						Proved reserves end of year	1,351	480	16,938	4,369
    						of which, proved developed reserves	1,028	401	14,138	3,548
    2008	Proved reserves end of year	1,396	498	17,581	4,529	Proved reserves end of year	1,396	498	17,581	4,529
    	of which, proved developed reserves	1,113	410	14,482	3,693	of which, proved developed reserves	1,113	410	14,482	3,693
    2007	Proved reserves end of year	1,604	535	18,893	4,971	Proved reserves end of year	1,604	535	18,893	4,971
    	of which, proved developed reserves	1,187	427	15,084	3,875	of which, proved developed reserves	1,187	427	15,084	3,875
    2006	Proved reserves end of year	1,667	541	19,129	5,068
    	of which, proved developed reserves	1,188	379	13,378	3,566

     

     Top 

    3.1.5 3.1.4 Production on the NCS

    In 2008,2009, our total equityentitlement oil and NGL production in Norway was 302286 mmbbl, and gas production was 37.138.7 bcm (1310(1,366 bcf), which represents an aggregate of 1.4611.450 mmboe per day.

    The following table shows the NCS production fields and field areas in which we are currently participating. Field areas are groups of fields operated as a single entity.

    	StatoilHydro’s equity interest in %(1)	Operator	On stream	License  expiry  date		Producing  wells		Average daily  production in 2008 mboe/day
    Area						Oil	Gas
    															Producing  wells
    Business cluster									Georgraphical area	Statoils equity interest in %(1)	Operator	On stream	License expiry date		Oil	Gas	Average daily  production in 2009 mboe/day
    Operations North Sea
    Sleipner Øst	59.60	StatoilHydro	1993	2028			14	44.4	The North Sea	59.60	Statoil	1993	2028			10	24.2
    Sleipner Vest	58.35	StatoilHydro	1996	2028			17	91.0	The North Sea	58.35	Statoil	1996	2028			18	95.2
    Gungne	62.00	StatoilHydro	1996	2028			4	14.5	The North Sea	62.00	Statoil	1996	2028			4	15.0
    Loke	50.00	StatoilHydro	2008	2018			1	0.1
    Troll Phase 1 (Gas)	30.58	StatoilHydro	1996	2030			39	149.3	The North Sea	30.58	Statoil	1996	2030			39	131.2
    Troll Phase 2 (Oil)	30.58	StatoilHydro	1995	2030		106		43.9	The North Sea	30.58	Statoil	1995	2030	(2)	113		41.8
    Fram	45.00	StatoilHydro	2003	2024		9		27.9	The North Sea	45.00	Statoil	2003	2024		9		30.2
    Kvitebjørn	58.55	StatoilHydro	2004	2031			8	47.8	The North Sea	58.55	Statoil	2004	2031			10	83.3
    Visund	53.20	StatoilHydro	1999	2023		6	1	24.2	The North Sea	53.20	Statoil	1999	2023		6	1	26.8
    Grane	38.00	StatoilHydro	2003	2030		24		65.3	The North Sea	36.66	Statoil	2003	2030	(3)	25	0	62.2
    Veslefrikk	18.00	StatoilHydro	1989	2015		18		2.3	The North Sea	18.00	Statoil	1989	2015		18	0	2.2
    Huldra	19.88	StatoilHydro	2001	2015		0	5	4.8	The North Sea	19.88	Statoil	2001	2015		0	5	4.3
    Glitne	58.90	StatoilHydro	2001	2013		7		5.2	The North Sea	58.90	Statoil	2001	2013		6(4)	0	3.8
    Heimdal	29.87	StatoilHydro	1985	2021	(2)		6	1.0	The North Sea	29.87	Statoil	1985	2021	(5)	0	6	1.2
    Brage	32.70	StatoilHydro	1993	2017	(3)	22		11.4	The North Sea	32.70	Statoil	1993	2015	(6)	22	0	10.9
    Vale/Vilje	28.85	StatoilHydro	2002	2021			1	4.6
    Vale									The North Sea	28.85	Statoil	2002	2021			1(7)	1.8
    Vilje									The North Sea	28.85	Statoil	2008	2021		2		7.7
    Volve	59.60	StatoilHydro	2008	2028		2		20.7	The North Sea	59.60	Statoil	2008	2028		3		32.8
    Total Operation North Sea						194	96	558.4							204	94	574.4
    Operations West
    Statfjord Unit	44.34	StatoilHydro	1979	2026		82	2	72.7	The North Sea	44.34	Statoil	1979	2026		93(8)	2	54.5
    Statfjord Nord	21.88	StatoilHydro	1995	2026		4		3.0	The North Sea	21.88	Statoil	1995	2026		7		1.1
    Statfjord Øst	31.69	StatoilHydro	1994	2026	(4)	5		4.9	The North Sea	31.69	Statoil	1994	2026	(9)	7		3.4
    Sygna	30.71	StatoilHydro	2000	2026	(5)	2		1.6	The North Sea	30.71	Statoil	2000	2026	(10)	3		0.7
    Gullfaks	70.00	StatoilHydro	1986	2016		104	9	163.3	The North Sea	70.00	Statoil	1986	2016		105	9	137.0
    Snorre	33.32	StatoilHydro	1992	2015	(6)	37		50.5	The North Sea	33.32	Statoil	1992	2015	(11)	34	0	38.9
    Tordis area	41.50	StatoilHydro	1994	2024		5		11.5	The North Sea	41.50	Statoil	1994	2024		6	0	7.9
    Vigdis area	41.50	StatoilHydro	1997	2024		10		24.0	The North Sea	41.50	Statoil	1997	2024		10	0	21.1
    Gimle	65.13	StatoilHydro	2006			1		6.8	The North Sea	65.13	Statoil	2006			2		3.9
    Oseberg	49.30	StatoilHydro	1988	2031		59		125.9	The North Sea	49.30	Statoil	1988	2031		59		105.8
    Tune	50.00	StatoilHydro	2002	2032			4	12.4	The North Sea	50.00	Statoil	2002	2032			4	10.5
    Total Operations West						309	15	476.6							326	15	384.8
    Operations North
    Kristin(7)	55.30	StatoilHydro	2005	2033	(8)	12		92.4
    Alve									The Norwegian Sea	85.00	Statoil	2009	2029		1		21
    Kristin									The Norwegian Sea	55.30	Statoil	2005	2033	(12)	12	0	64.9
    Norne	39.10	StatoilHydro	1997	2026		12		26.0	The Norwegian Sea	39.10	Statoil	1997	2026		12	0	16.6
    Urd	63.95	StatoilHydro	2005	2026		5		5.8	The Norwegian Sea	63.95	Statoil	2005	2026		5	0	4.1
    Heidrun	12.41	StatoilHydro	1995	2024		34		13.8	The Norwegian Sea	12.41	Statoil	1995	2024		34(13)	0	11.8
    Åsgard	34.57	StatoilHydro	1999	2027			37	124.8	The Norwegian Sea	34.57	Statoil	1999	2027		0	39	128.9
    Mikkel	43.97	StatoilHydro	2003	2022	(9)		3	21.0	The Norwegian Sea	43.97	Statoil	2003	2022	(14)	0	3	24.2
    Njord	20.00	StatoilHydro	1997	2021	(10)	8		12.9	The Norwegian Sea	20.00	Statoil	1997	2021 & 2023	(15)	8(16)	1	12.6
    Tyrihans									The Norwegian Sea	58.84	Statoil	2009	2029		3	0	20.4
    Snøhvit	33.53	StatoilHydro	2007	2035			6	17.1	The Barents Sea	33.53	Statoil	2007	2035		0	6	23.6
    Yttergryta									The Norwegian Sea	45.75	Statoil	2009	2027		0	1	4.5
    Total Operations North						59	46	313.8							75	50	332.5
    Partner Operated Fields
    Ormen Lange	28.92	Shell	2007	2041			6	61.5	The Norwegian Sea	28.92	Shell	2007	2041			10	112.0
    Ekofisk area	7.60	ConocoPhillips	1971	2028		152		26.2	The North Sea	7.60	ConocoPhillips	1971	2028		150	0	24.2
    Ringhorne Øst	14.82	ExxonMobil	2006	2030		3		5.1	The North Sea	14.82	ExxonMobil	2006	2030		3		4.2
    Sigyn	60.00	ExxonMobil	2002	2018		1	2	15.8	The North Sea	60.00	ExxonMobil	2002	2018		1	2	14.2
    Enoch	11.78	Talisman	2007	2018		1		0.8	The North Sea	11.78	Talisman	2007	2018		1		0.8
    Skirne	10.00	Total	2004	2025			2	2.4	The North Sea	10.00	Total	2004	2025			2	2.6
    Murchison (Norw. Part)	11.52	CNR	1980	2026				0.1
    Total Parter Operated Fields						157	10	111.9
    Total Partner Operated Fields															155	14	158.1
    Total						719	167	1,460.8							760.0	173.0	1,449.8
    (1) Equity interest as at December 31, 2008.			(6) PL089 expires in 2024 and PL057 expires in 2015
    (2) PL 036 expires in 2021 and PL102 expires in 2025. The owner			(7) Kristin equity reflects inclusion of Tofte reservoir
    (1) Equity interest as of December 31, 2009.									(1) Equity interest as of December 31, 2009.				(8) 89 single completed wells, 4 multiple completed wells
    (2) Troll Phase 2 (Oil) has 64 multi branched wells									(2) Troll Phase 2 (Oil) has 64 multi branched wells				(9) PL037 expires in 2026 and PL089 expires in 2024
    (3) Grane has 9 multi branched wells									(3) Grane has 9 multi branched wells				(10) PL037 expires in 2026 and PL089 expires in 2024
    (4) Glitne 1 multi branched well									(4) Glitne 1 multi branched well				(11) PL089 expires in 2024 and PL057 expires in 2015
    (5) PL036 expires in 2021 and PL102 expires in 2025. The owner									(5) PL036 expires in 2021 and PL102 expires in 2025. The owner				(12) PL134B expires in 2027 and PL199 expires in 2033
    share of the topside facilities is 39,44%, however the owner share	share of the topside facilities is 39,44%, however the owner share		(8) PL 134B expires in 2027 and PL199 expires in 2033						share of the topside facilities is 39,44%, however the owner share				(13) 1 multi branched well
    of the reservoir and production is 29,87%.	of the reservoir and production is 29,87%.		(9) PL092 expires in 2020 and PL 121 expires in 2022						of the reservoir and production is 29,87%.				(14) PL092 expires in 2020 and PL121 expires in 2022
    (3) PL 185 expires in 2015 and PL053B and PL055 both expire in 2017			(10)  PL107 expires in 2021 and PL 132 expires in 2024
    (4) PL037 expires in 2026 and PL089 expires in 2024
    (5) PL037 expires in 2026 and PL089 expires in 2024
    (6) PL185 expires in 2015 and PL053B and PL055 both expire in 2017									(6) PL185 expires in 2015 and PL053B and PL055 both expire in 2017				(15)  PL107 expires in 2021 and PL132 expires in 2024
    (7) Vale 1 multi branched well									(7) Vale 1 multi branched well				(16) 1 multi branched well

     

    The following table shows our average daily equityentitlement production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2009, 2008 2007 and 2006.2007.

    	Year ended December 31,									For the year ended December 31,
    	2008			2007			2006			2009			2008			2007
    	Oil and NGL	Natural gas		Oil and NGL	Natural gas		Oil and NGL	Natural gas		Oil and NGL	Natural gas		Oil and NGL	Natural gas		Oil and NGL	Natural gas
    Area production	mbbl	mmcm	mboe	mbbl	mmcm	mboe	mbbl	mmcm	mboe	mbbl	mmcm	mboe	mbbl	mmcm	mboe	mbbl	mmcm	mboe
    Operations North	175	22	314	181	19	303	182	16	281	175	25	332	175	22	314	181	19	303
    Operations North Sea	250	49	558	236	56	590	262	59	634	269	49	574	250	49	558	236	56	590
    Operations West	355	19	477	362	16	464	379	20	503	297	14	385	355	19	477	362	16	464
    Partner Operated Fields	43	11	112	39	3	60	41	2	56	43	18	158	43	11	112	39	3	60
    Total	824	101	1,461	818	95	1,417	864	97	1,474	784	106	1450	824	101	1461	818	95	1417

     

     Top 

    3.1.6 3.1.5 Development on the NCS

     Top 

    3.1.6.13.1.5.1 Fields under development on the NCS

    The following fields are currently under development on the Norwegian Continental Shelf.

    The Alve field, in which we hold an 85% interest, is located in PL159B in the Norwegian Sea, 14 kilometres south west of the Norne field. The PDO was submitted to the Norwegian authorities in January 2007 and approved in March 2007. The field will be developed through the installation of a four-slot subsea wellhead template that will be tied back to the Norne Floating Production Storage Offloading (FPSO). Production is scheduled to start in early 2009. The total investment for the project is estimated to be NOK 2.7 billion. Production commenced on 19 March, 2009.

    continental shelf:

    Gjøa is located in the North Sea and will be developed by installing a subsea production system and a semi-submersible production platform. Gas will be exported via the FLAGS pipeline to St.St Fergus and oil export throughexported via the Troll 2 pipeline to the StatoilHydro-operatedStatoil-operated Mongstad refinery near Bergen. The Gjøa platform will process and export volumes from both the Gjøa field and the neighbouring Vega fields. The platform will be supplied with land-based electricity from Mongstad. The total investments are estimated to betotal NOK 31.233.3 billion. We hold a 20% interest in Gjøa. Production is scheduled to start in late 2010.
    
    
    GDF Suez will be the operator from production start.

    The Gudrun Field is located in the North Sea. The field will be developed with a separate steel jacket based process platform for separation of oil and gas. Gas and partly stabilised oil will be transported in separate pipelines from Gudrun to Sleipner. Gas will be further transported through the Gassled system, while oil will be transported together with Sleipner condensate through pipeline to the Gassco operated Kårstø plant near Hugesund. The Plan for Development and operation was submitted to the Norwegian authorities in February 2010. Production is estimated to start in 1st quarter of 2014. The total investments are estimated to be NOK 20,3 billion. Statoil holds a 46,8% interest in Gudrun.

    Morvin, in which we hold an interest of 64%, is an oil and gas field located in the Norwegian Sea, 15 kilometres north-west of Åsgard. The field was discovered in 2001, and the Plan for Development and Operation was submitted in February 2008 and approved by the Norwegian authorities in April 2008. The field will be a subsea development with two templates tied in to Åsgard B for processing through a 20 kilometres long20-kilometre-long wellstream pipeline. The development of Morvin is currently estimated to require capital expenditure of NOK 98.4 billion, and production from the field is estimated to commence in late 2010.

    The PDO for Skarv was submitted in June 2007 and approved by the Norwegian Parliament in December 2007. Skarv is an oil and gas field located in the Norwegian Sea, in which we have an interest of 36.165% and for which BP is the operator. Skarv extends across three production licences (PL212/262 Skarv and PL 159 Idun). The field is being developed with an FPSO vessel and five subsea installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. Production is expected to start in August 2011, and the total development cost is estimated by the operator, BP, to be NOK 36.437.9 billion.

    The PDO for TyrihansGoliat, was submitted in which we hold an interest of 58.8%,February 2009 and approved by the Norwegian parliament in June 2009. Goliat is locatedthe first oilfield to be developed in the Norwegian Sea and consists of two hydrocarbon accumulations: Tyrihans South (an oilfield with associated gas) and Tyrihans North (a gasBarents sea. The field with a thin oil zone). The fields will beis being developed with subsea wells drilled and completed from five subsea templates, four dedicated production/gas injection and one for injection of raw sea water.tied back to a circular FPSO. The well streamoil will be transported in one pipelineoffloaded to the Kristin platform for processing. Gas injection for reservoir pressure support is provided from Åsgard B through ashuttle tankers. Associated gas injection pipeline to Tyrihans. Both the production pipeline between Tyrihanswill initially be reinjected and Kristin andlater exported together with the gas injection pipeline between Åsgard B and Tyrihans, as well ascap. Statoil is the subsea well templates, were installedonly partner in 2007.Goliat, with an interest of 35%. Eni is the operator. Production start-up is scheduled to startexpected in mid-2009.the fourth quarter 2013. The totaloperator's estimate of development costs are estimated to befor the field is NOK 14.928 billion.

    The Vega/Vega SørSouth project comprises the development of three separate gas-condensate accumulations: Vega NordNorth and Vega SentralCentral in PL248 and Vega SørSouth in PL090C. Our ownership interests in the licences are 60% and 45%, respectively. The fields are located in the North Sea. Three four-slot templates will be installed, and production will be transported to the Gjøa installation in a common pipeline. The total investments for the project are estimated to be NOK 7.97.5 billion. Production is scheduled to start in late 2010.

    The Yttergryta subsea gas and condensate field development, with an investment value of approximately NOK 1.4 billion, is an excellent example of a relatively small but significant project in our portfolio, since it was developed so quickly. The discovery was made in the summer of 2007 and the PDO was submitted in January 2008. Production drilling commenced in September 2008 and the wellstream will be tied back to Åsgard B platform via Midgard flow line for processing and further export. We hold a 45.75% interest in the project. Production started in January 2009.

    The table below shows some key figures for our major development projects.

    Project	StatoilHydro's share	StatoilHydros investment(1)	Production start	Plateau production  StatoilHydro's share(4)	Lifetime in years
    Alve	85.000 %	2.3	2009	21,000	12
    Gjøa	20.000 %	6.2	2010	19,000	15
    Morvin	64.000 %	5.8	2010	21,000	14
    Skarv(2)	36.165 %	13.2	2011	53,000	12
    Statfjord Late Life	44.340 %	8.7	2007	43,000(3)	12
    Tyrihans	58.840 %	8.8	2009	56,000	17
    Vega/Vega Sør	60%/45%	4.3	2010	30,000	13
    Yttergryta	45.750 %	0.6	2009	10,000	5
    (1) Estimated in NOK billion
    (2) Partner operated project
    (3) New additional production
    (4) Boe/day

    		Estimates of
    Project	Statoil's share	Statoil's investment (1)	Production start	Plateau production, Statoil's share (3)	Lifetime in years
    Gjøa	20.000 %	6.7	2010	19,000	15
    Goliat (2)	35.000 %	9.8	2013	30,000	18
    Gudrun	46.800 %	9.5	2014	40,000	12
    Morvin	64.000 %	5.4	2010	20,000	14
    Skarv (2)	36.165 %	13.7	2011	53,000	12
    Vega/Vega Sør	60% / 45%	4.1	2010	30,000	13
    (1) Estimated in NOK billion
    (2) Partner operated project
    (3) Boe/day

     

     Top 

    3.1.6.23.1.5.2 Redevelopments on the NCS

    The following projects are being developed on the NCS to give existing installations a new lease ofan extended life or to exploit new opportunities.

    Oseberg Low Pressureinvolves the installation of two new production manifolds for low-pressure wells with tie-in to second stage separators. Production is planned to startstarted in late 2009.February 2010.

    TheSnorre Redevelopment project, which is defined as an IOR project, and will contribute to achieveachieving the Snorre Unit and Vigdis overall oil recovery ambition. The project includes a water injection pipeline from Statfjord C to the Vigdis field.

    The Statfjord Late Lifeproject will convert Statfjord into a mainly gas-producing field by changing the drainage strategy. ExportThe export of gas to the UK through a new pipeline connected to the existing pipelines to Flags and St.St Fergus commenced in late 2007. The totalTotal investments in the project are estimated to beamount to NOK 19.621.4 billion.

    Troll Field projects includesinclude the Troll B Gas Injection projectProject and the Troll A P12 Pipeline Project. The main goalgoals for these projects isare IOR from Troll B and enablingto enable the Troll field to maintain an average gas export capacity of 120 million standard cubic metres per day and a long termlong-term gas export capacity of 30 gigabillion standard cubic metres per year.

    The Troll B Gas Injection project includes two gas injectors in the Troll West Gas Province south. Start upStart-up is planned in 2011.

    The Troll A P12 project includes a new 62.5 kilometres 36 inch62.5-kilometre 36-inch pipeline between Troll A and Kollsnes, modifications on Troll A and an interface with the Kollsnes plant. PipelineThe pipeline is planned to start in late 2011.

    The Troll C - O2 Template, which will be located north westnorth-west of the Troll C platform, is defined as an IOR project. The O2 Template will be tied back to the existing O1 Template, which is tied back to Troll C. Drilling is expected to startstarted in lateDecember 2009 and production is planned to start in 2010.

    A new low-pressure compressor module on Troll Cwill be installed on Troll C to increase capacity, and thereby production and recovery from Troll Vest.West. Production is planned to start in 2010.

    The Tune SørNorne M Template is a single satellitewill be located in the southern area of the Norne field. The template will have four production well tied back via the Tune Main templateslots and will be connected to the Oseberg Field Centre. Tie-inexisting infrastructure at the K template. Drilling and production is planned to start up are planned for mid-2009.in 2010.

     Top 

    3.1.73.1.6 Fields in production on the NCS

    3.1.7.1 3.1.6.1 Operations North Sea

    Operations North Sea coversincludes a majorlarge part of StatoilHydro'sStatoil's production activity on the NCS, and thereNCS. There is focus on increasing and prolonging production in the area, with priority ongiven to Improved Oil Recovery and the exploration and the development of new fields.

    Our producing fields in Operations North Sea are Troll, Fram, Sleipner, Kvitebjørn, Visund, Grane, Brage, Veslefrikk, Huldra, Glitne, Volve, Heimdal, Vilje and Vale. The area is dominated by the production of natural gas, as 59%53% of the equity production in 20082009 was gas. The petroleum reserves are located underbelow water depths of between 80 and 330 metres.

    

    In 2008, StatoilHydro's2009, Statoil's share of the area's production was 250269 mbbl of oil, condensate and NGL per day and 4918 mmcm (1,732(627 mmcf) of gas per day, or 558575 mboe in total per day.

    Brage is an oilfield east of Oseberg in the northern part of the North Sea. The oil is sent piped to Oseberg and onthen through the pipeline in the Oseberg Transport System to the Sture terminal. A gas pipeline is tied back to Statpipe. A new discovery in the Knockando area in the early autumn proved very successfully and came on production in October this year.

    Fram is connected to the Troll C platform for processing. Oil production started in 2003, and gas exports started in October 2007.

    Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS usingto use a stand-alone production system.

    Grane is the first field on the NCS to produce heavy crude oil, and is StatoilHydro'sStatoil's largest heavy oil field. The field is located to the east of the Balder field in the northern part of the North Sea. Oil from Grane is piped to the Sture terminal, where it is stored and shipped. Injection gas is imported to Grane in aby pipeline from the Heimdal facility. As a consequence, Grane will,result, after around 25 years of oil production, Grane will produce the injected gas. Due to a new drilling strategy, the field managed to increase daily production by approx. 15% in 2009.

    Heimdal is a gas field located in the northern part of the North Sea. Heimdal mainly operates as a processing centre for other fields. Huldra, Skirne and Vale deliver gas to Heimdal, and gas from Oseberg is also transported via Heimdal. Heimdal had reduced regularity in 2007, which contributed to reduced production on Heimdal Vale and Huldra.

    Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. Condensate from the Sleipner field is transported to the gas processing plant at Kårstø. The gas from Sleipner has a high level of carbon dioxide, which is extracted on the field and re-injected into a sand layer beneath the seabed to reduce the carbon dioxide emissions to the air. We are currently exploring several prospects and discoveries in the Sleipner area that can potentially be tied in to Sleipner.
    
    The Troll Area comprises Troll and Fram, and the Vega and Gjøa development projects. Troll is the largest gas field on the NCS and a major oilfield. The Troll Field Project submitted a new Plan for development, operation and installation in June 2008 for IOR in the area.

    In November we started test production for oil in the thin oil layers in the gas province of Troll East. The project is well under way.

    Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. Huldra is located in the Viking Graben and developed by a (normally unmanned) platform, remotely controlled from the Veslefrikk field. Oil from Veslefrikk is exported through the Oseberg Transportation System, while gas is exported to Kårstø. Veslefrikk also processes condensate from Huldra.

    The first oil flowed from the Vilje field to the Alvheim floating production, storage and offloading vessel (FPSO) on 1 August 2008. The Vilje field, which is linked to the Alvheim field, is located in the northern part of the North Sea, north of the Heimdal field. Vilje is the first StatoilHydro-operated field on the Norwegian continental shelf tied in to an installation that is run by another operator.

    The Visund oilfield is located to the east of the Snorre field in the northern part of the North Sea. The field contains oil and gas in several tilted fault blocks with separate pressure and liquid systems. The oil is piped to Gullfaks A for storage and export. Gas is exported to the Kvitebjørn gas pipeline and on to Kollsnes.

    Volve is an oilfield located in the southern part of the North Sea approximately 8eight kilometres north of Sleipner East.The development is based on production from the Mærsk Inspirer jack-up rig, with Navion Saga used as a storage ship to hold crude oil before export. Gas is piped to the Sleipner A platform for final processing and export. Volve started producing in February 2008.

    The Kvitebjørn field resumed production on 27 January 2009 after being shut down since August 2008 due to a gas leak created byresulting from damage caused to the Kvitebjørn gas pipeline. The damage, which was caused by a ship's anchor, was discovered during an inspection, and production was shut down. Production resumed in January 2008 after surveys showed that the pipeline could be temporarily used for export. Repair work was scheduled for summer 2008, but during preparatory work for the repair, critical equipment underwent extensive functional testing and parts of the equipment failed. Consequently, the repair was postponed until 2009. While making a routine inspection on the pipeline after the planned maintenance stop in August 2008, we discovered a gas leak from the pipeline and production was immediately stopped.

    Gas exports from Visund, which also uses the pipeline, were also affected by the pipeline damage.

     Top 

    3.1.7.2 3.1.6.2 Operations West

    The Operations West area contains light oil petroleum resources in a compact geographic area in which StatoilHydroStatoil is the sole operator. The main producing fields in the Operations West area are Statfjord, Gullfaks, Snorre, Oseberg, Tordis and Vigdis.

    OurStatoil's share of the area's production in 20082009 was 355256 mbbl per day of oil, condensate and41 mbbl per day of NGL and 19 mmcm87 mboe per day (682 mmcf per day) of gas, or 477385 mboe per day in total. Operations West is the leading oil producing area on the NCS and, even after 20 years of production, we believe there are still substantial opportunities for increased value creation.

    

    We haveStatoil has taken several initiatives to identify and implement measures to increase and prolong production from the Operations West area. These initiatives involve a combination of cost reductions and IOR, and they have resulted in athe prolongation of planned production beyond the current licence period for several of the fields.

    In 2008, Operation2009, Operations West performed fivesix turnarounds within the scheduled time frame and without severeserious HSE incidents.

    The Gimle field is a Gullfaks satellite field and is operated as a separate Unit. Permanent production started in May 2006, converting the Gimle exploration well drilled from the Gullfaks C platform into a production well. By the end of 2008, Gimle consisted of two producers and one injector, all drilled as long-reach wells from the Gullfaks C platform.

    Due to high depletion of the reservoir, production from Gullfaks South, Statfjord reservoir was temporarily shut down in October 2008. The production will be started up again when a new water injection well has been drilled.

    Gullfaks has been developed with three large concrete production platforms. Oil is loaded directly into custom-built shuttle tankers on the field. Associated gas is piped to the Kårstø gas processing plant and then on to continental Europe. FourFive satellite fields Gullfaks-Gullfaks South, Rimfaks, Gullveig, Gulltopp and Skinfaks - have been developed with subsea wells remotely controlled from the Gullfaks A and C platforms.

    The Gulltopp.Gimle Afield is a Gullfaks satellite field that is operated as a separate unit. At the end of 2009, Gimle consisted of two producers and one injector, all drilled as long-reach well has been drilledwells from the Gullfaks A-platform to develop the Gulltopp field. Gulltopp, which was discovered in 2002, is a small oilfield. Due to several operational problems, the well was temporarily plugged in the third quarter of 2006. Drilling resumed in October 2007, and the well was started up in 2008 producing considerably more than initially estimated.C platform.

    The Oseberg area includes the main Oseberg field, which has been developed with Field Centrefield centre installations, and the Oseberg C production platform, and two satellite fields, Oseberg East and Oseberg South, developed with production platforms. In addition, the Tune field and Oseberg West Flank have been developed with subsea installations and tied back to the Oseberg Field Centre. Oil and gas from the satellites is piped to the Oseberg Field Centre for processing and transportation. Oil is exported to shore through the Oseberg transportation system to the Sture terminal, and gas is exported through the Oseberg gas transportation system to Heimdal and on to market.

    There was a fatal accident on the Oseberg Delta is a subsea gas and oil development ofB installation on 7 May 2009. A person died after falling about 14 metres from scaffolding onto the resources indeck. A major safety programme for scaffodling activities has been launched after the Delta structure in block 30/9 that makes use of Oseberg Field Centre facilities for processing and export. Production started June 2008.

    Oseberg Gamma Statfjord is developed with two wells from Oseberg B. Oil production started in April, and water injection commenced in August 2008.

    Theta Cook was drilled as an exploration well from Oseberg C, converted directly to an oil producer and started in June 2008.

    Oseberg Field Centre celebrated 20 years of production in December 2008.accident.

    The PL 089 assetlicence includes the Vigdis, Borg and the Tordis fields. The Tordis field and the southern part of the Borg field have been 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. A subsea separator, boosting and injection unit was installed on Tordis in 2007 (Tordis SSBI), and most of the water from Tordis was injected through a dedicated water injection well into the Utsira formation.

    A leakage of produced water through the seabed was observed in May 2008, and the water injector was shut down resulting in reduced production from Tordis. The Tordis SSBI is planned to be started up in late 2009 or early 2010 with an alternative solution for the produced water disposal.

    The Vigdis field was developed in 1997, with three subsea templates with a well stream through pipelines connected to Snorre A, where the oil is stabilised and exported to Gullfaks for storage and loading. The northern part of Borg is also produced via the Vigdis templates. The Vigdis Extension Phase 2IOR project was completed earlyinvolving Increased Water Injection from Statfjord C is delayed due to the need for riser replacement, which is estimated to take place in 2008.2010.

    The Snorre field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A).system. Oil and gas is exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A.

    By July 2008 the Snorre field had produced 1000 mmboe of oil since field start-up.

    InspectionAn inspection revealed internal damage to three risers on Snorre B in the autumn of 2008, resulting in shut-downthe shutdown of risers and reduced production. Two of three risers were replaced during autumn 2009. The risers are expected tothird riser will be replaced in late 2009 or early 2010.

    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. Associated gas is piped through the Tampen link to the UK or, alternatively, to the Kårstø gas processing plant and then on to continental Europe. Three satellite fields (Statfjord Nord,North, Statfjord ØstEast and Sygna) have been developed, each of them tied back to the Statfjord C platform. In 2005, an amended PDO was approved by the Ministry of Petroleum and Energy for the late lifelate-life production period for Statfjord. The ministry granted a licence extension for the Statfjord area from 2009 to 2026.

    During modification work in the equipment shaft on 24 May 2008 an oil leakage from hot-tap equipment occurred. This resulted in an explosive atmosphere in parts of the shaft, and 50-70 cubic metres oil was pumped to sea to avoid escalation. Most of the personnel on board were evacuated, and no personal injury occurred.

    Due to integrity problems, the Statfjord Nord Satellite injection facility was shut down in November 2008. The field's production is currently reduced and is expected to be shut in early 2009. Equipment will be replaced during 2009.

     Top 

    3.1.7.33.1.6.3 Operations North

    Our producing fields in the Operations North area are Åsgard, Mikkel, Heidrun, Kristin, Norne, Urd, Njord and Snøhvit. The Yttergryta field started production in January 2009, and the Alve field started production in March 2009 and the Tyrihans field in July 2009.

    Our share of the area's production in 20082009 was 250175 mbbl per day of oil, condensate and NGL, and 4625 mmcm per day (777 mmcf per day) of gas, or 314333 mboe in total per day.

    

    This region is characterised by petroleum reserves located at water depths between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult and have challenged the participants to develop new types 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 decline in production from the mature fields through increased seismic activity and well maintenance. In addition, we intend to expand our activities by utilising our installed production and transportation capacity before building new infrastructure.

    The Heidrun platform is the largest concrete tension leg platform ever built. 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 in Norway. Additional gas volumes are exported through the Åsgard Transport System (ÅTS) to gas markets in continental Europe.

    Kristin is a gas and condensate field in the south-western section of the Operations North area. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and 170 degrees Celsius, respectively - are higher than any other developed field on the NCS. The stabilised condensate is exported to a joint Åsgard and Kristin storage vessel, and the rich gas is transported to shore via the ÅTS to the gas processing facility at Kårstø.

    Tyrihans started producing oil and gas in July 2009 and by the end of the year was producing from 3 wells. In 2008,addition gas is injected into a fourth injection well via Åsgard B. Tyrihans will be completed in 2010/2011 with another 7 wells. All production is processed on the last of twelve wells was completed and entered into production.

    Mikkel is a gas and condensate field. Production from two seabed templates is tied to the subsea installation at Midgard for onward transport to the Åsgard B gas processingKristin platform.

    Njord consists of two installations. Njord A is a platform with drilling facilities and a production plant for oil and gas. Njord B is a storage vessel for oil. The Njord field has produced oil since 1997, and gas exports started in late 2007 through thevia ÅTS and Kårstø.

    The Norne field has been developed with a production and storage ship tied to subsea templates. 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. Norne is connected to gas markets in continental Europe through a link with ÅTS.

    The Urd fields, Svale and Stær, are located ten kilometres and five kilometres north of the ÅTS.Norne field, respectively. The fields are produced through subsea facilities with the well stream tied back to the Norne FPSO.

    The Alve field, which consists of one producing well, was started up in March 2009. The field is produced through subsea facilities with the well stream tied back to the Norne FPSO.

    Snøhvit is the first developed gas field developed in the Barents Sea. Twenty wells will produce natural gas from three gas reservoirs: Snøhvit, Askeladd and Albatross. By the end of 2009 Snøhvit was producing from 6 wells. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore.

    The natural gas, which is transported to shore through a 143-kilometre long143-kilometre-long pipeline, and it is landed aton Melkøya where it is processed at our LNG plant. This plant is Europe's largest export factory for LNG. LNG, which is shipped to customers in Europe and the USA in tankers. The first shipment took place in late 2007.

    The LNG plant has suffered from operational challenges and there are still some uncertainties related to the timing of regular and stable operations. Performance and regularity has beenimproved significantly improved through 2008.in 2008 and 2009. One major maintenance stopshutdown in 2009 is plannedhas been carried out to achieve a further increasesimprovement in capacity and regularity.

    The Urd fields, Svale and Stær, are located ten kilometres and five kilometres north of the Norne field, respectively. The fields are produced through subsea facilities with the well stream tied back to the Norne FPSO.

    The Åsgard field contains three fields: Smørbukk, Smørbukk South and Midgard. The field was developed with the ÅsgardÅsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the ÅsgardÅsgard C storage vessel. The subsea production installations are among the most extensive in the world, with a total of 53 wells grouped in 18 seabed templates. Furthermore, the Åsgard B platform is the largest floating gas processing centre in the world and ÅsgardÅsgard A is one of the largest floating production ships ever built.

    The Åsgard development links the Haltenbanken area to Norway's gas transport system in the North Sea. Gas from the field is piped through the Åsgard Transport System (ÅTS) to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the ÅsgardÅsgard A vessel and condensate from the ÅsgardÅsgard C storage vessel are shipped from the field in shuttle tankers.

    Mikkel is a gas and condensate field. Production from two seabed templates is tied to the subsea installation at Midgard for onward transport to the Åsgard B gas processing platform.

    Yttergryta started production from a single well in January 2009. The well stream is tied back to Åsgard B for processing.

     Top 

    3.1.7.4 Partner operated3.1.6.4 Partner-operated fields on the NCS

    Partner-operated fields represent a significant proportion of StatoilHydro'sStatoil's oil and gas portfolio. The portfolio ranges from development projects to mature fields, and thetheir complexity of these requires detailed knowledge of the areas involved.

    Ormen Lange

    StatoilHydro has an 11.78% interest, a deepwater gas field in the EnochNorwegian Sea, is the second largest gas field operated by Talisman. on the NCS in which Statoil has a 28.92% interest. Statoil was operator for the development phase and Norske Shell became the operator for the production phase that began at the end of 2007. Statoil continues to execute approved, but not yet completed, parts of the subsea development. The fieldselected development is aan extensive subsea development tied backat depths ranging from 850 to Brae A1100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. Gas is then transported through a dry gas pipeline, Langeled, via Sleipner to Easington in the British sector. Production started in May 2007.UK.

    Ekofisk is the oldestfirst developed field complex inthat came into operation on the Norwegian Continental Shelf.continental shelf. The operator is ConocoPhillips. It consists of the fields Ekofisk, Eldfisk and Embla (StatoilHydro's(Statoil's interest 7.604%), plus Tor (StatoilHydro's(Statoil's interest 6.639%). Ekofisk has been upgraded with several new platforms over the years, theyears. The latest was 2/4-M, which was installed in 2005. Several new projects are being studied;studied: a new Ekofisk Hotelliving accomodation and fieldsfield centre, a new Ekofisk South drilling platform and redevelopmentredevelopments of Eldfisk.Eldfisk and Tor. Final decisions are expected to be takenmade during the next few years. These new platforms are expected to extend the field life beyond the current licence period, which ends in 2028.

    Ormen LangeSigyn, operated by ExxonMobil, is a deepwater gas and condensate field in the Norwegian Sea, is the second largest gas field on the NCS. StatoilHydro has an interest of 28.92%. StatoilHydro was the operator for the development phase and Norske Shell became the operator for the production phase that began at the end of 2007. StatoilHydro continues to execute approved, but not yet completed, partslocated 12 kilometres south-east of the subsea development. Ormen Lange extends acrossSleipner A installation in which we have a 60% interest. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. The development consists of three production licences. The selected development is an extensive seabed development at depths ranging from 850wells on one subsea template, with two pipelines and one umbilical connecting it to 1,100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. Sales gas is transported through a dry gas pipeline, Langeled, viathe Sleipner to Easington in the UK.A platform.

    StatoilHydroStatoil has a 14.82% interest in the ExxonMobil-operated field Ringhorne East. The unitised field started production in March 2006. Three production wells have been drilled from the Ringhorne facility. Oil is transported via Ringhorne to Balder for offshore loading. Gas is exported via Jotun into Statpipe. A fourth production well is planned.

    Sigyn, operated by ExxonMobil, is a gas and condensate field located 12 kilometres southeast of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. Our interest is 60%. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform.

    StatoilHydroStatoil has a 10% interest in the Skirne gas and condensate field, which is operated by Total. The field has two subsea templates.templates with one well each. The well stream is transported to Heimdal for processing. From there, gas is transported in Vesterled or Statpipe. The condensate is transported from Brae to Brae/FortiesSt Fergus in the UKUK.

    Statoil has an 11.78% interest in the Enoch field operated by Talisman. The field is a subsea development tied back to Brae A in the British sector. Production started in May 2007.

     Top 

    3.1.8 3.1.7 Decommissioning on the NCS

    There has been no decommissioning of StatoilHydro-operatedStatoil-operated fields during the last three years.

    The Norwegian government has laid down 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, known as the OSPAR Convention. However,During the last three years, however, there has been no decommissioning of StatoilHydro-operated fields during the last three years.Statoil-operated fields. On partner-operated fields, there has been removal activity aton Frigg and Ekofisk.

     Top 

    3.2 International E&P

    3.2.1 Industry overviewOur international E&P portfolio

    Statoil has built up a large international resource base in recent years. We are continuously optimising our portfolio, and our focus areas and strategies will be strengthened and supported through active portfolio management. .

    The global financial crisisMajor additions to our international portfolio include entry into the Marcellus shale gas acreage in north-eastern USA in 2008 and the subsequent recession whichpurchase of the global economy enteredKai Kos Dehseh oil sands in Canada in 2007. In 2008, we also took on the operatorship and acquired the remaining 50% equity share of Peregrino, a heavy oil project in Brazil. Statoil's main M&A activities in 2009 and early 2010 are presented below.

    Acquisitions:
    On 14 April 2009, Statoil acquired a 40% stake in 50 blocks from BHP Billiton in the second half of 2008 has inevitably also had an impact on the global upstream oil and gas industry.

    We have witnessed high volatility in oil and gas prices with concerns about availability dominating the first half of 2008. As the realityDeSoto Canyon area of the current global situation became more evidentUS Gulf of Mexico. This positions us in a frontier play in the second halfcentral GoM.

    On 18 May 2009, we reached agreement with BPC Limited to become the operator of three offshore exploration licences in the Bahamas, identified as a frontier play. Approval and awarding of the year, prices were subsequently impactedlicences by downward adjustmentsthe Government of the Commonwealth of the Bahamas is still pending.

    On 12 August 2009, we entered a deal where we farmed into a 30% share of the Repsol-operated BM-ES-29 licence in the Espirito Santo basin in Brazil, further positioning us in the pre-salt play. Repsol received equity shares in four of our GoM leases in exchange. The deal is currently pending government approval.

    Iraq is the latest new growth platform where we have succeeded in establishing a foothold in competition with other companies. In Iraq's second licensing round on 12 December 2009, Statoil and Lukoil submitted the winning bid for developing the West Qurna 2 field. On 31 January 2010 Statoil and Lukoil signed the development and production contract for West Qurna 2 with Iraqi authorities. The consortium of contractors consists of the state Iraq's North Oil Company (25%), Lukoil (56.25%) and Statoil (18.75%). Lukoil will be the operator.

     
    On 25 January 2010, we entered a deal with ConocoPhillips through which we gained 25% interest in 50 leases in the Chukchi Sea in Alaska. By adding on these leases to energy demand forecasts. This combinedthe 16 previously acquired in Chukchi, we now have a sizable acreage portfolio to explore in the coming years.

    In January 2010, we increased our share in St.Malo in the US GoM from 6.25% to 21.5% by exercising our pre-emption rights. The transaction was completed on 9 March 2010.

    On 17 March 2010, Statoil was the highest bidder on 21 leases in the Central lease sale 213 in the US GoM. Statoil's winning bids are subject to review and final approval by the Mineral Management Service (MMS).

    Divestments and other reduction of Statoil's portfolio:
    We completed the sale of our interests in licences off the coast of Denmark to Bayerngas Norge AS on 24 June 2009.

    On 30 June 2009, we completed the sale of our interest in the UK Caledonia field (21.32%) to Premier Oil ONS Limited.

    On 29 October 2009, we signed a well participation agreement with CNOOC under which we successfully farmed down Statoil's interest in several exploration prospects in the Gulf of Mexico.

    With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a heightened risk aversion20% interest, thus reducing Statoil's share from 40% to 30%.

    Libyan State oil Company (NOC) in speculative capital ledLibya has renegotiated the PSA for Mabruk, and in January 2010, our equity share of production in Mabruk was reduced from 25.0% to oil (Brent dated) being traded around USD 100 lower in December 2008 than at July 2008's all time high5.0% effective as of USD 144 per bbl.1 January 2008. 

    The industry has experienced a rapid increase in costs and capital expenditures over the past three to four years. This has been both as a result of limited competition and capacity in the service industry together with increased complexity of new projects. Although it could be expected that lower oil and gas prices and a lower volume of overall industry activity would contribute to a downward pressure on costs in the services and manufacturing industry, the technical challenges from increasing project complexity are unlikely to relent and will maintain an upward structural pressure on costs. In this environment, the industry is expected to increase its focus on cost control and capital deployment efficiency through tightening prioritisation among existing opportunities.

    International politics and adjustments to energy policies have also continued to influence the business environment in resource-rich countries across the world. In the short to medium term, there could be a potential for improved access and fiscal terms in some regions as a result of the global turmoil. However, it will not reduce the need for a continuous focus on building and leveraging technical and commercial capabilities in order to turn oil and gas resources into productive capacity.

    In recent years the industry has been characterised by a much higher level of competition, both in terms of the number and type of participants. This is unlikely to change. However, the sharp fall in share prices generally combined with the degree to which companies have access to capital to fund their future developments could act as catalysts to create change in the competitive landscape.

    The long-term challenge of providing the world with secure, affordable and environmentally acceptable energy remains as challenging a reality as ever. In combination, the above developments within the industry are likely to result in a continued highly competitive environment for scarce international upstream opportunities.

     Top 

    3.2.2 Portfolio managementInternational exploration activity

    Our

    Statoil's strategy is to develop key positions in four focus areas: deep water, heavy oil, gas value chains and harsh environments. It is also the framework for new growth and portfolio optimisation.

    In November 2008, StatoilHydro formed a strategic alliance with Chesapeake Energy Corporation, USA. The deal was completed in December 2008, with the purchase of a 32.5% interest in Chesapeake's Marcellus shale gas acreage in the Appalachia region of the northeastern USA. We paid USD 1.3 billion in cash and will pay a further USD 2.1 billion in the form of a 75% carry on drilling and completion of wells during the period 2009 to 2012. We have the right to a 32.5% participation in additional Chesapeake leases in the Marcellus shale play. In addition, the strategic alliance includes jointly exploring unconventional gas opportunities worldwide. The Chesapeake deal is another step in developing our gas value chain business expertise outside of Europe.

    In March 2008, we signed an agreement with Anadarko to acquire its remaining 50% interest of the Peregrino heavy oil field in Brazil. The transaction was formally closed on 11 December 2008, making StatoilHydro 100% owner and operator of the field. The sale was effective 1 January 2008. The oil production is expected to start in 2011 and StatoilHydro will subsequently become one of the largest foreign oil producers in Brazil.

    In 2008 we closed the sale of all our shallow water assets on the Shelf in the Gulf of Mexico(GoM) to Mariner Energy, Inc. for a cash consideration of USD 0.2 billion. The transaction was accomplished through the sale of our wholly owned subsidiary Hydro Gulf of Mexico, LLC. The sale was effective 1 January 2008. StatoilHydro remains one of the largest acreage holders in GoM deepwater with a strategic focus on high prospectivity deepwater areas. See note 3 business combinations for more information.

    On 9 February 2008, Sincor in Venezuela was transformed into an incorporated joint venture known as Petrocedeño, S.A. and partially nationalized. Our share was reduced from 15% in Sincor to 9.677% in Petrocedeño. The agreed compensation has been received in full from the Venezuelan government.

    Renegotiations of PSAs by the NOC in Libya have resulted in a reduced equity share. Our equity share of production in Murzuq was reduced from 8.0% to 2.4% effective as of 1 January 2008. Renegotiations are ongoing for Mabruk.

    In April 2008 we completed the divestment of our interest in the UK fields Dunlin (28.76%) and Merlin (2.35%), the Brent Pipeline system and the Sullom Voe Terminal located on the Shetland Islands to Fairfield and Mitsubishi. Effective date of sale was 1 January 2008.

     Top 

    3.2.3 Exploration activity

    Over the last years we have been continuously accessingaccess new exploration licencesacreage with high resource potential and moderate risk at the drilling stage to maximise the number of high impact wells.

    We have exploration licences in North America (Canada and the USA), Latin America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Morocco, Mozambique, Nigeria and Tanzania), Europe and the European, Caspian and Russian area (Denmark, theregion (the Faroes, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia). Our exploration strategy remains focused on accessing more new quality acreage, including unconventional hydrocarbons and exploration resources that are demanding in terms of technology.

    Since 2002In 2009, we have carried out a major global screening ofreduced our exploration spending and activity level to reflect the new market situation with lower oil and gas basins to rebuild our exploration portfolio and weprices. We have added significant resources and targeted new high-potential basins globally. In 2008 we have been high-grading the portfolio to better utilize the overall competence pool of StatoilHydro internationally.

    In 2008 we have also been further high-grading prospects for our short-term drilling programme. This entails prioritising and sequencing the most prospective drilling targets, optimising allocation of the rig fleet and providing a dedicated exploration organisation. We will continue to high-grade the portfoliocompleted 29 wells in 2009, and seven were ongoing at year end. Of the years to come.29 wells, six were announced as discoveries and nine are currently under evaluation. We plan to drill approximately 35about 30 wells in 2009.2010.

    In 2009, we reached an agreement with BPC Limited to become the operator of three offshore exploration licences: Zapata, Islamorada and Falcones in the Cay Sal area of the south-western Bahamas. Approval and the awarding of the licences by the Government of the Commonwealth of the Bahamas is still pending.

    In the Faroes, we have decided to enter into the third exploration period in Licence 008, and have committed to drilling one well during the period 2010-2014. We also received an extension for licences 006, 009 and 011 with one commitment well to drill.

    We completed 40 wellshave entered the next exploration period in 2008 and nine were ongoing at 31 December 2008. Of 40 wells, eight were announced as discoveries at year end,our 3/94 licence in Ireland with a commitment to drill one was annoucedwell.

    In 2009, we relinquished our sole licence in first quarter 2009 and 18 are currently under evaluation. Five of the nine ongoing wells were completed in the first quarter 2009, and one of them have been announced as a discovery.Morocco.

    The areas where we entered or had significant activity in 20082009 are presented below.

     Top 

    3.2.3.13.2.2.1 North America

     Top 3.2.3.1.1

    3.2.2.1.1 Canada

    StatoilHydro

    Statoil is operator and partner in prospectslicences off the coast of Newfoundland, and we have acquired 1100hold 1129 square kilometres (279,053 acres) of oil sand depositssands leases in Alberta.

    The Statoil-operated Mizzen well resulted in a discovery in 2009.

    Offshore
    In November 2008We completed drilling and testing operations for the Newfoundlandexploration Mizzen well in licence 1049 in the frontier Flemish Pass basin in March 2009. The well proved a hydrocarbon accumulation, and Labrador authorities announced that we werea Significant Discovery Licence was awarded two licences, one asin February 2010.. Statoil is the operator withand holds a 65% interest in the Flemish Pass Basinlicence.

    Ballicatters, an exploration well operated by Suncor with Husky as partner, the other witha Statoil interest of 50% interest, was drilled in the Jeanne d'Arc Basin with Petro-Canada asbasin on licence 1113 and 1092 from July to October 2009. For technical reasons, the operator.well has been suspended. A plan for re-entry is currently being developed.

    The licenses were awardedEvaluation work based on a work expenditure bid with no legal obligation to perform the work program. If no work program is committed during the five first years, 25% of the bid has to be paid. The licenses were formally awarded in January 2009.

    In 2008 a 3D seismic survey was acquired and processeddata on the two operated licenseslicences in the southern part of the Jeanne d'Arc Basin near the Terra Nova Field. StatoilHydro holds a 50% interest in both licenses.

    Drilling operations at the Mizzen exploration well in license EL 1049 in the frontier Flemish Pass basin started at the end ofhas continued during the year with StatoilHydro asin order to define drillable prospects. This work will continue in 2010, and plans for the operator with a 65% interest. The well is expected to be completed in 2009.

    In 2009 activities will also include the planned drilling of an exploration well on EL 1092 operated by Petro-Canada. We have a 50% interest in this license. Evaluation of the existing licensesidentified prospects will aim to identify new drillable prospects.be developed.

    Oil Sandssands
    We currently have an interest in 11141129 square kilometres (275,213(279,053 net acres) of oil sandssands' leases located in the Athabasca region of Alberta.

    In order to determine the extent of the exploitable oil sands deposits in Alberta, a total of more than fourthen five hundred wells were drilled in the region from 2003 to 2008.2009. In addition, 2076 square kilometres of 2Dextensive seismic and 210 square kilometres of 3D seismic have been acquired. The oil sands exploration program has been reduced, andsurveys were acquired during that period.

    In the 2008-2009 winter drilling programme, only wells required for delineation, observation and water source or disposal for Corner and Leismer Expansion remain in the 2009 winter drilling programme.
     
    near-term development phases were drilled.

    Our oil sand activities are described in more detailsdetail in section 3.2.6.1.13.2.5.1.1 Operational review-Internationalreview - International E&P-Fields&P - International fields in development and production-North America-Canada.production - North America - Canada.

     Top 

    3.2.3.1.23.2.2.1.2 The USAUSA

    StatoilHydro has

    We have significant activities in the USA, with more than 400 leases in ourthe Gulf of Mexico portfolio, and several66 in Alaska. With two new rigs in the Gulf of Mexico, we embarked on an extensive drilling programme and were drilling two operated wells to be drilled in coming years. We were also awarded 16 leases in Alaska in 2008.

    at the end of 2009.

    US Gulf of Mexico
    Since 2003,

    

    During 2009, we have establishedparticipated in ten exploration and appraisal wells, five of which were completed by year end. Heidelberg 1 and Vito 1 wells were announced as Miocene oil discoveries in 2009. A Vito appraisal well (sidetrack to Vito 1) was announced as a significant deepwater portfolioMiocene oil discovery in March 2010, and we are one ofa second sidetrack appraisal well is planned for 2010 to further delineate the largest deepwater acreage holdersdiscovery.

    In 2009, Statoil became the operator for an extensive drilling programme with two new rigs arriving in the Gulf of Mexico (GoM). Our current deepwater GoM portfolio consists of more than four hundred leases.

    

    During 2008 we completed nine exploration wells and appraisal wells. Appraisal well Big Foot 3, sidetrack number two, has confirmedduring the same pay intervalssecond half of the previously announcedyear. At year end, the Maersk Developer was drilling an appraisal well on the Tucker discovery in Walker Ridge and sidetrack well. Threethe Discoverer Americas was drilling an exploration well on the Krakatoa prospect in Mississippi Canyon. These two operations will continue in 2010, and we plan to drill additional deepwater wells were ongoingduring 2010.

    

    In 2009, we acquired a 40% stake in 50 leases from BHP Billiton in the frontier DeSoto Canyon area of the US Gulf of Mexico. DeSoto Canyon is located east of Statoil's current production operation at year end. TwoIndependence Hub. The area has water depths of them have been completed in first quarter with one announced discovery.

    about 1000 metres. We were awarded 21 deepwater blocks in the Central Lease Sale 205 in the first quarter of 2008. We participated in the Central Lease Sale 206 and Western Lease Sale 207 held in 2008. Following the sales we were awarded 1623 leases from Central Lease Sale 206 and five leases from Western Lease Sale 207 . We participated in the Central Lease Sale 208, including 14 in the eastern GoM with partner BHP Billiton. Following a thorough technical evaluation, it was decided not to submit any bids for the Western Lease Sale 209.

    Statoil was the highest bidder on 21 leases in the Central lease sale 213 in March 2009.There2010. Statoil's winning bids are no work commitments associatedsubject to review and final approval by the Mineral Management Service (MMS).

    To date, three multi-well participation agreements have been entered into with GulfEcopetrol (agreement concluded in 2008), Repsol and CNOOC, reducing our interests in a total of Mexico leases.eight deepwater prospects .

    In 2008 we have signedAlaska
    We entered an agreement with the Colombian oil company Ecopetrol America inc.ConocoPhillips under which we acquired a 25% equity in 50 leases covering the two companies will form a Joint Exploration Team for the Gulf of Mexico and drill three or more wellsDevil's Paw prospect in the coming years. Ecopetrol will farmChukchi Sea.

    With the selection of the seismic contractor in 2009, we have taken the first step towards 3D Seismic acquisition for Statoil's Chukchi Sea acreage, which is planned for 2010. Preparation of environmental and other permit applications is progressing and stakeholder engagement with interests of 20 to 30%North Slope communities has also commenced. In addition, Statoil has participated in the wells covered by the agreement.

    We have contracted two newly built rigs, Maersk Developer (joint contract with Woodside) and Discoverer Americas, which are expected to arrivecollection of environmental baseline data in the Gulf of Mexico during 2009. These rig slots will be usedChukchi Sea.

    Gas shales
    Exploration activity related to drill explorationgas shale in onshore USA is presented in article 3.2.5 Operational review-International E&P-Fields in development and appraisal wells on our operated exploration acreage. In addition we expect to participate as a partner in a number of exploration and appraisal wells.production.

    Alaska
    In 2008 we were awarded 16 leases in Chukchi Sea Lease Sale 193 in Alaska. Fourteen of these were joint bids with ENI Petroleum. We are the operator of all leases. The Chukchi Sea is located offshore Alaska northwest of Prudhoe Bay, in water depths less than 100 metres. The area is considered a frontier area with no production or infrastructure as of today. There are no work commitments associated with Alaska leases.

     Top 

    3.2.3.23.2.2.2 Latin America

     Top 3.2.3.2.1

    3.2.2.2.1 Brazil

    We have interests in eightnine exploration licences in four different basins in offshore waters inoff the coast of Brazil. We are the operator of four of the licences. During 2009, we acquired a 30% interest in the pre-salt licence BM-ES-29.

    
     

    In 2009, we farmed into a 30% share of the Repsol-operated BM-ES-29 licence in the Espirito Santo basin with one commitment well to drill. The interests in three blocks that we won in the 8th round in the Santos basin are pending award.

    We have completed two wells in BM-J-3 and one well in BM-C-33, which fulfilled our commitments for these licences. We have one commitment well in BM-CAL-10, one in BM-CAL-7 two commitment wells in BM-C-33 and one commitment well in licence BM-C-47 from the 9th Bid Round, awarded in March 2008.
    BM-C-47.

    

    A 30% interest in blocks S-M-1105 and 1109 and the operatorship and a 40% interest in block S-M-1233 in the 8th Bid Round are still pending award by the government.

    One exploration well spudded in 2008 in block BM-J-3 was completed in 2009. Petrobras is operator, and our share is 40%.

     Top 

    3.2.3.33.2.2.3 Africa

    3.2.3.3.1Algeria

    We are the operator and have 75% interest in the exploration phase for the Hassi Mouina block. This block extends over 23,000 square kilometres and is situated in the western/central part of the Sahara in an under-explored area.

    Three discoveries were announced in 2008. In 2008 we were granted an additional two year exploration period which expires in March 2010. The extension included a 30% relinquishment of the licence area.

    

    All commitments in the licence are fulfilled. In 2009 two additional appraisal wells will be completed. In addition to this a 3D campaign will be carried out across the discovery regions of the block.

    During 2008 an internal team has worked on maturing the technical solutions for a possible commercial development of the Hassi Mouina discoveries.

     Top 

    3.2.3.3.2 Libya

    StatoilHydro operates three exploration licences in Libya totalling over 23,000 square kilometres.

    Area 94 covers an area of 9,849 square kilometres on the south-eastern Cyrenaica Platform with a commitment of one exploration well and 2D seismic. The commitment well was spudded in 2009. We have a 100% interest in this area.

     

    Area 146 covers an area of 2,492 square kilometres in the Murzuk basin with a work commitment of 2D seismic and two exploration wells. We have a 100% interest in this area.

    Area 171 covers an area of 11,305 square kilometres in the Kufra basin with a work commitment of two exploration wells and 2D seismic. The first commitment well was drilled in 4Q 2008. We have a 50% interest in this area.

    In addition, we have a 20% exploration interest in Area 186, operated by Repsol. Nine wells were drilled during 2008.

     Top 

    3.2.3.3.3 Egypt

    We are operator with an 80% interest in two offshore exploration licences located in the Mediterranean, west of the Nile Delta in water depths ranging from sea level to 3000 metres. Production sharing agreements for both blocks were signed in July 2007.

    El Dabaa Offshore (Block 9) covers an area of 8368 square kilometres. We are committed to drilling one exploration well and conducting 2D and 3D seismic surveys over a four-year period. We have acquired and are evaluating the seismic surveys. Drilling is planned to commence in 2010.

    Ras El Hekma Offshore (Block 10) The block covers an area of 9802 square kilometres. The related work commitment includes 2D and 3D seismic surveys over a four-year period. 2D seismic acquisition and processing is complete. 3D seismic has been acquired and processing is scheduled for completion in 2009.

     Top 

    3.2.3.3.43.2.2.3.1 Angola

    StatoilHydro

    Statoil holds interests in blocks 4/05, 15, 15/06, 17, 31 and 34 in Angola. TwelveFourteen wells were completed in 2008,2009, with fourthree announced as discoveries.

    Block 4/05 We have extensive exploration activity in which we have a 20% interest is operated by Sonangol. The licence was given a two year extensionAngola, with a well commitment. One exploration well wasnumber of wells drilled in 2008.2009 and expected to be drilled in 2010 and the coming years. We have interests varying from 5% to 50% in six blocks .

    The Block 15 exploration licence, with ExxonMobil as operator, has expired. Areas with proven oil have been converted to Development Area (DA) and Provisional Development Areas (PDA). A total of 3638 exploration and appraisal wells have been drilled on the original Block 15 and offspring DA'sDAs and PDA's. PDAs.

    In 2008 two appraisal wells were drilled. We have a 13.33% interest in this block.

    Block 15/0617 in, which we have a 5% interest is operated by Eni. The work commitment for Block 15/06 is extensive, covering 3D seismic surveys and the drilling of eight wells, to be carried out during the first five years of the exploration phase. The 3D commitment was fulfilled and two of the eight exploration wells were drilled in 2008, both announced as discoveries.

    Block 17 in which we have a 23.33% interest is operated by Total. To date,Total, a total of 3234 exploration and appraisal wells have been drilled, and all exploration commitments have been met. with the last two completed in 2009.

    In 2008 two exploration wells were drilled.

    Block 31 in which we have 13.33% interest is operated by BP. In 2008, fiveBP, six exploration wells were completed in 2009 with two announced discoveries and toannounced. To date, a total of 2631 exploration wells have been drilled in the block. The licence was given a two year extension with a commitment of four wells. The exploration period ends in 2010.

    Block 34 in which we have a 50% interest is operated by the Angolan national oil company Sonangol P&P, and we are the technical assistant to the operator. In 2005, Sonangol P&P signed an agreement with the concessionaire to enter into the second exploration phase for Block 34 with a one well commitment. The licence was given a three year extension with no additional well commitment. The period expires in 2011.

     Top 

    3.2.3.3.5 Nigeria

    StatoilHydro is operator for two deepwater exploration licences, OML 128 and OML 129. In addition, we have shares in two exploration licences, OPL 315 operated by Petrobras and OPL 242 operated by Ocean Energy (Devon).

    OML 128. We have a 53.85% interest in OML 128. The Agbami field straddles OML 127 and OML 128. [OML 128] came on stream in July 2008. The remaining prospectivity in the licence will be re-assessed in 2009, based on information from the Bilah and NnwaDoro evaluations.

    OML 129. We have a 53.85% interest in OML 129. There are two discoveries in the block, Bilah and Nnwa. Only one well has been drilled in the Bilah condensate discovery.

    The Nnwa discovery extends into the Shell-operated Block OML 135 (known as the Doro structure). The joint StatoilHydro and Shell subsurface project which was started in 2007 was completed mid-2008 and the results have been presented to the Nigerian Authorities.

    OPL 315. We have 45% interest in block OPL315. The licence is committed to carry out a work programme by February 2011 consisting of one well and a seismic survey.

    OPL 242. We have a 15% interest in OPL 242. All exploration obligations have been fulfilled and we are in the process of relinquishing the licence.

    We had interests in OPL 324 and OPL 256 but these blocks were relinquished in 2008.

     Top 

    3.2.3.3.6 Tanzania

    StatoilHydro is operator with a 100% interest in Block 2. The total area of Block 2 is 11,099 square kilometres and it lies in water depths of between 400 and 3000 metres. This is a frontier area, as noThree wells have been drilled this far from the coast.

    The exploration period startedcompleted in 2007Block 15/06, with one discovery announced and is divided into three stages:

    • The first exploration period of four years with a 2D seismic commitment
    • The first extension period of four years with a one well drilling commitment
    • The second extension period of three years with aongoing at year end.

      We have fulfilled our commitments in blocks 15 and 17 and have remaining commitments to fulfil in other blocks: one well drilling commitment

    A 6200-kilometre 2D seismic survey was acquired during the first quarter of 2008. Final processed data was delivered in January 2009. According to the latest estimates the earliest time for first drilling will beBlock 4/05, two wells in 2011.Block 15/06, one well in Block 31 and one well in Block 34.

     Top 

    3.2.3.4 Europe,3.2.2.3.2 East Africa

    Statoil is the Caspianoperator of two large frontier offshore blocks in the East Africa region - Block 2 in Tanzania and RussiaArea 2&5 in Mozambique, both with water depths in the 1000 to 3000 metres range.

    3.2.3.4.1United Kingdom

    Our Statoil UK subsidiary produces oil and gas and conductsBlock 2 (11,099 square kilometres), Tanzania: We have fulfilled the seismic commitment in the current exploration on the UK continental shelf, where we have interests in more than 100 North Sea and Atlantic margin blocks.

    StatoilHydro is a 30% partner in a group of Chevron-operated exploration licences west of Shetland. In late 2008 drilling commenced on an exploration well on Rosebank / Lochnagar North.

    In 2008 Hess drilled a discovery well on the Amos Prospect which is located four kilometres south of Schiehallion. StatoilHydro has a 17.65% interestphase in this discovery.

    block. In 2008order to mature the block further, a high resolution1600-square-kilometre 3D seismic survey has been acquired between December 2009 and a pilot ocean bottom cable seismic programme were acquired overMarch 2010. In March 2010, we farmed down 35% of our equity to ExxonMobil. We are the Mariner Field. Also in 2008, a well was drilled on Bressayoperator of the block and tested. In addition, in this heavy oil area, StatoilHydro completed a well on the Broch Prospect (9/11e-14).

    The Mariner and Bressay heavy oil fields have been established as development projects but with further appraisal drilling ongoing. These fields are described in report section 3.2.6.4.1 Operational review, International E&P-Fields in development and production-Europe, Caspian region and Russia-United Kingdom.

     Top 

    3.2.3.4.2 Azerbaijan

    We have a 25.5%65% interest.

    Area 2&5 (13,402 square kilometres), Mozambique: We are the operator, with a 90% interest in the Shah Deniz licence, operated by BP. All exploration commitments have been fulfilled. There was a major gas-condensate discovery in 2007 confirming sufficient gas at Shah Deniz for a second stage development.

    A further appraisal well (SDX-5) was spuddedwhich consists of two blocks under one licence agreement, with the state oil company Empresa Nacional de Hidrocarbonetos (ENH) as partner. We are currently in the south-eastern part of the structure in 2008, andsecond exploration period during which there is expecteda commitment to be completed in 2009.shoot 3D seismic. A 1300-square-kilometre 3D survey is currently being acquired.

    We signed an exploration, development and production sharing agreement (PSA) in 1998, with BP as operator, covering the Alov, Araz and Sharg structures.

    We have a 15% interest in this PSA, which is located roughly 150 kilometres south-east of the Azeri capital of Baku. The contract area covers about 1400 square kilometres and is located in water depths of 450 to 800 metres. The structures are located in the area of the Caspian Sea that is the subject of a dispute between Azerbaijan and Iran, and, since the contract was signed, Iran has claimed that parts of the area are in Iranian waters. Negotiations with SOCAR, the State Oil Company of Azerbaijan, have resulted in a freezing of the licence fee until the border issue is resolved.

     Top 

    3.2.3.4.3 The Faroes

    StatoilHydro was awarded a 50% interest in one lease with operatorship in 2008. We are now the operator of five licenses in the Faroe Islands and partner in one in which Chevron is the operator.

    3D seismic operations have been conducted in licence 009 and 011 during 2008.

     Top 

    3.2.3.53.2.2.3.3 Egypt

    We are the operator, with an 80% interest, in two offshore exploration licences located in the Mediterranean, west of the Nile Delta, in water depths ranging from sea level to 3000 metres.

    El Dabaa Offshore (Block 9) covers an area of 8368 square kilometres. We have fulfilled the 2D and 3D seismic commitments. We have a commitment to drill one well in this licence and planning related to the drilling of this well will be in focus during 2010.

    Ras El Hekma Offshore (Block 10) covers an area of 9802 square kilometres. We have fulfilled our work commitment in this licence, which includes the acquisition of 2D and 3D seismic surveys. Initial processing was completed early in 2009, and further processing is ongoing.

     Top 

    3.2.2.4 Middle East and Asia

     Top 

    3.2.3.5.13.2.2.4.1 Indonesia

    StatoilHydro

    Statoil is operator of the Karama production sharing contract (PSC) with a 51% interest, and it has agreements which give us interestsa 40% interest in the deepwater Kuma and Karama blocksPSC. Both licences are located off Indonesia, where thein water depth rangesdepths ranging from 1000 to 2000 metres.

    

    In 2008 we2009, all the acquired 2297 square kilometres of 3D seismic data overhave been processed, and seismic interpretation and mapping of potential drilling locations have been initiated for both the Karama PSC and have fulfilled our seismic work obligation. Within the Kuma PSC, 1044 square kilometres of 3D seismic dataPSC. We have been acquired. A contract for usingentered into several shared drilling-related contracts together with the other five consortium companies that will use the contracted drillship, Global Santa Fe Explorer was signed by a consortium of six oil companies including StatoilHydro in 2008. The contract is for two years with a one year extension option. TheExplorer. We have three commitment wells in the Karama PSC, will be drilledand one commitment well in 2011, while the Kuma wellPSC. Drilling is expectedplanned to be drilledstart in late 2010 or early 2010/2011. Drilling preparations will be initiated for all operated and non-operated wells.

    A two year extension of the Memorandum of Understanding (MOU) with Pertamina was signed in October 2008.

     Top 

    3.2.3.5.2 India

    StatoilHydro has an agreement with the Indian state oil company Oil and Natural Gas Corporation (ONGC) that gives us access to exploration acreage off India, mostly in deep waters.

    In July 2008 the Indian Government approved the assignment of a 10% participating interest in Block KG-DWN-98/2 to StatoilHydro in accordance with a previously signed farm-out agreement. Block 98/2 is located on the East coast of India in the Krishna Godavari Basin. ONGC is operator with a 65% interest. The block covers an area of 7295 square kilometres. Several discoveriesstudies have been madeinitiated to support the definition of optimal drilling locations and in the block,preparation for safe and both gas and oil have been encountered.efficient drilling operations.

     Top 

    3.2.4 Oil and gas reserves3.2.3

    This section describes our internationalInternational oil and gas reserves and explains changes that have had an effect on

    At the reserves balance.

    The proved reservesend of 2009, the international business area increasedhad a total of 824 mmbbl of proved oil reserves and 34.3 bcm (1 210 bcf) of proved natural gas reserves.

    

    Measured in barrels of oil equivalents (boe), our international proved reserves consist of 79 % oil and 21 % natural gas, based on total international proved reserves of 1 039 mmboe.

    Several of our international fields contribute positively to the reserves balance in 2009:

    • Kizomba satellites phase 1 in Angola and the Caesar Tonga Unit in Gulf of Mexico, USA, were sanctioned in 2009.
    • The Gimboa field in Angola commenced test production in April 2009.
    • The PSVM development in Angola was approved by 2%the concessionaire in 2008 and as a result recorded proved reserves for the first time in 2009.
    • The Marcellus Shale Gas play in USA, part of our gas value chain strategy, recorded proved reserves in 2009 for the first time.
    • The Leismer Demonstration Project in the Kai Kos Dehseh leases in Canada, with initial production scheduled for late 2010, contributes to the reserves balance in 2009 with reference to several analogous SAGD projects in operation in the Athabascan area.

    Effective from 1039 mmboe1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20 % interest, thus reducing Statoil's share from 40 % to 1055 mmboe.30 % and having a negative effect on our reserves' balance.

    
    The increase in the oil price during 2009 has had a negative effect on our proved reserves estimate in 2008 reflects the effect of lower oil prices on entitlement productionreserves' estimates for international projects with a Production Sharing Agreement or a Buy Back Agreement.

    Several purchase and sale agreements and change of ownership were finalised in 2008 having effect on the international reserves balance:

    - The purchase of Anadarko's 50% share in Peregrino was finalised late in 2008 and contributed positively to the international reserves balance.
    - On 9 February 2008, Sincor in Venezuela was transformed into an incorporated joint venture known as Petrocedeño, S.A. and partially nationalised, resulting in a change of our share from 15% to 9.677% and a reduction of proved reserves.

    - The sale of our Shelf portfolio in Gulf of Mexico was effective from 1 January 2008, resulting in reduction in proved reserves.

    Acquisition of a share in the Marcellus shale gas play in the USA was completed December 2008, but no reserves are booked in 2008. With few wells in production, limiting the reserves that can be booked by the year end, StatoilHydro has not included the Marcellus shale in the 2008 proved reserves estimation.

    North American Oil Sands Corporation was officially taken over by StatoilHydro in the middle of 2007, but the current maturity level and recovery techniques of the asset do not yet justify recognition of proved reserves.

    The share of developed reserves at year-endyear end is 536565 mmboe, which is up 17.5%5 % from 2007.2008. Of the 20082009 proved developed reserves, 406413 mmboe are oil/NGLoil and 20.624.1 bcm (727(852 bcf) are natural gas. The increase in proved developed reserves is primary related to production start-up of developments in Angola and future development in fields in Azerbaijan and Libya.

    The following table shows our total international proved reserves as of 31 December for each of the last three years. Further information on reserves can be found in section 3.9 Operational review - Proved oil and gas reserves and in note 3435 - Supplementary oil and gas information - to our Consolidated Financial Statements.consolidated financial statements, which also explains revisions to the methodology for reserve estimation for 2009 compared with earlier years.

    		Oil/NGL	Natural gas		Total		Oil/NGL	Natural gas		Total
    Year		mmbbls	bcm	bcf	mmboe		mmbbls	bcm	bcf	mmboe
    2009						Proved reserves end of year	824	34.3	1,210	1,039
    						of which, proved developed reserves	413	24.1	852	565
    2008	Proved reserves end of year	805	39.7	1,403	1,055	Proved reserves end of year	805	39.7	1,403	1,055
    	of which, proved developed reserves	406	20.6	727	536	of which, proved developed reserves	406	20.6	727	536
    2007	Proved reserves end of year	785	40.4	1,426	1,039	Proved reserves end of year	785	40.4	1,426	1,039
    	of which, proved developed reserves	323	21.2	748	456	of which, proved developed reserves	323	21.2	748	456
    2006	Proved reserves end of year	756	44.3	1,567	1,032
    	of which, proved developed reserves	334	8.0	283	385

     

     Top 

    3.2.5 Production3.2.4 International production

    This section describes our production outside Norway.

    StatoilHydro's

    Statoil's petroleum production outside Norway in 2009 amounted to an average of 290357 mboe per day of entitlement production and 465512 mboe per day of equity production in 2008. Theproduction.

    Our total annual entitlement production in 20082009 was approximately 106130 mmboe, compared with 112106 mmboe in 2007.

    For the year ended 31 December
    	2008				2007				2006
    	Oil and NGL	Natural gas			Oil and NGL	Natural gas			Oil and NGL	Natural gas
    Production	mbbl	mmcm	mboe		mbbl	mmcm	mboe		mbbl	mmcm	mboe
    Total	232	9	290		252	9	307		194	6	234

    2008. The first table shows our average daily entitlement production of oil, including NGL and condensates,liquids and natural gas for each of the years ending 31 December 2009, 2008 2007 and 2006. New2007. In 2009 the fields thatTahiti and Thunder Hawk in the USA came on stream in 2008 were Mondo and Saxi-Batuquethe Gimboa field in Angola Deep Water Gunashlistarted test production.

    	For the year ended 31 December
    Entitlement production	2009	2008	2007
    Oil and NGL (mboe per day)	283	232	252
    Natural gas (mmcm per day)	12	9	9
    Total (mboe per day)	357	290	307

    The next table provides information about the fields which contributed to 2009 production.

    Field	Statoil's equity interest in percent	Operator	On stream	License expiry	Productive wells as of year end
    North America
    Canada: Hibernia	5.00%	HMDC	1997	2027	33
    Canada: Terra Nova	15.00%	Suncor	2002	2022	15
    USA: Lorien	30.00%	Noble	2006	HBP (1)	2
    USA: Front Runner	25.00%	Murphy Oil	2004	HBP	8
    USA: Spiderman Gas	18.33%	Anadarko	2007	HBP	3
    USA: Q Gas	50.00%	Statoil	2007	HBP	1
    USA: San Jacinto Gas	26.67%	ENI	2007	HBP	2
    USA: Zia	35.00%	Devon	2003	HBP	1
    USA: Seventeen Hands	25.00%	ENI	2006	HBP	1
    USA: Marcellus shale gas	Varies	Varies	2008	HBP	51
    USA: Tahiti	25.00%	Chevron	2009	HBP	6
    USA: Thunder Hawk	25.00%	Murphy Oil	2009	HBP	3
    Latin America
    Venezuela: PetroCedeño (2)	9.68%	PetroCedeño	2008	2032	404
    Sub Saharan Africa
    Angola: Kizomba A	13.33%	ExxonMobil	2004	2026	27
    Angola: Kizomba B	13.33%	ExxonMobil	2005	2027	24
    Angola: Xikomba	13.33%	ExxonMobil	2003	2027	5
    Angola: Marimba North	13.33%	ExxonMobil	2007	2027	3
    Angola: Mondo	13.33%	ExxonMobil	2008	2029	9
    Angola: Saxi-Batuque	13.33%	ExxonMobil	2008	2029	7
    Angola: Girassol/Jasmim	23.33%	Total	2001	2022	25
    Angola: Dalia	23.33%	Total	2006	2024	26
    Angola: Rosa	23.33%	Total	2007	2022	12
    Angola: Block 4/05  (3)	20.00%	Sonangol	2009	2026	3
    Nigeria: Agbami	18.85%	Chevron	2008	2024	12
    North Africa, Europe, Caspian and Russia
    Algeria: In Salah	31.85%	Sonatrach/BP/Statoil	2004	2027	32
    Algeria: In Amenas	50.00%	Sonatrach/BP/Statoil	2006	2022	17
    Libya: Mabruk (4)	5.00%	Total	1995	2028	59
    Libya: Murzuq	2.40%	Repsol	2003	2032	93
    Azerbaijan: ACG	8.56%	BP	1997	2024	59
    Azerbaijan: Shah Deniz	25.50%	BP	2006	2031	4
    UK: Alba	17.00%	Chevron	1994	2018	38
    UK: Caledonia (5)	21.32%	Chevron	2003	2018	1
    UK: Jupiter	30.00%	ConocoPhillips	1995	2010	16
    UK: Schiehallion	5.88%	BP	1998	2017	21
    Russia: Kharyaga (6)	30.00%	Total	1999	2032	20
    Middle East and Asia
    China: Lufeng (7)	75.00%	Statoil	1997	2011	0
    Iran: South Pars	37.00%	POGC	2008	2012	30
    Total International E&P					1073
    (1) Held by production; A company’s right to own and operate an oil and gas lease is perpetuated beyond its original primary term, as long thereafter as oil and gas is produced in paying quantities
    (2) Petrocedeño is a non-consolidated company
    (3) Producing wells are related to test production
    (4) Renegotiation of the PSA by the Libyan State oil Company (NOC) for the Mabruk field was completed in January 2010. Statoil's equity share in Mabruk was reduced from 25.0% to 5.0% effective as of 1 January 2008
    (5) Caledonia field was sold to Premier Oil in June 2009
    (6) With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20% interest, thus reducing Statoil's share from 40% to 30%
    (7) Lufeng field was shut down in June 2009

    The table below presents equity and entitlement production per country in Azerbaijan, Agbami in Nigeria and South Pars in Iran. In addition we purchased a 32.5% interest in the Marcellus shale gas acreage in the USA.2009.

    Field	StatoilHydro's equity interest in percent	Operator	On stream	License expiry	Producing wells	Development wells
    North America
    Canada: Hibernia	5.00%	1997	2027	31	1
    Canada: Terra Nova	15.00%	PetroCan	2002	2022	15	0
    USA: Lorien	30.00%	Noble	2006	2012	2	0
    USA: Front Runner	25.00%	Murphy Oil	2004	2010	6	0
    USA: Spiderman Gas	18.33%	Anadarko	2007	2012	3	0
    USA: Q Gas	50.00%	StatoilHydro	2007	2014	1	0
    USA: San Jacinto Gas	26.67%	ENI	2007	2012	2	0
    USA: Zia	35.00%	Devon	2003	2008 (1)	1	0
    USA: Seventeen Hands	25.00%	Dominion	2006	2010	1	0
    USA: Marcellus shale gas	32.50%	Chesapeake	2008	n/a	24	4
    Latin America
    Venezuela: Sincor (2)	15.00%	Sincor	2001	2008	n/a	n/a
    Venezuela: PetroCedeño (2)	9.68%	PetroCedeño	2008	2032	351	71
    Africa
    Algeria: In Salah	31.85%	Sonatrach/BP/StatoilHydro	2004	2027	30	4
    Algeria: In Amenas (3)	50.00%	Sonatrach/BP/StatoilHydro	2006	2022	16	8
    Angola: Kizomba A	13.33%	ExxonMobil	2004	2026	29	1
    Angola: Kizomba B	13.33%	ExxonMobil	2005	2027	22	1
    Angola: Xikomba	13.33%	ExxonMobil	2003	2027	4	0
    Angola: Marimba North	13.33%	ExxonMobil	2007	2027	2	0
    Angola: Mondo	13.33%	ExxonMobil	2008	2029	8	1
    Angola: Saxi-Batuque	13.33%	ExxonMobil	2008	2029	6	1
    Angola: Girassol/Jasmim	23.33%	Total	2001	2022	24	0
    Angola: Dalia	23.33%	Total	2006	2024	18	4
    Angola: Rosa	23.33%	Total	2007	2027	12	0
    Libya: Mabruk (4)	25.00%	Total	1995	2028	48	1
    Libya: Murzuq (4)	2.40%	Repsol	2003	2023	104	5
    Nigeria: Agbami	18.85%	Chevron	2008	2024	7	19
    Europe, Caspian and Russia
    Azerbaijan: ACG	8.56%	BP	1997	2024	52	2
    Azerbaijan: Shah Deniz	25.50%	BP	2006	2031	4	1
    Russia: Kharyaga	40.00%	Total	1999	2032	14	2
    UK: Alba	17.00%	Chevron	1994	2018	36	0
    UK: Caledonia	21.32%	Chevron	2003	2018	1	0
    UK: Jupiter	30.00%	ConocoPhillips	1995	2010	15	0
    UK: Schiehallion	5.88%	BP	1998	2017	21	1
    The Middle East and Asia
    China: Lufeng	75.00%	StatoilHydro	1997	2011	4
    Iran: South Pars	37.00%	POGC	2008	2012	30
    Total International E&P					944	127
    (1) Held by production
    (2) On 9 February 2008, Sincor in Venezuela was transformed into an incorporated joint venture known as Petrocedeño, S.A. and partially nationalized. Our share was reduced from 15% in Sincor to 9.68% in Petrocedeño.
    (3) Production under the terms of the In Amenas PSA commenced December 2006
    (4) Renegotiations of PSAs by the NOC in Libya have resulted in a reduced equity share. Our equity share of production in Murzuq was reduced from 8.0% to 2.4% effective as of 1 January 2008. Renegotiations are ongoing for Mabruk

    Country	Average daily equity production (1) mboe/day	Average daily entitlement production (2) mboe/day	Average daily equity production (1) mboe/day	Average daily entitlement production (2) mboe/day
    North America
    Canada	22.3		18.2
    USA	17.6	17.5	46.3
    Latin America
    Venezuela: Sincor (3)	1.0
    Africa
    Algeria	65.7	30.4
    Sub Saharan Africa
    Angola	204	117	191.3	118.6
    Libya (4)(3)	11.0	5.2
    Nigeria	7.7		38.5	35.7
    Europe, Caspian and Russia
    Azeribaijan	100	56.4
    North Africa, Europe, Caspian and Russia
    Algeria			66.7	42.0
    Libya (4)(3)			7.0	4.5
    Azerbaijan			106.3	54.6
    Russia	7.7	5.7	8.9	8.0
    UK	9.1		7.7
    The Middle East and Asia
    China	1.7	1.6	1.5	1.4
    Iran	0.8		6.2
    Subtotal International E&P production	449	275	499	343
    Equity accounted production
    Venezuela: PetroCedeño (3)	15.7
    Venezuela: PetroCedeño (4)			13.6
    Total International E&P including share of equity accounted production	465	290	512	357
    (1) In PSA countries our shares of capital expenditures and operational expenses are computed on the basis of equity production
    (1) In PSA countries our share of capital expenditures and operational expenses are computed on the basis of equity production			(1) In PSA countries our share of capital expenditures and operational expenses are computed on the basis of equity production
    (2) Production figures are after deductions for royalties, production sharing and profit sharing
    (3) On 9 February 2008, Sincor in Venezuela was transformed into an incorporated joint venture known as Petrocedeño, S.A. and partially nationalized. Our share was reduced from 15% in Sincor to 9.68% in Petrocedeño. As of the date of migration our share has been accounted for pursuant to the equity accounting method.
    (4) Renegotiations of PSAs by the NOC in Libya have resulted in a reduced equity share. Our equity share of production in Murzuq was reduced from 8.0% to 2.4% effective as of 1 January 2008. Reported volumes are after old equity share and there has been a cash settlement for the difference. Renegotiations are ongoing for Mabruk.
    (3) Renegotiation of PSA by the Libyan State oil Company (NOC) for the Mabruk field was completed in January 2010. 2009 volumes are based on old PSA terms.			(3) Renegotiation of PSA by the Libyan State oil Company (NOC) for the Mabruk field was completed in January 2010. 2009 volumes are based on old PSA terms.
    (4) Petrocedeño is accounted for pursuant to the equity accounting method.			(4) Petrocedeño is accounted for pursuant to the equity accounting method.

     

     Top 

    3.2.6 Fields3.2.5 International fields in development and production

    Major efforts are being made to make the transition from a mainly North Sea player to a world-class international operator.

    We are working continuously to develop our inventory of projects into producing assets by looking at innovative technical and commercial solutions.

    This section covers projects under development and fields in production. Pre-sanctioned projects, including some discoveries in the early evaluation phase, are also presented.

    Exploration activities are described in report section 3.2.3, Operational review-International E&P-Exploration activity. This section often refers to a field's plateau production, which refers tomeans yearly average equity production at plateau for a field where we have a 100% (not our share).ownership share. Capacities also refer to the total field or facility, a 100% share.facility.

    The number of development wells as of 31 December 2008 for producing fields is provided underExploration activities are described in report section 3.2.5 Production above.3.2.2 Operational review - International E&P - International exploration activity.

    The total number of development wells in fields under development, that were already drilled or undergoing drilling as of year end 2008 was 127.
    

    Projects	StatoilHydro's share	Operator	Time of sanctioning	Production start
    Angola: Gimboa	20%	Sonangol	2006	2009
    The USA: Tahiti	25%	Chevron	2005	2009
    The USA: Thunder Hawk	25%	Murphy	2006	2009
    Brazil: Peregrino	100%	StatoilHydro	2007	2011
    Canada: Leismer Demonstration Plant (Oil Sands phase 1)	100%	StatoilHydro	2007	2010
    Ireland: Corrib	36.50%	Shell	2001	2010/2011
    Angola: Pazflor	23.33%	Total	2007	2011
    Angola: PSVM	13.33%	BP	2008	2012

    Sanctioned projects coming on stream 2010-2012 *	Statoil's share	Operator	Time of sanctioning	Production start
    Canada: Leismer Demonstration Plant (Oil Sands phase 1)	100.0 %	Statoil	2007	2010
    Brazil: Peregrino	100.0 %	Statoil	2007	2011
    Angola: Pazflor	23.33%	Total	2007	2011
    Angola: PSVM	13.33%	BP	2008	2011
    The USA: Ceasar Tonga phase 1	23.55%	Anadarko	2009	2011
    Angola: Kizomba satellites phase 1	13.33%	Exxon	2009	2012
    * Not exhaustive

     

     Top 

    3.2.6.13.2.5.1 North America

    Statoil's E&P activities in North America comprise interests in the US Gulf of Mexico, shale gas in the Appalachian region of north-eastern USA, off the eastern coast of Canada and oil sands in the Alberta province in onshore Canada.

    We also have a representative office in Mexico City.

     Top 

    3.2.6.1.13.2.5.1.1 Canada

    In Canada, oil

    Oil sands represent a long termlong-term investment for the company and our Leismer Demonstration Project is on schedule. Offshore, we have production from Hibernia and Terra Nova, and two discoveries are under appraisal.

    

    development projects.

    Oil Sandssands
    

    

    In 2007, we acquired 100% of the shares in North American Oil Sands Corporation (NAOSC). At and operatorship of the time of acquisition, NAOSC owned Kai Kos Dehseh (KKD) leases. We currently own interests in 275,2131129 square kilometres (279,053 net acresacres) of oil sandssands' leases located in the Athabasca region of Alberta. In its raw state, bitumen is a heavy viscous oil that we will produce using the steam assistedsteam-assisted gravity drainage method (SAGD) from a depth of approximately 430 metres, with an average producing zone thickness ranging from 15 to 30 metres.

    StatoilHydro isOil sands represent a long-term investment, and Statoil has the operator of the Kai Kos Dehseh oil sands leases, and theflexibility required to develop it in stages. The first phase of the development is the Leismer SAGD Demonstration Project, which will be developed withhave a capacity of approximately 20,000 boebarrels of oil per day with initial production scheduled for late 2010. In 2007 we submitted an application

    Construction and commissioning of the Leismer Demonstration Project is on schedule, with approximately 75% completion progress at the end of December 2009. All the production wells have been drilled and completion of the wells is ongoing. The installation of the bitumen and diluent pipelines from the Leismer Demonstration Project to Cheecham is on schedule. Work on the Cheecham terminal is also proceeding according to plan. On completion, the Leismer Demonstration Project will be connected to the Alberta regulatory authorities for the full 220,000 boe per day commercial SAGD project.

    In 2007 we also submitted an applicationexisting pipeline infrastructure at Cheecham that runs to the Alberta regulatory authorities forEdmonton area.

    Statoil will use the constructionLeismer Demonstration Project as a learning platform, where we will test a number of technologies or processes aimed at improving efficiency and extraction and improving our environmental footprint. The Statoil Heavy Oil Research Centre in Calgary is an integral part of this effort.

    upgraderOffshore
    Statoil has interests in two crude oil producing fields: Hibernia (Statoil share 5%) and Terra Nova (15%), and in the two development projects; Hebron (9.7%) and Hibernia Southern Extension Unit (10.5%)
    
    Fields in production
    Hibernia, to process bitumen into lighter synthetic crude. We withdrew this application in December 2008. Prohibitive construction costs, the state of the global economy, an uncertain oil price outlook and lack of legislative clarity are the main reasons for this decision. Oil sands are a long term investment for the companywhich was developed with a high degree of optionalitygravity base structure (GBS), is operated by Hibernia Management and Development Company Ltd (HMDC). The Hibernia field is in the timinginitial stages of investments.decline, with 2009 production rates averaging 125,000 barrels of oil per day.

    OffshoreTerra Nova produces from a floating production, storage and offloading vessel (FPSO) and is operated by Suncor. The Terra Nova field is also in decline, with 2009 production rates averaging 80,000 barrels of oil per day.

    Discoveries Under AppraisalDevelopment projects
    The Hebron field, was discovered in 1981. Operatorship was transferred from Chevron tooperated by ExxonMobil, in 2008. A fiscal agreement was signed in August 2008 with the Government of Newfoundland and Labrador, which entails that the provincial government purchases a 4.9% equity share of the project. This reduces StatoilHydro's share in the project to 9.7% effective as of signing. The field is planned towill be developed with a gravity based structure.structure (GBS). To date, the pre-engineering project studies have been completed.

    The Hibernia Southern Extension Unit project, operated by ExxonMobil, comprises the development of resources in several fault blocks to the south of the existing Hibernia Main Field. Fiscal negotiations with the provincial government began in 2008 and are still ongoing..field. The field is planned for development as a satellite to be developed via drilling from the Hibernia GBS platform. We have 10%field. The Hibernia South Extension Unit is located across three license areas, where Statoil holds working interests of 22.5% in PL1005, 4.5% in EL1093 and 4.5% of the unit portion of PL1001. Statoil's unitised interest in this field.

    
    Hibernia was developed with a GBS and is operated by ExxonMobil. Production started in 1997 and the field is currently producing from 55 wells.10.5%.

    Terra Nova is producing from a floating production, storage and offloading vessel (FPSO), operated by Petro-Canada. Fifteen subsea producing wells are tied back to the FPSO. Terra Nova's production efficiency continues to be low due to a number of technical issues on the FPSO. Several initiatives are underway to improve production efficiency.

     Top 

    3.2.6.1.2 The 3.2.5.1.2 USA

    We

    With the projects Tahiti and Thunder Hawk on stream, and CaesarTonga sanctioned, we have built a high quality deep water asset portfoliotaken our assets in the Gulf of Mexico by combining acquisitions and exploration. In 2008to a new level. Onshore we expanded into onshore gas through a 32.5% interest in Chesapeake Energy Corporation'scontinue to ramp up production from our Marcellus shale gas acreage.

    asset.

    Onshore

    We also formed a strategic alliance with Chesapeake to jointly explore unconventional gas opportunities worldwide.

    

    The Marcellus Shale Gas play is located in the Appalachian region of the northeasternnorth-eastern USA. In November 2008, we acquiredentered into a Strategic Alliance with Chesapeake Energy, acquiring 32.5% interestof Chesapeake's 1.8 million acres in Chesapeake'sthe Marcellus. The Marcellus shaleprovides Statoil with a long-life gas acreage. Productionasset with considerable optionality. The asset is part of our gas value chain strategy, whereby we are building a North American gas marketing hub integrated with our Cove Point LNG import terminal and our offshore gas production in the Gulf of Mexico. Marcellus production started in 2008 and drilling of new wellsStatoil's daily equity production reached around 3,000 boe per day at year end 2009. Statoil and Chesapeake will continue in 2009. We also haveto acquire and high-grade acreage around the right to a 32.5% participation in additional Chesapeake leases inmost prospective areas of the Marcellus Shale play.play and will gradually build up production.

    

    Discoveries under appraisal,

    Offshore, Gulf of Mexico

    Fields in production
    The Jack oil fieldProduction started in May 2009 from the Chevron-operated Tahiti oilfield in which we have a 25% interestinterest. The field is located at Walker Ridge 758/759. Jack is operated by Chevronin Green Canyon Block 640 and was discoveredconsists of six wells in 2004. In 2008 we drilled another appraisal well.

    St. Malo, located at Walker Ridge 678, is also an oil field operated by Chevron. We have 6.25% interest in St. Malo. In 2008 we drilled another appraisal well. St. Malo and Jack are in approximately 2,100 metrestwo subsea drill centres connected to a Spar floating facility with a production capacity of water and separated by approximately 40 kilometres.125,000 bbl per day. The current plan is a joint developmentsecond phase of the two fieldsTahiti development is in the appraisal and Chevron has formed a joint integrated project team for this purpose. initiation phase. Tahiti 2 will add as many as six producing and four water injection wells to the existing architecture, and the Spar facility is being upgraded to handle 155,000 bbl per day.

    

    In July 2009, we plan to make a concept selection forproduction started from the development of the two fields and to start front-end engineering and design.

    We have a 27.5% interest in Big FootThunder Hawk which is a Chevron-operated discoveryoilfield located in WR29. During 2008 appraisal drilling took place and will continue into 2009. We expect to make a concept selection in 2009.

    The Caesar unit in which we have a 23.55% interest is operated by Anadarko and covers blocks GC683 and some surrounding blocks, including the Tonga discovery. A joint development is planned for Caesar and Tonga and the selected concept is a 4-well subsea tieback to the Anadarko-operated Constitution platform. During 2008 an appraisal well was drilled.

    Fields under development
    Mississippi Canyon Block 734. We have a 25% interest in the Chevron operated Tahiti field, located at Green Canyon 640. The TahitiMurphy Oil-operated development consistsconsisting of a Sparsemi-submersible floating production platform connected to two subsea drill centres with production capacity of 125,000 bbl per day. Production on Tahiti is expected to start mid 2009.

    In Thunder Hawk we have a 25% interest and Murphy is the operator. It isfacility located atin Mississippi Canyon 734. The field is being developed with a floating semi-submersible platform tied in to a third party processing facility in Mississippi CanyonBlock 736. The processing capacity is expected to beapproximately 45,000 bbl of oil per day.

    Fields in production
    Our threeEastern Gulf deepwater natural gas fields - Q, San Jacinto and Spiderman - are tied back topart of the Anadarko-operated Independence Hub. The three fields are the StatoilHydro operated Q field in addition to partner operatedis Statoil-operated while San Jacinto and Spiderman.Spiderman are partner-operated. The fields are producingproduce via subsea tiebackstie-backs to the Independence Hub platform, a floating production facility onlocated in Mississippi Canyon Block 920. The Independence Hub is owned by third parties and has a processing capacity of one billion cubic feet of natural gas per day.day (178 000 boe per day) . We ownhave contractual rights to 12.7% of the capacity of the hub. In the spring of 2008, the Independence Hub experienced an unexpected shut-down for two months due tothat capacity.

    We have a leak30% interest in the export pipeline. The leak was successfully repaired during the summer of 2008. Production was also shut down during Hurricanes Gustav and Ike, but no significant damage was done to the facility or the pipelines.

    Noble Energy-operated Lorien, oilfield, located atin Green Canyon 199,199. Lorien produces through a two-well subsea tie-back to Shell's Bullwinkle platform. Following Hurricanes Gustav and Ike, Lorien was shut-down due to damage to Bullwinkle. Production resumed in January 2009.

    The Murphy-operated Front Runner fieldoilfield is located in Green Canyon 338/339. Production339/382. We have a 25% interest in 2008 has been relatively stable. However, due to complex geology with relatively weak reservoir communication, the production from Front Runner, has been significantly lower than expected atwhich started production start in 2004. The gas-export line was damaged by Hurricane Ike. Gas export resumed in January 2009.

    We also had production from Ziain 2008 from two2009. It is a small deepwater fields called Ziaoil field located in Mississippi Canyon Block 496 and Seventeen Hands. They areHands, a small gas field located atin Mississippi Canyon 496Block 299. Both fields tie back to platforms owned by others.

    Fields under development
    Statoil has a 23.55% working interest in the Anadarko Petroleum-operated Caesar Tonga Unit in Green Canyon Block 683. Development of the four block unit was sanctioned in 2009 as a four-well subsea tie-back to the Anadarko's Constitution platform. The field is expected to start oil production in 2011.

    Discoveries under appraisal
    The Jack oilfield, which is located in Walker Ridge Block 758/759 and 299, respectively.in which we have a 25% interest, was discovered in 2004.

    St. Malo is an oilfield located in Walker Ridge Block 678. In January 2010, we increased our interest in St. Malo from 6.25% to 21.5% by exercising our pre-emption rights. St. Malo and Jack are in approximately 2000 metres of water, approximately 40 kilometres apart. Both fields are operated by Chevron and are currently planned to be developed jointly. In 2009, the concept for the development was selected and front-end engineering and design started. The development concept consists of separate subsea wells tied to a shared centrally located surface facility. The Jack and St Malo development is expected to be sanctioned in late 2010.

    We have a 27.5% interest in Big Foot, a Chevron-operated oil discovery located in Walker Ridge Block 29. In 2009, a dry tree tension leg platform with a drilling rig was selected as the development concept. Project sanctioning is expected in 2010.

     Top 

    3.2.6.23.2.5.2 Latin America

    Our current asset portfolio in Latin America comprises our interest in the Peregrino offshore heavy oil Peregrino development project in Brazil and anthe onshore extra heavy oil producing asset, the Petrocedeño, Mixed Company, in Venezuela.

    The Petrocedeño Mixed Company was formerly known as the Sincor project.
    We also have a representative office in Mexico City.

     Top 

    3.2.6.2.13.2.5.2.1 Brazil

    Statoil is operator for, and owns 100% of the Peregrino oil field off the coast of Brazil. By 2012, we are expected to become the largest international offshore operator in Brazil in terms of production.

    

    The Peregrino field is a heavy oil field located in approximately 120 metres of water in the prolific Campos Basin off the coast of Brazil, about 85 kilometres off the coast of Rio de Janeiro.

    The field is being developed with a Floating Production Storage and Offloading Vessel (FPSO) and two wellhead platforms with drilling capability. The first oil production is planned to come on stream in early 2011 and we expect to reach plateau production within the first year of production. Design capacity is 100,000 boe per day. All development contracts have been signed, and the execution phase of the project and installation of field facilities are now in progress.

     Top 

    3.2.5.2.2 Venezuela

    StatoilHydro has a long term view on its presence in Venezuela and

    Statoil has a 9.677% interest in the Petrocedeño, project.

    one of the largest extra heavy crude projects in Venezuela. 

    The Petrocedeño project involves the exploitation of extra heavy crude oil from the reservoirs in the Orinoco Belt. A diluting component is added in order forto enable the extra heavy oil to be transported by pipeline to the coast, where it is upgraded to a light, low-sulphur syncrude destined for the international market. Petrocedeño, S.A., owned by the project partners, operates the field and is responsible formarkets the development, operation, upgrading and marketing of its products.

    In 2008Petrocedeño experienced operational problems throughout 2009,and was not able to produce up to design capacity. A preventive maintenance shutdown took place at the Sincor project was transformed into an incorporated joint venture named Petrocedeño, S.A., which became operational starting from 9 February 2008. Our share was reduced from 15% in Sincor to 9.677% in Petrocedeño.

    A major maintenance turnaround was carried out in early part of 2008. The maintenance tasks were performed as planned, although someend of the important modification projectsyear and activities were postponedinitiated to 2009. Duringrestore the turnaround,plant to normal operation.

    We have been present in Venezuela since 1994, and we have a much higher volume of extra heavy oil was produced than originally planned and marketed as diluted crude oil.

     Top 

    3.2.6.2.2 Brazil

    In 2008, we acquired Anadarko's remaining 50% share of the Peregrino oil field and became 100% owner and operator. By 2012 StatoilHydro is expected to become the largest international offshore operator in Brazil in terms of production.

    The Peregrino field is a heavy oil field located in approximately 120 metres of waterlong-term perspective on our activities in the prolific Campos Basin offshore Brazil, about 85 kilometres off the coast of Rio de Janeiro.country.

     

    The field is being developed with a Floating Production Storage and Offloading Vessel (FPSO) and two well head platforms with drilling capability. The first oil production is planned to come on stream in 2011 and we expect to reach a plateau production of 100 mboe per day within the first year of production. All development contracts have been entered into and the execution phase of the project is in progress.

     Top 

    3.2.5.3 Sub Saharan Africa3.2.6.3 Africa

    We have interests in onshore producing assets in the North African countries of Algeria and Libya.

    Our current development and production portfolio in Sub Saharansub-Saharan Africa comprises blocks 4/05, 15, 17 and 31 offshoreoff the coast of Angola, and the OML 127 and OML 128 production licences off the coast of Nigeria.

     Top 

    3.2.5.3.1 Angola

    The Angolan continental shelf is the largest contributor to Statoil's production outside Norway. It yielded 191 mboe per day in equity production at the end of 2009, 37% of our total international oil and gas output.

    

    Angola is a key building block in our international strategy and our ambition is to become an operator in the country.

    Block 17 is operated by Total, and our interest is 23.33%. Production from the block currently comprises four development areas produced over two FPSOs. The Girassol, Jasmim and Rosa development areas are produced over the Girassol FPSO and the Dalia development area over the Dalia FPSO.

    

    Girassol and Jasmim went off plateau production in October 2008. The combined production from Girassol, Jasmim and Rosa was in the order of 215 mboe per day in 2009. Dalia FPSO produced at a peak level of 240 mboe per day in 2009.

    The Pazflor project, which comprises the discoveries Perpetua, Acacia, Zinia and Hortensia, will be produced over a new FPSO with expected production capacity of 200 mboe per day and start-up scheduled for the end of 2011. Once Pazflor starts production, Block 17 is expected to reach a production level of around 650 mboe per day.

    The CLOV project, the fourth FPSO development in Block 17, consists of the discoveries Cravo, Lirio, Orchidea and Violeta. Basic engineering started in 2008. Engineering, procurement and construction contracts are under evaluation, and sanction of the project is anticipated in 2010.

    Increased Oil Recovery (IOR) projects to fill ullage capacity on the Girassol FPSO and to increase oil recovery from Block 17 are under evaluation. The IOR projects include subsea tie-backs, development of infill wells and the use of new technology.

    Pursuant to the Production Sharing Agreement (PSA), all surplus gas from from Block 17 is to be delivered to Sonangol, which owns the gas. Block 17 is progressing on a Gas Export Project that is split into two phases. Phase I, sanctioned in 2007, is an export line from Block 17 to Block 2, where the gas can be injected through a wellhead platform if Angola LNG Terminal (AnLNG) is unavailable. Phase II, sanctioned in 2008, includes a 24-inch diameter pipeline from Block 2 to AnLNG. Costs related to the Gas Export Project will be recovered through the PSA.

    Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil. Our interest is 13.33%. Total production from Block 15 exceeded 600 mboe per day in 2009. Production from the block currently comes from five FPSOs; Kizomba A, Kizomba B, Xikomba, Kizomba C-Mondo and Kizomba C-Saxi Batuque. In addition, one satellite, Marimba, is producing through a tie-back to the Kizomba A FPSO. Xikomba, which is a small, isolated field, is expected to be shut down in October 2010.

    Kizomba satellites phase 1, consisting of two medium-sized discoveries - Clochas and Mavacola - was sanctioned by the partnership in 2009. Sonangol has approved all major contracts, and detailed engineering is ongoing. It is scheduled to come on stream in 2012.

    The Mondo 4 appraisal well drilled in 2009 proved a separate structure of limited size in the Mondo development area. Feasibility studies are ongoing, both for the Mondo 4 discovery and for the other remaining, undeveloped discoveries in the block.

    Pursuant to the PSA, all surplus gas from the offshore blocks is to be delivered to Sonangol, which owns the gas. The Gas Gathering Project for Block 15 is under development. It will collect gas from Kizomba A, B and C and the satellites. A dedicated trunk line will deliver the gas to AnLNG.

    Block 31, an ultra-deepwater licence, is operated by BP, and our interest is 13.33%. The common development of the first four discoveries in the northern part of the block - Plutao, Saturno, Venus and Marte (PSVM) - was approved by the concessionaire in July 2008. PSVM will be developed via a new FPSO with a production capacity of 150,000 boe per day. Production start-up is expected in late 2011.

    Work is also ongoing to pursue the development of SE-PAJD (Hub 2), comprising the Palas, Astraea, Juno and Dione discoveries.

    One to two additional production hubs are expected to be launched in this block.

    Block 4/05 is operated by Sonangol P&P, and our interest is 20%. This block includes the Gimboa field, which was sanctioned in 2006. The average production has been 21 mboe per day since the FPSO commenced test production in April 2009. Work is also ongoing to pursue the development of Gimboa Phase 2, with two small-sized discoveries, UMC-6 and UMC-7.

    Block 15/06 is operated by Eni. Our interest is 5%. Several discoveries have been made. Work is ongoing to assess a development solution for the discoveries located in the northwestern part of the block.

     Top 

    3.2.5.3.2 Nigeria

    In Nigeria, we have an interest in the largest deepwater producing field, Agbami.

    The Agbami field in deep waters off Nigeria has been developed with subsea wells connected to an FPSO. Production started in 2008. Agbami, which is operated by Chevron, is located in licences OML 127 and OML 128, offshore Nigeria.approximately 110 kilometres off the Nigerian coast. Our interest in the unitised field is 18.85%. The Agbami field reached a plateau production rate of 250 mboe per day in August 2009, four months ahead of schedule.

    There is renewed vigour on the part of the Nigerian government to restructure the oil and gas sector by introducing an omnibus bill called the Petroleum Industry Bill (PIB) to replace 16 petroleum related laws that will be repealed. So far, it is not possible to determine the impact of potential restructuring and changes in the regulatory and fiscal framework.

    The security and political situation is largely unchanged, with various groups causing continued uncertainty. The overall situation is monitored continuously and appropriate security measures are being assessed for our personnel and assets.

     Top 

    3.2.5.4 North Africa, Europe, Russia and Caspian

    Statoil has built a unique position as supplier to the European gas market. In addition to our heritage position on the Norwegian continental shelf, we have upstream assets supplying the market from both the south (Algeria), and south-east (Azerbaijan).

    The Shtokman field is a long-term resource that can enhance our upstream gas position while making us a supplier from the north-east.

    We have interests in production and development assets in Algeria, Libya, Ireland, the United Kingdom, Azerbaijan and Russia, in addition to early-phase evaluation assets in the United Kingdom and Algeria.

    We also have representative offices in Kazakhstan and Turkmenistan.

    

     Top 

    3.2.6.3.13.2.5.4.1 Algeria

    Our main asset,assets, In Salah gives us a considerable gas position in Algeria. We are also producing liquids from theand In Amenas, field.

    are the third and fourth largest gas developments in Algeria.

    Fields in production
    The In Salah onshore gas development, in which we have a 31.85% interest, is Algeria's third largest gas development. The field is currently producing at plateau level. level of around 130 mboe per day.Carbon capture is an important environmental commitment. The carbon capture and reinjection at In Salah is verified through a separate Joint Industry Project (between Statoil, BP and Sonatrach). The project aims to reaffirm the sustainability and reliability of carbon dioxide reinjection as a preferred solution for the reduction of carbon emissions. So far, more than three million tonnes of carbon dioxide have been captured and stored.

    A Contract of Association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and StatoilHydro.Statoil. A joint marketing company sells the gas produced in the development, and all gas that will be produced up until 2017 has been sold under long-term contracts.

    In addition to the operating activities at In Salah, drilling operations and a compression expansion project have been ongoing in 2008. The activities in 2009 will include startup of some of the compression stations and further work on preparing for the In Salah Southern Fields development. StatoilHydro is in charge of the compression project.

    The In Amenas onshore development is the fourth largest gas development in Algeria, containing significant liquid volumes. Production efficiency is high, but export capacity through the Sonatrach pipelines is limited.

    The development wasfacilities are built and isare operated through a joint operatorship between Sonatrach, BP and StatoilHydro,Statoil, and we have a 50% share of the development costs. ThisProduction from this project ishas currently producing atreached its plateau level. The rights and obligations are governed by a production sharing contract givingthat gives BP and StatoilHydroStatoil access to a share of the liquid volumes only. A continuous production drilling campaign is ongoing. Further preparations and maturing of the In Amenas Compression Expansion project is ongoing and will continue in 2009 with BP as lead.

    The overall security situation in the northern part of Algeria is still regarded as unstable and political situation continues to be sensitive and isbeing monitored continuously. Appropriate measures are assessed based on the basis of the perceived risk level.

    Fields in development
    The In Salah Gas Compression Project: start-up of two of the three gas compression plants is expected during 2010. The third plant is expected to start up in early 2011. Work is ongoing on the In Salah Southern Field Development Project to mature the remaining four discoveries into production.

    The In Amenas Gas Compression Project is led by BP and expected to be sanctioned in late 2010. The compressors are expected to come on stream in 2013. This risk monitoring will continue through 2009.make it possible to reduce wellhead pressure and thus increase production.

    In March 2009, the last of the 10 Hassi Mouina exploration/appraisal wells was completed and the drilling rig demobilised. A total of 2500 km of 2D seismic has been collected. At present, Statoil is working on assessing the technical solutions for and commercial attractiveness of a potential development.

     Top 

    3.2.6.3.23.2.5.4.2 Libya

    We are well positioned for growth in Libya, with two producing assets and oura focus on technology-based IOR projects.

    Fields in production
    The Mabruk oil fieldoilfield is located in licence C-17, north-west in the Sirte basinbasin. The Dahra south-east project was sanctioned in early 2009, and is developed in phases.

    A Field Development Plan (FDP) for Mabruk Phase I (previously denoted phase V), covering the Dahra South East is expecteddrilling and construction are progressing according to be approved by the Libyan National Oil Corporation (NOC) in 2009.plan.

    The NC 186 licence in the Murzuk area consists of severalseven fields. We are currently producing from the A,six fields (A, B, D, H, I and H fields which were developed withJ) through one common processing facility. The oil from thesethe Murzuk fields is blended with oil from the neighbouring licence NC 115 and is then transported by pipeline to the Az Zawia terminal west of Tripoli.

    Tripoli for lifting by ship. The I/R oilremaining field with an approved field development plan is K field, which straddles across both the NC 115 and NC 186 licenses, started production in June 2008.

    A FDP for the J and K fields was approved by both the partnership and NOC. The fields areis expected to start production in 2010.

    To avoid extensive The gas utilisation project aimed at stopping continuous flaring from the NC 186 fields, a gas utilization project is ongoing, with the aim of using the associated gas from the oil production for electricity generation. Start-up of the project is expected in 2009, when planned flaring in the 186 area will be eliminated.

     Top 

    3.2.6.3.3 Angola

    The Angolan continental shelf is the largest contributor to StatoilHydro's production outside Norway. It yielded 117 mboe per day in entitlement production at the end of 2008, 40% of our total international oil and gas output.

    FPSO vessels with subsea wellheads are the preferred oil-field development solution in deepwater Angola due to the great water depths, high production volumes and lack of infrastructure.

    

    Block 17 is operated by Total and our interest is 23.33%. Production from the block currently comprises the Girassol, Jasmim, Dalia and Rosa development areas. The Girassol and Jasmim development areas both produce over the Girassol FPSO. The plateau production level, reached in 2005, was 250 mboe per day. The second FPSO, Dalia, has been producing at peak level of 240 mboe per day in 2008. Rosa is a tie-back field to the Girassol FPSO. The combined production on the Girassol FPSO has a capacity limit of 280 mboe per day.

    The Pazflor project comprises the discoveries Perpetua, Acacia, Zinia and Hortensia. Pazflor was sanctioned in 2007. The FPSO is expected to have a production capacity of 200 mboe per day, with start-up scheduledstart up in 2011.2010.

    The installed production capacity on block 17 will be approximately 700 mboe per day, after Pazflor starts production.

    Work is ongoing to pursue the common development of four additional discoveries, Cravo, Lirio, Orchidea and Violeta (CLOV).

    The Gas Export Project (GEP)
    According to the PSA, all surplus gas from the offshore blocks is to be delivered to Sonangol who owns the gas. Block 17 is progressing on a Gas Export Project which is split into two phases. Phase I, which was sanctioned in 2007, comprises an export line from Block 17 to Block 2 where the gas can be injected through a wellhead platform if Angola LNG (AnLNG) for some reason is unavailable. Phase II includes a 24-inch diameter pipeline from Block 2 to AnLNG, and was sanctioned in July 2008. Costs related to the development will be recovered through the PSAs.

    Block 15 is operated by ExxonMobil and our interest is 13.33%. Production from the block currently comprises five FPSOs for Kizomba A, Kizomba B, Xikomba, Kizomba C-Mondo and Kizomba C-Saxi Batuque. Mondo and Saxi-Batuque came on stream on 1 January and 1 July 2008 respectively.

    Kizomba A, which encompasses the Hungo and Chocalho discoveries, commenced production in 2004. Marimba North is a tie-back to the Kizomba A FPSO. The peak production limit on the FPSO was then increased to 270 mboe per day, of which Marimba North produces 35 mboe per day. Kizomba B encompasses the Kissanje and Dikanza discoveries. Kizomba A and Kizomba B came off plateau during 2008. Xikomba is a small, isolated discovery producing from a leased FPSO. The combined Kizomba C production has already reached plateau levels of 200 mboe per day in 2008.

    According to the PSA, all surplus gas from the offshore blocks is to be delivered to Sonangol. The Gas Gathering Project for Block 15 will collect all surplus gas from Kizomba A, B and C including satellites. The trunkline will connect to AnLNG piping going to AnLNG.

    Work is also ongoing to pursue the development of two medium-sized discoveries: Clochas and Mavacola, which are called Kizomba Satellites Phase 1.

    Block 31, an ultra-deep water licence, is operated by BP, and our interest is 13.33%. The common development of the first four discoveries in the northern part of the block, Plutao, Saturno, Venus and Marte (PSVM) was approved by the Concessionaire in July 2008. The PSVM will be developed via a new FPSO with a production capacity of 150,000 boe per day.

    Work is also ongoing to pursue the development of PAJ, comprising the discoveries Palas, Astraea, and Juno.

    Two to four additional production hubs are expected to be launched in this block.

    Block 4/05 is operated by Sonangol P&P and our interest is 20%. This block includes the Gimboa field which was sanctioned in 2006. Peak production from the field is expected to be 35 mboe per day and the FPSO is expected to commence production in first half of 2009.

    Work is also ongoing to pursue the development of Gimboa Phase 2, two small-sized discoveries, UMC-6 and UMC-7.

     Top 

    3.2.6.3.4Nigeria

    In Nigeria, we have an interest in the largest deepwater producing field, Agbami.

    The Agbami field in deep waters off Nigeria has been developed with subsea wells connected to an FPSO. Production started up on 29 July 2008. Agbami, operated by Chevron, is located in licences OML 127 and OML 128, approximately 110 kilometres off the Nigerian coastline. Our interest in the unitised field is 18.85%. The Agbami field is expected to reach a plateau production of 250 mboe per day by late 2009.

    

    There is renewed vigor by the Nigerian government to restructure the oil and gas sector. StatoilHydro is following the developments in the country. So far it is not possible to determine the impact of a potential regulation restructure.

    With the Supreme Court judgement on the validity of the 2007 presidential election still being awaited, the political situation remains unstable, but there has been an improvement in the security situation in the strategically important oil region in the Niger Delta. The overall security and political situation is monitored continuously. We have developed rigorous security measures to protect our personnel and other assets. Appropriate measures are continuously being assessed based on the perceived risk level.

     Top 

    3.2.6.4 Europe, Caspian and Russia3.2.5.4.3 United Kingdom

    We have interests in production and development assets in Ireland, the United Kingdom, Azerbaijan and Russia in addition to early phase evaluation assets in the United Kingdom and Denmark.

    The Russian Shtokman field is an important part of our strategy to pursue opportunities in harsh arctic environments. Our ambition is to continue to build on our portfolio whilst pursuing opportunities to improve on the production and cost performance of our current producing assets, and bring existing discoveries through to development.

    We also have representative offices in Kazakhstan and Turkmenistan.

    

     Top 

    3.2.6.4.1 United Kingdom

    StatoilHydro has been presentseveral oilfields under appraisal in the United Kingdom (UK) since the early 1980s. Weand hold interests in fourthree producing fields.

    Fields in production
    The Alba oilfield, located in the central part of the UK North Sea, is operated by Chevron. We have a 17% interest in this field.

    Schiehallion oilfield is located west of the Shetland Islands. The operator is BP and we have a 5.88% interest.

    Jupiter is a gas field located in the southern part of the UK North Sea. We have a 30% interest and the operator is ConocoPhillips.

    All these fields Alba, Schiehallion, Jupiter and Caledonia and have several oil fields under appraisal, Bressay, Mariner, Mariner East and Rosebank.are in the mature to late-life stage of production.

    Discoveries under appraisal
    We are operator for Bressay (in which we have a 81.63% interest), Mariner (in which we have a 44.44% interest) and Mariner East (in which we have a 62% interest). TheseThey are all heavy oil discoveries where furtherfor which studies and appraisal will continue. Current development plans for both fields consist of a fixed steel jacket with drilling, processing and quartering facilities.

    Rosebank, (in which we have a 30% interest), a discovery made by Chevron in 2004, is located west of the Shetland Islands. We have a 30% interest in this field. The operator has recently completed appraisal drilling and is currently drilling further appraisal wells.moving towards concept selection.

    Fields in production
    The Alba field commissioned in 1994 is located in the central part on the UK North Sea and operated by Chevron. We have 17% interest in Alba.

    Schiehallion, commissioned in 1998, is a floating, production, storage and offloader (FPSO) located west of the Shetland Island, and the operator is BP. We have 5.88% interest.

    Jupiter is a gas field located in the southern part of the UK North Sea in which we have 30% interest. The operator is ConocoPhillips.

    Caledonia is a small single well tie-back to the Britannia platform in the central part of the North Sea in which we have 21.32% interest, and where the operator is Chevron.

    All fields are in a mature to late life stage of production.

     Top 

    3.2.6.4.23.2.5.4.4 Ireland

    We have a 36.5% interest in the Corrib gas field, which lies on the Atlantic Margin north-west of Ireland. The Shell-operated Corrib field development operated by Shell, was sanctioned in 2001, and production start-upwork towards first gas is currently expected at the end of 2010 or early 2011.

    progressing.

    The development will comprise seven subsea wells, and the gas will be transported through a pipeline to an onshore gas processing terminal. The gas will be exported from the terminal via the Bord Gais Eireann linklinelink line to the existing Irish gas grid.

    The Irish planning authorities granted planning permission for the gas terminal in 2004. Project execution was suspended in 2005 due to protests by local landowners. FollowingWork on the project recommenced in 2006 following a comprehensive safety review ofon the onshore pipeline by the Irish authorities, work on the project recommenced in 2006. Asauthorities. Alternative pipeline routes were identified as part of a community consultation process and a revised route was submitted to the Irish planning authority (ABP) during first quarter 2009. ABP responded to the application in November 2009 with a number of questions and a proposed alternative pipeline routes have been identified, androute which is predominantly located within the final planning application for the onshore pipelineSruwaddacon estuary rather than on land. The project is expected to be made in the second halfprocess of 2009. Currently, sixreviewing the proposal and will respond to ABP within May 2010. Six of the seven offshore wells have been drilled. Construction of the onshore gas terminal commenced in 2007is expected to be completed during 2010. First gas for the project will be dependent upon construction methodology adopted for the revised ons hore pipeline route and is ongoing.receipt of the necessary approvals from the Irish Authorities..

     Top 

    3.2.6.4.3 Denmark

    In the Danish sector of the North Sea we are a partner in the Hejre field, an undeveloped oil field.

    Discoveries under appraisal
    3.2.5.4.5 Azerbaijan

    We have a 25% interest in the Hejre oil field, operated by Dong, in licence 5/98 located in the Danish sector of the North Sea. The partnership is in the concept evaluation phase.

     Top 

    3.2.3.4.4 Azerbaijan

    StatoilHydro has been present in Azerbaijan since 1992. Since then, we have entered into three PSAs in Azerbaijan,1992, and we are amongnow the second largest foreign oil companiescompany 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 (ACG) oil field,oilfield, the Shah Deniz gas and condensate field and the Alov, Araz and Sharg prospects described in the report section 3.2.3.4.2 Operational review-International E&P-Exploration activity-Europe, The Caspian Region and Russia-Azerbaijan.prospects.

    

    We have an 8.5633% interest in the BP-operated ACG PSA. ProductionCrude oil production from the field commenced in 1997. The field has subsequently been developed through the ACG Phase I-III developments which were brought on streamfinalised in the period 2005 to 2008. Additional production through the ChiraqChirag Oil Project was sanctioned in March 2010 and is expected to commencestart production in 2013.

    A gas leak originating underground was detected on the seafloor beneath the Central Azeri The project will comprise one new platform in the third quarterwith capacity to produce 185 000 barrels of 2008 and production from the platform was temporarily shut down. Although limited production from Central Azeri was resumed in December 2008, the gas leak is expected to have a negative effect on theoil per day. Today, crude production from ACG throughout 2009.

    Exportexceeds 800,000 barrels of hydrocarbons. Currently,oil per day.
    
    The crude oil from ACG is transported to the Mediterranean Sea through the 1760 kilometres1760-kilometre Baku-Tbilisi-Ceyhan (BTC) Pipeline, in which we participate with an 8.71% interest. In August 2008,
    
    Statoil has a fire occurred at a pipeline bolt. However,25.5% interest in the impact on production from ACG was limited and the pipeline was brought back in operation three weeks after the incident. In the fourth quarter of 2008, the BTC Pipeline had an export capacity of more than 900 mbbl of oil per day.

    The Shah Deniz area covers 860 square kilometres and lies at a water depth of between 50 and 500 metres. PSA, where BP is the field operatoroperator. The production of gas from Stage one started at the beginning of 2007 and we have a 25.5% interest.exceeded six billion cubic metres in 2009. We are the operator of the AGSC company coveringthat manages gas sales, contract administration and business development for the Shah Deniz stage I.one gas. We are also the commercial operator of the South Caucasus Pipeline system (SCP) for gas transport from Shah Deniz to markets in Azerbaijan, Georgia and Turkey.

    

    The partnership is working with the ambition to start production of Shah Deniz Stage I commenced productiontwo in December 2006.2016, with a capacity of around 16 billion cubic metres of natural gas per year. The Stage 2 development of Shah Denizproject is progressing through the investment decision process and is presently in the concept selection stage. Field reserves support a significant Stage 2 development which is likelyphase, and commercial negotiations are ongoing to be on a similar or larger scalesecure sales contracts and transportation rights to Stage 1.the markets.

    The Caspian region has long been viewed as an area with a substantial risk of increased economic, social and political instability. Although the general situation has improved, there are still political disputes that remain unsolved in both Azerbaijan and Georgia, and the recent events in Georgia show that the risks should not be underestimated.Georgia.

     Top 

    3.2.6.4.53.2.5.4.6 Russia

    StatoilHydro

    Statoil has been present in Russia since the early 1990s.late 1980s. We have one producing field, the Kharyaga oil field, and a 24% ownership shareinterest in Shtokman Development AG, which is responsible for the Shtokman development phase I.one, and a 30% ownership interest in one producing field, the Kharyaga oilfield.

    Field under planning

    
    The Shtokman gas and condensate field is located in the Russian Barents Sea, and the Shtokman agreement with Gazprom gives StatoilHydroStatoil a 24% equity interest in Shtokman Development AG in which Gazprom (51%) and Total (25%) are the other two partners. The owners have seconded personnel to Shtokman Development AG (SDAG), which is responsible for planning, financing, constructing and operating the infrastructure that is necessary for the first phase of the development. Shtokman Development AGSDAG will own and operate the infrastructure for 25 years from the start of commercial production. The implementationSDAG is currently maturing the technical concept for the first phase of the Shtokman development in accordance with the framework agreements signed in 2007. Implementation of the project is subject to a final investment decision which is plannedpursuant to take place in 2010.SDAG's plans.

    Field in production
    The Kharyaga field is located onshore in the Timan Pechora basin in North Westnorth-west Russia. We have 40% interest andThe field is being developed under a production sharing agreement (PSA). Total is the operator. With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20% interest, thus reducing Statoil's share from 40% to 30%.

    The Kharyaga field will be developed in stages accordingPursuant to the terms of the PSA. OilPSA, the Kharyaga field is being developed in stages. Production from phase three started in 2009, and the production commenced in 1999, with Phase 1 productionhas been increased to design capacity of 10 mboe per day utilising three existing wells. Phase 2 was launched in 2000 to increase oil production and develop additional reserves. An additional 11 wells were drilled during this phase. Phase 3 has now been initiated with the aim of increasing production from 20 to 30 mboe30,000 bbl per day. This phaseAt year end 2009, 13 wells had been drilled out of a total of 23 planned wells. Phase three also involves drilling of more production and injection wells, a process upgrade andthe installation of gas treatment facilities.facilities that will stop gas flaring in the future.

     Top 

    3.2.6.53.2.5.5 The Middle East and AsiaAsia

    In January 2010, Statoil and Lukoil signed a development and production contract with Iraqi authorities for the development of the West Qurna 2 field.

    StatoilHydro has interests in the South Pars project in Iran and the Lufeng field offshore China.

    We are also pursuing business development opportunities in the region, and have representative offices in Indonesia, Singapore, Dubai and Australia and in selected countries in the Middle East. We are also qualified as "Non-restricted Operator" in Iraq and may thereby tender as operator for any field in the two upcoming licence rounds in the country in 2009.United Arab Emirates.

     Top 

    3.2.6.5.13.2.5.5.1 Iran

    Gas production from South Pars Phase eight started in August 2008 and from Phase six in December 2008. Production from

    Statoil was the third and final phase, South Pars Phase seven, is expected to commence after the summer of 2009.

    StatoilHydro entered the South Pars project in 2002 asoffshore operator for the development of the offshore partphases 6, 7 and 8 of the South Pars Phases six, seven gas and eight under a buy-back contract with a 37% share duringcondensate field in the Iranian sector of the Persian Gulf. The development phase. Upon completingis now complete and the development phase, StatoilHydro's obligation includes providing certain services tolast platform began production in 2009.

    The Iranian oil company NIOC has taken over as operator for the National Iranian Oil Company (NIOC) during the operations phase; however, our involvementfield. Statoil will be phased out once we have recouped our costsassisting NIOC for a limited transitional period in accordance with the project.

    Basedcontractual framework.
    
    Statoil has previously taken part in exploration and drilling activities in the country on the two discoveriesAnaran field. Work on this project has been stopped.
    Statoil also holds a licence for exploration of the Anaran block, Azar and Changuleh, StatoilHydro discussed a Development Service Contract with NIOC.

    StatoilHydro has an exploration and development service contract with NIOCKhorramabad field. No activity is planned for the Khorram-Abad block in Lurestan province in south-western Iran. The block covers 7400 square kilometres, and the work programme includes acquisition of 600 square kilometres of 2D seismic data and the drilling of three exploration wells. The gathering of seismic data was completed in the fourth quarter of 2008. There are at present no firm plans to drill the first well in the work programme.this licence.

    See report section 5.1.1 Risk review - Risk factors- Risks related to our business, for additional information concerningabout the risk of US sanctions relatedrelating to activities in Iran.

    The Companycompany will not make any future investments in Iran under the present circumstances; however,circumstances, but it is committed to fulfilling its buy-back contract obligations principally for the offshore partin respect of the South Pars phases six/seven/eight project.Pars.

     Top 

    3.2.6.5.23.2.5.5.2 China

    Statoil operated the Lufeng 22-1 oilfield in the South China Sea together with partner CNOOC from 1997 until mid-2009.

    StatoilHydro opened its firstProduction on Lufeng 22-1 was shut down on 15 June 2009. Abandonment of phase one and demobilisation of the Floating Production, Storage and Offloading (FPSO) vessel was finalised on 14 July 2009. Under an agreement between CNOOC and Statoil, CNOOC has taken over full responsibility for the abandonment of phases two and three of the field. The Shekou operations office was closed at the end of 2009.
    
    Statoil's activities in China in 1982. Today, our activities involve operating the Lufeng fieldare currently centred around R&D cooperation and business development.

    Lufeng will probably be shut down during 2009.

    In 2007 StatoilHydro entered into a strategic partnership with China National Petroleum Corporation ("CNPC") through the signing of a Memorandum of Understanding relating to domestic and international exploration and production, LNG value chain and research and development. This cooperation has now been expanded to also cover new energy.

     Top 

    3.3 Natural Gas

    3.3.1 Industry overview

    3.2.5.5.3 Iraq

    On 31 January 2010, Statoil and Lukoil signed a development and production contract with the Iraqi authorities for the development of the West Qurna 2 field.

    Fossil fuelsThe consortium of contractors consists of the state of Iraq's North Oil Company (25%), Lukoil (56.25%) and Statoil (18.75%). Lukoil will continuebe the operator. The development and production contract for the West Qurna 2 field was offered as a standard service contract under which the contractors receive cost recovery plus a remuneration fee. Lukoil and Statoil's bid for West Qurna 2 included a production plateau level of 1,800,000 barrels per day.

    Lukoil and Statoil are working to set up the organisation required to develop the field. A substantial proportion of the work will be done by an Iraqi workforce or by Lukoil, but Statoil will also contribute to the joint organisation. Statoil will also set up a small representative office in Baghdad.

    The security of personnel and implementation of necessary security measures are the main priorities. The security situation in Iraq is still demanding, but it has improved over the last two years. There are variations in different parts of the country, and West Qurna 2 is not considered to be the prime source of incremental energy supply for several decades to come - and natural gas is expected to continue to be the fastest growing fossil fuel in OECD markets.

    According to the International Energy Agency's (IEA) World Energy Outlook for 2008, fossil fuels will continue to be the prime source of incremental energy supply in the decades ahead. However, on a regional level,most challenging area.

    Statoil has been working with the growth in demandIraqi authorities for specific fuels will vary. In developing countries, coal is expected to see the fastest growth in demand, whereas natural gas is expected to continue to be the fastest growing fossil fuelmore than five years, conducting joint field studies and training Iraqi personnel. The entry into Iraq gives Statoil an important position in the OECD markets.

    In the IEA reference scenario, the world primary demand for natural gas will expand by just over half between 2006 and 2030, to 4,400 bcm, a rate of increase of 1.8% per year. The share of natural gas in total world primary energy demand is expected to increase to 22% in 2030. Some 57%Middle East, developing one of the projected increase in gas demand comes from the power sector, pushing up its share of global gas use from 39% today to 45%. Inter-regional gas trade is projected to more than double towards 2030, from 441 bcm in 2006 to more than 1000 bcm in 2030. The European Union expects the biggest increase in import volumes.

    Natural gas can substitute for other fuels in almost any application. In many global scenariosworld's largest oil fields for the mitigationbenefit of climate change, there is an implicit assumption that gas use will increase. Thus, future demand for natural gas looks robustboth the Iraqi people and sustainable, assuming that the necessary regulatory and competitive frameworks are established.participating companies.

    On the supply side, there is major concern over possible energy deficits (or "gaps") in several main gas-producing countries. In consequence, international natural gas markets will be influenced by policy decisions in key producing and reserve holding countries such as Russia, Iran, Algeria and Qatar.

    

    From around 2010, it is expected that Europe will need additional supplies of piped gas and/or LNG in order to cover demand. Gas from the NCS is attractive in the European market due to its high regularity and geographical location. We therefore expect that demand for gas from Norway will continue to increase in our primary gas markets, as domestic gas production elsewhere in Europe continues to decline.

    The international gas industry is driven by several trends that have implications for our business:

    • Accelerated growth in energy demand driven by population and economic growth, with natural gas playing a more important role in the energy mix. The IEA expects the current economic setback to be reversed by the end of 2009, with demand drivers for additional energy picking up again.
    • Due to increased import dependency, natural gas will be transported over increasingly long distances, both as LNG and via pipelines.
    • Environmental concerns and climate change policies are becoming more important.
    • Major resource-holding countries will have an even stronger impact on the global supply picture for gas.
    • Gas and power markets will continue to converge, especially in mature markets such as the OECD.

    These trends and developments indicate new opportunities for our gas business. While robust demand will continue to underpin the longer term supply business, increased transparency, connectivity and liquidity in the market place will open up new areas for value creation through optimisation and trading. Hence, our gas strategy aims to continue to strengthen the long-term supply business while at the same time grasping new business opportunities as market developments allow.

     Top 

    3.3.2 European3.3 Natural Gas

     Top 

    3.3.1European gas market

    In natural gas, we see short term challenges and long term upsides. We expect demand for gas to pick up along with an industrial recovery, and despite weak markets, Statoil's gas business has delivered good results.

    In the longer term, we believe natural gas will be an increasingly attractive commodity. According to the IEA World Energy Outlook 2008, the2009, estimated annual growth in global gas consumption in the period 20062007 to 2030 will be 1.8%1.5%, slightly less than the estimate from last year.year's estimate.

    Growth in gas demand in OECD Europe in the same period is expected to be 1.0%0.8% per annum. This translates tointo a demand for gas in OECD Europe in 2030 of approximately 694650 bcm - up from the current level of somearound 550 bcm. TheGas's share of gas in total primary energy consumption is approaching 25% in the OECD countries in Europe, and it is expected to reach almost 30%28% in 2030. Approximately 60%A large part of the growth in gas consumption in the period - more than 60 per cent - is expected to come from the electricity sector. The IEA expects continued growth in demand for all sub-sectors of the European natural gas market.

    We market and sell our own gas together withand the Norwegian State's natural gas.gas volumes. We are the second largest gas supplier into Europe and the sixth largest supplier in the world. Furthermore, we market gas sourced from producing areas other than the NCS. Other major gas suppliers in Europe are Gazprom in Russia, Sonatrach in Algeria and GasunieGasTerra in the Netherlands. We believe that the Norwegian natural gas exports will remain highly competitive due to their reliability, access to thea flexible and integrated transportation infrastructure and proximity to key European markets such as the UK, Germany and France. In addition, natural gas is an attractive source of energy from an environmental perspective since it emits far less CO2 than coal and oil.

    

    

    ForThe UK was for a long time the UK was the second largest producer of natural gas in Europe after Russia. However, by 2016 it is expected that the UK maycould be dependent on imports for approximately 80% of its gas requirements.requirements already in 2016. Based on our growing infrastructure, we believe we are well positioned to supply a portionpart of the UK's additional demand for imported natural gas and continue to become more involvedbe a key player in the UK market - Europe's largest and most liberalised natural gas market.

    The Langeled a newgas export pipeline was put into operation in 2007, connecting the NCS to Easington in the UK. Another new infrastructure project called the Tampen Link, a pipeline from the Statfjord field on the NCS to the existing Flags pipeline on the UK continental shelf, was also completed in 2007. By 2010, the ongoing Gjøa/Vega field developments will be completed and tied into the Flags system - further increasing NCS export capacity to the UK market.

    The recent disputeDisputes between Russia and Ukraine regardingabout gas transit highlightedhighlight the importance of Russian gas supplies to European markets. In the years ahead, Russian supplies are expected to grow further, and, in the longer term, the EU is set to import some 80% of its natural gas.gas due to declining domestic gas production. In order to diversify supplies, European countries and companies are actively seeking to establish alternative supply solutions, mainly through LNG, but also by establishing new pipeline infrastructure from the Caspian region and from North Africa.

    We believe that Europe will need additional sources of natural gas. We are participatinggas, both because of growth in demand and because of declining domestic production. Statoil participates in increasing gas production in Azerbaijan, with the Shah Deniz field in the Caspian Sea as a key asset. Gas is already exported from Azerbaijan to Georgia and Turkey throughvia the South Caucasus Pipeline (SCP). In order to bring gas even further west, we are participatingparticipate in the Trans-AdriaticTrans Adriatic Pipeline (TAP) that willaims to connect the Italian market with gas flowing westwards from Turkey, through Greece and Albania.

    As the European energy market undergoes deregulation and structural changes, we believe that natural gas will play an increasingly important role. This trend will be reinforced by additionalfurther steps in Europe to curb carbon dioxideclimate gas emissions, in particular by the use of carbon pricing mechanisms such as the EU EmissionEmissions Trading Scheme. We expect the use of natural gas as a source of electricity generation to continue to grow, as thereit is a neednecessary to replace even more coal-based generation capacity with natural gas. Deregulation openscreates new opportunities and business models in the gas sector, both with regard to added values through efficiency gains and to building a more substantial end userportfolio of sales portfolio.directly aimed at large industrial customers and local distribution companies. The integration of the gas and power markets also presents us with new business opportunities in trading and as a means of increasing the value of gas by upgrading through generation and improving our flexibility in market operations.opera tions. We therefore aim to manage and further develop marketed volu mes,volumes, and to increase the scale and scope of our trading and optimisation, andincluding both midstream and downstream activities.

    For information about the EU Gas Directive, please see report section 3.10.3 Operational review-Regulation-Gas directive of the European Union.review - Regulation - The EU gas directive.

     Top 

    3.3.3 3.3.2 Gas sales and marketing

    StatoilHydro

    Statoil is a long-term, and reliable natural gas supplier enjoyingthat has a strong position in some of the world's most attractive markets. We are the second biggest gas supplier into Europe and the sixth largest in the world.

    Europe
    The major export markets for NCS gas are Germany, France, the United Kingdom, Belgium, Italy, the Netherlands and Spain. Our main customers are large national or regional gas companies such as E.ON Ruhrgas, Gaz de France,GdF Suez, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), Distrigaz and Gasunie.GasTerra. In addition, we sell to large end users, mostly through long-term take-or-pay contracts.

    In the United Kingdom, we market our gas to large industrial customers, power generators and wholesalers, in addition to participating in the UK spot market. NG also has an end user sales business based in Belgium, serving largemajor customers in Belgium, the Netherlands and France. Our group-wide gas trading activity is mainly focused on the UK gas market, which is a significant market in terms of size and the most liberalised market in Europe. We are also increasingly taking part in other liquid trading points such as the TTF (Title Transfer Facility) in the Netherlands, and atthe Zeebrugge Hub in Belgium.Belgium and Gaspool in Germany.

    In 2004, Statoil (UK) Limited and SSE Hornsea Limited (subsidiaries of StatoilHydroStatoil and Scottish and Southern Energy Plc, respectively) 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, and close to the Easington terminal. On completion, the storage facility will comprise nine underground caverns. Statoil (UK) Limited owns one third of the storage capacity being developed, of which the SDFI has awill have access to 48.3% share.. The facility has been developed and will beis operated by SSE Hornsea Limited. The storage facility is expected to beginstarted limited commercial operation during the second quarter 2009, with full commercial operation of the nine cavernnine-cavern facility achieved duringscheduled for 2011. The design capacity forof the storage facility is expected to be 420 mmcm. StatoilHydro'sStatoil's share of the total development cost is estimated to be NOK 0.7 billion.

    In Germany, we hold a 30.8% stake in the Norddeutsche Erdgas-Transversale, or Netra, overland gas transmission pipeline, and a 23.7% stake in Etzel Gas Storage through our subsidiary StatoilHydroStatoil Deutschland. Currently, Etzel Gas Storage is currently increasing theits working gas capacity with nineby 10 additional caverns.caverns, one of which was completed in 2009. The rest will be completed in 2010 and early 2011. All partners in Etzel Gas Storage are participating in this project. The project is expected to be finalised within the calendar year 2009, according to schedule.

    USUSA

    

    In
    The USA is the US,world's largest and most liquid gas market. Statoil Natural Gas LLC (SNG) has a gas marketing and trading organisation in Stamford, Connecticut that markets natural gas to local distribution companies, industrial customers and power generators. We haveSNG has two long-term capacity contracts with Dominion Resources Inc., which owns the Cove Point LNG re-gasification terminal in Maryland. The first is for a long-term contract with the operatorone-third share of Cove Point Dominion Resources Inc.capacity (LTD1), securing uswhich equates to approximately 3.2bcm per year, and the second is for 100% of the Cove Point Expansion (CPX) capacity rights of 2.4approximately 7.7 bcm per yearyear. This equates to a total re-gasification capacity of 10.9 bcm per year. This expansion reflects Statoil's focus on the growing natural gas market in the USA and provides more flexibility in sourcing third party LNG to the terminal. The CPX capacity also includes downstream pipeline capacities from the Cove Point terminal to Leidy in Pennsylvania, and gas storage capacity at Leidy. The Cove Point Expansion capacity commenced services on 26 March 2009. A pier expansion project at Cove Point was approved by the Federal Energy Regulatory Commission (FERC) in July 2009 and construction has now started, with completion of the project expected in the latter part of 2011. This will enable the Cove Point terminal to accommodate larger LNG vessels than is currently the case and provide Statoil with increased supply opportunities for third party LNG cargoes into Cove Point.

    

    Through Statoil, SDFI pays for a share of the capacity at the Cove Point regasificationre-gasification terminal, in Maryland on the US east coast. The terminal interconnects with three interstate pipelines, allowing gas to be directed to the Mid-Atlanticdownstream pipeline capacity and North-East markets. The SDFI participates with a 56.5% share of our capacity in the terminal and pipeline.storage capacity. LNG is sourced from ourthe Snøhvit LNG facilitiesfacility in Norway and from third party suppliers, both spot and mid-term arrangements. In 2008 we delivered cargo number 100 of LNG to the Cove Point terminal. suppliers.
    
    SNG also markets the equity production from ourStatoil's assets in the US Gulf of Mexico, in addition to sourcing some pipeline gas domestically mainly for profit optimisation purposes.

    In 2005 StatoilHydro entered into contractual commitments with Dominion for 100% of the expansion of the Cove Point terminal with a capacity of approximate 7.7 bcm annually of gas for a 20-year period, with planned start-up in early 2009. The expansion reflects our focus on the growing liquefied natural gas market in the US, at the same time as market access through Cove Point is strategically important to a potential Snøhvit phase 2 and other LNG projects under consideration by StatoilHydro. In addition it gives us more flexibility in sourcing third party LNG to the terminal.

    The respective future shares of StatoilHydro and the SDFI on the Cove Point terminal, in addition to extra capacity and related commitments, are subject to further consideration, and the outcome may therefore have an impact on the extent of future commitments assumed and reported by StatoilHydro.

    
    
    In 2008, weStatoil entered into a strategic agreement with Chesapeake Energy Corporation.Corporation (as described in 3.2.5.1.2 The USA). The agreement is particularly important for NG in several ways. Firstly, it adds a major building block to ourStatoil's gas value chain position already establishedin the USA. It also provides access to large gas reserves located geographically near the North East which, historically, is the highest paying gas market. This will thereby strengthen Statoil's USA gas position. Over time, this will result in a significant increase in the volume of gas marketed and traded by Statoil in the USA.

    SNG has also concluded transportation agreements with Tennessee Gas Pipeline (a subsidiary of El Paso Corp), and Texas Eastern Transmission (a subsidiary of Spectra Energy Corp), ensuring Statoil the right to transport up to 2 billion cubic metres (bcm) per year/200 000 mcf/day directly from the Northern Marcellus production area to New York City and the surrounding areas. These agreements secure access to some of the main pipeline systems for gas in the New York City area and thereby help maximize the value of our gas produced in the Marcellus shale. We expect that this will create attractive sales opportunities in New York City, New Jersey and surrounding areas in what is regarded the most attractive gas market in the US - the world's largest and most liquid gas market, and secondly, we gain access to large reserves produced close to the highest paying market in the US. Also, it significantly strengthens our US gas position, building on our existing Cove Point LNG position and our well-established gas marketing and trading organisation in Stamford and the competence in our organisation. The agreement entails that over time, we will market and trade significantly higher volumes compared to the volumes today.

    Azerbaijan

    

    StatoilHydro
    Statoil has a 25.5% share in the Shah Deniz gas/condensate field in Azerbaijan and is the commercial operator for gas transportation and sales activities for StageShah Deniz stage 1 development and headinggas volumes. In addition, Statoil chairs the partnerspartners' gas sales committee for the Stage 2 development. Turkey is the main market for gas from Stage 1 of theplanned Shah Deniz development, and in additionstage 2 full field development. Azerbaijan, Georgia and AzerbaijanTurkey are also part of the gas sales portfolio.portfolio for stage 1 in which Turkey is the main market. Gas is transportedpurchased and sold through the Statoil-operated Azerbaijan Gas Supply Company (AGSC), and the gas is shipped to customers through the South Caucasus Pipeline (SCP) running, which runs from the Sangachal terminal in Azerbaijan via Georgia to the Georgian/Turkish border. Shah Deniz Stagestage 1 productiongas transportation and the related gas transportsales reached 6.2 bcm in SCP were ramped up throughout 2008 and is expected to reach the plateau production in 2009 (8.6 bcm annually).2009.

    

    The Stagestage 2 development of Shah Deniz is currently in the Concept Selection phase of the operator BP's Capital Value Process. Field reserves support a significant Stagestage 2 production and are likely towill be larger than in Stagestage 1. Key activities for NG in this respectcontext are related to the commercialisation of Stagestage 2 through the organisation, planning and conductconducting of gas market/transport evaluations and negotiations with counterparties in the Caspian region, Turkey, the European Union and Russia. The progressProgress of the marketing activities has been hampered by the lack of an intergovernmental agreement between Turkey and Azerbaijan on volumes for transit and sales intoto the Turkish market.

    In February 2008, StatoilHydroStatoil signed an agreement with the Swiss EGL Group to establish a joint venture to develop, build and operate the Trans Adriatic Pipeline (TAP) from Greece throughvia Albania to Italy. StatoilHydroWe joined the TAP project as part of our efforts to provide attractive export options and ensure competition for the Shah Deniz gas in the European market, hencemarket. TAP will thus be competing with other pipelines to attract potential customers for gas from Shah Deniz. A final investment decision is linked to the Shah Deniz Stagestage 2 development.

    Algeria
    Statoil has a 31.9% share in Algeria's third largest gas development, the In Salah field and In Amenas. The gas is sold through a joint marketing company that sells the gas produced from development on behalf of the operators Sonatrach, BP and Statoil. All gas that will be produced up until 2017 has been sold under long-term contracts.

    LNG

    
    In 2007,Statoil's LNG trading and commercial operations are based in the first vessel with a cargo of liquefied natural gas fromcompany's offices in Stavanger, Norway. From here, daily contact is maintained between the Snøhvit field left port at Melkøya. As well as pipeline-based supply, StatoilHydro now also supplies gas for export from the Norwegian continental shelf in a cooled state, as LNG, by ship. LNG gives us increased flexibility in terms of marketing gas globally. During 2008, LNG cargoes have been delivered to customers in Europe, the US and Japan. Theproduction plant at Melkøya, isvessels at sea and the contractual receivers of the LNG. Production from the plant at Melkøya, the first LNG production facility in Europe, and it is a key component in StatoilHydro's focus on LNG, which is one of the fastest growing gas markets in the world. Snøhvit LNG is a pioneering and technologically innovative project. Since theproved to be unstable throughout 2009. In addition to scheduled shutdownmaintenance during the summer 2008, Snøhvit has maintained a stablemonths of August to October, several unexpected interruptions to production were experienced during the year. Despite the operational issues at around 80% of the planned capacity. OurMelkøya, we met our contractual delivery commitments to our customers Iberdrola and SNG commenced on 1 October 2006. To meet our obligations we have put into effectthrough mitigation a ctivities,activities, such as purchasing of replacement LNG and piped gas to supplement available Snøhvit LNG. Global LNG prices have been under pressure from lower demand and increased global production. The largest drop in LNG imports was seen into the US market. Of the Snøhvit production, a total of six cargoes were diverted away from the US market into higher pr iced markets in Europe. Statoil will continue to pursue its ambition to grow a global LNG portfolio.

     Top 

    3.3.3 3.3.4 Norway's gas transport system

    The Norwegian gas pipeline system has been developed over the last 30 years to become an integrated gas pipeline system connecting gas producing fields to receiving terminals in Europe via processing plants on the Norwegian mainland to receiving terminals in Europe.

    mainland.

    Norway's gas pipelines currently have a total length of 7800 kilometres. Since 2003, all gas pipelines with third party customers are unitizedhave been unitised into a single joint venture, Gassled, with regulated third party access. The Gassled system is operated by the independent system operator, Gassco AS, a company wholly owned by the Norwegian State. In 2008,2009, the Gassled system transported 94.696.6 bcm (3.3(3.4 tcf) of gas to Europe.

    

    The Gassled system was expanded in 2006 with the Langeled pipeline from Nyhamna to Easington. The Tampen Link pipeline from the Statfjord platform to the British Flags pipeline system was included in 2007. In 2009, the Gassled system is furtherwas again expanded through the merger of the Kvitebjørn gas pipeline, Norne Gas Transportation System and the Etanor ethane fractionation system at Kårstø. When new gas infrastructure facilities are merged into Gassled, the ownership shares are adjusted in relation to the relative value of the assets and each owner's relative interests.interest.
    
    From 1 January 2011, the Gassled ownership interests are planned towill be adjusted due to an agreed increased ownership interest for Petoro.adjusted. Petoro's interests will increase by approximately 8% and all other parties will reduce their interests proportionally. Similar adjustments ofwill be made to the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA are expected to be made.DA. In addition, StatoilHydro'sStatoil's future ownership interest in Gassled may change as a result of the inclusion of new infrastructure, or if Gassled undertakes investments without participation from its owners in proportion with their ownership interests in Gassled.infrastructure.

    StatoilHydro acts asStatoil is technical service provider (TSP) for Gassco forwith respect to the Kårstø and Kollsnes processing terminals as well as for the major partmost of the pipeline infrastructure system.

    As an integrated pipeline network with high flexibility and regularity, we believe that the Norwegian gas pipeline system is an essential facility that ensures reliable supplies of natural gas to Europe.

    The tables below showpresent facts ofabout the NCS gas pipelines, including transportation routes and daily capacities, and our ownership in Gassled and other terminals.

    Gas pipelines included in Gassled	Start up date	Product	Start point	End point	Transport capacity(1) mmcm/day	StatoilHydro share in %	Gas pipelines included in Gassled	Start up date	Product	Start point	End point	Transport capacity(1) mmcm/day	Statoil share in %
    Zeepipe							Zeepipe
    Zeepipe 1	1993	Dry gas	Sleipner riser platform	Zeebrugge	40.9	See Ownership structure Gassled
    Zeepipe 2A	1996	Dry gas	Kollsnes	Sleipner riser platform	72.0
    Zeepipe 2B	1997	Dry gas	Kollsnes	Draupner E	71.0
    							Zeepipe 1	1993	Dry gas	Sleipner riser platform	Zeebrugge	40.9	See Ownership structure Gassled
    							Zeepipe 2A	1996	Dry gas	Kollsnes	Sleipner riser platform	72.0
    							Zeepipe 2B	1997	Dry gas	Kollsnes	Draupner E	71.0
    Europipe 1	1995	Dry gas	Draupner E	Dornum/Emden	44.5		Europipe 1	1995	Dry gas	Draupner E	Dornum/Emden	44.5
    Franpipe	1998	Dry gas	Draupner E	Dunkerque	52.4		Franpipe	1998	Dry gas	Draupner E	Dunkerque	52.4
    Europipe II	1999	Dry gas	Kårstø	Dornum	64.6		Europipe II	1999	Dry gas	Kårstø	Dornum	64.6
    Norpipe AS	1977	Dry gas	Norpipe Y (Ekofisk Area)	Emden	43.1		Norpipe AS	1977	Dry gas	Norpipe Y (Ekofisk Area)	Emden	43.1
    Åsgard Transport	2000	Rich gas	Åsgard	Kårstø	70.4		Åsgard Transport	2000	Rich gas	Åsgard	Kårstø	70.4
    Statpipe							Statpipe
    Zone 1	1985	Rich gas	Statfjord	Kårstø	26.8
    Zone 4A	1985	Dry gas	Heimdal	Draupner S	33.3
    			Kårstø	Draupner S	20.1		Zone 1	1985	Rich gas	Statfjord	Kårstø	26.8
    Zone 4B	1985	Dry gas	Draupner S	Norpipe Y (Ekofisk Area)	30.0
    							Zone 4A	1985	Dry gas	Heimdal	Draupner S	33.3
    										Kårstø	Draupner S	20.1
    							Zone 4B	1985	Dry gas	Draupner S	Norpipe Y (Ekofisk Area)	30.0
    Oseberg Gas Transport	2000	Dry gas	Oseberg	Heimdal	39.9		Oseberg Gas Transport	2000	Dry gas	Oseberg	Heimdal	39.9
    Vesterled (Frigg transport)	2001	Dry gas	Heimdal	St. Fergus	36.0		Vesterled (Frigg transport)	2001	Dry gas	Heimdal	St. Fergus	36.0
    Langeled North	2007	Dry gas	Nyhamna	Sleipner Riser	Approx. 70.0		Langeled North	2007	Dry gas	Nyhamna	Sleipner Riser	Approx. 70.0
    Langeled South	2006	Dry gas	Sleipner	Easington	68.0		Langeled South	2006	Dry gas	Sleipner	Easington	68.0
    Tampen Link	2007	Rich gas	Statfjord	FLAGS	26.5(2)		Tampen Link	2007	Rich gas	Statfjord	FLAGS	26.5 (2)
    Norne Gas Transportation System (3)	2001	Rich gas	Norne field	Åsgard Transport	11.0
    Kvitebjørn gas pipeline (4)	2004	Rich gas	Kvitebjørn	Kollsnes	25.4
    Norne Gas Transportation System							Norne Gas Transportation System	2001	Rich gas	Norne field	Åsgard Transport	11.0
    Kvitebjørn gas pipeline							Kvitebjørn gas pipeline	2004	Rich gas	Kvitebjørn	Kollsnes	25.4
    Gjøa Gas Pipe (3)							Gjøa Gas Pipe (3)	2010	Rich gas	Gjøa Field	FLAGS	17.0
    (1) We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries. (2) 26.5 mmcm/d is the maximal committable capacity (3) To be included in Gassled from 1 January 2009 (4) To be included in Gassled when operational after the pipeline repair in 2009.
    (1) We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries.							(1) We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries.
    (2) 26.5 mmcm/d is the maximal committable capacity							(2) 26.5 mmcm/d is the maximal committable capacity
    (3) To be included in Gassled from 1st June 2010							(3) To be included in Gassled from 1st June 2010

     

    Gas pipelines not included in Gassled

    Start-up date

    Product

    Start point

    End point

    Transport capacitymmcm/day

    StatoilHydroshare in %

    Start-up date

    Product

    Start point

    End point

    Transport capacity mmcm/day

    Statoil share in %

    Haltenpipe

    1996

    Rich gas

    Heidrun field

    Tjeldbergodden/ Åsgard Transport

    7.1

    19.06

    1996

    Rich gas

    Heidrun

    Tjeldbergodden/ Åsgard Transport

    7.1

    19.06

    Heidrun gas export

    2001

    Rich gas

    Heidrun

    Åsgard Transport

    10.9

    12.41

    2001

    Rich gas

    Heidrun

    Åsgard Transport

    10.9

    12.41

    Terminal facilities included in Gassled

    Startup date

    Product

    Location

    Zeepipe JV

    Europipe receiving facilities

    1995

    Dry gas

    Dornum, Germany

    Europipe metering station

    1995

    Dry gas

    Emden, Germany

    Norsea Gas AS

    1977

    Dry gas

    Gas Terminal, Emden, Germany

    Statpipe JV (Kårstø gas treatment plant)

    1985

    Dry gas/NGL

    Kårstø, Norway

    Easington Receiving Facilities

    2006

    Dry gas

    Easington, UK

    Vesterled JV (Frigg terminal)

    1978

    Dry gas

    St. Fergus, Scotland

    Kollsnes Gas Plant

    1996

    Dry gas/NGL

    Kollsnes, Øygarden Norway

    Etanor DA

    2000

    Ethane

    Kårstø, Norway

    Terminals not included in Gassled

    Startup date

    Product

    Location

    Zeepipe terminal JV (1)

    1993

    Dry gas

    Zeebrugge, Belgium

    Dunkerque terminal DA (2)

    1998

    Dry gas

    Dunkerque, France

    (1) Gassled owners hold 49 per cent interest in the terminal.

    (1) Gassled owners hold 49 per cent interest in the terminal.

    (2) Gassled owners hold 65 per cent interest in the terminal.

    (2) Gassled owners hold 65 per cent interest in the terminal.

    Ownership structure Gassled	Period 2009-2010	Period 2011-2028
    Petoro AS(1)	38.46%	46.51%
    Statoil ASA	32.10%	28.32%
    ExxonMobil	9.43%	8.03%
    Total	7.78%	6.04%
    Shell	5.32%	4.92%
    Norsea Gas AS	2.73%	2.25%
    ConocoPhillips	2.00%	1.67%
    Eni	1.53%	1.27%
    Dong	0.66%	1.00%
    Statoil interest including 28.58% of Norsea Gas AS	32.88%	28.96%
    (1)      Petoro holds the participating interest on behalf of the SDFI.

    Gas pipelines included in Gassled	Start up date
    Zeepipe	1993/1996/1997
    Europipe 1	1995
    Franpipe	1998
    Europipe II	1999
    Norpipe AS	1977
    Åsgard Transport	2000
    Statpipe	1985
    Oseberg Gas Transport	2000
    Vesterled (Frigg transport)	2001
    Langeled North	2007
    Langeled South	2006
    Tampen Link	2007
    Norne Gas Transportation System	2001
    Kvitebjørn Gas Pipeline	2004
    Gjøa Gas Pipe 3)	2010
    Terminal facilities included in Gassled	Startup date	Product Location
    	Location
    Zeepipe JV
    Europipe receiving facilities	1995	Dry gas	Dornum, Germany
    Europipe metering station	1995	Dry gas	Emden, Germany
    Norsea Gas AS	1977	Dry gas	Gas Terminal, Emden, Germany
    Statpipe JV (Kårstø gas treatment plant)	1985	Dry gas/NGL	Kårstø, Norway
    Easington Receiving Facilities	2006	Dry gas	Easington, UK
    Vesterled JV (Frigg terminal)	1978	Dry gas	St. Fergus, Scotland
    Kollsnes Gas Plant	1996	Dry gas/NGL	Kollsnes, Øygarden Norway
    Etanor DA 1)	2000	Ethane	Kårstø, Norway
    1) Etanor DA facilities was transferred to Gassled 01.01.2003 whilst the right to the tariff income will be transferred from the Etanor DA owners to Gassled as of 01.01.2009

    Terminals not included in Gassled	Startup date	Product	Location
    Zeepipe terminal JV (1)			1993	Dry gas	Zeebrugge, Belgium    We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries.
    Dunkerque terminal DA (2)   26.5 mmcm/d is the maximal committable capacity		1998	Dry gas	Dunkerque, France
    (1) (3)  To be included in Gassled owners hold 49 per cent interest in the terminal. (2) Gassled owners hold 65 per cent interest in the terminal. from 1 July 2010.

    Ownership structure Gassled	Period 2007-2008 (2)	Period 2009-2010 (3)	Period 2011-2028
    Petoro AS(1)	37.89%	38.46%	46.51%
    StatoilHydro ASA	32.06%	32.10%	28.32%
    ExxonMobil	9.66%	9.43%	8.03%
    Total	8.00%	7.78%	6.04%
    Shell	5.33%	5.32%	4.92%
    Norsea Gas AS	2.81%	2.73%	2.25%
    ConocoPhillips	2.02%	2.00%	1.67%
    Eni	1.56%	1.53%	1.27%
    Dong	0.68%	0.66%	1.00%
    StatoilHydro interest including 28.58% of Norsea Gas AS	32.86%	32.88%	28.96%
    Petoro holds the participating interest on behalf of the SDFI. Change effective date 2007 is 1 September 2007. Change effective date 2009 is 1 January 2009. The changes are due to inclusion of the pipelines Norne Gas Transportation System, Kvitebjørn Gas Pipeline and the right to the Etanor tariff income respectively.

     

     Top 

    3.3.53.3.4 Kårstø gas processing plant

    As technical service provider (TSP), StatoilHydroStatoil is responsible for the operation, maintenance and further development of the Kårstø gas treatmentprocessing plant on behalf of the operator Gassco.

    Kårstø processes rich gas and condensate, or light oil, from the NCS received via the Statfjord-KårstøStatfjord pipeline, the Åsgard-KårstøÅsgard pipeline and the Sleipner condensate pipeline. The treatmentprocessing plant currently has a rich gas capacity of 88 mmcm per day. Products produced at Kårstø include ethane, propane, iso-butane, normal butane, and naphtha and stabilizedstabilised condensate. When all these elements have been separated from the gas, the remaining gas (dry gas) is sent to customers via the Statpipe, Europipe II and Rogass pipelines. The treatmentprocessing plant currently has currently a dry gas export capacity of 7877 mmcm per day.

    

    In order to meet technical requirements and future needs, theThe Kårstø processing plant will undergois undergoing comprehensive upgrading over the next few years. KEP2010years in order to meet safety and technical requirements and future needs. KEP is the project name for several projects intended to make the Kårstø facilities more robust forand ensure safe and efficient operations. The project's frameworkoperation. This investment is estimated at around NOK 6.57 billion. The first projectsub-project was completed successfully completed in 2008. Plans call forentail the completion of the remaining KEP2010 projectssub-projects between 2010 and 2012. Civil work started late 2008. The KEP2010 workforce workingpeak manning for KEP on site will comprisebe around 500 personnel at any given time.700. In 20082009, Kårstø produced 24.624.1 bcm of dry gas, 0.80.9 million tonnes of ethane, 3.24.2 million tonnes of LPG and 2.2 million tonnes of condensate/naphtha exportedfor export to customers worldwide.

     Top 

    3.3.63.3.5 Kollsnes gas processing plant

    As technical service provider (TSP), StatoilHydroStatoil is responsible for the operation, maintenance and further development of the Kollsnes gas treatmentprocessing plant on behalf of the operator Gassco.

    The plant was initially built to receive gas landed from the Troll field throughin two 36-inch pipelines. The plant currently has a design capacity of 147144 mmcm per day. In 2008, an upgrade was completed of the flash gas compressor and the condensate system, was successfully completed to increaseincreasing the robustness of the plant. In 2008,2009, Kollsnes produced 33.831.0 bcm of dry gas and 82.82.0 mmcm of condensate.

    

     Top 

    3.3.73.3.6 Gas sales agreements

    StatoilHydro is required by the Norwegian State to manage, transport and sell gas on behalf of the SDFI. StatoilHydro

    Statoil manages, transports and markets approximately 80% of all NCS gas.

    Due to the relatively large size of the NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, most of StatoilHydro'sStatoil's gas sales contracts are long-term contracts whichthat typically run for 10 to 20 years or more. Under these contracts, the purchasers agree to take daily and annual quantities of gas and, if the gas is not taken, they are obliged to pay for the contracted quantity. The majority of StatoilHydro'sStatoil's long-term sales contracts have reached plateau level.

    Prices under traditional long-term contracts are generally tied to a formula based on the prevailing prices for substitute fuels tofor natural gas, typically heavy fuel oil and gas oil.gasoil. By contrast, the most recent long-term gas sales contracts in the UK are priced with reference to a daily UK market gas price index. There can be significant price fluctuations during the life of the contract. Prices underUnder the traditional long-term contracts, prices are typically adjusted quarterly and are calculated on the basis of the prevailing prices prevailing in the three to nine months before the date of adjustment as published in reference indices. However, the price formula, which allows for monthly or quarterly adjustment, does not pick up on all trends in the marketplace, e.g. changes in the 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, either by either the buyer or the sel ler.t he seller. Under our long-term sales contracts either party is entitled to initiate a price review process under certain circumstances as set forth in these contracts.circumstances.

    

    In 2008, StatoilHydro2009, Statoil was involved in commercial discussions (in lieu of a price review) or in formal price review processes for approximately 70%75% of the volumes covered by our long-term sales contracts.

     Top 

    3.4 Manufacturing and& Marketing

    3.4.1 Industry overview

    As the current economic recession unfolds, we expect the change in the global demand for oil products to be negative in 2009 and maybe in 2010.

    We expect the current economic downturn will revert to the long term trend of two-and-half to four percent growth. We expect demand to increase in parallel with a recovery in the global economy. Such growth will mainly be seen in emerging markets, as environmental policies and low population growth will constrain oil demand in mature economies.

    In the medium to long term, we see growth limitations in global oil supply capacity. Oil production outside OPEC countries has already showed signs of flattening out, mainly due to the natural decline in output from mature oil fields. Supply growth will mainly come from OPEC countries in the future. In the longer term, we also expect limitations to OPEC production, due to lack of investment capacity and policies to make the period of stable oil revenues last as long as possible. In this context, we see incentives to develop both unconventional oil resources and alternative sources of oil products. There is a need to develop technologies to do this in a more environmentally acceptable way.

    In the longer term, oil demand will therefore be limited by supply capacity. The supply side will also set limitations as to the requirements for refinery capacity. A number of refineries are currently under planning and construction around the world, and despite some delays due to the economic downturn, refinery capacity is expected to be more than sufficient in the years ahead. However, with higher prices and limited supply, we expect oil to continue its trend towards becoming primarily a fuel source for transport, such as gasoline, jet fuel and diesel, and less of a source for energy for stationary use, such as heating. This will put further pressure on refineries to increase the yield of these desired products. Income from refining will therefore mainly come from the upgrading of heavy oil components into transportation fuel products.

    In developed economies, the legislative drive to remove sulphur and other pollutants from oil products is seen coming to an end now that the goals have been achieved, and future regulations are expected to focus on biofuel or other renewable content. However, an issue remains as to whether new regulation will seek to migrate shipping away from using heavy fuel oil to using diesel, in order to cut emissions. That could put increased pressure on a diesel market that already looks tight due to a lack of sufficient diesel upgrading capacity.

     Top 

    3.4.2 Oil Sales, Trading and Supply

    We are

    Statoil is one of the largestmajor net sellers of crude oil in the world, operating from sales offices in Stavanger, Oslo, London, Singapore and Stamford, and selling and trading crude oil, condensate, NGL and refined products.

    

    

    

    We market and sell ourStatoil's own volumes and SDFI's equity production of crude oil and NGLs, together with those of the Norwegian State andNGL, in addition to third party volumes. In 2008, we sold 717 mmbbl2009, our total sales of crude oil and condensate. This included salescondensate were equivalent to 721 million barrels, including supplies to our own refineries and other internal entities.refineries. The main crude oil market for StatoilHydroStatoil is in north-western Europe. In addition, we also sell volumes to North America and Asia. Most of the crude oil volumes are sold in the crude spot market based on publicly quoted market prices. Of the total volumes721 mill bbls sold in 2008,2009, approximately 45%47% were StatoilHydroStatoil's own equity volumes.

    We also operate the South Riding Point crude oil terminal in the Bahamas in addition to being responsible for optimising the commercial utilisation of the crude terminals located at Mongstad and Sture in Norway.

     Top 

    3.4.1.1 South Riding Point

    On 22 October 2009 Statoil completed the acquisition of SRP Holding Limited, which holds the lease for the South Riding Point crude oil terminal in the Bahamas until 2049. The lease includes oil storage as well as loading and unloading facilities.

    The terminal, which is located on Grand Bahama Island, consists of two shipping berths and ten storage tanks with storage capacity for 6.75 million barrels of crude.

    We plan to upgrade the terminal to allow for the blending of crude oils, including heavy oils. Future blending operations will normally be carried out onshore, but facilities will also be installed that allow for blending from ship to ship at the jetty.

    The acquisition is a strategic measure that will both support our global trading ambitions and improve our handling capacity for heavy oils. We have rented capacity at the terminal since 1993. New blending facilities and full terminal capacity will strengthen both our marketing and trading positions in the North American market. The terminal will also be an important part of our plans to market our own volumes of heavy oil.

    In addition to the existing lease period, we have an option to extend the agreement for an additional 30 years until 2079.

     Top 

    3.4.33.4.2 Manufacturing

    We are

    Statoil is majority owner and operator of the Mongstad refinery and Tjeldbergodden methanol plant in Norway and sole owner and operator of the Kalundborg refinery in Denmark, andDenmark. We also operate the Oseberg Transportation System including the Sture crude oil terminal.

    System.

    We are majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil distillation capacity of 179180 mbbl per day, and sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbl per day. In addition, we have the rights to 10% of the production capacity at the Shell operatedShell-operated refinery in Pernis, Thethe Netherlands, which has a crude oil distillation capacity of 400 mbbl per day. Our methanol operations consist of oura 81.7% stake in the gas-based methanol plant at Tjeldbergodden, Norway, which has a design capacity of 0.95 million tonnes per year.

    

    We also operate the Oseberg Transportation System (36.2% stake) including the Sture crude oil terminal. The plant was built to receive crude from the Oseberg field through a 28-inch pipeline, and since 2003 it has also been receivingreceived crude from the Grane field through a 29-inch pipeline. Oseberg blend (after stabilisation), Grane blend and some LPG are exported, while some LPG and condensatenaphtha is piped to Mongstad.Mongstad combined with condensate from the Kollsnes gas processing plant.

    The following table givesshows operating characteristics offor the plants at Mongstad, Kalundborg and Tjeldbergodden.

    All data for year ended December 31	All data for year ended December 31															All data for year ended December 31
    	Throughput (1)				Distillation capacity (2)				On stream factor % (3)				Utilization rate % (4)			Throughput (1)				Distillation capacity (2)				On stream factor % (3)				Utilization rate % (4)
    Refinery	2008	2007	2006		2008	2007	2006		2008	2007	2006		2008	2007	2006	2009	2008	2007		2009	2008	2007		2009	2008	2007		2009	2008	2007
    Mongstad	10.0	10.9	11.2		8.7				92.2	97.8	99.1		88.2	93.2	97.9	10.0	10.0	10.9		8.7	8.7			92.3	92.2	97.8		86.8	88.2	93.2
    Kalundborg	5.2	4.7	4.9		5.5				88.3	96.4	94.7		90.3	91.7	91.0	5.0	5.2	4.7		5.5	5.5			95.3	88.3	96.4		88.2	90.3	91.7
    Tjeldbergodden	0.91	0.70	0.89		0.95				98.9	81.7	94.6		96.5	97.7	95.6	0.71	0.91	0.70		0.95	0.95			82.6	98.9	81.7		90.2	96.5	97.7
    (1) Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes.
    Higher than destillation capacity for Mongstad due to high volumes of fuel oil and NGL not going through the crude destillation unit.
    (2) Nominal crude oil and condensate distillation capacity, and methanol production capacity , measured in million tonnes.
    (1) Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes. Higher than destillation capacity for Mongstad due to high volumes of fuel oil and NGL not going through the crude destillation unit.																(1) Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes. Higher than destillation capacity for Mongstad due to high volumes of fuel oil and NGL not going through the crude destillation unit.
    (2) Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in million tonnes.																(2) Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in million tonnes.
    (3) Composite reliability factor for all processing units, excluding turnarounds.	(3) Composite reliability factor for all processing units, excluding turnarounds.															(3) Composite reliability factor for all processing units, excluding turnarounds.
    (4) Composite utilization rate for all processing units, stream day utilization.	(4) Composite utilization rate for all processing units, stream day utilization.															(4) Composite utilization rate for all processing units, stream day utilization.

     

     Top 

    3.4.3.13.4.2.1 Mongstad

    The Mongstad refinery is a medium-sized, modern and sophisticated refinery. It is linked to offshore fields, the Sture crude oil terminal and the KollnesKollsnes gas terminal,processing plant, making it an attractive site for landing and processing hydrocarbons.

    The Mongstad refinery was built in 1975,1975. It was significantly expanded and upgraded in the late 1980s, and it has been subject to considerable investmentsinvestment over the last 15 years in order to meet new product specifications,specifications. It is a medium-sized, modern and sophisticated refinery. The refineryIt is directly linked to offshore fields through two crude oil pipelines and indirectly linked through an NGL/condensate pipeline to the crude oil terminal at Sture and the gas terminalprocessing plant at Kollsnes, makingKollsnes. This makes Mongstad an attractive site for landing and processing hydrocarbons and for the further development of our oil and gas reserves. The

    

    In addition to the refinery, the main facilities at Mongstad in addition to the refinery, areconsist of a crude oil terminal and a Natural Gas Liquids (NGL) process unit and terminal. The crude terminal is owned 65% by StatoilHydro,Statoil. A large proportion of its crude oil comes through two direct pipelines from the Troll field. The storage capacity is 9.4 million barrels of crude.

    Vestprosess, which is owned 34% by Statoil, transports and anprocesses NGL terminal, owned byand condensate. The Vestprosess pipeline connects the Kollsnes and Sture plants to Mongstad. The NGL is fractionated in which StatoilHydro has an ownership interest of 34%.

     the Vestprosess NGL unit to produce naphtha, propane and butane.

    The refinery is owned 79% by StatoilHydroStatoil and 21% by Shell. We have a service agreement with Shell Global Solutions, a Shell subsidiary, which provides technical operational support, project development support and general technical advice to Mongstad.

    Approximately 45% of Mongstad's total production is delivered to the Scandinavian markets and 55% is exported to north-westernnorth-west Europe and the United States.

    The following table shows the approximate quantities of refined products (in thousand tonnes) produced at Mongstad for the periods indicated. As shown below, inIn addition to crude, the Mongstad refinery upgrades large volumes of heavy fuel feedstock,oil, NGL from Oseberg and Tune, and condensate from Troll, Kvitebjørn, Visund and Visund.

    	For the year ended 31 December
    Mongstad product yields and feedstock	2008		2007		2006
    LPG	311	3 %	373	4 %	359	3 %
    Gasoline / naphtha	3 902	39 %	4 721	43 %	4 802	43 %
    Jet / kerosene	820	8 %	755	7 %	801	7 %
    Gasoil	3 680	37 %	3 865	35 %	4 050	36 %
    Fuel oil	485	5 %	311	3 %	302	3 %
    Coke / sulphur	190	2 %	222	2 %	231	2 %
    Fuel, flare & loss	575	6 %	692	6 %	620	6 %
    Total throughput	9 963	100 %	10 939	100 %	11 165	100 %
    North Sea crude oils:
    Troll, Heidrun (FOB crude oils)	4 676	47 %	4 751	43 %	5 508	49 %
    Other North Sea crude oils (CIF crude oil)	3 072	31 %	3 780	35 %	2 616	24 %
    Residue	1 132	11 %	1 265	12 %	1 323	12 %
    Other fuel and blendstock	1 083	11 %	1 143	10 %	1 718	15 %
    Total feedstock	9 963	100 %	10 939	100 %	11 165	100 %
    Note: Changes in throughput and yields are partly due to maintenance shutdowns (e.g. major turnaround in 2008).

    Fram.

    The Mongstad refinery is able tocan manufacture products to meet different specifications through its in-line blending during ship loading.

    	For the year ended 31 December
    Mongstad product yields and feedstock	2009		2008		2007
    LPG	372	4%	311	3%	373	4%
    Gasoline / naphtha	4,401	44%	3,902	39%	4,721	43%
    Jet / kerosene	717	7%	820	8%	755	7%
    Gasoil	3,473	34%	3,680	37%	3,865	35%
    Fuel oil	374	4%	485	5%	311	3%
    Coke / sulphur	164	2%	190	2%	222	2%
    Fuel, flare & loss	532	5%	575	6%	692	6%
    Total throughput	10,033	100%	9,963	100%	10,939	100%
    Troll, Heidrun (FOB crude oils)	4,062	40%	4,676	47%	4,751	43%
    Other North Sea crude oils (CIF crude oil)	3,679	37%	3,072	31%	3,780	35%
    Residue	1,316	13%	1,132	11%	1,265	12%
    Other fuel and blendstock	976	10%	1,083	11%	1,143	10%
    Total feedstock	10,033	100%	9,963	100%	10,939	100%
    Note: Changes in throughput and yields are partly due to maintenance shutdowns (e.g. major turnaround in 2008).

    The refinery reliability (i.e. on streamon-stream factor) was high in 2006 and 2007, but the site experienced some operational problems during 2008.2008 and 2009. In addition, there were also shutdowns due to the market situation in 2009. In 2008 the largest turnaround in Mongstad's history was executed on schedule. There were no turnarounds in 20062007 or 2007.2009. Capacity utilisation (the share of available plant capacity actually used) was reduced in 2009, also due to the market situation.

    In 2006, we received final permission to buildWe are building a combined heat and power plant (CHP plant) at Mongstad.

    The CHP plant is part of a strategically important project for Manufacturing & Marketing. The use of heat from the CHP plant will result in significant improvements toimprove the Mongstad refinery's energy efficiency. The CHP plant is expected to providehas a capacity of approximately 280 megawatts of electric power and 350 megawatts of process heat, howeverheat. The plant will have a gradual start-up phase as the utilisation will berefinery needs less steam due to a changed feedstock pattern, lower forthroughput and the first years after the unit is expected to come in commercial operation in 2010.postponement of projects. The plant is under construction,commissioning and testing, and will be operated by Dong Energy, with StatoilHydroStatoil paying an annual feetariff for its use. By the end of 2008, the progress of the total CHP investment project was 80%. There is also an agreement with the Troll licensees that this facility will supply power to the Troll A gas platform and the associated Kollsnes onshore Kollsnes processing plant. In addition to the CHP plant, the CHP investment project includes a new gas pipeline from Kollsnes and necessary modifications at the refinery.

    StatoilHydroTogether with the Norwegian Government, Statoil is involved in several projects together with the Norwegian government that aim to develop solutions for carbon capture and storage (CCS) at Mongstad. These projects are further described in report section 3.5.2.13.5.2 Operational review-Technology andreview - Technology & New Energy-Research and development-R&D initiatives.Energy - New energy.

     Top 

    3.4.3.23.4.2.2 Kalundborg

    The Kalundborg refinery is a small yet highly efficientand flexible oil refinery. It has a high degree of flexibility, enablingThis enables it to produce a variety of products, such as gasoline, jet fuel,although its main products are low-sulphur petrol and diesel propane and fuel oils tofor markets in Denmark and Sweden.

    

    The refinery is connected throughvia two pipelines (gasoline/gas oil)(one gasoline and one gasoil) to our terminal at Hedehusene, near Copenhagen.

    Kalundborg's refined products are also supplied to other markets in north-western Europe, mainly Germany and France. Fuel oil is exported to Italy and the US.

    USA.

    The following table shows the approximate quantities of refined products (in thousand tonnes) produced by Kalundborg forin the periods indicatedindicated.

    			For the year ended 31 December						For the year ended 31 December
    Kalundborg product yields and feedstock	Kalundborg product yields and feedstock		2008		2007		2006		2009		2008		2007
    LPG			54	1%	78	2%	96	2%	71	1%	54	1%	78	2%
    Gasoline / naphtha	Gasoline / naphtha		1,598	31%	1,497	32%	1545	31%	1,620	32%	1,598	31%	1497	32%
    Jet / kerosene	Jet / kerosene		251	5%	209	4%	259	5%	130	2%	251	5%	209	4%
    Gasoil			2,105	40%	1,997	42%	2042	42%	2,140	43%	2,105	40%	1997	42%
    Fuel oil (2)			1,023	20%	746	16%	775	16%	886	18%	1,023	20%	746	16%
    Coke / sulphur	Coke / sulphur		6	0%	5	0%	5	0%	0	0%	6	0%	5	0%
    Fuel, flare & loss	Fuel, flare & loss		183	3%	185	4%	193	4%	189	4%	183	3%	186	4%
    Total throughput(1)	Total throughput(1)		5,220	100%	4,717	100%	4,915	100%	5,036	100%	5,220	100%	4,718	100%
    North Sea crude oils:
    Condensates: Ormen Lange, Snöhvit, Sleipner	Condensates: Ormen Lange, Snöhvit, Sleipner		659	12%	170	4%	1088	22%	998	20%	659	12%	170	4%
    Other North Sea crude oils	Other North Sea crude oils		4,314	83%	4,395	93%	3641	74%	3,713	74%	4,314	83%	4395	93%
    Other fuel and blendstocks	Other fuel and blendstocks		247	5%	153	3%	187	4%	202	4%	247	5%	153	3%
    Other crudes									123	2%
    Total feedstocks	Total feedstocks		5,220	100%	4,718	100%	4,916	100%	5,036	100%	5,220	100%	4,718	100%
    1) Total throughput has increased from 2007, The increase is explained by optimisation arising after startup of
    the Fuel Reduction plant, strong operational focus on throughput optimisation and no large turnaround in 2008
    2) Fuel Oil volume has increased due to large import of flux material since the start of the Fuel Reduction Project
    1) Total throughput has decreased from 2008, due to the economic downturn. The refinery operates in a market,
    that is oversupplied with products, so the production during 2009 was not maximized.
    2)The Fuel Reduction plant has been in operation throughout 2009, except for a planned shutdown in September,
    and an incident in October, hence the reduction in 2009.

    The refinery reliability (i.e. on-stream factor) was relatively high in 2007 and 2009, but 2008 was more challenging; partly related to startup after a major modification project. There was a turnaround in 2007. Capacity utilisation (the share of available plant capacity actually used) was reduced in 2009 due to the market situation.

    Kalundborg is a plant with high energy efficiency and high utilisation. The refinery has improved its performance significantly in recent years through several small investment projects aimed at increasing flexibility and improving yield/product quality. It produces high qualityhigh-quality products, including low-sulphur petrol,gasoline and diesel, in accordance with EU specifications.

    The Fuel Reduction Project which reduces production of heavy fuel oilwas completed in 2008, and increasesit is now producing according to the production of sulphur-free auto diesel, was started up in 2008.design specifications.

     Top 

    3.4.3.33.4.2.3 Tjeldbergodden

    The Methanolmethanol plant at Tjeldbergodden is the largest in Europe and one of the most energy efficient in the world. It is supplied with natural gas from the Heidrun field in the Norwegian Sea through the Haltenpipe.

    We ownStatoil owns 81.7% of the plant, which has a maximum proven capacity of 0.92 mmtpa. The actualmillion metric tonnes per year (mmtpa). Actual throughput in 20082009 was 0.91 mmtpa.reduced due to depressed methanol market prices and necessary maintenance. Methanol production in 2009 was 0.71 mmtpa

    

    We also own 50.9% of Tjeldbergodden Luftgassfabrikk DA, one of the largest air separation units (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%) and ConocoPhillips (11.3%). The ASU supplies oxygen to the methanol plant and AGA markets and sells the industrial gases produced.Scandinavia.

     Top 

    3.4.3.43.4.2.4 Sture

    The Sture terminal receives crude oil throughin two pipelines, from the Oseberg area and the Grane field in the North Sea. The terminal is part of the Oseberg Transportation System in which StatoilHydroStatoil has a 36.2% stake.

    The terminal has a storage capacity for 6.3 million barrels of crude.
    
    The processing facilities at Sture recover the lightest components from the unstablestabilise Oseberg crude extractingoil and recover LPG mix (propane and butane) and naphtha. TwoOseberg Blend and Grane crude qualities and LPG mix are exported, and volatile organic compounds (VOC) are recovered when loading tankers.exported. LPG and naphtha are also transported through the Vestprosess pipeline to Mongstad.

    

     Top 

    3.4.43.4.3 Energy and Retail

    Energy and Retail has approximately 11,000retail employs close to 10,500 employees and consists of approximately 2,100who run 2000 service stations and 350300 automated truck stops in eight countries. We also market refined products directly to consumer and industrial markets.

    The majority of Energy and Retail's sales are generated in Scandinavia. In Norway we have a transport fuel market share of approximately 35%. In Sweden, our transport fuel market share is approximately 32%, and in Denmark it is approximately 27%, based on sales from Statoil and JET-branded stations together with truck-stop sales. Other service stations are located in Poland, Russia and the Baltic states: Estonia, Lithuania and Latvia. We are the market leader in Estonia and Latvia measured in terms of fuel volumes sold, with approximately 23% and 36% respectively of the local transport fuel market in 2009.

    The full-service stations in the Retailretail segment provide automotivesell transportation fuels, car accessories and basic vehicle service products. In addition, mostMost stations also offer consumer goods including(including fast food,food), convenience products and basic groceries. In 2008, these stations,2009, together with automated stations, these stations sold approximately 8.46.9 billion litres of petrol and diesel. Sales from truck stops accounted for additional sales of 11.0 billion litres.

    

    The following table lists these retail outlets by region or country as of 31 December 20082009 and our volume of automotive fuel sales for the year ended 31 December 2008.2009.

    Retail outlets/country
    Service Stations	Scandinavia	Poland	Baltics	Russia	Total	Scandinavia	Poland	Baltics	Russia	Total
    StatoilHydro owned and operated	276	185	164	15	640
    StatoilHydro owned and dealer operated	517	0	1	0	518
    Dealer owned and StatoilHydro operated	0				0
    Statoil owned and operated						276	186	167	19	648
    Statoil owned and dealer operated						464				464
    Dealer owned and operated	254	44	10	0	308	178	57	6		241
    Automated stations	555	41	17	0	613	588	47	17		652
    Total	1,602	270	192	15	2,079	1506	290	190	19	2005
    Truck Stops	346	1	0		347	292	0			292
    Automotive fuel volumes (millions of litres)	Automotive fuel volumes (millions of litres)					Automotive fuel volumes (millions of litres)
    Petrol	2,453	361	521	37	3,372	2,449	375	439	61	3324
    Diesel	3,819	392	560	4	4,775	3,391	568	469	19	4447
    LPG/Ethanol	337	144	29	0	510	67	137	24	0	228
    Total	6,609	897	1,110	41	8,657	5,907	1,080	932	80	7,999

    In addition to the retail operations, Energy and Retail also supplies aviation and marine fuels, as well as a large number of Statoil-brand refined products. Such products include oil based heating fuelsoil and lubricants whichthat are supplied to both retail and industrial customers. We

    

    JET integration
    A total of 123 JET stations in Sweden and 70 JET stations in Denmark have operations for lubricants and LPGbeen successfully integrated into Statoil. A major IT integration has taken place in Poland andorder to move the Baltic countries, supplementing our strong market position in Scandinavia.

    

    stations from the old ConocoPhillips systems over to the Statoil IT platform. The majorityintegration of these 193 sites boosts Energy and Retail sales are generatedRetail's position as the leading fuel company in Scandinavia. We have an approximate transport fuel market share of 36% in NorwayScandinavia, with a balance between full-service and 23% in Denmark. In Sweden our transport fuel market share is approximately 33%, based on sales fromautomated outlets.

    On 1 April 2009, Statoil sold 118 unmanned Swedish Hydro/Uno-X branded filling stations, 40 unmanned Swedish JET-branded stations and Hydro branded stations together with truck site sales and bulk deliveries. Other service stations are located in Poland, Russia and the Baltic countries; Estonia, Lithuania and Latvia. We rank as a market leader, measured in terms of fuel volumes sold, in Estonia and Latvia with approximately 26% and 34%, respectively,all of the local transport fuel market40 unmanned Norwegian JET-branded station to St1 OY. These sales were in 2008

    Acquisition of Jet
    On 21 October 2008, the European Commission granted permission for StatoilHydro to take over the bulk of the Jet self-service retail chain in Scandinavia that was then owned and operated by ConocoPhillips. To complyaccordance with the terms set by the European commission StatoilHydro agreedwhen approving Statoil's acquisition of JET in Norway, Sweden and Denmark.

    Developing our business

    Statoil's Board of Directors has approved a proposal to sell 80create a stand-alone Energy & Retail business through an initial public offering (IPO) on the Oslo Stock Exchange. The IPO will take place at the earliest in the fourth quarter of 2010 or at a time when the capital market is deemed favourable for such an offering. Statoil intends to remain a majority shareholder of Energy & Retail at the time of the 274 filling stations acquired, so asinitial public offering and listing. The size and time horizon of Statoil's future ownership in Energy & Retail will be tailored to limit market concentration. StatoilHydro will also be obliged to sell 118 Hydro stations in Sweden as partsupport and develop company value both for Energy & Retail and for the Statoil Group. The introduction of the divestment package.

    The transactionnew ownership structure is an important element in our endeavoursnot expected to becomehave a significant impact on the leading fuel company in Scandinavia.financial statements.

     Top 

    3.5 Technology and& New Energy

    3.5.1 Industry overview

    The success of our business is closely related to the application of the advanced technological expertise that for the most part has been acquired through our exploration and production activities on the NCS.

    Many major challenges have been addressed, including operating in the harsh weather and environmentally sensitive conditions of the Norwegian Sea, transporting oil and gas across the deep Norwegian trench, and draining complex petroleum reservoirs characterised by high pressures and high temperatures. Much of this experience is increasingly being applied to StatoilHydro's international operations.

    The renewable energy industry continues to grow, driven by ambitions to increase the contribution of sustainable energy to the total energy supply. Despite the challenges associated with the current financial crisis we believe that the new energy industry has gathered sufficient momentum in recent years for it to continue to be an important focus area for StatoilHydro. Although energy production from renewables is still modest in most countries, wind power, solar energy and biofuels are developing into significant industries.

     Top 

    3.5.23.5.1 Research and development initiatives

    3.5.2.1 R&D initiatives

    The ResearchOur research and Developmentdevelopment (R&D) efforts focus on the technology areas identified as addressing our key business cluster concentrates on StatoilHydro's technology focus areas in which the company wishes to develop and sustain distinctive technology positions.

    challenges.

    The R&D portfolio is structuredorganised in sixfive programmes: Exploration, IOR -Exploration; Increased Oil Recovery and Reservoir Drilling & Well,Well; New Development Solutions,Solutions; Oil and Gas Value Chain,Chain; New Energy/Energy and New IdeasIdeas. In addition, there is an Academia programme that addresses cooperation with universities and Academia.research institutes.

    Research and Development expenditures weredevelopment expenditure has been stable for the last three years at approximately NOK 2.24, NOK 1.97 and NOK 1.622.1 billion in 2008, 2007 and 2006, respectively. R&D expenditures are partly financed by joint venture partners of StatoilHydro operated activities. per year.
    Cooperation with external partners for example academia,such as academic institutions, R&D institutes and suppliers are keyis crucial in relation to technology provision. Typically more than 50% of theThe aim is a 50/50 split between internal and external R&D expenditure is external work.

    As conventional fossil fuels become ever harder to find, our company is increasingly setting its sights on remote geographical areas and developing unconventional hydrocarbon sources such as tight gas, oil sands and building growth platforms in carbon-neutral energy sources (renewables).spending.

    In the exploration technology context, we are developing new basin and prospect concepts that enable better global screening, exploration drilling and quantitative prediction of basin prospectivity. In addition, we are working on the identification, characterisation and prediction of deep-waterdeepwater plays for exploration withinin complex geological settings. IncorporationThe incorporation of integrated geophysical and geological methodologies into next generation workflows results in continued improvement of subsurface imaging and interpretation. The goal is to considerably reduce the risk of drilling dry holes and to enable us to determine the presence of commercially viable reservoirs prior to drilling.

    For proven reservoirs, the aim is to optimise hydrocarbon recovery by improving ways of identifying remaining reservesresources and draining our reservoirs as efficiently and effectively as possible. Important success factors here are data integration and faster model updates for integrated operations across disciplines, organisational entities and geographical areas. The objective is to achieve more reliable, better and swifter decisions. We developare developing fit-for-purpose modelling techniques for better and more efficient modelling of reservoir drainage, more efficient drilling and intervention solutions and more cost effective well construction methods.

    Innovative offshore field development solutions lead toare resulting in a transition from topside facilities to intelligent, remotely-operated, autonomous seabed facilities, coupled with ultra-long, subsea tie-backs and wellstream compression devices. However, we also see that compact processing technology developed for subsea applicationsapplication has a substantial potential to improve efficient production efficiency on existing platforms. The aim is to improve the regularity and performance forof both new and producing fields. Furthermore, it is necessary to increase theour knowledge about design and operationoperations in ice-bound areas and in ultra-deepwater conditions. Environmental activities relating to our licence-to-operate in the far north and time-critical research relating to exploration drilling in the far north are being addressed. We haveare also started to developdeveloping technology for the processing and transportation of offshore heavy oil.

    
      
    The opportunities in gas value chain technology may lie in gaining greater access to, and cost-effectively developing, difficult unconventional gas resources. We are developing technology for the processing and transportation of challenging gas as well as pipeline solutions for deep and ultra-deep assets. In supporting our M&M business we work onassets, and refining technology for handling challenging and unconventional crude oil.oil, such as for the Peregrino field in Brazil.

    The Calgary Heavy Oil Technology Centre was established early this yearin 2008 to strengthen our efforts in heavy oil technologies. The focus is on developing onshore extra heavyextra-heavy oil value chains and on improving recovery methods, water management and carbon capture.

    The final demonstration of GTL technology on a semi-commercial scale was completed this year. This concludes a demonstration programme where a Joint Venture consisting of StatoilHydro together with partners Lurgi and PetroSA has demonstrated the technology.chains.

    Our commitment to environmental stewardship is twofold: meeting our objective of zero harm to the environment by expanding our toolkit of environmental monitoring and integrated risk-modelling systems, and, secondly, by creating business in new energy sources. In addition to our present activities in offshore wind and marine biofuels we plan to further investigateare assessing opportunities in renewable energy sources and carriers. We are working on costCost and energy efficientenergy-efficient carbon capture and storage (CCS) with nothat does not harm to the environment and weis an important element being addressed by Statoil. We believe technological innovation is the key to meeting a profitable, sustainable, low-carbon energy future. Integrating trend-breaking technologies such as biotechnology and other new ideas into the value chains is also part of our research and development effort.efforts.

    As part of the research effort, we are pursuing an extensive collaboration programme with academiaacademic institutions in which we gain access to world classworld-class research within strategic areas for StatoilHydro.Statoil. By stimulating the development of leading competence withinexpertise in the energy segment, we also secure long termlong-term recruitment to science and technology.

    By supporting collaboration between universities, research institutions and industry, we believe this also contributescontribute to building a strong Norwegian petroleum cluster.

     Top 

    3.5.33.5.2 New energy

    The

    New Energy portfolio has a particular focusfocuses particularly on creatingdeveloping profitable business in the shortareas where we may have a competitive edge as a result of our offshore expertise. Key areas are offshore wind and medium term through the Windcarbon capture and BioFuels businesses.

    storage.

    Renewable Power Productionpower production
    Today'sOur main focus in renewable power production is on making offshore wind portfolio consists of several onshore development projects in Norway andpower a profitable business, but we are also engaged in activities in onshore wind, wave, tidal, solar and geothermal energy. In October 2002, Havøygavlen Wind Park came on line with a capacity of 40 MW. It generates enough power for approximately 5000 Norwegian homes. Havøygavlen is the world's northernmost wind farm, located close to North Cape. Havøygavlen is a wholly owned subsidiary of Statoil. We also have two windmills that power a pioneering project on the island of Utsira. In addition, Statoil has several other onshore wind projects under evaluation in Norway.

    Sheringham Shoal
    In 2009, Statoil joined forces with the Norwegian utilities company Statkraft to develop the Sheringham Shoal offshore wind farm in the early phasesUK. Located off the coast of possibly developingnorthern Norfolk, the 315 MW Sheringham Shoal offshore shallow water wind projectfarm is expected to provide enough energy to power almost 220,000 British homes. Sheringham Shoal, which received consent in August 2008, will be a major contributor of clean power to the UK market. The generated electricity and renewable energy certificates will be sold in the UK.UK market. Construction work started in 2009. The 88 wind turbine generators will be set into production one by one as they are commissioned and tested in the period up until the end of 2011.

    To fulfil its EU 2020 renewable energy target, the UK Government has estimated that more than 30% of its electricity production will have to come from renewable electricity by 2020. Offshore wind will play a major part in achieving this target. In May 2008 StatoilHydro approvedJanuary 2010 The Crown Estate announced the buildingthird round of offshore leasing, awarding areas which could develop in total 32 GW of offshore wind capacity. This comes in addition to the potential capacity of 8 GW from previous rounds. Statoil was as part of the Forewind consortium awarded the Dogger Bank zone. This is the largest area in the licensing round with an expected capacity of 9-13 GW. Forewind is a consortium of four equal partners. In addition to Statoil, it consists of RWE npower renewables, Scottish and Southern Energy and Statkraft. This is currently an investment opportunity, and Statoil has as of yet not committed to any investments in the project.

    Hywind - the world's first full-scale floating wind turbine
    In 2009, Statoil crossed a new energy frontier when the company developed the world's first full-scale floating wind turbine - Hywind. The 2.3 MW turbine, a pilot of a concept developed by Statoil, is located 10 km off the island of Karmøy north of Stavanger in Norway. The test period started in autumn 2009 and will last for two years. The Hywind pilot is based on known technology from both the wind power industry and oil and gas industry, which has been combined in a completely new way. Work on this project rests on the fundamental philosophy that existing turbine solutions can function using floating structures and mooring systems developed for the offshore sector.

    Having demonstrated technological feasibility through the Hywind pilot, and this demonstration projectthe next phase will focus on demonstrating commercial feasibility. Statoil is therefore considering locations for further demonstration.

    Sustainable fuels
    Biofuel is considered to be the world's first full scale floating windmill. It is a 2.3 MW unit and is scheduledmost effective measure for operation offreducing carbon dioxide emissions from the west coast of Norway second half of 2009. Complementary offshore wind technologies are available through our equity positions in the Norwegian companies Sway AS and ChapDrive AS.

    In 2008 we invested in Brightsource Energy, which develops technology for concentrated solar thermal power, and the Iceland Deep Drilling Project (IDDP), which is a joint-research programme within deep geothermal energy in Iceland.

    Our existing technology investments have also begun to show promise. Pelamis, a wave energy device in which StatoilHydro has invested, was the technology chosen for the world's first wave energy park situated off the Portuguese coast. In addition, it has been selected for other new projects in the UK. Hammerfest Strøm AS, a tidal power technology company in which StatoilHydro participates together with Iberdrola/Scottish Power, has been selected to be used in projects planned by Scottish Power.

    Sustainable Fuels
    Today we own 42.5% of Mestilla, a 100,000 t/year rape seed biodiesel production facility in Lithuania, where production started in November 2007. Our strategy is to deliver rapid commercial growth within sustainable biofuels andtransport sector. We wish to position ourselves for low cost next generationlonger-term growth in low-cost second-generation marine biofuel production. StatoilHydro's ambition istechnology by building technological expertise and securing access to become a significant provider of sustainable biofuels with a global productionwinning technologies through demo projects, and trading positionby engaging in technology development and to be a high quality supplier in our retail markets.

    Being able to produce biofuels sustainably is a prerequisite for developing our biofuels business. We are working actively to prevent damage to biodiversity, ecosystems and areas of high conservation value and emphasise the greenhouse gas accounts in a life cycle perspective. Our aim is to contribute to positive local development through competence building and job creation.

    Our activities within hydrogen are centred on both short and long-term options. Through our subsidiary Hydrogen Technologies we are actively developing and promoting ongoing sales of water electrolysis technology. We have also developed hydrogen station technologies aiming at the emerging markets within the transport sector.

    StatoilHydro opened Norway's first hydrogen filling station in Stavanger in August 2006 and the second in Porsgrunn in June 2007. The stations are part of the national development project HyNor, in which StatoilHydro is a leading player. HyNor is a unique Norwegian joint industry initiative to demonstrate real life implementation of hydrogen energy infrastructure along a route of 580 kilometres from Oslo to Stavanger.

    On Utsira, an island off the west of Karmøy, StatoilHydro owns and operates a hydrogen demonstration plant where electricity from wind turbines is used to provide power to the local society and to produce hydrogen. When wind speeds are not sufficient to provide enough electricity, the hydrogen plant is used to generate power.active technology monitoring.

    CO2 ManagementCarbon capture and storage
    Carbon capture and storage (CCS) is regardedseen as one of the main means to combatmethods of combating climate change. StatoilHydroStatoil has long been a pioneer of CCS withinin oil and gas production, and we currently operatesoperate some of the world's largest projects in this area. Statoil is engaged in the development of potential medium and long-term breakthrough technologies for carbon dioxide capture. They include both improvements of existing concepts and radically novel concepts. The aim is to significantly improve energy efficiency and reduce costs.

    • When StatoilHydro started

      Together with Gassnova (which represents the Norwegian government in matters relating to CCS), the South African integrated energy and chemical company Sasol, and Shell, we are building a centre for carbon dioxide capture technologies at Mongstad, known as the European carbon dioxide Technology Centre Mongstad (TCM). Sasol has signed a Memorandum of Understanding (MoU) to explore the possibility of becoming a participant in the TCM.

      The technology centre demonstration plant aims to help suppliers develop more cost-efficient, environmentally friendly and safe technologies for carbon dioxide capture to handle emissions from different flue gases, such as gas power, coal power and refineries. The plants will have the capacity to capture up to 100,000 tonnes of carbon dioxide annually, and store CO2 atthis therefore represent an important step towards full, industrial scale carbon dioxide capture. Construction activities are progressing according to plan after starting in summer 2009, and start up is scheduled for the end of 2011/early 2012.

      CCS business development
      Based on our experience from Sleipner, In Salah and Snøhvit and our experience of handling geological risk and developing large projects, Statoil is seeking CCS-related business opportunities. Provided that satisfactory commercial and legal conditions are in October 1996, it was the first of its kindplace, Statoil's ambition is to develop, own and operate profitable CCS projects, focusing on storage. However, to become an important tool in the world. Its implementation has meant a reduction in CO2fight against emissions of nearly one million tonnes per year, equivalentgreenhouse gases and combating climate change, CCS must become commercially viable.

      Potential storage sites are restricted to sedimentary basins that are distributed around the emissions from 400,000 cars.

    • The Snøhvit fieldworld. These basins are found both onshore and offshore, mostly in the Barents Sea now providesvicinity of land areas. Statoil has established a subsurface team dedicated to mapping and maturing future carbon dioxide storage. The ambition is to store our own carbon dioxide (for example from our own production of carbon dioxide-rich natural gas to Europe's first LNG (liquefied natural gas) production site. The Hammerfest LNG-plant at Melkøya will capture about 0.7 million tonnes of CO2 per yearstreams like Sleipner), and third party carbon dioxide (for example from the well stream when in full production. The CO2 will then be compressed and sent back to the offshore field for storage in a reservoir 2500 metres below the seabed.
    • StatoilHydro is a co-operator with BP in the In Salah field located in the middle of the Sahara Desert in Algeria. Since 2004, up to 1.2 million tonnes of CO2 have been captured and stored in the In Salah field per year.

    By using this experience as a base and placing the main focus on storage, StatoilHydro intends to generate new businesscarbon dioxide from CO2 management. The planned facilities at Mongstad will provide valuable experience in the transportation and storage of CO2.
    
    coal-fired power plants).

    Our business efforts within CO2activities in carbon dioxide also include the development of projects under the United Nations' Clean Development Mechanism (CDM) projects under the UN.. This activity builds on our CO2experience of carbon dioxide reduction experience withinfrom the oil and gas sector. Our main target regions are Mexico, China, and Indonesia. Country selection is based on CDM market conditions, StatoilHydro'sStatoil's presence in thatthe country and other criteria, such as emission data and sector attractiveness. Our main activities so far have been in Mexico and China.

     Top 

    3.5.3 Technology commercialisation
    development

    We are among the front runners in applying technology within the oil and gas industry.

    We achieve this by providing best practice support, devising world-class concepts for our development projects, and by leading established corporate initiatives to improve performance.

    Our Industry Development unit supports suppliers,technological expertise enhances our performance in areas such as exploration, improved oil recovery (IOR) and integrated operations (IO). Technology development is used to promote and achieve corporate targets for production growth, increased regularity, reduced costs and improved drilling efficiency.

    We also support innovators and entrepreneurs with their technology developments and commercialisation activities, thus helping to create robust suppliers and new technology products that are vital forto our oil, gas and new energy activities. The unit also supports industries and technology development in other countries where StatoilHydro has operations.
    
    Industrial Development acts as a catalyst by linking those developing new technology products to commercial activities and end users within StatoilHydro, providing funding and expertise, and taking strategic ownership in promising companies within the energy technology industry. Furthermore, StatoilHydroStatoil has ownership interests and engagementis involved in all the major Science Parks and Incubators in Norway.

    StatoilHydro activelyNorway, and benefits from venture activities to accessaimed at accessing new technologies. In the autumn of 2008 it was decided to strengthen this activity by establishing2009, we established a special purpose company, Energy Capital Management AS, to manage corporate venture activities within StatoilHydro.activities. This move represents a further focusfocuses on venture capital as a tool tofor accessing new technologies, and it will support StatoilHydro'sunderpin Statoil's technology strategy and help to capitalise on today's ownership positions withinin the venture business.

     Top 

    3.5.4 Technology development

    StatoilHydro is In addition, through the world's largest operator of offshore fields in water depths greater than 100 metres,LOOP programme, Statoil helps suppliers to develop new, innovative products and we have considerable experience in overcoming the challenges presented by harsh environments.

    Nevertheless, there is a need to rapidly utilise new technology to increase the resource base and maximise production.

    Technology & New Energy (TNE) is the centre of force for the development and implementation of new technology in the company. This is achieved by providing best practice support and expertiseservices for our operations, developing world-class technical concepts for our development projects, and leading established corporate initiatives in order to improve our performance in exploration, IOR and integrated operations. In this manner, TNE will support the other business areas in achieving corporate targets for production growth, increased regularity, reduced costs and improved drilling efficiency.business.

    Selected advances made in 20082009 are summarised below:

    Advanced seismic imaging for exploration
    OneMajor technological advances have been made for seismic imaging in complex geology. New state-of-the-art migration algorithms required to image sub-salt structures in the Gulf of Mexico and other salt provinces have been developed and qualified for use by the major challengesinternal imaging teams in exploration is to acquire the best seismic imageNorway and Houston. This new internal imaging capability will improve our capability in terms of the subsurface, even in areas with very complex geology,defining sub-salt plays and subsequently combine seismic data without compromising geological insights. Our Integrated Imaging workflow allows for improved integration of geologyprospects and geophysics in exploration subsurface imaging, leading to better subsurface interpretation in exploration and increases the probability of oil and gas discoveries.maturing drillable prospects. This methodadvance is a clear leaderkey short-term element in the exploration seismic imaging and interpretation initiative.

    Through-tubing rotary drilling
    New drilling and supports the company's quest to be the leading exploration company.

    well technology developed by Statoil and FMC Technologies will improve oil recovery from subsea fields. The first set of 3D electromagnetic data (EM) was retrieved from the Troll areatechnology has now been successfully tested on the Norwegian Continental Shelf this year. Increased insight into acquisition and interpretation technology of the Troll data increases the use of EMÅsgard field in the exploration workflowNorwegian Sea. This technology enables the reuse of old subsea wells in a simpler and adds significantly to the use of EM data for subsurface identification of oil and gas. Electromagnetic data has potentially siginificant applications in hydrocarbon explorationmore inexpensive way than before, by enabling the oil and gas to be detected in reservoirs instead of water. Combined with seismic data, the EM data can reduce uncertainty in exploration and lead to higher discovery rates.

    The massive volume of exploration data and need for efficient analysis to ensure exploration success has led to the development of a proprietary version of Google Earth. The StatoilHydro Earth Exploration Toolbox, visualized in the Google Earth environment, is a significant step towards quick access and interpretation of exploration data, leading to an effective workflow for evaluating subsurface prospectivity. Such workflows assist the rapid development of subsurface geology models and increase the probability of locating prospective areas and layers for discovery of oil and gas.

    StatoilHydro is now qualifyingdrilling a new down-hole drilling tool, the Rotary Steerable System (RSS), together with Schlumberger. These tools will be used to drill sidetracks from old wells without removingwell directly through the production tubing. A window outtubing in an existing well. The technology is estimated to have a great potential to increase oil production from subsea fields.

    Steerable liner drilling 9-5/8"
    The steerable drilling liner concept had its first successful pilot on the formation is madeBrage field in one side of the old well and the RSS tool is then used to drill a new hole outside the window.2009. This quick departure from the old well will dramatically increasetechnology improves the ability to reachdrill in depleted reservoirs that could not beand unstable formations, and it is an important tool for drilling infill wells in mature fields.

    Compact inline technology
    A compact cyclonic oil/water and gas/liquid separation unit has been developed. Full-scale pilot testing was carried out on Gullfaks this year. This type of inline technology has multiple areas of application. It is an important tool in relation to succeeding with subsea processing in deep waters such as efficiently reached before, if at all. The impressive steering characteristicsthe Gulf of Mexico. It is excellent for de-bottlenecking and tie-ins to existing platforms, and it presents future opportunities for unmanned platforms. It is Statoil-owned technology, licensed to FMC.

    Experience from mono ethylene glycol (MEG) regeneration systems
    Results from the start-up and operation of the tool also makeMEG system on Snøhvit and Ormen Lange have been summarised. The experience from these two MEG systems gives Statoil unique knowledge and understanding of the complex MEG chemistry and process, and it generates new ideas for how such systems can be improved to increase operational regularity.

    Laboratory experiments for thermal extra-heavy oil recovery
    An experimental rig has been constructed in Alberta, Canada to provide data for optimising the solvent co-injection process in order to reduce energy consumption (steam-oil ratio) and improve bitumen recovery efficiency compared with steam-assisted gravity drainage (SAGD). Two SAGD experiments have been successfully performed as part of providing the basis for studying solvent co-injection and developing expertise in this experimental technique. The solvent co-injection experiment has been completed, and the preliminary results are promising when compared with the two previous SAGD experiments. It is expected that solvent co-injection will reduce both CO2 emissions and water consumption. This has implications for both investments and operating costs.

    Hot tapping
    The world's deepest hot tap operation on a pressurised pipeline was performed on the Ormen Lange field in the Norwegian Sea in early August. Hot tapping operations involve carrying out repairs, replacements or tie-ins on pipelines that remain pressurised. That makes it possible to reach targets further awayavoid expensive shutdowns and simplifies the tie-in of new pipeline systems to existing infrastructure.

    Lander technology
    Lander technology is an important contributor to the paradigm shift that is taking place in environmental monitoring. Depending on the communication systems (physical downloading of data, cable, communication buoys) and how the lander systems are powered (batteries or from our installations/from land), the old wellmulti-sensor platform can measure and ultimately doublesend data in real-time. Since the numberlanders serve as a platform, different sensors will be deployed depending on the nature of targetsthe actual activity of interest. So far, a lander has been deployed in Nordland VII for measurement of background information on physical and recoverable reserves that can be reached with the usechemical condition in addition to measurement of this technology.biological fluxes.

    Current technology for capturing CO2 from flue gases is associated with significant energy requirements and large capital costs. Exhaust gas recirculation (EGR) is a method known to reduce costs and energy requirements, and StatoilHydro has monitored the technology for several years. A technology qualification programme is under development for EGR in connection with the General Electric Frame 9E gas turbines at Mongstad.

     Top 

    3.6 Projects

    3.6.1 Industry overview

    On the NCS, the trend is away from a portfolio of major development projects and towards subsea tie-in projects and complex redevelopment projects on existing installations where vital work must be timed to coincide with planned turnarounds.

    The growing portfolio makes the shortage of engineering competence just as critical as in previous years, with respect to the number of available engineering personnel and the competence and quality of work delivered. In addition, increased international activity is expected to challenge our ability to utilise our competence and allocate our resources in the most efficient way. As a result, there is a risk that engineering may be negatively affected, which in turn, may influence construction and completion progress.

    High activity levels on the NCS will make strong demands on our ability to execute projects as sanctioned and in accordance with our HSE target of zero harm. To succeed, we must challenge established models, ensure continuous improvement and establish best practice on the basis of experience.

    As regards physical deliveries of goods and services, we have only seen moderate price decreases while the oil price plunged during the second half of 2008. This remains a concern, and it means that our long term investment plans are being revised. However, we anticipate a high activity level in 2009.

     Top 

    3.6.2 Project development

    There

    Our projects portfolio is considerable diversity in our projects portfolio,very diverse, ranging from new projects and improvements to existing assets to generategenerating production growth on the NCS toand supporting the company's ambitions to become a global energy player.

    On the NCS,Completion of our two mega projects, Gjøa and Peregrino, will be our biggest milestones in 2010 and 2011. Moreover, several modification projects such as Gjøa, Tyrihans, Morvin and Alve will contribute to continued production growth. Ormen Lange Offshore and Statfjord Late Life are examples of complex projects that are expected to contribute toinvolve optimising production from existing assets.

    The following table gives a project overviewexisisting fields.

    Project completions 20092010 - 20102011	Type
    Offshore NCS	Alve, Gjøa Norne M, Ormen Lange Offshore, Troll 02 Template, Tyrihans, Vega
    	Modifications NCSHeidrun PPL upgrade
    	Brage Prod. Water Re-injection, Heimdal New Power Generator, KvitebjørnMorvin
    	Ormen Lange Southern Fields
    	Oseberg C mud module
    	Oseberg D Gas Capacity Upgrade, Treatment
    	Oseberg D HRSG
    	Oseberg F Low Pressure Prod., Production
    	Sleipner A 10 bar inlet pressure
    	Snorre A produced water upgrade
    	Snorre A Re-development, IOR, Snøhvit Improvement Project,
    	Snorre B produced water upgrade
    	Statfjord Late Life Troll A Compressors,
    	Tordis/Vigdis Control systems
    	Troll A Living Quarter Extension
    	Troll B gas injection
    	Troll C Low Pressure Production Veslefrikk Produced Water
    	Troll O2 Template,
    	Troll P12 Pipeline
    	Vega
    	Visund Nord
    	Åsgard Gas Transfer
    Onshore	Energiverk Mongstad Combined Heat and Power Plant, NOX Mongstad,
    	Statoil Mongstad Miljøinvestering (SMIL)
    	New Energy	HywindKårstø Double Inlet X-over (DIXO)
    	Kårstø NGL Metering station
    	Kollsnes projects
    International	In Salah Gas Compression
    	Leismer Demonstration, South Pars 6 - 8, Demo
    	Peregrino

    Another dimension of complexity to our business comes from executingExecuting projects internationally --- an essential part of fulfilling the group's ambitions to become a truly global energy player.player - adds a further element of complexity to our business. Examples of PRO's contributions in this respect are the Leismer Demonstration project and the In Salah and Peregrino projects.Gas Compression.

    ToIf we are to build an international reputation as a world-class implementer of projects, the way in which we deliver results is as important as the results themselves. That means delivering on time and cost, and without compromising high HSE and ethical standards.

     Top 

    3.6.2.1 Norwegian Continental Shelf

    We continue to strengthen our solid position on the NCS with several large and complex new development projects currently being executed.

    The largest project in our portfolio today is Gjøa, located west of the Sogn area. Gjøa is being developed with a semi-submersible production platform and five subsea templates The producing facility is designed in a way that makes it possible to process oil and gas from other smaller discoveries in the area in the future, such as Vega - a gas and condensate field that is being tied back to the platform in a joint pipeline.

    The Gjøa platform will be provided with land-based electricity from Mongstad that is estimated to avoid emissions of 240,000 tonnes of carbon dioxide per year, equivalent to the annual emissions from 100,000 cars. At production start-up, expected to be in the autumn of 2010, we will hand over the operatorship of Gjøa to Gaz de France .
    
    Tyrihans is a stand-alone subsea field development tied back to the Kristin platform. The field will be developed with four production/gas injection templates and one water injection template, with a total of 12 wells (eight oil producers, two gas injectors, one gas producer and one water injector).

    The Tyrihans field was discovered in 1982/1983 and the PDO was approved by the Norwegian authorities in February 2006.

    The remaining work prior to the estimated start-up in mid-2009 consists of topside modifications on Kristin and Åsgard B and delivery of the subsea production system and seawater injection system.

    Another ongoing project located on the Halten Bank is Morvin. Initially it was not regarded as commercially viable when it was discovered in 2001. However, an appraisal well in the summer 2006 verified sufficient recoverable reserves, and Morvin was subject to an accelerated development process. PDO was issued to the authorities on 1 February 2008, and approved 28 April 2008.

    Morvin is a High Pressure High Temperature field, and is being developed with technology solutions copied from Kristin. The two templates, with a total of four production wells, are tied in to Åsgard B, 20 kilometres away. Templates and production pipeline were installed during summer 2008 and topside installation work has commenced. Production start-up is scheduled for late 2010.

    The Yttergryta subsea gas and condensate field development is an example of a relatively small but unique project in our portfolio. The discovery was made in the summer of 2007, and production start-up took place on 5 Januar 2009, four months ahead of schedule. The wellstream is tied back to the Åsgard B platform for processing and further export.
    
    Ormen Lange Offshore is the second phase of the gigantic Ormen Lange gas field development. We currently have two separate ongoing projects on Ormen Lange; Southern Field Development and Subsea Compression Pilot. The purpose of these projects is to ensure optimal depletion from the field when the pressure in the reservoir drops. Groundbreaking work is now being done to qualify technology for subsea compression on Ormen Lange, and, if successful, the new technology could contribute to considerable cost savings, not only for the Ormen Lange partners, but for the entire oil and gas industry.

    The field was developed with seabed installations at depths down to 1100 metres, combined with an onshore plant at Nyhamna in Aukra municipality in Norway for processing and exporting the gas. The gas is exported through the world's longest subsea pipeline, Langeled, 1200 kilometres to Easington on the east coast of Britain. The gas can also be transported via the riser platform on the Sleipner field in the North Sea to customers on the European continent.

    Following a gradual increase in production over the first two to three years, the field is expected to produce 70 million standard cubic metres of gas per day.

     Top 

    3.6.2.2 Onshore facilities

    Large redevelopment programmes are currently underway at the Kårstø, Mongstad and Kollsnes production sites.

    A total of approximately NOK 14 billion is currently being invested to ensure regularity of gas production, to prepare for future volumes, and to ensure that future HSE requirements from authorities are met by sanctioned projects offshore.

    At Mongstad, the projects related to the construction of a Combined Heat and Power (CHP) plant are well underway. StatoilHydro is executing a major refinery upgrade and building a gas pipeline from Kollsnes to Mongstad in relation to this CHP plant. The latter has been completed by mid December 2008. In parallel, StatoilHydro is executing a large environmental project, called SMIL, which also is planned to be completed during 2009. The CHP plant is built and operated by DONG Energy and is planned to start up early in 2010.

    At Kårstø, several smaller projects have been gathered together in the Kårstø Expansion Project 2010 (KEP 2010). The first part is a compressor upgrade which will make it possible to increase the pressure, and thus enable more stability in the gas flow through the export pipelines leaving Kårstø. This sub-project was completed in fourth quarter of 2008.

    The second part of the project is a complete modernisation and upgrading of the security and control systems at the site, to prepare the plant for several more years of production and to meet stricter future HSE standards. A project replacing the NGL Metering stations was sanctioned late in 2008. The NGL Metering stations are planned to be started up by the end of 2011.

    The Kollsnes Flash Gas and Condensate project is an upgrade of the existing system due to capacity and regularity limitations. The installation of a new flash gas compressor train and a new condensate treatment train was completed by the end of December 2008 and will contribute to increasing production and operating regularity at the Kollsnes processing plant. In addition, capacity for future production of 40 million standard cubic metres per day is built into the system.

     Top 

    3.6.2.3 International

    We have a number of key projects taking place internationally, in such countries as Algeria, Canada, Brazil and the US.

    In Algeria we are involved in onshore gas production and exploration activities. The In Salah Gas Compression project is part of the original development plan for In Salah, and it consists of turbine and electricity-driven gas compressor facilities that will be installed at Reg, Teg and Kretchba, respectively. The purpose of the new compressor facilities is to counteract the declining production rates from the three fields. Construction work has started with site preparations, prefabrication of pipes and equipment delivery. The project is behind schedule, but mitigating actions have been implemented to secure the schedule and prevent further delays.
    
    The Leismer field is located in our oil sands lease in the Athabasca region in Alberta, Canada. The Leismer Demonstration project is the first oil sands development being undertaken by StatoilHydro, and is based on Steam Assisted Gravity Drainage (SAGD) technology to extract bitumen from the reservoir. The Central Processing Unit will have a processing capacity of 20 mboe per day. Four well pads have been constructed with a total of 22 well pair slots for steam injection and bitumen extraction. A 12 inch bitumen transport pipeline with a total capacity of 40 mboe per day and an eight inch diluents pipeline from site to Cheecham (length 71 kilometres) is also planned to be constructed. Civil engineering work on the processing site has been completed and installation of prefabricated modules for the processing unit is ongoing. Start-up of bitumen production is scheduled for late 2010.

    On 4 March 2008, StatoilHydro signed an agreement with Anadarko to purchase Anadarko's remaining 50% share of the Peregrino field in Brazil. The agreement also involves transfer of the operatorship to StatoilHydro, and we now hold a 100% ownership share in the field. The transfer of project responsibility took effect on 2 June 2008, and was formally approved by the Brazilian petroleum authorities, Agencia National de Petróleo, on 11 December 2008.

    The Peregrino field is located 85 kilometres off the Brazilian coast in approximately 100 metres of water. A development plan for Phase 1 was approved early 2007, containing two drilling and wellhead platforms and a floating vessel for production, storage and offloading of oil (FPSO). The first oil is planned to come on stream in 2011 and plateau production of 100 mboe per day is expected to be reached within the first year of production.

    The project is progressing according to schedule, and the two wellhead platforms are currently under construction at Kiewit's yard in Corpus Christi, Texas. The FPSO vessel, Mærsk Nova, is being upgraded at the Keppel Tuas yard in Singapore, while the process facility is being fabricated at the Keppel yard in Batam.

    On 12 December 2002, we became operator of the development of the offshore part of the South Pars phases six-seven-eight project in Iran. The South Pars offshore project phases six, seven and eight consist of three wellhead platforms with three pipelines for gas to shore, a condensate loading line and associated single point mooring (SPM) for condensate exports, the drilling of 27 production wells, the hook-up of three pre-drilled wells and required reservoir management.
    
    Gas production from South Pars phase eight started in August 2008 and from phase 6 in December 2008. Production from the third and final phase, South Pars phase seven, is expected to commence after the summer of 2009. Installation of the third and final rich gas export pipeline began in December 2008.

     Top 

    3.6.2.4 Redevelopments

    A major part of our project portfolio consists of activities relating to ongoing redevelopment efforts, aimed at maximising production from the NCS.

    As fields mature, production equipment needs upgrading. In the years ahead, a number of fields will need upgrading or renewal of drilling units, control systems, cranes and other major redevelopment efforts.

    We endeavour to organise these tasks as field projects in line with coordinated master plans for the different fields, such as the various redevelopment projects taking place at Statfjord, Troll and Oseberg, among others.

    The PDO for the Troll projects was submitted to the Ministry of Petroleum and Energy this summer. The Troll B Gas Injection project and the P12 pipeline to Kollsnes are both part of the PDO. The extension of the living quarters on Troll A and low-pressure production on Troll C are also vital projects in the Troll field.

    The various redevelopment projects related to the Oseberg field represent a substantial investment aimed at ensuring the vitality of the field in the coming years. Vital projects include low-pressure production on Oseberg F, a heat recovery steam generator on Oseberg D, upgrading of the drilling unit at Oseberg B and upgrading of the Oseberg C Mud module.

    Over the next few years, the Statfjord Late Life project will redevelop all three Statfjord installations from oil processing to gas processing facilities, thereby extending the lifetime of the field by several years. We expect the daily production of gas to exceed daily oil production on Statfjord in 2010.

     Top 

    3.7 People and the group

    The impact of the global economic turmoil on our employees and the labour market within our industry is not yet fully evident. We are planning for growth and need to maintain and further develop our core competencies.

    Our

    Statoil's overall strategic objective in 2008 has beenis to build a globally competitive company cultureand an exceptional place to perform and develop.

    The financial and economic turmoil that is basedcharacterised the global economy in 2009 has affected the entire industry, leading to a stronger focus on efficiency improvements and on the optimal use of existing resources. At the same time, the increase in business activities internationally requires Statoil to develop new capabilities to succeed globally and to attract talents in new countries.

    We have recently reviewed our global people policies to ensure consistent common standards across groups. Together with our values and driven by performance. In everyday work life, this means that we create a positive working environment that makesethical code of conduct, our people attracted to, inspired by and committed to our company.policies are the most important guidelines for furthering the people processes.

     Top 

    3.7.1 Our peopleEmployees in Statoil

    Our rapid international growth challenges our ability to maintain recruitment of highly skilled personnel from all countries in which we operate.

    StatoilHydro

    The Statoil group employs approximately 29,500 people worldwide. Our people29,000 permanent employees in 40 countries, and more than 18,000 of them are centralemployed in Norway, and approximately 11,000 were employed outside Norway. Of these, 9,399 were employed in the retail business.

    In 2009, the Statoil group recruited almost 3,700 new employees, 50% were recruited to the delivery of the StatoilHydro business strategy and sustainable development policy. In 2008 we continued to advance our people strategy, which focuses mainly on integrating post-merger best practices, maintaining cooperation with our unions, recruiting, developing skills and improving employee performance.retail organisation.

    At 31 December 2008 and 31 December 2007, we had 29,500 employees worldwide. The table below provides the number of employees at year-end for each of the past 3 years and a breakdown of employees by geographic location.

    Number of employees	As of 31 December
    	2008	2007	2006
    Norway	18,001	18,102	13,987
    Rest of Europe	10,460	10,095	11,015
    Africa	145	101	49
    Asia	338	206	203
    South America	103	71	59
    North America	449	317	95
    IS Partner*		611
    Total	29,496	29,503	25,408
    * IS Partner is an information systems service provider that was sold to an external party in
    February 2008. The employees are primarily situated in Norway.

    The increase in employees by approximately 4100 or 16% from 2006 to 2007 can be primarily attributed to the merger between Statoil ASA and Hydro oil and energy activities.

    Cooperation with Unions. Our cooperation with the unions has been improved, by redefining the agreement between the parties in ICEM. Our process for people performance, development and deployment has been simplified and improved.

    Recruiting. The percentage of non-Norwegians working at our various locations in Norway has increased from 5.12% in December 2007 to 5.88% in December 2008. AtBy the end of 2008, 11,400, or 39% of our people2009, 35% were employed outside Norway.

    StatoilHydro is a knowledge and technology-based company and our people are highly qualified to do their work: 56% ofunder the employees in StatoilHydro ASA have a university or college background, and having 27% have a craft certificate. StatoilHydro employs the most apprentices in Norway, with 176 apprentices joined our company in 2008. The total number of apprentices in StatoilHydro at December 2008 was 337.

    At the end of December the average age of our employees at StatoilHydro ASA was 44 and the majority of our people, 69%,35, 57% were between 35 and 55 years old, while 19.5%and 8% were 55 years or older. The table below provides an overview of our people were less than 35 years old.the number of permanent employees and percentage of women in the Statoil group from 2007 to 2009.

    	Number of employees			Women
    Geographical Region	2009	2008	2007	2009	2008	2007
    Norway	18,100	17,891	17,959	31%	30%	29%
    Rest of Europe	9,593	10,475	10,151	50%	47%	46%
    Africa	165	144	117	28%	32%	34%
    Asia	150	169	144	55%	54%	52%
    North America	584	448	315	34%	39%	33%
    South America	147	102	72	48%	53%	53%
    TOTAL	28,739	29,229	28,758	37%	35%	37%
    Non - OECD	2,703	3,009	2,904	64%	65%	66%

    * Service station personnel are included

    Geographical Region	Permanent employees 2009	Consultants	Total Workforce*	Consultants**	% of part time	New hires
    Norway	18100	5309	23409	23%	4.5	1310
    Rest of Europe	9593	4556	14149	32%	7.2	2113
    Africa	165	41	206	20%	N/A	29
    Asia	150	36	186	19%	N/A	13
    North America	584	281	865	32%	N/A	172
    South America	147	104	251	41%	N/A	62
    TOTAL	28739	10327	39066	26%	N/A	3699***
    Non - OECD	2703	314	3017	10%	N/A	288
    *Total workforce consists of number of permanent employees and consultants
    ** Consultants do not include enterprise personnel
    *** 1843 of these were recruited to the retail business

    Statoil's low turnover rates reflect a high level of satisfaction and engagement among its employees, which is also supported by the results of the annual organisational and working environment survey. In 2008,Statoil ASA, the overalltotal turnover at StatoilHydro ASArate for 2009 was 1.9%0.73%. The figure below provides an overview of the total turnover percentage for women was 1.5%,rate by gender and for men 2.1%.age in Statoil ASA

    

     Top 

    3.7.2 DiversityEqual opportunities

    We are committed to building a workplace that promotes diversity and equality

    inclusion through its people processes and practices.

    We promote diversityIn December 2009, the overall percentage of gender, age and ethnicity among our employees.

    The importance of diversity is statedwomen in our values and in our ethical codes of conduct. We aim to create the ame opportunities for all of our employees, regardless of gender, age on ethnicityand do not tolerate discrimination or harassment of any kind in our workplace.

    By December 2008,company was 37% of our people were women,, and 40% of the members on our board of directors were women.women, as were 22% of the corporate executive team. The focus on diversity issues is also reflected in the company's people strategy. One of the key priorities in 2009 has been to strengthen diversity in the leadership pipeline. The total proportion of female managers in Statoil ASA is 27%25%, and, among managers under the age of 45, the proportion is 35%34%. Moreover,

    Through our development programmes, we aim to increase the number of female managers, and we endeavour to give equal representation to men and women in leadership development programmes. In 2009, we worked systematically on the development, deployment and succession planning of business-critical leadership positions. Of leaders promoted to the top 170 roles in 2009, 47% were female. Of the 84 senior vice presidents in Statoil, 24% are relatively well represented in the technical disciplines. In 2008, 25%female, while 35% of our successor pool for these roles are female.

    We also devote close attention to male-dominated positions and discipline areas. In 2009, 26% of staff engineers were women, and among staff engineers with up to 20 years' experience, the proportion of women is 28%31%. The proportion of female skilled workers in 2008 is 18%2009 was 16%.

    We work systematically with recruitment and development programmes in order to increase the number of women in male-dominated positions and discipline areas.

    The reward system in StatoilHydroStatoil is gender neutral, meaningnon-discriminatory and supports equal opportunities, which means that, men and women withgiven the same position, experience and performance, men and women will be at the same salary levels.level. However, due to differences between women and men in types of positions and numbersnumber of years' experience, between women and men,there are some differences in compensation appear when comparing the general wagepay levels of men and women. On average, the earnings of female skilled workers are 93%

    

    Cultural diversity
    We believe that being a global and sustainable company requires people with a global mindset. One way to build a global company is to ensure that recruitment processes both within and outside Norway contribute to a culturally diverse workforce. In December 2009, 4% of the earningsmanagers and 7% of their male colleagues. Therethe rest of our employees based in our Statoil offices in Norway are no significant differences betweenof non-Norwegian origin. Outside Norway, we need to continue to focus on increasing the earningsnumber of femalepeople and male staff engineers.managers that are locally recruited, and to reduce long-term, extensive use of expats in our business operations.

     Top 

    3.7.3 Integration

    In 2007 we completed the first phase of the integration between Statoil and Hydro. In 2008 we started the integration of our operational units.

    One of our main actions in 2008 has been to complete the integration of our operating organisation in EPN, M&M and NG and to ensure a successful post-merger process for the parts of the organisation that were integrated in 2007.

    During the first half of 2008, the integration planning committee, which consists of representatives from the corporate executive committee and the labour unions, has been involved in planning and designing the new operating model. From the 2nd quarter of 2008 and throughout 2009, project teams in the business areas that are involved in the second phase of the integration will complete the manning process and implement changes that the new operating model requires.

    We have also carried out an integration monitoring survey which measures progress and satisfaction between our people and the merger process every three months. The results from 2008 indicate that the staff who were integrated in 2007 increasingly feel that they are being well taken care of, and that they have influence in decisions regarding their own working situation. For our people undergoing the integration in 2008 and 2009, the results are less positive.

    Several activities have been carried out in order to ensure a successful post-merger process for the employees that were integrated in 2007. An integration research team, consisting of external researchers from the three research institutions International Research Institute of Stavanger, Institute for Research in Economics and Business Administration (SNF) and FAFO, have been assigned to deliver an independent evaluation of the entire integration process. The research programme will run for three years. So far, 13 professors and researchers, one PhD-candidates and 13 master students have been able to generate new knowledge and research about mergers and organisational outcomes based on data material and observations from the ongoing integration process in our company.

    In 2009 one of our major post-merger activities will be to further strengthen the common and integrated company identity by launching our new vision and company name.

     Top 

    3.7.4 Unions and representatives

    We emphasise the value of cooperation with our employees, and 69% of staff (StatoilHydro ASA) are members of a labour union. Our

    Statoil's cooperation with employee representatives and labourtrade unions is based on confidence, trust and trust.

    StatoilHydro emphasizescontinuous dialogue between management and the value of cooperation with its employees, andpeople in various cooperative bodies.

    In Statoil, 69% of the employees in the parent company are members of a labourtrade union.
     
    Work councils and working environment committees are established where required by law or agreement.

    In 2009, one of Statoil's cooperation priorities has been to improve relations with European employee representatives. The way the company and theEuropean Work Council (EWC) consists of employee representatives work togetherfrom nine European countries, mostly from the retail side of the business. The EWC is illustratedan arena where Statoil's employees in Europe receive relevant information on a regular basis, and engage in direct dialogue with management on matters concerning the integration process between group as a whole. Two conferences were held for this purpose in 2009.

    Statoil and Hydro described above.

    Theis also currently party to an international agreement with ICEM (Linkthe International Federation of Chemical, Energy, Mine and General Workers Union (ICEM). This agreement supports and facilitates Statoil's ambition to ICEM), which is an international federation that represents trade unions worldwide, was renewed in 2008. We were the first company in the oilfurther promote and gas industry to sign this agreement. The cooperation with ICEM enables exchange of informationdevelop good employee and further development of good working practices within our operations worldwide. Theindustrial relations on a broad global basis and its content in the agreement reflects our policies and values on areas such as industrial relations, human rights and labour standards and HSE.

    Since 2007, Statoil has undergone major organisational changes as a result of the merger between Statoil and Hydro's oil and gas division. In 2009, Statoil finalised the merger by implementing its new operating model on the Norwegian continental shelf, which affected 5000 offshore employees. The unions and the company agreed on the principles for the new collaboration model, which involve simplifying and decentralising the model.

     Top 

    3.7.53.7.4 Organisational structure

    The following table shows significant subsidiaries owned directly by the parent company, as well as the parent company's equity interest and the subsidiaries\'subsidiaries' country of incorporation. In each case our

    Our voting interest is in each case equivalent to our equity interest.

    Ownership in certain subsidiaries (in %)
    		Country of incorporation				Country of incorporation
    Name	%			Name	%		%	Country of incorporation	Name	%	Country of incorporation
    AS Eesti Statoil	100	Estonia		Statoil Nigeria Outer Shelf AS	100	Norway
    Latvija Statoil SIA	100	Lativia		Statoil Norge AS	100	Norway
    SIA Statoil Latvija							100	Latvia	Statoil Norge AS	100	Norway
    Statholding AS	100	Norway		Statoil North Africa Gas AS	100	Norway	100	Norway	Statoil Norsk LNG AS	100	Norway
    Statoil AB	100	Sweden		Statoil North Africa Oil AS	100	Norway	100	Sweden	Statoil North Africa Gas AS	100	Norway
    Statoil Angola Block 15 AS	100	Norway		Statoil North America Inc.	100	United States	100	Norway	Statoil North Africa Oil AS	100	Norway
    Statoil Angola Block 15/06 Award AS	100	Norway		Statoil Orient Inc AG	100	Switerzland	100	Norway	Statoil North America Inc.	100	United States
    Statoil Angola Block 17 AS	100	Norway		Statoil Polen Invest AS	100	Norway	100	Norway	Statoil Orient AG	100	Switzerland
    Statoil Angola AS	100	Norway		Statoil Sincor AS	100	Norway
    Statoil Angola Block 31 AS							100	Norway	Statoil Petroleum AS	100	Norway
    Statoil Apsheron AS	100	Norway		Statoil SP Gas AS	100	Norway	100	Norway	Statoil Polen Invest AS	100	Norway
    Statoil Asia Pacific Pte. Ltd.	100	Singapore		Statoil (UK) Ltd	100	United Kingdom
    Statoil Azerbaijan Alov AS	100	Norway		Statoil Venezuela AS	100	Norway
    Statoil Azerbaijan AS	100	Norway		StatoilHydro Canada Ltd.	100	Canada	100	Norway	Statoil Sincor AS	100	Norway
    Statoil BTC Finance AS	100	Norway		StatoilHydro Orinoco AS	100	Norway	100	Norway	Statoil SP Gas AS	100	Norway
    Statoil Coordination Center N.V.	100	Belgium		StatoilHydro Petroleum AS	100	Norway
    Statoil Danmark A/S	100	Denmark		StatoilHydro Russia AS	100	Norway
    Statoil Coordination Centre NV							100	Belgium	Statoil UK Ltd	100	United Kingdom
    Statoil Danmark AS							100	Denmark	Statoil Venezuela AS	100	Norway
    Statoil Deutschland GmbH	100	Germany		StatoilHydro Venture AS	100	Norway	100	Germany	Statoil Venture AS	100	Norway
    Statoil do Brasil Ltda	100	Brazil		Statpet Invest AS	100	Norway
    Statoil Exploration Ireland Ltd	100	Ireland		UAB Lietuva Statoil	100	Lithuania
    Statoil Exploration Ireland Ltd.							100	Ireland	Statpet Invest AS	100	Norway
    Statoil Forsikring AS	100	Norway		Statoil Metanol ANS	82	Norway	100	Norway	UAB Lietuva Statoil	100	Lithuania
    Statoil Hassi Mouina AS	100	Algeria		Mongstad Refining DA	79	Norway	100	Norway
    Statoil Iran AS	100	Norway		Mongstad Terminal DA	65	Norway
    Statoil New Energy AS							100	Norway	Statoil Methanol ANS	82	Norway
    Statoil Nigeria AS	100	Norway		Tjeldbergodden Luftgassfabrikk DA	51	Norway	100	Norway	Mongstad Refining DA	79	Norway
    Statoil Nigeria Deep Water AS	100	Norway					100	Norway	Mongstad Terminal DA	65	Norway
    Statoil Nigeria Outer Shelf AS							100	Norway	Tjeldbergodden Luftgassfabrikk DA	51	Norway

     

     Top 

    3.8 OilProduction volumes and price information

    Statoil's operational review is in accordance with the organisation of its operations, whereas certain disclosures about oil and gas reserves are based on geographical areas as required by the SEC.

    Statoil prepares its operational review in accordance with its segment (business area) structure. Each business area is presented individually, and includes underlying business clusters according to how the business area organises its operations.

    For further information on extractive activities, refer to sections 3.1 Operational review - E&P Norway and 3.2 Operational review - International E&P for descriptions of Exploration and Production Norway and International Exploration and Production, respectively.

    Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures based upon geographical areas as required by the SEC. The geographical areas are defined by continent, and consist of Eurasia, Africa and the Americas. Relevant information is further split into Norway and Eurasia excluding Norway.

    For further information on disclosures for oil and gas reserves and certain other supplemental disclosures based upon geographical areas as required by the SEC, refer to this section 3.8 Operational review - Production volumes and price information and 3.9 Operational review - Proved oil and gas reserves.

     Top 

    3.8.1 Entitlement production

    This section describes our oil and gas production and sales volumes.

    The following table sets outshows our Norwegian and international entitlement production of crude oil and natural gas for the periods indicated. The stated production volumes are the volumes that StatoilHydroStatoil is entitled to in accordance withpursuant to conditions laid down in concessionlicence 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.flaring. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian State'sstate's oil and natural gas. Production of extra heavy oil from the field Petrocedeño in Venezuela is included as crude oil.

    Production	For the year ended 31 December
    				For the year ended 31 December
    Entitlement production				2009	2008	2007
    	2008	2007	2006
    Norway
    Crude oil (mmbbls)1	302	299	315
    Crude oil (mmbbls)1				279	302	299
    Natural gas (bcf)	1,348	1,238	1,250	1367	1348	1238
    Natural gas (bcm)	38.2	35.1	35.4	38.7	38.2	35.1
    Combined oil and gas (mmboe)	542	519	539	523	542	519
    International
    Crude oil (mmbbls)1	85	92	70
    Eurasia excluding Norway
    Crude oil (mmbbls)1				19	n/a
    Natural gas (bcf)				49	n/a
    Natural gas (bcm)				1.4	n/a
    Combined oil and gas (mmboe)				28	n/a
    Africa
    Crude oil (mmbbls)1				63	n/a
    Natural gas (bcf)				54	n/a
    Natural gas (bcm)				1.5	n/a
    Combined oil and gas (mmboe)				73	n/a
    America
    Crude oil (mmbbls)1				20	n/a
    Natural gas (bcf)				48	n/a
    Natural gas (bcm)				1.4	n/a
    Combined oil and gas (mmboe)				29	n/a
    Outside Norway
    Crude oil (mmbbls)1				n/a	85	92
    Natural gas (bcf)	121	114	84	n/a	121	114
    Natural gas (bcm)	3.4	3.2	2.4	n/a	3.4	3.2
    Combined oil and gas (mmboe)	106	112	85	n/a	106	112
    Total
    Crude oil (mmbbls)1	386	391	385
    Crude oil (mmbbls)1				381	386	391
    Natural gas (bcf)	1,469	1,352	1,335	1519	1469	1352
    Natural gas (bcm)	41.6	38.3	37.8	43.0	41.6	38.3
    Combined oil and gas (mmboe)	648	632	624	652	648	632
    1 Crude oil includes natural gas liquids (NGL) and condensate production. NGL includes both LPG and naphta
    1) Crude oil includes natural gas liquids (NGL) and condensate. NGL includes both LPG and naphta.				1) Crude oil includes natural gas liquids (NGL) and condensate. NGL includes both LPG and naphta.

    Sales Volume Information
    In addition to our own volumes, we market

     Top 

    3.8.2 Average production cost and sell oil and gas owned by the Norwegian State through the Norwegian State's share in production licences, known as the State's direct financial interest, or SDFI, together with our own production. For additional information see section 3.13 Operational review-Related party transactions. sales prices

    The following table sets out SDFItables present the average unit of production cost based on entitlement volumes and StatoilHydrorealised sales volumeprices. The information has been split by continent for crude oil and natural gas, as applicable,2009, while this split is not available for the periods indicated. The SDFI volumes shown below include royalty oil we sell on behalf of the Norwegian State. The payment of royalty obligations on the NCS was abolished on 31 December 2005. The StatoilHydro natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International E&P and ethane volumes.prior periods.

    Sales Volumes	Year ended December 31,
    	2008	2007	2006
    StatoilHydro: (1)
    Crude oil (mmbbls) (2)	372	395	382
    Natural gas (bcf)	1,387	1,257	1,334
    Natural gas (bcm) (3)	39	36	38
    Combined oil and gas (mmboe)	619	619	620
    Third party volumes: (4)
    Crude oil (mmbbls)(2)	242	240	200
    Natural gas (bcf)	127	177	152
    Natural gas (bcm) (3)	4	5	4
    Combined oil and gas (mmboe)	265	271	227
    SDFI assets owned by the Norwegian State (including royalty):
    Crude oil (mmbbls) (2)	213	235	254
    Natural gas (bcf)	1,440	1,327	1,168
    Natural gas (bcm) (3)	41	38	33
    Combined oil and gas (mmboe)	470	472	462
    Total
    Crude oil (mmbbls) (2)	827	869	836
    Natural gas (bcf)	2,955	2,760	2,655
    Natural gas (bcm) (3)	84	78	75
    Combined oil and gas (mmboe)	1,353	1,361	1,309
    (1) The StatoilHydro volumes included in the table above assume that volumes sold were equal to lifted volumes in the relevant year. This differs from the sales volumes reported elsewhere in this report by the Oil Trading and Supplies (OTS) organisation in the Manufacturing and Marketing segment in that such volumes include volumes still in inventory or transit held by other reporting entities within the group. Excluded from such volumes are volumes lifted by the International E&P but not sold by OTS, and volumes lifted by E&P Norway or International and still in inventory or in transit.
    (2) Sales volumes of crude oil include NGL and condensate. All sales volumes reported in the table above include internal deliveries to our manufacturing facilities.
    (3) At a gross calorific value (GCV) of 40 MJ/scm.
    (4) Third party volumes of crude oil include both volumes purchased from partners in our upstream operations and other cargos purchased in the market. The third party volumes are purchased either for sale to third parties or for our own use. Third party volumes of natural gas include third party LNG volumes related to our activities at the Cove Point regasification terminal in the U.S.

    	Norway	Outside Norway
    Year ended 31 December 2008
    Average sales price liquids in USD per bbl	91.5	88.7
    Average sales price natural gas in NOK per Sm3	2.4	1.3
    Average production cost in NOK per boe	37.3	42.2
    Year ended 31 December 2007
    Average sales price liquids in USD per bbl	70.9	69.1
    Average sales price natural gas in NOK per Sm3	1.69	1.17
    Average production cost in NOK per boe	46.3	34.4

    	Norway	Eurasia excluding Norway	Africa	America
    Year ended 31 December 2009
    Average sales price liquids in USD per bbl	57.8	58.2	57.8	61.7
    Average sales price natural gas in NOK per Sm3	1.9	0.6	1.4	0.9
    Average production cost in NOK per boe	36.9	55.2	40.9	45.3

     

     Top 

    3.9 Proved oil and gas reserves

    Proved oil and gas reserves were estimated to be 5408 mmboe at the end of 2009, compared with 5584 mmboe at the end of 2008, compared to 6010 mmboe at the end of 2007.

    2008.

    Proved reserves and changes toin proved reserves are estimated in accordance with SEC definitions. As of 31 December 2009 Statoil's estimates reflect the revisions to Rule 4-10 of SEC Regulation S-X on the definitions of reserves. For additional information see "Critical accounting judgements and key sources of estimation uncertainty; Proved oil and gas reserves" in note 2 Significant accounting policies to the consolidated financial statements. For prior period figures, see note 35 Supplementary oil and gas information to the consolidated financial statements. The reserves replacement ratio is defined as the sum of proved reserves additions and revisions of proved reserves, divided by produced volumes in any given period.

    Summary of oil and gas reserves as of 31 December 2009 based on average fiscal-year prices.

    	Proved reserves
    	Oil and NGL	Natural Gas	Total oil and gas
    Reserves category	(mmbbls)	(bcf)	(mmboe)
    Developed
    Norway	1,028	14,138	3,548
    Eurasia excluding Norway	94	523	187
    Eurasia	1,122	14,661	3,735
    Africa	208	256	254
    America	111	73	124
    Undeveloped
    Norway	322	2,800	821
    Eurasia excluding Norway	44	224	84
    Eurasia	366	3,024	905
    Africa	102	83	116
    America	265	51	274
    Total proved reserves	2,174	18,148	5,408

    

    

    Changes in proved reserves estimates most commonly originate from revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or the inclusion of proved reserves in new discoveries through the sanctioning of development projects. These are sources of additions to 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 maycan also be added or subtracted through acquisitions or disposals of assets.

    Changes in proved reserves maycan also originate frombe due to factors outside management control, such as changes in oil and gas prices. Proved reserves as of 31 December 2009 have been determined based on a 12 month average price, whereas proved reserves for previous years are based on year end prices. While lowerhigher oil and gas prices normally allow lessmore oil and gas to be recovered from the accumulations, StatoilHydro'sStatoil's proved oil and gas reserves under PSAs and similar contracts will generally increasedecrease as a result. StatoilHydroStatoil will receive largersmaller quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of the decreasedincreased oil and gas prices. These changes are included in the revisions category in the table below.'

    

    Reserves in new discoveriesIn Norway, reserves are normally booked onlyas proved when a development plan is submitted, since there is reasonable certainty that such a plan will be approved by the regulating authorities. Outside of Norway, reserves are booked as proved when regulatory approval has beenis received, or when such approval is imminent. Reserve additions from newNew discoveries with reserves booked in 2008 are expected to be produced2009 all start production in the period from year 2009 to 2021.2013. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years.

    Additions that have contributed to our proved reserves in 2009 are:
    Extension and discoveries that have increased our proved reserves in 2009 are:

    • The Goliat field in the Bartents Sea in Norway, Kizomba satellites phase 1 in Angola and the Caesar Tonga Unit in Gulf of Mexico, USA, were sanctioned in 2009.
    • The Beta Vest structure, an extension to the Sleipner Vest field, proved hydrocarbons by drilling in 2009.
    • The Gimboa field in Angola commenced test production in April 2009.
    • The PSVM development in Angola was approved by the concessionaire in 2008 and is carrying proved reserves in 2009.
    • The Marcellus Shale Gas play in the USA, part of our gas value chain strategy, carries proved reserves in 2009.

    Approval of future development plans for several of our producing fields on the NCS has contributed positively to revision of proved reserves:

    • On the Oseberg field, a decision to upgrade existing drilling facilities allows for more wells to be drilled, resulting in increased reserves.
    • On the Rimfaks field, a decision of pressure depleting the Brent reservoir has increased the reserves.
    • On the Kvitebjørn field, a project has been approved that will allow for production at lower reservoir pressure through installation of a compressor module, thereby increasing the reserves.

    In December 2008, the SEC issued new rules for reporting of oil and gas reserves by revising the definition of proved reserves. The technical aspects of the new rules have affected our proved reserves from certain fields:

    • At the Kai Kos Dehseh leases in the Athabascan area in Canada, the Leismer Demonstration Project is able to book proved reserves for the first time, referring to several analogous reservoirs in the Athabascan area where reserves are currently produced using the SAGD technology. The project was sanctioned in 2008 and is scheduled to start production in 2010.
    • Future extension of the licence period is now assumed reasonably certain on the NCS, increasing the proved reserves for certain fields.
    • Some fields, previously limited by lowest known hydrocarbons, have been included in the proved reserves based on a lower contact established with reasonable certainty based on reliable technology.

    The effect of the new rules on our total proved reserves is however immaterial and is estimated to be less than 2%. This estimate includes the effect of the change in product price to be used, from year end price to a 12 month average price.

    Below is a table showing the reserves additions in each change category relating to the reserve replacement ratio for the years 2009, 2008 2007 and 2006. 2007.

    	For the year ended 31 December
    (million boe)	2008	2007	2006
    Revisions and improved recovery	213	325	300
    Extensions and discoveries	17	215	86
    Purchase of petroleum-in-place	69	0	0
    Sales of petroleum-in-place	(10)	0	(3)
    Change in interest *	(68)	0	0
    Total reserve additions	222	541	383
    Production	(648)	(632)	(624)
    Net change in proved reserves	(426)	(91)	(241)
    * Reduction of interest in Petrocedeño

    A total of 222 mmboe proved reserves was added during 2008, of which 186 mmboe were proved developed reserves. The remaining 36 mmboe were proved undeveloped reserves.

    	For the year ended 31 December
    (million boe)	2009	2008	2007
    Revisions and improved recovery	326	213	325
    Extensions and discoveries	155	17	215
    Purchase of petroleum-in-place	0	69	0
    Sales of petroleum-in-place	(4)	(10)	0
    Change in interest *	0	(68)	0
    Total reserve additions	476	222	541
    Production	(652)	(648)	(632)
    Net change in proved reserves	(176)	(426)	(91)
    * Reduction of interest in Petrocedeño

    The reserves replacement ratio was 73% in 2009, compared with 34% in 2008, compared to 86% in 2007.2008. The decreaseincrease in the reservereserves replacement ratio in 20082009 compared to 2007with 2008 is mainly due to 20082009 being a year with small reservemore reserves additions from sanctions of new fields and sanctioned future development projects and high production.plans for producing fields. The average replacement rate for the last three years was 60%64%, including purchases, sales and reduction of sharehold interestthe shareholding in Petrocedeño. o in 2008.

    	For the year ended 31 December			For the year ended 31 December
    Reserves replacement ratio (three-year average)	2008	2007	2006	2009	2008	2007
    Corporate	0.60	0.81	0.76	0.64	0.60	0.81
    E&P Norway	0.51	0.78	0.62
    International E&P	1.10	0.98	1.74

    The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity related to the timing of project sanctions, and the time lag between exploration expenditure and booking of reserves.

    We review our petroleum reserves in the course of business as new information becomes available. This information can be related to remaining reserves, existing production performance, decisions related to development, production, acquisition and divestmentPreparation of reserves and changes in economic conditions. In addition, information onestimates
    Statoil's annual proved oil and gas reserves standardised measure of discounted net cash flows related to proved oil and gas reserves, and other information related to proved oil and gas reserves reported in note 34 - Supplementary oil and gas information - to our Consolidated Financial Statements,reporting process is collected and checked for consistency and conformity with applicable standardscoordinated by a central group thatof experts. This group is called Corporate Exploration and Production Forecasting (CEPF) and consists of experts within geosciences, reservoir and production technology and financial evaluation with on average more than 20 years of experience from the oil and gas industry. The CEPF group reports to the Vice President of Finance and Control in the Technology and New Energy business area and is thus independent of both E&P Norway and the exploration and productionInternational E&P business units.areas.

    Although this group reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Before presentingInformation about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves, is collected from the assets and checked for consistency and conformity with applicable standards by CEPF. The final numbers for each asset are quality controlled and signed off by the responsible asset manager before aggregation to required reporting level by CEPF.

    The aggregated results are brought forward for approval to relevant Business Area management teams and the managementcorporate executive committee and finally presented to the board of directors.

    The technical person primarily responsible for overseeing the relevant business unitspreparation of the reserves estimates is the manager of the CEPF group. The person who presently holds this position has a Bachelor's Degree in Earth sciences from the University of Gothenburg, and a Master's degree in Petroleum Exploration and Exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 24 years of experience in the Chief Executive Officer, this central group asks DeGolyeroil and MacNaughton, independent petroleum engineering consultants, to perform an independent evaluationgas industry of which 23 are within Statoil. She is a member of the Norwegian Petroleum Society and a vice chairperson of the UNECE Expert Group on Resource Classification (EGRC).

    Development of reserves
    Total quantity of proved reserves. This was last performedundeveloped oil and gas reserves as of 31 December 2008.2009 was 1 295 mmboe of which 63% is related to fields in Norway. Significant undeveloped reserves are related to large gas fields on the NCS with continuous development activity, such as Troll, Snøhvit, Tyrihans, Visund and Ormen Lange.

    Due to the nature of large fields with continuous development activity such as Troll and Snøhvit in Norway, Azeri-Chirag-Gunashli in Azerbaijan and Petrocedeño in Venezuela, these fields contain reserves that remain undeveloped for five years or more. The Troll phase 3 development activity includes start-up of production from additional wells in 2024 while the Snøhvit development activity includes start-up of production from additional wells in the Askeladden structure in 2017, both to maintain the plateau production. The development activity for Azeri-Chirag-Gunashli and Petrocedeño include continuous drilling beyond 2015.

    Fields under development but not yet in production, such as Skarv, Gjøa and Goliat in Norway, CaesarTonga in GoM USA, Corrib in Ireland, Leismer Demonstration Project in Canada, Peregrino in Brazil and Kizomba satellites in Angola represent approximately 30% of the total proved undeveloped reserves at year end 2009.

    The results obtainedsanctioning of new projects such as CaesarTonga in the GoM and Marcellus in the USA, Goliat in Norway, the Leismer Demonstration Project in Canada and the Kizomba satellites and PSVM in Angola added a total of 128 mmboe of proved undeveloped reserves in 2009. Start of production and further development of producing fields contributed to converting reserves from undeveloped to developed. The net change in proved undeveloped reserves during 2009 represents a reduction of 60 mmboe.

    Start of production from the fields Alve, Yttergryta and Tyrihans in Norway, Tahiti and Thunder Hawk in GoM USA, Marcellus in USA and Gimboa in Angola increased our developed reserves by DeGolyer and MacNaughton do not differ materially224 mmboe in 2009. Most of this increase came from those reported by us when compared on the basis of net equivalent barrels of oil. DeGolyer and MacNaughton have provided us with a summary letter report describing their procedures and conclusions, a copyconverting undeveloped reserved into developed reserves.

    In 2009 Statoil incurred NOK 56.9 billion in development costs related to assets carrying proved reserves, of which is included in the following report section.NOK 29.9 billion were related to moving proved undeveloped reserves to developed.

    Reserve engineering is a process of forecasting the recovery and sale ofAdditional information about proved oil and gas from a reservoir andreserves is provided in part subjective. It is clearly associated with considerable uncertainty, both positive and 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 note 3435 - Supplementary oil and gas information - to our Consolidated Financial Statements,Statements.

    Delivery commitments
    From the Norwegian Continental Shelf (NCS) Statoil is required, on behalf of the Norwegian State's direct financial interest (SDFI), to manage, transport and sell the Norwegian State's oil and gas. These reserves are sold in conjunction with our own reserves. As part of this arrangement, Statoil will deliver gas to customers in accordance with various types of sales contracts. In order to fulfil the commitments, Statoil will utilise a field supply schedule which provides the highest possible total value for further detailsthe joint portfolio of oil and gas between Statoil and SDFI.
    
    As at 31 December 2009, the Statoil/SDFI arrangement amounted to a total of 29.5 tcf (835 bcm) in total expected gas commitments on the NCS. The principles for booking of proved reserves are limited to contracted gas sales or gas with access to a robust gas market.

    The majority of Statoil's gas volumes are sold under long term contracts with Take or Pay clauses. For each individual year, Statoil and SDFI express their delivery commitments as the sum of the Annual Contract Quantity (ACQ). In the contract years 2009 to 2012, the joint ACQ for the respective years are; 2.50, 2.43, 2.39, and 2.40 tcf. The majority of delivery commitments will be fulfilled by production from our existing proved reserves.reserves from fields where Statoil and/or SDFI participates, while any shortfalls would be covered by sourcing existing gas markets.

     Top 

    3.9.1 Operational statistics

    Operational statistics include information about acreage and the number of wells drilled.

    Productive oil and gas wells and developed and undeveloped acreage
    The following tables show the number of gross and net productive oil and gas wells and total gross and net developed and undeveloped oil and gas acreage in which Statoil had interests at 31 December 2009.

    A "gross" value reflects wells or acreage in which Statoil has interests (presented as 100%). The net value corresponds to the sum of whole or fractional working interest for Statoil in gross wells or acreage.

    At 31 December 2009		Norway	Eurasia excluding Norway	Africa	America	Total
    Number of productive oil and gas wells
    Oil wells	— gross	813	140	305	472	1,730
    	— net	294.0	19.3	32.7	48.2	394.2
    Gas wells	— gross	159	49	49	58	315
    	— net	68.5	16.6	18.0	17.5	120.6

    The total gross number of productive wells as of end 2009 includes 340 oil wells and 16 gas wells with multiple completions or wells with more than one branch.

    At 31 December 2009 (in thousands of acres)		Norway	Eurasia excluding Norway	Africa	America	Total
    Developed and undeveloped oil and gas acreage
    Acreage developed	— gross	763	198	815	146	1,922
    	— net	277	52	258	17	604
    Acreage undeveloped	— gross	13,843	12,012	30,921	10,439	67,215
    	— net	6,181	6,266	20,398	4,723	37,568

    Net productive and dry oil and gas wells drilled
    The following tables show the net productive and dry exploratory and development oil and gas wells completed or abandoned by Statoil in the past three years. The 2009 information is split by continent, whereas this split is not available for prior years. Productive wells include wells in which hydrocarbons were found, and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing sufficient quantities to justify completion as an oil or gas well.

    Year 2009	Norway	Eurasia excluding Norway	Africa	America	Total
    Net productive and dry exploratory wells drilled	21.3	0.9	4.4	2.8	29.3
    — Net dry exploratory wells drilled	9.6	0.3	2.1	1.0	13.0
    — Net productive exploratory wells drilled	11.7	0.6	2.2	1.8	16.3
    Net productive and dry development wells drilled	25.7	4.6	8.1	13.9	52.3
    — Net dry development wells drilled	1.2	0.4	0.7	0.0	2.3
    — Net productive development wells drilled	24.5	4.2	7.3	13.9	50.0

    		Norway	Outside Norway	Total
    Year 2008
    Net productive and dry exploratory wells drilled		26.1	12.1	38.2
    — Net dry exploratory wells drilled		7.2	5.8	13.0
    — Net productive exploratory wells drilled		18.9	6.3	25.2
    Net productive and dry development wells drilled		27.9	23.7	51.6
    — Net dry development wells drilled		0.5	0.0	0.5
    — Net productive development wells drilled		27.4	23.7	51.1
    Year 2007
    Net productive and dry exploratory wells drilled		13.2	14.0	27.1
    — Net dry exploratory wells drilled		4.5	5.9	10.4
    — Net productive exploratory wells drilled		8.7	8.0	16.7
    Net productive and dry development wells drilled		34.7	19.7	54.4
    — Net dry development wells drilled		0.7	1.0	1.7
    — Net productive development wells drilled		34.0	18.7	52.7

    Related to our oil sand development in the Athabasca region of Alberta we also drilled 48 wells in 2009 to delineate the bitumen pay. All of these wells were drilled, logged, cored and abandoned. We also drilled 15 water wells in which we were searching for suitable source or disposal water zones. Some of these were abandoned and some completed for water needs.

    Exploratory and development drilling in process
    The following table shows the number of exploratory and development oil and gas wells in the process of being drilled by Statoil at 31 December 2009.

    At 31 December 2009		Norway	Eurasia excluding Norway	Africa	America	Total
    Number of  wells in progress
    Developement Wells	— gross	35	7	11	111	164
    	— net	15.3	1.0	2.6	58.6	77.5
    Exploratory Wells	— gross	4	-	1	6	11
    	— net	1.8	-	0.1	2.1	4.0

     Top 

    3.9.2 Report of DeGolyer and MacNaughton

    Statiol's estimates of proved reserves are not materially different from those prepared by independent petroleum engineering consultants.

    DeGolyer and MacNaughton, independent petroleum engineering consultants, have performed an independent evaluation of StatoilHydro'sStatoil's proved reserves as of 31 December 2008. A copy2009. The evaluation accounts for 100 % of a summary letter report from DeGolyer and MacNaughton, describing their procedures and conclusions, is included below.

    DeGolyer and MacNaughton
    5001 Spring Valley Road
    suite 800 East
    Dallas, Texas 75244

    February 13, 2009

    StatoilHydro ASA
    Forusbeen 50
    N-4035 Stavanger
    Norway

    Gentlemen:
    Pursuant to your request, we have prepared estimates of theStatoil's proved oil, condensate, liquefied petroleum gas (LPG), and sales gas reserves, as of December 31, 2008, of certain properties with interests owned by StatoilHydro ASA (StatoilHydro) in Algeria, Angola, Azerbaijan, Brazil, Canada, China, Iran, Ireland, Libya, Nigeria, Norway, Russia, the United Kingdom, the United States, and Venezuela.reserves. The estimates are discussed in our “Report as of December 31, 2008 on Proved Reserves attributable to StatoilHydro ASA in Certain Properties” (the Report). We also have reviewed StatoilHydro’s estimates of reserves, as of December 31, 2008, of the same properties included in the Report.

    In our opinion, the information relating toaggregated net proved reserves estimated by us and referred to herein has been prepared in accordance with Paragraphs 10–13, 15, and 30(a)–(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the Financial Accounting Standards Board and Rules 4– 10(a) (1)–(13) of Regulation S–X of the United States Securities and Exchange Commission (SEC).

    StatoilHydro represents that its estimates of the proved reserves, as of December 31, 2008, attributable to StatoilHydro’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalents (MMboe):

    Oil, Condensate, and LPG (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)
    2,201		18,984		5,584
    Note: Gas is converted to oil equivalent using a factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent.

    StatoilHydro has advised us that its estimates of proved oil, condensate, LPG, and natural gas reserves are in accordance with the rules and regulations of the SEC. It is our opinion that the guidelines and procedures that StatoilHydro has adopted to prepare its estimates are in accordance with generally accepted petroleum reserves evaluation practices and are in accordance with the requirements of the SEC.

    Our estimates of the proved reserves, as of December 31, 2008, attributable to StatoilHydro’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalents (MMboe):

    Oil, Condensate, and LPG (MMbbl)		Sales Gas (Bcf)		Oil Equivalent (MMboe)
    2,257		18,889		5,623
    Note: Gas is converted to oil equivalent using a factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent.

    In comparing the detailed reserves estimates prepared by usDeGolyer and MacNaugthon do not differ materially from those prepared by StatoilHydro for the properties involved, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of StatoilHydro in the properties included in the Report, resulting in overall differences not being substantial. It is our opinion that the reserves estimates prepared by StatoilHydro on the properties reviewed by us and referred to above,Statoil when compared on the basis of net equivalent million barrels of oil, in aggregate, do not differ materially from those prepared by us.barrels.

    Net proved reserves at 31 December 2009	Oil, Condensate and LPG (mmbbl)	Sales Gas (bcf)	Oil Equivalent (mmboe)
    Estimated by Statoil	2,174	18,148	5,408
    Estimated by DeGolyer and MacNaughton	2,284	18,274	5,540

    A reserves report summarising this evaluation is included as Exhibit 15(a)(iii).

    Submitted,

    DeGOLYER and MacNAUGHTON

    /s/ Lloyd W. Cade
    _________________________________
    Lloyd W. Cade, P.E.
    Senior Vice President
    DeGolyer and MacNaughton

     Top 

    3.10 Regulation

    The principal Norwegian legislation applying togoverning our petroleum activities in Norway areconsists of the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.

    The principal Norwegian legislation applying togoverning our petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of 29 November 29, 1996 (the "Petroleum Act"), and the regulations promulgatedissued thereunder, as well as the Norwegian Petroleum Taxation Act of 13 June 13, 1975 (the "Petroleum Taxation Act"). The Petroleum Act states the principle that the Norwegian Statestate is the owner of all subsea petroleum on the NCS, that the exclusive right to resource management is vested in the Norwegian Statestate and that the Norwegian Statestate alone is authorizedauthorised to award licenses concerning thelicences for petroleum activities. We are dependent uponon the Norwegian Statestate for its approval of our NCS exploration and development projects and our applications for production rates for individual fields.

    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 Norwegian parliament, orthe 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 licenseslicences 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 setadopted by the Storting are approved. As set forthout 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 Petroleu mPet roleum 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,firstly, when the Norwegian State acts in theits capacity as the majority owner of our shares and, second,secondly, when the Norwegian State acts in its capacity as regulator:

    • The Norwegian State held 67% of our ordinary shares as at 5of 12 March 2009.2010. The Norwegian State's shareholding in StatoilHydroStatoil is managed by the Ministry of Petroleum and Energy. The Ministry of Petroleum and Energy will normally determinedecide how the Norwegian State will vote its shares on proposals submitted to general meetings of the shareholders. However, in certain exceptional cases, it may be necessary for the Norwegian State to seek approval from the Storting before voting on a certain proposal. This will normally be the case if we issue additional shares and such issuance would significantly dilute the Norwegian State's holding, or if such issuance would require a capital contribution from the Norwegian State in excess of government mandates. It is not possible to predict howwhat stance the Norwegian Storting will decidetake on a proposal for issuance of additional shares whichthat would either significantly dilute its holding of StatoilHydroStatoil shares or require a capital contribution from it in excess of governmental mandates. A decision by the Norwegian State against our proposal to issue additional shares would prevent us from raising additional capital in this manner and could adversely affect our ability to pursue business opportunities and to further develop the company.
    • The Norwegian State exercises important regulatory powers over us, as well as over other companies and corporations. As part of our business, we, or the partnerships to which we are a party, frequently need to apply for licenseslicences and other approvalsapproval of various typeskinds from the Norwegian State. In respect of certain important applications, such as approvalsthe approval of major plans for operation and development of fields, the Ministry of Petroleum and Energy must obtain the consent of the Storting before it can approve our or the relevant partnership's application. This may take additional time and affect the content of the decision. Although StatoilHydroStatoil is majority-owned by the Norwegian State, it does not receive any preferential treatment with respect to licenseslicences granted by or under any other regulatory rules enforced by the Norwegian State.

    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 EEA law and EU law to the extent that EU law has been acceptedincorporated into EEA law under the EEA Agreement.

     Top 

    3.10.1 The Norwegian licensing system

    The

    Production licences are the most important type of licenselicence awarded under the Petroleum Act, is the production licence, and the Ministry of Petroleum and Energy holds executive discretionary power to award a production licence and to determinedecide the terms of that licence.

    In 20082009, we participated in 346222 production licenselicences on the NCS. As a participant in licenses,licences, we are subject to the regulations of the Norwegian licensing system.

    TheProduction licences are the most important type of licenselicence awarded under the Petroleum Act, is the production licence, and the Ministry of Petroleum and Energy holds executive discretionary power to award a production licence and to determinedecide the terms of that licence. The Government is not entitled to award us a licence in an area until the Storting has decided to open the area in question for exploration. The terms of our production licenseslicences are determinateddecided by the Ministry of Petroleum.Petroleum and Energy.

    A production licence grants the holder 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 licence. Notwithstanding the exclusive rights granted under a production licence, the Ministry of Petroleum and Energy has the power, in exceptional cases, to permit third parties to carry out exploration in the area covered by a production licence. For a list of our shares in production licences, see the report section 3.1.53.1.4 Operational review-Ereview - E&P Norway-Production.Norway - Production on the NCS.

    Production licences are normally awarded through licensing rounds. The first licensing round for NCS production licences was announced in 1965. The award of the first licences covered areas in the North Sea. Over the years, the awardawarding of licences has moved northward and covers areas in both in the Norwegian Sea and in the Barents Sea. In recent years, the principal licensing rounds have mainly included licences in the Norwegian Sea. Beginning in 2003, the Norwegian government changed its policy on mature areas and introduced a scheme for award ofawarding production licences namedcalled "Award in Predefined Areas" (APA) in mature parts of the Norwegian Continental Shelf.continental shelf. The awardawarding of licences in the predefined areas has taken place every year since 2003. TheIn a report to the Storting, the Ministry of Petroleum and Energy has in a report to the Storting, announced that this policy will continue.

    The Norwegian State accepts licence applications from individual companies and group applications. This allows us to choose our exploration and development partners.

    Production licences are awarded to joint ventures. As is the case for most fields on the NCS, our production activities are conducted through joint venture arrangements with other companies and in some cases with the Norwegian State through its wholly-owned company Petoro. 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.licence. Once a production licence is awarded, the licensees are required to enter into a joint operating agreement and an accounting agreement whichthat 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.interests. The number of votes required to make a decision varies from licence to licence, but a decision is normally reached when a certain number of the members and a percentage of the ownership interests, specified individually in each licence, have voted in favour of a proposal. The voting rules are structured so that a licensee holding more than 50% of a licence normally cannot vote through a proposal on its own, but will need the support of one or more of the other licensees. I nIn licences 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 licence aswith respect to the Norwegian State's exploitation policies or financial interests. This veto rightpower has never been used.

    Under the joint operating agreements covering licences 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 whichthat are assumed to be of a political nature or principal importance,matters of principle, 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, StatoilHydroStatoil held this right, which was exercised three times, most recently in 1988. In autumn 2002, the Storting began to allow individual licenselicence groups to substitute this special voting rule for the SDFI with a veto rule similar to the veto rules whichthat have applied to licences awarded since 1996. Such a substitution is subject to the approval fromof 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. In 20082009, we were the operator for 42 of our 48 production licenses.licences. The operator is in practice always a member of the joint venture holding the production licence, 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 maycan normally terminate its engagement uponat six months' notice. The management committee may, however,However, with the consent of the Ministry of Petroleum and Energy, the management committee may instruct the operator to continue performingto perform its duties until a new operator has been appointed. The management committee can terminate the operator's engagement uponat 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 Min istryMinist ry 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 licences are normally awarded for an initial exploration period, which is typically six years, but which can either 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 licence. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfil the obligations set out in the production licence, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years. TheAs a rule, the right to prolong the licence does not apply as a main rule to the whole of the geographical area covered by the initial licence, but only to a percentage, typically 50%. The size of the area whichthat must be relinquished is determined at the time the licence is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production licence.

    If natural resources other than petroleum are discovered in the area covered by a production licence, 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 licence.licence period. To date, such a delay has never been imposed.

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

    Licensees may buy or sell interests in production licences 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 interestinterests in a licence, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. There are inIn most licences there are no pre-emption rights in favour of the other licensees. TheHowever, the SDFI, or the Norwegian State, as appropriate, however, still holds pre-emption rights in all licences. AllExcept from one minor transaction which is still pending approval, all of our licensinglicencing transactions entered into in 20082009 were approved by the Ministry of Petroleum and Energy and the Ministry of Finance.

    A licence from the Ministry of Petroleum and Energy is also required in order to establish facilities for the transport and utilizationutilisation of petroleum. When applying for such licences, the owners, which are in practice licensees under a production licence, must prepare a plan for installation and operation. Licences to establishfor the establishment of facilities for transport and utilizationutilisation 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 utilizationutilisation of petroleum in Norway and on the NCS are organizedorganised as a joint ventureventures of a group of licenselicence holders, and the participants' agreements are similar to the joint operating agreements entered into amongby the members of joint ventures holding production licenses.licences. All of our applications for facility licenseslicences submitted in 20082009 have been granted by the Ministry of Petroleum and Energy.

    Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for the transportation and utilizationutilisation 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 licence or the cessation of the use of the facility, and it 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 licence 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 the expropriation of private property apply. None of our production licenseslicences expired in 20082009 and none are due to expire in 2009.2010.

    Licences for the establishment of facilities for transport and utilizationutilisation of petroleum typically include a clause whereby the Norwegian State can require that the facilities be transferred to it free of charge at the expirationon expiry of the licence period.

     Top 

    3.10.2 Gas sales and transportation

    StatoilHydro markets

    We market gas from the Norwegian continental shelf on our own and the Norwegian state's behalf. Gas is transported through the Gassled pipeline network to customers in Europe.

    Gas sales contracts with buyers for the supply of Norwegian gas are concluded individually with each company.

    The upstream gas transportation system consists of several pipelines owned by a joint venture called Gassled. We have a 32.10%32.102% direct ownership interest in Gassled (32.88%(32.881% including our indirect interest through our 28.58% holding in Norsea Gas AS) and are responsible for the technical operation of the majority of the gas export pipelines and onshore plants in the Gassled processing and transportation systems for Gassled; seesystem. See section 3.3.43.3.3 Operational review-Natural Gas-Norway's gas transport system.

    The Norwegian authorities have issued regulations by a royal decreeBy Royal Decree of 20 December 2002, forthe Norwegian authorities issued regulations relating to access to and tariffs for capacity in the upstream gas transportation system. There are three main considerations behind the regulations. Firstly, the regulations, together with the lawAct adopted by the Storting in June 2002, the regulations implement the Gas Directive of the European Union. Secondly, they established a system for access to the upstream gas transportation system that is compatible with company-based gas sales from the NCS. Thirdly, they 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 only applicable only to the upstream gas transportation system owned by the Gassled joint venture. The regulations establish the main principles for access to the upstream gas transportation system. The access regime consists of a regulated primary market where, pursuant to the regulations, the right to book spare capacity in accordance with regulations, is allocated to users with need requisite needneeds for transportationthe transport of natural gas. Furthermore, 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.needs change.

    The capacityCapacity in the primary market is released and booked through Gassco AS on the internet. Spare capacity is 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 distributionthe basis of an allocation formula. However, in casethe event of scarce capacity, consideration must first be given to the owners' duly substantiated needs for capacity, limited to twice the owner's equity interest in the upstream pipeline network.

    Based on authorisation givengranted under the regulations, tariffs for the use of capacity in Gassled are determineddecided by the Ministry of Petroleum and Energy. The Ministry'sministry'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 respecton the basis of the actually transported volume.

     Top 

    3.10.3 The EU Gas directive of the European UnionDirective

    The EU Gas Directive, which has been included in the EEA Agreement and incorporated into Norwegian legislation, regulates the European gas market in conjunction with the gasGas Transmission Access Regulation of 2005.

    Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that is continuingcontinues to be affected by changes in EU regulations and the implementation of such regulations in EU member sates.states. Such regulation affects our ability to expand or even maintain our current market position, as quantities sold under our gas sales contracts may be subject to a material change in gas prices as a result of the regulations under the EU Gas Directive.

    The Directive requires that, with effect from July 2007, all consumers in Europe should be able to choose their energy supplier beginning in July 2007.supplier. Fundamental changes to this directive and regulation were proposedadopted by the European CommissionUnion in September 2007July 2009 and will enter into force in EU in March 2011 (set out in EC Directive 2009/73), with a specific focus on the separation of ownership of transmission assets from supply activities. The objective of these proposalschanges is to increase competition in national markets and integrate them into regional and, eventually, a single EU-wide market for natural gas. The final form of these proposals are as yet unknown and are expected to be developed further throughout 2009. It is difficult to predict the effect liberalisation measures will have on the evolutiondevelopment of gas prices, but the main objective of the single gas market is to bringcreate greater choice and reducedreduce prices for customers through increased competition.

     Top 

    3.10.4 HSE regulation

    Our 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 administered by the Ministry of LabourPetroleum and Government Administration,Energy, our 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. StatoilHydroStatoil established a system for monitoring the technical safety of its facilities and plants in 2001, and, as part of this system, it collects and interprets information from its operating activities and incorporates risk management ininto its operating activities.

    We are required to maintain at all times to maintain a plan to deal with emergency situations in our petroleum operations. During an emergency, the Ministry of Labour, the Ministry of Fisheries and GovernmentCoastal Affairs/the Norwegian Coastal 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 Petroleum Safety Authority Norway (PSA) has the regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. The PSA's spherearea of responsibility also includes supervision of safety, emergency preparedness and the working environment at the petroleum facilitiesfor both offshore and connected pipeline systems on land.onshore facilities.

    In our capacity as a holder of licences under the Petroleum Act, we are subject to strict statutory liability in respect of losses or damagesdamage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licenses.licences. This means that anyone who suffers damage or loss as a result of pollution caused by any of our NCS licence 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 extenta level it considers reasonable.

     Top 

    3.10.5 Taxation of StatoilHydroStatoil

    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 and from 2007, a nitrogen oxide fee.

    Under our production licenseslicences we are obligatedobliged to pay an area fee to the Norwegian State. Below is a summary of certain key aspects of the Norwegian tax rules that apply to our operations.

    Corporate income tax.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%. 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. Norm prices 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 providesstates 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 includin ginto consideration, including spot market prices and contract prices withinin the industry.

    The maximum rate forof depreciation of development costs related to offshore production installations and pipelines is 16.67% per year. The depreciationDepreciation starts when the cost is incurred. Exploration costs may be deducted in the year in which they are incurred. Beginning in 2007, financialFinancial costs related to the offshore activity are calculated directly based on a formula set out in the Petroleum Tax Act. The financial costs deductible against the offshore tax regime are the total financial costs multiplied by 50% of tax values divided by average interest bearinginterest-bearing debt. All other financial costs and income are allocated to the onshore tax regime.

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

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

    Dividends received are subject to tax in Norway. The basis for taxation is 3% of the dividend amounts received, and thiswhich is subject to the standard 28% income tax.tax rate. Dividends from low-tax countries or portfolio investments outside the EEA will under certain circumstances be subject to the standard 28% income tax rate based on the full amounts received.

    Capital gains from the realisation of shares are taxable where thetaxable. The basis for taxation is 3 %3% of the gain, which is subject to the standard 28% income tax. Capital losses from the realisation of shares are not deductible. Exemptions exist forapply to shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA, where, capital gains under certain circumstances, capital gains will be subject to the standard 28% income tax rate and capital losses will be deductible.

    Special petroleum tax.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%. The special tax is applied to relevant income in addition to the standard 28% income tax, resulting in a 78% 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 againstfrom the special petroleum tax, and a tax-free allowance, or uplift, is granted at a rate of 7.5% per year. The uplift is computed on the basis of the original capitalizedcapitalised cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditures areexpenditure is incurred. Unused uplift may be carried forward indefinitely.

    Abandonment costs.costs
    Abandonment costs incurred can be deducted as operating expenses. Provisions for future abandonment costs are not tax deductible.

    Carbon dioxide emissions tax.tax
    A special carbon dioxide emissions tax applies to petroleum activities on the NCS. The tax is NOK 0.450.46 for 20082009 and NOK 0.460.47 for 20092010 per standard cubic metre of gas burned or directly released and per litre of oil burned. From 2008,In addition, companies operating on the NCS have to buy quotasallowances to cover the carbon dioxide emissions from the petroleum activities.

    Nitrogen oxide fee.emissions tax Beginning on
    With effect from 1 January 2007, the Norwegian government introduced a nitrogen oxide feetax applicable to emissions of nitrogen oxide on the NCS. The fee is NOK 15.3915.85 per kilogram of nitrogen oxide for 20082009 and NOK 15.8516.14 for 2009.2010.

    AlternativelyAs an alternative to paypaying the nitrogen oxygen fee, companies maycan voluntarily agree to contribute to an industry nitrogen oxygen fund for the years 2008-2010. The contribution to the fund is NOK 11 per kilogram of nitrogen oxide emissions. We have entered into an agreement to contribute to the fund.

    Area fee.fee
    After the expirationexpiry of the initial exploration period, the holders of production licences are required to pay an area fee. The amount of the area fee is set out in regulations promulgatedissued under the Petroleum Act. In respect of most of the production licences, the initial annual area fee is currently NOK 700030,000 per square kilometre. The annual areaFor the subsequent year the fee is increased yearly byto NOK 7000 until it reaches NOK 70,00060,000 per square kilometre and thereafter the yearly fee is increased to NOK 120,000 per square kilometre. Production licences for which a plan for development and operation (PDO) has been submitted are, from the time of submission of the PDO and for as long as extraction from the deposit takes place, exempt from the obligation to pay the area fee for the area defining the deposits included in the PDO.

    Taxation outside Norway
    StatoilHydro'sStatoil's international petroleum activities are subject to tax accordingpursuant to local tax legislation. Fiscal regulation of our upstream operations is generally based on corporate income tax regimes and/or production sharing agreement (PSA) regimes. Royalties may be applicable in each regime.

    Generally, income from StatoilHydro'sStatoil's upstream production outside of Norway is subject to tax at the higher of the Norwegian on-shoreonshore rate (28%) or the prevailing tax rate of tax in the countries in which it operates. StatoilHydroStatoil is subject to excess (or "windfall") profit tax in some of the countries where it produces crude oil.

    Production sharing agreements.agreements
    Under a PSA, the host government typically retains the right to the hydrocarbons in place. The contractor underUnder a PSA, the contractor normally receives a share of the oil produced to recover its costs, and additionally is also entitled to an agreed share of the oil as profit. The allocation of profit oil between the state and the contractors is typically increasing towards the stateincreasingly based on a success factor, such as surpassing certain specified internal rates of return, production rates or accumulated production. Normally, the contractors carry the exploration costs and risk prior to a commercial discovery and are then are entitled to recover those costs during the producing phase. Fiscal provisions in a PSA contract are to a large extent negotiable and are unique to each PSA. ContractorsParties to a PSA are generally insulated from legislative changes toin a country's general tax laws.

    Income tax regimes.regimes
    Under an income tax/royalty regime, companies are granted licenseslicences by the government to extract petroleum, and the state may be entitled to royalties in addition to tax based on the company's net taxable income from production. TheIn general, the fiscal terms surrounding these licenseslicences are in general, not negotiable and the company is subject to legislative changes to the tax laws.

     Top 

    3.10.6 The Norwegian state's participation

    The Norwegian state's direct participation in petroleum operations on the NCS

    The Norwegian State's policy as an owner of shares of StatoilHydroa shareholder in Statoil 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 largely organised mainly through us. In 1985, the Norwegian State established the State's direct financial interest,Direct Financial Interest, or SDFI, through which the Norwegian State has taken direct participating interests in licences and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licences and petroleum facilities in which we also hold interests.

    As a result of changes in global markets and competitive conditions in the petroleum industry, the Norwegian State implementedcarried out 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 26 April 2001. The key elements of the restructuring plan led to:

    • the partial privatizationprivatisation of Statoil
    • a restructuring of the Norwegian State's SDFI assets, including the sale of SDFI assets to us and to other oil and gas companies, and an exchange of interests in certain oil and gas infrastructure between the SDFI and us
    • the establishment of procedures to ensure that, as long as the Norwegian State instructs us to do so, we will continue to market and sell the State's oil and gas, together with our oil and gas
    • the transfer of responsibility overfor and management of the SDFI's assets from us to a new company namedcalled Petoro AS, which is wholly owned by the Norwegian State; and
    • the transfer of operational responsibility overfor certain pipelines on the NCS from us to Gassco AS, which is wholly owned by the Norwegian State.
     Top 

    3.10.7 Marketing and sale of SDFI oil and gas

    Historically, we have marketed and sold the Norwegian State's oil and gas as a part of our own production, and the Norwegian State has elected to continue this arrangement.

    Accordingly, at an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article whichthat 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 25 May 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 maximiseaimed at maximising the aggregate value of its ownership interests in StatoilHydroStatoil 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 out below.

    Objectives.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 to ensure an equitable distribution of the total value creation between the Norwegian State and us. In addition, the following considerations are important:

    • to create the basis for making long-term and predictable decisions concerning the marketing and sale of the Norwegian State's oil and gas;
    • to ensure that results, including costs and revenues related to our oil and gas and the Norwegian State's oil and gas, are transparent and possible to measure; and
    • to ensure an efficient and simple administration and execution.

    Our tasks.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 licence, in relationrelating 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 for 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 receiveshas all rights and obligations related to the Norwegian State's oi loil and gas.

    Costs.Costs
    The Norwegian State does not pay us a 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.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.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 own natural gas volumes, a list has been established for deciding the priority between each individual field. To decide the ranking, a mathematical optimisation model is used whichthat describes existing and planned production facilities, infrastructure and processing terminals wherein which 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 effect of the draw on the depletion rate
    • identification of time criticaltime-critical fields
    • influence on oil/liquid fields with associated gas needingrequiring gas disposal; and
    • freespare capacity and flexibility in transportation systems and onshore facilities.

    The various 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 incidentsevents occur that may significantly influence the ranking. Within each individual field wherein which 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.amendment
    The Norwegian State may at any time utilise its position as majority shareholder of StatoilHydro at any timeStatoil to withdraw or amend the instruction requiring us to market and sell the SDFI oil and natural gas together with our own.

     Top 

    3.10.8 Petoro AS

    Petoro AS - the SDFI management company

    In 1985, the Norwegian State began taking a direct financial interest in production licences through the establishment of the SDFI, and, in 2001, a new state-owned company, Petoro, was establishedformed to administermanage SDFI assets.

    From the establishment of Statoil in 1972 and until 1 January 1985, the participation of the Norwegian State in production licences and facilities for the transport and utilisation of petroleum took place entirely through Statoil. As of 1With effect from January 1985, the Norwegian State's participation was reorganised through the establishment of the SDFI. Through this reorganisation, the Norwegian State began taking a direct financial interest in production licences. The establishment of the SDFI entailed athe transfer of a substantial part of our participation in most of our then-existingthen licences to the SDFI, although, formally, such licences continued to be held wholly in our name. Since its establishment in 1985, the SDFI has taken shares in most licences awarded. The SDFI also holds shares in a number of oil and gas pipelines and land-based terminal facilities.

    In connection with the restructuring, the Norwegian State establishedformed a new State-ownedstate-owned company, Petoro AS, in May 2001, 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 toin accordance with the owner's instruction described underin report section 3.10.83.10.7 Operational review-Regulation-Marketing and sale of the SDFI oil and gas. 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 licence interests it holds, it does not receive any revenues from sales of the Norwegian State's oil and gas, and it is not permitted to obtainhave an operator role. However, Petoro AS may become a participant in new licences awarded by the Norwegian State.

     Top 

    3.10.9 Gassco AS

    Gassco AS - the gas transportation operating company

    In connection with the restructuring of the Norwegian State's oil and gas interests in May 2001, the Norwegian State establishedformed a separate company, Gassco AS.

    Gassco took over as operator of the natural gas transportation system previously operated by us on 1 January 2002. 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 of, and does not affect existing arrangements, with respect to ownership or access to the natural gas transportation system or tariffs for transport.transport tariffs. However, in accordance with the joint venture agreements relating tofor 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 portionshare of Gassco AS's expenses associated withrelating to 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 AS or we may terminate without cause each of these contracts without cause, except for the contract for the Statpipe joint venture, after five years. Either Gassco AS or we may also terminate the part of the Statpipe contract which refers tothat concerns the offshore pipelines, after five years. Currently, Gassco AS may terminate the part of the Statpipe contract that refers toconcerns the Kårstø plant at any time, provided that 2/3two-thirds of the owners, representing more than 2/3two-thirds of the ownership interests, have supported such termination.

    The natural gas transportation system was transferred to a new joint venture called Gassled as of 1 January 2003. Gassco AS is the operator of the Gassled joint venture. Our initial direct ownership interest in Gassled is currently 32.06% (32.86%32.102% (32.881% including our indirect interest through our 28.58% holding in Norsea Gas AS), 15.71%15.73% in Zeepipe Terminal JV and 20.84%20.87% in Dunkerque Terminal DA. From 1 January 2011, our direct ownership interest in Gassled will be reduced to 28.05%28.217% due to an increased ownership interest for SDFI.Petoro. In addition, our ownership interest in Gassled may also 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. For more information on the Gassled joint venture, see report section 3.3.43.3.3 Operational review-Natural Gas-Norway'sreview - Natural Gas - Norway's gas transportation system.

     Top 

    3.11 Competition

    In

    There is intense competition in the oil and gas industry there is intense competition for customers, production licences, 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.

    StatoilHydroStatoil competes with major integrated oil and gas companies, as well as with independent and government-owned companies for the acquisition of assets and licences 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 and demand, the cost of exploration and production, global production levels, alternative fuels and governmental and environmental regulations.

    StatoilHydro'sStatoil's ability to remain competitive will require,depend, among other things, on 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 captureseize 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.

     Top 

    3.12 Property, plant and equipment

    We have interests in real estate in numerous countries throughout the world, but no one individual property is significant to us as a whole. Plans have been announced for a new office building to be leased in Oslo.

    Our principal offices located at Forusbeen 50, N-4035, Stavanger, Norway, comprise approximately 135,000 square metres of office space, and are owned by StatoilHydro.

    Statoil.
    
    A letter of intentcontract has been signed with IT Fornebu Holding AS in Oslo for the long-term lease of a new 60,000 square metre office building to be built at Fornebu in Bærum municipality. The building, which will enable all of StatoilHydro'sStatoil's activities in the Oslo region to be collocated, andconsolidated, will be ready for occupation in the autumn of 2012. IT Fornebu Holding AS will be the owner and StatoilHydroStatoil will be the tenant.

    For a description of our significant reserves and sources of oil and natural gas, see note 3435 - supplementarySupplementary oil and gas information in the Consolidated Financial Statements.Statements in this report.

     Top 

    3.13 Related party transactions

    We have the following transactions with related parties, including state-owned entities and the bank DnB NOR:

    DnBNOR bank:

    Transactions with the Norwegian Statestate
    For a description of shares held by the Norwegian State,state, see report section 7.86.4 Shareholder information-Major shareholders. See also report section 4.2.34.2.7 Financial performance-Liquidityanalysis and review -Liquidity and capital resources-Material contracts for details on the merger between Statoil and Norsk Hydro's oil and energy activities.resources - Material contracts.

    Transactions with other entities in which the Norwegian State is a major shareholder
    AsBecause the Norwegian State controls a result of the substantial proportion of industry in Norway, controlled by the Norwegian State, there are many state-controlled entities with whom we do business. The financial value of most such transactions is relatively small, and the ownership interest of the Norwegian State ofin such counter partiescounterparties 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 in particular, we purchase telephone services from Telenor ASA, a telecommunications company in which the Norwegian State holds a 53.97% interest. Such purchases are made pursuant to standard tariff rates applicable to public and private companies in Norway.

    Other transactions with the Norwegian State
    Total purchases of liquids and natural gas from the Norwegian State amounted to NOK 74,338 million (204 mmboe) in 2009. In 2008 and 2007, the total purchases amounted to NOK 112,682 million (223 mmboe) in 2008,and NOK 98,498 million (237 mmboe) in 2007 and NOK 104,628 million (254 mmboe) in 2006.respectively. Purchases of natural gas from the Norwegian State (excluding purchases from licences and sales on behalf of the Norwegian State) amounted to NOK 265 million in 2009. In 2008 and 2007, the purchases of natural gas amounted to NOK 375 million in 2008,and NOK 287 million, respectively. The significant amounts included in 2007the line item Payables to associated companies and NOK 293 millionother related parties in 2006.note 25 Trade and other payables to the Consolidated financial statement, are amount payables to the Norwegian State for these purchases. The prices paid by StatoilHydroStatoil for the oil purchased from the Norwegian State are estimated at market prices. In addition, StatoilHydroStatoil sells the Norwegian State's natural gas in its own name, but for the account and risk of the Norwegian State.S tate.

    The Norwegian State compensates usStatoil for its relative share of the costs related to certain StatoilHydroStatoil natural gas storage and terminal investments and related activities. See report section 3.10.83.10.7 Operational review-Regulation-Marketing and sale of the SDFI'sSDFI oil and gas for more details.

    Although StatoilHydro is majority-owned by the Norwegian State itis Statoil's majority owner, Statoil does not receive any preferential treatment with respect to licences granted by the Norwegian State or under any other regulatory rules enforced by the Norwegian State.

    Employee Loansloans
    We have a general arrangement with DnB NORDnBNOR whereby DnB NORDnBNOR makes available to each of our employees personal consumer loans of up to NOK 300,000. The employees pay the "norm interest rate", which is variable and 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 forresulting from paying the interest rate difference will be dependent on the loan volume, but, based on current interest rates, it would not exceed NOK 5 million per year.

    Three employee-elected membersMembers of the board of directors and one member of the executive Committee each entered into loan agreements under this facility prior to 30 July 2002, and had, as of 31 December 2008, an aggregate total balance outstanding payable to DnB NOR under this loan facility of NOK 628,180. Members of thecorporate executive committee and the board of directors may not enter intotake up loans under the foregoingcurrent programme. None of the three employee-elected members of the board of directors and none of members of the corporate executive committee had any balances outstanding under this facility as of 15 March 2010.

    Employees inat certain employment levels are entitled to an interest freeinterest-free car loan from the company. Members of the corporate executive committee and employee electedemployee-elected members of the board are generally excluded from this arrangement. As of 31 December 2008arrangement, and none of the membersthem had any balances outstanding as of the executive committee had such loans, while one of the employee elected members of the board had a loan balance of NOK 260,555.15 March 2010.

     Top

    4 Financial performanceanalysis and review

    StatoilHydro

    Statoil delivered a strong operational performance in 2008 marked2009 and the company is in good financial shape and well positioned to continue to deliver growth and shareholder value towards 2012 and beyond.

    The company met its guided production level by record highincreasing equity production the most expansiveby 2%, to 1.962 mboe per day. It also delivered a successful exploration programme everwhile maintaining cost control and capital discipline. However, net operating income amountingwas down by 39%, mainly because of lower prices for both oil and gas. Net operating income amounted to NOK 198.8121.6 billion.

    We also delivered significantAround 80% of the Hydro merger synergies from the merger,have been achieved, and the ongoing integrationremainder are expected to be realised during 2010. Significant cost reductions have secured Statoil's highly competitive operating unit cost position.

    The company has had a strong cash flow throughout the financial turmoil and standardisation of offshore operationshas a sound financial position. Statoil is aimedthus positioned to further improve HSE results. These improvements will also increase StatoilHydro's flexibility and efficiencycontinue its production growth towards 2012 despite the current weakness in the organisation.

    With the additiongas markets, and it has projects and resource potential to underpin profitable growth beyond 2012. The board of a strong balance sheet and active cost management, StatoilHydrodirectors is well positioned to manage through the global economic downturn. The group has the necessary strength and flexibility to pursue the long term strategic direction.

    A downturn also representsproposing an opportunityattractive dividend of NOK 6.00 per share for improvements. We seek to reduce our own costs, improve quality and processes and work with our suppliers to bring industry costs down to more sustainable levels. The ongoing integration and standardisation of operational activities is a key element in our improvement agenda.2009.

    The following tables show selected consolidated financial and statistical data for StatoilHydro. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU). The accounting policies applied by the Group also comply with IFRSs as issued by the International Accounting Standards Board (IASB).

    CONSOLIDATED STATEMENTS OF INCOME
    	For the year ended 31 December
    (in NOK billion)	2008	2007	2006
    REVENUES AND OTHER INCOME
    Revenues	652.0	521.7	519.0
    Net income (loss) from associated companies	1.3	0.6	0.7
    Other income	2.8	0.5	1.8
    Total revenues and other income	656.0	522.8	521.5
    OPERATING EXPENSES
    Purchases [net of inventory variation]	(329.2)	(260.4)	(249.6)
    Operating expenses	(59.3)	(60.3)	(44.8)
    Selling, general and administrative expenses	(11.0)	(14.2)	(10.8)
    Depreciation, amortisation and impairment losses	(43.0)	(39.4)	(39.5)
    Exploration expenses	(14.7)	(11.3)	(10.7)
    Total operating expenses	(457.2)	(385.6)	(355.3)
    Net operating income	198.8	137.2	166.2
    FINANCIAL ITEMS
    Net foreign exchange gains (losses)	(32.6)	10.0	4.5
    Interest income and other financial items	12.2	2.3	3.7
    Interest and other finance expenses	2.0	(2.7)	(3.1)
    Net financial items	(18.4)	9.6	5.1
    Income before tax	180.5	146.8	171.2
    Income tax	(137.2)	(102.2)	(119.4)
    Net income	43.3	44.6	51.8
    Attributable to:
    Equity holders of the parent company	38.3	44.1	51.1
    Minority interest	5.0	0.5	0.7
    	43.3	44.6	51.8
    Earnings per share for income attributable to equity holders of the company - basic and diluted	13.58	13.80	15.82

     

     Top

    4.1 StrongContinued deliveries in turbulent markets

    

    Statoil delivers sound financial and operational performance

    

    Good operational performanceresults in a demanding market. The activity level is the best protection in times of uncertainty,high, and the merger was keyour production is growing according to our continuous performance improvements. We delivered record production in 2008 and brought 12 new fields on stream.

    plan.

    In 2008, StatoilHydro2009, Statoil delivered total liquids and gas entitlement production of 1.806 mboe per day, up 3% from 1.751 mboe per day up 2% from 1.724 mboe per day in 2007.2008. The contribution from international operations reached a record high and accountedthe highest level yet, accounting for 18%approximately 20% of the entitlement production. Total equity production increased by 5%2% from 20072008, to 1.9251.962 mboe per day in 2008. Strong2009.

    Despite strong production and high prices contributed to aincreased contribution from higher volumes, net operating income ofwas down 39% at NOK 121.6 billion in 2009, compared with NOK 198.8 billion in 2008, compared to NOK 137.2 billion in 2007.2008. The increasedecrease was mainly dueattributable to an increase inlower prices for oil and gas and increased depreciation, amortisation and impairment losses. Having realised prices on both liquidsapproximately 80% of the expected synergies from the merger, Statoil has reduced overall expenses, reduced expenditures related to logistics and natural gas, measured in NOK,procurement, improved operational efficiencies, and was only partly offset by increased operating expenses caused by a higher activity level and new, more expensive fields coming on stream.value creation through commodities trading.

    StatoilHydroStatoil delivered an extensive exploration programme in 2008.2009. Of a total of 7970 exploration wells completed before 31 December 2008, 402009, 29 were drilled outside the NCS. Thirty-fiveForty wells were declaredannounced as discoveries, seven of which eight are located outside the NCS. An additional eight wells have been completed since 31 December 2008. In 2008, 2302009, 481 mmboe were added through revisions, extensions and discoveries, compared with additions of 230 mmboe in 2008, also through revisions, extensions and discoveries.

    In total, the companyall, Statoil achieved a reserve replacement ratio of 34%73% in 2008.2009.

    StatoilHydroStatoil maintained a high level of activity in progressing projects into production in 2008. Seven2009. Four projects on the NCS and sixtwo international projects came on stream in 2008, and we also sanctioned 132009. Eight new projects have been sanctioned for development in 2009, three of which four are outside Norway.

    During 2008,In 2009, the group gained access to 2013 new exploration licences in the Gulf of Mexico, Alaska, Brazil,India, Canada, GoM, Libya, Brasil and the Faroe Islands. On the NCS, we were grantedawarded access to 1213 new licences, as operator in ninefor six and as partner in three.seven. We were also awarded five licence extensions, as operator for four and partner in one. In addition, the group acquiredsigned a 15%contract with Lukoil and the Iraqi government concerning an 18.75% interest in the GoliatWest Ourna 2 field and a 10% interest in the Ragnarrock discovery on the NCS. In accordance with an agreement with Chesapeake Energy Corporation, StatoilHydro acquired a 32.5% interest in the Marcellus shale gas acreage in the USA. Statoilhydro also completed the purchase of the remaining 50% interest and became the operator of the Peregrino development offshore Brazil.Iraq.

    The report for 2007 was the first annual report in which financial statements for the merged StatoilHydro organisation was presented. Historical data was restated as if the merged company had existed for all periods.

     Top

    4.1.1 Sales volumes

    Sales volumes include our lifted entitlement volumes, the sale of SDFI volumes as well as our marketing of third party volumes

    We take part in the production of oil and natural gas volumes, and incur capital expenditures and operating expenses on the basis of such equity volumes. Under certain profit sharing agreements (PSAs), a portion of the equity production is distributed to the relevant government before arriving at the volumes that we are ultimetely entitled to sell (entitlement volumes). The timing of when we lift our share of entitlement volumes may cause us to at any point in time have a difference between our share of entitlement volumes and the volumes lifted. This difference is called overlift if we have lifted more than our share of the entitlement production, and underlift if our cumulative lifting is less than our share of the entitlement volumes. The lifted volumes and volumes in inventory are the basis for what we can sell to third parties.

    In addition to our own volumes of lifted entitlement production and in storage, we market and sell oil and gas owned by the Norwegian state through the Norwegian state's share in production licences, known as the State's Direct Financial Interest, or SDFI. For additional information, see section 3.13 Operational review-Related party transactions. The following table shows SDFI and Statoil sales volume information for crude oil and natural gas, as applicable, for the periods indicated. The Statoil natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International E&P and ethane volumes.

    For more information on the differences between equity and entitlement production, sales volumes and lifted volumes, see section 4.1.10 Financial analysis and review - Continued deliveries in turbulent markets - Definitions of reported volumes.

    Sales Volumes		Year ended December 31,
    	2009	2008	2007
    Statoil: (1)
    Crude oil (mmbbls) (2)	381	372	395
    Natural gas (bcf)	1462	1387	1257
    Natural gas (bcm) (3)	41.4	39.3	35.6
    Combined oil and gas (mmboe)	642	619	619
    Third party volumes: (4)
    Crude oil (mmbbls)(2)	257	242	240
    Natural gas (bcf)	192	127	177
    Natural gas (bcm) (3)	5.4	3.6	5.0
    Combined oil and gas (mmboe)	291	265	271
    SDFI assets owned by the Norwegian State:
    Crude oil (mmbbls) (2)	200	213	235
    Natural gas (bcf)	1,431	1,440	1,327
    Natural gas (bcm) (3)	40.5	40.8	37.6
    Combined oil and gas (mmboe)	455	470	472
    Total
    Crude oil (mmbbls) (2)	838	827	869
    Natural gas (bcf)	3,085	2,955	2,760
    Natural gas (bcm) (3)	87.4	83.7	78.2
    Combined oil and gas (mmboe)	1388	1353	1361
    (1) The Statoil volumes included in the table above are based on the premise that volumes sold were equal to lifted volumes in the relevant year. Changes in inventory may cause these volumes to differ from the sales volumes reported elsewhere in this report by the Oil Trading and Supplies (OTS) organisation in the Manufacturing and Marketing segment in that such volumes include volumes still in inventory or transit held by other reporting entities within the group. Excluded from such volumes are volumes lifted by the International E&P but not sold by OTS, and volumes lifted by E&P Norway or International and still in inventory or in transit.
    (2) Sales volumes of crude oil include NGL and condensate. All sales volumes reported in the table above include internal deliveries to our manufacturing facilities.
    (3) At a gross calorific value (GCV) of 40 MJ/scm.
    (4) Third party volumes of crude oil include both volumes purchased from partners in our upstream operations and other cargos purchased in the market. The third party volumes are purchased either for sale to third parties or for our own use. Third party volumes of natural gas include third party LNG volumes related to our activities at the Cove Point regasification terminal in the U.S.

     Top

    4.1.2 Group profit and loss analysis

    Revenues and other income were NOK 133.2465.4 billion higherin 2009, which is NOK 190.6 billion lower than in 20072008 and 134.5 million moreNOK 57.4 billion lower than in 2006.2007. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by StatoilHydro.

    	Twelve months ended 31 December
    Consolidated statements of income (in NOK billion)	2008	2007	08 -07 Change	2006	07-06 Change
    Revenues and other income
    Revenues	652.0	521.7	25%	519.0	1%
    Net income (loss) from equity accounted investments	1.3	0.6	111%	0.7	(10%)
    Other income	2.8	0.5	428%	1.8	(72%)
    Total revenues and other income	656.0	522.8	25%	521.5	0%
    Operating expenses
    Purchase, net of inventory variation	329.2	260.4	26%	249.6	4%
    Operating expenses	59.3	60.3	(2%)	44.8	35%
    Selling, general and administrative expenses	11.0	14.2	(23%)	10.8	31%
    Depreciation, amortisation and impairment	43.0	39.4	9%	39.5	(0%)
    Exploration expenses	14.7	11.3	30%	10.7	6%
    Total operating expenses	457.2	385.6	19%	355.3	9%
    Net operating income	198.8	137.2	45%	166.2	(17%)
    Net financial items	(18.4)	9.6	(291%)	5.1	89%
    Income tax	(137.2)	(102.2)	(34%)	(119.4)	14%
    Net income	43.3	44.6	(3%)	51.8	(14%)
    Earnings per share for income attributable to equity holders of company basic and diluted
    	13.6	13.8	(100 %)	15.8	(13 %)

    Statoil.

     

    Operational data	Twelve months ended 31 December
    	2008	2007	08 -07 Change	2,006	07-06 Change
    Average liquids price (USD/bbl)	91.0	70.5	29 %	63.2	12 %
    USDNOK average daily exchange rate	5.63	5.86	(4 %)	6.42	(9 %)
    Average liquids price (NOK/bbl) [3]	513	413	24 %	406	2 %
    Gas prices (NOK/scm)	2.40	1.66	45 %	1.94	(15 %)
    Refining margin, FCC (USD/boe) [4]	8.2	7.5	9 %	7.1	6 %
    Total entitlement liquids production (mboe per day)[5]	1055	1070	(1 %)	1057	1 %
    Total entitlement gas production (mboe per day)	696	654	6 %	651	0 %
    Total entitlement liquids and gas production  (mboe per day) [6]	1751	1724	2 %	1708	1 %
    Total equity liquids production (mboe per day)	1200	1165	3 %	1118	4 %
    Total equity gas prodcution (mboe per day)	725	674	8 %	661	2 %
    Total equity liquids and gas production (mboe per day)	1925	1839	5 %	1780	3 %
    Total liquids liftings (mboe per day)	1019	1081	(6 %)	1048	3 %
    Total gas liftings (mboe per day)	696	654	6 %	651	0 %
    Total liquids and gas liftings (mboe per day)  [7]	1714	1735	(1 %)	1699	2 %
    Production cost entitlement volumes (NOK/boe, last 12 months)  [8]	38.1	44.1	(14 %)	28.4	55 %
    Equity production cost excluding restructuring and gas injection cost (NOK/boe, last 12 months) [10]	33.3	31.2	7 %	28.1	11 %

    Consolidated statement of income	Year ended 31 December
    (in NOK billion)	2009	2008	2007	09-08 change	08 -07 change
    Revenues and other income
    Revenues	462.3	652.0	521.7	(29%)	25%
    Net income from associated companies	1.8	1.3	0.6	39%	111%
    Other income	1.4	2.8	0.5	(51%)	428%
    Total revenues and other income	465.4	656.0	522.8	(29%)	25%
    Operating expenses
    Purchase, net of inventory variation	205.9	329.2	260.4	(37%)	26%
    Operating expenses	56.9	59.3	60.3	(4%)	(2%)
    Selling, general and administrative expenses	10.3	11.0	14.2	(6%)	(23%)
    Depreciation, amortisation and net impairment losses	54.1	43.0	39.4	26%	9%
    Exploration expenses	16.7	14.7	11.3	14%	30%
    Total operating expenses	343.8	457.2	385.6	(25%)	19%
    Net operating income	121.6	198.8	137.2	(39%)	45%
    Net financial items	(6.7)	(18.4)	9.6	(64%)	(291%)
    Income tax	(97.2)	(137.2)	(102.2)	(29%)	(34%)
    Net income	17.7	43.3	44.6	(59%)	(3%)
    Earnings per share for income attributable to equity holders of company basic and diluted
    	5.7	13.6	13.8	(58 %)	(100 %)

     

    
    

    Operational data	Year ended 31 December
    	2009	2008	2007	09-08 change	08-07 change
    Average liquids price (USD/bbl)	58.0	91.0	70.5	(36 %)	29 %
    USDNOK average daily exchange rate	6.30	5.63	5.86	12 %	(4 %)
    Average liquids price (NOK/bbl)	364	513	413	(29 %)	24 %
    Gas prices (NOK/scm)	1.90	2.40	1.66	(21 %)	45 %
    Refining margin, FCC (USD/boe)	4.3	8.2	7.5	(48 %)	9 %
    Total entitlement liquids production (mboe per day)	1066	1055	1070	1 %	(1 %)
    Total entitlement gas production (mboe per day)	740	696	654	6 %	6 %
    Total entitlement liquids and gas production  (mboe per day)	1806	1751	1724	3 %	2 %
    Total equity liquids production (mboe per day)	1202	1200	1165	0 %	3 %
    Total equity gas prodcution (mboe per day)	760	725	674	5 %	8 %
    Total equity liquids and gas production (mboe per day)	1962	1925	1839	2 %	5 %
    Total liquids liftings (mboe per day)	1045	1019	1081	3 %	(6 %)
    Total gas liftings (mboe per day)	740	696	654	6 %	6 %
    Total liquids and gas liftings (mboe per day)	1785	1714	1735	4 %	(1 %)
    Production cost entitlement volumes (NOK/boe, last 12 months)	38.4	38.1	44.1	1 %	(14 %)
    Equity production cost excluding restructuring and gas injection cost (NOK/boe, last 12 months)	35.3	33.3	31.2	6 %	7 %

    

    Revenues and other income totalledwas NOK 656.0465.5 billion in 2008. This was2009, compared to NOK 133.2656,0 billion more than in 20072008 and NOK 134.5521.7 billion more than in 2006.2007. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by StatoilHydro. WeStatoil. In addition, we also market and sell the Norwegian State'sstate's share of oilliquids from the NCS. All purchases and sales of the Norwegian State's production of liquids are recorded as purchases net of inventory variations and sales, respectively.

    The NOK 190.6 billion decrease in revenues from 2008 to 2009 was mainly attributable to lower prices of both liquids and gas. Realised prices of liquids measured in NOK decreased by 29% from 2008 to 2009, contributing NOK 56.5 billion to the reduction in revenues. Gas prices were down 21% in 2009 compared to last year, and contributed NOK 25.0 billion to the reduction in revenues. The reduction in revenues was partly compensated by a 4% increase in liftings of both liquids and gas, with a total off-setting effect of NOK 15.2 billion. The decrease in revenues related to volumes purchased from The Norwegian State contributed NOK 124.3 billion.

    Realised prices of liquids measured in NOK increased by 29% from 2007 to 2008. The increased prices of liquids contributed2008, contributing NOK 37.0 billion to the revenues, whereas the overall gas sales volumes contributed NOK 6.1 billion and the increase in prices of natural gas contributed NOK 29.2 billion to the change. This was partly off-set by a decrease in liftings of liquids of NOK 9.0 billion.

    Realised oil prices measured The increase in NOK increased by 2%revenues related to volumes purchased from 2006 to 2007. The increased oil pricesNorwegian State contributed NOK 3.1 billion to the revenues, whereas the contribution from increased oil liftings was NOK 5.0 billion. Overall gas sales contributed with NOK 3.6 billion to the change. This was partly off-set by a decrease in gas prices with a negative impact of NOK 10.471.0 billion.

    The volumes of liquids lifted shouldand sold will over time correlate with theequal our production of entitlement volumes, produced. However, the volumesbut may be higher or lower than production in any period due to operational factors affectingdifferences between the timingcapacity of when we lift the liquids fromvessels lifting our volumes and the fields. actual entitlement production in the period. Total liquids liftings was 1.045 mmboe per day in 2009, an increase of 3% compared to last year. In 2008, total liquids liftings decreased from 1.081 mmboe per day in 2007 to 1.019 mmboe per day in 2008. From 2006 to 2007, total liquids liftings increased from 1.048 mmboeThe average daily underlift was 21 mboe per day in 2006 to 1.081 mmboe2009 and 37 mboe per day in 2008, while there was an average overlift of 11 mboe per day and 2007.

    

    Entitlement volumes lifted is the basis for the revenue recognition, while equity production volumes more directly affect operating costs.costs more directly. See report section 4.1.9 Financial performance-Strong operational performance-Reportedanalysis and review - Continued deliveries in turbulent markets - Sales volumes for more details on the PSA effects that causecauses differences between equity and entitlement volumes. See below for more details on the difference between lifted and produced volumes.

    Total natural gas sales were 45.2 bcm (1,60 tcf) in 2008, 42.0 bcm (1.48 tcf) in 2007 and 40.2 bcm (1.42 tcf) in 2006. The 8% increase from 2007 to 2008 was mainly due to increased entitlement gas sales, but was partly offset by a net decrease in StatoilHydro third party sales volumes. The increase in entitlement sales volumes mainly relates to higher production from NCS in addition to the first full year of production from Shah Deniz in Azerbaijan. From 2006 to 2007, the increase of 1.8 bcm was mainly due to higher third party gas sales, and was partly offset by a net decrease in StatoilHydro entitlement sales volumes.

    Net income (loss) from equity accounted investments.associated companies Our share of equitywas NOK 1.8 billion in net income of affiliates was2009, NOK 1.3 billion in 2008 and NOK 0.6 billion in 2007 and NOK 0.7 billion in 2006.2007.

    Other income was NOK 1.4 billion in 2009, compared with NOK 2.8 billion in 2008 compared toand NOK 0.5 billion in 2007 and NOK 1.8 billion2007. The income in 2006.2009 stem mainly from insurance proceeds relating to business interruptions. The income in 2008 and 2007 was mainly related to gain from sale of assets whereas the income in 2006 was mainly related to a change in the write-down of inventory to production cost and gains from sales of assets.

    Purchase, net of inventory variation includes the cost of the oil and NGL production that we purchasepurchased from the Norwegian Statestate pursuant to the MarketingOwners Instruction. The purchase, net of inventory variation amounted to NOK 205.9 billion in 2009, compared to NOK 329.2 billion in 2008 compared toand NOK 260.4 billion in 2007 and NOK 249.6 billion in 2006.2007. The increase from 2006 throughout2007 through 2008 was mainly caused by higher prices of liquids measured in NOK, while the 37% decrease from 2008 to 2009 mainly stem from lower prices of liquids measured in NOK.

    

    Operatingexpenses include field production costs and transport systems related to the company's share of oil and natural gas production. Operating expenses were NOK 59.356.9 billion in 2009, reduced by 4% since 2008 comparedwhen operating expenses were NOK 59.3 billion. The reduction was mainly attributable to reduced transportation costs and the reversal of a provision related to a take or pay contract in previous periods. In 2007, operating expenses were NOK 60.3 billion, in 2007 and NOK 44.8 billion in 2006. Thethe 2% decrease from 2007 to 2008 was primarily due to restructuring costs related to the merger in 2007 and was only partly offset by increased costs related to start-up of new fields, higher activity and industry cost inflation in 2008. The 35% increase from 2006 to 2007 was primarily due to restructuring costs and other costs related to the merger, as well as higher operation and maintenance costs, increased transportation costs and new fields coming on stream.

    Total liquids and gas entitlement production increased from 1.724 mmboe per day in 2007 to 1.751 mmboe per day in 2008.2008 to 1.806 mmboe per day in 2009. In 2006,2007, total liquids and gas production was 1.7081.724 mmboe per day. activities. Equity production of oil and gas increased from 1.839 mmboe per day in 2007 to 1.925 mmboe per day in 2008.2008 to 1.962 mmboe per day in 2009. In 2006,2007, equity production of liquids and gas was 1.7801.839 mmboe per day.

    The 2% increase in equity production from 2008 to 2009 was primarily due to increased production from start-up of new fields, ramp-up on existing fields, partly offset by declining production from mature fields, various operational issues and maintenance activities. Entitlement production increased by 3% due to the same reasons and also due to a less adverse effect of product sharing agreements (PSA-effects).

    The 5% increase in equity production from 2007 to 2008 was primarily due to new fields coming on stream and a higher gas off-take, partly offset by declining production from maturing fields. The 2% increase in entitlement production was due to the same reasons, but was partly offset by higher adverse PSA-effects.

    ProductionThe production cost per boe based on entitlement volumes was NOK 38.138.4 for the 12 months ended 31 December 2008,2009, compared towith NOK 44.138.1 for the 12 months ending 31 December 2007. [8]2008. In 2006,2007, the production cost per boe was NOK 28.4 (USD 4.44).

    44.1. Production costs are incurred based on our equity production. Management therefore thinks that unit of production cost based on equity production is a better measure of cost control than unit of production cost based on entitlement volumes. Based on equity volumes, [10] the production cost per boe for the two periods was NOK 33.535.3 and NOK 41.4,34.6, respectively. Normalised at a USDNOK exchange rate of 6.00, the production cost for the 12 months ending 31 December 2008 was NOK 38.6 per boe, compared to NOK 44.3 per boe for the 12 months ending 31 December 2007 and NOK 28.1 per boe for the 12 months ending 31 December 2006 [9]. Normalised production cost is defined as a non-GAAP financial measure. [2]

    The production cost per boe, both actual and normalised, has decreased significantly from 2007 to 2008, mainly due to a NOK 3,6 billion change in non-recurring restructuring costs relating to the merger in 2007, but the positive effect was partly offset by start-up of new fields, increased maintenance cost and general industry cost pressure.

    Adjusted for restructuring costs and other costs arising from the merger recorded in the fourth quarter of 2007 and gas injection costs, the production cost per boe of equity production for the 12 months ending 31 December 20082009 and 2007,2008, was NOK 33.335.3 and NOK 31.233.3 respectively.

    These figures have not been normalised for currency effects. Adjustments are made for certain costs related to the purchase of gas used for injection into oil-producing reservoirs. The adjustment facilitates comparison of field production costs with other fields which do not pay for their own gas used for injection into oil producing reservoirs.

    

    Selling, general and administrative expenses include expenses related to the sale and marketing of our products, such as business development costs, payroll and employee benefits. These amount to NOK 10.3 billion in 2009, compared to NOK 11.0 billion in 2008 compared withand NOK 14.2 billion in 2007 and NOK 10.8 billion in 2006.2007. The 6% decrease from 2008 to 2009 consists of numerous different factors, cost savings being one of them. The 23% decrease from 2007 to 2008 was mainly due to restructuring costs related to the merger in 2007 and was only partly offset by increased costs related to higher activity and industry cost inflation in 2008. The 32% increase from 2006 to 2007 was also mainly due to restructuring costs and other costs arising from the merger in 2007, and was only partly offset by a pre-tax gain in 2006 of NOK 0.6 billion from the sale of Statoil Ireland.

    

    Depreciation, amortisation and impairment includes depreciation of production installations and transport systems, depletion of fields in production, amortisation of intangible assets and depreciation of capitalised exploration expenditure. It also includes write-downs of impaired long-lived assets.assets and reversals of impairments. These expenses amounted to NOK 54.1 billion in 2009, compared to NOK 43.0 billion in 2008 compared toand NOK 39.4 billion in 2007 and NOK 39.5 in 2006.2007.

    The 9%26% increase in depreciation, amortisation and impairment expenses in 20082009 compared to 20072008 was due to increased production on the NCS and impairment charges net of reversals of NOK 7.1 billion, mostly related to assets in the Gulf of Mexico and refinery assets in Norway.

    Depreciation, amortisation and impairment expenses in 2008 showed a increase of 9% compared to 2007. The increase was due to impairment charges net of reversals of NOK 2.3 billion, mostly related to GoM,the Gulf of Mexico, and an increase in production.
     
    Depreciation, amortisation and impairment expenses in 2007 showed a decrease of NOK 3.3 billion compared to 2006. The decrease was offset by higher asset retirement costs of NOK 2.1 billion and the start-up of new fields in 2007. The impairments of Gulf of Mexico shelf fields and Front Runner amounted to NOK 4.9 billion in 2006, compared to impairments in 2007 of Lufeng, Front Runner, Thunder Hawk and GoM shelf fields amounting to NOK 1.2 billion.

    	Year ended 31 December
    Depreciation, amortisation and net impairment losses (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Ordinary depreciation	(46.5)	(40.4)	(37.0)	15 %	9 %
    Amortisation of intangible assets	(0.1)	(0.1)	(0.2)	5 %	(31 %)
    Impairments, net of reversals	(6.4)	(2.4)	(2.2)	166 %	11 %
    Impairment of intangible assets	(1.0)	0.0	0.0	n/a	n/a
    Depreciation, amortisation and net impairment losses	(54.1)	(43.0)	(39.4)	26 %	9 %

    Exploration expenditures are capitalised to the extent that exploration efforts are considered successful, or pending such assessment. Otherwise, such expenditures are expensed. The exploration expense consists of the expensed portion of our exploration expenditure in 20082009 and write-offs of exploration expenditure capitalised in previous years. TheIn 2009, the exploration expense wasexpenses were NOK 16.7 billion, a 14% increase since 2008 when exploration expenses were NOK 14.7 billion in 2008,billion. In 2007, exploration expenses were NOK 11.3 billionbillion.

    	For the year ended 31 December
    Exploration (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Exploration expenditure (activity)	16.9	17.8	14.2	-5%	25%
    Expensed, previously capitalised exploration expenditure	7.0	3.7	1.7	89%	118%
    Capitalised share of current periods exploration activity	(7.2)	(6.8)	(4.6)	6%	48%
    Exploration expense	16.7	14.7	11.3	14%	30%

    The 14% increase in 2007exploration expenses from 2008 to 2009 was mainly due to a higher number of wells drilled and NOK 10.7 billiona higher portion of exploration expenditure capitalised in 2006.

    	For the year ended 31 December
    Exploration (in NOK billion)	2008	2007	08-07 change	2006	07-06 change
    Exploration expenditure (activity)	17.8	14.2	25%	13.4	6%
    Expensed, previously capitalised exploration expenditure	3.7	1.7	118%	1.5	13%
    Capitalised share of current periods exploration activity	(6.8)	(4.6)	48%	(4.2)	10%
    Exploration expense	14.7	11.3	30%	10.7	6%

    
    previous years being impaired. The 30% increase in exploration expenses from 2007 to 2008 was mainly due to a higher number of wells drilled, generally more expensive wells, higher field evaluation costs and delineation onof the oilsandsoil sands project in Canada. The 6% increase in

    In 2009, a total of 68 exploration expenses from 2006 to 2007 was mainly due to higherand appraisal wells and two exploration activity, generally more expensiveextension wells were completed, 41 on the NCS and 29 internationally. Thirty-eight exploration and appraisal wells and an increase in the expensing of previously capitalised licences and well expenditures.two exploration extension wells have been declared as discoveries.

    

    In 2008, a total of 79 exploration and appraisal wells and nine exploration extension wells were completed, 48 on the NCS and 40 internationally. Thirty-five exploration and appraisal wells and six exploration extension wells have been declared as discoveries. In 2007, a total of 71 exploration and appraisal wells and two exploration extension wells were completed, 26 on the NCS and 47 internationally. Thirty-four exploration and appraisal wells and two exploration extension wells were declared as discoveries.

    

    In 2007, a total of 71 exploration and appraisal wells were completed, 24 on the NCS and 47 internationally. In addition, two exploration extension wells were completed in the same period. Thirty-four of the exploration and appraisal wells were confirmed discoveries, 16 on the NCS and 18 internationally. Both exploration extension wells were discoveries.

    In 2006, a total of 73 exploration and appraisal wells were completed, 18 on the NCS and 55 internationally. Five exploration extension wells were completed during the same period. Thirty-two of the exploration and appraisal wells were confirmed discoveries, eight on the NCS and 24 internationally. Two exploration extension wells were discoveries.

    Net operating income was NOK 121.6 billion in 2009, compared to NOK 198.8 billion in 2008 compared toand NOK 137.2 billion in 20072007. The 39% decrease from 2008 to 2009 was primarily attributable to lower prices of liquids and NOK 166.2 billion in 2006.gas, and increased depreciation, amortisation and impairment losses, partly offset by income from higher volumes sold. The 45% increase from 2007 to 2008 was mainly due to higher realised prices onfor both liquids and natural gas, measured in NOK, and it was only partly offset by increased operating expenses caused by a higher activity level and new, more expensive fields coming on stream.

    The 18% decrease in netNet operating income from 2006 toin 2007 was mainly due to an increase inalso influenced by increased operating, selling and administrative expenses stemming in part from restructuring and other costs arising from the merger, a negative change in derivatives, new fields coming on stream and increased activity levels. The restructuring costs and other costs arising from the merger were recorded primarily under operating and general and administrative expenses, and they were allocated to the business areas where possible. Restructuring costs and other costs arising from the merger waswere primarily related to pensions and early retirement costs and impairment of assets in Sweden.

    In 2009, net operating income was affected by the following items: impairment losses net of reversals (NOK 12.2 billion) and underlift (NOK 1.2 billion) negatively affected net operating income, while higher fair value of derivatives (NOK 2.2 billion), higher values of products in operational storage (NOK 2.1 billion), other accruals (NOK 1.3 billion), gain on sale of assets (NOK 0.5 billion) and reversals of restructuring costs (NOK 0.3 billion) all positively affected net operating income in 2009.

    In 2008, net operating income was impacted ofaffected by the following items: impairment charges net of reversals (NOK 4.8 billion), lower values of products in operational storage (NOK 2.8 billion), underlift (NOK 2.4 billion) and other accruals (NOK 2.3 billion) all impactedaffected net operating income in 2008 negatively, while increased fair value of derivatives (NOK 1.8 billion), gains on derivatives to hedge the value of inventories (NOK 0.8 billion), gains on sales of assets (NOK 1.4 billion) and reversal of restructuring cost accrual (NOK 1.6 billion)
    positively impactedaffected net operating income in 2008.

    In 2007, net operating income was impacted of the following items: impairment charges net of reversals (NOK 2.8 billion), loss on derivatives to hedge the value of inventories (NOK 1.1 billion), other accruals (NOK 1.2 billion), restructuring cost accrual (NOK 6.7 billion) and other costs related to the merger (NOK 3.2 billion) all impacted net operating income in 2007 negatively, while increased fair value of derivatives (NOK 0.5 billion), overlift (NOK 1.6 billion), higher values of products in operational storage (NOK 1.5 billion) positively impacted net operating income in 2008.

    In 2008, Net financial items amounted to a loss of 6.7 billion in 2009, compared to a loss of NOK 18.4 billion in 2008.

    The NOK 11.7 billion positive change from 2008 to 2009 was mostly attributable to NOK 2.0 billion net currency gains caused by a 17% weakening of US dollar versus the NOK for the year ended 31 December 2009, compared to NOK 32.6 net currency losses caused by a 29% strengthening of the US dollar versus the NOK for the year ended 31 December 2008.

    Net foreign exchange losses in 2009 and net foreign exchange losses in 2008 are mainly related to currency derivatives used for currency and liquidity risk management. Effective 1 January 2009 the functional currency changed to US dollar for the parent company. As a result US dollar denominated non-current financial liabilities that impacted Net foreign exchange gains (losses) in 2008, do not impact the income statement in 2009. The positive impact of net currency exchange gains was partly offset by a NOK 8.5 billion decrease in interest income and other financial items and a NOK 14.5 billion increase in interest and other finance expenses.

    Interest income and other financial items amounted to NOK 3.7 billion for the year ended 31 December in 2009, compared to NOK 12.2 billion for the year ended 31 December 2008. The NOK 8.5 billion decrease was mainly related to NOK 3.9 billion in lower income from securities and NOK 5.5 billion in decreased interest income on current financial assets.

    Interest expense and other finance expenses amounted to a net expenses of NOK 12.5 billion for the year ended 31 December 2009, compared to a net gain of NOK 2.0 billion for the year ended 31 December 2008. The decrease of NOK 14.5 billion mostly relate to fair value losses on interest rate derivatives used to manage the interest rate risk of the loan portfolio, due to increasing US dollar rates for 2009. Correspondingly, decreasing US dollar rates in 2008 resulted in fair value gains on these swap positions.

    In 2008, Net financial items amounted to a loss of NOK 18.4 billion, compared towith a gain of NOK 9.6 billion in 2007.

    The NOK 28.0 billion negative change from 2007 to 2008 was mostly attributable to NOK 32.6 billion innet currency losses caused by a 29% weakeningstrengthening of US dollar versus the NOK against USD infor the year ended 31 December 2008, compared to a NOK 10.0 billion gainnet currency gains from a 14% strengtheningweakening of the US dollar versus the NOK againstfor the USDyear ended 31 December 2007.

    Net foreign exchange losses in 2007. The2008 and net foreign exchange gains in 2007 are mainly related to currency derivatives used for currency and liquidity risk management, in combination with net impact on the US dollar denominated loan portfolio.The negative impact of currency exchange losses was partly offset by a NOK 9.9 billion increase in interest income and other financial items and a NOK 4.7 billion decrease in interest and other financialfinance expenses.

    Interest income and other financial items amounted to NOK 12.2 billion infor the year ended 31 December 2008, compared to NOK 2.3 billion infor the year ended 31 December 2007. The increase of NOK 9.9 billion mainly related to an increase in interest income of NOK 4.4 billion and an increase in income from securities of NOK 5.5 billion, mainly related to currency gains on USD denominated investments.

    Interest expense and other financialfinance expenses amounted to a net gain of NOK 2.0 billion infor the year ended 31 December 2008, compared to a net loss of NOK 2.7 billion in 2007. The decrease of NOK 4.7 billion mainly related to a NOK 5.1 billion change in fair value adjustment of interest rate swap positions used to managefor the interest rate risk on the external loan portfolio, due to a decrease in USD rates of 2.2% during 2008.

    In 2007 net financial items amounted to an income of NOK 9.6 billion, compared to an income of NOK 5.1 billion in 2006. The 88% increase was principally the result of changes in currency gains and losses on the USD portions of our non-current financial liabilities outstanding and currency gains and losses on NOK hedging transactions. In both cases, currency gains and losses relate to changes in the USDNOK exchange rate, due to the weakening of the USD against the NOK.

    Currency swaps are used for risk management purposes to hedge our long-term interest-bearing loans recorded in USD. As a result, the company's long-term debt portfolio is exposed to changes in the USDNOK exchange rate. The USD weakened by NOK 0.85 in relation to the NOK in 2007, compared to a weakening of NOK 0.51 in 2006.

    Interest and other financial income amounted to NOK 2.3 billion in 2007, compared to NOK 3.7 billion in 2006. Interest and other financial expenses amounted to NOK 2.7 billion in 2007, compared to NOK 3.1 billion in 2006. The decrease in interest and other expenses was mainly due to a decrease in interest expenses on our long term loan portfolio, caused by currency effects and gains on interest rate swaps related to former Hydro long-term interest-bearing loan contracts. This portfolio was swapped from fixed to floating interest rate in the second half of 2007. These effects were partly offset by increased accretion expenses related to asset retirement obligations and a decrease in interest being capitalised. This was mainly due to the fact that fields such as Snøhvit and Ormen Lange came on stream inyear ended 31 December 2007.

    Management of the portfolio of security investments, mainly related to equity securities, is held by our insurance captive, Statoil Forsikring AS, commercial papers is held by Statholding AS and liquidity funds is held by StatoilHydroStatoil ASA.

    The Norwegian central bank's closing rate for USDNOK was 5.78 on 31 December 2009, 7.00 on 31 December 2008 and 5.41 on 31 December 2007 and 6.26 on 31 December 2006.2007. These exchange rates have been applied in StatoilHydro'sStatoil's financial statements.

    In 2008 incomeIncome taxes were NOK 137.297.2 billion in 2009, equivalent to a tax rate of 76.0%84.6%, compared to NOK 102.2137.2 billion in 2008, equivalent to a tax rate of 69.6%76.0% and NOK 102.2 billion in 2007.2007, equivalent to a tax rate of 69.6%.

    The increase in the tax rate from 2008 to 2009 was mainly due to significant taxable exchange gains, which do not have an impact on the statement of income for companies whose functional currency is USD. In 2009 the taxable income related to these exchange gains is estimated to be NOK 25.0 billion higher than income before tax, which increases the tax rate. In addition, the tax rate was increased by relatively higher income from the NCS with higher than average tax rates, and impairment losses with lower than average tax rates.

    The increase in the tax rate from 2007 to 2008 was mainly related to the net loss on financial items which is tax deductible at a lower tax rate than the average rate. In addition, the tax rate was increased by the deferred tax expense caused by currency effects in certain group companies which are taxable in a different currency than the functional currency. This was partly offset by the tax effect of a proportionally higher operating income being subject to a lower than average tax rate.

    The effective tax rate is calculated as income taxes divided by income before taxes. Fluctuations in the effective tax rates from year to year are principally the 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%; other. Other Norwegian income, including the onshore portion of net financial items are taxed at 28%, and income in other countries taxed at the applicable income tax rates.

    Adjusted forIn 2009, the non-recurring NOK 2.0 billion reduction in deferred tax liabilities relating to allocation of financial items with respect to the NCS and temporary differences in inter-company transactions, income taxes in 2006 were NOK 119.4 billion, equivalent to a tax rate of 69.7%. The tax rate in 2007 was lower than the adjusted tax rate in 2006, mainly due to higher net financial income and the increased effect of uplift deduction on the NCS. The lower tax rate was partly offset by relatively less income from outside the NCS being subject to lower taxation than the average tax rate.

    In 2008, the Minoritynon-controlling interest (minority interest) in net profit was negative NOK 0.6 billion, compared to an income of NOK 0.005 billion compared toin 2008 and NOK 0.5 billion in 2007. The minoritynon-controlling interest is primarily related to the Mongstad crude oil refinery. In 2006, the minority interest in net profit was NOK 0.7 billion in 2006.

    Net income was NOK 17.7 billion in 2009, compared to NOK 43.3 billion in 2008 compared toand NOK 44.6 billion in 2007. The 59% decrease from 2008 to 2009 is mainly due to reduced operating income caused by lower revenues from liquids and gas sales and a higher effective tax rate, only partly offset by reduced loss on net financial items.

    The 3% decrease from 2007 to 2008 was mainly due tocaused by a loss on financial items, high income taxes and increased operating expenses, and was only partly offset by higher prices on both liquids and natural gas, measured in NOK. In 2006, net income was NOK 51.9 billion and the decrease in 2007 was mainly due to lower operating income primarily because of restructuring costs and other costs arising from the merger, negative changes in derivatives and a higher tax rate, partly offset by higher net financial income.

    The Board of Directors proposes an ordinaryto the Annual General Meeting a dividend of NOK 4.406.00 per share for 2009, making an aggregate total of NOK 19.1 billion. In 2008, to the Annual General Meeting,ordinary dividend was NOK 4.40 per share, as well as NOK 2.85 per share in special dividend, making an aggregate total of NOK 23.1 billion. Ordinary dividend for 2007 was NOK 4.20 per share, as well as NOK 4.30 per share in special dividend, making an aggregate total of NOK 27.1 billion infor 2007. In 2006, ordinary and special dividend was NOK 4.00 per share and NOK 5.12 per share, respectively, making an aggregate total of NOK 19.7 billion.

     Top

    4.1.2 4.1.3 Group outlook

    StatoilHydro expects entitlement

    Statoil's guidance for equity production is in the range of 1,925 to remain at approximately 2008 levels1,975 mboe per day in 2009. This assumes no adverse effects2010.

    The expected volumes are exclusive of potential reductionsany Opec cuts. Commercial considerations related to gas sales activities, operational regularity, the timing of new capacity coming on stream and gas offtake represent the most significant risks related to the production guidance.

    Planned turnarounds in OPEC quotas.

    Maintenance activity is expected2010 are estimated to have littlea negative impact on the equity production of around 50 mboe per day in the first quarter of 2009.2010.

    Capital expenditures for 2009,expenditure in 2010, excluding acquisitions, are and capital leases, is estimated to be around USD 13.513 billion. Approximately 50% of the forecasted investments for 2009 are in assets expected to contribute to growth in oil and gas production, about one third are related to investments in currently producing assets, with the remainder in other activities.

    UnitThe unit production cost for equity volumes is estimated in the range of NOK 33 to 36 per barrel in the period from 2009 to 2012, excluding purchases of fuel and gas for injection. For 2009, the unit production cost is expected to be temporarily in the upper end of this range. The short term increaseNOK 35-36 per boe, which is expected to be caused by several large fields ramping up or preparing for production. In addition, some fields, such as ACG and Kvitebjørn, are not producing at full capacity. Furthermore,on a high degree of maintenance during 2009 and continuing uncertainty regarding developments in the NOK/US dollar rate are expected to adversely affect the unit production cost inpar with 2009.

    StatoilHydro's ambition is to deliver a competitive ROACE compared with its peer group.

    Exploration drilling is the primary tool for growing our business. WeThe company will continue to high-grade ourmature its large portfolio of exploration assets and we expect to maintain a highexpects an exploration activity level in 2010 of exploration activity in 2009, although slightly lower than in 2008. around USD 2.3 billion.

    We expect to complete between 65 and 70 exploration and appraisal wells in 2009. Rigs have already been securedprices for most of the exploration drilling in 2009 and to some extent also for subsequent years. Exploration activity is estimated to amount to some USD 2.7 billion for 2009.

    The year 2008 was one of the most volatile periods in the product, gas liquid and crude oil, markets. Whileproducts and natural gas prices have been strong in Europe, crude oil and gas liquids prices decreased dramatically during the third and fourth quarters of 2008. We anticipate that crude oil and gas liquids prices will remain at relatively low levels and that prices willto continue to be volatile in the short to medium term. Refining margins have been declining for more than a year, and we anticipate that they will remain low, at least in the near term.

    The price development for natural gas is uncertain in the short term due to the financial turmoil. The natural gas market is also influenced by developments in the overall power market and the industrial segment in which gas competes with coal and fuel oil products, both having fallen significantly in price. Going forward, the value of natural gas in the power segment will increasingly be determined by competition with coal, renewable energy and nuclear energy. Climate policies and regulations will also be important factors in determining gas pricing.

    New LNG capacity is coming on stream, and will be directed to the most favourable markets. As the amount of available LNG is anticipated to be substantial, there is a corresponding uncertainty related to the price effects to the relevant markets.

    In the long term, we continue to havetake a positive view of gas as an energy source. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. In the USUSA, we believe that our position in the Marcellus shale gas acreage, in combination with Gulf of Mexico production and our LNG regasification capacity position at Cove Point, will provide a foundation for growth in our US market position in the years to come.ahead.

    StatoilHydro'sStatoil's income could vary significantly with changes in commodity prices, while volumes are fairly stable through the year. There is a small seasonal effect on volumes betweenin the winter and summer seasons due to normally higher off-takes of natural gas during cold periods. There is normally an additional small seasonal effect on volumes fromas a result of the higher maintenance activity level of maintenance ofon offshore production facilities during the second and third quarters each year, since generally better weather conditions allow for more maintenance work during the second and third quarter each year.work.

    These forward-looking statements reflect current views about 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. See "Forward looking statements" section 10 Forward looking statements.10.

     Top

    4.1.3 4.1.4 Segment performance and analysis

    Oil and natural gas are subject to internal transactions between our business segments before being sold in the market. We have established a pricing policy for transfers based on the market price.

    The table details certain financial information for our four business segments: Exploration and& Production Norway (EPN), International Exploration and& Production (INT), Natural Gas (NG) and Manufacturing and& Marketing (M&M). WhenWe eliminate intercompany sales when combining business segment results, we eliminate intercompany sales.results. These include transactions recorded in connection with our oil and natural gas production in the EPN or INT segments, and also in connection with the sale, transporttransportation or refining of our oil and natural gas production in the M&M or NG segments.

    EPN produces oil, which it sells internally to Oil Sales, Trading and Supply (OTS) in the M&M segment, which then sells the oil in the market. EPN also produces natural gas, which it sells internally to ourthe NG segment, also for sale in the market. A large share of the oil and a small share of the natural gas produced by INT is also sold in the same way as the oil and the natural gas produced by EPN. The remaining oil and gas from INT is sold directly in the market. We haveStatoil has established a market price-based transfer pricing policy whereby we set an internal price is set at which ourthe EPN business area sells oil and natural gas to the M&M and NG segments.

    The transfer price formula for natural gas produced by EPN and marketed and sold by NG was changed as ofwith effect from 1 January 2008 in order to to better reflect fundamental changes in the markets for competing energies, for instance crude oil, for developments in natural gas markets and for changes in the natural gas sales contracts portfolio. The new internal price is linked to the gas market prices, and it also better reflects the distribution of value creation between NG and EPN. In 2008 the transfer price was NOK 1.87 per scm. The change was effective as of 1 January 2008 and it is reflected in our financial reporting, without restating prior periods. The periods being restated.

    In 2009, the average transfer price for natural gas per standard cubic metre was NOK 1.38 per scm. The average transfer price was NOK 1.87 in 2008 and NOK 1.39 in 2007 and NOK 1.36 in 2006.2007. For sales of oil sold from EPN to M&M, the transfer price of oil is the applicable market reflective price minus a margin of NOK 0.70 per barrel.

    For additional information please refer to section 9.15note 5 Segments in Notes to the Consolidated Financial Statements.

    The following table shows certain financial information for ourthe four segments, including intercompany eliminations for each of the years in the three-year period ending 31 December 2008.2009.

    	For the year ended 31 December
    (in NOK billion)	2008	2007	2006
    Exploration & Production Norway
    Total revenues	219.8	179.2	179.2
    Net operating income	166.9	123.2	135.1
    Non-current assets	165.5	153.1	151.5
    International Exploration & Production
    Total revenues	46.1	41.6	32.6
    Net operating income	12.8	12.2	3.9
    Non-current assets	160.6	107.3	96.0
    Natural Gas
    Total revenues	110.8	73.4	97.1
    Net operating income	12.5	1.6	21.7
    Non-current assets	35.7	35.6	30.1
    Manufacturing & Marketing
    Total revenues	531.3	428.0	412.0
    Net operating income	4.5	3.8	7.3
    Non-current assets	34.4	27.6	25.2
    Other and elimination
    Total revenues	(252.1)	(199.5)	(199.4)
    Net operating income	2.1	(3.4)	(1.9)
    Non-current assets	3.9	2.9	2.9
    StatoilHydro group
    Total revenues	656.0	522.8	521.5
    Net operating income	198.8	137.2	166.2
    Non-current assets	400.1	326.5	305.6
    Non-current assets, not allocated to segments	33.5	26.9	27.0

     

    Sales by region	For the year ended 31 December
    (in NOK billion)	2008	% of total sales	2007	% of total sales	2006	% of total sales
    Norway	495.3	76%	386.7	74%	393.3	76%
    United States	57.9	9%	53.1	10%	45.6	9%
    Sweden	26.0	4%	23.1	4%	21.7	4%
    Denmark	19.4	3%	14.9	3%	14.6	3%
    Singapore	13.1	2%	14.2	3%	8.6	2%
    UK	15.7	2%	-	-	-	-
    Other	27.3	4%	30.1	6%	36.9	7%
    Total	654.7	100%	522.2	100%	520.8	100%

    	For the year ended 31 December
    (in NOK billion)	2009	2008	2007
    Exploration & Production Norway
    Total revenues	158.7	219.8	179.2
    Net operating income	104.3	166.9	123.2
    Non-current assets	176.0	165.5	153.1
    International Exploration & Production
    Total revenues	41.8	46.1	41.6
    Net operating income	2.6	12.8	12.2
    Non-current assets	152.7	160.6	107.3
    Natural Gas
    Total revenues	98.6	110.8	73.4
    Net operating income	18.5	12.5	1.6
    Non-current assets	34.8	35.7	35.6
    Manufacturing & Marketing
    Total revenues	351.2	531.3	428.0
    Net operating income	(0.5)	4.5	3.8
    Non-current assets	28.6	34.4	27.6
    Other and elimination
    Total revenues	(184.9)	(252.1)	(199.5)
    Net operating income	(3.3)	2.1	(3.4)
    Non-current assets	3.0	3.9	2.9
    Statoil group
    Total revenues	465.4	656.0	522.8
    Net operating income	121.6	198.8	137.2
    Non-current assets	395.1	400.1	326.5
    Non-current assets, not allocated to segments	51.4	33.5	26.9

     

    (in NOK million)	Crude oil	Gas	NGL	Refined products	Other	Total sale
    Year ended 31 December 2009
    Norway	182,353	80,018	34,655	45,927	18,137	361,090
    USA	19,836	5,555	117	14,017	672	40,197
    Sweden	0	0	0	16,556	3,795	20,351
    Denmark	0	0	0	15,105	1,957	17,062
    Other	9,978	2,959	154	10,762	1,102	24,955
    Total revenues (excluding net income from associated companies)	212,167	88,532	34,926	102,367	25,663	463,655

    (in NOK million)	Crude oil	Gas	NGL	Refined products	Other	Total sale
    Year ended 31 december 2008
    Norway	260,171	79,813	44,536	79,659	31,105	495,284
    United States	24,712	8,795	1,660	20,182	2,545	57,894
    Sweden	0	0	0	23,428	2,618	26,046
    Denmark	0	0	0	16,858	2,558	19,416
    Singapore	11,203	1,906	0	0	0	13,109
    UK	1,982	10,878	2	0	2,800	15,662
    Other	7,305	930	198	16,885	2,008	27,326
    Total revenues (excluding net income from associated companies)	305,373	102,322	46,396	157,012	43,634	654,737

    (in NOK million)	Crude oil	Gas	NGL	Refined products	Other	Total sale
    Year ended 31 December 2007
    Norway	209,764	62,911	47,119	52,537	14,342	386,673
    United States	24,142	5,269	1,766	22,823	(864)	53,136
    Sweden	0	0	0	15,217	7,892	23,109
    Denmark	0	0	0	13,161	1,759	14,920
    Singapore	13,861	0	0	367	0	14,228
    Other	13,290	2,485	139	11,517	2,691	30,122
    Total revenues (excluding net income from associated companies)	261,057	70,665	49,024	115,622	25,820	522,188

     Top

    4.1.4 4.1.5 Exploration and& Production Norway

    Our overall strategy on the NCS is to conduct safe, efficient and reliable operations and capture the full potential of the NCS by developing profitable oil and gas resources.

    StatoilHydro hasStatoil delivered an extensive exploration programme on the NCS in 2008.2009. We participated in 39 exploration and appraisal wells, 31 of which 27 resulted in discoveries. In addition, we completed ninetwo exploration extensions, of which six resulted inboth announced as discoveries. Total exploration expenditurewas NOK 8.2 billion in 2009, compared with NOK 8.7 billion in 2008 compared withand NOK 5.7 billion in 2007 and NOK 4.6 billion in 2006.2007.

    The total capital expenditure in 2008 wasGross investments amounted to NOK 34.9 billion compared within 2009, which is unchanged from 2008 and slightly higher than NOK 31.1 billion in 2007 and NOK 29.2 million in 2006.2007. Around half of our investments are related to new fields, while the other half are investments onin existing fields.

    In total, sevenfour new fields came on stream on the NCS in 2008: Volve, Gulltopp, Gamma Main Statfjord, Vigdis Øst, Theta Cook, Oseberg Delta2009: Yttergryta, Alve, Tyrihans and Vilje.Tune South.

    Our production of oil and gas on the NCS averaged 1.450 mmboe per day in 2009, compared with 1.461 mmboe per day in 2008 compared toand 1.417 mmboe per day in 2007 and 1.474 in 2006.2007.

     Top

    4.1.4.1 4.1.5.1 Profit and loss analysis

    Exploration and& Production Norway generated total revenues of NOK 219.8158.7 billion in 20082009 and its net operating income was NOK 166.9104.3 billion. The average daily entitlement production in 20082009 was 824 mbbl per day for oil and 637784 mboe per day for liquids and 666 mboe per day for gas.

    	Twelve months ended 31 December					For the year ended 31 December
    Income statement
    (in NOK billion)	2008	2007	08-07 Change	2006	07-06 Change
    Income statement (in NOK billion)						2009	2008	2007	09-08 change	08-07 change
    Total revenues and other income	219.8	179.2	23 %	179.2	0 %	158.7	219.8	179.2	(28 %)	23 %
    Operating expenses	23.5	29.1	(19 %)	19.2	52 %	23.4	23.5	29.1	(0 %)	(19 %)
    Selling, general and administrative expenses	(0.1)	0.3	(135 %)	0.5	(30 %)	0.1	(0.1)	0.3	(153 %)	(135 %)
    Depreciation, amortisation and impairment	24.0	23.0	4%	20.9	10 %	25.7	24.0	23.0	7 %	4%
    Exploration expenses	5.5	3.6	52%	3.5	5 %	5.2	5.5	3.6	(6 %)	52%
    Total expenses	52.9	56.1	(6 %)	44.1	27 %	54.4	52.9	56.1	3 %	(6 %)
    Net operating income	166.9	123.1	36%	31.5	291 %	104.3	166.9	123.1	(38 %)	36%
    Operational data:
    Liquids price (USD/bbl)	91.5	70.9	29%	63.6	11 %	57.8	91.5	70.9	(37 %)	29%
    Liquids price (NOK/bbl)	515.4	415.2	24%	408.3	2 %	363	515	415	(30 %)	24%
    Transfer price natural gas (NOK/scm)	1.9	1.4	34%	1.4	3 %	1.38	1.87	1.39	(26 %)	34%
    Liftings:
    Liquids (mboe per day)	807.8	831.1	(3 %)	856.0	(3 %)	778	808	831	(4 %)	(3 %)
    Natural gas (mboe per day)	637.0	598.6	6%	610.0	(2 %)	666	637	599	5 %	6%
    Total liquids and gas liftings (mboe per day)	1444.7	1429.8	1%	1466.0	(2 %)	1444	1445	1430	(0 %)	1%
    Production:
    Entitlement liquids (mboe per day)	823.8	817.9	1%	864.0	(5 %)	784	824	818	(5 %)	1%
    Entitlement natural gas (mboe per day)	636.9	598.7	6%	610.0	(2 %)	666	637	599	5 %	6%
    Total entitlement liquids and gas production (mboe per day)	1460.7	1416.5	3%	1474.0	(4 %)	1450	1461	1417	(1 %)	3%

    

    We generated total revenuesof NOK 158.7 billion in 2009, NOK 219.8 billion in 2008 and NOK 179.2 billion in 2007. A decrease of 37% in the average price in USD of oil sold by E&P Norway to Manufacturing and Marketing accounted for NOK 52.1 billion of the decrease in revenues, and a 26% decrease in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas accounted for NOK 18.9 billion of the decrease in revenues. This was partly offset by a positive currency exchange rate deviation of NOK 12.6 billion due to a 14.0% increase in the USD/NOK exchange rate. Furthermore, lifted volumes of liquids decreased by 4.0%, making a negative contribution of NOK 5.7 billion, which was partly offset by a 4.3% increase in lifted volumes of natural gas, making a positive contribution of NOK 2.9 billion.

    

    The average daily lifting of liquids in 2009 was 778 mboe per day, compared with 808 mboe per day in 2008 and 831 mboe per day in 2007. Over time, the volumes lifted and sold will equal the volumes produced, but they may be higher or lower in any period due to differences between the capacity of the vessels lifting our volumes and the actual entitlement production in the period. The average daily underlift was 6 mboe per day in 2009 and 16 mboe per day in 2008, compared with an average overlift of 13 mboe per day in 2007.

    There was an increase in total revenues from NOK 179.2 billion in 2007 and 2006.to NOK 219.8 billion in 2008. An increase of 31% in the average oil price in USD of oil sold by E&P Norway to Manufacturing and Marketing contributed NOK 54.6 billion, and a 35% increase in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas, contributed NOK 17.9 billion. Lifted volumes of natural gas increased by 6.7%, makingresulting in a positive contribution of NOK 3.2 billion. This was offset by a negative currency exchange rate deviation of NOK 11.1 billion due to a 7.2% decrease in the USD/NOK exchange rate. In addition, other income increased by NOK 3.1 billion, mainly as a result of a change in the fair value of derivatives. Lifted volumes of crude oil decreased by 2.5%, making a negative contribution of NOK 3.1 billion.

    From 2006 to 2007 there was an increase of 11% in the average oil price in USD of oil sold by E&P Norway to Manufacturing and Marketing contributed NOK 13.3 billion, and a 2% increase in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas, contributed NOK 1.1 billion. This was offset by a negative currency exchange rate deviation of NOK 12.0 billion due to a 9% decrease in the USD/NOK exchange rate. Lifted volumes of crude oil decreased by 3%, making a negative contribution of NOK 3.8 billion, and there was a 2% decrease in lifted volumes of natural gas, making a negative contribution of NOK 0.9 billion. In addition, other income increased by NOK 2.4 billion, mainly as a result of higher income from derivatives and higher processing income.

    The average daily lifting of oil in 2008 was 808 mbbl per day, compared to 831 mbbl per day in 2007 and 856 mbbl per day in 2006.

    

     Average daily entitlement oil production in 2008 was 824 mbbl per day, compared to 818 mbbl per day in 2007 and 864 mbbl per day in 2006. The increased production from 2007 to 2008 was mainly related to start-up of the Volve field in February 2008, higher production at Kvitebjørn until the shutdown from August 2008 compared to 2007 when Kvitebjørn was shut down to allow safe drilling operations most of the year, new wells at Fram and building up production at Ormen Lange. The increase was partly offset by declining production from wells in the Grane, Norne, Troll Olje, Tordis, Visund and Sleipner fields.

    The reduced production from 2006 to 2007 was largely caused by the shutdown of production on the Kvitebjørn field from 1 May 2007 in order to allow drilling operations to be carried out safely, as well as a natural decline on the Oseberg field. The reduction in production was partly offset by increased production from the Kristin field, which reached plateau level in late 2007.

    The average daily entitlement gas production was 637 mboe per day in 2008 (equal to 101.3 mmcm or 3.58 mmcf), compared to 599 mboe in 2007 (equal to 95.2 mmcm or 3.36 mmcf) and 610 mboe in 2006 (equal to 97.0 mmcm or 3.42 mmcf).

    Operating, general and administrative expenses were NOK 23.5 billion in 2009, compared with NOK 23.4 billion in 2008. Operating, general2008 and administrative expenses were NOK 29.4 billion in 2007 and NOK 19.6 billion in 2006. Operating costs amounted to NOK 23.5 billion in 2008. Operating costs amounted to NOK 29.1 billion in 2007 and NOK 19.2 billion in 2006.2007. Increased processing/transportation cost were partly offset by lower operating plant cost.

    The decrease of NOK 6.0 billion in operating, general and administrative expenses from 2007 to 2008 was mainly due to a decrease in other expenses of NOK 6.8 billion, mainlywhich was largely due to restructuring costs as a result of the merger in 2007 and a decrease in transportation costs byof NOK 1.3 billion in transportation costs in 2008, due in part to increased elimination and reduced booking.booking of transportation capacity. In addition, selling, general &and administrative expenses decreased by NOK 0.4 billion andwhile processing costs decreased by NOK 0.3 billion, from 2007 to 2008. This was partially countered by an increase of NOK 2.7 billion in operating plant costs, which was largely due to the start up of new fields of NOK 1.1 billion, increased cost forcosts of NOK 0.5 billion of gas purchased for injection at Grane by NOK 0.5 billion and increased operationaloperating activity.

    

    The average daily production of entitlement liquids in 2009 was 784 mboe per day, compared with 824 mboe per day in 2008 and 818 mboe per day in 2007. The decrease in production from 2008 to 2009 was mainly related to expected declines on several fields, various operational issues on the Kristin, Gullfaks South and Norne fields, turnaround and less NGL due to less gas offtake on Oseberg and close-down of the Tordis subsea separator from the end of May 2008 due to leakage from a well. The decrease was partly offset by build up of production at Ormen Lange and Snøhvit and new production from Alve, Tyrihans, Volve, Vilje and Yttergryta, and Kvitebjørn returning to full production from July 2009 after it was shut down due to a damaged gas pipeline.
    
    The increased production from 2007 to 2008 was mainly related to the start-up of the Volve field in February 2008, higher production on Kvitebjørn than in 2007until the shutdown from August 2008, when Kvitebjørn was shut down to allow safe drilling operations most of the year, new wells on Fram and a building up of production on Ormen Lange. The increase was partly offset by declining production from wells in the Grane, Norne, Troll Olje, Tordis, Visund and Sleipner fields.

    The average daily production of NOK 9.8 billionentitlement gas was 666 mboe per day in operating, general2009 (equal to 105.9 mmcm or 3.74 mmcf), compared with 637 mboe in 2008 (equal to 101.3 mmcm or 3.58 mmcf) and administrative expenses from 2006 to 2007 was mainly due to an increase in other expenses of NOK 6.3 billion, mainly due to restructuring costs as a result of the merger599 mboe in 2007 and an increase of NOK 3.2 billion in operating plant costs, which was largely due(equal to an increase in well maintenance costs of NOK 0.9 billion, higher operation and maintenance costs of NOK 0.8 billion, higher production fees, mainly due to the introduction of nitrogen oxide charges of NOK 0.4 billion in 2007, Grane Gas purchases totalling NOK 0.3 billion, higher business development costs of NOK 0.3 billion and higher head office research and development costs of NOK 0.2 billion. In addition, processing costs increased by NOK 0.4 billion from 2006 to 2007.

    

    95.2 mmcm or 3.36 mmcf).
    
    The unit production cost was NOK 36.93 per boe in 2009, compared with NOK 37.31 per BOEboe in 2008 compared withand NOK 46.26 per boe in 2007 and NOK 26.93 per boe in 2006.2007. The total production cost was NOK 19.5 in 2009, compared with NOK 19.9 billion in 2008, compared withand NOK 23.9 billion in 2007 and NOK 14.5 billion in 2006.2007.

    The 19% decrease from 2007 to 2008 is due to a 17% decrease in costs of 17% and ana 3% increase in production of 3%.production. Indirect operating costs decreased by NOK 7.2 billion, mainly due to restructuring costs as a result of the merger in 2007 and the refund in 2008 of the licence partners' proportional share of the restructuring costs. Operating plant costs increased by NOK 2.7 billion, due to both higher activity and increased pressure on costs in the industry. NOK 1.1 billion is attributed to startupthe start-up of new fields. Other variable costs increased by NOK 0.8 billion due to losslosses on sales of assets.

    The 60% increase from 2006 to 2007 is due to both an increase in costs of 65% and a decrease in production of 4%. Indirect operating costs increased by NOK 5.5 billion due to restructuring costs as a result of the merger in 2007. Direct operating costs increased by NOK 3.2 billion, due to both higher activity and increased pressure on costs in the industry.

    Depreciation, depletion and impairment expenses were NOK 25.7 billion in 2009, compared with NOK 24.0 billion in 2008. Depreciation, depletion2008 and amortisation expenses were NOK 23.0 billion in 2007 and NOK 20.9 billion2007. The increase is mainly due to new fields in 2006. production in 2009.

    The NOK 1.0 billion increase from 2007 to 2008 was mainly due to higher depreciation costs as a result of higher depreciation offshore due toresulting from increased production and changes in the portfolio of producing fields.

    The NOK 2.1 billion increase from 2006 to 2007 was mainly due to higher depreciation costs as a result of asset retirement costs and higher depreciation offshore due to changes in the portfolio of producing fields.

    Exploration expenditure (including capitalised exploration expenditure) in 20082009 amounted to NOK 8.2 billion, compared with NOK 8.7 billion compared toin 2008 and NOK 5.7 billion in 2007, and NOK 4.6 billion2007. The decrease from 2008 to 2009 was mainly due to fewer wells being drilled in 2006. 2009.

    The increase stemsfrom 2007 to 2008 primarily stemmed from a higher number of wells being drilled. The increase in exploration expenditure from 2006 to 2007 was mainly due to increased drilling and seismic activity, as well as to a significant increase in the area fee.

    From 2006 to 2007 the drilling expenditure increased by approximately NOK 0.4 billion, while the increase in seismic activity amounted to NOK 0.3 billion. The increase in area fee was due to new regulations on the NCS and it contributed approximately NOK 0.4 billion to the increased costs.

    Exploration expenses in 20082009 were NOK 5.2 billion, compared with NOK 5.5 billion compared toin 2008 and NOK 3.6 billion in 2007,2007.

    In 2009, 39 exploration and NOK 3.5 billion in 2006, mostly due to moreappraisal wells being drilled.

    and two exploration extension wells were completed on the NCS, of which 31 exploration and appraisal wells and both exploration extension wells were announced as discoveries. In 2008, 39 exploration and appraisal wells and nine exploration extension wells were completed on the NCS, of which 27 exploration and appraisal wells and six exploration extension wells were discoveries.

    In 2007, 24 exploration and appraisal wells and two exploration extension wells were completed. Of these, 16 exploration and appraisal wells and both exploration extension wells resulted in discoveries.

    In 2006, 18The drilling of two exploration and appraisal wells and five exploration extension wells were completed, of which eight appraisal and exploration wells and two exploration extension wells were discoveries.

    Drilling of seven exploration and appraisal wells werewas ongoing at the end of the fourth quarter of 2008. Ten2009. Three exploration and appraisal wells have been completed since 31 December 2008. Of these, eight exploration2009. All of the wells, Omega North, Lower Lunde and Hild appraisal, wells were discoveries: Obesum2, Visund S1, Dompap/Måke sidetrack, Fulla, Curran, Pan sidetrack, Katla and Asterix. Verona and Obelix were dry.discoveries.

    The reconciliation of exploration expenditure with exploration expenses is shown in the table below.
    

    Exploration	Twelve months ended 31 December
    (in NOK billion)	2008	2007	08-07 Changes	2006	07-06 Changes
    Exploration expenditure (activity)	8.67	5.75	51%	4.65	24%
    Expensed, previously capitalized exploration expenditure	0.75	0.05	1,398%	0.18	(72 %)
    Capitalized share of current period's exploration activity	(3.89)	(2.16)	(80 %)	(1.35)	(60 %)
    Exploration expenses	5.53	3.64	52 %	3.48	5 %

    	For the year ended 31 December
    Exploration (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Exploration expenditure (activity)	8.2	8.7	5.8	(6 %)	51%
    Expensed, previously capitalized exploration expenditure	1.2	0.7	0.1	57%	1398%
    Capitalized share of current period's exploration activity	(4.2)	(3.9)	(2.2)	(7 %)	(80 %)
    Exploration expenses	5.2	5.5	3.6	(6 %)	52 %

    Net operating income in 20082009 was NOK 104.3 billion compared with NOK 166.9 billion compared toin 2008 and NOK 123.2 billion in 20072007. The NOK 62.6 billion decrease in 2009 was mainly due to decreased prices for oil and NOK 135.1 billion in 2006. gas.

    The NOK 43.7 billion increase in 2008 was mainly due to price and volume effects and NOK 5.5 billion in restructuring and other costs arising from the merger in 2007.

    The NOK 11.9 billion decrease from 2006 to 2007 was mainly due to price and volume effects, NOK 5.5 billion in restructuring and other costs arising from the merger, higher operating costs of NOK 3.2 billion, mainly due to higher operation and maintenance costs and well maintenance, increased depreciation, mainly due to higher asset retirement costs, which contributed NOK 2.1 billion to the decrease, an increase in other operating expenses of NOK 1.0 billion and processing and transportation costs increasing by NOK 0.4 billion in 2007.

     Top

    4.1.4.24.1.5.2 Outlook

    Our 2010 drilling portfolio is well balanced between frontier impact wells, growth wells and infrastructure near wells.

    We expect to continueExploration is our high level of exploration activity in 2009preferred growth vehicle and we plan to drill approximately 30-35 explorationcurrently have a robust portfolio consisting of frontier impact wells, on the NCS. A significant part of the drilling activity is expected to take place in mature areas close towells that could provide a basis for establishing new infrastructure (growth wells), and infrastructure near existing infrastructure.wells.

    We also plan to drill wells in frontier areas of the Norwegian Sea and in the Barents Sea. We have secured rig capacity for our drilling activity level in 2009.2010 and are well positioned to take advantage of the expected future softening in the rig market. We expect to drill 16 to 20 exploration wells on the NCS in 2010.

    A plan for development and operation (PDO) of the GoliatGudrun field in the BarentsNorth Sea has beenwas submitted to the government byGovernment in February 2010. Statoil is the operator Eni. StatoilHydroand has a 35%46.8% share in the field.

    In the period leading up to 2012, several new fields are expected to commence production. Gjøa, Vega/Vega SørSouth and Morvin are expected to commencestart production in 2010, while the BP-operated Skarv field is expected to commencestart production in 2011.

    

    Yttergryta is the first field that StatoilHydro as a joint company has developed from PDO to production start.

    Three new fields will commence production during 2009; Yttergryta has already started producing, while Alve and Tyrihans will commence production later.

     Top

    4.1.5 4.1.6 International Exploration and& Production

    Our strategy is to develop keydeliver international growth in the short and medium term from existing positions, in four focus areas: deep water, heavy oil, gaswhile creating new opportunities for long-term value chains and harsh environments. It is also the framework for new growth and portfolio optimisation.

    creation.

    InternationalIn our international exploration activities in 2008 have2009, we focused on high-grading our portfolio with strict prioritisation and sequencing of the drilling targets. FourtyIn total, 29 exploration and appraisal wells were completed in 20082009 and, at year end, eightseven wells were announced as discoveries, six of thesewhich were considered to be discoveries or confirmed discoveries.completed this year and one was completed last year. At year end, nine wells were pending final evaluation. The total exploration expenses were NOK 11.5 billion in 2009, compared with NOK 9.2 billion in 2008, compared with NOK 7.7 billion in 2007.2008.

    Our international entitlement production was 357 mboe per day in 2009, compared with 290 mboe per day in 2008 compared to 307 mboe per day in 2007.2008. The average daily equity production of oil and gas was 465512 mboe per day in 2008,2009, compared to 422with 465 mboe in 2007. 2008.

    Equity volumes represent produced volumes under a PSAProduction Sharing Agreement (PSA) contract that corresponds to StatoilHydro'sStatoil's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent StatoilHydro'sStatoil's share of the volumes distributed to the partners in the field, whichfield. They are subject to deductions for, among other things, royalties and the host government's share of profit oil. Entitlement volumes lifted isare the basis for revenue recognition, while equity production volumes affect operating costs more directly.directly. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The d istinctiondistinction between equity and entitlement is relevant to most PSA regimes. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.

    AcquisitionsOur international portfolio has been further strengthened in 2008 included2009 through a successful bid for a service contract on the purchaseWest Qurna 2 field in the second licence round in Iraq. Statoil will hold an 18.75% equity share in the consortium. In early 2010, we increased our equity share in the St. Malo discovery in the US Gulf of 50% of the Peregrino project in Brazil, making StatoilHydro 100% owner and operator of the field. StatoilHydro formed a strategic alliance with Chesapeake Energy Corporation and acquired a 32.5% interest in Chesapeake's Marcellus shale gas acreage onshore USA.Mexico from 6.25% to 21.5% by exercising our pre-emption rights. We closed the sale of allalso divested our shallow water assets on the ShelfDanish continental shelf, and our equity share in the GulfKharyaga field in Russia has been reduced from 40% to 30%. An overview of Mexico (GoM) to Mariner Energy, Inc. and divested our interestsportfolio transactions in the UK fields Dunlin (28.76%) and Merlin (2.35%).2009 is presented in article 3.2.1 - Portfolio management.

    The total capital expenditure of NOK 48.739.4 billion in 20082009 was higherlower than in previous years, triggered by many projects under development in additionlast year, mainly due to the acquisition of new assets to secure longer term growth, such asequity in Peregrino in Brazil and Marcellus Shale acreage in USA.the USA in 2008.

     Top

    4.1.5.1 4.1.6.1 Profit and loss analysis

    INT generated total revenues of NOK 46.141.8 billion in 20082009 and net operating income wasof NOK 12.82.6 billion. The average daily entitlement production of liquidliquids was 232 mbbl283 mboe and the average daily entitlement production of gas was 5974 mboe.

    	Twelve months ended 31 December					For the year ended 31 December
    Income statement
    (in NOK billion)	2008	2007	08 -07 Change	2006	07-06 Change
    IFRS income statement (in NOK billion)						2009	2008	2007	09-08 change	08-07 change
    Total revenues and other income	46.1	41.6	11%	32.6	28 %	41.8	46.1	41.6	(9 %)	11%
    Purchase, net of inventory variation	1.7	1.9	(12 %)	1.0	93 %	1.1	1.7	1.9	(32 %)	(12 %)
    Operating expenses	5.6	5.4	4%	4.2	31 %	6.7	5.6	5.4	18%	4%
    Selling, general and administrative expenses	3.2	3.3	(4 %)	2.0	65 %	2.8	3.2	3.3	(11 %)	(4 %)
    Depreciation, amortisation and impairment	13.7	11.1	23%	14.4	(23 %)	17.1	13.7	11.1	25 %
    Exploration expenses	9.2	7.7	19%	7.2	7 %	11.5	9.2	7.7	26%	19%
    Total expenses	33.3	29.4	13%	28.7	3 %	39.2	33.3	29.4	18%	13%
    Net operating income	12.8	12.2	5%	3.9	210 %	2.6	12.8	12.2	(80 %)	5%
    Operational data:
    Liquids price (USD/bbl)	88.7	69.1	28%	60.9	13 %	58.4	88.7	69.1	(34 %)	28%
    Liquids price (NOK/bbl)	499.3	404.8	23%	391.0	4 %	366.5	499.3	404.8	(27 %)	23%
    Liftings:
    Liquids (mboe per day)	210.8	250.0	(16 %)	191.4	31 %	267	211	250	26 %	(16 %)
    Natural gas (mboe per day)	58.9	54.9	7%	40.2	37 %	74	59	55	25 %	7%
    Total liquids and gas liftings (mboe per day)	269.7	304.8	(12 %)	231.6	31 %	341	270	305	26 %	(12 %)
    Production:
    Entitlement liquids (mboe per day)	231.5	252.2	(8 %)	193.7	30 %	283	232	252	22 %	(8 %)
    Entitlement natural gas (mboe per day)	58.9	55.0	7%	40.2	37 %	74	59	55	25 %	7%
    Total entitlement liquids and gas production (mboe per day)	290.5	307.2	(5 %)	233.9	31 %	357	290	307	23 %	(5 %)
    Total equity liquids and gas production (mboe per day)	464.7	422.1	10%	303.5	39 %	512	465	422	10 %	10%

    We generated total revenues of NOK 41.8 billion in 2009, compared with NOK 46.1 billion in 2008 compared toand NOK 41.6 billion in 20072007. The decrease from 2008 to 2009 was mainly related to a 34% decrease in realised liquid and gas prices that made a negative contribution of NOK 32.6 billion14.3 billion. This reduction was partly offset by a 26% increase in 2006. the lifted volumes, which contributed positively in the amount of NOK 11.2 billion.

    The increase from 2007 to 2008 was mainly related to a 19% increase in realised liquid and gas prices, which contributed NOK 7.7 billion, gaingains from the sale of assets, and income from affiliated companies which contributed NOK 2.2 billion. This was partly offset by aan 11% decrease in the lifted volumes, which contributed negatively bymade a negatvie contribution of NOK 5.4 billion.

    The average daily liquid lifting of liquids was 267 mboe in 2009, compared with 211 mbblmboe in 2008 compared withand 250 mbblmboe in 2007. Over time, the volumes lifted and sold will equal our production of entitlement volumes, but they may be higher or lower in any period due to differences between the capacity and timing of the vessels lifting our volumes and the actual entitlement production in the period. The average daily over/underlift in 2009, 2008 and 2007 was 2 mboe underlift, 4 mboe underlift and 191 mbbl in 2006.19 mboe overlift, respectively.

    The average daily entitlement production of liquidliquids was 283 mboe in 2009, compared with 232 mbblmboe in 2008 compared withand 252 mbblmboe in 20072007. The 22% increase in average daily liquids production from 2008 to 2009 was mainly related to the ramp-up of the Agbami field in Nigeria and 194 mbblSaxi-Batuque in 2006. Angola, start-up on Tahiti in the Gulf of Mexico and a higher entitlement factor on PSA fields due to lower prices.

    The 9% decrease in average daily liquid production from 2007 to 2008 was mainly related to decreased production from ACG in Azerbaijan due to the Central Azeri gas leakage and Kizomba A in Angola coming off plateau, in addition to overall reduced entitlement volumes from PSA fields due to high realised prices. These decreases were partly offset by start-upsthe start-up of Agbami in Nigeria and the Saxi-Batuque and Mondo fields in Angola.

    The average daily entitlement production ofgas was 74 mboe in 2009 (equivalent to 12 mmcm or 413 mmcf), compared with 59 mboe in 2008 (equivalent to 9 mmcm or 331 mmcf), compared to and 55 mboe in 2007 (equivalent to 9 mmcm or 309 mmcf) and 40 mboe in 2006 (equivalent to 6 mmcm or 224 mmcf). The 7%25% increase in daily gas production from 2008 to 2009 was mainly related to higher off-take from the In Salah field and increased production from Independence Hub due to extensive hurricane activity in 2008.

    The increase in daily gas production from 2007 to 2008 was mainly related to the ramp-up of production from Shah Deniz in Azerbaijan, and the start-up of new gas fields in the GoM in the third and fourth quarterquarters of 2007 (Q, Spiderman, San Jacinto). The increase was partly offset by divestment of the GoM shelf fields with effect from year end 2007 and reduced offtakeoff-take and a maintenance turnaround aton the In Salah field in Algeria.

    The average daily equity liquidliquids and gas production was 465512 mboe per day in 2008,2009, compared with 465 mboe in 2008 and 422 mboe in 2007 and 304 mboe in 2006.2007.

    The unit of production cost based on entitlement volumes was USD 7.2 per boe in 2009, compared with USD 7.6 per boe in 2008 compared toand USD 5.9 per boe in 2007 and USD 5.8 per boe in 2006. 2007.

    Measured in NOK, it was 45.2 per boe in 2009, 42.2 per boe in 2008 and 34.4 per boe in 20072007. The 6.3% increase in unit of production cost measured in NOK from 2008 to 2009 is mainly due to the strengthening of USD in relation to NOK and 37.5increased preparations for operating activity. These increases were partly offset by a higher entitlement factor due to lower realised oil and gas prices in 2006.2009. The 23% increase in unit of production cost measured in NOK from 2007 to 2008 iswas mainly due to reduced entitlement production and increased costcosts related to new fields on stream, increased activity, inflation and industry cost pressure.

    Production costs are incurred based on our equity production. Management therefore thinks that unit of production cost based on equity production is a better measure of cost control than unit of production cost based on entitlement volumes. Based on equity volumes, the production cost per boe for the three periods was USD 4.9, USD 4.6 and USD 4.3 respectively. The increase between the years was mainly due to an underlying cost pressure and more expensive fields coming on stream.

    The unit of production cost based on equity volumes was USD 4.9 per boe in 2009, compared with USD 4.6 per boe in 2008 compared toand USD 4.3 per boe in 2007 and USD4.50 per boe in 2006.2007. Measured in NOK, it was 42.230.8 per boe in 2009, 25.9 per boe in 2008 and 25.0 per boe in 2007 and 28.9 per boe in 2006. See report section 4.1.9 Financial performance-Strong operational performance-Reported Volumes for a description of entitlement and equity volumes.2007.

    Operating, general and administrative expenses decreasedincreased by NOK 0.10.7 billion to NOK 10.59.5 billion in 2009, compared with NOK 8.8 billion in 2008 compared toand NOK 10.68.7 billion in 2007 and NOK 7.2 billion in 2006.2007.

    Depreciation, depletion and amortisation expenses were NOK 17.1 billion in 2009, compared with NOK 13.7 billion in 2008 compared withand NOK 11.1 billion in 2007 and2007. The 25% increase from 2008 to 2009 was due to an increase of NOK 14.44.6 billion in 2006. ordinary depreciation, which was mainly due to new assets coming on stream. This increase was partly offset by a NOK 1.2 billion decrease in net impairments, which was mainly due to adverse effects of market conditions in 2008.

    The 23% increase in 2008 compared to 2007 was mainly due to an increased net impairment write-down effect of NOK 0.9 billion mainlythat was largely related to market conditions, and a NOK 1.7 billion increase in ordinary depreciation that was mainly due to new assets coming on stream and a changereduction in the provedproven reserves estimates in 2008, which formsform the basis for the unit of production depreciation.

    Depreciation, depletion and amortisation expenses were NOK 11.1 billion in 2007, compared with NOK 14.4 billion in 2006. The 23 decrease in 2007 compared to 2006 was mainly due to the NOK 4.9 billion impairment write-down effect on depletion, depreciation and
    amortisation accounts of US GoM shelf fields and Front Runner in our US portfolio in 2006. This decrease was partly offset by impairment
    write-downs of NOK 1.2 billion for Lufeng, Front Runner, Thunder Hawk and US GoM shelf fields in 2007. A change in the proved reserves estimates in 2007, which forms the basis for the unit of production depreciation, and increased depreciation from new assets coming on
    stream also contributed to the increase.

    Exploration	Twelve months ended 31 December
    (in NOK billion)	2008	2007	08-07 Changes	2006	07-06 Changes
    Exploration expenditure (activity)	9.1	8.5	8%	8.7	(3 %)
    Expensed, previously capitalized exploration expenditure	3.0	1.6	88%	1.3	26 %
    Capitalized share of current period's exploration activity	(2.9)	(2.4)	(23 %)	(2.8)	16 %
    Exploration expenses	9.2	7.7	20 %	7.2	7 %

    Depreciation, depletion and amortisation	For the year ended 31 December
    (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Ordinary depreciations	16.2	11.6	9.9	40 %	17 %
    Impairments	2.6	3.2	1.2	(19 %)	167 %
    Reversal of impairments	(1.7)	(1.1)	0.0	55 %	n/a
    Depreciation, depletion and amortisation cost	17.1	13.7	11.1	25 %	23 %

    Exploration expenditure was NOK 8.7 billion in 2009, compared with NOK 9.1 billion in 2008 compared withand NOK 8.5 billion in 20072007. The decrease from 2008 to 2009 was mainly due to a reduction in seismic spending, reduced drilling activity and lower field evaluation costs. The reduction was partly offset by the strengthening of the USD/NOK 8.7 billion in 2006. exchange rate from 2008 to 2009.

    The increase from 2007 to 2008 was mainly due to more expensive wells, higher field evaluation costs and delineation drilling on the oil sands project in Canada.

    Exploration	For the year ended 31 December
    (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Exploration expenditure (activity)	8.7	9.1	8.5	(4 %)	8%
    Expensed, previously capitalised exploration expenditure	5.8	3.0	1.6	94%	88%
    Capitalised share of current period's exploration activity	(3.0)	(2.9)	(2.4)	4 %	(23 %)
    Exploration expenses	11.5	9.2	7.7	26 %	19 %

    Exploration expensesexpenses were NOK 11.5 billion in 2009, compared with NOK 9.2 billion in 2008 compared withand NOK 7.7 billion in 20072007. The increase from 2008 to 2009 is mainly due to the net impairment effect of capitalised exploration assets of NOK 2.9 billion, partly offset by decreases in drilling activity and NOK 7.2 billion in 2006. seismic spending.
    
    The increase from 2007 to 2008 was mainly due to more expensive wells, higher field evaluation cost and delineation drilling on the oil sands project in Canada andas well as net impairment write-down effects that were mainly related to changes in market conditions. The increase was partly offset by an increased capitalisation rate.

    In total, 4029 exploration and appraisal wells were completed in 20082009 and, at year end, eightseven wells were announced as discoveries, six of thesewhich were considered to be discoveries or confirmed discoveries.completed this year while one well was completed last year. At year end, nine wells were pending final evaluation. In 2008, 40 exploration and appraisal wells were completed, eight of which were announced as discoveries. In 2007, 47 exploration and appraisal wells were completed, 18 of which were considered discoveries. In 2006, 55 exploration and appraisal wells were completed, 24 of which were consideredannounced as discoveries.

    Net operating income in 20082009 was NOK 2.6 billion, compared with NOK 12.8 billion compared toin 2008 and NOK 12.2 billion in 20072007. The decrease is mainly related to reduced prices, which contributed negatively in the amount of NOK 14.3 billion, increased depreciation, depletion and amortisation, which contributed NOK -3.33.4 billion, in 2006. exploration expenses increasing by NOK 2.3 billion, other income decreasing by NOK 1.2 billion, which was mainly related to the sale of assets and miscellaneous increases of NOK 0.2 billion. This was partly offset by increased lifted volumes, which positively affected the result by NOK 11.2 billion.

    The increase from 2007 to 2008 was mainly related to the price effect, which contributed NOK 7.7 billion, and gaingains from the sale of assets and income from affiliated companies of NOK 2.2 billion and other miscellaneous increases of NOK 0.2 billion, partly offset by decreased entitlement production, contributingwhich contributed NOK 5.4 billion, increased depreciation, depletion and amortisation of NOK 2.6 billion, and exploration, which contributed NOK 1.5 billion.

    
    

     Top

    4.1.5.2 4.1.6.2 Outlook

    Our

    Going forward, we will build on our strong production performance from 2009 and lay the foundation for further medium and long-term growth both by focusing on exploration strategy remains unchanged, but weand by maturing and developing our existing portfolio of projects.

    We will have adjusted oura continued strong focus on exploration activity somewhat due to changesand are planning for spending in the oil price.2010 on a par with 2009. We expect to drill approximately 30-35around 30 international exploration and appraisal wells in 2009.this year.

    Ninety-six percentAll of our projected 2012 production is related to already-sanctioned fields. During 2009 weWe expect the Gimboa field in Angola and Tahiti and Thunder Hawk fieldsLeismer Demonstration project to start production in the USA to start production. We expect our short term production to be affected by OPEC quotas.

    Our exploration strategy remains unchanged as we view exploration as our primary growth tool. We will continue to look at acreage acquisitions in the areas that have high resource potential. However, we have adjusted our exploration activity somewhat due to changes in the oil price environment and therefore expect slightly lower activity in 2009 compared to last year.

    Approximately 30-35 international exploration and appraisal wells are expected to be drilled in 2009. Rig capacity has been confirmed for this drilling.fourth quarter 2010.

    We will continue to develop and execute new projects in the portfolio with athe focus on cost consciousness and capital flexibility.

     Top

    4.1.6 4.1.7 Natural Gas

    The market in 2009 was characterised by falling gas prices and lower demand. Despite the challenging market situation, Natural Gas exportsmanaged to deliver strong results in 2009.

    We experienced a drop in natural gas prices in 2009. Our volume-weighted average price was NOK 1.90 per scm in 2009, a decrease of 21% from 2008. Most gas supply contracts in Europe are indexed to oil products, which means that a change in oil prices will affect the gas markets after a certain time delay (6-9 months). During the second half of 2008, oil prices fell sharply from more than USD 140 per barrel to some USD 40 per barrel. This affected natural gas prices in the second half of 2009.

    All of the gas from the NCS reachedsold by the Natural Gas business area is purchased from Exploration & Production Norway (EPN) at a record highmarket-based internal price. The drop in 2008 and are expected to grow further.

    We are currently the second largest supplier of natural gas to Europe,sales prices was thus largely offset by a lower internal purchase price. Our average internal purchase price was NOK 1.38 per scm in 2009, a decrease of 26% from 2008.

    Statoil sold 41.4 bcm of entitlement gas in 2009, a slight increase compared with a market share of approximately 15% in Europe, including the volumes from the State's Direct Financial Interest. Gas exports from the NCS were at a record level in 2008 and are expected to grow. In 2008, StatoilHydro sold 39.3 bcm entitlement gas.2008. In addition, we sold 32.035.3 bcm of NCS gas on behalf of the SDFI. Most of the gas was sold to European energy providers under long-term contracts. Our market share is approximately 20-25% in Germany and France and approximately 15% in the UK.

    Two significant factors strongly influence our financial results: the external sales priceUK and the internal transfer price.Netherlands.

    In 2008, natural gas prices reachedDuring 2009, we have scaled up our trading activities and delivered a record highs. Our volume weighted averagehigh trading result, which was made possible by our downstream positions and our ability to capitalise on price was NOK 2.40 per scm in 2008, an increase of 45% from 2007. Most gas supply contracts in Europe are indexed towards oil products, such that a change in oil prices will affect the gas markets with some time delay (6-9 months). Increasing oil prices up until the summer months of 2008 were followed by high prices in the gas markets in late 2008. During the second half of 2008 oil prices fell sharply from more than 140 dollars per barrel to some 40 dollars per barrel. We expect this will affect natural gas prices in 2009.volatility.

    All of the gas from the NCS sold by the Natural Gas business area is purchased from Exploration & Production Norway (E&PN). Previously, the internal transfer price formula was linked to the oil price for Brent Blend. A new market-based internal price for natural gas was put into effect from 1 January 2008. The transfer price formula for natural gas has been updated to better reflect fundamental changes in the markets for competing energies, i.e. crude oil, developments in natural gas markets and changes in the natural gas sales contracts portfolio. In 2008 the transfer price was NOK 1.87 per scm.

    The total capital expenditure of NOK 2.0 billion in 2008 was lower than in previous years, mainly due to fewer pipeline, storage and processing plants being under development.

     Top

    4.1.6.14.1.7.1 Profit and loss analysis

    Total revenues

     Revenues in the Natural Gas business mainly come from gas sales under long-term gas sales contracts and tariff revenues from transportation and processing facilities. Natural Gas generated revenues of NOK 110.898.6 billion in 2008.

    	Twelve months ended 31 December
    Income statement
    (in NOK billion)	2008	2007	08 -07 Change	2006	07-06 Change
    Total revenues and other income	110.8	73.5	51%	97.1	(24 %)
    Purchase, net of inventory variation	80.9	56.7	43 %	61.3	(8 %)
    Operating expenses	13.8	12.3	13 %	12.1	2 %
    Selling, general and administrative expenses	1.3	1.1	9 %	0.5	125 %
    Depreciation, amortisation and impairment	2.3	1.8	25%	1.4	29 %
    Total expenses	98.3	72.0	37%	75.4	(5 %)
    Net operating income	12.5	1.5	739%	21.7	(93 %)
    Operational data:
    Natural gas sales StatoilHydro entitlement (bcm)	39.3	35.6	10 %	35.9	(1 %)
    Natural gas sales (third-party volumes) (bcm)	5.9	6.4	(8 %)	4.3	49 %
    Natural gas sales (bcm)	45.2	42.0	8 %	40.2	4 %
    Natural gas sales on commission	1.4	0.8	79 %	NA	-
    Natural gas price (NOK/scm)	2.40	1.66	45 %	NA	-
    Transfer price natural gas (NOK/scm)	1.87	1.39	34 %	1.35	3 %
    Regularity at delivery point	100.0 %	100.0 %	0%	100.0 %	0 %

    2009.

    	For the year ended 31 December
    IFRS income statement (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Total revenues and other income	98.6	110.8	73.5	(11 %)	51%
    Purchase, net of inventory variation	62.1	80.9	56.7	(23 %)	43 %
    Operating expenses	14.4	13.8	12.3	4 %	13 %
    Selling, general and administrative expenses	0.8	1.3	1.1	(38 %)	9 %
    Depreciation, amortisation and impairment	2.8	2.3	1.8	22 %	25%
    Total expenses	80.1	98.3	72.0	(19 %)	37%
    Net operating income	18.5	12.5	1.5	48 %	739%
    Operational data:
    Natural gas sales Statoil entitlement (bcm)	41.4	39.3	35.6	5 %	10 %
    Natural gas sales (third-party volumes) (bcm)	8.4	5.9	6.4	42 %	(8 %)
    Natural gas sales (bcm)	49.8	45.2	42.0	10 %	8 %
    Natural gas sales on commission	1.3	1.4	0.8	(7 %)	79 %
    Natural gas price (NOK/scm)	1.90	2.40	1.66	(21 %)	45 %
    Transfer price natural gas (NOK/scm)	1.38	1.87	1.39	(26 %)	34 %
    Regularity at delivery point	100.0 %	100.0 %	100.0 %	0 %	0%

     

    
    

    

    The total revenuesRevenues in the Natural Gas business mainly come from gas sales under long-term gas sales contracts and tariff revenues from transportation and processing facilities. Natural Gas generated revenues of NOK 98.6 billion in 2009, compared with NOK 110.8 billion in 2008 compared withand NOK 73.5 billion in 2007 and NOK 97.1 billion2007. The 11% decrease from 2008 to 2009 was mainly due to lower prices for natural gas throughout 2009 compared with 2008, partly offset by a 10% increase in 2006. sales volumes.
    
    The 51% increasedecrease in total revenues from 2007 to 2008 was mainly due to the high prices for natural gas throughout 2008, compared with 2007, as well as a 10%an 8% increase in entitlement sales volumes.

    The 24% decrease in total revenues
    
    Purchase, net of inventory variation decreased by 23% from 20062008 to 2007 was mainly due to declining natural gas prices measured in NOK in 20072009 and negative changes in fair value of derivatives.

    Cost of goods sold increased by 43% from 2007 to 2008. The decrease from 2008 and decreased by 8% from 2006 to 2007.2009 is mainly related to a 26% decrease in the transfer price to E&PN. The increase from 2007 to 2008 iswas mainly related to a 34% increase in the transfer price and higher NCS volumes purchased from E&PN. The decrease from 2006 to 2007 is mainly related to a decrease in the third party purchase price of natural gas, partly offset by a slight increase in the transfer price paid to E&PN.

    
    
    Operating, sellingSelling, general and administrative expenses increased byin 2009 remained at the same level as in 2008. The 12% increase from 2007 to 2008 was mainly due to higher transportation costs related to increased LNG transportation and increased booking of throughput capacity in Gassled in 2008. The 6% increase from 2006 to 2007 is mainly caused by early retirement cost accruals and increased accruals for removal costs.

    In 2008, the
    
    netNet operating income was NOK 18.5 billion in 2009, compared with NOK 12.5 billion in 2008. The increase of NOK 6 billion was mainly due to an increased margin between gas sale revenues and gas purchase costs in 2009 compared with 2008, in addition to higher processing and transport income in 2009. The increased margin was a result of the positive contribution from realised trading and optimisation positions in addition to a NOK 2.7 billion gain on derivatives in 2009 compared with a NOK 1.2 billion gain in 2008.
    
    Net operating income for 2008 was NOK 12.5 billion, compared towith NOK 1.5 billion in 2007. The volume weighted average sales price increased by 45%, amounting in total to NOK 31.2 billion, of which the rise in European piped gas price contributed NOK 27.0 billion. Changes in European gas prices lag behind changes in crude oil prices.

    

    Net operating income for 2007 was NOK 1.5 billion, compared with NOK 21.7 billion in 2006. The decreaseincrease of NOK 20.111.0 billion was mainly due to a 13% decrease in prices for piped natural gas, which reduced income by NOK 9.5 billion, and negative changes amounting to NOK 10.3 billion45% increase in the fair value of derivatives.

    With effect from 2008, volume-weighted average sales price.
    
    Natural Gas provides an explanation of the adjusted net operating income from itshas two main business activities: Processing and Transport and Marketing and Trading. Processing and Transport activities consists mainly of our share in Gassled and theour role as Technical Service Provider role at Kårstø and Kollsnes. Marketing and Trading consistsactivities consist of our gas sales and trading activities. The transportation costs associated with the Natural Gas segment, are included in the Marketing and Trading activity carries the associated transportation costs within the Natural Gas segment. The split between business segments is only restated for 2007.

    activity.
    
    Net operating income in Processing and Transport was NOK 5.67.6 billion in 2009, compared with NOK 6.3 billion in 2008. Processing and Transport revenues increased by NOK 1.3 billion due to higher booking in 2009, while fixed operating expenses remained at the same level.

    Net operating income in 2008 amounted to NOK 6.3 billion, compared towith NOK 5.6 billion in 2007. Processing and Transport incomerevenues increased by NOK 0.31.1 billion, while fixedpartly offset by operating expenses, depreciation and depreciationimpairment, which increased by NOK 0.30.4 billion.

    
    
    Net operating income in Marketing and Trading wasamounted to NOK 7.010.9 billion in 2009, compared with NOK 6.2 billion in 2008. The increase of NOK 4.7 billion was mainly due to the positive contribution from realised trading and optimisation positions in 2009 in addition to a NOK 2.7 billion gain on derivatives in 2009 compared with a NOK 1.2 billion gain in 2008.

    Net operating income in 2008 amounted to NOK 6.2 billion, compared towith a loss of NOK 4.1 billion in 2007. Marketing and Trading income increased byThe increase of NOK 11.110.3 billion was mainly due to increased price (NOK 31.2 billion)a 78% increase in the margin between gas sale revenues and higher volumes sold (NOK 7.7 billion). The main offsetting factors to the increased income were NOK 24.2 billion in highergas purchase costs of goods sold, NOK 1.5 billion in increased operating expenses, NOK 0.5 billion increased depreciation expences, and NOK 0.2 billion increased selling and administrative expenses.compared with 2007. The increased operating expenses are mainly duemargin was the result of a 45% increase in the volume-weighted average sales prices in addition to higher transportation costa NOK 1.2 billion gain on derivatives in 2008.

    2008 compared with a NOK 3.4 billion loss in 2007.
    
    Total natural gas sales were 49.8 bcm (1.76 tcf) in 2009, 45.2 bcm (1.60 tcf) in 2008 and 42.0 bcm (1.48 tcf) in 20072007. The 10% increase from 2008 to 2009 in gas volumes sold was due to an increase in both our own and 40.2 bcm (1.42 tcf) in 2006. third party volumes.
    
    The 8% increase from 2007 to 2008 in gas volumes sold was mainly due to increased entitlementown gas sales, but this was partly offset by a net decrease in StatoilHydroStatoil third party sales volumes. Third party gas is mainly used for portfolio balancing and optimisation and trading purposes. The increase in entitlement sales volumes mainly relates to higher production from NCS in addition to the first full year with production from Shah Deniz, Azerbaijan. Of the total natural gas sales in 2008, 39.3 bcm (1.39 tcf) was entitlement gas, including 1.4 bcm (0.05 tcf) of gas from Shah Deniz in Azerbaijan and 0.9 bcm (0.03 tcf) from Gulf of Mexico, and 2.6 bcm (0.92 tcf) was the SDFI's share of US piped gas.

    The 4% increase from 2006 to 2007 in gas volumes sold was mainly due to increased third-party gas sales, but this was partly offset by a net decrease in StatoilHydro entitlement sales volumes. The decrease in entitlement sales volumes was mainly related to production problems on Kvitebjørn throughout 2007.

    
    
    The weighted average gas price for our sales was NOK 1.90 per scm in 2009, compared with NOK 2.40 per scm in 2008, compared to NOK 1.66 per scm in 2007, an increasea decrease of 45%21%. The increasedecrease in price from 20072008 to 20082009 was mainly due to an increasea decrease in prices for oil products (such asduring the second half of 2008, affecting our long-term gas oil and fuel oil) and other competing energy sources,sales contracts after a delay of six to nine months, as well as higherto lower gas prices onat the National Balancing Point (NBP) in the UK. The sales of natural gas from In Salah are reported by the International Exploration & Production business area. The weighted average price is only available from 2007.UK in 2009 than in 2008.

     Top

    4.1.6.24.1.7.2 Outlook

    The present economic downturnreduced demand for gas, from the industrial sector in particular, means that there is currently sufficient supply to meet demand.demand in all the major gas markets. In the longer term, however, the market balance is more uncertain. Increasing transport distanceswill probably require new supplies and complexitythus new projects.

    The impact of new resources suggest an increase in prices.

    In the short term, the present economic downturn means that there is sufficient supply in Europe, Asia and North America to meet demand expectations. Balance in supply and demand will probably impact gas prices.

    In the longer term, however, the market balance is more uncertain and the current economic impact on long termlong-term demand and the development of new gas projects areis difficult to assess. Increasing transport distances and complexityThe balance between these two factors will determine the development of new resources would seem to suggest an upward price trend over time, ensuring sufficient prices to maintain supplies.long-term gas prices.

    The short termshort-term gas market is affected by new LNG capacity coming on stream, the success of US gas shale production and by reduced demand for energy. LNG in the Atlantic basin is responding to changes in prices between major markets, taking advantage of arbitrage opportunities. Our view on these events isWe believe that we have value creation potential through increased gas exports due to the proximity and flexibility of our infrastructure to favourableprofitable markets.

    In the long term, we continue to have a positive view of gas as an energy source for Europe. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. The trend for LNG as a link between regional markets is expected to continue as more LNG will come on stream, making gas a commodity that is driven by global development.

    Our gas strategy remains firm. In 2009,2010, we plan to have focus on on extracting maximum value from our long termlong-term gas sales portfolio throughby maintaining daily supply regularity and contract modernisationcontinuing to restructure our contracts as a part of regular contract revisions. In addition, we will focus on participating in the short termshort-term gas markets in order to add value through balancing, trading and optimisation activities. Business development efforts will be concentrated on commercialising our position in the Shah Deniz field and our newly-acquired gas position in the US. This position in the Marcellus shale gas acreage, inUSA. In combination with Gulf of Mexico production and our LNG regasification capacity position at Cove Point, the position in the Marcellus shale gas acreage will provide a foundationsound basis for growth in ourcontinued development of a value-creating US market position in the years to come.business.

     Top

    4.1.7 4.1.8 Manufacturing and& Marketing

    In 2008,2009, we experienced volatilechallenging market conditions and a worldwide economic downturn,significant decline in refining margins, further emphasising the importance of efficientcost-efficient operations and prudent project selection and execution.

    During 2008In 2009, we also continued the standardisation and simplification process throughout the business area in order to both increase efficiency.efficiency and reduce our operating costs.

    Our total capital expenditure ofwas NOK 6.8 billion in 2008 was higher than in previous years, triggered by high activity in2009. In addition to the execution of ongoing projects and a major turnaround at our refineries, we acquired the Mongstad refinery.long-term lease of the South Riding Point terminal. Capital expenditure was NOK 8.5 billion in 2008 and NOK 4.8 billion in 2007 and NOK 2.5 billion in 2006.2007.

    

    

    
     

    
    Oil sales, trading and supply
    With average crude, condensate and condensateNGL sales of 22.4 mmbbl per day in 2008,2009, we are one of the world's largest net sellers of crude oil.sellers. Of ourthese daily sales, of 2 mmbbl, approximately 1.01.1 mmbbl were our own equity volumes, 0.50.7 mmbbl were third party volumes and 0.50.6 mmbbl were SDFI volumes. Including NGL, theOur average sales volume was 2.3 mmbbl per day in 2008, compared withand 2.4 mmbbl per day in 2007. In 2006,

    On 22 October 2009, we completed the average sales volumeacquisition of the long-term lease of the South Riding Point crude oil terminal in the Bahamas. This acquisition was 2.3 mmbbl per day.

    We will continue to strengthenin line with our strategy of strengthening our global trading position by securing physical infrastructure and building physical third party positionscontracts, based on our production in selected regions. Physical activity pertainsrelates to an actual commodity and does not involve trading in financial instruments. The average daily third party crude volumes we sold in 2008 were 0.532009 totalled 0.70 mmbbl, compared to 0.52with 0.66 mmbbl in 20072008 and 0.420.66 mmbbl in 2006. Although2007.
    
    Manufacturing
    We reduced refining throughput in 2009 due to low margins, but since maintenance activity was lower than in 2008, has been a year with high financial uncertaintythe total throughput was slightly higher in 2009. Both Mongstad and increased counterparty risk, no credit losses have been realised on customer sales during the year.
    
    Manufacturing
    MongstadKalundborg also had a challenging year with their largest ever turnaround including major modifications in the cracker unit, as well as some unplanned shutdowns.shutdowns during 2009. A gasoil leakage incident occurred at Kalundborg, while Mongstad experienced technical problems in its cracker unit. Tjeldbergodden had significant shutdownslow production in 2008, partly unplanned and partly2009 due to start-up after the fuel reduction project. Sture had stable operationsdepressed methanol market prices and high regularity, and Tjeldbergodden had high regularity and utilisation in 2008.necessary maintenance shutdowns.

    Energy and retail
    We have maintained our leading energy and retail positions and have the leadinglargest or second largest market share in most of the countries in which we operate.

    On 21 October 2008, the European Commission granted permission for StatoilHydro to take over the bulk1 April 2009, Statoil sold 118 unmanned Swedish Hydro/Uno-X-branded filling stations, 40 unmanned Swedish JET-branded stations and all of the Jet self-service retail chain40 unmanned Norwegian JET-branded station to St1 OY. These sales were in Scandinavia from ConocoPhillips. To complyaccordance with the terms set by the commission, StatoilHydro agreedEuropean Commission when it approved Statoil's acquisition of JET in Norway, Sweden and Denmark.

    Statoil's board of directors has decided to sell 80consider a new ownership structure for the group's energy and retail business. Listing on the Oslo stock exchange is expected to be the most likely solution, but this would not take place before the fourth quarter of 2010 at the earliest. Should listing be the result of the 274 filling stations acquired. StatoilHydroevaluation process, Statoil will alsoprobably consolidate the business on the introduction. The size and time horizon of Statoil's further ownership will be obligedtailored to sell 118 Hydro stations in Sweden as partthe new company's development needs. No significant impact on the financial statements is expected on initiation of the divestment package.this new ownership structure.

    The transaction is an important element in our endeavours to become the leading fuel company in Scandinavia.

    We also continued to strengthen our position as one of the leading suppliers of biofuels in Scandinavia and the Baltic countries during 2008. Biofuels are now available at more than 1,300 service stations in seven different countries.

     Top

    4.1.7.14.1.8.1 Profit and loss analysis

    In Manufacturing and& Marketing, total revenues and other income increaseddecreased to NOK 531351 billion, mainly due to higherlower oil prices.

    	Twelve months ended 31 December
    Income statement (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    Total revenues and other income	351.2	531.3	428.1	(34 %)	24 %
    Purchase, net of inventory variation	325.0	501.4	401.8	(35 %)	25 %
    Operating expenses	10.8	14.7	12.6	(27 %)	16 %
    Selling, general and administrative expenses	8.3	8.6	7.0	(3 %)	23 %
    Depreciation, amortisation and impairment	7.8	2.1	2.8	267 %	(25 %)
    Total expenses	351.8	526.8	424.2	(33 %)	24 %
    Net operating income	(0.5)	4.5	3.9	(112 %)	17 %
    Operational data:
    FCC margin (USD/bbl)	4.3	8.2	7.5	(48 %)	9 %
    Contract price methanol (EUR/tonne)	173.0	344.0	317.0	(50 %)	9 %

    Total revenues and other incomeincreased decreased from NOK 428 billion in 2007 to NOK 531 billion in 2008. 2008 to NOK 351 billion in 2009. The decrease from 2008 to 2009 was mainly due to lower prices for crude and other oil products. The average crude price in USD decreased by approximately 37% in 2009 compared to 2008, but was partly offset by the strengthening of the average USD exchange rate by almost 12%.

    The increase from 2007 to 2008 was mainly due to higher prices onfor crude and other oil products. The average crude price in USD increased by approximately 40% in 2008 compared to 2007 but was partly offset by the weakening of the average USD exchange rate by almost 4%.
     

    	Twelve months ended 31 December
    Income statement
    (in NOK billion)	2008	2007	08 -07 Change	2006	07-06 Change
    Total revenues and other income	531.3	428.1	24%	411.8	4.0 %
    Purchase, net of inventory variation	501.4	401.8	25 %	383.4	5 %
    Operating expenses	14.7	12.6	16 %	11.8	7 %
    Selling, general and administrative expenses	8.6	7.0	23 %	7.1	(2 %)
    Depreciation, amortisation and impairment	2.1	2.8	(25 %)	2.3	20 %
    Total expenses	526.8	424.2	24 %	404.6	5 %
    Net operating income	4.5	3.9	14 %	7.2	(86 %)
    Operational data:
    FCC margin (USD/bbl)	8.2	7.5	9 %	7	5 %
    Contract price methanol (EUR/tonne)	344.0	317.0	9 %	300	5 %

    The increase from 2006 to 2007 was mainly due to higher prices and volumes for crude and gas oil products. The average oil price increased by 12% in 2006 compared to 2007, which was partly offset by the weakening

    Purchase, net of the average USD exchange rate by almost 9% in 2006 compared to 2007.

    

    Cost of goods soldinventory variation increaseddecreased from NOK 402 billion in 2007 to NOK 501 billion in 2008 to NOK 325 billion in 2009, mainly due to lower prices on volumes purchased. The increase of 25% from 2007 to 2008 was primarily due to increased prices on volumes purchased. The increase of 5% from 2006 to 2007 was also a result of increased crude oil prices and purchased volumes.

    Operating, selling, general and administrative expenses decreased by 18% in 2009 compared with 2008. This was due to lower freight rates, and reversal of the 2008 provision of NOK 1.3 billion related to a take-or-pay contract at Mongstad. Manufacturing incurred increased operating costs in 2009 due to high maintenance activity.

    Costs increased by 19% in 2008 compared with 2007. This was due to increased transportation costs of NOK 0.7 billion for shipments of crude made to Asia in 2008, and a provision of NOK 1.3 billion for an expected increased cost related to a take or paytake-or-pay contract at Mongstad. Manufacturing incurred increased operating costs in 2008 due to high maintenance activity. During 2007 there were additional costs associated with provisions for pension liabilities of NOK 0.7 billion included in restructuring costs relating to the merger.

    Costs increased by 3% in 2007 compared with 2006, mainly due to the provision for pension liabilities of NOK 0.7 billion.

    Depreciation, amortisation and impairment totalled NOK 7.8 billion in 2009, compared with NOK 2.1 billion in 2008. The increase was mainly due to an impairment loss of NOK 5.4 billion in 2009 in Manufacturing.

    The decrease of 25% in 2008 compared with NOK 2.8 billion in 2007. The decrease2007 was mainly due to an impairment loss of NOK 0.95 billion in 2007 in Energy & Retail Sweden, of which NOK 0.5 billion was included in restructuring costs relating to the merger.

    The increase of 24% in 2007In 2009, the net operating loss was NOK 0.5 billion, compared with 2006 was a result of impairment writedowns in 2007.

    In 2008, net operating income was of NOK 4.5 billion compared within 2008
    and NOK 3.83.9 billion in 2007. The increasenet operating loss in 2009 was primarily due to a net positiveimpacted by impairment loss on refinery assets (NOK 5.4 billion), loss on inventory hedge positions which do not qualify for hedge accounting (NOK 2.0 billion), restructuring costs in Energy and Retail (NOK 0.2 billion), currency effect on the value of NOK 2.4 billion relating to operational andinventories in commercial storage valuation changes,(NOK 0.2 billion), and lower refining margins and methanol prices. Positive effects in 2009 were a largegain from price change on our operational storage (NOK 2.1 billion), reversal of a take-or-pay contract provision (NOK 1.3 billion), strong trading results and improved retail margins.

    The net operating income in 2008 was impacted by a positive currency effect due to currencyon the value of inventories in commercial storage (NOK 3.3 billion), and a negative effect due to price changes. In addition, there were pension cost provisions of NOK 0.7 billion in 2007. Impairment losses and provisions in connection with restructuring of the retail business in Sweden were NOK 0.5 billion lower in 2008 compared to 2007.gain on inventory hedge positions which do not qualify for hedge accounting (NOK 0.8 billion). Negative effects in 2008 when compared to 2007 included an expected increased cost related towere loss from price change on our operational storage (NOK 2.8 billion), a take or paytake-or-pay contract of NOKprovision (NOK 1.3 billionbillion), restructuring costs in Energy and lost revenues due to the turnaround undertaken at Mongstad.Retail (NOK 0.5 billion) and lower results in Manufacturing and Energy and Retail.

    The NOK 3.4 billion decrease from 2006 tonet operating income in 2007 was mainly due to increased retirement pension costsimpacted by a gain from price change on our operational storage (NOK 1.5 billion). Negative effects in 2007 were currency effect on the value of NOK 0.7 billion, negative currency effects of NOK 0.7 billion, a decreaseinventories in trading results of NOK 0.6 billion,commercial storage (NOK 1.4 billion), loss on inventory hedge positions which do not qualify for hedge accounting (NOK 1.1 billion), restructuring and impairment losscosts in Energy and Retail (NOK 1.1 billion) and pension cost provisions of NOK 0.5 billion due to weak market conditions and restructuring of the retail business in Sweden. A gain of NOK 0.6 billion was also achieved in 2006 from the sale of our retail business in Ireland.(NOK 0.7 billion).

    Oil Sales,sales, trading and supply
    In 2008,2009, net operating income was NOK 4.23.7 billion, compared with NOK 1.34.2 billion in 2008 and NOK 1.4 billion in 2007. The good resultnet operating income in 2009 was impacted by a gain from price change on our operational storage (NOK 2.1 billion) and strong trading results, especially within product and gas liquids trading. Negative effects in 2009 were loss on inventory hedge positions which do not qualify for hedge accounting (NOK 2.0 billion), and currency effect on the value of inventories in commercial storage (NOK 0.2 billion).

    The net operating income in 2008 was mainly due toimpacted by a net positive currency effect on the value of NOK 2.8 billion relating to operational andinventories in commercial storage valuation changes. The(NOK 3.3 billion), and a gain on inventory hedge positions which do not qualify for hedge accounting (NOK 0.8 billion) and improved overall trading results. Negative effects in 2008 were loss from price change on our operational storage (NOK 2.8 billion), and negative results improved, but within product trading, we experienced negative trading results, leading to a scaling down of product trading by the end of the year.

    The decrease of NOK 0.9 billion from 2006 tonet operating income in 2007 was mainly due toimpacted by a gain from price change on our operational storage (NOK 1.5 billion). Negative effects in 2007 were a currency effect on the value of inventories in commercial storage (NOK 1.4 billion), and loss on inventory hedge positions which do not qualify for hedge accounting (NOK 1.1 billion).

    

    Manufacturing
    In 2009, net operating loss was NOK 5.3 billion, compared with positive net operating income of NOK 0.7 billion in currency losses, lower trading results of NOK 0.6 billion compared with 20062008 and a deferred gain on inventories, which was partly offset by gains on operational storage.

    

    Manufacturing
    In 2008, net operating income was NOK 0.7 billion, compared with NOK 3.3 billion in 2007. The decreasenet operating loss in 2009 was impacted by impairment loss on the Mongstad and Kalundborg refinery assets (NOK 5.4 billion), low refining margins and high operating costs due to the increased activity levels in maintenance and modification. Both the average refining margin and the contract price for methanol decreased by approximately 50% in 2009. A positive effect in 2009 was reversal of a take-or-pay contract provision (NOK 1.3 billion).

    The net operating income in 2008 was mainly due to a provision forimpacted by a take-or-pay contract of NOKprovision (NOK 1.3 billion,billion), a large turnaround at Mongstad, and high operating costs due to the increased activity levels in maintenance, modifications and business development. Margins were low at Mongstad due to the turnaround, but improving at Kalundborg due to the fuel reduction project and good feedstock optimisation. TheBoth the average refining margin and the contract price for methanol increased by 9% from EUR 317/tonne in 2007 to EUR 344/tonne in 2008.

    The NOK 1.1 billion decrease from 2006 tonet operating income in 2007 was mainly due to lower regularityimpacted by strong refining margins, combined with high refinery reliability and higher operating costs due to turnaround activities. The lower USD/NOK exchange rate and lower capacity utilisation also contributed negatively. Margins were good at Mongstad, but they were lower than expected at Kalundborg due to high crude differentials and the delay in the fuel reduction project. The average contract price for methanol increased by 6% from EUR 300/tonne in 2006 to EUR 317/tonne in 2007.utilisation.

    Energy and retail
    NetIn 2009, net operating income was NOK 1.3 billion, compared with a net operating loss wasof NOK 0.2 billion in 2008 compared withand NOK 17 million0.0 billion in 2007. We experienced increased revenues duringThe net operating income in 2009 was impacted by improved retail margins. Negative effects in 2009 were restructuring costs (NOK 0.2 billion), and lower fuel and convenience sales volumes.

    The net operating income in 2008 mainly due to a large increase in transportwas impacted by loss from price change for our operational storage (NOK 0.4 billion), restructuring costs (NOK 0.5 billion), lower non fuel market prices,margins and a small increase in sales volumes, at our outlets, from 8.3 billion to 8.4 billion litres. The decrease in total net income was mainly due toand increased operating costs coupled with negative effects from storage valuation changes. Costs related to thecosts.

    The net operating income in 2007 was impacted by restructuring of our retail businessand impairment costs in Sweden were reduced from NOK(NOK 1.1 billion in 2007 to NOK 0.5 billion in 2008.billion).

    The NOK 0.6 billion decrease from 2006 to 2007 was mainly due to increased impairment loss and provisions from NOK 0.6 billion in 2006 to NOK 1.1 billion in 2007, due to weaker market conditions and restructuring of our retail business in Sweden. There was also a net gain of NOK 0.6 billion in 2006 related to the sale of our retail business in Ireland. These effects were offset to some extent by an increase of 8% in transport fuel volumes at our outlets, from 7.7 billion to 8.3 billion litres, together with an increase in margins. During the same period, margins on convenience products rose by 15%.

     Top

    4.1.7.24.1.8.2 Outlook

    2009

    Worldwide demand for oil products should increase during 2010, whilst global refinery overcapacity is expected to continue for several years to come, maintaining pressure on refining margins.

    We believe that retail volumes will increase, but that there will be a challenging year with lower crude prices, an overcapacity situationreduction in Europe, and high volatility in all our markets. In the long term, growth areas are expected to be biofuels, transportation fuel and convenience sales.
    margins

    Oil sales, trading and supply
    The year 2008 wasWe expect the most volatile periodglobal demand for oil products to recover during 2010. As the global economy remains in a fragile state, a return to pre-recession demand levels is not imminent. In the mid to long term, we expect that efficiency gains in the product, gas liquidstransportation sector will continue to lead to falling demand for oil products in both Europe and crude oil markets. Dated Brent entered the year on a strong upward trend extendingUS, with any future growth coming mainly from 2007 and then accelerating as financial investors increased positions in a search for more favourable yields, thus exacerbating the upward trend. Strong support from a tight gasoil/diesel market and declining crude oil inventories led to an increasingly tight oil market and dated Brent crude prices reached a record level of 144 USD/bbl on 3 July 2008. However, several signals started to discourage investors; an underlying tendency of slower global GDP growth, weak product demand,developing economies, especially in the US, and rising OECD stocks after a period of increased OPEC output. As these factors became ever more apparent, the financial crisis intensified and crude oil prices peaked and started a sharp fall during the autumn of 2008 prompting OPEC to scale back production. Increased risk aversion and a need for cash induced investors to sell in liqu id markets to cover losses in illiquid ones, gave commodities a disproportionally large share of the sell-off. With a shift of both sentiment and outlook during 2008, crude oil prices were fundamentally different in the first half of the year compared to the second and traded at around 40 USD/bbl by the end of December.

    Manufacturing
    The demand for refined products around the Atlantic basin is expected to decrease and lead to surplus capacity, especially for gasoline. Rationalisation of European refining capacity is required to maintain healthy margins. Competitive profitability and survival will very much depend on location, the ability to utilise the available feedstock and deliver the optimal product qualities, and cost level. The average crude oil barrel is becoming more sour and heavier. As both the heavy and light ends have increased, product specifications have become more stringent,Asia and the Middle East. The fall in demand for fuel oil is falling. All these factors necessitate additional processing flexibility and capacity, and continued investment in fuel oil conversion is expected. Bio-components are expectedalso driven by long-term demographic trends. Diesel demand, relative to grow in market share. After heavy cost-cutting in the 1990s, good margins in the current decade have increased the focus on reliability and utilisation. In combination with high pressure in the labour and contractor markets, this has led to heavy cost increases. Falling margins and general recession is expected to significantly increase management attention on operating and investment costs.

    Methanol prices were expected to return to a moderate level as new capacity in stranded gas areas became available, but the financial turmoil has caused an earlier and deeper price decline. Europegasoline is expected to continue to increase in Europe. This will lead to an increasing surplus of gasoline in Europe for exportation, but with the "traditional" export market of the US also expected to move into surplus, this European surplus will have to be exported greater distances. The increasing demand for diesel and jet fuel will also impact upon optimal refinery configuration and product margins.

    In the longer term, we expect the oil market to be supply constrained, and as the availability of conventional, light crudes continues to decline, there should be increasingly strong incentives for refineries to process heavy and extra heavy crude oils such as Canadian bitumen.

    We anticipate that a net importer of methanol, and European producersstrong increase in global Gas Liquids supply (due to higher gas production in North Africa, the Middle East), will therefore still havelead to a geographical advantage.

    Energy and retail
    2009 will be a very challenging year, but in the long term the main growth areas'buyers market'. The increased LPG volumes are expected to be used mainly as feedstock for petrochemical production while some volumes could also be used within the transportation fuel mainlysector.

    Manufacturing
    The outlook for the refinery industry continues to be challenging, with the low-margin environment we experienced in 2009 expected to continue for some time. In the short term, we see that the drop in demand has led to refinery overcapacity and subsequent pressure on margins. This situation is exacerbated due to the start up of several export refineries in the Far East and Middle East. In the longer term, the overcapacity in the Atlantic Basin refining capacity could lead to capacity closures in Europe. The most likely candidates for closure would probably be smaller refineries with less ability to convert heavy crudes into transportation fuels.

    New fuel standards which will require traceability and the reporting of GHG emissions from all fuel types (and possibly introducing minimum standards) are currently being developed in the EU and are also proposed in the US. In future, we expect profitability to depend on location and the flexibility to process different crudes.

    Energy and retail
    As regards our local transportation fuel markets where Statoil is an active retailer, margins are currently relatively healthy, although the market is experiencing a reduction in volumes and sales of non-fuel goods as a result of the economic downturn. In 2010 and going forward, we expect the markets to slowly recover to a more normal state, with decreased margins but slightly increased volumes, both for transportation fuel and convenience goods. Medium to long-term growth in the transportation fuel sector will be driven by the anticipated growth in the diesel sector, and convenience sales.

    We are reinforcing our long-term ambition of sales growth in Eastern Europe, though in 2009 this will be limited due to investment constraints. We continued to expand our station network in Poland during 2008 and recently entered the St. Petersburg market in Russia. We already have a strong footholdsector. The longer-term perspective is more uncertain. There is consolidation in the Baltic countries,market, which could lead to margins being maintained, but 2008 was a challenging year duethe threshold is lower for new entrants to the economic downturn experiencedautomated stop sector in particular. In the long-term, we should expect increased competition from alternative fuels (biofuel, electricity, gas etc). Biofuels' market share of transportation fuel has increased sharply in recent years and it is expecte d to continue to be an important blending component. Threats and opportunities and the pace of development in the region.different markets could vary significantly depending on the strength of government regulation and tax incentives.

    The acquisition of Jet in Scandinavia will allow us to strengthen our Scandinavian retail fuel position.

    We believe that use of heavy oil products in the stationary energy sector will gradually be replaced by either gas carriers (LNG and LPG), or other non-fossil energy carriers.

     Top

    4.1.8 4.1.9 Eliminations and other operations

    Eliminations

    Eliminiations and other operations for the years ending 31 December 2009, 2008 2007 and 2006.

    2007.

    Other operations consist of the activities of Corporate Services, Corporate Centre, Group Finance and the two corporate technical service providers, Technology and New Energy, and Projects.

    In connection with our other operations, we recorded a net operating loss of NOK 1.1 billion in 2009, compared with a loss of NOK 0.7 billion in 2008 compared withand a loss of NOK 2.3 billion in 2007 and2007. The increase in net operating loss is mainly related to a lossgain from the sale of NOK 1.9 billionIS Partner AS recorded in 2006. 2008.

    The increasedecrease from 2007 to 2008 iswas primarily due to athe gain related toon the sale of IS Partner AS in 2008 and the fact that no provisions were made for early retirement costs and other restructuring costs in 2008, as compared towith 2007, when provisions were made in relation tofor early retirement and pension benefits due to the merger. The increase was partly offset by increased costs because of higher activity.

     Top

    4.1.9 Reported4.1.10 Definitions of reported volumes

    Here we explain some of the terms used when reporting our volumes, such as lifted entitlement volumes, produced (equity) volumes, equity volumes, entitlement volumes and proved reserves.

    Volumes that explain revenues

    
    In explaining revenues and changes in revenues, we report on lifted entitlement volumes. This is because we can only recognise income from volumes to which we have legal title, and such title typically arises upon lifting (that is,(i.e. loading onto a vessel) of the volumes. Under PSA contracts,a Production Sharing Agreement (PSA), we are only entitled to receive and sell certain parts of the volumes produced, and we therefore refer to entitlement volumes for revenue recognition purposes. The difference between equity and entitlement volumes is described in more detail below.

    Volumes of lifted liquids (crude oil, condensate and natural gas liquids) and natural gas correlate with production over time, with production, but they may be higher or lower than entitlement production for the period due to operational factors that affect the timing of when StatoilHydro-charteredStatoil-chartered vessels lift the oilliquids from the fields. Volumes of natural gas produced on the NCS are deemed to be equal to lifted volumes of natural gas from the NCS.

    Volumes of lifted liquids and natural gas may be sold or put into storage. The volumes that give rise to revenues from the sale of liquids and natural gas in the period are therefore equal to lifted volumes plus changes in inventories of liquids and natural gas.

    Volumes that explain operating expenses
    In explaining operating expenses, in total and production cost per barrel of oil equivalents, we believe that produced (equity) volumes are a better indicator of activity levels than lifted volumes. Moreover, we believe that equity volumes are a better indicator of the activity level under PSA contractsPSAs than entitlement volumes, since our capital expenditure and operating expenses under such contracts are linked to equity volumes produced rather than to entitlement volumes received.

    Equity volumes represent produced volumes under a PSA contract that correspond to StatoilHydro'sStatoil's percentage ownership interest in a particular field. Entitlement volumes, on the other hand, represent StatoilHydro'sStatoil's share of the volumes distributed under a PSA to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes. The main countrycountries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.

    Volumes of proved reserves
    Proved reserves are entitlement volumes recognised as reserves in accordance with SEC Rule 4-10 (a) and relevant guidance. They represent volumes that with reasonable certainty will be produced and to which we will have entitlement in the future. See section 3.9 Operational review - Proved oil and gas reserves and note 34-Supplementary35 - Supplementary oil and gas information in the consolidated statementsConsolidated Financial Statements in this report, for details about how we measure and report on proved reserves.

     Top

    4.2 Liquidity and capital resources

    Cash

     Top

    4.2.1 Review of cash flows

    The cash flow provided byfrom operating activities was NOK 102.573.0 billion in 2008, while cash flow used in investing activities was NOK 85.8 billion.2009. As of 31 December 2008,2009, the debt ratio was 27.3% and we had liquid assets of NOK 28.431.7 billion.

    	For the year ended 31 December
    Condensed cash flow statement (in NOK billion)	2009	2008	2007	Change 08-09	Change 07-08
    Cash flows from underlying operations	181.9	239.9	195.7	(57.9)	44.1
    Cash flows from (to) changes in working capital	(5.7)	1.3	0.5	(7.0)	0.8
    Taxes paid	(100.5)	(139.6)	(102.4)	39.1	(37.2)
    Other changes	(2.8)	0.9	0.1	(3.7)	0.8
    Cash flows provided by operations	73.0	102.5	93.9	(29.5)	8.6
    Acquisitions	0.0	(13.1)	0.0	13.1	(13.1)
    Additions to PP&E and intangible assets	(75.2)	(76.2)	(75.5)	1.0	(0.6)
    Proceeds from sales	1.4	5.4	1.1	(3.9)	4.3
    Other changes	(1.6)	(1.9)	(0.7)	0.3	(1.3)
    Cash flows used in investing activities	(75.4)	(85.8)	(75.1)	10.5	(10.7)
    Net change in long-term borrowing	41.4	(0.3)	(1.2)	41.7	0.9
    Net change in short-term borrowing	(7.1)	10.5	0.8	(17.6)	9.7
    Dividends paid	(23.1)	(27.1)	(25.7)	4.0	(1.4)
    Other changes	0.1	(0.1)	18.1	0.2	(18.3)
    Cash flows from (used in) financing activities	11.3	(17.0)	(7.9)	28.3	(9.1)
    Net increase (decrease) in cash flows	8.9	(0.3)	10.9	9.3	(11.2)

     

    CONSOLIDATED BALANCE SHEETS
    	Twelve months ended 31 December
    (in NOK billion)	2008	2007	2006
    ASSETS
    Non-current assets
    Property, plant and equipment	329.8	278.4	272.2
    Intangible assets	66.0	44.9	31.2
    Associated companies	12.6	8.4	8.6
    Deferred tax assets	1.3	0.8	0.8
    Pension assets	0.0	1.6	1.1
    Financial investments	16.5	15.3	14.0
    Derivative financial instruments	2.4	0.6	0.5
    Financial receivables	4.9	3.5	4.3
    Total non-current assets	433.6	353.5	332.6
    Current assets
    Inventories	15.2	17.7	15.3
    Trade and other receivables	69.9	69.4	62.4
    Current tax receivable	3.8	0.0	18.7
    Derivative financial instruments	27.5	21.1	21.3
    Financial investments	9.8	3.4	1.0
    Cash and cash equivalents	18.6	18.3	7.5
    Total current assets	144.8	129.8	126.2
    TOTAL ASSETS	578.4	483.2	458.8

    CONSOLIDATED BALANCE SHEETS
    	Twelve months ended 31 December
    (in NOK billion)	2008	2007	2006
    EQUITY AND LIABILITIES
    Equity
    Share capital	8.0	8.0	8.0
    Treasury shares	0.0	0.0	0.0
    Additional paid-in capital	41.5	41.4	44.6
    Additional paid-in capital related to treasury shares	(0.6)	(0.4)	(3.6)
    Retained earnings	148.0	140.9	122.2
    Other reserves	17.3	(12.6)	(3.4)
    StatoilHydro shareholders' equity	214.1	177.3	167.8
    Minority interest	2.0	1.8	1.6
    Total equity	216.1	179.1	169.4
    Non-current liabilities
    Financial liabilities	54.6	44.4	49.2
    Deferred tax liabilities	68.1	67.5	72.1
    Pension liabilities	25.5	19.1	11.0
    Accruals and other provisions	54.4	43.8	42.2
    Total non-current liabilities	202.7	174.8	174.6
    Current liabilities
    Trade and other payables	61.2	64.6	55.6
    Current tax payable	57.1	50.9	47.1
    Financial liabilities	20.7	6.2	5.6
    Derivative financial instruments	20.8	7.6	6.5
    Total current liabilities	159.7	129.4	114.9
    Total liabilities	363.4	304.2	289.4
    TOTAL EQUITY AND LIABILITIES	578.4	483.2	458.8

    Other financial information	Year ended 31 December
    	2008	2007	2006
    Net debt to capital employed (GAAP basis) (1)	17.7 %	13.9 %	21.4 %
    Net debt to capital employed (2)	17.5 %	12.4 %	20.5 %
    After-tax return on average capital employed (GAAP basis) (3)	21.0 %	17.7 %	22.7 %
    After-tax return on average capital employed (4)	21.1 %	19.9 %	22.9 %
    (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 and to add into the capital employed measure interest-bearing elements which are classified together with non-interest-bearing elements under GAAP. See report section 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, adjusted as indicated in footnote 2 above. See 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.

    in (%)		Year ended December 31,
    	2008	2007	2006
    Ratio of earnings to fixed charges	52.1 %	19.6 %	21.2 %
    Based on IFRS. For the purpose of these ratios, earnings consist of the income before (i) tax, (ii) minority interest, (iii) amortization of capitalized interest and (iv) fixed charges (which have been adjusted for capitalized interest) and after adjustment for unremitted earnings from equity accounted entities.  Fixed charges consist of interest (including capitalized interest) and estimated interest within operating leases.

    

    Cash flows from operating activities
    OurStatoil's primary source of cash flow consists of funds generated from operations. CashThe cash flow providedfrom operating activities amounted to NOK 73 billion in 2009, compared with NOK 102.5 billion in 2008. The decrease of NOK 29.5 billion was primarily due to a NOK 57.9 billion decrease in cash flows from underlying operations, an increase of NOK 7.0 billion in cash flows used as working capital and a decrease of NOK 3.7 billion in cash flows used for non-current items related to operating activities. These effects were partly offset by a decrease of NOK 39.1 billion in taxes paid.

    The cash flow from operating activities was NOK 102.5 billion in 2008, compared towith NOK 93.9 billion in 2007. The increase of NOK 8.6 billion increase was due to an increase in cash flows from underlying operations of NOK 44.1 billion and cash flows of NOK 0.8 billion from other non-current items related to operating activities ofand NOK 5.9 billion.0.8 from changes in working capital. . These effects were partly offset by an increase in taxes paid of NOK 37.2 billion and negative cash flows from changes in working capital of NOK 4.3 billion.

    Net cash flows generated from operations for 2007 were NOK 93.9 billion, compared to NOK 88.6 billion in 2006. The increase of NOK 5.3 billion in cash flows from operating activities from 2006 to 2007 was mainly due to changes of NOK 12.4 billion in working capital, a decrease of NOK 8.6 billion in non-current items related to operating activities and a decrease of NOK 5.8 billion in taxes paid. These increases were partly offset by a decrease of NOK 21.5 billion in cash flows from underlying operations.

    Condensed cash flow statement	Twelve months ended 31 December
    (in NOK billion)	2008	2007	Change	2006	Change
    Cash flows from underlying operations	239.9	195.7	44.1	208.6	(12.8)
    Cash flows from (to) changes in working capital	(3.8)	0.5	(4.3)	(11.9)	12.4
    Taxes paid	(139.6)	(102.4)	(37.2)	(108.2)	5.8
    Other changes	6.1	0.1	5.9	0.1	(0.0)
    Cash flows provided by operations	102.5	93.9	8.6	88.6	5.3
    Acquisitions	(13.1)	0.0	(13.1)	0.0	0.0
    Additions to PP&E and intangible assets	(76.2)	(75.5)	(0.6)	(59.9)	(15.7)
    Proceeds from sales	5.4	1.1	4.3	3.4	(2.3)
    Other changes	(1.9)	(0.7)	(1.3)	(0.7)	0.1
    Cash flows to investments	(85.8)	(75.1)	(10.7)	(57.2)	(17.9)
    Net change in long-term borrowing	(0.3)	(1.2)	0.9	(2.2)	1.0
    Net change in short-term borrowing	10.4	0.8	9.7	(9.7)	10.5
    Dividends paid	(27.1)	(25.7)	(1.4)	(17.8)	(7.9)
    Other changes	(0.1)	18.1	(18.3)	(1.8)	19.9
    Cash flows used in financing activities	(17.0)	(7.9)	(9.1)	(31.4)	23.5
    Net increase (decrease) in cash flows	(0.3)	10.9	(11.2)	0.0	10.9

    

    Cash flows used in investing activities
    Cash amounted to NOK 75.4 billion in 2009, a decrease of NOK 10.5 billion from 2008. The decrease mostly stems from acquisitions paid for in 2008, partly offset by a reduction of NOK 3.9 billion in proceeds from sales.

    Approximately 55% of the investments in 2009 were investments in assets expected to contribute to growth in oil and gas production, while approximately 35% relate to investments in currently producing fields. The remaining 10% represent investments in Statoil's other activities.

    The cash flow used in investing activities was NOK 85.8 billion in 2008, compared towith NOK 75.1 billion in 2007. The increase of NOK 10.7 billion increase is mostlywas largely related to the NOK 13.1 billion in paymentsacquisitions, for the most part related to recent acquisitions,the purchase of the remaining 50% share of the Peregrino development, NOK 3.6 billion in increased investments in other intangible assets and NOK 2.3 billion in increased capitalisation of exploration expenditures, partly offset by a reduction of NOK 5.3 billion worth of lowerin investments in property, plant and equipment and NOK 4.3 billion in higher proceeds from sales of assets.

    Approximately 50% of the investments in 2008 arewere investments in assets expected to contribute to growth in oil and gas production, while approximately 35% relate to investments in currently producing fields, and thefields. The remaining 15% represent investments in StatoilHydro'sStatoil's other activities.

    Net cash flows used in investing activities amounted to NOK 75.1 billion in 2007, compared with NOK 57.2 billion in 2006. The NOK 17.9 billion increase was mostly related to NOK 15.7 billion in higher investments in property plant and equipment and NOK 2.3 billion in less proceeds from sales of assets in 2007 compared to 2006.

    Gross investments are defined as additions to property, plant and equipment (including intangible assets and long termlong-term share investments) and capitalised exploration expenditure. Gross investments wereamounted to NOK 85.0 billion in 2009, compared with NOK 95.4 billion in 2008 compared toand NOK 75.0 billion in 2007. The

    	For the year ended 31 December
    Gross investments (in NOK billion)	2009	2008	2007	09-08 change	08-07 change
    - E&P Norway	34.9	34.9	31.1	(0 %)	12 %
    - International E&P	39.4	48.7	36.2	(19 %)	35 %
    - Natural Gas	2.6	2.0	2.1	29 %	(6 %)
    - Manufacturing & Marketing	6.8	8.5	4.8	(20 %)	76 %
    - Other	1.3	1.3	0.8	3 %	73 %
    Gross investments	85.0	95.4	75.0	(11 %)	27 %

    Gross investments in 2008 were higher than in 2007 and 2009 due to significant investments that year, most notably in the remaining 50% share of the Peregrino development off the coast of Brazil and the investment in a 32.5% share of the Marcellus shale gas development in the USA. Moreover, gross investments increased in 2009 compared with previous years due to the capitalisation of a financial lease contract.

    Cash flows used in investing activities are reconciled with gross investments in the table below. In 2009, the difference between cash flows used in investing activities and gross investments is largely related to financial lease whereas, in 2008, compared to 2007the difference was mostly related to acquisition of assets and proceeds from sales of assets.assets and other changes in non-current loans granted and joint venture activities.

    	For the year ended 31 December
    Reconciliation of cash flow to gross investments (in NOK billion)	2009	2008	2007
    Cash flows to investments	75.4	85.8	75.1
    Proceeds from sales of assets	1.4	5.4	1.1
    Financial lease	6.9	0.3	0.0
    Other changes in non-current loans granted and JV balances	1.3	3.9	(1.2)
    Gross investments	85.0	95.4	75.0

    Gross investmentsCash flows related to financing activities
    Net cash flows from financing activities for 2009 amounted to NOK 75.011.3 billion, in 2007, compared to NOK 64.3 billion in 2006.

    		For the year ended 31 december
    Gross investments (in NOK billion)	2008	2007	Change	2006	Change
    - E&P Norway	34.9	31.1	12 %	29.2	6 %
    - International E&P	48.7	36.2	35 %	28.9	25 %
    - Natural Gas	2.0	2.1	(6 %)	3.2	(34 %)
    - Manufacturing & Marketing	8.5	4.8	76 %	2.5	93 %
    - Other	1.3	0.8	73 %	0.5	63 %
    Total gross investments	95.4	75.0	27 %	64.3	17 %

    The difference betweenwith cash flows used in investingfinancing activities and gross investments in 2007of NOK 17.0 billion for 2008. The change of NOK 28.3 billion was mainly related to the effects ofNOK 41.7 billion in net changes in long-term loans granted and other long-term itemsborrowing, NOK 4.0 billion less dividend paid in 2009, partly offset by proceeds from the salerepayment of assets. In additionshort-term borrowings in the amount of NOK 7.1 billion in 2009, compared with an increase of NOK 10.5 billioni n short-term borrowings in 2008.

    New long-term borrowings in 2009 amounted to NOK 46.3 billion due to the investments includedneed to ensure a level of financial flexibility in the table above,a lower oil-price environment, compared with NOK 2.42.6 billion in LNG-related assets has been transferred from E&P Norway to the Natural Gas business area.2008. NOK 4.9 billion in long-term debt was repaid in 2009, compared with NOK 2.9 billion in 2008.

    Reconciliation of cash flow to gross investments	For the year ended 31 December
    (in NOK billion)	2008	2007	2006
    Cash flows to investments	85.8	75.1	57.2
    NCS portfolio transactions	0.0	0.0	0.1
    Capital leases	0.0	0.0	2.4
    Proceeds from sales of assets	5.4	1.1	3.4
    Other changes in non-current loans granted and JV balances	4.2	(1.2)	1.2
    Gross investments	95.4	75.0	64.3

    Cash flows used in financing activities
    in 2009 included a dividend of NOK 23.1 billion paid by Statoil ASA to shareholders related to the annual accounts for 2008, while the dividend paid by Statoil ASA to its shareholders in 2008 relating to the annual accounts for 2007 amounted to NOK 27.1 billion.

    Net cash flows used in financing activities in 2008 amounted to NOK 17.0 billion, compared towith NOK 7.9 billion in 2007. The increase of NOK 9.1 billion increase was mainly related to a decreasesettlement of the demerger balance with Norsk Hydro of NOK 18.7 billion, in combinationcombined with increasedan increase in dividend paid of NOK 1.4 billion. These effects were partly offset by increased current financial liabilitiesliabiliites of NOK 10.5 billion in 2008, mainly related to collateral on financial counterparties and commercial papers.

    New long-term borrowings at 31 December 2008 wereamounted to NOK 2.6 billion, compared towith NOK 1.7 billion at 31 December 2007. The repayment of long-term debt at 31 December 2008 was NOK 2.9 billion compared with NOK 2.9 billion at 31 December 2007.

    Cash flows used in financing activities in 2008 included a dividend of NOK 27.1 billion paid by Statoil ASA to shareholders related to the annual accounts for 2007, while the dividend paid by Statoil ASA to its shareholders in 2007 relating to the annual accounts for 2006 was NOK 25.7 billion.

    Net cash flows used in financing activities in 2007

     Top

    4.2.2 Selected balance sheet information

    The following tables contain selected financial information related to our balance sheet and financial ratios that form part of the basis for the subsequent analysis of financial assets and liabilities.

    	For the year ended 31 December
    Selected financial data - Balance sheet (in NOK billion)	2009	2008	2007
    ASSETS
    Non-current assets
    Property, plant and equipment	340.8	329.8	278.4
    Intangible assets	54.3	66.0	44.9
    Investments in associated companies	10.1	12.6	8.4
    Deferred tax assets	2.0	1.3	0.8
    Pension assets	2.7	0.0	1.6
    Financial investments	13.3	16.5	15.3
    Derivative financial instruments	17.6	21.3	12.8
    Financial receivables	5.7	4.9	3.5
    Total non-current assets	446.5	452.5	365.6
    Current assets
    Inventories	20.2	15.2	17.7
    Trade and other receivables	58.9	69.9	69.2
    Current tax receivables	0.2	3.8	0.2
    Derivative financial instruments	5.4	9.4	8.8
    Financial investments	7.0	9.7	3.4
    Cash and cash equivalents	24.7	18.6	18.3
    Total current assets	116.4	126.7	117.5
    TOTAL ASSETS	562.8	579.2	483.1

    	For the year ended 31 December
    Selected financial data - Balance sheet (in NOK billion)	2009	2008	2007
    EQUITY AND LIABILITIES
    Equity
    Share capital	8.0	8.0	8.0
    Treasury shares	(0.0)	(0.0)	(0.0)
    Additional paid-in capital	41.7	41.4	41.4
    Add. paid-in cap. rel.to treasury shares	(0.8)	(0.6)	(0.4)
    Retained earnings	145.9	148.0	140.9
    Other reserves	3.6	17.3	(12.6)
    Statoil shareholder's equity	198.3	214.1	177.3
    Non-controlling interests	1.8	2.0	1.8
    Total equity	200.1	216.1	179.1
    Non-current liabilities
    Financial liabilities	96.0	54.6	44.4
    Derivative financial instruments	1.7	1.6	0.0
    Deferred tax liabilities	76.3	68.1	67.5
    Pension liabilities	21.1	25.5	19.1
    Asset retirement obligations, other provisions ans other liabilities	55.8	54.4	43.8
    Total non-current liabilities	250.9	204.3	174.8
    Current liabilities
    Trade and other payables	59.8	61.2	64.6
    Current tax payable	41.0	57.1	50.9
    Financial liabilities	8.1	20.7	6.2
    Derivative financial instruments	2.9	19.9	7.5
    Total current liabilities	111.8	158.9	129.2
    Total liabilities	362.7	363.1	304.0
    TOTAL EQUITY AND LIABILITIES	562.8	579.2	483.1

    	Year ended 31 December
    Other financial information	2009	2008	2007
    Net debt to capital employed (GAAP basis) (1)	26.6 %	17.8 %	13.9 %
    Net debt to capital employed (2)	27.3 %	17.5 %	12.4 %
    After-tax return on average capital employed (GAAP basis) (3)	10.4 %	21.0 %	17.7 %
    Ratio of earnings to fixed charges (4)	7.1	52.1	19.6
    (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 and to add into the capital employed measure interest-bearing elements which are classified together with non-interest-bearing elements under GAAP. See report section 4.3 Financial analysis and review - Non-GAAP 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)Based on IFRS. For the purpose of these ratios, earnings consist of the income before (i) tax, (ii) minority interest, (iii) amortization of capitalized interest and (iv) fixed charges (which have been adjusted for capitalized interest) and after adjustment for unremitted earnings from equity accounted entities. Fixed charges consist of interest (including capitalized interest) and estimated interest within operating leases.

     Top

    4.2.3 Financial assets and liabilities

    Gross financial liabilities amounted to NOK 7.9104.1 billion, compared to NOK 31.4 billion in 2006. The decrease in cash flows used in financing activities from 2006 to 2007 was mainly related to the settlement of the demerger balance with Norsk Hydro ASA on 1 October 2007, which was partly offset by increased dividends paid in 2007 compared to 2006.

    New long-term borrowings as of 31 December 2007while net financial liabilities were NOK 1.7 billion, compared to NOK 0.175.3 billion at 31 December 2006.2009. The repayment of long-termnet debt to capital employed ratio was 27.3% at 31 December 2007 was NOK 2.9 billion compared with NOK 2.3 billion at 31 December 2006. Cash flows used in financing activities in 2007 included a dividend of NOK 25.7 billion paid by Statoil ASA to shareholders related to the annual accounts for 2006, while the dividend paid by Statoil ASA to its shareholders in 2006 relating to the annual accounts for 2005 was NOK 17.8 billion.

    2009.

    Current items
    Current items (total current assets minus total current liabilities) were positive in the amount of NOK 4.6 billion at 31 December 2009, while they were negative by NOK 32.2 billion at 31 December 2008.

    The increase of NOK 36.8 billion was due to a decrease in current liabilities such as NOK 16.1 billion in taxes payable, NOK 12.5 billion in financial liabilities and NOK 17.0 billion in derivative financial instruments, and an increase in cash and cash equivalents of NOK 6.1 billion, partly offset by a decrease in accounts receivable of NOK 13.6 billion.

    Current items (total current assets minus total current liabilities) were negative by NOK 14.9 billion at 31 December 2008, compared towhile they were positive by NOK 0.4 billion at 31 December 2007.

    The changedecrease of NOK 15.3 was mainly due to an increase in current liabilities, such as accounts payable of NOK 3.8 billion taxesin accounts payable, of NOK 6.1 billion derivatives ofin taxes payable, NOK 13.1 billion collateral ofin derivatives, NOK 7.7 billion commercial papers ofin collateral, NOK 3.0 billion in commercial papers and a current portion of non-financial liabilities of NOK 4.0 billion, in combination with a decrease in inventories of NOK 2.5 billion. These factors were partly offset by a decrease in accounts payable with related parties of NOK 7.2 billion in combination with an increase in current assets such as accounts receivable of NOK 2.9 billion in accounts receivable, NOK 1.0 billion in joint venture receivables, of NOK 1.0 billion, derivatives of NOK 6.4 billion in derivatives and current financial investments of NOK 6.4 billion.

    Current items were NOK 25.5 billion as of 31 December 2007, compared to NOK 43.8 billion as of 31 December 2006. The decrease in net non-current financial liabilities from 2006 to 2007 was mainly related to an increase of NOK 13.1 billion in liquid assets, in combination with a decrease of NOK 4.8 billion in gross non-current financial liabilities due to the weakening of the USD in relation to NOK during 2007.

    We believe that taking into consideration StatoilHydro'sgiven Statoil's established liquidity reserves (including committed credit facilities), and StatoilHydro has sufficient working capital for foreseable requirements,Statoil's credit rating and access to capital markets, we are well positioned to execute the planned long-term funding in the first half of 2009.Statoil has sufficient working capital for its foreseeable requirements. Our main sources of liquidity are described below.

     
    Liquidity
    Our annual cash flow from operations is highly dependent on oil and gas prices and our levels of production, andproduction. It is only influenced to a small degree by seasonality and maintenance turnarounds. Fluctuations in oil and gas prices, which are outside our control, will cause changes in our cash flows. We will use available liquidity to finance Norwegian petroleum tax payments (due on 1 February, 1 April, 1 June, 1 August, 1 October and 1 December each year), any dividend payment and investments. Our investment programme is spread over the year. There may be a gap between funds from operations and funds required to fund investments, which will be financed by short and long-term borrowings. We intendaim to keep ratios relating to net debt at levels consistent with our objective of maintaining our long-term credit rating at least within the single A category. In this context, StatoilHydroStatoil carries out differentvarious risk assessments, some of them in line with financial matrixesmatrices used by S&P and Moody's, such as free cash flow from operations over net debt and net debt to capital employed.

    Our long-term and short-term ratings from Moody's are Aa2 and P-1, respectively. Our long-term rating from Standard & Poor's was raised to AA- in August 2007, reflecting the majority ownership by the Norwegian State. Standard & Poor's short-term rating of StatoilHydroStatoil is A-1+. The current rating outlook is stable"Stable" from both agencies.

    As of 31 December 2009, we had liquid assets of NOK 31.7 billion, including NOK 24.7 billion in cash and cash equivalents and NOK 7.0 billion of current financial investments (domestic and international capital market investments). Approximately 46% of our liquid assets were held in NOK-denominated assets, 26% in USD, 14% in EUR and 15% in other currencies (GBP, CAD, BRL), before the effect of currency swaps and forward contracts.

    As of 31 December 2008, we had liquid assets of NOK 28.4 billion, including NOK 18.6 billion in cash and cash equivalents and NOK 9.7 billion of current financial investments (domestic and international capital market investments). Approximately 29% of our liquid assets were held in EUR-denominated assets, 6% in NOK and 58% in USD, 3% in GBP and 4% in other currencies, before the effect of currency swaps and forward contracts.

    As of 31 December 2007, we had liquid assets of NOK 21.6 billion, including NOK 18.3 billion in cash and cash equivalents and NOK 3.4 billion ofCompared with year end 2008, current financial investments (domestic and international capital market investments). Approximately 54% of our liquid assets were held in EUR-denominated assets, 26% in NOK and 20% in USD, before the effect of currency swaps and forward contracts.

    Compared to year end 2007, current financial investments increaseddecreased by NOK 6.42.7 billion during 2008,2009, and cash and cash equivalents increased by NOK 0.46.1 billion. The increase ofin liquid assets during 20082009 was mainly due higher cash inflows from increased revenues in 2008 compared to 2007, partly offset by higher investments in 2008 compared to 2007. The average liquids price increased from USD 72 (NOK 423) per barrel in 2007 to USD 97 (NOK 548) per barrel in 2008.new long-term debt.

    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 in order 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 favourable.

    As of 31 December 2008,2009, the group had USD 2.0 billion available 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, after exercising of an extension option in 2006, it is available for drawdowns until December 2011. At year end 2008, no amounts had been drawn under the revolving credit facility. In 2008 we drew down a line of credit established in our favour on a bilateral basis by an international financial institution. The loan is denominated in USD and has a final maturity of five years.

    StatoilHydro plans to issueTo secure necessary financial flexibility, Statoil ASA issued new bonds in 2009 of GBP 800 million due in March 2031, EUR 1.2 billion due in March 2021, EUR 1.3 billion due in March 2015, USD 0.5 billion due in April 2014, USD 1.5 billion due in April 2019 and USD 0.9 billion due in October 2014, aggregating to a total of NOK 46.3 billion.

    In 2010, Statoil will continue to secure necessary financial flexibility going forward. As a part of this plan, the group utilised the updated EMTN program in March 2009 toand, depending, among other things, on oil and gas price developments, it may issue a GBP 800 million bond with a 22 year tenure, a EUR 1.2 billion bond with a 12 year tenure and a EUR 1.3 billion bond with a six year tenure.bonds should market conditions be viewed as attractive. See section 5.2.1 Risk review-Risk management-Financial risk andreview - Risk management - Managing financial risk management-liquidity risk management- for more information about liquidity.

    Gross interest-bearing financial liabilities
    Gross interest bearing financial liabilities
    were NOK 104.1 billion at 31 December 2009, compared with NOK 75.3 billion at 31 December 2008. The NOK 28.8 billion increase was due to a combination of increased non-current financial liabilities of NOK 41.4 billion and decreased current financial liabilities of NOK 12.5 billion.

    The increase in non-current financial liabilities was mostly attributable to the issuing of new bonds of GBP 800 million due in March 2031, EUR 1.2 billion due in March 2021, EUR 1.3 billion due in March 2015, USD 0.5 billion due in April 2014, USD 1.5 billion due in April 2019 and USD 0.9 billion due in October 2014, aggregating to a total of NOK 46.3 billion, in combination with a new financial lease of NOK 8.9 billion relating to a leased FPSO and energy plant currently in the construction phase, partly offset by the repayment of loans of NOK 4.9 billion.

    

    Gross interest bearinginterest-bearing financial liabilities were NOK 75.3 billion at year end 2008, compared with NOK 50.5 billion at the end of 2007. The increase of NOK 24.8 billion was mainly related to an increase of NOK 10.2 billion in non-current financial liabilities by NOK 10.2 billion due to the weakening of the NOK versus the USD (NOK 1.59). In addition, cash collateral on financial counter partiescounterparties and commercial papers increased by NOK 7.3 billion and NOK 3.0 billion, respectively, in 2008.

    Gross non-current financial liabilities were NOK 50.5 billion at year end 2007, compared with NOK 54.8 billion at the end of 2006. The decrease was mainly due to the weakening of the USD in relation to NOK in 2007 and the repayment of long-term borrowings in 2007. For risk management purposes, currency swaps are used to ensure that StatoilHydroStatoil keeps long-term interest-bearing debt in USD. As a result, most of the group's non-current financial liabilities are exposed to changes in the USD/NOK exchange rate.

    Net interest bearinginterest-bearing financial liabilities
    Net interest-bearing financial liabilities amounted to NOK 75.3 billion at 31 December 2009, compared with NOK 46.0 billion at 31 December 2008. The change of NOK 29.3 billion was mainly related to an increase in gross financial liabilities of NOK 28.8 billion, in combination with an increase in cash, cash equivalents and current financial investments of NOK 3.4 billion, partly offset by changed adjustments of NOK 2.9 billion.

    Net interest-bearing financial liabilities amounted to NOK 46.0 billion at 31 December 2008, compared with NOK 25.5 billion at 31 December 2007. The increase was mainly related to an increase in gross financial liabilities, partly offset by an increase in cash equivalents and current financial investments of NOK 6.8 billion.

    

    Net interest bearing financial liabilities amountedThe net debt to NOK 25.5 billioncapital employed ratio
    The net debt to capital employed ratio before adjustments, defined as net interest-bearing debt in relation to capital employed, was 26.6% in 2009, compared with 17.8% in 2008 and 13.9% in 2007.
    The adjusted net debt to capital employed ratio was 27.3% as of 31 December 2007,2009, compared with NOK 43.8 billion17.5% as of 31 December 2006.2008. The decrease9.8% increase was mainly duerelated to an increase in net financial liabilities of NOK 29.3 billion, in combination with an increase in capital employed of NOK 13.1 billion in liquid assets and a decrease NOK 4.8 billion in gross non-current liabilities, mainly due to the weakening of the USD in relation to NOK in 2007. (For a reconciliation of net non-current financial investments with gross non-current financial liabilities, seebillion. (See report section 4.3.3 Financial performance-Non-GAAPanalysis and review -Non-GAAP measures-Net debt to capital employed ratio for more information.)

    Our method of calculating the net debt to capital employed ratio includes certain adjustments to net debt and capital employed, and it may therefore be considered to be a non-GAAP financial measure.

    The net debt to capital employed ratio, defined as net interest-bearing debt in relation to capital employed, was 17.5% as of 31 December 2008, compared with 12.4% as of 31 December 2007. The 5.1% increase was mainly related to an increase of NOK 20.5 billion in net financial liabilities, of NOK 20.5 billion, partly offset by an increase of NOK 6.8 billion in cash equivalents and current financial investments of NOK 6.8 billion.

    Our method of calculating the net debt to capital employed ratio includes certain adjustments, and it may therefore be considered to be a non-GAAP financial measure. The net debt to capital employed ratio without adjustments was 17.7% in 2008, compared with 13.9% in 2007. (See report section 4.3.3 Financial performance-Non-GAAP measures-Net debt to capital employed ratio for more information.)

    The net debt to capital employed ratio was 12.4% as of 31 December 2007, compared with 20.5% as of 31 December 2006. The decrease in the net debt to capital employed ratio in 2007 was mainly related to a decrease in net debt and an increase in shareholders' equity.investments.

    The group's borrowing needs are mainly covered through the issuing of short-term and long-term securities, including utilisation of a US Commercial Paper Programme and a Euro Medium Term Note (EMTN) Programme (the limits of the programme being USD 4 billion and USD 6 billion, respectively), and through draw-downs under committed credit facilities and credit lines. After the effect of currency swaps, 100% of our borrowings are in US dollars.USD.

    Our financial policies take into consideration funding sources, the maturity profile of long-term debt, interest rate risk management, currency risk and the management of liquid assets. Our borrowings are denominated in various currencies and swapped into USD, since the largest proportion of our net cash flow is denominated in USD. In addition, we use interest rate derivatives, primarily consisting of interest rate swaps, to manage the interest rate risk of our long-term debt portfolio.

    New long-term borrowings totalled NOK 46.3 billion in 2009 and NOK 2.6 billion in 2008 and NOK 1.7 billion in 2007.2008. The repayment of long-term debt at 31 December 20082009 was NOK 2.94.9 billion, compared with NOK 2.9 billion at 31 December 2007.2008.

    The company's central finance function manages the funding, liability and liquidity activities at group level based on our adopted financial policies.

    Cash, cash equivalents and current financial investments were NOK 31.7 billion at 31 December 2009, compared with NOK 28.4 billion as ofat 31 December 2008, compared to NOK 21.6 billion as of 31 December 2007.2008. The increase of NOK 6.83.3 billion was mainly due to higher cash inflows from increased revenuesnew long-term debt in 2008 compared to 2007, partly offset by higher investments in 2008 compared to 2007. The average liquids price increased from USD 72 (NOK 423) per barrel in 2007 to USD 97 (NOK 548) per barrel in 2008.2009.

    Cash and cash equivalents wereamounted to NOK 24.7 billion at 31 December 2009, compared with NOK 18.6 billion as ofat 31 December 2008, compared to NOK 18.3 billion as of 31 December 2007.2008. Current financial investments, which are part of our cash management, amounted to NOK 7.0 billion at 31 December 2009, compared with NOK 9.7 billion as ofat 31 December 2008, compared to NOK 3.4 billion as of 31 December 2007.2008.

     Top

    4.2.1 4.2.4 Principal contractual obligations

    The table summarises our principal contractual obligations and other commercial commitments as of 31 December 2008.

    2009.

    The table includes contractual obligations, but excludes derivatives and other hedging instruments as well as asset retirement obligations, which for the most part are expected to lead to cash disbursements more than five years intoin the future. Obligations payable by StatoilHydroStatoil to unconsolidated equity affiliates are included gross in the table. Where StatoilHydroStatoil includes both an ownership interest and the 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 report section 5.2.2 Risk review - Risk management- Quantitative and qualitative disclosuresmanagement - Disclosures about market risk, for more information.
     

    	As at 31 December, 2008
    	Payment due by period *
    Contractual obligations (in NOK billion)	Less than 1 year	1-3 years	3-5 years	More than 5 years	Total
    Undiscounted non-current financial liabilities	-	14.6	14.1	53.3	82.1
    Minimum operating lease payments	16.1	22.5	10.8	4.0	53.3
    Nominal minimum payments related to transport capacity, terminal capacity and similar commitments	7.8	16.1	13.5	41.7	79.1
    Total contractual obligations	23.9	53.2	38.4	98.9	214.4
    * "Less than 1 year" represents 2009; "1-3 years" represents 2010 and 2011, "3-5 years" represents 2012 and 2013, while "More than 5 years" includes amounts for 2014 and later periods.

    	As at 31 December, 2009
    	Payment due by period *
    Contractual obligations (in NOK billion)	Less than 1 year	1-3 years	3-5 years	More than 5 years	Total
    Undiscounted non-current financial liabilities	6.9	15.7	21.9	87.0	131.6
    Minimum operating lease payments	14.0	18.9	7.2	3.1	43.2
    Nominal minimum payments related to transport capacity, terminal capacity and similar commitments	8.7	15.4	12.8	37.6	74.4
    Total contractual obligations	29.6	50.0	41.9	127.7	249.2
    * "Less than 1 year" represents 2010; "1-3 years" represents 2011 and 2012, "3-5 years" represents 2013 and 2014, while "More than 5 years" includes amounts for 2015 and later periods.

    Non-current financial liabilitiesdebt in the table represents principal payment obligations. For information on interest commitments relating to long-term debt, reference is made to note 2022 - Non-current financial liabilities and note 2527 - Leases, to our Consolidated Financial Statements included in this report.

    Contractual obligations in respect ofrelating to capital expenditures, acquisitions of intangible assets and construction in progress amounted to NOK 47.430.1 billion as of 31 December 2008,2009, of which payments of NOK 21.115.1 billion are due within one year.

    

    Over time, we have increasing flexibility in terms of capital expenditure commitments. This flexibility is partly dependantdependent on decisiondecisions made by partners.

    

    The group's projected pension benefit obligation was NOK 59.261.4 billion and the fair value of plan assets amounted to NOK 33.743.0 billion as of 31 December 2008.2009. Actuarial gains and losses amounted to NOK 7.93.2 billion as of 31 December 20082009 and are reported as part of the Statement of Recognised Income and Expense (SORIE)comprehensive income (equity). Company contributions are mainly related to employees in Norway. This payment mayContributions to pension plans can either be paid in cash or be deducted from the pension premium fund. On 31 December 2008, theThe pension premium fund amountsamounted to NOK 7.2 billion and NOK 4.5 billion.billion at 31 December 2009 and 2008, respectively. The decision whether to pay in cash or deduct from the pension premium fund is made on an annual basis. In 2009, a pension premium amounting to NOK 4.1 billion was paid. In 2008, NOK 2.9 billion was deducted from the pension premium fund. The company contribution in 2008, paid in cash, was NOK 0.2 billion (exclusive of payroll tax). In addition, NOK 1.2 billion was paid to Statoil's pension fund as a capital increase in 2008.

    The expected company contribution related to 2009 is2010 amounts to NOK 2.52.1 billion.

     Top

    4.2.2 4.2.5 Investments

    Our investments have increaseddecreased compared with 2008 due to more complex and challenging projects, inorganic growth and cost increases due to a tight supplier market.

    substantial acquisitions during the previous year, mainly in our international project portfolio.

    

    Capital expenditure
    Our capital expenditure in our four principal business segments in 2006from 2007 through 20082009 is described below, including the allocation per segment as a percentage of gross investments. Capital expenditure is expected to amount to approximately NOK 95.3USD 13.0 billion in 2009.

    	For the year ended 31 December,
    Gross investments (NOK billion)	2008	% of total	2007	% of total	2006	% of total
    E&P Norway	34.9	37 %	31.1	41 %	29.2	45 %
    International E&P	48.7	51 %	36.2	48 %	28.9	45 %
    Natural Gas	2.0	2 %	2.1	3 %	3.2	5 %
    Manufacturing & Marketing	8.5	9 %	4.8	6 %	2.5	4 %
    Other	1.3	1 %	0.8	1 %	0.5	1 %
    Total gross investments	95.4	100 %	75.0	100 %	64.3	100 %

    Exploration expenditure
    We experienced a step-up in exploration activities in during the period from 2006 to 2008. Exploration expenditure in 2008 amounted to NOK 17.8 billion,2010, compared to NOK 14.2with USD 12.4 billion in 2007 and NOK 13.4 billion in 2006. Exploration expenditure is expected to further increase to approximately NOK 18 billion in 2009. The group expects to participate in the drilling2009 (exclusive of approximately 70 wells in 2008. However, no guarantees can be given with regard to the numbercapitalisation 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 capitalised and expensed. See report section 4.2.5 Financial performance-Liquidity and capital resources-Critical accounting judgements.financial leases).

    We use the "Successful efforts" method of accounting for oil and natural gas-producing activities. Expenditure on drilling and equipping exploratory wells is capitalised until it is clarified whether there are proved reserves. Expenditure on drilling exploratory wells that do not find proved reserves and geological, geophysical and other exploration expenditure is expensed. Unproved oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether major capital expenditure can be justified, may remain capitalised for more than one year. The main conditions are either that firm plans exist for future drilling in the licence or that a development decision is planned in the near future.

    	For the year ended 31 December
    Gross investments (in NOK billion)	2009	2008	2007	09-08 Change	08-07 Change
    - E&P Norway	34.9	34.9	31.1	(0 %)	12%
    - International E&P	39.4	48.7	36.2	(19 %)	35%
    - Natural Gas	2.6	2.0	2.1	29 %	(6 %)
    - Manufacturing & Marketing	6.8	8.5	4.8	(20 %)	76 %
    - Other	1.3	1.3	0.8	3 %	73 %
    Total gross investments	85.0	95.4	75.0	(11 %)	27 %

    Production cost per barrel is expected to increase as a result of tail-end production on mature fields on the NCS, PSA effects on production in international areas and continued pressure on costs in the industry.

    		For the year ended 31 December
    Gross investments (in NOK billion)	2009	% of total	2008	% of total	2007	% of total
    - E&P Norway	34.9	41 %	34.9	37 %	31.1	41 %
    - International E&P	39.4	46 %	48.7	51 %	36.2	48 %
    - Natural Gas	2.6	3 %	2.0	2 %	2.1	3 %
    - Manufacturing & Marketing	6.8	8 %	8.5	9 %	4.8	6 %
    - Other	1.3	2 %	1.3	1 %	0.8	1 %
    Total gross investments	85.0	100 %	95.4	100%	75.0	100 %

    This section describes our estimated capital expenditure for 20092010 with respect to potential capital expenditure requirements for the principal investment opportunities available to us and other capital projects currently under consideration. The figure is based on StatoilHydroStatoil developing organically, and it excludes possible expenditures related to acquisitions. Therefore, the expenditure estimates and descriptions with respect toof investments in the segment descriptions below could differ materially from the actual expenditure. For more information onabout the various projects in each of the segments, see the respective report sub-sections described under sectoinsection 4 Financial performance.analysis and review.

    E&P Norway.Norway. A substantial proportion of our 20092010 capital expenditure has been allocated to thewill be spent on ongoing development projects on Skarv, Ormen Lange,Morvin, Gjøa, Vega, MorvinGoliat, the Gullfaks fields and Statfjord late life.IOR projects.

    International E&P.&P. We currently estimate that a substantial proportion of our 20092010 capital expenditure will be allocated tospent on the following ongoing and planned development projects: Peregrino in Brazil, Pazflor and PSVM in Angola, Marcellus Shale Gas and Tahiti in the USA ,and Leismer Demo Project in Canada and Corrib in Ireland.Canada.

    Natural Gas.Gas. We currently estimate that most of the 20092010 capital expenditures will be spent on projects related to upgrading of the Kårstø processing plant and the Gassled transportation system, and on transport solutions for Marcellus Shale Gas. In addition, projects are under execution to increase our flexibility to move gas in additiontime, to improve robustness in relation to delivery obligations and to exploit opportunities relating to daily and seasonal gas price fluctuations. These projects involve both Gassled on the new Gjøa gas pipeline. The Gjøa gas pipeline tiesNCS and our assets in the Gjøa field into Britain's existing Far North Liquids and Associated Gas System (Flags), which runs to St. Fergus in Scotland.UK.

    Manufacturing & Marketing.Marketing. We are focusing our capital expenditure on upgrading our refineries to increase robustness and flexibility, as well as developing extra heavy oil value chains based on E&P assets. In 2006, we received the final permit to build a combined heat and power plant (CHP plant) at Mongstad. It is being constructed and will be built and operated by the Danish company Dong under a long-term lease agreement, inunder which StatoilHydro haveStatoil has an option to take over ownership after 20 years free of charge. We and our partners at Mongstad and on Troll will investare investing NOK 3.33.9 billion in refinery modifications and a gas pipeline from Kollsnes to Mongstad in connection with the CHP plant. In additionplant, which is expected to the CHP project, the main focus at Mongstadstart operation in the next three years will be a coke safety unit, automation upgrade and improvements to infrastructure.2010. At Kalundborg, the main focus is on infrastructure improvements. In 2009, we bought the lease for the Bahamian South Riding Point crude terminal. We are currently assessing the need for upgrading of the terminal to enable it to take new, potentially h eavier crudes.

    As illustrated in section 4.2.14.2.4 Financial performance-Liquidityanalysis and review - Liquidity and capital resources-Principalresources - Principal contractual obligations, we have committed to certain investments in the future. The proportion of estimated investments that we have also committed to as ofat year end 2008 is declining2009 will decline with the time horizon.time. The fartherfurther into the future, the more flexibility we will have in committing to therevise expenditure. This flexibility is partly dependent on whatthe expenditure our partners in joint ventures agree to commit to.

    Exploration expenditure
    We experienced some reduction in exploration activities in 2009 compared with the level in 2008. Exploration expenditure in 2009 amounted to NOK 16.9 billion, compared with NOK 17.8 billion in 2008 and NOK 14.2 billion in 2007. Exploration expenditure is expected to decline to approximately USD 2.3 billion in 2010. The group expects to participate in the drilling of approximately 50 wells in 2010. However, no guarantees can be given with regard to the number of wells drilled, the cost per well and the results of drilling. Evaluation of the results of drilling will influence the amount of exploration expenditure capitalised and expensed. See report section 4.2.9 Financial analysis and review - Critical accounting judgements.

    We use the "Successful efforts" method of accounting for oil and natural gas-producing activities. Expenditure on drilling and equipping exploratory wells is capitalised until it is clarified whether there are proven reserves. Expenditure on drilling exploratory wells that do not find proven reserves and geological, geophysical and other exploration expenditure is expensed. Unproven oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but where classification of those reserves as proven depends on whether major capital expenditure can be justified, may remain capitalised for more than one year. The main conditions are either that firm plans exist for future drilling in the licence or that a development decision is planned in the near future.

    Finally, we may alter the amount, timing or segmental or project allocation of our capital expenditure in anticipation of or as a result of a number of factors outside our control, including, but not limited to:

    • exploration and appraisal results, such as favourable or disappointing seismic data or appraisal wells;
    • cost escalation, such as higher exploration, production, plant, pipeline or vessel construction costs;
    • government approval of projects;
    • government awards of new production licences;
    • partner approvals;
    • the development and availability of satisfactory transport infrastructure;
    • the development of markets for our petroleum products and other products, including price trends;
    • political, regulatory or tax regime risks;
    • accidents such as rig blowouts or fires, and natural hazards;
    • adverse weather conditions;
    • environmental problems which could lead, for instance, to development restrictions, costs relating to regulatory compliance or the effects of petroleum discharges or spills; and
    • acts of war, terrorism and sabotage.
     Top

    4.2.34.2.6 Off balance sheet arrangements

    This section describes various agreements, such as operational leases and transportation and processing capacity contracts, that are not recognised in the balance sheet.

    We have entered into various agreements, such as operational leases and transportation and processing capacity contracts, that are not recognised in the balance sheet. See report section 4.2.4 Financial analysis and review - Liquidity and capital resources - Principal contractual obligations, for more information.

    We are not party to any off-balance sheet arrangements such as the use of Variable Interest Entities.

    The group is party to certain guarantees, commitments and contingencies that, pursuant to IFRS, are not necessarily recognised in the balance sheet as liabilities. See note 28 Other commitments and contingencies in section 8 Consolidated financial statements for more information.

     Top

    4.2.7 Material contracts

    On 18 December 2006,

    Statoil and Norsk Hydro ASA announced that they had agreed to ahas not entered into any material contracts since the merger of Norskwith Hydro's oil and energy activities with Statoil. The merger was completed on 1 October 2007 and Statoil changed its name to StatoilHydro ASA.

    2007.

    See report section 3.13 Operational review-Related party transactions and report section 6.4 Shareholder information-Majorinformation - Major shareholders, for a description of certain agreements we have entered into with the Norwegian State.

    The merger was implemented by means of a demerger transaction effected in accordance with Norwegian law whereby the assets, rights and obligations relating to Norsk Hydro's oil and energy activities and certain related assets were transferred to the merged company for a consideration in the form of shares of Statoil to be issued to the shareholders of Norsk Hydro. Shareholders of Norsk Hydro received 0.8622 shares of the merged company for each Norsk Hydro share that they owned and 0.8622 ADSs in Statoil for each Norsk Hydro ADS that they owned. Following completion of the merger, the Norwegian State owned 62.5% of our shares. The shareholding has since increased and as of 5 March 2009, the Norwegian State had a direct interest of 67% of our shares, and an indirect holding of 3.94% through the state pension fund (Folketrygdefondet), for a total of 70.94% interest.

    In accordance with the terms of the merger plan, with effect from 1 January 2007, the merged company took over certain assets, rights and obligations related to Norsk Hydro's activities, including: 

    • all payment obligations relating to outstanding bonds of the Norsk Hydro group, totalling approximately NOK 19 billion as of 1 January 2007;
    • all guarantee obligations relating to the Norsk Hydro assets transferred to the merged company, representing a guarantee liability of approximately NOK 20 billion as of 1 January 2007;
    • the allocation of rights, assets and obligations (including environmental and pension liabilities) based on an allocation ratio determined in accordance with the merger plan;
    • the inter-company demerger balance representing a loan or claim of such magnitude that the net interest-bearing debt of the Norsk Hydro assets transferred to the merged company was NOK 1 billion as of 1 January, 2007. The balance was settled in February 2009 and will not have a significant impact on the consolidated equity. (See note 31 to the financial statements for more information about the merger);
    • the assumption of pension obligations relating to employees of the Norsk Hydro group transferred to the merged company and certain former and retired employees; and
    • all historical and future rights and obligations with respect to taxation issues of the relevant Norsk Hydro activities from 1 January, 2007.
     Top

    4.2.44.2.8 Impact of inflation

    Price increases for raw materials and services that are necessary tofor the development and operation of oil and gas producinggas-producing assets have affected our results in recent years.

    In recent years,Although the price pressure has abated since it peaked in 2008, our results have been significantly affected significantlyin the last few years by inflation in the cost of certain raw materials and services that are necessary for the development and operation of oil and gas producinggas-producing assets. Meanwhile, otherOther parts of our business are not exposed to similar cost pressures.

    

    While some of the cost pressure relatesrelate to capitalised expenditures and thus only affectingaffect our annual profit through increased depreciation, certain elements of operating expenditures have also been affected by this inflation. See our analysis of profit and loss as well as applicablerelevant outlook sections in report section 4.1 Financial performanceanalysis and review - Strong operational performance for details."Continued deliveries in turbulent markets".

    As measured by the general consumer price index, inflation in Norway for the years endingended 31 December 2009, 2008 and 2007 was 2.0%, 2.1% and 2006 was 2.1%, 0.9% and 2.6%, respectively.

     Top

    4.2.54.2.9 Critical accounting judgements and

    This section describes key sources of estimation uncertainty

    This section describes and the critical judgements that the Groupgroup has made in the process ofwhen applying the accounting policies.

    The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU). The accounting policies applied by the group also comply with IFRS as issued by the International Accounting Standards Board (IASB). This means that we are required to make estimates and assumptions. We believe that, of the company's significant accounting policies (see note 2 - Significant accounting policies, to our Consolidated Financial Statementsconsolidated financial statements included in this report), the following may involve a greater degree of judgement and complexity, which, in turn, could materially affect the net income if various assumptions were changed significantly.significantly changed.

    Critical judgements inwhen applying accounting policies
    The following are the critical judgements, apart from those involving estimations (see below), that the Groupgroup has made in the process of applying the accounting policies and that have the most significant effect on the amounts recognised in the financial statements:

    Revenue recognition - gross versus net presentation of traded SDFI volumes of oil and gas production
    As described under Transactions with the Norwegian State (see note 2 - Significant accounting policies to our Consolidated Financial Statements included in this report),above, the Groupgroup markets and sells the Norwegian State's share of oil and gas production from the NCS. The Groupgroup includes the costs of purchase and proceeds from the sale of the SDFI oil production in its CostPurchases [net of goods soldinventory variation] and Revenue,Revenues, respectively. In making the judgement, the Groupgroup considered the detailed criteria for the recognition of revenue from the sale of goods, set out in IAS 18 Revenue, and assessed in particular by analogyit assessed whether the risk and reward of the ownership of the goods had been transferred from the SDFI to the Group.group.

    As also described in note 2 - significant accounting policies to our Consolidated financial statements,above, the Groupgroup sells, in its own name, but for the Norwegian State's account and risk, the State's production of natural gas. This sale, and related expenditures refunded by the State, are recorded net in the Group'sgroup's financial statements. In making the judgementjudgment, the Groupgroup considered the same criteria as for the oil production and concluded that the risk and reward of the ownership of the gas had not been transferred from the SDFI to the Group.group.

    Method of accounting applied for the Hydro Petroleumpetroleum merger
    As described under Basis of preparation (see note 2 - Significant accounting policies to our Consolidated Financial Statements included in this report), theThe merger between former Statoil ASA and Hydro Petroleum has beenpetroleum in 2007 was accounted for using the carrying amounts of the assets and liabilities. When making this judgement, the Groupgroup considered, firstly, whether the former Statoil ASA and Hydro Petroleumpetroleum were under the common control of the Norwegian State and, secondly, given the conclusion that both entities were under the control of the Norwegian State, assessed what method of accounting would provide the most meaningful portrayal of the merger for accounting purposes. StatoilHydroStatoil concluded that such a reorganisation would be best presented using the carrying amounts of assets and liabilities, and restating allit is presented in the financial statements for all periods presented as if the companies had always been combined.

    Key sources of estimation uncertainty
    The preparation of consolidated financial statements requires that management make estimates and assumptions that affect reported amounts of assets and liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the result of which formforms the basis offor making the judgements about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis consideringtaking the current and expected future market conditions.conditions into consideration.

    The group is exposed to a number of underlying economic factors, such as liquids prices, natural gas prices, refining margins, foreign exchange rates, as well asinterest rates and financial instruments with fair valuevalues derived from changes in these factors, which affect the overall results. In addition, the group's results of the group are influenced by the level of production, which, in the short term, may be influenced by, for instance, maintenance.maintenance programmes. In the long term, the results are impacted by the success of exploration and field development activities.

    The matters described below are considered to be the most important in relation to understanding the key sources of estimation uncertainty that are involved in preparing these financial statements and the uncertainties that could most significantly impactaffect the amounts reported on the results of operations, financial position and cash flows.

    
    
    ProvedProven oil and gas reserves. Proved
    Proven oil and gas reserves have been estimated by internal experts in accordance withon the basis of industry standards and governed by criteria established by regulations of the SEC. The SEC revised Rule 4-10 of Regulation S-X and changed a number of oil and gas reserve estimation requirements effective for the year ending 31 December 2009 . This required , on a prospective basis , the use of a price based on a 12-month average for reserve estimation instead of a single end-of-year price and allows for nontraditional sources such as bitumen extracted from oil sands to be included as reserves . The Financial Accounting Standards Board (FASB) also aligned the requirements for supplemental oil and gas disclosures with the changes made by the SEC . Statoil estimates that implementation of the revisions had an immaterial impact on proved reserves as of 31 December 2009 and will have an immaterial impact on unit of production depreciation starting in 2010 . However , the comparability of disclosures between years is impacted by the new requirements.

    Reserves estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbons volumes, the production, historical extraction recovery and processing yield factors and installed plant operating capacitycapacity. For future development projects, proven reserves estimates are only included where there is a significant commitment to project funding and operating approval limits.execution and when relevant governmental and regulatory approvals have been secured or are reasonably certain to be secured. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of the extracting and processing of the hydrocarbons. An independent third party has evaluated StatoilHydro's provedStatoil's proven reserves estimates, and the results of suchthis evaluation do not differ materially from management estimates. ProvedProven oil and gas reserves are the estimatedthose quantities of crude oil naturaland gas, and natural gas liquids which, geological an dby analysing geoscience and engineering data, demonstrateca n be estimated with reasonable certainty to be recoverable in future yearseconomically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and operating conditions, i.e., prices and costs asgovernment regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the dateperiod before 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.contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. Future changes in provedproven oil and gas reserves, for instance as a result of changes in prices, could have a material impact on the unit of production rates used for depreciation and amortisation.

    
    
    Expected oil and gas reserves.reserves
    Expected oil and gas reserves have been estimated by internal experts in accordance withon the basis of industry standards and are used for impairment testing purposes and for calculation ofcalculating asset retirement obligations. Reserves estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbons volumes, the production, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of the extracting and processing of the hydrocarbons. Future changes in expected oil and gas reserves, for instance as a result of changes in prices, could have a material impact on asset retirement obligations, as well as foron the impairment testing of upstream assets, which could have a material adverse effect on operat ingoperating income as a result of increasedchanged impairment charges.

    
    
    Exploration and leasehold acquisition costs.costs
    The Group accounting policy is to capitalisegroup capitalises the costs of drilling exploratory wells pending determination of whether the wells have found provedproven oil and gas reserves. The Groupgroup also capitalises leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgements onJudgments as to whether these expenditures should remain capitalised or written down due to impairment losses in the period may materially affect the operating income for the period.

    
    
    Impairment/reversal of impairment.
    The Groupgroup has significant investments in property, plant and equipment and intangibles.intangible assets. Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired, thus requiring the book value to be written down to its recoverable amount. Impairments are reversed if the conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgement and may depend to a large extent depend uponon the selection of key assumptions about the future.future used.

    UnprovedUnproven oil and gas properties are assessed for impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount.amount, and at least annually. If, following evaluation, an exploratory well has not found provedproven reserves, the previously capitalised costs are tested for impairment. Exploratory wells that have found reserves, but classificationSubsequent to the initial evaluation phase for a well, it will be considered a trigger for impairment testing of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalisedwell if no development decision is planned for more than one year. The main conditions are that either firm plans existthe near future, and, moreover, if there is no concrete plan for future drilling in the licence, or a development decisionlicence. Impairment of unsuccessful wells is planned inreversed if the near future.conditions for impairment are no longer present.

    Estimating the recoverable amountamounts involves complexity in estimatingcomplex estimates of relevant future cash flows based on assumptions about the future, assumptions which areand discounted to their present value.

    Impairment testing requires long-term assumptions to be made concerning a number of often volatile economic factors, such as future market prices, refinery margins, currency exchange rates and future output, discount rates and political and country risk, among others, in order to establish relevant future cash flows. Impairment testing frequently also requires judgement to be applied as regards applicable probabilities and probability distributions. This also applies to the levels of sensitivity inherent in the establishment of recoverable amount estimates, and, consequently, in ensuring that the robustness of the estimates of recoverable amounts, where relevant, is factored sufficiently into the impairment evaluations and reflected in the impairment or reversal of impairment recorded in the financial statements. Long-term assumptions for major factors are made at group level about major economic factors, and there is a high degree of reasoned judgement involved in establishing these assumptions, in determining other relevant factors such as forward price curves, in estimating production outputs, and in determining the ultimate termination value of an asset.

    
    
    Employee retirement plans.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 income, management make a number of critical assumptions affecting these estimates. Most notably, assumptions made onabout 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 potentially material impact on the amounts presented. Significant changes in these assumptions between periods can have a material effect on the accounts.

    financial statements.
    
    Asset retirement obligationsobligations..
    The Groupgroup has significant obligations to decommission and remove offshore installations at the end of the production period. Legal obligations associated with the retirement of non-current assets are recognised at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, thethat cost is capitalised as part of the related non-current 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, considering relevant risks and uncertainties. Most of the removal activities are many years intoin the future and the removal technology and costs are constantly changing. The estimates include assumptions ofabout both the the time required and the day rates for rigs, marine operations and heavy lift vessels, thatwhich can vary considerably depending on the assumed removal complexity.complexity of the removal. As a result, the initial recognition of the liability, and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items involve the application of significant judgement.

    
    
    Derivative financial instruments and hedging activities. The Group recognises all derivatives on the balance sheet at fair value. Changes in fair value of derivatives are included in the statement of income. Loans subject to fair value hedge accounting are adjusted for the fair value impact of the hedged risk. This adjustment will offset the majority of the change in fair value of the corresponding derivative.

    
    When not directly observable in active markets, 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. Changes in internal assumptions and forward curves could materiallyhave a material impact on the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in a corresponding impact on income or loss in the income statement.

    
    
    Income tax.
    The Groupgroup annually incurs significant amounts of income taxes payable to various jurisdictions around the world, and it also recognises significant changes toin deferred tax assets and deferred tax liabilities, all of which are based on management's interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon management's ability to properly apply at timeswhat are in part very complex sets of rules, to recognise changes in applicable rules and, in the case of deferred tax assets, management's ability to project future earnings from activities that may applycan utilise loss carry forwardcarryforward positions against future income taxes.

     Top

    4.2.6 Off balance sheet arrangements

    This section describes various agreements such as operational leases and transportation and processing capacity contracts that are not recognised in the balance sheet.

    We have entered into various agreements, such as operational leases and transportation and processing capacity contracts that are not recognised in the balance sheet. See report section 4.2.1 Financial performance-Liquidity and capital resources-Principal contractual obligations for more information.

    We are not party to any off-balance sheet arrangements such as the use of Variable Interest Entities.

    The group is party to certain guarantees, commitments and contingencies that pursuant to IFRS are not necessarily recognised in the balance sheet as liabilities. See note 26 Other commitments and contingencies in the Consolidated Financial Statements in section 8 for more information.

     Top

    4.3 Non-GAAP measures

    Use and reconciliation of

    This section describes the non-GAAP financial measures

    SEC regulations require us to disclose .

    We are 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 generally accepted accounting principles, which in our case refers to IFRS.

    The following financial measures may be considered non-GAAP financial measures:

    • Return on Average Capital Employed (ROACE).
    • Normalised productionProduction cost per barrel.barrel of entitlement and equity volumes.
    • Net debt to capital employed ratio.
     Top

    4.3.1 Return on capital employed (ROACE)

    StatoilHydro uses

    We use ROACE to measure the return on capital employed, regardless of whether the financing is through equity or debt.

    

    StatoilHydro usesWe use ROACE to measure the return on capital employed, regardless of whether the financing is through equity or debt. In the company's view, this measure provides useful information for both for the company and for investors regardingabout performance during the period under evaluation. We make regular use of this measure to evaluate our operations. Our use of ROACE should not be viewed as an alternative to income before financial items, income taxes and minority interest, or to net income, which are measures calculated in accordance with generally accepted accounting principles or ratios based on these figures.

    

    ROACE was 21.3%10.4% in 2009, compared with 21.0% in 2008 compared with 17.9%and 17.7% in 2007 and 22.9% in 2006.2007. The increasedecrease from last year was mainly due to higher prices on both liquids and natural gas, an increase of volumes of natural gas solda 43% drop in net income adjusted for financial items after tax and a 15% increase in net financial loss.capital employed.

    Adjusted for the effects of restructuring costs and other costs arising from the merger, ROACE was 10.5% in 2009, compared with 21.1% in 2008 compared with 19.9%and 20% in 20072007. The decrease from 2008 to 2009 was caused by a drop in income and 22.9% in 2006.increased capital employed. ROACE is defined as a non-GAAP financial measure.

    Calculation of numerator and denominator used in ROACE calculation	Twelve months ended 31 December
    (in NOK million, except percentages)	2008	2007	2006
    Net income for the last 12 months	43,270	44,641	51,847
    After-tax net financial items for the last 12 months	6,415	(7,157)	(5,072)
    Net income adjusted for financial items after tax (A1)	49,685	37,484	46,775
    Adjustment for restructuring costs and other costs arising from the merger	(354)	4,212	0
    Net income adjusted for restructuring costs and other costs arising from the merger (A2)	49,331	41,696	46,775
    Calculated average capital employed:
    Average capital employed before adjustments (B1)	236,405	211,806	206,100
    Average capital employed (B2)	233,273	208,857	204,408
    Calculated ROACE:
    Calculated ROACE based on average capital employed before adjustments (A1/B1)	21.0 %	17.7 %	22.7 %
    Calculated ROACE based on average capital employed (A1/B2)	21.3 %	17.9 %	22.9 %
    Calculated ROACE based on average capital employed and one-off effects (A2/B2)	21.1 %	19.9 %	22.9 %

    Calculation of numerator and denominator used in ROACE calculation	For the year ended 31 December
    (in NOK billion, except percentages)	2009	2008	2007
    Net income for the year	17.7	43.3	44.6
    After-tax net financial items for the year	10.5	6.4	(7.2)
    Net income adjusted for financial items after tax (A1)	28.2	49.7	37.5
    Adjustment for restructuring costs and other costs arising from the merger	(0.1)	(0.4)	4.2
    Net income adjusted for restructuring costs and other costs arising from the merger (A2)	28.2	49.3	41.7
    Calculated average capital employed:
    Average capital employed before adjustments (B1)	271.2	236.4	211.8
    Average capital employed (B2)	268.7	233.3	208.9
    Calculated ROACE:
    ROACE based on average capital employed before adjustments (A1/B1)	10.4 %	21.0 %	17.7 %
    ROACE based on average capital employed and adjusted for restructuring costs (A2/B2)	10.5 %	21.1 %	19.9 %

     

     Top

    4.3.2 NormalisedUnit of production cost

    Normalised

    The production cost is computed on the basis of entitlement volumes and equity volumes in NOKorder to evaluate the underlying development in production costs.

    Production cost per boe of equity volumes is used to evaluate the underlying development in production costs.

    Normalised Significant portions of Statoil's international production cost in NOK per boe is usedare subject to evaluateproduction-sharing agreements with countries' authorities. Under these agreements, we cover our share of the underlying development in production costs. StatoilHydro'soperating expenditures related to the equity volumes produced. Our international production costs are mainly incurred in USD.thus affected by the amount of equity barrels produced, more than by the entitlement volumes received. In order to exclude currencythe effects and to reflectthat production-sharing agreements have on entitlement volumes (PSA effects), we also compute the change in the underlyingunit of production cost the USD/NOK exchange rate is held constant at 6.00 when calculating normalised production cost. The normalised figures for the relevant previous periods have been restated in order to facilitate comparison.
     based on equity volumes.

    	Entitlement production			Equity production
    	Twelwe months ended 31 December			Twelwe months ended 31 December
    (in NOK per boe)	2008	2007	2006	2008	2007	2006
    Calculated production cost	38.1	44.1	28.4	34.6	41.4	27.3
    Calculated production cost, excluding restructuring cost from the merger	40.6	35.7	na	36.9	33.5	na
    Calculated production cost, excluding restructuring and gas injection cost	36.7	33.2	25.1	33.3	31.2	24.1
    Total  liquids and gas production (mboe per day)	1,751	1,724	1,708	1,925	1,839	1,780

    	Entitlement production			Equity production
    	For the year ended 31 December			For the year ended 31 December
    Production cost summary (in NOK per boe)	2009	2008	2007	2009	2008	2007
    Calculated production cost	38.4	38.1	44.1	35.3	34.6	41.4
    Calculated production cost, excluding restructuring cost from the merger	38.8	40.6	35.7	35.7	36.9	33.5
    Calculated production cost, excluding restructuring and gas injection cost	38.4	36.7	33.2	35.3	33.3	31.2

    Entitlement volumes used in the calculation of the normalised production cost per boe have therefore been adjusted for PSA effects. Higher oil price levels negatively affect the production entitlement volumes, negatively, and hence the production unit cost.

    

    Entitlement volumes are highly affected by production sharingproduction-sharing agreements (PSA effects). On average, the equity volumes exceeded entitlement volumes by 174205 mboe per day in 2009, 166 mboe per day in 2008 and 115 mboe per day in 2007 and 70 mboe per day in 2006.2007. With the same cost basis but higher volumes, the cost per barrel of equity volumes will always be lower than the cost per barrel of entitlement volumes. Based on equity volumes, the average production cost (not normalised) was NOK 35.3 per boe in 2009, compared with NOK 34.6 per boe in 2008 compared toand NOK 41.4 per boe in 20072007.

    The following is a reconciation of our overall operating expenses per year with production cost per year as used when computing the unit of production cost per oil equivalent of entitlement and NOK 27.3 per boe in 2006.
     equity volumes.

    Production cost per boe	Twelve months ended 31 December
    	2008	2007	2006
    Total production costs last 12 months (in NOK million)	24,184	27,776	17,675
    Produced volumes last 12 months (million boe)	635	629	623
    Average USDNOK exchange rate last 12 months	5.64	5.86	6.41
    Production cost (USD/boe)	6.83	7.70	4.44
    Calculated production cost (NOK/boe)	38.1	44.1	28.4
    Normalisation of production cost per boe:
    Production costs last 12 months International E&P (in USD million)	759	662	498
    Normalised exchange rate (USDNOK)	6.00	6.00	6.00
    Production costs last 12 months International E&P normalised at USDNOK 6.00	4,552	3,972	2,987
    Production costs last 12 months E&P Norway (in NOK million)	19,947	23,919	14,488
    Total production costs last 12 months in NOK million (normalised)	24,499	27,891	17,475
    Production cost (NOK/boe) normalised at USDNOK 6.00 [8]	38.6	44.3	28.1

    	For the year ended 31 December
    Reconcilliation of overall operating expenses to production cost (in NOK billion)	2009	2008	2007
    Operating expenses, Statoil Group	15.7	16.2	22.7
    Deductions of costs not relevant to production cost calculation
    1) Business Areas non-upstream	7.6	8.5	8.5
    Total operating expenses upstream	8.0	7.6	14.2
    2) Operation over/underlift	0.3	(0.4)	(0.1)
    3) Transportation pipeline/vessel upstream	1.0	1.3	2.1
    4) Miscellaneous items	(0.1)	0.5	0.1
    Total operating expenses upstream excl. over/underlift & transportation	6.7	6.3	12.1
    Total production costs last 12 months	25.0	24.2	27.8
    5) Grane gas purchase	0.2	0.6	0.4
    6) Restructuring costs from the merger	(0.3)	(1.6)	5.3
    7) Change in ownership interest	0.0	0.8	0.0
    Total operating expenses upstream for adjusted cost per barrel calculation	6.7	6.6	6.3

    

     Top

    4.3.3 Net debt to capital employed ratio

    The

    In the company's view, the calculated net debt to capital employed ratio is viewed by the company as providingprovides a more complete picture of the group's current debt situation than gross interest-bearing debt.

    TheIn the company's view, the calculated net debt to capital employed ratio is viewed by the company as providingprovides a more complete picture of the group's current debt situation than gross interest-bearing debt. The calculation uses balance sheet items relating to total debt and adjusts for cash, cash equivalents and short-term investments. Certain adjustments are made, since different legal entities in the group lend to projects and others borrow from banks, projectbanks. Project financing through an external bank or similar institution will not be netted in the balance sheet and will over-report the debt stated in the balance sheet comparedin relation to the underlying exposure in the group. Similarly, certain net interest-bearing debtdebts incurred from activities pursuant to the Marketing Instruction offrom the Norwegian State is off-setare set off against receivables on the SDFI.

    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.

    The table below reconciles the net interest-bearing debt, capital employed and net debt to capital employed ratio with the most directly comparable financial measure or measures calculated in accordance with GAAP.

    Calculation of capital employed and net debt to capital employed ratio	Twelve months ended 31 December
    (in NOK billion)	2008	2007	2006
    Total shareholders' equity	214.1	177.3	167.8
    Minority interest	2.0	1.8	1.6
    Total equity and minority interest (A)	216.1	179.1	169.4
    Short-term debt	20.7	6.2	5.6
    Long-term debt	54.6	44.4	49.2
    Gross interest-bearing debt	75.3	50.5	54.8
    Cash and cash equivalents	18.6	18.3	7.5
    Current financial investments	9.7	3.4	1.0
    Cash and cash equivalents and current financial investments	28.4	21.6	8.6
    Net debt before adjustments (B1)	46.9	28.9	46.2
    Other interest-bearing elements	1.9	0.0	0.0
    Marketing instruction adjustment	(1.7)	(1.4)	0.0
    Adjustment for project loan	(1.1)	(2.0)	(2.4)
    Net interest-bearing debt (B2)	46.0	25.5	43.8
    Normalisation for cash-build up before tax payment (50% of tax payment)	0.0	0.0	0.0
    Net interest-bearing debt (B3)	46.0	25.5	43.8
    Calculation of capital employed:
    Capital employed before adjustments to net interest-bearing debt (A+B1)	264.8	208.0	215.6
    Capital employed before normalisation for cash build-up for tax payment (A+B2)	262.0	204.5	213.2
    Capital employed (A+B3)	262.0	204.5	213.2
    Calculated net debt to capital employed:
    Net debt to capital employed before adjustments (B1/(A+B1))	17.7 %	13.9 %	21.4 %
    Net debt to capital employed before normalisation for tax payment (B2/(A+B2)	17.5 %	12.4 %	20.5 %
    Net debt to capital employed (B3/(A+B3))	17.5 %	12.4 %	20.5 %

    Calculation of capital employed and net debt to capital employed ratio	For the year ended 31 December
    (in NOK billion, except percentages)	2009	2008	2007
    Total shareholders' equity	198.3	214.1	177.3
    Non-controlling interests	1.8	2.0	1.8
    Total equity and minority interest (A)	200.1	216.1	179.1
    Short-term debt	8.1	20.7	6.2
    Long-term debt	96.0	54.6	44.4
    Gross interest-bearing debt	104.1	75.3	50.5
    Cash and cash equivalents	24.7	18.6	18.3
    Current financial investments	7.0	9.7	3.4
    Cash and cash equivalents and current financial investments	31.7	28.4	21.6
    Net debt before adjustments (B1)	72.4	46.9	28.9
    Other interest-bearing elements	5.0	1.9	0.0
    Marketing instruction adjustment	(1.4)	(1.7)	(1.4)
    Adjustment for project loan	(0.7)	(1.1)	(2.0)
    Net interest-bearing debt (B2)	75.3	46.0	25.5
    Calculation of capital employed:
    Capital employed before adjustments to net interest-bearing debt (A+B1)	272.5	263.0	208.0
    Capital employed, adjusted (A+B2)	275.4	262.0	204.5
    Calculated net debt to capital employed:
    Net debt to capital employed before adjustments (B1/(A+B1))	26.6 %	17.8 %	13.9 %
    Net debt to capital employed (B2/(A+B2))	27.3 %	17.5 %	12.4 %

     

     Top

    4.4 Accounting Standards (IFRS)

    In accordance with Norwegian and European Union (EU) regulations, StatoilHydro has prepared its first set of

    We prepare our consolidated financial statements for 2007 in accordance with the International Financial Reporting Standards (IFRS) as adopted by the EU.

    The accounting policies applied by the group also comply with IFRSEU and as issued by the International Accounting Standards Board (IASB).

    Board.

    We prepared our first set of consolidated financial statements pursuant to IFRS for 2007. The IFRS standards have been applied consistently to all periods presented in the consolidated financial statements and when preparing an opening IFRS balance sheet as of 1 January 2006 (subject to certain exemptions allowed by IFRS 1) for the purpose of the transition to IFRS.

    Change in parent company functional currency
    StatoilHydro reports with the US dollar

    With effect from 2009, we have reported using USD as the functional currency in the parent company, while the group has retainedwe use NOK as the reporting currency, effective in the first quarter of 2009.

    Everything else being equal, this is expected to reduce the volatility in net income caused by fluctuations in the USD/NOK rate. Due to the difference between functional currency and reporting currency, certain currency valuation effects will still be recorded, but they will now be recorded directly to equity under other comprehensive income.

    Specifically, USD denominated assets and liabilities held by the parent company that to date have given rise to material currency gains and losses will no longer give rise to such effects. An example of this has been the recent currency losses on USD denominated loans.

    Assets and liabilities held by the parent company and denominated in other currencies than USD, e.g. NOK, will however give rise to new currency gains and losses. An example of this will be the NOK denominated tax liabilities.

    The change in functional currency is thus expected to reduce volatility in net income but add volatility in other comprehensive income. The change is not expected to have a material impact on the ability to pay dividends.currency. Prior period financial statements arehave not been restated, since this is not required to be restated.by the standard.

     Top 

    5 Risk review

     Top 

    5.1 Risk factors

    5.1.1 Risks related to our business

    This section discusses some of the potential risks relating to our business, such as oil prices, the financial crisis, competition and international relations.

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

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

    • global and regional economic and political developments in resource-producing regions, particularly in the Middle East and South America
    • global and regional supply and demand
    • the ability of the Organization of the Petroleum Exporting Countries (OPEC)(Opec) and other producing nations to influence global production levels and prices
    • prices of alternative fuels which affect our realised prices under our long-term gas sales contracts
    • Norwegian and foreign governmental regulations and actions
    • global economic conditions
    • war or other international conflicts
    • changes in population growth and consumer preferences
    • the price and availability of new technology, and
    • weather conditions.

    It is impossible to predict future price movements for oil and natural gas with certainty. An extendedA prolonged decline in oil and natural gas prices will adversely affect our business, the results of our operations and our financial condition, our liquidity and our ability to finance planned capital expenditure. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators could lead to further reviews for impairment of the group's oil and natural gas properties. Such reviews would reflect management's view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on ourthe results of our operations in the period in which it occurs. Rapid material and/or sustained reductions in oil, gas and product prices can impact on the validity of the assumptions on which strategic decisions are based and can impact on the economic viability of projects p lannedpr ojects planned or in development. For an analysis of the impact on net operating income of changes in oil and gas prices, see section 5.2 Risk review-RiskReview-Risk Management.

    The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.
    The credit crisis and related turmoil in the global financial systems may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. If the capital and credit markets continue to experience volatility and the availability of funds remains limited, we may incur increased costs associated with debt financings and our ability to access the capital markets or borrow money may become restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions, on our ability to fund our operations and capital expenditures in the future and on our growth rate and shareholder returns. Decreases in the funded levels of our pension plans may also increase our pension funding requirements. In this context, changes in our debt rating could have a material adverse effect on our interest costs and fina ncing sources. Our debt rating can be materially influenced by a number of factors including, but not limited to, acquisitions, investment decisions, and capital management activities.

    The current economic situation could lead to reduced demand for oil and natural gas, or further reductions in the prices of oil and natural gas, or both, which would have a negative impact on our financial position, results of operations and cash flows. Governments will be facing greater pressure on public finances, leading to risk of increased taxation. These factors may also lead to intensified competition for market share and available margin, with consequential potential adverse effects on volumes. The financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

    We may not be able to realise the full benefits of the merger.
    It may not be possible to realise the full benefits that we anticipated to result from the merger with Hydro Petroleum, which was completed in October 2007, or we may not realise these benefits within the expected timeframe (2009 to 2010). The benefits of the merger may be offset by operating losses relating to changes in commodity prices or in oil and gas industry conditions, risks and uncertainties relating to our exploration and production prospects, an increase in operating or other costs, unanticipated difficulties and restructuring and other costs related to the merger, the impact of competition and other risk factors relating to the industry.

    DrillingExploratory 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 or considering exploring in various geographical areas, including resource provinces such as the Norwegian Sea, the Barents Sea, the Deepwaterdeepwater US Gulf of Mexico, the Arctic, onshore Algeria and Libya, as well as offshore Alaska, Angola, Brazil and Venezuela, where environmental conditions are challenging and costs can be high. In addition, our use of advanced technologies requires greater pre-drilling expendituresexpenditure 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 of or delays in the availability of drilling rigs and the delivery of equipment. For example, we have entered intoint o long-term leases for drilling rigs which may turn out not to be required for the originally intended operations, and we cannot be certain that these rigs will be re-employed or at what rates they will be re-employed. Fluctuations in the market for leases of drilling rigs will also have an impact on the rates we can charge in re-employing these rigs. Our overall drilling activity or drilling activity within a particular project area may be unsuccessful. Such failure will have a material adverse effect on the results of our 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 provedproven reserves are on the Norwegian Continental Shelfcontinental shelf (NCS), a maturing resource province. Unless we conduct successful exploration and development activities and/or acquire properties containing provedproven reserves, our provedproven reserves will decline as reserves are produced. Successful execution of our group strategy depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed to provedproven reserves in a timely and efficient manner, we will be unable to sustain the long-term replacement of reserves. In addition, the volume of production from oil and natural gas properties generally declines as reserves are depleted. For example, some of our major fields, such as 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.

    In a number of resource richresource-rich countries, national oil companies control a significant portionproportion of oil and gas reserves that remain to be developed. To the extent that national oil companies choose to develop their oil and gas resources without the participation of international oil companies or that we are unable to develop partnerships with national oil companies, our ability to find and acquire or develop additional reserves will be limited.

    Our future production is highly dependent on 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 provedproven reserves and production will decline and adversely affect the results of our operations and financial condition.

    We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of licences, 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:

    • diversification and reduction of risk;risk
    • the financial strength necessary for capital-intensive developments;developments
    • exploitation of benefits of integration;integration
    • exploitation of economies of scale in technology and organisation;organisation
    • exploitation of advantages of expertise, industrial infrastructure and reserves;reserves, and
    • strengthening of positions as global players.

    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 licences, and they may be able to invest more in developing technology than our financial or human resources permit. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged behind the industry. For more information on the competitive environment, see section 3.11 Operational Review-Competition.

    We face challenges in executingachieving our strategic objective of successfully exploiting growth opportunities.
    An important element of our strategy is to continue to pursue attractive growth opportunities available to us, both in enhancing and repositioning 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, and the challenges to renewal of our upstream portfolio are growing due to increasing global competition for access to opportunities globally.opportunities.

    Our ability to successfully implement this strategy successfully will depend on a variety of factors, including our ability to:

    • identify acceptable opportunities
    • negotiate favourable terms
    • develop the performance of new market opportunities or acquired properties or businesses promptly and profitably
    • integrate acquired properties or businesses into our operations
    • arrange financing, if necessary, and
    • comply with legal regulations.

    As we pursue business opportunities in new and existing markets, we anticipate significant investments and costs in connection with 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 successfully pursue and exploit 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 forecasts may be materially affected. Any such new projects we acquire will require additional capital expenditure and will increase the cost of our discoveries and development. 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 either or both of our forecasts with respect to unit production costs 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, including those operations and properties subject to the final phases of integration after the merger with Hydro Petroleum. We may require additional debt or equity financing to undertake or consummate future acquisitions or projects, and such financing may not be available on terms satisfactory to us, if at all, and it 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 realising profits and 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 may 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 Gulf of Mexico and 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.

    Our development projects on the NCS also face the challenge of remaining profitable. 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 potentially face 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.

    We face challenges in the renewable energy sector.
    Although energy production from renewables is at this timecurrently modest in most countries, wind power, solar energy and biofuels are developing into significant industries. We cannot predict the demand for renewables. We believe that technological innovation and the integration of trend-breaking technologies such as biotechnology and other new ideas is key to advancing in the renewable energy sector and meeting a profitable, sustainable, low-carbon energy future. Some of our competitors may be able to invest more in developing technology in the renewable energy sector than we do. Our performance in the renewable energy sector could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged behind the industry. In addition, projects in renewable energy deal withinvolve emerging technologies, evolving manufacturing techniques and/or cutting edge implementation. Little precedence exists for incorporating certain renewable aspects into new o r existing projects.

    We may not be able to produce some of our oil and gas economically due to the lack of necessary transportation infrastructure when a field is in a remote location.
    Our ability to exploit economically any discovered petroleum resources beyond our provedproven reserves will be dependent, among other factors, on 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 natural 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, the states bordering the Caspian Sea dispute ownership and the distribution of proceeds from the Caspian's seabed and subsoil resources. Our activities in the Persian Gulf may be subject to disruption due, for example, to war and terrorism. Other countries, such as Venezuela, Nigeria and Angola, where we also have operations, have experienced expropriation or nationalisation 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 ourthe results of our operations or financial condition.

    Our operations are subject to political and legal factors in the countries in which we operate.
    We have assets in a number of countries with emerging or transitioning economies, which lack well-established and reliable legal systems, where the enforcement of contractual rights is uncertain or where the governmental and regulatory framework is subject to unexpected change. Our exploration and production activities in these countries are often undertaken together with national oil companies and are subject to a significant degree of state control. In recent years, governments and national oil companies in some regions have begun to exercise greater authority and impose more stringent conditions on companies pursuing exploration and production activities, which is a trend we expect to continue. Intervention by governments in such countries can take a wide variety of forms, including:
    

    • restrictions on exploration, production, imports and exports,
    • the awardawarding or denial of exploration and production interests,
    • the imposition of specific seismic and/or drilling obligations,
    • price controls,
    • tax or royalty increases, including retroactive claims,
    • nationalisation or expropriation of our assets,
    • unilateral cancellation or modification of our licence or contract rights,
    • the renegotiation of contracts,
    • payment delays, and
    • currency exchange restrictions or currency devaluation.

    The likelihood of these occurrences and their overall effect on us vary greatly from country to country and are not predictable. If such risks materialise, they could cause us to incur material costs or cause our production to decrease, potentially having a material adverse effect on our operations or financial condition.

    Our activities in certain countries could lead to US sanctions.
    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 6-7-8 of the South Pars gas development project in the Persian Gulf. ByAdjusted for an impairment in 2005, a partial reversal of impairment in 2009 and cumulative depreciation charges, the net book value was USD 306.2 million at year end of 2008, we had invested a total of USD 225.3 million in South Pars.2009. In addition, as a result of the merger with Norsk Hydro's oil and gas business, StatoilHydro nowStatoil owns a 75% interest in the Anaran Block in Iran, which was acquired by Norsk Hydro in 2000. Following the commerciality declaration of the Azar discovery in the Anaran Block in August 2006, weNorsk Hydro agreed to conduct negotiations with the National Iranian Oil Company for a Master Development Plan and a Development Service Contract. The Anaran Block is currently in the exploration phase.Byphase. Statoil had invested USD 104 million in the end of 2008, StatoilHydro had zero book value of investments, afterproject but this amount has been fully written off following an impairment related to the Anaran project.review in 2008. Work on th is project has stopped. Also as a result of the merger, StatoilHydroStatoil now owns a 100% interest in the Khorramabad Exploration Block, , where StatoilHydrofor which Statoil is the operator. In September 2006, Norsk Hydro signed the Khorramabad Exploration and Development Contract with the National Iranian Oil Company, with a total commitment of USD 49.5 million over four years related to seismic surveysurveys and other exploration activities. We completed the gathering of seismic data in the Khorramabad Exploration Block in the fourth quarter of 2008. The scope and timing ofNo further work programmes on the Khorramabad Exploration Blockactivity is now being evaluated.planned for this license. See section 3.2.6.5.13.2.5.5.1 Operational review-InternationalReview - International E&P - The Middle East and Asia - Iran.

    In June 2008congressional testimony to the US DepartmentHouse Foreign Affairs Sub-committee on the Middle East and South Asia in October 2009, Assistant Secretary of State announcedfor Near Eastern Affairs, Jeffrey D. Feltman, testified that it wouldthe Obama Administration intends to review StatoilHydro's activities to determine whether they breachedoil and gas investments in Iran by foreign companies for potential violations of the Iran Sanctions Act of 1996 (ISA). InFollowing this testimony, toStatoil has, on a voluntary basis, provided officials from the House Foreign Affairs Committee on 9 July 2008, Undersecretary ofU.S. State for Political Affairs William Burns suggested that the Norwegian company's investmentDepartment with information about its activities and investments in South Pars might fall within the purview of the ISA.Iran. The ISA requires the President of the USUnited States to sanction companies with investments ofthat invest more than USD 20 million or moreduring any 12-month period in Iran's energy sector. Such sanctions could include denial of US bank loans and restrictions on the importation of goods produced by the sanctioned company. We cannot predict interpretationsthe interpretation or implementation of orUS governmental policies under the implementation policy of the US Government under ISA with respect to our current or future activities in Iran or other areas.Iran. It is possible that the United StatesUS authorities may determine that theseour investments in Iran or other activities willrelated projects constitute activity covered by the ISA and, willas a result, may subject us to s anctions.sanctions.

    Certain countries, including Iran and certain other countries, including Cuba, have been identified by the US State Department as state sponsors of terrorism. Our activities in Cuba consist of a 30% interest in six deepwater exploration blocks acquired from Repsol-YPF in 2006. At the end of 2008,As at 31 December 2009, we had invested USD 13.712.5 million in these projects. These activities are not material to our business, financial condition or results of operations, as the total amount invested in these operations in 2008 represented less than 0.02 %0.03% of our total assets as of 31 December 2008.2009.

    We are aware that the U.S. Congress is considering legislation that would tighten U.S. sanctions against Iran, primarily targeting the sale of refined petroleum to Iran. We are also aware of initiatives by certain US states and US institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring divestment from, or reporting of interests in, companies that do business with countries designated as state sponsors of terrorism. These policies could adverselyhave an adverse impact on investment by certain investors in our securities.

    We are exposed to potentially adverse changes in the tax regimes of each jurisdiction in which we operate.
    We operate in 40 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 to other companies in our industry. In addition, in the long-term, the marginal tax rate in the oil and gas industry tends to change 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 the results of our operations.

    We are exposed to potential losses and could be seriously harmed by natural disasters, operational catastrophes or security breaches.
    Exploration for, the production of, and the transportation of oil and natural gas is hazardous, and natural disasters, operator error or other occurrences can result in oil spills, gas leaks, loss of containment of hazardous materials exposed to blowouts, cratering, fires, equipment failure and loss of well control. Failure to manage these risks could result in injury or loss of life, damage or destruction of wells and production facilities pipelines and other property and damage to the environment. All modes of transportation of hydrocarbons contain inherent risks. A loss of contaminant of hydrocarbons and other hazardous materials could occur during transportation by road, rail, sea or pipeline. ThisGiven the high volumes involved, this is a significant risk due to the potential impact of a release on the environment and people given the high volumes involved.people.

    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.

    We are exposed to risks regarding the safety and security of our operations. Inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulationregulatory action, legal liability and damage to our reputation. Security threats require continuous oversight and control. Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt businesses and operations and could cause harm to people.

    Our crisis management systems may be ineffectiveineffective.
    We have developed contingency plans to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframetime frame could prolong the impact of any disruption and could severely affect business and operations. Likewise, we have crisis management plans and capability to deal with emergencies at every level of our operations. If we do not respond or are not perceived to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

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

    The reliability of provedproven reserve estimates depends on:

    • the quality and quantity of our geological, technical and economic data;
    • whether the prevailing tax rules and other government regulations, contracts and oil, gas and other prices will remain the same as on the date estimates are made;
    • the production performance of our reservoirs; and
    • extensive engineering judgments.

    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. In addition, fluctuations in oil and gas prices will have an impact on our provedproven reserves relating to fields governed by Production Sharing Agreements, or PSAs, since part of our entitlement under PSAs relates to the recovery of development costs. 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 the results of our operations.
    Our business faces foreign exchange risks because a large percentage of our revenues and cash receipts are denominated in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations between the US dollar and other currencies may adversely affect our business and can give rise to foreign exchange exposures with a consequent impact on underlying costs and revenues. See note 28section 5.2.1 Risk review - Financial risk management-Market risk to the Consolidated Financial Statements in this report or Section 5.2.1. Risk review-Risk management-financial risk andmanagement - Managing financial risk management below for more information regarding risk management.risk.

    We are exposed to risks relating to trading and supply activities.
    StatoilHydroStatoil is engaged in substantial trading and commercial activities in the physical markets and it also uses financial instruments such as futures, options, over-the-counter (OTC) forward contracts, market swaps and contracts for differences related to crude oil, petroleum products, natural gas and electricity in order to manage price volatility. We also use financial instruments to manage foreign exchange and interest rate risk.

    Although StatoilHydroStatoil believes it has established appropriate risk management procedures, trading activities involve elements of forecasting and StatoilHydroStatoil bears the risk of market movements - the risk of significant losses if prices develop contrary to expectations - and the risk of default by counterparties. See note 28section 5.2.1 Risk review - Financial risk management-Market risk to the Consolidated Financial Statements in this report or Section 5.2.1. Risk review-Risk management-financial risk andmanagement - Managing financial risk management below for more information regarding risk management. Any of these risks could have an adverse effect on the results of our operations and financial condition.

    Our investments, business, profitability 
    The global financial turmoil may have impacts on our liquidity and financial condition that we cannot currently predict.
    The current economic situation could lead to reduced demand for oil and natural gas or reductions in the prices of oil and natural gas, or both, which would have a negative impact on our financial position, results of operations and cash flows. Governments will be facing greater pressure on public finances, leading to a risk of increased taxation. These factors may be adversely affected asalso lead to intensified competition for market share and available margin, with consequential potential adverse effects on volumes. The financial and economic situation may have a resultnegative impact on third parties with whom we do, or may do, business. While the ultimate outcome and impact of the difficult conditions in thecurrent financial markets.
    StatoilHydro's ability to access or continue to access domestic and international capital markets and lenders to the extent sufficient to meet its funding needs, including the refinancing of outstanding debt falling due,turmoil cannot be predicted, it may be adversely affected byhave a number of factors, including Norwegian and international economic conditions and the state of the Norwegian financial system.

    Since the second half of 2007, disruption in the global credit markets, coupled with the repricing of credit risk and the deterioration of the housing markets in the United States, the United Kingdom and elsewhere, has created increasingly difficult conditions in the financial markets. Among the sectors of the global credit markets that are experiencing particular difficulty due to the current crisis are the markets associated with subprime mortgage backed securities, asset backed securities, collateralised debt obligations, leveraged finance and complex structured securities. These conditions have resulted in historically high volatility, lessmaterial adverse effect on our future liquidity, or no liquidity, widening of credit spreads and a lack of price transparency in certain markets.

    Most recently, these conditions have resulted in the failures of a number of financial institutions in the United States and Europe and unprecedented action by governmental authorities and central banks around the world. It is difficult to predict how long these conditions will last and how StatoilHydro's business, projects and markets will be affected. These conditions may be exacerbated by persisting volatility in the financial sector and the capital markets, or concerns about, or a default by, one or more institutions, which could lead to significant market wide liquidity problems, losses or defaults by other institutions. Accordingly, these conditions could adversely affect StatoilHydro's business, financial condition or results of operations in future periods. In addition, StatoilHydro may become subject to litigation and regulatory or governmental scrutiny, or may be subject to changes in applicable regulatory regimes that may be materially adverse. Furthermore, it is not possible to pr edict what structural and/or regulatory changes may result from the current market conditions or whether such changes may be materially adverse to StatoilHydro and its prospects.financial condition.

    We may fail to attract and retain senior management and skilled personnel.
    The attraction and retention of senior management and skilled personnel is a critical factor in the successful execution of our strategy as an international oil and gas group. We may not always be successful in hiring or retaining suitable senior management and skilled personnel. Failure to recruit or retain senior management and skilled personnel or more generally maintain good employee relations could compromise achievement of our strategy and cause disruption to the management structure and relationships, an increase in costs associated with staff replacement, lost business relationships or reputational damage. An inability to attract or retain suitable employees could have a significant adverse impact on our ability to operate.

    Failure to meet our ethical and social standards could harm our reputation and our business.
    Our code of conduct, which applies to all employees of the group, including hired personnel, consultants, intermediaries, lobbyists and others who act on our behalf, defines our commitment to high ethical standards and compliance with applicable legal requirements wherever we operate. Incidents of ethical misconduct or non-compliance with applicable laws and regulations could be damaging to our reputation, , competitiveness and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations.

    We set ourselves high standards of corporate citizenship and aspire to contribute to a better qualify of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.

     Top 

    5.1.2 Risks related to the regulatory regime

    This section discusses potential risks to our business relating to the regulatory regime, such as having to comply with new laws and regulations.

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

    Fundamental changes continue to take place in the organisation 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 European Commission launched a new initiative to further developIn July 2009, the EU adopted an expansive legislative package setting out new regulations for the internal markets in energy, electricity and gas marketwhich will enter into force in SeptemberMarch 2011. The new regulations contain numerous requirements for energy companies relating to supply, transmission, and distribution. The requirements include greater separation of 2007production and it is expected that this packagesupply activities from transmission and distribution activities; the establishment of legislative measures will be approved by May 2009.independent national electricity regulators charged with supporting a competitive, secure and environmentally-sustainable internal markets in electricity and gas; and the harmonization of technical standards in order to promote cross-border collaboration and investment. The impactnew regulations also provide for a European Agency for the Cooperation of such measures depends on the final version implemented but it is expectedEnergy Regulators with competence to create stronger national regulators, a pan European regulatory agency and promote the improved functioningoversee many parts of the gas market in Europe.legislative package.

    Another EU initiative likely to impact on the market for gas involves the environmental package implemented in December 2008, which strengthens and extends the Emissions Trading Scheme and creates national targets for renewable energy. BothThis will have positive and negative impacts on the competitive position of natural gas as a fuel.

    The third focus area of EU energy policy is supply security and this has leadled to an increased focus on projects diversifying gas supplies to the EU. As a result, the Caspian region, now receives increased attention from the EU where StatoilHydroStatoil participates in the Shah Deniz field.field, is now receiving increasing attention from the EU. Solutions to bring Caspian gas to Europe are receiving political support from the EU in an attempt to resolve the complex transportation issue in the region.

    Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that will continue to be affected by changes in EU regulations and the implementation of such regulations in EU member states. As a result of the directives, 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 in connection with complying 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 relating to compliance with increasingly complex laws and regulations covering the protection of the environment and human health and safety, including:

    • costs of reducing certain types of emissions to air and discharges to the sea
    • remediation of environmental contamination at various owned and previously-owned facilities and at third party sites where our products or waste have been handled or disposed of
    • compensation of persons claiming damages caused by our activities or accidents, and
    • costs in connection with the decommissioning of drilling platforms and other facilities.

    The Norwegian Petroleum Safety Authority (PSA) was established on 1 January 2004, with regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. See section 3.10 Operational review-Regulation.Review-Regulation.

    In our capacity as holder of licences on the NCS under the Norwegian Petroleum Act of 29 November 1996, we are subject to statutory strict liability in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licences. This means that anyone who suffers losses or damage as a result of pollution caused by operations in any of our NCS licence 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 on licences, increasingly strict enforcement of or new interpretations of existing laws and regulations, or the discovery of previously unknown contamination may require future expenditure in order to:

    • modify operations
    • install pollution control equipment
    • implement additional safety measures
    • perform site clean-ups, or
    • curtail or cease certain operations.

    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 petrol sulphur levels and diesel quality, affect product specifications and operational practices. Future expenditure to meet such specifications could have a material adverse effect on our operations or financial condition.

    Compliance with laws, regulations and obligations relating to climate change and other environmental regulations could result in substantial capital expenditure, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted.affected. Many of our mature fields are producing increasing quantities of water with oil and gas. Our ability to dispose of this water in environmentally acceptable ways may have an impact on our oil and gas production.

    If we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment, we could fail to live up to our aspirations of no or minimal damage to the environment and contributing to human progress.

    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 State's Direct Financial Interest (SDFI) and its indirect impact through tax and environmental laws and regulations, the Norwegian State awards licences for reconnaissance, production and transportation, and it approves, among other things, exploration and development projects, gas sales contracts and applications for (gas) production rates for individual fields. The Norwegian State may, if important public interests are at stake, also instruct us and other oil companies to reduce the production of petroleum. Furthermore, in the production licences in which the SDFI holds an interest, the Norwegian State retains the ability to direct petroleum licencees' 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 our operations could be materially and adversely affected. For more information about the Norwegian State's regulatory powers, see section 3.10 Operational review-Regulation.Review-Regulation.

     Top 

    5.1.3 Risks related to Norwegian state ownership

    This section discusses some of the potential risks relating to our business that could derive from the majority ownership by the Norwegian state

    State as well as our involvement in the SDFI.

    The interests of our majority shareholder, the Norwegian State, may not always be aligned with the interests of our other shareholders, and this 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 StatoilHydroStatoil and the SDFI's interest in NCS licences must be managed in accordance with 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 usStatoil 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 whichthat may affect the development and marketing of our own and the Norwegian State's oil and gas.

    The Norwegian State held 66.89%67% of our ordinary shares as of 512 March 2009 and held an additional 3.94% through Folketrygdfondet, totaling to 70.83%.2010. A two-thirds majority is required to determinedecide matters submitted forto a vote of shareholders, and the Norwegian state effectively has the power to influence the outcome of any shareholder vote due to the size of its percentage ownership inof our shares, including amending our articles of association and electing all non-employee members of the corporate assembly. The employees are entitled to be represented by up to one-third of the members of the board of directors and one-third of the corporate assembly.

    The corporate assembly is responsible for electing our board of directors. It also makes recommendations to the general meeting concerning the board of directors' proposals relating to the company's annual accounts, balance sheet, allocation of profits and coverage of loss. The interests of the Norwegian State in deciding these and other matters and the factors it considers in exercising its votes, especially under 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 the Norwegian State's coordinated ownership strategy into account, and we may not be able to fully pursue our own commercial interests, including those relating to our strategy for the 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 section 3.13 Operational review-Related party transactions and Section 6.4 Shareholder information-Major shareholders.transactions.

     Top 

    5.2 Risk management

    Our overall risk management approach includes identifying, evaluating, and managing risk in all our activities. We manage risk in order to secureensure safe operations and to reach our corporate goals in compliance with our requirements.

    We have an enterprise-wide risk management approach, which means we:

    • have a risk and reward focus at all levels inof the organisation,
    • evaluate significant risk exposure related to major commitments,
    • manage and coordinate risk at corporate levellevel.

    We divide risk management into three categories:

    • Strategic risks, which are long-term fundamental risks monitored by our Corporate Risk Committee. Our Corporate Risk Committee, which is headed by our Chief Financial Officerchief financial officer and which includes, among others, representatives fromof our principal business segments, is responsible for reviewing, defining and developing our strategic market risk policies. The Committeecommittee meets monthly to determinedecide our risk management strategies, including hedging and trading strategies and valuation methodologies.
    • Tactical risks, which are short-term trading risks based on underlying exposures managed by our principle business segment line managers, and
    • Operational risks such as those described under risk factors and which cover all major operational goals and underlying risk drivers are managed by our principle business segment line managers. In addition, insurable risks are managed by our captive insurance company operating in the Norwegian and international insurance markets.

    To address our strategic and tactical risks, we have developed policies aimed at managing the volatility inherent in certainsome of these natural business exposures, and, in accordance with these policies, we enter into various financial and commodity-based transactions (derivatives). While the policies and mandates are set at the group level, the business areas responsible for marketing and trading commodiites are also responsible for managing the commodity-based price risks. The interest-, liqudity-, liability-,interest, liqudity, liability and credit risks are managed centrally by the finance department.

    The following section describes in some detail the market risks that we are exposed to and how we manage these risks.

     Top 

    5.2.1 Financial risk andManaging financial risk management

    The results of our operations largely depend on a number of factors, most significantly those that affect the price we receive in NOK for our sold products.

    Specifically, such factors include the level of crude oil and natural gas prices, trends in the exchange rate between the USD, in which the trading price of crude oil is generally stated and to which natural gas prices are frequently related, and NOK, in which our accounts are reported and a substantial portionproportion of our costs are incurred; our oil and natural gas production volumes, which in turn depend on entitlement volumes under PSAs and available petroleum reserves, and our own, as well as our partners' expertise and co-operationcooperation in recovering oil and natural gas from those reserves; and changes in our portfolio of assets due to acquisitions and disposals.

    Our results will also be affected by trends in the international oil industry, including possible actions by governments and other regulatory authorities in the jurisdictions in which we operate, or possible or continued actions by members of the Organisation of Petroleum Exporting Countries (OPEC) that affect price levels and volumes; refining margins; increasing cost of oilfield services, supplies and equipment; increasing competition for exploration opportunities and operatorships, and deregulation of the natural gas markets, which may cause substantial changes to the existing market structures and to the overall level and volatility of prices.

    The following table shows the yearly averages for quoted Brent Blend crude oil prices, natural gas contract prices, fluid catalytic cracking (FCC) margins and the USDNOKUSD/NOK exchange rates for 2009, 2008 2007 and 2006.2007.

    Yearly average	2008	2007	2006
    Crude oil (USD/bbl brent blend)	91	70.5	63.2
    Natural gas (NOK per scm)(1)	2.4	1.66	1.94
    FCC margins (USD/bbl)(2)	8.2	7.5	7.1
    USDNOK average daily exchange rate	5.63	5.86	6.42
    (1)         From the Norwegian Continental Shelf.
    (2)         Refining margin.

    Yearly average	2009	2008	2007	2006
    Crude oil (USD/bbl brent blend)	58.0	91.0	70.5	63.2
    Natural gas (NOK per scm)(1)	1.9	2.4	1.7	1.9
    FCC margins (USD/bbl)(2)	4.3	8.3	7.5	7.1
    USDNOK average daily exchange rate	6.3	5.6	5.9	6.4
    (1) From the Norwegian Continental Shelf.
    (2) Refining margin.

    The illustration shows how certain changes in the crude oil price, natural gas contract prices and the USDNOKUSD/NOK exchange rate, if sustained for a full year, could impactaffect our financial results in 2009.2010.

    

    The estimated sensitivity of our financial results to each of the factors on our financial results has been estimated based on the assumption that all other factors would remain unchanged. The estimated effects on the financial results would differ from those that would actually appear in our consolidated financial statements because our consolidated financial statements would also reflect the effect on depreciation, trading margins, exploration expenses, inflation, potential tax system changes and the effect of any hedging programmes in place.

    Our oil and gas price hedging policy is designed to assist our long-term strategic development and our attainment of targets by protecting financial flexibility and cash flows.

    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 largely accrue in NOK. We seek to manage this currency mismatch by issuing or swapping long-term debt in USD. This debt policy is an integrated part of our total risk management programme. We also engage in foreign currency hedging in order to cover our non-USD needs, which are primarily in NOK. We manage the risk arising from our interest rate exposure 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. In general, an increase in the value of the USD in relation to NOK can be expected to increase our reported earnings. Please see section 5.2.2 Risk review-Risk management-Quantativenotes 6 Financial risk management, 30 Financial instruments by category and 31 Financial instruments: measurement and market risk sensitivities to the co nsolidated financial statements for quantitative and qualitative disclosures about market risk. Please see section 4.4 Financial per formance - Accounting standards for a description of the expected effects on reported financial results of the change in functional currency of the parent company.

    We sell the Norwegian State's share of oil and natural gas production from the NCS. Amounts payable to the Norwegian State for these purchases are included as Accounts payable - related parties in the consolidated balance sheets. The pricing of the crude oil is based on market reflective prices. NGL prices are based on either attained prices, market value or market reflective prices.

    StatoilHydroStatoil sells, in its own name, but for the Norwegian State's account and risk, the State's natural gas production. This sale, as well as related expenses refunded by the State, is shown net in our financial statements. Expenses refunded by the State include expenses incurred in connection with activities and investments that are necessary in order to secure market access and optimise the profit from the sale of the Norwegian State's natural gas. For sales of the Norwegian State's natural gas, both for our own use and to third parties, the payment to the Norwegian State is based on prices attained, a net back formula or market value. We purchase a small proportion of the Norwegian State's gas. For further details, see section 3.13 Operational review-Related party transactions.

    High oil prices have contributed to higher earnings and profitability from international projects with PSAs than previously anticipated. Under a PSA, the partners are generally entitled to production volumes that cover the development costs and an agreed share of the remaining volumes. When oil prices are high, this means that these projects will move from a phase where earnings cover development costs to a phase where profits are generated at an earlier point in time. In PSA contracts, the higher the oil price, the sooner the field is profitable and the smaller is the share of the production that goes to the partners. The actual effect varies between different agreements and countries. Often these tax regimes are asymmetric, i.e. the company's upside is somewhat limited while the company is fully exposed to the downside. See section 4.1.9 Financial performance-Strong operational performance-Reportedanalysis and review - continued deliveries in turbulent markets - sales volumes above for a description of the impact of the PSA effects.

    Historically, our revenues have largely been generated from the production of oil and natural gas on the NCS. Norway imposes a 78% marginal tax rate on income from offshore oil and natural gas activities.activities (a symmetrical tax system). See section 3.10.5 Operational review-Regulation-Taxation of StatoilHydro.Statoil. Our earnings volatility is moderated as a result of the significant proportion of our Norwegian offshore income that is subject to a 78% tax rate in profitable periods, and the significant tax assets generated by our Norwegian offshore operations in any loss-making periods. Most of the taxes we pay are paid to the Norwegian State. Since 1 January 2004, dividends received have not been subject to tax in Norway. Exemptions are granted for dividends from low-tax countries or portfolio investments outside the EEA.

    Government fiscal policy is an issue in several of the countries in which we operate, such as, but not limited to, Venezuela, the United States, Nigeria, Algeria and Angola. For instance, government fiscal policy could require royalties in cash or in kind, increased tax rates, increased government participation, and changes in terms and conditions as defined in various production or income sharingincome-sharing contracts. Our financial statements are based on currently enacted regulations and on any current claims from tax authorities regarding past events. Developments in government fiscal policy may have a negative effect on future net income.

    Financial risk management
    OurStatoil's business activities naturally expose usthe group to financial risk. The group's approach to risk management includes identifying, evaluating, and managing risk in all our activities using a top-down approach withfor the purpose of avoiding sub-optimisation and utilising correlations observed from a group perspective. Only summing up the different market risks without including the correlations will overestimate our total market risk. Due toFor this we utilisereason the group utilises correlations between all the most important market risks, such as oil and natural gas prices, product prices, currencies, and interest rates, to calculate the overall market risk (i.e. utilizeand thereby utilise the natural hedges embedded in our portfolio).portfolio. This approach also reduces the number of unnecessary transactions, (i.e. reducingwhich reduces transaction costs and avoiding sub-optimisation).avoids sub-optimisation.

    In order to achieve the above effects, the group has centralizedcentralised trading mandates (financial positions taken to achieve financial gains, in addition to established policies) such that all major/strategic transactions are co-ordinated through our Corporate Risk Committee. This implies that localLocal trading mandates are therefore relatively small.

    OurThe group's Corporate Risk Committee, which is headedchaired by our Chief Financial Officerthe chief financial officer and which includes among others, representatives from ourof the principal business segments, is responsible for defining, developing, and reviewing ourthe group's risk policies. The Chief Financial Officer in co-operation withchief financial officer, assisted by the Corporate Risk Committee, is also responsible for overseeing and developing StatoilHydro's Enterprise-Wide Risk ManagementStatoil's enterprise-wide risk management and proposing appropriate measures to adjust risk adjusting measures at the corporate level. To help facilitate its role, the CommitteeThe committee meets at least six times per annum and regularly receives risk information relevant forto the group from our Corporate Risk Department.corporate risk department.

    The financial risk management covers market risks, including commodity price risk, interest rate risk, currency risk and equity price risk; liquidity risk; and credit risk.

    Market risk management

    Strategic market risk
    We define strategicStatoil operates in the worldwide crude oil, refined products, natural gas and electricity markets and is exposed to market risks, as long-term risks fundamental toincluding fluctuations in hydrocarbon prices, foreign currency rates, interest rates and electricity prices that can affect the operationrevenues and costs of our business.operating, investing and financing. These risks are monitored and reviewedprimarily managed on a short-term basis with the objectivefocus on achieving the highest risk-adjusted returns for the group within the given mandate. Long-term positions, defined as having a time horizon of avoiding sub-optimisation, reducingsix months or more, are managed at the likelihoodcorporate level while short-term positions are managed at segment and lower levels in accordance with trading strategies and mandates approved by the Corporate Risk Committee.

    The group has established guidelines for entering into contractual arrangements (derivatives) in order to manage its commodity price, foreign currency rate, and interest rate risk. The group uses both financial and commodity-based derivatives to manage the risks in revenues and the present value of experiencing financial distress and supporting the Group's ability to finance future growth even under adverse market conditions. Based on these objectives, policies and procedures have been implemented to reduce our overall exposure to strategic risks.cash flows.

    Tactical market risk
    All tactical risk management activities occur within and are continuously monitored against established mandates.

    Commodity price risk
    Commodity price risk constitutesis our most important tactical market risk. To manage the commoditiescommodity price risk, 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 mainly traded mainly on the InterContinental Exchange (ICE) in London, the New York Mercantile Exchange (NYMEX), 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 ICE.

    The term of oil and refined oil products derivatives is usually less than one year and the term for Naturalnatural gas and electricity derivatives is three years or less. The commodity price risk is managed by the marketing and trading organisations in the Natural gasGas and Manufacturing and& Marketing segments,business areas, respectively. The risks are managed in the trading currencies of the commodities in question, and not necessarily in the functional or reporting currency of the company.

    Currency risk
    We consider StatoilHydroStatoil to be a USD company for currency management purposes. Fluctuations in exchange rates can have significant effects on our results. Foreign exchange risk is assessed on a portfolio basis in accordance with approved strategies and mandates. We only use only well-understood, conventional derivative instruments, which includeincluding futures and options traded on regulated exchanges, OTC swaps, options and forward contracts.

    Our cash inflows are largely denominated in or driven by USD, while our cash outflows mainly derive from tax and dividend payments in NOK, as well as certain investments, payment of salaries and various other costs payable in NOK. Accordingly, our exposure to foreign currency rates existsis primarily withrelated to USD versus NOK. We seek to manage this currency mismatch by issuing or swapping non-current financial debt into USD.

    We further seek to manage short-term currency mismatches by using derivative instruments for both for currency and liquidity management purposes. Typically, we purchase NOK during the course of a calendar year in order to cover projected NOK payments of Norwegian income taxes and dividends in the first half of athe subsequent year. This means, from time to time, that we purchase substantial amounts in NOK amounts on a forward basis using derivative instruments.

    Interest rate risk
    The existence ofgroup has assets earning and liabilities owingwith variable interest rates of interestthat expose usthe group to cash flow risk caused by market interest rate fluctuations. We enter into various types of interest rate contracts in managing our interest rate risk. We enterThe group enters into interest rate derivatives, particularly interest rate swaps, to alter interest rate exposures,exposure, to lower expected funding costs over time and to diversify sources of funding. By using the fixed interest rate debt market when issuing new debt while at the same time altering the interest rate exposure by entering into interest rate swaps, funding sources becomes more diversified than if we were only able to use the floating rate debt market.

    We principally manage the group's interest rates by converting cash flows from the long-term debt portfolio issues with fixed coupon rates ends into floating rate interest payments. Bond issues are normally issued at fixed rates in local currency (JPY, EUR, CHF, GBP and USD). These bonds are converted to floating USD bonds by using interest rate and currency swaps. Under interest rate swaps, we agreethe group agrees 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.

    We principally manage our interest rates on the basis that the non-current debt portfolio has floating rate interest payments. The modified duration (the percentage change in value for one percentage point change in yield) expresses the way we monitor thegroup's interest rate risk. Generally, our modified durationpolicy also includes a mandate to deviate from base policy and keep part of the long-term debt in fixed interest rates.

    Equity price risk
    The group's captive insurance company held listed equity securities as a part of its portfolio. In addition, the group has some other non-listed equity securities acquired for long-term strategic purposes. By holding these assets, the group is exposed to be be between 0equity price risk defined as the risk of declining equity prices leading to a decline in the fair value of the group's assets recognised in the balance sheet. The equity price risk in the portfolio held by the group's captive insurance company with the aim of maintaining a moderate risk profile is managed through geographical diversification, the use of broad benchmark indexes and 1.0%. Other strategies can be approved from time to time if justified by factors such as corporate risk considerations, tax considerations, large non-recurring transactions, credit rating concerns, etc.the use of several different fund managers.

    Liquidity risk management
    Liquidity risk is the risk that we will not be able to meet our obligations when they fall due. The purpose of liquidity and short termshort-term liability management is to make certain that the group at all times has sufficient funds available at all times to cover financial obligations.

    StatoilHydro'sOn a monthly basis, Statoil's business activities normally generate on a monthly basis, a positive cashflowcash flow from operations. However, in months when taxes are paid (February, April, June, August, October and December) or annual dividend is paid (typically in May/June) cashflowscash flows are typically limited. Our operating cashflowscash flows are negatively impactedaffected by declines in oil and gas prices, however,prices. However, during 20082009, our overall liquidity position remained strong and our policies for managing liquidity remained unchanged.

    TheAs a rule, the amount of liquid assets will as a rule, follow a cyclical pattern and increase from month to month, with anthe exception forof months with tax or dividendsdividend payments, when the amount is sharply reduced. In the period following tax and dividend payments, the amount of liquid assets will often be significantly reduced. A need for short-term funding will then be triggered for a period until the debt is repaid andrepaid. This is subsequently followed by a new accumulation of liquid assets.

    Short-term funding can be carried out bilaterally through direct borrowing from banks, insurance companies, etc. An alternative is to issue short termshort-term debt securities under one of the existing funding programmes or under documentation established ad hoc. These funding programmes are as follows:

    • A USD 4 billion US commercial paper programme. This is the most flexible programme used for working capital, including timing issues on corporate tax and dividend payments, as well as for periodic acquisition financing.
    • A USD 2 billion committed multi-currency revolving credit facility from international banks, including a USD 500 million swing-line facility. The facility was entered into in 2004, and is available for draw-downs until December 2011. This facility is primarily intended as a "back-up" facility for the US commercial paper programme, and should be regarded as support for the credit rating of this programme.
    • Uncommitted credit lines. Short-termA short-term funding source occasionally required beyondover and above the other short-term programmes and accumulated cash.

    In order to have access to sufficient liquidity at all times, StatoilHydroStatoil defines and continouslycontinuously maintains a minimum liquidity reserve, which comprises unused committed external credit facilities, cash and cash equivalents, and current financial investments, excluding the current portion of the investment portfolio held by the group's captive insurance subsidiary.

    	at 31 December		As at 31 December
    Liquid assets as (in NOK billion)	2008	2007
    Liquid assets (in NOK billion)			2009	2008	2007
    Cash & cash equivalents	18.6	18.3	24.7	18.6	18.3
    Financial investments	9.7	3.3	7.0	9.7	3.3
    Total liquid assets	28.4	21.6	31.7	28.4	21.6

    Funding and liability
    As a basic principle, we separate investment decisions from financing decisions. Funding needs arise as a result of the Group'sgroup's general business activity. The main rule is to establish financing at corporate level. Project financing may be applied in cases involving joint ventures with other companies.

    We aim at all times to maintain access to a variety of funding sources, both in respect of both instruments and geography, and to maintain relationships with a core group of international banks that provide various kinds of banking and funding services.

    We have credit ratings from Moody's and Standard & Poor's and the stated objective is to have a rating at least within the single A category. This rating ensures necessary predictability when it comes to funding access atto favourable terms and conditions. Our current long-term ratings are Aa2 stable outlook and AA- stable outlook from Moody's and Standard & Poor's, respectively. The short-term rating from Moody's is P-1 and A-1+ from Standard & Poor's. We intend to keep financial ratios relating to our debt at levels consistent with our objective of maintaining our long-term credit rating at least within the single A category. To sustain financial flexibility going forward we seek to maintain a credit rating at least within the single A category. In this context we carry out different risk assessments, some of them in line with financial matrixesmatrices used by S&P and Moody's, such as free funds from operations over net debt and net debt to capital employed.

    In order to control our refinancing risk, the maturity and redemption profile of non-current debt issuedwe issue, is managed within certain limitations.limits. The limits are expressed as maximum annual mandatory redemptions as a share of StatoilHydro'sStatoil's capital employed.

    Liquidity forecasts serve as tools for financial planning. In order to maintain necessary financial flexibility, we have requirements for maximum (forecasted) current debt and minimum (forecasted) liquidity reserve. IssuanceThe issuance of long termlong-term debt is used as a tool for reducing current debt and/or increasing the liquidity reserve. New non-current funding will be initiated if liquidity forecasts revealuncover non-compliance with given limits, unless further detailed considerations indicate that the non-compliance is likely to be very temporary. In thissuch case, the situation will be further monitored before additional non-current debt is drawn.

    For further information onabout our debenture bonds, bank loans and other debt portfolio profile, see note 24-Current22 Non-current financial liabilities to our Consolidated Financial Statements in this report.the consolidated financial statements.

    StatoilHydro'sStatoil's dividend policy includes providing a return to our shareholders through cash dividends and share repurchases. The level of cash dividends and share repurchases can fluctuate in any one year, can fluctuate depending on our assessment of future cashflows,cash flows, capital expenditure plans, financing requirements and appropriate financial flexibility. See note 19-Shareholders equitysection 6 Shareholder information section for additional information onabout our dividend policy.

    Credit risk management
    Credit risk is the risk that our customers or counterparties to financial instruments will cause us financial loss by failing to honour their obligations. Credit risk arises from credit exposuresexposure in connection with customer accounts receivablesreceivable as well as from derivatederivative financial instruments and deposits with financial institutions. Theoretically, the group's maximum credit exposure for financial assets is the aggregated balance sheet carrying amounts of financial investments (excluding equity investments of NOK 6.5 billion in 20082009 and NOK 7.56.5 billion in 2007)2008), derivative financial instruments, financial receivables, trade and other receivables, and cash and cash equivalents. The group manages this exposure through its credit risk management policies and procedures.

    The currentrecent financial crisisturmoil has broughtresulted in additional focus on the need for all entities to have robust credit policies withand close monitoring of associated risks. Over the years, we have established a clear credit policy, which has proven especially valuable during this period of widespread financial pressure. The tools we use to manage and monitor credit risk have been tested by the continuing crisis and no significant credit losses have realised forwere experienced by the group during 2008.2008 and 2009.

    Key elements of our credit risk management approach includeinclude:

    • A conservative global credit risk policy
    • Credit mandates
    • Internal credit rating process
    • Credit risk mitigation tools
    • Continuously monitoring and managing credit exposuresexposures.

    Prior to entering into transactions with new counterparties, our credit policy requires all counterparties to be formally identified, approved and assigned internal credit ratings as well as exposure limits. Once established, all counterparties are re-assessed minimumat least annually, with high riskhigh-risk counterparties being reviewed more frequently. The internal credit ratings reflect our assessment of the counterparties' credit risk and are similar to rating categories used by well known credit rating agencies, Standard & Poor's and Moody's. Exposure limits are determined based on the basis of assigned internal credit ratings combined with other factors, such as expected transaction and industry characteristics, as outlined in our credit policy. The mandate for setting credit limits is regularly reviewed with regard to changes in market conditions.

    ThereSeveral instruments are several instruments available to us to reduce or control credit risk, at both on an individual counterparty and portfolio level. The main tools used by StatoilHydroStatoil are variations of bank and parental guarantees, prepayments and cash collateral. For bank guarantees, only highly rated international banks are accepted.

    We manage credit risk at both on a portfolio and counterparty level. We have pre-defined limits regarding the minimum average credit rating allowed at any given time onat the group portfolio level as well as maximum credit exposures for individual counterparties. We monitor the portfolio on a regular basis and individual exposures versus limits on a daily basis. The total credit exposure portfolio of StatoilHydroStatoil is well diversified with respect to the number and quality of counterparties and industries, and geographically. The majorityMost of our credit exposure is typically with investment grade counterparties.

    The following table contains the average credit exposure by counterparty by internal credit rating and includes the rating categoriescategories' share of the group's total exposure:

    The following table contains the fair market value of open non-exchange traded derivative assets splitbroken down by our assessment of the counterparty's credit risk:

    	At 31 December
    Receivables split by counterparty credit rating (in NOK billion)	2009	2008	2007
    Counter-party rated:
    Investment grade, rated A or above	27.7	21.7	19.6
    Other investment grade	16.4	7.1	0.9
    Non-investment grade or not rated	15.0	0.8	0.7

    As of 31 December 2009, counterparties have paid NOK 4.7 billion in cash, which is held by us as collateral to offset a portion of this credit exposure.

    Consistent with our policies, commodity derivative counterparties have been assigned internal credit ratings corresponding to those of their respective parent companies. In cases where the parent company is highly rated, it may not be necessary to seek a parent company guarantee from such a counterparty.

    

    The graph illustrates the magnitude as of 31 December 2009 of our credit risk exposure broken down by our assessment of the counterparties' credit risk. As can be seen from the illustration, most of our credit risk exposure is with counterparties assessed by us as having investment grade credit rating. Our assessment of each counterparty's credit risk is often consistent with the credit ratings published by credit rating agencies but may vary on a case-by-case basis due to differences in the timing and/or the judgments inherent in the specific credit risk assessment. Our assessment of each counterparty's credit risk may also change over time due to changes in company-specific or general conditions.

    The illustration above reflects the credit risk exposure that Statoil has to its counterparties as of 31 December 2009. Credit ratings of such counterparties may be subject to revision or withdrawal at any time in accordance with our internal credit rating policy, and any such change to a counterparty's credit rating may affect Statoil's credit risk exposure.

    As stated above, in accordance with our internal credit rating policy, we reassess counterparty credit risk at least annually and assess counterparties that we identify as high risk more frequently. The internal credit ratings reflect our assessment of the counterparties' credit risk and are similar to rating categories used by well known credit rating agencies, such as Standard & Poor's and Moody's. The mandate for setting credit limit is regularly reviewed with regard to changes in market conditions.

    (in NOK million)		At 31 December
    		2008	2007
    Counter-party rated:
    Investment grade, rated A or above		21,727	19,647
    Other investment grade		7,094	928
    Non-investment grade or not rated		761	689

    As of 31 December 2008, NOK 10.1 billion is held as collateral in the Group to offset a portion of this credit exposure.

    Consistent with our policies, commodity derivative counter-parties have been assigned credit ratings corresponding to those of their respective parent companies. If the parent company is highly rated, it may not be necessary to obtain a parent company guarantee from such a counterparty.

    The graph illustrates the magnitude as per 31 December 2008 of our credit risk exposure sorted by our assessment of the counterparties' credit risk. As can be seen from the illustration, most of our credit risk exposure is with counterparties assessed by us to have investment grade credit rating. Our assessment of each counterparty's credit risk is often consistent with the credit ratings published by credit rating agencies but may vary on a case by case basis due to differences in the timing and or the judgments inherent in the specific credit risk assessment. Our assessment of each counterparty's credit risk may also change over time due to changes in company specific or general conditions.
    

    

    The illustration above reflects the credit risk exposure that StatoilHydro has to its counterparties as 31 December 2008. Credit ratings of such counterparties may be subject to revision or withdrawal at any time in accordance with our internal credit rating policy, and any such change to a counterparty's credit rating may affect StatoilHydro's credit risk exposure.

     Top 

    5.2.2 Quantitative and qualitative disclosuresDisclosures about market risk

    StatoilHydro

    Statoil uses financial instruments to manage commodity price risks, interest rate risks, currency risks and liquidty and funding risks, and significant amounts of assets and liabilities are accounted for as financial instruments.

    See note 2930 Financial instruments by category to the Consolidated Financial Statementsfinancial statements for details onof the nature and extent of such positions, and note 3031 Financial instruments measurement and hedgingmarket risk sensitivities for qualitative and quantitative disclosures of the risks associated with these instruments.

     Top 

    5.3 Legal proceedings

    We are involved in a number of judicial, regulatory and arbitration proceedings concerning matters arising in connection with the conductingconduct of our business.

    Except as set forth below, we are currently not aware of any legal proceedings or claims that we believe could, individually or in the aggregate, have significant effects on our financial position or profitability or on the results of our operations or liquidity.

    The AFT case
    StatoilHydroStatoil ASA issued a declaration to the Norwegian Ministry of Petroleum and Energy (MPE) in 1999 in connection with a dispute between four Åsgard partners and StatoilHydroStatoil related to the construction of new facilities for the Åsgard development at the Kårstø Terminal. The declaration confirmed that the MPE will receive similar treatment as the four Åsgard partners with respect to the disputed issues. On the basis of the declaration, the MPE alleged the right to compensation and initiated legal proceedings against Statoil on 29 April 2008 issuedin a writ involving a multi-component compensation claim, theclaim. The aggregate principal exposure of which for StatoilHydro approximatesthe claim was estimated to be between NOK 4 and 7 billion after tax. Following a verdict in Stavanger district court on 15 January 2010, Statoil and the MPE on 5 March 2010 reached an amicable settlement of the case pursuant to which both parties waived their rights to appeal the court verdict. Under the terms of the settlement, Statoil has agreed to pay t he MPE a cash compensation of NOK 500 million after tax, and NOK 375 million in pre-tax interest, corresponding to NOK 270 million after tax.

    During the fourth quarter of 2008, ExxonMobil, the final Åsgard partner at the time of the original dispute, has issued a similar writ with a compensation claim approximating an estimated exposure of up to NOK 1 billion after tax. StatoilHydro rejects both claims.The dispute with ExxonMobil was settled in October 2009, and the impact of this settlement on the consolidated financial statements was not material.

    The Libya case
    StatoilHydroStatoil was informed on 26 September 2007 ofabout possible consultancy agreements and transactions associated with Hydro's petroleum activities in Libya, which were transferred to StatoilHydroStatoil as of 1 October 2007 as part of the merger with Hydro's petroleum business, and which could be in conflict with applicable Norwegian and US anti-corruption legislation. Following a preliminary assessment by StatoilHydro,Statoil, an external review was initiated of the relevant aspects was initiated.aspects. The external US and Norwegian legal counsels that have conducted the review deliveredsubmitted their report to StatoilHydroStatoil ASA's CEO on 6 October 2008. The report has also been deliveredsubmitted to the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim), the US Department of Justice, the US Securites and Exchange Commission and the Libyan authorities. The report does not draw any legal conclusions and inconclusions. In accordance with the mandate for the review, only entailsthe report sets out the facts relevant to appli cable Norwegianapplicable Norw egian and US anti-corruption legislation to which StatoilHydroStatoil ASA may be subject as a result of the merger. On 15 May 2009, Økokrim announced it would not open an investigation related to the international activites of the former Hydro Oil & Energy. Neither the US authorities nor the Libyan authorities have initiated any actions or proceedings in relation to the matters described in the investigation reports.

     Top 

    6 Shareholder information

    StatoilHydro

    Statoil is the largest company listed on the Oslo stock exchange (Oslo Børs),Stock Exchange, where it trades under the ticker code STL. Statoil is also listed on New York Stock Exchange under the ticker code STO.

    Statoil share	2009	2008	2007	2006	2005
    Share price STL high (NOK)	146.80	214.10	191.50	210.50	166.50
    Share price STL low (NOK)	108.90	96.40	151.50	147.25	91.25
    Share price STL average (NOK)	129.50	153.60	169.70	174.25	130.60
    Share price STL year-end (NOK)	144.80	113.90	169.00	165.25	155.00
    Market value year-end (NOK billion)	462	363	539	358	336
    Daily turnover (million shares)	9.6	13.5	16.5	12.6	10.1
    Ordinary and diluted earnings per share (EPS) (NOK) 1)	5.75	13.58	13.80	15.82	14.19
    P/E 1) 2)	25.18	8.39	12.25	10.45	10.92
    Total dividend per share (NOK) 3)	6.00	7.25	8.50	9.12	8.20
    Ordinary dividend per share (NOK) 3)	6.00	4.40	4.20	4.00	3.60
    Special dividend per share (NOK)	0.00	2.85	4.30	5.12	4.60
    Growth in ordinary dividend per share 4)	36.4 %	4.8 %	5.0 %	11.1 %	12.5 %
    Growth in total dividend per share	-17.2 %	-14.7 %	-6.8 %	11.2 %	54.7 %
    Total dividend per share (USD) 5)	1.04	1.26	1.47	1.58	1.42
    Pay-out ratio 6)	104%	53%	61%	57%	58%
    Dividend yield 7)	4.1 %	6.4 %	5.0 %	5.5 %	5.3 %
    Net interest bearing debt to capital employed 1)	27.3%	17.5%	12.4%	20.5 %	15.1 %
    Ordinary shares outstanding, weighted average	3,183,873,643	3,185,953,538	3,195,866,843	3,230,849,707	2,165,740,054
    Ordinary shares outstanding, year-end	3,188,647,103	3,188,647,103	3,188,647,103	3,208,800,400	2,189,585,600
    1) Figures for 2005 are USGAAP, only former Statoil figures.
    2) Share price at year-end divided by EPS.
    3) Proposed cash dividend for 2009.
    4) Excluding special dividend and share buy-back.
    5) The USD amounts are based on the Norwegian Central Bank's exchange rate at 31 December 2009.
    6) Total dividend paid per share divided by EPS. Total capital distribution in 2006 is 67%, including share buy-back of NOK 1.55 per share in 2006.
    7) Total dividend paid per share divided by year-end share price.

    

    			2008	2007	2006	2005	2004
    Share price STL high (NOK)			214.10	191.50	210.50	166.50	103.50
    Share price STL low (NOK)			96.40	151.50	147.25	91.25	74.00
    Share price STL year-end (NOK)			113.90	169.00	165.25	155.00	95.00
    Market value year-end (NOK billion)			363	539	358	336	206
    Daily turnover (million shares)			13.5	16.5	12.6	10.1	6.7
    Ordinary and diluted earnings per share (EPS) (NOK) 1)			13.58	13.80	15.82	14.19	11.50
    P/E 1) 2)			8.39	12.25	10.45	10.92	8.26
    Dividend paid per share (NOK) 3)			7.25	8.50	9.12	8.20	5.30
    Pay-out ratio 4)			53%	61%	57%	58%	46%
    Dividend yield 5)			6.4 %	5.0 %	5.5 %	5.3 %	5.6 %
    Net debt to capital employed 1) 6)			17.5%	12.4%	20.5 %	15.1 %	18.9 %
    Ordinary shares outstanding, weighted average			3,185,953,538	3,195,866,843	3,230,849,707	2,165,740,054	2,166,142,636
    Ordinary shares outstanding, year-end			3,188,647,103	3,188,647,103	3,208,800,400	2,189,585,600	2,189,585,600
    1) Figures for 2004 and 2005 are USGAAP, only former Statoil figures.
    2) Share price at year-end divided by EPS.
    3) Proposed dividend for 2008. Including ordinary and special dividend.
    4) Dividend paid per share divided by EPS. Total capital distribution in 2006 is 67%, including share buy-back of NOK 1.55 per share in 2006.
    5) Dividend paid per share divided by year-end share price.
    6) The relationship between net interest-bearing debt and capital employed.

    As of 31 December 2009, Statoil represented 31% of the total value of all companies registered on the Oslo Stock Exchange, with a market value of NOK 462 billion.

    Statoil's share price closed at NOK 144.80 at the end of 2009. Taking into consideration the dividend of NOK 7.25 per share paid in 2009, the total return was NOK 38.15 or 33%. Quote history shows the development of the Statoil share price compared with the oil price and the Oslo Stock Exchange Benchmark Index (OSEBX).The board of directors proposes a dividend of NOK 6.00 per share for 2009, for approval by the annual general meeting on 19 May 2010. The NOK 6.00 dividend per share it is proposed to distribute to our shareholders is equivalent to a direct yield of approximately 4.1%, and we will distribute 104% of net income from 2009. Net income per share amounted to NOK 5.75 in 2009, a decrease of 57.7% compared with 2008.

    

    Turnover of shares is a measure of traded volumes. On average, 13.59.6 million StatoilHydroStatoil shares were traded on the Oslo BørsStock Exchange every day in 2008,2009, a decrease of 18%29% on the previous year. StatoilHydroStatoil shares accounted for 21.1%22% of the total market value traded throughout the year (see illustration).
     

    

    

    As of 31 December 2008, StatoilHydro represented 36% of the total value of all companies registered on the Oslo Børs, with a market value of NOK 363 billion.

    The group's share price decreased from NOK 169.00 at the end of 2007 to NOK 113.9 at the end of 2008. The Board of Directors proposes an ordinary dividend of NOK 4.40 per share for 2008, as well as NOK 2.85 per share as special dividend for approval by the Annual General Meeting on 19 May 2009. The total dividend of NOK 7.25 per share proposed to be distributed to our shareholders is equivalent to a direct yield of approximately 6.4%, and we will distribute 53% of net income from 2008. Net income per share amounted to NOK 13.58 in 2008, a decrease of 1.6% compared to 2007.

    StatoilHydroStatoil ASA hashad 3,188,647,103 ordinary shares outstanding at year end. StatoilHydroStatoil ASA has one class of shares, and each share confers one vote at the general meeting.

    On average, 13.5 million StatoilHydro shares were traded on the Oslo Børs every day in 2008, a decrease of 18% on the previous year. StatoilHydro shares accounted for 21.1% of the total market value traded throughout the year (see illustration).

    As of 31 December 2008, StatoilHydro2009, Statoil had approximately 103,400103,900 shareholders registered in the Norwegian Central Securities Depository (VPS), an increase corresponding to 6% onwhich is virtually unchanged from 103,400 shareholders the year before. There is no duty to register as an ADR-holder in the USA, and the actual number of registered ADR holders as of 31 December 2009 was 719, while the number of beneficial holders is not known. Dividend for 2008 was paid to approximately 113,000 beneficiaries in the USA according to the records of The Bank of New York Mellon. The number of American Depositary Receipts traded on the New York Stock Exchange decreased by 4%28% during the course of the year.year to 61.3 million shares at the end of 2009.

     Top 

    6.1 Dividend policy

    Our

    The board of directors has decided to adjust the company's dividend policy reflects our ambitionin order to return an amount in the range of 45 to 50% of consolidated net income pursuant to IFRS to our shareholders, through cash dividends and share repurchases.

    create a more predictable dividend level going forward.

    It is StatoilHydro'sStatoil's ambition to grow the ordinaryannual cash dividend, measured in NOK per share. Furthermore, it is StatoilHydro's intention to return to it shareholders, through cash dividends and share, repurchases, an amount in line with long-term underlying earnings. When deciding the range of 45 to 50 percent of consolidated net income as determined in accordance with IFRS. In any one year, however,annual dividend level, the aggregate of cash dividends and share repurchases may be higher or lower than 45 to 50 percent of net income, depending on the company's evaluation ofBoard will take into consideration expected cash flow, capital expenditure plans, financing requirements and appropriate financial flexibility.
    
    For more information

    In addition to cash dividend, Statoil might buy back shares as part of its total distribution of capital to the shareholders.

    The direct link to the IFRS net income has been removed, and the focus will be on growing the purchaseannual cash dividend per share in line with long-term underlying earnings. The new policy does not entail a change in the long-term dividend level, including potential share buy-backs, compared with the previous policy. The Board emphasises the importance of StatoilHydro shares, seealso maintaining an attractive dividend level in the report section 6.2 Shareholder information-Equity securities purchased by issuer.future.

     Top 

    6.1.1 Dividends

    Dividends for a fiscal year are declared at our annual general meeting in the following year. The Norwegian Public Limited Companies Act forms the legal framework for dividend payments.

    Under this Act, dividends may only be paid in respect of a financial period as tofor 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.

    We can only distribute dividends (1) if our equity, based on StatoilHydro ASAStatoil ASA's unconsolidated balance sheet, amounts to 10% or highermore of the total assets reflected onin our unconsolidated balance sheet without following a creditor notice procedure as required for reducing the share capital, (2) to the extent compatible with good and careful business practice with due regard to any losses whichthat we may have incurred after the last balance sheet date or whichthat we may expect to incur, and (3) provided that the dividend to be distributed is calculated on the basis of our unconsolidated financial statements.

    Although we currently intend to pay annual dividends on our ordinary shares, we cannot assure 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.

    The following table shows the cash dividend amounts paid to all shareholders since 2006 on a per share basis and in the aggregate, as well as cash dividendsdividend proposed by our board of directors to be paid in 20092010 on our ordinary shares for the fiscal year 2008.2009.

    In 2006, 2007, and 2008, the total dividend per share represented an ordinary dividend and a special dividend. The total cash dividend per share proposed by the boardconsisted of directors for 2009 also includes an ordinary dividend and a special dividend. The special dividends paid in these years are the result of increased annual net income due to higher realizedrealised oil and gas prices. There is no guarantee that special dividends

    		Per ordinary share  1)
    		Ordinary	Special	Total
    		dividend	dividend	dividend	Total
    Year		NOK	NOK	NOK	NOK billion
    2005		3.60	4.60	8.20	17.8
    2006		4.00	5.12	9.12	19.7
    2007		4.20	4.30	8.50	27.1
    2008		4.40	2.85	7.25	23.1
    2009		6.00	0.00	6.00	19.1
    1)  For fiscal years 2008, 2007, 2006 and 2005 the total dividend per share consisted of an ordinary dividend and a special dividend.
    The 2009 dividend will be paid on 2 June 2010.

    The proposed dividend for 2009 will be paid inconsidered by the future, even if higher oilannual general meeting on 19 May 2010. The Statoil share will be traded ex-dividend from 20 May 2010, and gas prices are sustained over time.
     the approved dividend will be disbursed on 2 June 2010.

    	Per ordinary share¹
    	Ordinary dividend	Special dividend	Total dividend	Total
    Year	NOK	NOK	NOK	Billion NOK
    2004	3.20	2.10	5.30	11.5
    2005	3.60	4.60	8.20	17.8
    2006	4.00	5.12	9.12	19.7
    2007	4.20	4.30	8.50	27.1
    2008	4.40	2.85	7.25	23.1
    (1)	For fiscal years 2008, 2007, 2006, 2005, and 2004 the total dividend per share consisted of an ordinary dividend and a special dividend. The 2008 dividend is expected to be paid in the end of May 2009.

    Since we will only pay dividends in Norwegian kroner (NOK), exchange rate fluctuations will affect the US dollar amounts in USD received by holders of ADSsADRs after the ADR depositary converts cash dividends into USD. The dividend will be made availabe to the depository on 2 June 2010. The depository will convert the dividend into USD at the prevailing exchange rate for NOK and pay the US dollars.ADR holders the USD equivalent of the dividend in NOK, minus prevailing bank charges. The payment date for dividend in USD to US ADR holders is expected to be 14 June 2010.

    Share repurchases
    In addition to a cash dividend, Statoil might buy back shares as part of its total distribution of capital to its shareholders. For the period 2008-20092009-2010, the board of directors did not requestask the Annual General Meeting in StatoilHydroannual general meeting of Statoil for an authorisation to repurchase StatoilHydroStatoil shares in the market for subsequent cancellation, and StatoilHydro therefore did not buy any shares for cancellation in 2008.annulment. We did not undertake any share repurchases in 20082009 and 2007,2008, and no shares were acquired in the market for subsequent cancellation. In 2006, a number of 20,158,848 shares were repurchased totallingfor the total amount of NOK 3.3 billion.

    There is no guarantee that share repurchases will continue in the future. Future share repurchases will depend on the authorisation of our shareholders, as well as a number of factors prevailing at the time our board of directors considers any share repurchase.

     Top 

    6.2 Equity securities purchased by issuer

    Shares are acquired in the market for transfer to employees under the share savings scheme in accordance with the limits set by the board. However, no shares were repurchased in the market for the purpose of subsequent cancellation in 2009.

     Top 

    6.2.1 StatoilHydroStatoil share savings plan

    Since 2004, Statoil subsequently StatoilHydro, has had a share savings plan for all employees of the group. The purpose of this plan is to strengthen the business culture and encourage loyalty through employees becoming part-owners of the company.

    Through regular salary deductions, employees can invest for an amount up to 5% of their basicbase salary in StatoilHydroStatoil shares. In addition, the company contributes with 20% of the amount, up to a maximum of NOK 1500.1,500 per year (approximately USD 250). This company contribution is a tax freetax-free employee benefit under the current Norwegian tax legislation. After a lock-in period of two calendar years, one extra share will be awarded for each share purchased. TheUnder current Norwegian tax legislation, the share award is a taxable employee benefit, with a value equal to the value of the shares and taxed at the time of the award, under the current Norwegian tax legislation.award. Shares transferred to employees are acquired by the company in the market.

    The board decides the manner in which the acquisition of StatoilHydrodirectors is authorised to acquire Statoil shares in the market takes place.on behalf of the company. The authorisation can be used to acquire own shares for a total nominal value of up to NOK 15 million. Shares acquired in accordance with thepursuant to this authorisation may only be used for sale and transfer to employees of the StatoilHydroStatoil group as part of the group's share investment plansaving scheme, as approved by the board.board of directors. The minimum and maximum amountamounts that may be paid per share will beare NOK 50 and NOK 500, respectively. Within these limits, the board of directors maycan freely decide when to acquire shares, are acquired, although the purchases follow a fixed plan for one year at a time.

    The authorisation was last renewed by the annual general meeting on 2019 May 20082009 and is valid until the next annual general meeting.meeting, but not beyond 30 June 2010. This authorisation replaces the previous authorisation to acquire own shares for implementation of the share saving scheme for employees granted by the annual general meeting on 20 May 2008.

    The nominal value of each share is NOK 2.50. AtWith a maximum overall nominal value of NOK 15 million, the authorisation for the repurchase of shares in connection with the group's share savings plan covers the repurchase of no more than six million shares.

    Share savings plan

    Period in which shares where repurchased	Number of shares repurchased		Average price per share in NOK		Total number of shares purchased as part of program (1)	Maximum number of shares that may yet be purchased under the program authorisation (1)
    January 2008	364,000		146.15		2,088,300	3,911,700
    February 2008	347,000		153.30		2,435,300	3,564,700
    March 2008	341,000		156.23		2,776,300	3,223,700
    April 2008	315,012		168.10		3,091,312	2,908,688
    May 2008	265,000		198.49		3,356,312	2,643,688
    June 2008	269,850		195.67		269,850	5,730,150
    July 2008	313,000		169.66		582,850	5,417,150
    August 2008	340,000		154.75		922,850	5,077,150
    September 2008	381,574		138.95		1,304,424	4,695,576
    October 2008	453,000		118.89		1,757,424	4,242,576
    November 2008	467,100		117.78		2,224,524	3,775,476
    December 2008	598,000		107.84		2,822,524	3,177,476
    January 2009	521,800		116.64		3,344,324	2,655,676
    February 2009	494,500		123.08		3,838,824	2,161,176
    Total	5,470,836	(2)	141.08	(3)	3,838,824	2,161,176
    (1) The authorisation to repurchase a maximum of six million shares with a maximum overall nominal value of NOK 15 million for repurchase of shares in
    connection with the group's share investment plan was given by the annual general meeting on 15 May 2007. The authorisation was renewed by the
    annual general meeting on 20 May 2008 maintaining a maximum of six million shares with a maximum overall nominal value of 15 million for repurcase
    of shares, and valid until June 2009.
    (2) All shares repurchased have been purchased in the open market and pursuant to the authorisation mentioned above.
    (3) Weighted average price per share.

    Period in which shares where repurchased	Number of shares repurchased		Average price per share in NOK		Total number of shares purchased as part of program (1)	Maximum number of shares that may yet be purchased under the program authorisation (1)
    January 2009	521,800		116.64		3,344,324	2,655,676
    February 2009	494,500		123.08		3,838,824	2,161,176
    March 2009	520,400		117.45		4,359,224	1,640,776
    April 2009	521,600		116.88		4,880,824	1,119,176
    May 2009	460,100		132.96		5,340,924	659,076
    June 2009	450,400		136.58		450,400	5,549,600
    July 2009	492,000		125.10		942,400	5,057,600
    August 2009	461,000		133.83		1,403,400	4,596,600
    September 2009	469,800		131.88		1,873,200	4,126,800
    October 2009	453,700		137.31		2,326,900	3,673,100
    November 2009	444,900		141.88		2,771,800	3,228,200
    December 2009	454,000		139.89		3,225,800	2,774,200
    January 2010	452,500		147.11		3,678,300	2,321,700
    February 2010	519,000		128.88		4,197,300	1,802,700
    Total	6,715,700	(2)	130.16	(3)	4,197,300	1,802,700
    (1) The authorisation to repurchase a maximum of six million shares with a maximum overall nominal value of NOK 15 million for repurchase of shares in
    connection with the share savings plan was given by the annual general meeting on 20 May 2008. The authorisation was renewed by the
    annual general meeting on 19 May 2009 maintaining a maximum of six million shares with a maximum overall nominal value of 15 million for repurcase
    of shares, and valid until 30 June 2010.
    (2) All shares repurchased have been purchased in the open market and pursuant to the authorisation mentioned above.
    (3) Weighted average price per share.

     

     Top 

    6.2.2 Purchase of shares for cancellation

    The Board did not request the General Meeting in StatoilHydro for an authorisation to repurchase StatoilHydro shares in the market for subsequent cancellation in the period 2008-2009.

    This was due to the Norwegian government's stated intention to increase its ownership interest in StatoilHydro from 62.5% to 67%. As of 5 March 2009, the Norwegian State owns a 66.89% interest in StatoilHydro and a 3.94% through Folketrygdfondet, total 70.83% interest in StatoilHydro. Now that the Government has reached its stated intended ownership share, the Board may ask the General Meeting for a new share repurchase authorisation.

    In 2007, the annual general meeting of Statoil authorised the board of directors to acquire Statoil shares in the market for subsequent cancellation. This authorisation was valid until 20 May 2008. StatoilHydro did not make use of this authorisation in 2007 or 2008.

    In accordance with the resolution of the extraordinary general meeting on 5 July 2007 and with the authorisation to repurchase shares granted by the annual general meeting on 10 May 2006, Statoil carried out a capital reduction in September 2007 through the redemption and cancellation of a total of 20,158,848 shares with a nominal value of NOK 2.50 per share, of which 14,291,848 shares were redeemed from the Norwegian State, represented by the Ministry of Petroleum and Energy, and canceled.

     Top 

    6.3 Information and communications

    Keeping the market updated about StatoilHydro'sStatoil's financial performance and future prospects is important to us.

    the basis for assessing the value of the company.

    Information provided to the stock market must be transparent and ensure equal treatment, and it must aim to provide shareholders with correct, clear, relevant and timely information that forms athe basis for assessing the value of the company.

    The StatoilHydroStatoil share is listed on the stock exchanges in Oslo and New York, and the company distributes its share price sensitiveprice-sensitive information through the international wire services, the Oslo Stock Exchange in Norway, the Securities and Exchange Commission in the US,USA, and the companycompany's website.

    Our registrar manages our shares listed on the Oslo stock exchangeStock Exchange on our behalf and provides the connection to the Norwegian Central Securities Depository (VPS). Major services provided by the registrar are investor services for private shareholders, the disbursement of dividend and assistance at our general meetings. The DnB NOR bank is currently account registrar for StatoilHydro.Statoil.

     Top 

    6.3.1Investor6.3.1 Investor contact

    Our investor relations staff function (IR) coordinates the dialogue with our shareholders.

    We place great emphasis on ensuring that relevant and timely information is distributed to the capital markets. Given the size and diversity of our shareholder base, the opportunities for direct shareholder interaction are limited to a certain extent. Our investor relations"Investor Centre" web pages are therefore specially designed for investors and analysts who wish to follow the company's progress - http://www.statoilhydro.com/www.statoil.com/ir

    Our quarterly presentations and other relevant presentations by management are broadcastedbroadcast directly on the internet, and the pertaining reports are made available together with other relevant information on the company's website.

    StatoilHydroStatoil meets the requirements for the information symbol and English symbol issued by Oslo Stock Exchange (Oslo Børs.rs).

    
     

    Ticker Codes

    Oslo BørsStock Exchange STL
    New York Stock Exchange STO
    Reuters STL.OL
    Bloomberg STL NO

    Financial calendar for 2010
    11 February	Fourth quarter results 2009 and strategy update
    26 March	Annual report 2009
    05 May	First quarter 2010
    19 May	Annual general meeting 2010
    20 May	Share trading ex-dividend
    02 June	Dividend payment
    29 July	Second quarter 2010
    03 November	Third quarter 2010

     Top 

    6.4 Major shareholders

    The Norwegian State is the largest shareholder in StatoilHydro.Statoil, with an ownership interest of 67%. Its ownership interest is managed by the Ministry of Petroleum and Energy.

    Statoil was partially privatised and listed on the stock exchange on 18 June 2001, when it became a public limited company. After the initial offering, the government retained 81.7% of the Statoil shares. From 2005 and prior to the merger with Hydro's oil and energy activities in 2007, the Norwegian stateState owned 70.9% of the shares in Statoil.

    Pursuant to the agreed exchange ratio as part ofagreed in connection with the merger with Hydro's oil and gas activities, the State's ownership interest in StatoilHydrothe merged company was 62.5%, or 1,992,959,739 shares on 1 October 2007. In accordance with the Storting's decision of 2001 concerning a minimum state shareholding of two-thirds in Statoil, the Government expressed its intention to increase the state's shareholding in StatoilHydro over time to 67%. During 2008 the Government has built up the State's ownership interest in StatoilHydroStatoil by buying shares in the market. On 31 Decembermarket during the period from June 2008 the State's ownership interest in StatoilHydro was 66.42%, or 2,117,961,391 shares. On 5to March 2009. In March 2009, the Government announced that the State's ownership interest hashad reached 67%, and the Government's purchase of StatoilHydroStatoil shares was completed by acquiring 143.3 million shares for a combined NOK 19.3 billion since 2 June 2008.completed. As of 12 March 20092010, the Norwegian State had a 67% ownership interest in StatoilHydroStatoil and 3.94%3.13% interest through F olketrygdfondet,Folketrygdfondet, totalling to 70.94%70.13%.

     

    

    As of 12 March 2008,2010, the National Insurance Fund, (Folketrygdfondet) owned 125,688,10099,922,060 shares, or 3.94%3.13% of the total number of ordinary shares. The Norwegian State is the only person or entity known to us to own beneficially, directly or indirectly more than 5% of our outstanding shares. We have not been notified of any other beneficial owner of 5% or more of our ordinary shares as of 612 March 2009.2010.

    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 Mellon (formerly known as 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 Mellon that in the United States, as of 612 March 2009,2010, there were 75,227,15060,900,828 ADRs outstanding in the United States (representing approximately 2.36%1.9% of the ordinary shares outstanding). As of 612 March 20092010, there were 724719 registered holders of ADRs resident in the United States and 293,178,809 ordinary279,447,057ordinary shares were held by 546514 registered holders resident in the United States representing approximately 9%8.8% in total.

    StatoilHydroStatoil has one class of shares, and each share confers one vote at the general meeting. The Norwegian State does not have any different voting rights that differ from the rights of other ordinary shareholders. Pursuant to the Norwegian Public Limited Liability Companies Act, a majority of more than two-thirds of the votes cast as well as of the votes represented at a general meeting is required 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.

    Since the Norwegian State, acting through the Minister of Petroleum and Energy, has increased its holding in excess of two-thirds of the shares in the company, it has the sole power to amend 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 Boardboard of Directorsdirectors and approve the dividend proposal by the Boardboard of Directors.directors.

    The Norwegian State endorses the principles set out in "The Norwegian Code of Practice for Corporate Governance", and it has stated that it expects companies in which the State has ownership interests to adhere to the code. The principle of ensuring equal treatment of different groups of shareholders is a key element in the State's own guidelines. In companies in which the State is a shareholder together with others, the State wishes to exercise the same rights and obligations as any other shareholder and not act in a manner that has a detrimental effect on the rights or financial interests of other shareholders. In addition to the principle of equal treatment of shareholders, emphasis is also placed on transparency in relation to the State's ownership and on the general meeting being the correct arena for owner decisions and formal resolutions.

    Shareholders at 6 March 2009					Type	Number of shares	Ownership in %
    Shareholders at 12 March 2010								Type	Number of shares	Ownership in %
    The Norwegian State (Ministry of Petroleum and Energy)	The Norwegian State (Ministry of Petroleum and Energy)					2,132,829,691	66.89		2,136,393,559	67.00
    Folketrygdfondet (Norwegian national insurance fund)	Folketrygdfondet (Norwegian national insurance fund)					125,738,100	3.94		99,922,060	3.13
    Bank of New York ADR Department	Bank of New York ADR Department				Nominee	70,014,750	2.20	Nominee	59,422,950	1.86
    State Street Bank					Nominee	47,552,749	1.49
    Clearstream Banking	Clearstream Banking				Nominee	43,111,702	1.35	Nominee	43,650,052	1.37
    State Street Bank	State Street Bank				Nominee	42,652,342	1.34	Nominee	42,408,969	1.33
    JPMorgan Chase Bank	JPMorgan Chase Bank				Nominee	36,231,346	1.14	Nominee	40,485,140	1.27
    State Street Bank								Nominee	29,164,652	0.91
    State Street Bank								Nominee	24,777,757	0.78
    The Northern Trust								Nominee	23,865,000	0.75
    Bank of New York Mellon	Bank of New York Mellon				Nominee	27,041,941	0.85	Nominee	20,242,707	0.63
    The Northern Trust					Nominee	17,020,750	0.53
    JPMorgan Chase Bank					Nominee	16,881,926	0.53
    Bank of New York Mellon					Nominee	16,025,000	0.50
    The Northern Trust					Nominee	15,532,513	0.49
    Investors Bank					Nominee	14,343,718	0.45
    The Northern Trust					Nominee	13,205,834	0.41
    State Street Bank								Nominee	15,094,135	0.47
    DnB NOR Bank ASA	DnB NOR Bank ASA					10,650,794	0.33		14,300,885	0.45
    The Northern Trust	The Northern Trust				Nominee	9,498,114	0.30	Nominee	12,198,941	0.38
    Svenska Handelsbanken					Nominee	8,685,780	0.27
    Skandinaviska Enskilda Bank								Nominee	11,922,115	0.37
    Vital Forsikring ASA									11,841,626	0.37
    The Northern Trust								Nominee	11,077,896	0.35
    Bank of New York Mellon								Nominee	10,739,642	0.34
    State Street Bank	State Street Bank				Nominee	8,001,335	0.25	Nominee	10,682,635	0.34
    DNB NOR Norge						7,884,240	0.25
    RBC Dexia Investors					Nominee	7,746,317	0.24
    Euroclear Bank								Nominee	9,661,453	0.30
    DnB NOR, Norge VPF									9,410,930	0.30
    Source: Norwegian Central Securities Depository (VPS)	Source: Norwegian Central Securities Depository (VPS)

     

     Top 

    6.5 Market and market prices

    The principal trading market for our ordinary shares is the Oslo stock exchange on whichStock Exchange, and the shares have been listed since our initial public offering on 18 June 2001.

    The ordinary shares are also listed on the New York Stock Exchange, trading in the form of American Depositary Shares (ADSs),.

    Statoil's shares have been listed on the Oslo Stock Exchange since our initial public offering on 18 June 2001. The ADSs trading on the New York Stock Exchange are evidenced by American Depositary Receipts (ADRs). Each, and each ADS represents one ordinary share. StatoilHydroStatoil has a sponsored ADR facility with the Bank of New York Mellon as Depositary.depositary.

    For the periods indicated, the following tables show

     Top 

    6.5.1 Share prices

    These are the reported high and low quotations at market closing for the ordinary shares on the Oslo Børs, asand New York stock exchanges for the periods indicated.

    They are derived from itsthe Oslo Stock Exchange Daily Official List, and the highest and lowest sales prices of the ADSs as reported on the New York Stock Exchange composite tape.

    			NOK per ordinary share			USD per ADS
    Share price			High	Low		High	Low
    Year ended 31 December
    2004			103.50	74.00		15.93	10.85
    2005			166.50	91.25		25.80	14.69
    2006			210.50	147.25		34.52	22.39
    2007			191.50	151.50		35.19	23.90
    2008			214.10	96.40		42.47	13.37
    Quarter ended
    31 March 2007			167.50	151.50		28.00	23.90
    30 June 2007			183.50	162.25		31.03	26.01
    30 September 2007			191.50	153.00		34.93	25.53
    31 December 2007			187.00	159.90		35.19	28.77
    31 March 2008			169.90	135.30		31.76	25.30
    30 June 2008			214.10	155.00		42.47	30.35
    30 September 2008			187.10	130.60		36.95	21.85
    31 December 2008			144.80	96.40		23.06	13.37
    March up until 6 March 2009			131.00	108.90		18.64	15.11
    Month of
    September 2008			160.30	130.60		27.67	21.85
    October 2008			135.00	104.50		23.06	15.72
    November 2008			144.80	102.00		22.00	13.37
    December 2008			116.60	96.40		17.13	13.93
    January 2009			131.00	113.00		18.64	15.72
    February 2009			123.70	112.90		18.31	16.01
    March up until 6 March 2009			117.30	108.90		16.51	15.11

    	NOK per ordinary share		USD per ADS
    Share price	High	Low	High	Low
    Year ended 31 December
    2005	166.50	91.25	25.80	14.69
    2006	210.50	147.25	34.52	22.39
    2007	191.50	151.50	35.19	23.90
    2008	214.10	96.40	42.47	13.37
    2009	146.80	108.90	26.41	15.11
    Quarter ended
    31 March 2008	169.90	135.30	31.76	25.30
    30 June 2008	214.10	155.00	42.47	30.35
    30 September 2008	187.10	130.60	36.95	21.85
    31 December 2008	144.80	96.40	23.06	13.37
    31 March 2009	131.00	108.90	20.09	15.11
    30 June 2009	140.70	113.80	22.19	17.01
    30 September 2009	137.90	119.40	23.20	18.26
    31 December 2009	146.80	126.00	26.41	21.69
    March up until 12 March 2010	149.20	126.90	26.47	21.57
    Month of
    September 2009	135.40	128.30	23.20	21.19
    October 2009	141.50	126.00	25.45	21.69
    November 2009	146.80	135.70	26.41	23.69
    December 2009	146.50	140.00	25.44	24.18
    January 2010	149.20	134.00	26.47	22.36
    February 2010	137.00	126.90	23.55	21.57
    March up until 12 March 2010	139.50	134.50	23.70	22.75

     Top 

    6.5.2 Fees related to Statoil's ADR program

    Fees and charges payable by a Holder of ADSs

    The Bank of New York Mellon, as Depositary, collects its fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the amounts distributed or by selling a portion of distributable property to pay the fees. The Depositary may generally refuse to provide fee-attracting services until its fees for those services are paid.

    The charges of the Depositary payable by investors are as follows:

    Persons depositing or withdrawing shares must pay:	For:
    USD 5.00 (or less) per 100 ADSs (or portion of 100 ADSs)	Issuance of ADSs, including issuances resulting from a distribution of shares or rights or other property
    	Cancellation of ADSs for the purpose of withdrawal, including if the deposit agreement terminates
    USD 0.02 (or less) per ADS	Any cash distribution to ADS registered holders
    A fee equivalent to the fee that would be payable if securities distributed to you had been shares and the shares had been deposited for issuance of ADSs	Distribution of securities distributed to holders of deposited securities which are distributed by the Depositary to ADS registered holders
    Registration or transfer fees	Transfer and registration of shares on our share register to or from the name of the Depositary or its agent when you deposit or withdraw shares
    Expenses of the Depositary	Cable, telex and facsimile transmissions (as provided in the deposit agreement)
    	Converting foreign currency to U.S. dollars
    Taxes and other governmental charges the Depositary or the custodian have to pay on any ADS or share underlying an ADS, for example, stock transfer taxes, stamp duty or withholding taxes	As necessary
    Any charges incurred by the Depositary or its agents for servicing the deposited securities	As necessary

    Reimbursements and payments made and fee waivers granted by the Depositary
    The Depositary has agreed to reimburse certain Company expenses related to the Company's ADR program and incurred by the Company in connection with the program. In the year ended 31 December 2009, the Depositary reimbursed USD 1,595,055 to the Company.

    The table below sets forth the types of expenses that the Depositary has agreed to reimburse and the amounts reimbursed in the year ended 31 December 2009:

    Category of Expenses	USD Amount Reimbursed for the year ended 31 December 2009
    NYSE listing fees	106,382
    US investor relations expenses and other miscellaneous expenses	1,488,673
    Total Amount Reimbursed	1,595,055
    * Net of withholding tax paid by the Depository.

    The Depositary has also agreed to waive fees for standard costs associated with the administration of the ADR program and has paid certain expenses directly to third parties on behalf of the Company. The expenses paid to third parties include expenses relating to the mailing of notices and meeting material as well as the tabulate of votes in connection with the Company's annual general meeting.

    The table below sets forth the expenses that the Depositary waived or paid directly to third parties in the year ended 31 December 2009:

    Category of Expenses	USD Amount Waived or Paid for the year ended 31 December 2009
    Third-party expenses paid directly by the Depositary	147,030
    Service fees and out of pocket expenses waived by the Depositary	130,000
    Total Amount Waived or Paid Directly to Third Parties	277,030

    Under certain circumstances, including removal of the Depositary or termination of the ADR program by the Company, the Company is required to repay to the Depositary amounts reimbursed and/or expenses paid to or on behalf of the Company during the twelve month period prior to notice of removal or termination.

     

     Top 

    6.6 Taxation

    This section describes the material Norwegian tax consequences that apply to shareholders resident in Norway as well asand to non-resident shareholders in connection with the acquisition, ownership and disposal of shares and ADSs.

    Norwegian tax matters
    This section does not provide a complete description of all tax regulations whichthat might be relevant (i.e. for investors to whom special regulations may be applicable). This section is based on current law and practice. Shareholders should consult their professional tax adviser for advice concerning individual tax consequences.
    

    Taxation of dividends
    Under the participation exemption model, corporate shareholders resident in Norway for tax purposes are exempt from tax on dividends distributed by Norwegian companies. However, effective from 7 October 2008, 3% of net income that is tax free under the participation exemption will be included in the Norwegian corporate shareholder's general taxable income. For individual shareholders, double taxation applies: Dividenddividend income exceeding a "deductible allowance", which is an amount equal to the risk-free interest after tax on the base cost of the shareholding, will be taxable at a flat rate, currently 28%. The average interest on Treasury bills of 3three months' maturity will be applied.

    Non-resident shareholders are as a general rule subject to withholding tax at a rate of 25% on dividends distributed by Norwegian companies. This withholding tax does not apply to corporate shareholders that document that they are genuinely resident for tax purposes in a country in the European Economic Agreement area (EEA area) and that it isthey are involved in genuine economic business activity in that country, provided that Norway is entitled to receive information from the state of residency accordingpursuant to a tax treaty or other international treaty. If no such treaty exists with the state of residency, the shareholder may instead present a certification issued by the tax authorities of the state of residency verifying the documentation.

    The withholding rate of 25% is often reduced in tax treaties between Norway and other countries. Generally, the treaty rate does not exceed 15% and, in cases where a corporate shareholder holds a qualifying percentage of the shares of the distributing company, the withholding tax rate on dividends may be further reduced. The withholding tax rate in the tax treaty between the United States and Norway is currently 15% in all cases. The treaty is currently being renegotiated, but it is uncertain at what point in time a new treaty will be in place. Shareholders that carry on business activities in Norway and whose shares are effectively connected with such activities are not liable to the withholding tax. In such case, the rules described in the above paragraph regarding corporate shareholders resident in Norway apply. We are obliged by law to deduct any applicable withholding tax when paying dividends to non-resident shareholders.

    Under the tax treaty between Norway and the United States, the 15% withholding rate will apply to dividends paid on shares held directly by holders who are able to properly demonstrate to the company that they are entitled to the benefits of the tax treaty.

    Dividends paid to the depositary for redistribution to shareholders who hold ADSs will in principle be subject to withholding tax of 25%. The beneficial owners will in this case have to apply to the Central Office of- Foreign Tax Affairs (COFTA) for a refund of the excess amount of tax withheld.

    An application for a refund of withholding tax must contain the following:

    1. A specificationSpecification of the distributing company(ies) involved, the exact amount of shares, the date the dividend payments were made, the total dividend payment, the withholding tax deducted in Norway and the amount that is being reclaimed. The withholding tax must be calculated in Norwegian currency and all sums specified accordingly (in NOK).
    2. Documentation that shows that the refund claimant received the dividends and the withholding tax rate that was applied in Norway.
    3. A certificate of residence issued by the tax authorities stating that the refund claimant is resident for tax purposes in that state in the income year in question or at the time the dividends were decided. This documentation must be the original document.
    4. If the refund application is based on an assertion that the shareholder is covered by the participation exemption method, the application must also contain the information necessary to decide whether the refund claimant is an entity covered by the tax exemption model.
    5. The information required to decide whether the refund claimant is the beneficial owner of the dividend payment(s).
    6. If the securities are registered with a foreign custodian/bank/clearing house, the claimant must provide information about which foreign custodian/bank/clearing house the securities are registered with in Norway.

    The application must be signed by the applicant. If the application is signed by a proxy, a copy of the letter of authorisation must be enclosed.

    However, pursuant to agreements with the Financial Supervisory Authority of Norway and the Norwegian Directorate of Taxes, the Bank of New York, acting as depositary, is entitled to receive dividends from us for redistribution to a beneficial owner of shares or ADSs at the applicable treaty withholding rate, if the beneficial holder has provided the Bank of New York with appropriate certification to establish such holder's eligibility for the benefits under the tax treaty with Norway.

    Wealth tax.
    The shares are included in the basis for the computation of wealth tax imposed on individuals who, for tax purposes, are considered to be resident in Norway. Norwegian limited companies and certain similar entities are not subject to wealth tax. Currently, the marginal wealth tax rate is 1.1% of the value assessed. As of 2008, the assessment value of listed shares is 100% of the listed value of such shares on 1 January in the assessment year.

    Non-resident shareholders are not subject to wealth tax in Norway for shares in Norwegian limited companies unless the shareholder is an individual and the shareholding is effectively connected with his business activities in Norway.

    Inheritance tax and gift tax.
    When shares or ADSs are transferred, either through inheritance or as a gift, such transfer may give rise to inheritance tax in Norway if the deceased at the time of death, or the donor at the time of the gift, is a resident or citizen of Norway. However, if a Norwegian citizen is not a resident of Norway at the time of his or her death, Norwegian inheritance tax will not be levied if an inheritance tax or a similar tax is levied by the country of residence. Irrespective of citizenship, Norwegian inheritance tax may be levied if the shares or ADSs are effectively connected with the conducting of a trade or business through a permanent establishment in Norway.
    

    Taxation on the realisation of shares
    Under the participation exemption model, corporate shareholders resident in Norway for tax purposes are exempt from tax on gains on the sale, redemption or other disposal of shares.shares in Norwegian companies. Corporate shareholders will not be allowed a deduction for losses incurred on the sale, redemption or other disposal of shares in Norwegian companies if a gain would be exempted from taxation. However, effective from 7 October 2008, 3% of net income that is tax free under the participation exemption will be included in the Norwegian corporate shareholder's general taxable income. Costs directly related to the acquisition and sale of such shares are not deductible for tax purposes. Corporate shareholders will not be allowed a deduction for losses incurred on the sale, swap or redemption of shares if a gain would be exempted from taxation.

    For individual shareholders resident in Norway for tax purposes, the sale, redemption or other disposal of shares will be considered a taxable realisation of shares. Gains or losses in connection with such realisation are included in or deducted from the individual's general taxable income in the year of disposal. Ordinary income is taxed at a flat rate of 28%. The gain is subject to tax and the loss is deductible irrespective of the length of the ownership and the number of shares disposed of.

    The taxable gain or loss is calculated as the sales price adjusted for transaction expenses minus the taxable basis. A shareholder's tax basis is normally equal to the acquisition cost of the shares. Any unused "deductible allowance" from previous years attributable to the individual shares realised may be deducted.deducted, but the deduction can not exceed the gain on the shares.

    Shareholders not resident in Norway are generally not subject to tax in Norway on capital gains, and losses are not deductible on the sale, redemption or other disposal of shares or ADSs in Norwegian companies, unless the shareholder is carryingcarries on business activities in Norway and such shares or ADSs are or have been effectively connected with such activities. In addition, individual shareholders previously resident in Norway may, on certain conditions, be liable to tax in Norway foron such gains if the realisation takes place within five years of the end of the calendar year in which the shareholder ceased to be a resident of Norway for tax purposes, or, alternatively, within five years of the Norwegian tax residency expiring pursuant to Norwegian domestic law or tax treaty.

    Transfer tax.
    No transfer tax is imposed in Norway in connection with the sale or purchase of shares.
    

    United States tax matters
    This section describes the material United States federal income tax consequences for US holders (as defined below) of owning shares or ADSs. It only applies to you if you hold your shares or ADSs as capital assets for tax purposes. This section does not apply to you if you are a member of a special class of holders subject to special rules, including:

    • dealersdealers in securities;
    • traders in securities that elect to use a mark-to-market method of accounting for their securities holdings;
    • tax-exempt organisations;
    • life insurance companies;
    • persons liable to alternative minimum tax;
    • persons that actually or constructively own 10% or more of the voting stock of StatoilHydro;Statoil;
    • persons that hold shares or ADSs as part of a straddle or a hedging or conversion transaction; or
    • persons whose functional currency is not USD.

    This section is based on the Internal Revenue Code of 1986, as amended, its legislative history, existing and proposed regulations, published rulings and court decisions, and the Convention between the United States of America and the Kingdom of Norway for the Avoidance of Double Taxation and the Prevention of Fiscal Evasion with Respect to Taxes on Income and Property (the ''Treaty''). These laws are subject to change, possibly on a retroactive basis. In addition, this section is based in part upon the representations of the depositary and the assumption that each obligation in the deposit agreement and any related agreement will be performed in accordance with its terms. For United States federal income tax purposes, if you hold ADRs evidencing ADSs, you will generally be treated as the owner of the ordinary shares represented by those ADRs. Exchanges of shares for ADRs, and ADRs for shares will not generally be subject to United States federal income tax.

    You are a ''US holder'' if you are a beneficial owner of shares or ADSs and you are for United States federal income tax purposes:

    • an individual who is a citizen or resident of the United States;
    • a United States domestic corporation;
    • an estate whose income is subject to United States federal income tax regardless of its source; or
    • a trust if a United States court can exercise primary supervision over the trust's administration and one or more United States persons are authorised to control all substantial decisions of the trust.

    You should consult your own tax advisoradviser regarding the United States federal, state and local and the Norwegian and other tax consequences of owning and disposing of shares and ADSs in your particular circumstances.

    Taxation of dividends.dividends.
    Subject to the passive foreign investment, or PFIC, rules discussed below, if you are a US holder, the gross amount of any dividend paid by StatoilHydroStatoil of its current or accumulated earnings and profits (as determined for United States federal income tax purposes) is subject to United States federal income taxation. If you are a non-corporate US holder, dividends paid to you in taxable years beginning before 1 January 2011 that constitute qualified dividend income will be taxable at a maximum tax rate of 15% if you hold the shares or ADSs for more than 60 days during the 121-day period beginning 60 days before the ex-dividend date and meet other holding-period requirements. Dividends we pay with respect to shares or ADSs will generally be qualified dividend income.

    You must include any Norwegian tax withheld from the dividend payment in this gross amount even though you do not in fact receive the amount withheld as tax. The dividend is taxable tofor you when you, in the case of shares, or the depositary, in the case of ADSs, receive the dividend, actually or constructively. The dividend will not be eligible for the dividends-received deduction generally allowed to United States corporations in respect of dividends received from other United States corporations.

    The amount of the dividend distribution that you must include in your income as a US holder will be the value in US dollars (USD) of the payments made in Norwegian kroner (NOK) determined at the spot NOK/USD rate on the date the dividend distribution is includedincludible in your income, regardless of whether or not the payment is in fact converted into US dollars. Distributions in excess of current and accumulated earnings and profits, as determined for United States federal income tax purposes, will be treated as a non-taxable return of capital to the extent of your tax basis in the shares or ADSs and, to anthe extent in excess of your tax basis, will be treated as capital gain.

    Subject to certain limitations, the 15% Norwegian tax withheld in accordance with the Treatytreaty and paid to Norway will be creditable or deductible against your United States federal income tax liability. Special rules apply when determining the foreign tax credit limitation with respect to dividends that are subject to the maximum 15% rate. Dividends will be income from sources outside the United States. Dividends paid in taxable years beginning before 1 January 2007 will generally be ''passive income'' or ''financial services income'', and dividends paid in taxable years beginning after 31 December 2006 will, depending on your circumstances, be either ''passive'' or ''general'' income, which, in either case, is treated separately from other types of income for purposes of computing the foreign tax credit allowable to you.

    Any gain or loss resulting from currency exchange rate fluctuations during the period from the date you include the dividend payment in income until the date you convert the payment into US dollars will generally be treated as ordinary income or loss and will not be eligible for the special tax rate applicable to qualified dividend income. Such gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes.

    Taxation of capital gains.gains.
    Subject to the PFIC rules discussed below, if you are a US holder and you sell or otherwise dispose of your shares or ADSs, you will generally recognise a capital gain or loss for United States federal income tax purposes equal to the difference between the value in US dollars of the amount that you realise and your tax basis, determined in US dollars, in your shares or ADSs. A capital gain by a non-corporate US holder that is recognised before 1 January 2011 is generally taxed at a maximum rate of 15% if the holding period of the holder is longer than one year. The gain or loss will generally be income or loss from sources within the United States for foreign tax credit limitation purposes.

    If you receive any foreign currency on the sale of shares or ADSs, you may recognise ordinary income or loss from sources within the United States as a result of currency fluctuations between the date of the sale of the shares or ADSs and the date the sales proceeds are converted into US dollars.

    PFIC Rules.
    We believe that the shares and ADSs should not be treated as stock of a PFIC for United States federal income tax purposes, but this conclusion is a factual determination that is made annually and thus may be subject to change. If we were to be treated as a PFIC, unless a US holder elects to be taxed annually on a mark-to-market basis with respect to the shares or ADSs, a gain realised on the sale or other disposition of the shares or ADSs would in general not be treated as a capital gain. Instead, if you are a US holder, you would be treated as if you had realised such gain and certain "excess distributions" ratably over your holding period for the shares or ADSs and would be taxed at the highest tax rate in effect for each such year to which the gain was allocated, together with an interest charge in respect of the tax attributable to each such year. With certain exceptions, the shares or ADSs will be treated as stock in a PFIC if we were a PFIC at any time d uringduring the period you heldhel d the shares or ADSs. Dividends that you receive from us will not be eligible for the special tax rates applicable to qualified dividend income if we are treated as a PFIC with respect to you, either in the taxable year of the distribution or the preceding taxable year, but will instead be taxable at rates applicable to ordinary income.

     Top 

    6.7 Exchange controls and other limitations

    Exchange controls and other limitations affecting shareholders
    

    Under Norwegian foreign exchange controls currently in effect, transfers of capital to and from Norway are not subject to prior government approval except for the physical transfer of payments in currency, which is restricted to licensed banks.

    This means that non-Norwegian resident shareholders may receive dividend payments without Norwegian exchange control consent as long as the payment is made through a licensed bank.

    There are presently no restrictions affecting the rights of non-residents or foreign owners to hold or vote for our shares.

     Top 

    6.8 Exchange rates

    The table below shows the high, low, average and end-of-period noon buyingexchange rates infor the City of New York for cable transfers in foreign currenciesNorwegian krone per USD 1.00 as certified for customs purposesannounced by the Federal ReserveCentral Bank of New York for Norwegian kroner per USD 1.00. Norway.

    The average is computed using the noon buying rate onmonthly average exchange rates announced by the last business dayCentral Bank of each monthNorway during the period indicated.

    Year ended December 31	Year ended December 31		Low		High		Average		End of Period	Low	High	Average	End of Period
    2004			6.0551		7.1408		6.7241		6.0794
    2005			6.0667		6.8023		6.4591		6.7444	6.0809	6.7945	6.4426	6.7687
    2006			5.9869		6.8490		6.3582		6.2287	6.0125	6.8381	6.4135	6.2551
    2007			5.2619		6.4728		5.8109		5.4310	5.2751	6.4727	5.8610	5.4110
    2008			4.9467		7.2848		5.6773		6.9756	4.9589	7.2183	5.6390	6.9989
    2009										5.5433	7.2048	6.2898	5.7767

     

    2008							Low		High
    										Low	High
    2009
    September	September						5.4948		5.9307	5.7625	6.1041
    October							5.8833		7.0680	5.5433	5.8107
    November							6.5930		7.2169	5.5596	5.8081
    December							6.6216		7.2848	5.5805	5.8600
    2009
    2010
    January							6.6827		7.2087	5.6026	5.8800
    February							6.6179		7.0474	5.8327	6.0036
    March (up to and including 6 March 2009)							7.0479		7.2778
    March (up to and including 12 March 2010)										5.8358	5.9571

    On 6 March 200912, 2010, the noon buyingexchange rate announced by Central Bank of Norway for the Norwegian kronerkrone was USD 1.00 = 7.0612 NOK.NOK 5.8358.

    Fluctuations in the exchange rate between the Norwegian kronerkrone and the US dollar will affect the amounts in US dollars received by holders of American Depositary Shares (ADSs) on the conversion of dividends, if any, paid in Norwegian kroner on the ordinary shares, and they may affect the US dollar price of the ADSs on the New York Stock Exchange.

     Top 

    7 Corporate governance

    The

    Statoil's objective of StatoilHydro is to create long-term value for its shareholders through exploration for, and production, transportation, refining and marketing of petroleum and petroleum derived products.

    petroleum-derived products,and other forms of energy.

    In pursuing our corporate objective, we are committed to the highest level of governance and to cultivating a value-based performance culture that rewards exemplary ethical standards, respect for the environment and personal and corporate integrity. We believe that there is a link between high-quality governance and the creation of shareholder value.

    The work of the board of directors is based on the existence of a clearly-defined division of roles and responsibilities between the shareholders, the board of directors and the management in StatoilHydrocompany's management.

    Our governing structures and controls help to ensure that we run our business in a profitable manner tofor the benefit of our shareholders, employees and other stakeholders in societies in which we operate.

    The following principles underline our approach to corporate governance:

    The following principles underline our approach to corporate governance: All shareholders will be treated equally Statoil will ensure that all shareholders have access to up-to-date, reliable and relevant information about the company's activities Statoil will have a board of directors that is independent of the group's management. The board focuses on there not being any conflicts of interest between shareholders, will be treated equally StatoilHydro will ensure that all shareholders have access to up-to-date, reliable and relevant information about the company's activities StatoilHydro will have a board of directors that is independent of the group's management. The board focuses on there not being any conflicts of interest between owners, the board of directors and the company's management The board of directors will base its work on the principles for good corporate governance applicable at all times

    Corporate governance in StatoilHydroStatoil is subject to annual reviews and discussions by the corporate board of directors.

    StatoilHydro'sStatoil's board of directors endorses the 'Norwegian Code of Practice for Corporate Governance', last revised 4 December 2007.on 21 October 2009. The company's compliance with and, if applicable, deviation from the Code of Practice is commented on, and these comments made available.

    Compliance with NYSE listing standardsare available at www.statoil.com/codeofpractice.
    StatoilHydro is a public limited company with a governance structure based on Norwegian law. StatoilHydro's primary listing is onIn the Oslo stock exchange (Oslo Børs). The group is also registeredboard's view, Statoil has complied with the US Securities and Exchange Commission and listedcode of practice throughout the year ended 31 December 2009. In the statutory report, the board presents its statement on the New York Stock Exchange (NYSE). As a consequence, StatoilHydro is required to disclose any significant ways in which its corporate governance, practices differ from those applicable to US companies undersequenced as the NYSE listing standards. A statementNorwegian code of difference, pursuant to Rule 303A.11 of the NYSE Listed Company Manual, is set out below.practice stipulates.

    Committees
    NYSE rules applicable to US companies require that there be certain board committees composed of independent directors with responsibility for certain matters.

    In accordance with Norwegian law, managing the company is the responsibility of the board of directors.
    StatoilHydro has an audit committee and a compensation committee (called remuneration committee), which are responsible for preparing certain issues for the board of directors.

    The committees operate pursuant to charters that are broadly comparable to the form required by the NYSE rules.

    The committees report on a regular basis to and are subject to continuous oversight by the board of directors.

    The membership of StatoilHydro's audit committee includes one employee-elected director, who meets the requirements for independence under Rule 10A-3(b)(1) of the US securities Exchange Act of 1934, but would not be considered independent for purposes of the NYSE rules.

    Among other things, the audit committee evaluates the qualifications and independence of the company's external auditor. However, in accordance with Norwegian law, the auditor is elected by the annual general meeting of the company's shareholders.

    StatoilHydro does not have a nominating/corporate governance committee. Instead, the roles prescribed for a nominating/corporate governance committee under the NYSE rules are principally carried out by the corporate assembly and the election committee.

    StatoilHydro's corporate governance principles are developed by management and the board of directors.
    Oversight of the board of directors and management is carried out by the corporate assembly.

    Independence
    StatoilHydro's board of directors consists of members elected by shareholders and employees, none of whom are executive officers of the company.

    The directors elected among StatoilHydro's employees would not be considered "independent", as defined under NYSE Rule 303A.02, but are independent for the purposes of Rule 10A-3(b)(1) of the US securities Exchange Act of 1934, which applies to members of the company's audit committee.

    The NYSE rules require that the board of directors must affirmatively determine that each "director has no material relationship with the listed company."

    StatoilHydro's board of directors has determined that, in its judgement, all of the shareholder-elected directors are independent.

    Shareholder approval of equity compensation plans
    The NYSE rules require that all equity compensation plans, with limited exemptions, must be subject to shareholder vote.

    Although issuance of shares and authority to buy back company shares must be approved by StatoilHydro's annual general meeting of shareholders under Norwegian company law, approval of equity compensation plans is normally reserved for the board of directors.

     Top 

    7.1 Ethics Code of Conduct

    Together with StatoilHydro'sStatoil's values statement, the Ethics Code of Conduct constitutes the basis and framework for our performance culture and governance system.

    culture.

    Our ability to create value is dependent on applying high ethical standards, and we are determined that StatoilHydroStatoil shall be known for these.these standards. Ethics is treated as an integral part of our business activities. The group requiresdemands high ethical standards of everyone who acts on our behalf and will maintainconduct an open dialogue on ethical issues, internally and externally.

    The StatoilHydroStatoil Ethics Code of Conduct describes theStatoil's commitment and requirements which applyin connection with issues of an ethical nature that relate to business practice and personal conduct.

    In our business practice.activities, we will comply with applicable laws and regulations and act in an ethical, sustainable and socially responsible manner. Respect for human rights is an integral part of Statoil's values base.
    
    The Code'sEthics Code of Conduct's target group isconsists of everyone who works for the Statoil group, including all employees, the chief executive officer, the chief financial officer, the controller and members of the board of directors of StatoilHydroStatoil and its subsidiaries. The Ethics Code of Conduct is accessibleavailable at
    www.statoilhydro.com/en/AboutStatoilHydro/EthicsValues/Pages/ethics.aspx www.statoil.com/Ethics. Statoil's anti-corruption compliance programme can also be found on the same webpage.

    Business partners are also expected to have ethical standards that are compatibleconsistent with StatoilHydro's standards.Statoil's ethical requirements.

    StatoilHydroStatoil has a dedicated ethics helpline that maycan be used by employees or any person that wantswho want to express concerns or seek advice regarding the legal and ethical conduct of StatoilHydro'sStatoil's business.

     Top 

    7.2 Articles of association

    The Articlesarticles of Associationassociation and the Norwegian Public Limited Companies Act form the legal framework for StatoilHydro'sStatoil's operations.

    StatoilHydro's ArticlesStatoil's current articles of Associationassociation were adopted at the Extraordinary General Meetingannual general meeting of 5 July 2007:shareholders on 19 May 2009 and entered into force on 2 November 2009:

    Summary of our Articlesarticles of Associationassociation
    
    Name of the Company
    Our registered name is StatoilHydroStatoil ASA. We are a Norwegian public limited company.
       
     
    Registered office
    Our registered office is in Stavanger, Norway, registered with the Norwegian Register of Business Enterprises under number 913 609 016.

    Object of the company
    The object of our company, as set forth in Article 1, is, either by us or through participation in or together with other companies, to carry out exploration, production, transportation, refining and marketing of petroleum and petroleum derived products, and other forms of energy, as well as other businesses.

    Share capital
    Our share capital is NOK 7,971,617,757.50 divided into 3,188,647,103 ordinary shares.

    Nominal value of shares
    The nominal value of each ordinary share is NOK 2.50.

    Board of directors
    Our articles of association provide that our board of directors shall be composedconsist of ten directors. The board, including the chair and the deputy chair, shall be elected by the corporate assembly.

    Corporate Assembly.

    Corporate Assemblyassembly
    We have a corporate assembly of 18 members who are elected for two-year terms. The general meeting elects 12 members with four alternatesdeputy members, and six members with alternatesdeputy members are elected by and from among the employees.

    Annual general meeting
    Our annual general meeting is held no later than June 30 each year upon at least two weeks' written notice.year.

    The meeting will deal with the Annual Reportannual report and accounts, including distribution of dividends, and any other matters as required by law or our articles of association.

    Marketing of petroleum on behalf of the Norwegian State
    Our articles of association provide that we are responsible for marketing and selling petroleum produced under the SDFI's shares in production licenseslicences on the NCS as well as petroleum received by the Norwegian State as royalty together with our own production. Our general meeting adopted an instruction in respect of such marketing on 25 May 2001.

    Nomination Committeecommittee
    The general meeting decided to amend our articlestasks of association on 7 May 2002 in order to establish athe nomination committee (in the articles of association referred to as the 'election committee'"election committee"). The tasks of the election committee are to make recommendations to the general meeting regarding the election of and fees tofor shareholder-elected members and deputy members of the corporate assembly, and to make recommendations to the corporate assembly regarding the election of and fees tofor shareholder-elected members and deputy members of the board of directors.
       
    The full Articlesarticles of Associationassociation can be found at
    http://www.statoilhydro.com/en/aboutstatoilhydro/corporategovernance/articlesofassociation/pages/default.aspx www.statoil.com/ArticlesOfAssociation.

     Top 

    7.3 General meeting of Shareholders

    The annual general meeting of shareholders (AGM) is the company's supreme body. The objective of the general meeting is to ensure shareholder democracy, and StatoilHydrodemocracy. Statoil encourages all shareholders to participate in person or by proxy.

    Shareholders who are unable to attend theThe annual general meeting of shareholders (AGM) is the company's supreme corporate body. The 2010 AGM is scheduled for 19 May, 2010 in person may follow the proceedingsStavanger, Norway, with simultaneous transmission by webcast. The business of the AGM is conducted in Norwegian with simultaneous English translation during the webcast.

    The main framework as regards convening and translated simultaneously into English.

    Pursuant to StatoilHydro's articles of association andholding the Norwegian Public Limited Companies Act, the AGM:

    • Elects the shareholders' representatives to the corporate assembly
    • Elects the nomination committee (referred toAGM in Statoil is as the election committee in the articles of association)
    • Elects the external auditor and stipulates the auditor's fee
    • Approves the board of directors' report in accordance with Norwegian requirements, the financial statements and the dividend, proposed by the board of directors and recommended by the corporate assembly
    • Deals with any other matters listed in the notice convening the meeting
    follows:

    Pursuant to the company's articles of association, the AGM must be held by the end of June each year.

    Notice of the meeting and documentsdocumentation for the AGM are published on StatoilHydro'sStatoil's website together withat least 21 days prior to the annual reportmeeting and are sent consecutively by mail to the shareholders. Documentation from previous AGMsall shareholders whose address is available on StatoilHydro's website.

    All shareholders are entitled to have their proposal discussed at the annual general meeting, if the proposal has been submitted in writing to the board of directors in due time to either be included in distributed notice of meeting or in a new notice of meeting to be distributedknown no later than two weeks21 days before the general meeting is to be held. As a general rule, the general meeting cannot discuss matters that are not listed in the notice of meeting.

    AGM. All shareholders who are registered in the Norwegian Central Securities Depository (VPS) will receive an invitation to the AGM. They

    Shareholders are entitled to submit proposals andhave their proposal dealt with at the general meeting if the proposal has been submitted in writing to the board of directors in sufficient time to allow inclusion in the distributed notice of meeting. Shareholders who are prevented from attending may vote in person or by proxy.

    The deadline for registration for the AGM is four days priorthe day before the AGM is due to the AGM.take place.

    The chair of the AGM willis normally beopened and chaired by the chair of the corporate assembly. If there is a dispute concerning individual matters and the chair of the corporate assembly belongs to one of the disputing parties, or is for some other reason not perceived as being impartial, another person will be appointed to chair the AGM in order to ensure impartiality in relation to the matters to be considered.

    Given the As Statoil has a large number of shareholders and theirwith a wide geographical distribution, the number ofStatoil offers shareholders who are able to attend the AGM in person will be limited. StatoilHydro therefore offers its shareholders an opportunity to follow the proceedingsAGM by webcast.

    The businessfollowing matters are decided at the AGM:

    • Election of the AGM is conductedshareholders' representatives to the corporate assembly
    • Election of the nomination committee (referred to as the election committee in Norwegianthe articles of association)
    • Election of the external auditor and translated simultaneously into English.
      stipulation of the auditor's fee
    • Approval of the board of directors' report, the financial statements and any dividend, proposed by the board of directors and recommended by the corporate assembly
    • Any other matters listed in the notice convening the AGM

    All of our ordinary shares carry an equal right to vote at general meetings. Except as otherwise provided, decisions which shareholdersResolutions at AGMs are entitled to make pursuant tonormally passed by simple majority. However, Norwegian company law or our articles of association may be made byrequires a simplequalified majority of the votes cast. In the case of elections, the persons who obtain the most votes cast are deemed elected. However,for certain decisions,resolutions, including resolutions to waive preferential rights in connection with any share issue, to approveapproval of a merger or demerger, to amend ouramendment of the articles of association or authorisation to authorise an increase or reduction in ourreduce the share capital, must receivecapital. Such matters require the approval of at least two-thirds of the aggregate number of votes cast as well as two-thirds of the share capital represented at the AGM.

    The minutes of the AGM are made available on Statoil's website immediately after the AGM.

    As regards extraordinary general meetings (EGM), an EGM shall be held if demanded by the corporate assembly, the chair of the corporate assembly, the auditor or shareholders representing at least 5% of the share capital in order to consider and decide a shareholders' meeting.specific matter. The board must ensure that the extraordinary general meeting is held within a month of such demand being submitted.

    In the following, we will provide an outline of certain resolutions by the AGM:

    Issuing of new shares
    If we issue any new shares, including bonus share issues, our articles of association must be amended, which requires the same votemajority as other amendments to our articles of association. In addition, under Norwegian law, our shareholders have a preferential right to subscribe to issues of new shares by us. The preferential rightsright to subscribe to an issue may be waived by a resolution inof a general meeting passed by the same percentage thresholdas required to approve amendments to our articles of association. The general meeting may, with a votemajority as described above, authorizeauthorise the board of directors to issue new shares, and to waive the preferential rights of shareholders in connection with such issuances.share issues. Such authorizationauthorisation may be effective for a maximum of two years, and the par value of the shares to be issued may not exceed 50% of the nominal share capital when the authorizationauthorisation was granted.

    The issuanceissuing of shares through the exercise of preferential rights to holders who are citizens or residents of the United States upon the exercise of preferential rightsUSA may require us to file a registration statement in the United StatesUSA under United StatesUS securities laws. If we decide not to file a registration statement, these holders may not be able to exercise their preferential rights.

    RightsRight of Redemptionredemption and Repurchaserepurchase of Sharesshares
    Our articles of association do not authorizeauthorise the redemption of shares. In the absence of authorization,authorisation, the redemption of shares may stillnonetheless be decided by a general meeting of shareholders by a two-thirds majority underon certain conditions. However, the share redemption would, for all practical purposes, depend on the consent of all shareholders whose shares are redeemed.

    A Norwegian company may purchase its own shares if an authorizationauthorisation to do so has been givengranted by a general meeting with the approval of at least two-thirds of the aggregate number of votes cast as well as two thirdstwo-thirds of the share capital represented at the general meeting. The aggregate par value of such treasury shares held by the company must not exceed 10% of the company's share capital and treasury shares may only be acquired if, according to the most recently adopted balance sheet, the company's distributable equity according to the latest adopted balance sheet, exceeds the consideration to be paid for the shares. The authorizationAuthorisation by the general meeting cannot be givengranted for a period exceeding 18 months.
    
    Distribution of Assetsassets on Liquidationliquidation
    Under Norwegian law, a company may be wound-upwound up by a resolution of the company's shareholders inat a general meeting passed by both a two-thirds majority of the aggregate votes cast and two-thirds of the aggregate share capital represented at the general meeting. The shares rank equalare ranked equally in the event of a return on capital by the company upon a winding-up or otherwise.
    
    Electronic voting distribution
    StatoilHydro intendsIn 2010, a proposal to make userevise the articles of electronic votingassociation will be forwarded by the board for approval by the AGM. The revision, if approved, will allow distribution of documents to future AGMs at its general meetings as soon as Norwegian legislation allows this.Statoil's web site. A shareholder may nevertheless request that documents, which relate to matters to be dealt with by the AGM, be sent to him/her.

    Extraordinary general meetings  
    Pursuant to Norwegian law, the corporate assembly, the chair of the corporate assembly, the auditor, or shareholders representing at least 5% of the share capital, may demand that an extraordinary general meeting be held in order to have a specific matter considered and decided. The board must ensure that the extraordinary general meeting is held within a month of such a demand being submitted.

     Top 

    7.4 Board of directorsNomination committee

    Pursuant to StatoilHydro's

    In accordance with Statoil's articles of association, the boardnomination committee (referred to as the election committee in the articles of directorsassociation) consists of 10 members. The management is not represented on the board. A majorityfour members who are shareholders, or representatives of the members of the board are deemed to be 'independent' board members.

    As required by Norwegian company law, the company's employees are entitled to be represented by three board members. There are no board member service contracts that provide for benefits upon termination of office. The StatoilHydro board has determined that, in its judgment, all of the non-employee directors are independent. In doing so, however, the board did not explicitly take into consideration the NYSE's five specific tests.

    shareholders.

    The boardcommittee is independent of directors of StatoilHydro ASA is responsible for the overall management of the StatoilHydro group, and for supervising the group's activities in general. The board of directors handles matters of major importance or of an extraordinary nature. However, it may require management to refer any matter to it. The board of directors appoints the president and chief executive officer (CEO), and stipulates the job instructions, powers of attorney and terms and conditions of employment for the president and CEO.

    The board of directors has two sub-committees, the audit committee and the compensation committee.

    The board held 13 meetings in 2008. Attendance at board meetings was 97%.

    Members of the board of directors
    Svein Rennemo
     

    Position: Chair of the board and member of the board's compensation committee.
    Born: 1947
    Term of office: Member of the board of StatoilHydro ASA since 1 April 2008
    Independent: Yes
    Other directorships: Chair of the board of Integrated Optoelectronics AS and Pharmaq AS Member of the board of Norske Skogindustrier ASA.
    Number of shares in StatoilHydro ASA pr. 31. December 2008: 10,000
    Loans from StatoilHydro: None
    Experience: CEO of Petroleum Geo Services ASA from 2002 until 1 April 2008 (when he took up office as chair of the board of StatoilHydro)
    From 1994 to 2001, Mr Rennemo worked for Borealis, first as Deputy CEO and CFO and from 1997 as CEO.
    He held various management positions in Statoil from 1982 to 1994, latterly as head of the petrochemical division.
    During the period 1972 to 1982, he was an analyst and monetary policy and economics advisor with Norges Bank (the Norwegian central bank), the OECD Secretariat in Paris and the Ministry of Finance.
    Education: Economist from the University of Oslo.
    Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly.
    Other matters: Svein Rennemo is a Norwegian citizen, and he lives in Norway.

    Marit Arnstad
     

    Position: Deputy chair and member of the board's audit committee.
    Born: 1962
    Term of office: Member of the board of Statoil ASA from June 2006 and member of the board of StatoilHydro ASA since 1 October 2007
    Independent: Yes
    Other directorships: Chair of the board of the Norwegian University of Science and Technology (NTNU). Board member of Adresseavisen ASA, NTE Nett AS, Aker Seafood ASA and Acta ASA.
    Number of shares in StatoilHydro ASA pr. 31. December 2008: 0
    Loans from StatoilHydro: None
    Experience: Ms Arnstad is an advocate with the law firm Schjødt AS.
    Ms Arnstad was Minister of Petroleum and Energy during the period 1997 - 2000. She was a member of the Norwegian parliament, the Storting, for the Centre Party from 1993 to 1997 and 2001 to 2005, and was leader of the party's parliamentary group from 2003 to 2005. Before this, she was a Higher Executive Officer at the Ministry of the Environment.
    Education: Law graduate (cand. jur.) from the University of Oslo.
    Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
    Other matters: Marit Arnstad is a Norwegian citizen, and she lives in Norway.

    Kjell Bjørndalen
     

    Position: Board member and member of the board's compensation committee.
    Born: 1946
    Term of office: Member of the board of StatoilHydro ASA since 1 October 2007. Member of Statoil ASA's corporate assembly from 1992 to 2007.
    Independent: Yes
    Other directorships: Mr Bjørndalen is a member of the boards of Alfred Berg Kapitalforvaltning AS, Xynergo AS and Bank 1 Oslo.
    Number of shares in StatoilHydro ASA pr. 31. December 2008: 0
    Loans from StatoilHydro: None
    Experience: Until October 2007, he was president of the Norwegian United Federation of Trade Unions (Fellesforbundet) and a member of the secretariat of the Norwegian Confederation of Trade Unions (LO).
    Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly.
    Other matters: Kjell Bjørndalen is a Norwegian citizen, and he lives in Norway.

    Roy Franklin
     

    Position: Member ofboth the board and the board's audit committee.
    Born: 1953
    Term of office: Membercompany's management.

    The duties of the boardnomination committee are:

    • to present recommendations to the AGM for the election of StatoilHydro ASA since 1 October 2007
      Independent: Yes
      Other directorships: Chair of Brindex, the Association of British Independent Oil Exploration Companies,shareholder-elected members and a member of the joint British oil industry and government task force Pilot from 2002 to 2005.
      He is non-executive chair of the boards of Bateman Litwin NV, Novera Energy Ltd, a leading UK company in the field of renewable energy, TS Marine Ltd, based in Aberdeen and Keller Group plc, a London-based international engineering company. Board member of the Australian oil and gas company Santos Ltd.
      Number of shares in StatoilHydro ASA pr. 31. December 2008: None
      Loans from StatoilHydro: None
      Experience: Has broad experience from management positions in several countries, including positions with BP, Paladin Resources plc and Clyde Petroleum plc.
      Education: Bachelor of Science in geology from the University of Southampton in the UK.
      Family relations: No family relations to otherdeputy members of the Board, members of the Corporate Executive Committee or the Corporate Assembly.
      Other matters: Roy Franklin is a UK citizen and he lives in the UK.
      In 2004, he was awarded an OBE for his work for the British oil and gas industry.

      Elisabeth Grieg
      

      Position: Board member and member of the board's compensation committee.
      Born: 1959
      Term of office: Member of the board of Norsk Hydro ASA from 2001 corporate assembly

    • to 2007 and member of the board of StatoilHydro ASA since 1 October 2007.
      Independent: Yes
      Other directorships: Chair of the board of Grieg Shipping Group and Grieg Star Shipping AS. Board member in Grieg Maturitas AS, Grieg Foundation and SOS Children's Villages, Norway. Member ofpresent recommendations to the corporate assembly and election committee of Orkla ASA, and of the council of Det Norske Veritas.
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 33,108
      Loans from StatoilHydro: None
      Experience: Managing Director of Grieg International AS and co-owner of the Grieg Group. President of the Norwegian Shipowners' Association
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Elisabeth Grieg is a Norwegian citizen, and she lives in Norway.
      Elisabeth Grieg is part-owner of the family company Grieg Maturitas AS, which indirectly owns 20% of AON Grieg AS. AON Grieg AS acted as broker for StatoilHydro in 2008 and received fees totalling NOK 16,934,611 from StatoilHydro in 2008.
      In addition, Grieg Maturitas AS and other family companies own a direct and indirect interest of 75% of Grieg Logistics AS. Elisabeth Grieg's husband, Stig Grimsgaard Andersen, is a board member of Grieg Logistics AS. Grieg Logistics AS delivered logistics and transport services to StatoilHydro in 2008, for which it received fees totalling NOK 135,177,387.

      Kurt Anker Nielsen
       

      Position: Board member and chair of the board's audit committee.
      Born: 1945
      Term of office: Member of the board of Norsk Hydro ASA from 2004 to 2007 and member of the board of StatoilHydro since 1 October 2007
      Independent: Yes
      Other directorships: Mr Nielsen is chair of the board of Reliance A/S and deputy chair of the board of Novozymes A/S. He is a board member of Novo Nordisk A/S, Novo Nordisk Fonden, ZymoGenetics Inc, Vestas Wind Systems A/S and Life Cycle Pharma A/S
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 0
      Loans from StatoilHydro: None
      Experience: Kurt Anker Nielsen has held senior management positions in Novo A/S and Novo Nordisk A/S in Denmark, including the positions of CFO and managing director.
      Education: MSc (Economics and Business Administration), Copenhagen Business School.
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Kurt Anker Nielsen is a Danish citizen and he lives in Denmark

      Grace Reksten Skaugen
       

      Position: Board member and member of the board's compensation committee
      Born: 1953
      Term of office: Member of the board of Statoil from 2002 and a member of the board of StatoilHydro from 1 October 2007
      Independent: Yes
      Other directorships: Chair of the boards of Entra Eiendom AS and Ferd Holding and member of the board of the Swedish listed company Investor AB
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 400
      Loans from StatoilHydro: None
      Experience: Self-employed consultant, director within Corporate Finance in Enskilda Securities in Oslo from 1994 to 2002. Has also worked with venture capital and shipping in Oslo and London and carried out research in microelectronics at Columbia University in New York
      Education: She has a doctorate in laser physics from the Imperial College of Science and Technology at the University of London and an MBA from the Norwegian School of Management (BI)
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Grace Reksten Skaugen is a Norwegian citizen and she lives in Norway
       
      Lill-Heidi Bakkerud  
      

      Position: Represents the employees on the board.
      Born: 1963.
      Term of office: Member of the board of Statoil ASA from 1998 to 2002 and from 2004 to 2007. Member of the board of StatoilHydro ASA since 1 October
      Independent: No
      Other directorships: She is a member of the executive committee of the Industry Energy (IE) trade union and holds a number of offices as a result of this
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 330
      Loans from StatoilHydro: None
      Experience: She has worked as a process technician at the petrochemical plant in Bamble and on the Gullfaks field in the North Sea. She is now a full-time employee representative as leader of the StatoilHydro branch of IE.
      Education: Has a craft certificate as a process/chemistry worker
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Lill-Heidi Bakkerud is a Norwegian citizen, and she lives in Norway

      Claus Clausen
       

      Position: Represents the employees on the board
      Born: 1954
      Term of office: Member of the board of Statoil ASA from 2006 to 2007 and StatoilHydro ASA since 1 October 2007
      Independent: No
      Other offices: None
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 165
      Loans from StatoilHydro: None
      Experience: Mr Clausen worked for Statoil from 1991, and from 1997 he held various positions in the process discipline. He was attached to Statfjord from 2001, among other things as process discipline manager. Mr Clausen is currently head of inspection and surface maintenance in Stavanger
      Education: Claus Clausen has an engineering degree from Bergen Engineering College
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Claus Clausen is a Norwegian citizen, and he lives in Norway

      Morten Svaan
      

      Position: Represents the employees on the board and is a member of the board's audit committee
      Born: 1956
      Term of office: Member of the board of Statoil ASA from 2002 to 2007 and of StatoilHydro ASA since 1 October 2007
      Independent: No
      Other directorships: None
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 933
      Loans from StatoilHydro: NOK 260,555. This is a car loan in the company on the terms and conditions that apply to all employees at his job level
      Experience: Mr Svaan worked for Statoil from 1985. He now works on health, safety and the environment (HSE) for the Technology & New Energy business area, largely focusing on security and emergency response. Mr Svaan was chief employee representative for the Statoil branchelection of the NIF/Tekna union from 2000 until 2004.
      Education: He has a PhD in chemistry from the Norwegian University of Science and Technology and a degree in business economics from the Norwegian School of Management (BI)
      Family relations: No family relations to othershareholder-elected members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Morten Svaan is a Norwegian citizen, and he lives in Norway

      The following two persons are employee-elected observer on the board, with no voting rights
       
      Ragnar Fritsvold  
       

      Position: An employee-elected observer on the board
      Born: 1948
      Term of office: Member of the board of Norsk Hydro ASA from May 2007 until October 2007. Observer on the board of StatoilHydro ASA since 1 October 2007
      Independent: No
      Other directorships: None
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 468
      Experience: Mr Fritsvold joined Hydro in 1979, and he is now a staff engineer in StatoilHydro and a full-time employee representative. He was leader of the Hydro branch of the Norwegian Society of Graduate Technical and Scientific Professionals (Tekna) from 1999 to 2007.
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Ragnar Fritsvold is a Norwegian citizen, and he lives in Norway

      Geir Nilsen
      

      Position: Employee-elected observer on the board. Represents employees who are members of the Norwegian Confederation of Trade Unions (LO)
      Born: 1955
      Term of office: Member of the board of Norsk Hydro ASA from 2003 to 2007. Observer on the board of StatoilHydro since 1 October 2007
      Independent: No
      Other directorships: None
      Number of shares in StatoilHydro ASA pr. 31. December 2008: 626
      Experience: Joined Hydro in 1973 and worked as a maintenance manager in Petrochemicals/PVC from 1984 to 1988. Employed offshore from 1988, as a maintenance manager from 1996
      Education: Automation worker
      Family relations: No family relations to other members of the Board, members of the Corporate Executive Committee or the Corporate Assembly
      Other matters: Geir Nilsen is a Norwegian citizen, and he lives in Norway

       Top 

      7.4.1 Audit committee

      The board elects up to four of its members to serve on the audit committee. The current members of the audit committee are Kurt Anker Nielsen (chair), Marit Arnstad, Roy Franklin and Morten Svaan.

      The audit committee is a sub-committee of the board of directors and its objective is to carry out more thorough assessments of specific matters in the StatoilHydro group and report to the board of directors. The audit committee is instructed directors

    • to assistpresent recommendations to the board in its supervisingAGM for the election of issues such as:

      (1) the quality and integritymembers of the company's financial statements and related disclosures
      (2) the external auditor's qualifications and independence
      (3) the performance of the external auditor pursuant nomination committee

    • to the requirements of Norwegian law and the laws of those countries where the company is listed on the stock exchange
      (4) the performance of the company's internal audit function, internal controls and risk management systems
      (5) the company's compliance with legal and regulatory requirements, including the requirements relating to listing on stock exchanges and
      (6) 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 makespresent a recommendation to the board of directorsproposal for the appointmentremuneration of the external auditor based on its evaluation of the qualifications and independence of the auditor proposed for election or re-election. The audit committee meets at least six times a year, and it 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 has procedures for receiving and dealing with 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.

      The audit committee held 8 meetings in 2008. There was 97 % attendance at the committee's meetings.

      The committee's mandate is available at http://www.statoilhydro.com/en/AboutStatoilHydro/CorporateGovernance/GoverningBodies/AuditCommittee/Pages/default.aspx

       Top 

      7.4.1.1 Audit committee financial expert

      The board of directors has decided that a member of the audit committee, Kurt Anker Nielsen, qualifies as an "audit committee financial expert", as defined in Item 16A of Form 20-F.

      The board of directors has also concluded that Kurt Nielsen is independent in accordance with the meaning of Rule 10A-3 under the Securities Exchange Act.

      7.4.1.2 Exemptions from listing standards

      This section describes an exemption from the listing standards for audit committees that StatoilHydro relies upon.

      StatoilHydro relies on the exemption provided in Rule 10A-3(b)(1)(iv)(C) from the independence requirements of the Securities Exchange Act with respect to Morten Svaan, a member of the audit committee who is also one of three members of the board of directors, of StatoilHydro elected by the employees in accordance with Norwegian company legislation. Mr Svaan iscorporate assembly and the nomination committee

    Shareholders can, using a non-executive employee ofform on the company.
    
    StatoilHydro does not believe that its reliance on this exemption will materially adversely affect the ability of the audit committee to act independently or to satisfy the other requirements of Rule 10A-3 relating to audit committees.

     Top 

    7.4.2 Compensation committee

    The compensation committee is a sub-committee ofcompany's website, propose candidates for the board of directors, that assists the board of directors on matters relating to management compensationcorporate assembly and leadership development.the nomination committee.

    The compensation committee is a sub-committeemembers of the boardnomination committee are elected by the AGM. Two of directorsthe members are elected from among the shareholder-elected members of the corporate assembly. Members of the nomination committee are normally elected for a term of two years.

    The members of the nomination committee are:

    • Olaug Svarva (chair), managing director, Folketrygdfondet
    • Gro Bækken, managing director of OLF, Oljeindustriens Landsforening (the Norwegian Oil Industry Association) as of 1 January (Gro Brækken has, due to conflict of interest, not participated in the nomination committee since 17 August 2009)
    • Tom Rathke, managing director, Vital Forsikring and the main responsibilities are:executive vice president, DnB NOR
    • Bjørn Ståle Haavik, director general, Ministry of Petroleum and Energy

    The nomination committee held 16 meetings in 2009.

    (1) as a preparatory bodyThe rules of procedure for the board, make recommendations to the board in all matters relating to executive reward principles, remuneration strategies and concepts, the CEO's contract and terms of employments and leadership development, assessments and succession planningnomination committee are available at www.statoil.com/NominationCommittee.

    (2) to be informed about and advise the company's management in its work on StatoilHydro's remuneration strategy and in drawing up appropriate remuneration policies and

    (3) to review StatoilHydro's remuneration policies in order to safeguard the owners' long-term interests.

    The committee consists of four board members. At year end 2008, the committee members were Grace Reksten Skaugen (chair), Svein Rennemo, Elisabeth Grieg and Kjell Bjørndalen.
    All of the committee members are independent, non-executive directors.

    The committee held 6 meetings in 2008. There was 95 % attendance at the committee's meetings.

    The committee's mandate is accessible at http://www.statoilhydro.com/en/AboutStatoilHydro/CorporateGovernance/GoverningBodies/BoardsCompensationCommittee/Pages/default.aspx

     Top 

    7.5 Corporate assembly

    Pursuant to the Norwegian Public Limited Liability Companies Act, companies with more than 200 employees must elect a corporate assembly unless otherwise agreed between the company and a majority of its employees.

    Name	Occupation	Place of Residence	Year of birth	Position	Family relations to Corporate Executive committee, Board or Corporate Assembly members	Share ownership for members pr 31.12.2009	Share ownership for members pr 12.03.2010	First time elected	Expiration date of current term
    Olaug Svarva	Managing Director, Folketrygdfondet	Oslo	1957	Chair, Shareholder elected	No	0	0	2007	2010
    Idar Kreutzer	CEO, Storebrand	Oslo	1962	Deputy chair, Shareholder elected	No	0	0	2007	2010
    Karin Aslaksen	Senior Vice President, Elkem AS	Hosle	1959	Shareholder elected	No	0	0	2008	2010
    Greger Mannsverk	Managing Director, Bergen Group Kimek	Kirkenes	1961	Shareholder elected	No	0	0	2002	2010
    Steinar Olsen	Self-employed	Stavanger	1949	Shareholder elected	No	0	0	2007	2010
    Benedicte Berg Schilbred	Working Chair of the Board, Odd Berg Group	Tromsø	1946	Shareholder elected	No	0	0	2007	2010
    Ingvald Strømmen	Dean, NTNU	Ranheim	1950	Shareholder elected	No	0	0	2006	2010
    Inger Østensjø	Chief administrative officer, Stavanger Municipality	Stavanger	1954	Shareholder elected	No	0	0	2006	2010
    Rune Bjerke	CEO, DnBNOR	Oslo	1960	Shareholder elected	No	0	0	2007	2010
    Kåre Rommetveit	Director, Bergen Medical research foundation	Hjellestad	1945	Shareholder elected	No	0	0	2007	2010
    Tore Ulstein	Managing Director, Ulstein International	Ulsteinvik	1967	Shareholder elected	No	0	0	2008	2010
    Eldfrid Irene Hognestad	Principal Engineer, Technology & New Energy	Stavanger	1966	Employee representative	No	694	791	2009	2011
    Stig Lægreid	Union Official, Projects	Oslo	1963	Employee representative	No	426	466	2009	2011
    Per Martin Labråthen	Process technician, Exploration & Production Norway	Brevik	1961	Employee representative	No	406	431	2007	2011
    Anne K.S. Horneland	Union Official, Exploration & Production Norway	Hafrsfjord	1956	Employee representative	No	1629	1847	2006	2011
    Jan-Eirik Feste	Union Official, Marketing & Manufacturing	Lindås	1952	Employee representative	No	282	305	2008	2011
    Per Helge Ødegård	Union Official, Exploration & Production Norway	Porsgrunn	1963	Employee representative	No	824	963	1994	2011
    Anne Synnøve Hebnes	Manager, Technology & New Energy	Stavanger	1972	Employee representative, observer	No	0	0	2006	2011
    Oddbjørn Viken	Manager, Exploration & Production Norway	Røyken	1961	Employee representative, observer	No	1580	1824	2009	2011
    Frode Solberg	Union Official, Natural Gas	Bergen	1969	Employee representative, observer	No	0	0	2009	2011

    The corporate assembly must be composedconsist of at least 12 members or a larger quantitynumber divisible by three. Shareholders elect two-thirds of the members toof the corporate assembly, while employees elect the remaining one-third.third.

    Pursuant to StatoilHydro'sStatoil's articles of association, ourthe corporate assembly consists of 18 members. Twelve memebersmembers and four alternatesdeputy members are elected at the general meeting by the shareholders, and six members, two observers and deputy members are elected by and from among the employees, such employees being non-executives.non-executive personnel.

    Members of the corporate assembly are normally elected for a term of two years. Members of the board of directors and the general manager cannot be members of the corporate assembly, but they are entitled to attend and to speak at meetings of the corporate assembly unless the corporate assembly decides otherwise in individual cases.

    The corporate assembly's main duty is to elect the board of directors.

    Its responsibilities also include overseeing the board and the CEO's management of the company, making decisions on investments of considerable magnitude in relation to the company's resources and making decisions involving the rationalisation or reorganisation of operations that will entail major changes in or reallocation of the workforce.

    The duties of the corporate assembly are defined in section 6-37 of the Norwegian Public Limited Liability Companies Act.

    The corporate assembly held 5five meetings in 2008.2009.

    The following is a list of the members of the corporate assembly as of 31 December 2008:

    Name	Occupation	Place of Residence	Year of birth	Position	Family relations to Corporate Executive committee, Board or Corporate Assembly members	Share ownership for members	First time elected	Expiration date of current term
    Olaug Svarva	Managing Director, Folketrygdfondet	Oslo	1957	Chair, Shareholder elected	No	0	2007	2010
    Idar Kreutzer	CEO, Storebrand	Oslo	1962	Deputy chair, Shareholder elected	No	0	2007	2010
    Karin Aslaksen	Senior Vice President, Elkem AS	Hosle	1959	Shareholder elected	No	0	2008	2010
    Greger Mannsverk	Managing Director, Bergen Group Kimek	Kirkenes	1961	Shareholder elected	No	0	2002	2010
    Steinar Olsen	Self-employed	Stavanger	1949	Shareholder elected	No	0	2007	2010
    Benedicte Berg Schilbred	Working Chair of the Board, Odd Berg Group	Tromsø	1946	Shareholder elected	No	0	2007	2010
    Ingvald Strømmen	Dean, NTNU	Ranheim	1950	Shareholder elected	No	0	2006	2010
    Inger Østensjø	Chief administrative officer, Stavanger Municipality	Stavanger	1954	Shareholder elected	No	0	2006	2010
    Rune Bjerke	CEO, DnBNOR	Oslo	1960	Shareholder elected	No	0	2007	2010
    Gro Brækken	Secretary General, Save the Children	Snarøya	1952	Shareholder elected	No	0	2007	2010
    Kåre Rommetveit	Director, Bergen Medical research foundation	Hjellestad	1945	Shareholder elected	No	0	2007	2010
    Tore Ulstein	Managing Director, Ulstein International	Ulsteinvik	1967	Shareholder elected	No	0	2008	2010
    Anne Synnøve Hebnes	Manager, Technology & New Energy	Stavanger	1972	Employee representative	No	0	2006	2009
    Per Helge Ødegård	Union Official, Exploration & Production Norway	Porsgrunn	1963	Employee representative	No	964	1994	2009
    Arvid Færaas	Manager, Natural Gas	Vormedal	1962	Employee representative	No	344	2000	2009
    Einar Arne Iversen	Union Official, Corporate Staffs & Services	Molde	1962	Employee representative	No	1512	2000	2009
    Tore Amund Fredriksen	Principal engineer, Technology & New Energy	Porsgrunn	1953	Employee representative	No	826	2007	2009
    Per Martin Labråthen	Process technician, Exploration & Production Norway	Brevik	1961	Employee representative	No	129	2007	2009
    Jan-Eirik Feste	Union Official, Marketing & Manufacturing	Lindås	1952	Employee representative, observer	No	130	2008	2009
    Anne K.S. Horneland	Union Official, Exploration & Production Norway	Hafrsfjord	1956	Employee representative, observer	No	1760	2006	2009

    All members of the corporate assembly reside in Norway. Members of the corporate assembly do not have service contracts with the company or its subsidiaries providing for benefits upon termination of employment.

     Top 

    7.6 ManagementBoard of directors

    Pursuant to Statoil's articles of association, the board of directors consists of 10 members. The management is not represented on the board, and all shareholder-elected directors are independent.

    As required by Norwegian company law, the company's employees are entitled to be represented by three board members. There are no board member service contracts that provide for benefits upon termination of office. Statoil's board of directors has determined that, in its judgement, all of the shareholder-elected directors are independent, as defined by the Norwegian Code of Practice.

    The board of directors of Statoil ASA is responsible for the overall management of the Statoil group, and for supervising the group's activities in general. The board of directors handles matters of major importance or of an extraordinary nature. However, it may require the management to refer any matter to it. The board of directors appoints the president and chief executive officer (CEO), and stipulates the job instructions, powers of attorney and terms and conditions of employment for the president and CEO.

    The board of directors has two sub-committees, the audit committee and the compensation committee.

    The board held 11 meetings in 2009. Attendance at board meetings was 94%.

    Members of the board of directors

    
    Svein Rennemo

    

    Position: Chair of the board and member of the board's compensation committee.
    Born: 1947
    Term of office: Chair of the board of Statoil ASA since 1 April 2008.
    Independent: Yes
    Other directorships: Chair of the board of Integrated Optoelectronics AS, Tomra Systems ASA and Pharmaq AS. Member of the board of Norske Skogsindustrier ASA.
    Number of shares in Statoil ASA as of 31 December 2009: 10,000
    Loans from Statoil: None
    Experience: CEO of Petroleum Geo-Services ASA from 2002 until 1 April 2008 (when he took up office as chair of the board of Statoil ASA).From 1994 to 2001, Rennemo worked for Borealis, first as deputy CEO and CFO and, from 1997, as CEO.
    He held various management positions in Statoil from 1982 to 1994, latterly as head of the petrochemical division.During the period 1972 to 1982, he was an analyst and monetary policy and economics adviser at Norges Bank (the Norwegian Central Bank), the OECD Secretariat in Paris and the Ministry of Finance.
    Education: Economist, University of Oslo.
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Svein Rennemo is a Norwegian citizen, and he lives in Norway.

    Marit Arnstad

    

    Position: Deputy chair and member of the board's audit committee.
    Born: 1962
    Term of office: Member of the board of Statoil ASA since June 2006, deputy chair since 1 October 2007.
    Independent: Yes
    Other directorships: Chair of the board of the Norwegian University of Science and Technology (NTNU) and of Statskog SF. Board member of Polaris Media ASA, Aker Seafoods ASA and NTE Nett AS.
    Number of shares in Statoil ASA as of 31 December 2009: None
    Loans from Statoil: None
    Experience: Arnstad is an advocate with the law firm Arntzen de Besche Trondheim AS. Arnstad was Minister of Petroleum and Energy during the period 1997 - 2000. She was a member of the Norwegian parliament, the Storting, representing the Centre Party from 1993 to 1997 and 2001 to 2005, and was leader of the party's parliamentary group from 2003 to 2005. Before that, she was a higher executive officer with the Ministry of the Environment.
    Education: Law graduate (cand. jur.) from the University of Oslo.
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Marit Arnstad is a Norwegian citizen, and she lives in Norway.

    Kjell Bjørndalen

    

    Position: Board member and member of the board's compensation committee.
    Born: 1946
    Term of office: Member of the board of Statoil ASA since 1 October 2007. Member of Statoil ASA's corporate assembly from 1992 to 2007.
    Independent: Yes
    Other directorships: Bjørndalen is a member of the boards of Alfred Berg Kapitalforvaltning AS and Xynergo AS.
    Number of shares in Statoil ASA as of 31 December 2009: None
    Loans from Statoil: None
    Experience: Until October 2007, he was president of the Norwegian United Federation of Trade Unions (Fellesforbundet) and a member of the secretariat of the Norwegian Confederation of Trade Unions (LO).
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Kjell Bjørndalen is a Norwegian citizen, and he lives in Norway.

    Roy Franklin

    

    Position: Member of the board, and chair of the board's audit committee.
    Born: 1953
    Term of office: Member of the board of Statoil ASA since 1 October 2007.
    Independent: Yes
    Other directorships: Franklin is a non-executive chair of the board of Keller Group plc, a London-based international ground engineering company, and a board member of the Australian oil and gas company Santos Ltd.
    Number of shares in Statoil ASA as of 31 December 2009: None
    Loans from Statoil: None
    Experience: Has broad experience from management positions in several countries, including positions with BP, Paladin Resources plc. and Clyde Petroleum plc.
    Education: Bachelor of Science in geology from the University of Southampton, UK.
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Roy Franklin is a UK citizen and he lives in the UK. In 2004, he was awarded an OBE for his work for the British oil and gas industry.

    Elisabeth Grieg

    

    Position: Board member and member of the board's compensation committee.
    Born: 1959
    Term of office: Member of the board of Norsk Hydro ASA from 2001 to 2007. Member of the board of Statoil ASA since 1 October 2007.
    Independent: Yes
    Other directorships: Grieg is chair of the board of Grieg Shipping Group and Grieg Star Shipping AS. Board member in Grieg Maturitas AS, Grieg Foundation and SOS Children's Villages, Norway. Member of the council of Det Norske Veritas.
    Number of shares in Statoil ASA as of 31 December 2009: 8,190
    Loans from Statoil: None
    Experience: Grieg is managing director of Grieg International AS, co-owner of the Grieg Group and president of the Norwegian Shipowners' Association.

    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Elisabeth Grieg is a Norwegian citizen, and she lives in Norway. She is a part-owner of the family company Grieg Maturitas AS, which indirectly owns 20% of AON Grieg AS. In 2009 AON Grieg AS acted as a broker for Statoil, for which Statoil paid fees totalling NOK 6,178,373.81. In addition, Grieg Maturitas AS and other family companies own a direct and indirect interest of 75% in Grieg Logistics AS. Grieg's husband, Stig Grimsgaard Andersen, is a member of the board of Grieg Logistics AS. Grieg Logistics AS delivered logistics and transport services to Statoil in 2009, for which it received fees totalling NOK 112,412,045.

    Jakob Stausholm

    

    Position: Board member and member of the board's audit committee.
    Born: 1968
    Term of office: Member of the board of Statoil ASA since July 2009.
    Independent: Yes
    Other directorships: No
    Number of shares in Statoil ASA as of 31 December 2009: None
    Loans from Statoil: None
    Experience: Stausholm is the chief financial officer of the global facility services provider ISS A/S.
    Before joining ISS's corporate executive committee in 2008, he was employed by the Shell Group for 19 years and held a number of management positions, inter alia as vice president finance for the group's exploration and production in Asia and the Pacific, as chief internal auditor, and various senior finance positions in Europe and Latin America.
    Education: M.Sc. in economics from the University of Copenhagen.
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Jakob Stausholm is a Danish citizen and he lives in Denmark.

    Grace Reksten Skaugen

    

    Position: Board member and member of the board's compensation committee.
    Born: 1953
    Term of office: Member of the board of Statoil ASA since 2002.
    Independent: Yes
    Other directorships: Chair of the boards of Entra Eiendom AS, Ferd Holding and Norsk Institutt for Styremedlemmer, and member of the boards of REC ASA and the Swedish listed company Investor AB.
    Number of shares in Statoil ASA as of 31 December 2009: 400
    Loans from Statoil: None
    Experience: Self-employed business consultant, director in corporate finance in Enskilda Securities in Oslo from 1994 to 2002. Has also worked with venture capital and shipping in Oslo and London and carried out research in microelectronics at Columbia University in New York.
    Education: She has a doctorate in laser physics from the Imperial College of Science and Technology at the University of London and an MBA from the Norwegian School of Management (BI).
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Grace Reksten Skaugen is a Norwegian citizen and she lives in Norway.

    Lill-Heidi Bakkerud

    

    Position: Employee-elected member of the board.
    Born: 1963.
    Term of office: Member of the board of Statoil ASA from 1998 to 2002, and again since 2004.
    Independent: No
    Other directorships: Bakkerud is a member of the executive committee of the Industry Energy (IE) trade union and holds several offices as a result of this.
    Number of shares in Statoil ASA as of 31 December 2009: 300
    Loans from Statoil: None
    Experience: She has worked as a process technician at the petrochemical plant in Bamble and on the Gullfaks field in the North Sea. She is now a full-time employee representative as the leader of IE Statoil branch.
    Education: Has a craft certificate as a process/chemistry worker.
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Lill-Heidi Bakkerud is a Norwegian citizen, and she lives in Norway.

    Morten Svaan

    

    Position: Employee-elected member of the board and member of the board's audit committee.
    Born: 1956
    Term of office: Member of the board of Statoil ASA since 2002.
    Independent: No
    Other directorships: None
    Number of shares in Statoil ASA as of 31 December 2009: 1,245
    Loans from Statoil: None
    Experience: Svaan has worked for Statoil since 1985. He now works on health, safety and the environment (HSE) for the Technology & New Energy business area, largely focusing on security and emergency response. Svaan was chief employee representative for the Statoil branch of the NIF/Tekna trade union from 2000 until 2004.
    Education: He holds a PhD in chemistry from the Norwegian University of Science and Technology and a degree in business economics from the Norwegian School of Management (BI).
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Morten Svaan is a Norwegian citizen, and he lives in Norway.

    Einar Arne Iversen

    

    Position: Employee-elected member of the board.
    Born: 1962
    Term of office: Member of the corporate assembly of Statoil ASA from 2000 to 2009. Member of the board of Statoil ASA since June 2009.
    Independent: No
    Other directorships: None
    Number of shares in Statoil ASA as of 31 December 2009: 2,561
    Loans from Statoil: As of 31 December 2009: an employee loan amounting to NOK 153,880.02 and a car loan totalling NOK 178,886. Both loans were taken up prior to Iversen's election to the board of Statoil ASA. As of 15 March 2010, both loans have been settled.
    Experience: Iversen joined Statoil in 1986, worked on technical training in Bergen and was training manager at Tjeldbergodden. He has held the offices of deputy secretary-general and secretary-general of the NITO trade union since 1998.
    Education: Engineer, NKI Technical College.
    Family relations: No family relations to other members of the board, members of the corporate executive committee or the corporate assembly.
    Other matters: Einar Arne Iversen is a Norwegian citizen, and he lives in Norway.

     Top 

    7.6.1 Audit committee

    The board elects at least three of its members to serve on the audit committee and appoints one of them to act as chair. The employee representatives on the board may nominate one committee member.

    The current members of the audit committee are Roy Franklin (chair), Marit Arnstad, Jakob Stausholm and Morten Svaan (employee representative).

    The board of directors' audit committee (audit committee) is a sub-committee of the board of directors (board) and its objective is to act as a preparatory body in connection with the board's supervisory roles with respect to financial reporting and the effectiveness of the company's internal control system, and other tasks assigned to the audit committee in accordance with the provisions herein. The audit committee is instructed to assist the board in its supervising of issues such as:

    • monitoring the financial reporting process, including reviewing implementation of accounting principles and policies
    • monitoring the effectiveness of the company's internal control, internal audit and risk management systems
    • maintaining continuous contact with the statutory auditor regarding the annual and consolidated accounts
    • reviewing and monitoring the independence of the company's internal auditor and the independence of the statutory auditor, ref. the Statutory Auditor law, chapter 4 and, in particular, whether other services than audits delivered by the statutory auditor or the audit firm are a threat to the statutory auditor's independence.

    The audit committee supervises implementation of and compliance with the group's Ethics Code of Conduct and supervises 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.

    Under Norwegian law, the external auditor is elected by the shareholders at the annual general meeting. The audit committee makes a recommendation to the board concerning the appointment of the external auditor based on its evaluation of the qualifications and independence of the auditor proposed for election or re-election. The audit committee meets at least five times a year, and it 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 shall ensure that the company has procedures in place for receiving and dealing with complaints received by the company regarding accounting, internal control or auditing matters, and for the confidential and anonymous submission, via the group's ethics helpline, by company employees of concerns regarding accounting or auditing matters as well as other matters regarded as being in breach of the group's Ethics Code of Conduct or statutory provisions. The audit committee is designated as the company's qualified legal compliance committee for the purposes of section 307 of the Sarbanes-Oxley Act of 2002.

    The audit committee may examine all activities and circumstances relating to the operations of the company in the execution of its tasks. In this connection, the audit committee may request the chief executive officer or any other employee to give it access to information, facilities and personnel and such assistance as it requests. The audit committee is authorised to carry out or instigate such investigations as it deems necessary in order to carry out its tasks and it may use the company's internal audit or investigation unit, the external auditor or other external advice and assistance. The costs of such work will be covered by the group.

    The audit committee is responsible to the board only for the execution of its tasks. The work of the audit committee in no way alters the responsibility of the board and its individual members, and the board retains full responsibility for the audit committee's tasks.

    The audit committee held six meetings in 2009. There was 95% attendance at the committee's meetings.

    The committee's mandate is available at www.statoil.com/auditcommittee.

     Top 

    7.6.1.1 Audit committee financial expert

    The board of directors has decided that a member of the audit committee, Jakob Stausholm, qualifies as an "audit committee financial expert", as defined in Item 16A of Form 20F.

    The board of directors has also concluded that Jakob Stausholm is independent within the meaning of Rule 10A-3 under the Securities Exchange Act.

     Top 

    7.6.2 Compensation committee

    The compensation committee is a sub-committee of the board of directors that assists the board of directors on matters relating to management compensation and leadership development.

    The compensation committee is a sub-committee of the board of directors and its main responsibilities are:

    (1) as a preparatory body for the board, to make recommendations to the board in all matters relating to principles for executive rewards, remuneration strategies and concepts, the CEO's contract and terms of employments and leadership development, assessments and succession planning

    (2) to be informed about and advise the company's management in its work on Statoil's remuneration strategy and in drawing up appropriate remuneration policies for senior executives, and

    (3) to review Statoil's remuneration policies in order to safeguard the owners' long-term interests.

    The committee consists of four board members. At year end 2009, the committee members were Grace Reksten Skaugen (chair), Svein Rennemo, Elisabeth Grieg and Kjell Bjørndalen. All of the committee members are independent, non-executive directors.

    The committee held eight meetings in 2009. There was 81% attendance at the committee's meetings.

    The committee's mandate is available at www.statoil.com/CompensationCommittee

     Top 

    7.7 Compliance with NYSE listing rules

    Statoil's primary listing is on the Oslo Stock Exchange (Oslo Børs). Consequently Statoil's corporate governance practices follow the requirements of Norwegian law [and the Oslo Stock Exchange]. Statoil is also registered as a foreign private issuer with the US Securities and Exchange Commission with American Depositary Shares representing its Ordinary Shares listed on the New York Stock Exchange (NYSE). Therefore, Statoil is also subject to the NYSE's listing rules ("NYSE rules"). As a foreign private issuer, Statoil is exempt from most of the NYSE corporate governance standards that domestic US companies must follow. However, Statoil is required to disclose any significant ways in which its corporate governance practices differ from those applicable to domestic US companies under the NYSE rules. A statement of differences is set forth below:

    Corporate governance guidelines
    The NYSE rules require domestic US companies to adopt and disclose corporate governance guidelines. Statoil's corporate governance principles are developed by management and the board of directors. Oversight of the board of directors and management is exercised by the corporate assembly.
      
    Director independence
    The NYSE rules require domestic US companies to have a majority of "independent directors", as defined by the NYSE rules. The NYSE definition of an "independent director" sets out five specific independence tests and also requires an affirmative determination by the board of directors that the director has no material relationship with the company.

    Pursuant to Norwegian company law, Statoil's board of directors consists of members elected by shareholders and employees. Statoil's board of directors has determined that, in its judgement, all of the shareholder-elected directors are independent. In making its independence determinations, the board focuses on there not being any conflicts of interest between shareholders, the board of directors and the company's management but does not explicitly take into consideration the NYSE's five specific tests. The directors elected from among Statoil's employees would not be considered independent under the NYSE rules because they are employees of Statoil. None of the employee-elected directors is an executive officer of the company.

    Board committees
    Pursuant to Norwegian company law, managing the company is the responsibility of the board of directors. Statoil has an audit committee and a compensation committee that are responsible for preparing certain issues for the board of directors. The committees operate pursuant to charters that are broadly comparable to the form required by the NYSE rules. They report on a regular basis to, and are subject to, continuous oversight by the board of directors.

    Statoil complies with the NYSE rule regarding the obligation to have an audit committee that meets the requirements of Rule 10A-3 of the US Securities Exchange Act of 1934.

    As required by Norwegian company legislation, the members of Statoil's audit committee include an employee-elected director. Statoil relies on the exemption provided for in Rule 10A-3(b)(1)(iv)(C) from the independence requirements of the US Securities Exchange Act of 1934 with respect to the employee-elected director. Statoil does not believe that its reliance on this exemption will materially adversely affect the ability of the audit committee to act independently or to satisfy the other requirements of Rule 10A-3 relating to audit committees. The other members of the audit committee meet the independence requirements under Rule 10A-3.

    Among other things, the audit committee evaluates the qualifications and independence of the company's external auditor. However, in accordance with Norwegian law, the auditor is elected by the annual general meeting of the company's shareholders.

    The Statoil Board of Directors does not have a nominating/corporate governance board sub-committee. Instead, the roles prescribed for a nominating/corporate governance committee under the NYSE rules are principally carried out by the corporate assembly and the election committee.

    Shareholder approval of equity compensation plans
    The NYSE rules require that, with limited exemptions, all equity compensation plans be subjected to a shareholder vote. Although the issuance of shares and authority to buy back company shares must be approved by Statoil's annual general meeting of shareholders under Norwegian company law, approval of equity compensation plans is normally reserved for the board of directors.

     Top 

    7.8 Management

    The president and CEO has overall responsibility for day-to-day operations in StatoilHydro,Statoil and also appoints the corporate executive committee (CEC). Each of the CEC members heads separate business areas or staff functions.

    The president and CEO has overall responsibility for day-to-day operations in StatoilHydro.Statoil. The president and CEO is responsible for developing StatoilHydro'sStatoil's business strategy and presenting it to the board of directors for decision, for the development and execution of the business strategy, and for nurturing a performance-driven, value-based culture.

    The president and CEO appoints the corporate executive committee (CEC). Members of the CEC have a collective duty to safeguard and promote theStatoil's corporate interests of StatoilHydro and to provide the president and CEO with the best possible basis for settingdeciding the company's direction, making decisions and ensuring execution and follow-up of business activities. In addition, each of the CEC members heads separate business areas or staff functions.

    Members of StatoilHydro'sStatoil's corporate executive committee

    Helge Lund
    
    Helge Lund. Chief executive officer
    

    

    Born: 1962
    Position: CEO of Statoil fromASA since August 2004, CEO of StatoilHydro since 1 October 20072004.
    External offices: None
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008:2009: 13,85723,515
    Loans from StatoilHydro:Statoil: None
    Experience: Came to Statoil from the position of CEO in Aker Kværner ASA. Held central managerial positions in the Aker RGI system from1999. Has been political adviser to the Conservative Party of Norway's parliamentary group, a consultant with McKinsey & Co and Deputy Managing Directordeputy managing director of Nycomed Pharma ASAS.
    Education: MA in business economics (siviløkonom) from the Norwegian School of Economics and Business Administration (NHH) in Bergen and Master of Business Administration (MBA) from INSEAD in FranceFrance.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assemblycorporate assembly.
    Other matters: Helge Lund is a Norwegian citizen, and he lives in NorwayNorway.

    Eldar Sætre
     
    Eldar Sætre. Chief financial officer
    

    

    Born: 1956
    Position: CFO of Statoil fromASA since October 2003. CFO of StatoilHydro since 1 October 2007.
    External offices: Member of the board of directors of Strømberg Gruppen AS.
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008:2009: 6,0579,644
    Loans from StatoilHydro:Statoil: None
    Experience: He worked forjoined Statoil fromin 1980 and has since held several management positions in the group, mainly in the fields of accounting and finance.
    Education: MA in business economics (siviløkonom) from the Norwegian School of Economics and Business Administration in Bergen.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Eldar Sætre is a Norwegian citizen, and he lives in Norway.
    
    

    Øystein Michelsen
     
    Executive vice president, Exploration & Production Norway
    

    

    Born: 1956
    Position: Executive vice president in StatoilHydroStatoil ASA since 10 November 20082008.
    External offices: Board memberMember of Unifob (university research companythe board in Bergen) and OLF (theOljeindustriens Landsforening (OLF, the Norwegian Oil Industry Association)
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008:2009: 2,0405,866
    Loans from StatoilHydro:Statoil ASA: None
    Experience: Recruited to Hydro's research centre in Porsgrunn in 1981, he was attached to Hydro Oiloil and Energyenergy division from 1985, and was head of the operations unit for Hydro's oil activities from 2004. He has been senior vice president for StatoilHydro'sStatoil's Operations North cluster since 1 October 2007.
    Education: MA in engineering (sivilingeniør) from the Norwegian Institute of Technology (NTH) in Trondheim.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Øystein Michelsen is a Norwegian citizen, and he lives in Norway.
    
    

    Peter Mellbye
     
    Executive vice president, International Exploration & Production
    

    

    Born: 1949
    Position: Executive vice president in Statoil fromASA since 1992. Executive vice president in StatoilHydro since 1 October 2007.
    External offices: Member of the board of the Energy Policy Foundation of Norway (EPF).
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008:2009: 7,90612,170
    Loans from StatoilHydro:Statoil: None
    Experience: Worked for the Ministry of Trade and the Norwegian Export Council before joining Statoil in 1982. Held several central management positions in Statoil. Executive vice president of Natural Gas from 1992 to 2004.
    Education: Cand. polit. degree from the University of Oslo.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assemblycorporate assembly.
    Other matters: Peter Mellbye is a Norwegian citizen, and he lives in NorwayNorway.

    Rune Bjørnson
     
    Executive vice president, Natural Gas
    

    

    Born: 1959
    Position: Executive vice president in Statoil fromASA since 2004. Executive vice president in StatoilHydro since 1 October 2007.
    External offices: None.None
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008:2009: 4,351.7,853
    Loans from StatoilHydro:Statoil: None.None
    Experience: He has worked for Statoil from 1985,since1985, holding various management positions in the Natural Gas business area. He was vice president in Statoil UKU.K. Ltd. from 2001 to 2003.
    Education: Cand. polit. degree from the University of Bergen.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Rune Bjørnson is a Norwegian citizen, and he lives in Norway.

    Jon Arnt Jacobsen
     
    Executive vice president, Manufacturing & Marketing
    

    

    Born: 1957
    Position: Executive vice president in Statoil fromASA since 2004. Executive vice president in StatoilHydro since 1 October 2007.
    External offices: None.Member of the board of Storebrand ASA.
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008:2009: 7,16410,982
    Loans from StatoilHydro:Statoil: None.None
    Experience: Worked for Den norske Bank (DnB) for 13 years, where he held positions including General Managergeneral manager and head of DnB's Singapore branch. Group Finance Directorfinance director of Statoil from 1998 to 2004.
    Education: MA in business economics (siviløkonom) from the Norwegian School of Management (BI) in Oslo and Master of Business Administration (MBA) from the University of Wisconsin.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Jon Arnt Jacobsen is a Norwegian citizen, and he lives in Norway.
    
    

    Gunnar Myrebøe
     
    Executive vice president, Projects
    

    

    Born: 1949
    Position: Executive vice president in StatoilHydroStatoil ASA since 10 November 2008.
    External offices: None.None
    Number of shares in StatoilHydro ASApr.Statoil ASA as of 31 December 2008:2009: 2,726.5,595
    Loans from StatoilHydro:Statoil: None.None
    Experience: Worked for Phillips Petroleum before joining Statoil in 1981. Among other things, he was in charge of project development for the Sleipner condensate project, was responsible for gas technology in the Natural Gas business area, washas been project director for Norfra (Franpipe) and was head of Statoil research and technology.
    From 2003 to 2007, Mr Myrebøe led the development of the offshore part of Snøhvit and, since the merger between Statoil and Hydro, he has been responsible for offshore modifications in the Projects business area.
    Education: Graduated with a Master of Science degree (sivilingeniør) from the Norwegian University of Science and Technology (NTNU) in 1973.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Gunnar Myrebøe is a Norwegian citizen, and he lives in Norway.
    
    

    Margareth Øvrum
     
    Executive vice president, Technology & New Energy
    

    

    Born: 1958
    Position: Executive vice president in Statoil fromASA since September 2004. Executive vice president in StatoilHydro since 1 October 2007.
    External offices: Board memberMember of Elkemthe board of Atlas Copco AB, Ratos AB and the Research Council of NorwayNorway.
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008: 7,9772009: 12,031
    Loans from StatoilHydro:Statoil: None
    Experience: SheØvrum has worked for Statoil from 1982since1982 and has held central management positions in the company, including the position of executive vice president for health, safety and the environment and executive vice president for Technologytechnology & Projects.projects. She was the company's first female platform manager, on the Gullfaks field. She was senior vice president for operations for Veslefrikk and vice president of operations support for the Norwegian continental shelf.
    Education: MA in engineering (sivilingeniør) from the Norwegian Institute of Technology (NTH) in Trondheim, specialising in technical physics.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Margareth Øvrum is a Norwegian citizen, and she lives in Norway.
    
    

    Helga Nes
    
    Executive vice president, Corporate Staffs & Services
    

    

    Born: 1956
    Position: Executive vice president in StatoilHydroStatoil ASA since 10 November 2008.
    External offices: None.None
    Number of shares in StatoilHydroStatoil ASA pr.as of 31 December 2008: 1,3972009: 3,616
    Loans from StatoilHydro:Statoil: None
    Experience: Ms Nes worked for Hydro from 1984, as a process engineer, quality manager and head of staff, among other positions. Ms Nes was responsible for HSE and HR in exploration and development in Hydro's Oiloil and Energyenergy division from 2002 to 2004, and IT director from 2004 to 2007.
    From 2007, Ms Nes was in charge of HSE and HR in the Projects business area in StatoilHydro.Statoil.
    Education: Cand. real degree in organic chemistry from the Norwegian University of Science and Technology (NTNU) and a Master of Business Administration from the Norwegian BI Norwegian School of Management.
    Family relations: No family relations to other members of the Corporate Executive Committee,CEC, members of the Boardboard or the Corporate Assembly.corporate assembly.
    Other matters: Helga Nes is a Norwegian citizen, and she lives in Norway.

     Top 

    7.7 Nomination committee

    In accordance with StatoilHydro's articles of association the nomination committee (referred to as the election committee in the articles of association) consists of four members who are shareholders, or representatives of shareholders.

    The committee is independent of both the board and the company's management.

    The duties of the nomination committee are:

    • to present recommendations7.9 Compensation to the AGM for the election of shareholder-elected members and deputy members of the Corporate Assembly
    • to present recommendations to the corporate assembly for the election of shareholder-elected membersgoverning bodies

      This section details compensation paid to the board of directors,

    • the corporate executive committee and the corporate assembly.

      In 2009, aggregate compensation totalling NOK 880,174 was paid to present a proposalthe members of the corporate assembly, NOK 4,437,000 to the members of the board of directors and NOK 45,479,000 to the members of the corporate executive committee.

      Detailed information about the individual compensation of the members of the board of directors and the members of the corporate executive committee in 2009 is provided in the tables below.

      Members of the board (In NOK thousand)	Board remuneration	Audit committee	Compensation committee	Total remuneration
      Rennemo Svein	590	0	63	653
      Arnstad Marit	375	105	0	480
      Skaugen Grace R	300	0	90	390
      Grieg Elisabeth	300	0	63	363
      Svaan Morten	300	105	0	405
      Bjørndalen Kjell	300	0	56	356
      Franklin Roy	462	145	0	607
      Bakkerud Lill-Heidi	300	0	0	300
      Stausholm Jakob *	150	55	0	205
      Iversen Einar Arne **	162	0	0	162
      Nilsen Geir ***	138	0	0	138
      Clausen Claus ****	138	0	0	138
      Nielsen Kurt Anker *****	68	34	0	102
      Fritsvold Ragnar Per ***	138	0	0	138
      Total	3721	444	272	4437
      * Member since 2 July 2009
      ** Member since 17 June 2009
      *** Observer until 17 June 2009
      **** Member until 17 June 2009
      ***** Member until 24 March 2009

      Management remuneration in 2009 (in NOK thousand)
      	Fixed remuneration
      Members of Corporate Executive Committee 1)	Base pay 2)	LTI 3)	Bonus 4)	Taxable benefits in kind	Taxable reimbursements	Taxable salary	Non-taxable benefits in kind	Non-taxable reimbursements	Non-taxable salary	Total remuneration	Estimated pension cost 5)	Estimated present value of pension obligation
      Lund Helge (CEO)	6495	1890	1500	338	19	10242	485	19	504	10746	3950	21254
      Bjørnson Rune (Executive vice president (E.V.P.), Natural Gas)	2507	600	540	221	20	3888	0	25	25	3913	767	18668
      Jacobsen Jon Arnt (E.V.P, Manufacturing & Marketing)	2874	669	361	68	8	3980	0	37	37	4017	1398	16147
      Mellbye Peter (E.V.P, International Exploration & Production)	3787	813	731	205	20	5556	9	31	40	5596	1339	37287
      Sætre Eldar (CFO)	2927	713	712	162	31	4545	178	25	203	4748	870	25595
      Øvrum Margareth (E.V.P, Technology & New Energy)	2771	694	624	55	13	4157	0	48	48	4205	902	25243
      Nes Helga (E.V.P, Staff functions & corporate services)	2271	550	365	176	39	3401	181	17	198	3599	684	17150
      Michelsen Øystein (E.V.P, Exploration & Production Norway)	3220	750	481	217	6	4674	280	23	303	4977	749	21378
      Myrebø Gunnar (E.V.P, Projects & Procurement)	2419	575	324	45	5	3368	299	11	310	3678	732	21463
      Total	29271	7254	5638	1487	161	43811	1432	236	1668	45479	11391	204185
      1) In addition to remuneration to the members of the Corporate Executive Committee, a final payment to former E.V.P, Staff functions & corporate services, Hilde Merete Aasheim, was made during 2009. The payment covered vacation
      pay and value of unused vacation days. Total remuneration for Mrs. Aasheim during 2009 was NOK 416 thousand.
      2) Base pay consists of base salary, holiday allowance and any other administrative benefits.
      3) Fixed long-term incentive (LTI) element. The LTI implies an obligation to invest the net amount in Statoil shares. A lock-in period of 3 years applies for the investment.
      4) Bonus paid in 2009 is related to the period 1 October 2007 to 31 December 2008 due to the merger between Statoil and Hydro Oil and gas effective from 1 October 2007.
      5) Pension cost is calculated based on actuarial assumptions and pensionable salary at 31 December 2009 and will be recognised as pension cost in the Statement of Income in 2010. Payroll tax is not included.

      Statoil's remuneration policy 
      Statoil's remuneration policy is strongly linked to the company's people policy and core values. Certain key principles have been adopted for the design of the company's remuneration concept. These principles pertain in general but they are applied differently for the different remuneration systems and job categories.

      The remuneration concept is an integrated part of our values-based performance framework. It shall:

      • reflect our competitive market strategy and local market conditions
      • strengthen the common interests of people in the Statoil group and shareholders
      • be in accordance with statutory regulations and good corporate governance
      • be fair, transparent and non-discriminatory
      • reward and recognise delivery and behaviour equally
      • differentiate on the basis of responsibilities and performance
      • reward both short and long-term contributions and results.

      Our rewards and recognition policy is designed to attract and retain the right people - people who perform, change and learn. The overall remuneration level and composition of rewards reflect the national and international framework and business environment within which Statoil operates.

      The decision-making process
      The decision-making process for implementing or changing remuneration policies and concepts and determining salaries and other remuneration for the corporate executive committee is in accordance with the provisions of the Norwegian Public Limited Liability Companies Act sections 5-6, 6-14, 6-16 a) and the board's Rules of Procedures as last amended on 31 July 2008.

      The remuneration concept for the corporate executive committee
      Statoil's remuneration concept for the corporate executive committee consists of the following main elements:

      • Fixed remuneration
      • Variable pay
      • Pensions and insurance schemes
      • Severance pay arrangements
      • Other benefits.

      Fixed remuneration
      Fixed remuneration consists of the base salary and a long-term incentive.
         
      Base salary
      The base salary shall be competitive in the markets in which the company operates and shall reflect the individual's responsibility and performance. The evaluation of performance is based on fulfilment of certain pre-defined goals; see "Variable pay" below. The base salary is normally reviewed once a year.

      Long-term incentive (LTI)
      Statoil will continue its established long-term incentive system for a limited number of senior managers, including the members of the corporate executive committee.

      The long-term incentive system is a fixed, monetary compensation calculated as a percentage of the participant's base salary, ranging from 20 to 30 per cent depending on the participant's position. The participant is obliged to use the fixed LTI amount (after tax) to buy Statoil shares on the market every year and to hold the shares for a lock-in period of three years.

      The long-term incentive and the annual variable pay system constitute a remuneration concept that focuses on both short and long-term goals and results. The long-term incentive contributes to strengthening the commonality of interest between the top management and the shareholders of Statoil.
         
      Variable pay
      The intention is to continue the company's variable pay concept in 2010.Based on performance, the chief executive officer is entitled to annual variable pay with a maximum potential of 50 per cent of the fixed remuneration. The executive vice presidents have an equivalent variable pay scheme with a maximum potential of 40 per cent.

      In order to obtain an improved distribution of the annual variable pay budget, and to underpin a drive towards an even stronger performance, it has been decided to adjust the pay out level for performance at target from 67 per cent to 50 per cent of the maximum potential.

      Remuneration policies' effect on risk
      The remuneration concept is an integrated part of our performance management system. It is an overarching principle that there should be a close link between performance and remuneration.

      Individual salary and annual variable pay reviews are based on the performance evaluation in our performance management system. However, participation in the long-term incentive (LTI) scheme and the size of the annual LTI element are not based directly on performance but are linked to the level of the position in question.

      The goals that form the basis for performance assessment are established between the manager and the employee as part of our performance management process. The performance goals have two dimensions: delivery and behaviour, where delivery and behaviour are equally important and given equal weight. Delivery goals are established for each of the five perspectives: finance, operations, market, HSE, people and organisation. In each perspective, both longer-term strategic objectives and shorter-term key performance indicators (KPI) are set, as well as actions to be executed. Some of these actions will be risk-mitigating actions derived from strategic or operational risk assessments. Behaviour goals are based on Statoil's core values and leadership principles. They address the behaviour required and expected in order to achieve our delivery goals.

      Performance evaluation is a holistic evaluation that combines measurement and assessment of performance against both delivery and behaviour goals. The KPIs are used as indicators only. Hence, sound judgement and hindsight are applied before final conclusions are drawn. For instance KPI results are reviewed in relation to their strategic contribution, sustainability and any significant changes in assumptions.

      This balanced score card approach, with goals defined in both the delivery and behaviour dimension, and holistic performance evaluation should significantly reduce the risk that our remuneration policies are likely to have a material adverse effect.

      One of several targets in the performance contracts of the chief executive officer and chief financial officer is related to the company's relative total shareholder return (TSR). The amount of annual variable pay is decided on the basis of an overall assessment of the achievement of various targets including, but not limited to, the company's relative TSR.

       Top 

      7.10 Share ownership

      This section describes the number of Statoil shares owned by the members of the board of directors and the corporate assembly.

    executive committee.

    A form for shareholders' nominationThe number of candidates are made available in connection with nomination toStatoil shares owned by the members of the board of directors.

    The membersdirectors and the executive committee and/or owned by their close associates is shown below. Individually, each member of the nominationboard of directors and the corporate executive committee are elected by the AGM. Twoowned less than 1% of the members are elected from amongoutstanding Statoil shares.

    Ownership of Statoil shares (including share ownership of "close associates")	As of  31 December 2009	As of 12 March 2010
    Members of the Corporate Executive Committee
    Helge Lund	23515	24912
    Eldar Sætre	9644	10365
    Margareth Øvrum	12031	12689
    Rune Bjørnson	7853	8476
    Jon Arnt Jacobsen	10982	11699
    Peter Mellbye	12170	13033
    Øystein Michelsen	5866	5866
    Gunnar Myrebøe	5595	5918
    Helga Nes	3616	3647
    Members of the Board of Directors
    Svein Rennemo	10000	10000
    Marit Arnstad	0	0
    Elisabeth Grieg	33108	33108
    Kjell Bjørndalen	0	0
    Grace Reksten Skaugen	400	400
    Jakob Stausholm	0	0
    Roy Franklin	0	0
    Lill-Heidi Bakkerud	330	330
    Morten Svaan	1245	1326
    Einar Arne Iversen	2561	2740

    Individually, each member of the shareholder-electedcorporate assembly owned less than 1% of outstanding Statoil shares as of 31 December 2009 and as of 12 March 2010. In aggregate, members of the corporate assembly. Membersassembly owned a total of 5,841 shares as of 31 December 2009 and a total of 6,627 shares as of 12 March 2010. Information about the nomination committee are elected for a termindividual share ownership of two years.

    Thethe members of the nomination committee are:

    • Olaug Svarva (chair), managing director, Folketrygdfondet
    • Gro Bækken, secretary general, Savecorporate assembly is presented in the Children Norway
    • Tom Rathke, managing director, Vital Forsikring and Executive Vice President, DnB NOR
    • Bjørn Ståle Haavik, acting secretary general, Ministry of Petroleum and Energy

    The nomination committee held 8 meetings in 2008.section 7.5 Corporate governance - Corporate assembly.

    The rulesvoting rights of procedure formembers of the nominationboard of directors, the corporate executive committee are accessible at http://www.statoilhydro.com/en/AboutStatoilHydro/CorporateGovernance/GoverningBodies/ElectionCommittee/Pages/default.aspx.and the corporate assembly do not differ from those of ordinary shareholders.

     Top 

    7.8 7.11 Independent auditor

    This section provides details about the independent auditor, and about policies, procedures and remuneration relating to the auditor.

    Our independent registered public accounting firm (independent auditor) is independent in relation to StatoilHydroStatoil and is appointed by the general meeting of shareholders. The independent auditor's fee must be approved by the general meeting.meeting of shareholders.

    Pursuant to the rulesinstructions for the board's audit committee (audit committee) approved by the board of procedure,directors, the board's audit committee is responsible for ensuring that the company is subject to an independent and effective external and internal audit.

    Every year, the independent auditor presents a plan for the audit committee for the execution of the independent auditor's work.

    The independent auditor is present at the board meeting that deals with the preparation of the annual accounts.

    The independent auditor participates in meetings with the audit committee at which the internal control system is discussed.

    When evaluating the independent auditor, emphasis is placed on the firm's competence,qualifications, capacity, local and international availability and the size of the fee.

    The board's audit committee evaluates and makes a recommendation regarding the choice of independent auditor and it is responsible for ensuring that the independent auditor meets the requirements of the authorities in Norway and in the countries where StatoilHydroStatoil is listed on the stock exchange.listed. The independent auditor is subject to the provisions of US securities legislation, which stipulate that a responsible partner may not lead the engagement for more than five consecutive years.

    The board's audit committee considers all reports from the independent auditor before they are considered by the board of directors. The audit committee holds regular meetings with the externalindependent auditor without the company's management being present.

    Audit Committee Pre-approval PoliciesThe audit committee's policies and Proceduresprocedures for pre-approval
    In its instructions for the audit committee, the board of directors has delegated to the audit committee the authority to pre-approve assignments to be performed by the independent auditor. The audit committee has issued guidelines for the management's pre-approval of assignments to be performed by the independent auditor.

    All services provided by the independent auditor must be pre-approved by the audit committee. Provided that the suggested types of services are permissible under SEC guidelines, pre-approval is usually granted inat a regular audit committee meeting. The Chairmanchair of the audit committee has been given the authorityauthorised to pre-approve services according tothat are in accordance with policies established by the audit committee specifyingthat specify in detail the types of services qualifying, providedthat qualify. It is a condition that any services pre-approved in this manner are presented to the full audit committee at its next meeting. Some pre-approvals maycan therefore be granted by the Chairmanchair of the audit committee if an urgent reply is deemed necessary.

    Remuneration toof the independent auditor in 20082009
    In the annual consolidated financial statements and in the parent company's financial statements, the independent auditor's remuneration is split between the audit fee and the fee for audit-related and other services. The chair presents the split between the audit fee and the fee for audit-related and other sevices to the annual general meeting of shareholders.

    Ernst & Young AS is the company's independent registered public accounting firm. The table below itemises the expensed remuneration paid to the external auditor in 2009, 2008 (andand 2007, and 2006, respectively):respectively:

    		Audit related and Other service fees *			Audit related fee	Other service fee
    (in NOK million, excluding VAT)	Audit fee		Total	Audit fee			Total
    2009
    Ernst & Young - Norway				34.2	5.3	3.7	43.2
    Ernst & Young - outside Norway				27.1	1.5	0.9	29.5
    Total				61.3	6.8	4.6	72.7
    2008
    Ernst & Young - Norway	35.0	5.0	40.0	35.0	4.9	0.1	40.0
    Ernst & Young - outside Norway	25.3	3.9	29.2	25.3	3.8	0.1	29.2
    Total	60.3	8.9	69.2	60.3	8.7	0.2	69.2
    2007
    Ernst & Young - Norway	20.7	7.4	28.1	20.7	7.3	0.1	28.1
    Ernst & Young - outside Norway	24.1	1.1	25.2	24.1	0.8	0.3	25.2
    Total	44.8	8.5	53.3	44.8	8.1	0.4	53.3
    2006
    Ernst & Young - Norway	15.9	4.2	20.1
    Ernst & Young - outside Norway	19.9	2.4	22.3
    Total	35.8	6.6	42.4
    * Included in the amount for 2008 is NOK 0.4 million related to miscellaneous services at several locations.

    All fees included in the table were approved by the audit committee.

    Audit Servicesservices are defined as the standard audit work that needs tomust be performed eachevery year in order to issue an opinion on theStatoil's consolidated financial statements of StatoilHydro, and to issue reports on the IFRSsIFRS's statutory financial statements. It also includes other audit services, which are those services that only the independent auditor can reasonably can provide, such as auditing of non-recurring transactions and the application of new accounting policies, audits of significant and newly implemented system controls and limited reviews of quarterly financial results.

    Audit Related ServicesAudit-related services include those other assurance and related services provided by auditors, but not restricted to those that can only reasonably be provided by the external auditor signingwho signs the audit report, that are reasonably related to the performance of the audit or review of the company's financial statements, such as acquisition due diligence, audits of pension and benefit plans, consultations concerning financial accounting and reporting standards.

    In addition toOther services include services provided by the figures inauditors within the table above, we paid an audit fee and otherframework of Sarbanes Oxley Act, i.e. certain agreed upon procedures.

    Audit fees to Deloitte amounting to NOK 39.48.9 million, NOK 8.5 million and NOK 5.66.1 million for 2007 and 2006, while audit feesrelating to Statoil-operated licences were paid to Ernst & Young relating to StatoilHydro-operated licences amounted to NOK 8.5, NOK 6.1 and NOK 4.0 million for the years 2009, 2008 and 2007, and 2006, respectively. These fees are in addition to the figures in the table above.

    The increasesincrease in audit fees and audit related and other fees from 2006 to 2007 and from 2007 to 2008 arewere mainly due to the increase in activity in connection with the merger with Hydro Petroleum.

     Top 

    7.9 Compensation to the governing bodies

    This section details compensation paid to the board of directors, corporate executive committee and corporate assembly.

    In 2008, aggregate compensation totalling NOK 828,660 was paid to the members of the corporate assembly, NOK 4,572,000 to the members of the board of directors, NOK 43,233,000 to the members of the corporate executive committee.

    Detail information about the individual compensation of members of the board of directors and the members of the corporate executive committee in 2008 is given in the tables below.

    Members of the board (In thousand NOK)	Board remuneration	Audit committee	Compensation committee	Total remuneration
    Rennemo Svein*	440	0	14	454
    Arnstad Marit**	417	100	0	517
    Skaugen Grace R	294	0	50	344
    Grieg Elisabeth	294	0	28	322
    Svaan Morten	294	100	0	394
    Bjørndalen Kjell	294	0	35	329
    Nielsen Kurt Anker	294	150	0	444
    Fritsvold Ragnar Per	294	0	0	294
    Franklin Roy	492	100	0	592
    Nilsen Geir	294	0	0	294
    Clausen Claus	294	0	0	294
    Bakkerud Lill-Heidi	294	0	0	294
    Total	3995	450	127	4572
    * Chair of the Board from 1 April 2008
    ** Acting chair of the Board from 1 January through 31 March 2008

    Members of Corporate Executive Committee	Fixed Salary 2)	LTI 3)	Bonus 4)	Benefits in kind	Taxable reimburse- ments	Taxable salary	Benefits in kind	Re-imbur-sements	Non taxable salary	Total Remuneration	Pension cost 5)	Pension obligation
    Lund Helge (CEO)	6,847	1,890	550	369	21	9,677	479	17	496	10,173	5,317	22,289
    Bjørnson Rune (Executive vice president (E.V.P), Natural Gas)	2,535	600	113	191	21	3,460	0	26	26	3,486	822	18,346
    Jacobsen Jon Arnt (E.V.P, Manufacturing & Marketing)	3,038	669	131	59	15	3,912	0	44	44	3,956	1,514	15,286
    Mellbye Peter (E.V.P, International Exploration & Production)	4,194	813	108	141	22	5,278	54	39	93	5,371	1,364	41,945
    Sætre Eldar (CFO)	3,047	713	154	196	30	4,140	177	24	201	4,341	924	25,129
    Øvrum Margareth (E.V.P, Technology & New Energy)	3,375	694	138	54	23	4,284	55	50	105	4,389	876	22,623
    Nes Helga 1) (E.V.P, Staff functions & corporate services, 10.11.08 - 31.12.08)	412	0	0	18	6	436	21	5	26	462	62	8,306
    Michelsen Øystein 1) (E.V.P, Exploration & Production Norway, 10.11.08 - 31.12.08)	591	0	0	26	1	618	37	19	56	674	97	14,741
    Myrebø Gunnar 1) (E.V.P, Projects, 10.11.08 - 31.12.08)	452	0	0	2	4	458	0	7	7	465	84	13,589
    Ruud Morten 1) (E.V.P, Projects, 01.01.2008 - 06.10.08)	1,980	590	0	11	15	2,596	0	28	28	2,624	535	19,460
    Torvund Tore 1) (E.V.P, Exploration & Production Norway, 01.01.2008 - 06.10.08)	2,958	863	0	16	8	3,845	168	33	201	4,046	939	36,541
    Aasheim Hilde Merete 1) (E.V.P, Staff functions & corporate services, 01.01.2008 - 01.11.08)	2,239	131	500	153	0	3,023	217	6	223	3,246	0	1,645
    Total	31,668	6,963	1,694	1,236	166	41,727	1,208	298	1,506	43,233	12,534	239,900

    1) The figures presented are total direct compensation for the period when a position in the Corporate Executive Committee is held.
    2) Fixed salary consists of base salary, holiday allowance and any other administrative benefits.
    3) Fixed long-term incentive element.
    4) Bonus received in 2008 is related to the variable long-term incentive system that was terminated in 2007. Bonuses for the period 1 October 2007 to 31 December 2008 will be paid in 2009.
    5) Pension cost is calculated based on actuarial assumptions and pensionable salary at 31 December 2008 and will be recognised as pension cost in the Statement of Income in 2009. The figures presented represent benefits earned assuming that a position in the Corporate Executive Committee is held for a full year. Payroll tax is not included.

     Top 

    7.10 Share ownership

    This section describes the number of StatoilHydro shares owned by the members of the board of directors and the executive committee.

    The number of StatoilHydro shares owned by the members of the board of directors and the executive committee, and/or owned by their close associates, is shown below. Each member of the board of directors and the executive committee individually owned less than 1% of the StatoilHydro shares outstanding.

    Ownership of StatoilHydro shares (including share ownership of "close associates")
    Members of the Corporate Executive Committee	As of  31 December 2008	As of 6 March 2009
    Helge Lund	13,857	14,520
    Eldar Sætre	6,057	6,236
    Margareth Øvrum	7,977	8,195
    Rune Bjørnson	4,351	4,564
    Jon Arnt Jacobsen	7,164	7,482
    Peter Mellbye	7,906	8,050
    Øystein Michelsen	2,040	2,040
    Gunnar Myrebøe	2,726	2,870
    Helga Nes	1,397	1,397
    Members of the Board of Directors
    Svein Rennemo	10,000	10,000
    Marit Arnstad	0	0
    Elisabeth Grieg	33,108	33,108
    Kjell Bjørndalen	0	0
    Grace Reksten Skaugen	400	400
    Kurt Anker Nielsen	0	0
    Roy Franklin	0	0
    Lill-Heidi Bakkerud	330	330
    Claus Clausen	165	165
    Morten Svaan	933	954
    Ragnar Fritsvold (observer)	468	468
    Geir Nilsen (observer)	626	626

    
    Each member of the corporate assembly individually owned less than 1% of StatoilHydro shares outstanding as of 31 December 2008 and as of 6 March 2009. Members of the corporate assembly in aggregate owned a total of 5,665 shares as of 31 December 2008 and a total of 5,665 shares as of 6 March 2009.

    Information about share ownership by members of the Corporate Assembly is presented in Section 7.5.

    Members of the board of directors, executive committee and corporate assembly do not have different voting rights from the rights of ordinary shareholders.

     Top 

    7.117.12 Controls and procedures

    This section describes controls and procedures relating to our financial reporting.
    
    

    Evaluation of disclosure controls and procedures
    Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b) as of the end of the period covered by Form 20-F. Based on that evaluation, the chief executive officer and chief financial officer have concluded that these disclosure controls and procedures are effective at a reasonable level of assurance.

    In order to facilitate the evaluation, StatoilHydroStatoil established a disclosure committee in January 2008 to review material disclosures made by StatoilHydroStatoil for any errors, misstatements and omissions. The disclosure committee is chaired by the chief financial officer. It consists of the heads of Investor Relations, Accounting and Financial Control, Tax and General Counsel and may be supplemented by other internal and external personnel. The head of the Internal Audit is an observer at the committee's meetings.
    
    In designing and evaluating our disclosure controls and procedures, our management, with the participation of the chief executive officer and chief financial officer, recognised that any controls and procedures, no matter how well designed and operated, can only provide reasonable assurance that the desired control objectives will be achieved, and that our management must necessarily exercise judgment in evaluating the cost-benefit aspects of possible controls and procedures. Because of the limitations inherent in all control systems, no evaluation of controls can provide absolute assurance that all control issues and any instances of fraud in the company have been detected.

    The management's report on internal control overof financial reporting
    The management of StatoilHydroStatoil ASA is responsible for establishing and maintaining adequate internal control of financial reporting. Our internal control overof financial reporting is a process designed, under the supervision of the chief executive officer and chief financial officer, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of StatoilHydro'sStatoil's financial statements for external reporting purposes in accordance with International Financial Reporting Standards as adopted by the European Union (EU). The accounting policies applied by the group also comply with IFRS as issued by the International Accounting Standards Board (IASB) and adopted by the European Union (EU).

    ManagementThe management has assessed the effectiveness of internal control overof financial reporting based on the Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, the management has determinedconcluded that StatoilHydro'sStatoil's internal control over financial reporting as of 31 December 20082009 was effective.

    StatoilHydro'sStatoil's internal control overof financial reporting includes policies and procedures that pertain to the maintenance of records that, in reasonable detail, accurately and fairly, reflect transactions and dispositions of assets; provide reasonable assurance that transactions are recorded in the manner necessary to permit the preparation of financial statements in accordance with IFRS, and that receipts and expenditures are only carried out in accordance with the authorisation of the management and the directors of StatoilHydro;Statoil; and provide reasonable assurance regarding the prevention or timely detection of any unauthorised acquisition, use or disposition of StatoilHydro'sStatoil's assets that could have a material effect on our financial statements.

    Because of its inherent limitations, internal control overof financial reporting may not prevent or detect all misstatements. Moreover, projections of any evaluation of the effectiveness of internal control to future periods are subject to a risk that controls may become inadequate because of changes in conditions and that the degree of compliance with the policies or procedures may deteriorate.

    The effectiveness of internal control overof financial reporting as of 31 December 20082009 has been audited by Ernst & Young AS, an independent registered public accounting firm whichthat also audits our consolidated financial statements included in this Annual Report.annual report. Their audit report on the internal control overof financial reporting is included in section 8 in the Consolidated Financial Statements section 8 of this report.

    Changes in internal controls overof financial reporting
    No changes occurred in our internal control overof financial reporting during the period covered by Form 20-F that have materially affected, or are reasonably likely to materially affect, our internal control overof financial reporting.

     Top 

    8 Consolidated Financial Statements

    CONSOLIDATED STATEMENTS OF INCOME
    CONSOLIDATED STATEMENT OF INCOME					CONSOLIDATED STATEMENT OF INCOME
    		For the year ended 31 December				For the year ended 31 December
    (in NOK million)	Note	2008	2007	2006	Note	2009	2008	2007
    REVENUES AND OTHER INCOME
    Revenues		651,977	521,665	518,960		462,292	651,977	521,665
    Net income (loss) from associated companies	13	1,283	609	679
    Net income from associated companies					15	1,778	1,283	609
    Other income		2,760	523	1,843		1,363	2,760	523
    Total revenues and other income	5	656,020	522,797	521,482	5	465,433	656,020	522,797
    OPERATING EXPENSES
    Purchases [net of inventory variation]		( 329,182)	( 260,396)	( 249,593)		( 205,870)	( 329,182)	( 260,396)
    Operating expenses		( 59,349)	( 60,318)	( 44,801)		( 56,860)	( 59,349)	( 60,318)
    Selling, general and administrative expenses		( 10,964)	( 14,174)	( 10,824)		( 10,321)	( 10,964)	( 14,174)
    Depreciation, amortisation and impairment losses	11	( 42,996)	( 39,372)	( 39,450)
    Depreciation, amortisation and net impairment losses					13	( 54,056)	( 42,996)	( 39,372)
    Exploration expenses		( 14,697)	( 11,333)	( 10,650)		( 16,686)	( 14,697)	( 11,333)
    Total operating expenses		( 457,188)	( 385,593)	( 355,318)		( 343,793)	( 457,188)	( 385,593)
    Net operating income	5	198,832	137,204	166,164	5	121,640	198,832	137,204
    FINANCIAL ITEMS
    Net foreign exchange gains (losses)		( 32,563)	10,043	4,457		1,993	( 32,563)	10,043
    Interest income and other financial items		12,207	2,305	3,675		3,708	12,207	2,305
    Interest and other finance expenses		1,991	( 2,741)	( 3,060)		( 12,451)	1,991	( 2,741)
    Net financial items	8	( 18,365)	9,607	5,072	10	( 6,750)	( 18,365)	9,607
    Income before tax		180,467	146,811	171,236		114,890	180,467	146,811
    Income tax	9	( 137,197)	( 102,170)	( 119,389)	11	( 97,175)	( 137,197)	( 102,170)
    Net income		43,270	44,641	51,847		17,715	43,270	44,641
    Attributable to:
    Equity holders of the parent company		43,265	44,096	51,117
    Minority interest		5	545	730
    Equity holders of the company						18,313	43,265	44,096
    Non-controlling interest (Minority interest)						( 598)	5	545
    		43,270	44,641	51,847		17,715	43,270	44,641
    Earnings per share for income attributable to equity holders of the company - basic and diluted	10	13.58	13.80	15.82	12	5.75	13.58	13.80

     

    CONSOLIDATED BALANCE SHEETS
    		At 31 December
    (in NOK million)		2008	2007
    ASSETS
    Non-current assets
    Property, plant and equipment	11	329,841	278,352
    Intangible assets	12	66,036	44,850
    Investments in associated companies	13	12,640	8,421
    Deferred tax assets	9	1,302	793
    Pension assets	21	30	1,622
    Financial investments	14	16,465	15,266
    Derivative financial instruments	28	2,383	609
    Financial receivables	14	4,914	3,515
    Total non-current assets		433,611	353,428
    Current assets
    Inventories	15	15,151	17,696
    Trade and other receivables	16	69,931	69,378
    Current tax receivable	3	3,840	0
    Derivative financial instruments	28	27,505	21,093
    Financial investments	17	9,747	3,359
    Cash and cash equivalents	18	18,638	18,264
    Total current assets		144,812	129,790
    TOTAL ASSETS		578,423	483,218

    CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
    	For the year ended 31 December
    (in NOK million)	2009	2008	2007
    Net income	17,715	43,270	44,641
    Foreign currency translation differences	(13,637)	30,880	(9,858)
    Actuarial gains (losses) on employee retirement benefit plans	3,191	(7,945)	74
    Change in fair value of available for sale financial assets	(66)	(1,362)	926
    Income tax on income and expense recognised directly in OCI	(742)	(802)	(175)
    Other comprehensive income (OCI)	(11,254)	20,771	(9,033)
    Total comprehensive income	6,461	64,041	35,608
    Attributable to:
    Equity holders of the parent company	7,059	64,036	35,063
    Non-controlling interest	(598)	5	545
    	6,461	64,041	35,608

     

    CONSOLIDATED BALANCE SHEETS
    		At 31 December
    (in NOK million)		2008	2007
    EQUITY AND LIABILITIES
    Equity
    Share capital		7,972	7,972
    Treasury shares		(9)	(6)
    Additional paid-in capital		41,450	41,370
    Additional paid-in capital related to treasury shares		(586)	(359)
    Retained earnings		147,998	140,909
    Other reserves		17,254	(12,611)
    StatoilHydro shareholders' equity		214,079	177,275
    Minority interest		1,976	1,792
    Total equity	19	216,055	179,067
    Non-current liabilities
    Financial liabilities	20	54,606	44,374
    Deferred tax liabilities	9	68,144	67,477
    Pension liabilities	21	25,538	19,092
    Asset retirement obligations, other provisions and other liabilities	22	54,359	43,845
    Total non-current liabilities		202,647	174,788
    Current liabilities
    Trade and other payables	23	61,200	64,624
    Current tax payable	9	57,074	50,941
    Financial liabilities	20	20,695	6,166
    Derivative financial instruments	28	20,752	7,632
    Total current liabilities		159,721	129,363
    Total liabilities		362,368	304,151
    TOTAL EQUITY AND LIABILITIES		578,423	483,218

    CONSOLIDATED BALANCE SHEET
    		At 31 December	At 31 December	At 1 January
    		2009	2008	2008
    (in NOK million)	Note		(restated)	(restated)
    ASSETS
    Non-current assets
    Property, plant and equipment	13	340,835	329,841	278,352
    Intangible assets	14	54,253	66,036	44,850
    Investments in associated companies	15	10,056	12,640	8,421
    Deferred tax assets	11	1,960	1,302	793
    Pension assets	23	2,694	30	1,622
    Financial investments	16	13,267	16,465	15,266
    Derivative financial instruments	30	17,644	21,282	12,768
    Financial receivables	16	5,747	4,914	3,515
    Total non-current assets		446,456	452,510	365,587
    Current assets
    Inventories	17	20,196	15,151	17,696
    Trade and other receivables	18	58,895	69,931	69,378
    Current tax receivable		179	3,840	0
    Derivative financial instruments	30	5,369	9,366	8,802
    Financial investments	19	7,022	9,747	3,359
    Cash and cash equivalents	20	24,723	18,638	18,264
    Total current assets		116,384	126,673	117,499
    TOTAL ASSETS		562,840	579,183	483,086

     

    CONSOLIDATED STATEMENTS OF RECOGNISED INCOME AND EXPENSE (SORIE)
    	For the year ended 31 December
    (in NOK million)	2008	2007	2006
    Foreign currency translation differences	30,880	(9,858)	(3,817)
    Actuarial gains (losses) on employee retirement benefit plans	(7,945)	74	(3,032)
    Change in fair value of available for sale financial assets	(1,362)	1,039	(524)
    Change in fair value of available for sale financial assets transferred to the Consolidated Statements of Income	0	(113)	0
    Income tax on income and expense recognised directly in equity	(802)	(175)	2,321
    Income and expense recognised directly in equity	20,771	(9,033)	(5,052)
    Net income for the period	43,270	44,641	51,847
    Total recognised income and expense for the period	64,041	35,608	46,795
    Attributable to:
    Equity holders of the parent company	64,036	35,063	46,065
    Minority interest	5	545	730
    	64,041	35,608	46,795

    CONSOLIDATED BALANCE SHEET
    		At 31 December	At 31 December	At 1 January
    		2009	2008	2008
    (in NOK million)	Note		(restated)	(restated)
    EQUITY AND LIABILITIES
    Equity
    Share capital		7,972	7,972	7,972
    Treasury shares		(15)	(9)	(6)
    Additional paid-in capital		41,732	41,450	41,370
    Additional paid-in capital related to treasury shares		(847)	(586)	(359)
    Retained earnings		145,909	147,998	140,909
    Other reserves		3,568	17,254	(12,611)
    Statoil shareholders' equity		198,319	214,079	177,275
    Non-controlling interest (Minority interest)		1,799	1,976	1,792
    Total equity		200,118	216,055	179,067
    Non-current liabilities
    Financial liabilities	22	95,962	54,606	44,374
    Derivative financial instruments		1,657	1,617	27
    Deferred tax liabilities	11	76,322	68,144	67,477
    Pension liabilities	23	21,142	25,538	19,092
    Assets retirement obligations, other provisions and other liabilities	24	55,834	54,359	43,845
    Total non-current liabilities		250,917	204,264	174,815
    Current liabilities
    Trade and other payables	25	59,801	61,200	64,624
    Current tax payable		40,994	57,074	50,941
    Financial liabilities	26	8,150	20,695	6,166
    Derivative financial instruments	30	2,860	19,895	7,473
    Total current liabilities		111,805	158,864	129,204
    Total liabilities		362,722	363,128	304,019
    TOTAL EQUITY AND LIABILITIES		562,840	579,183	483,086

     

    CONSOLIDATED STATEMENTS OF CASH FLOWS
    	For the year ended 31 December
    (in NOK million)	2008	2007	2006
    OPERATING ACTIVITIES
    Income before tax	180,467	146,811	171,236
    Adjustments to reconcile net income to net cash flows
    provided by operating activities:
    Depreciation, amortisation and impairment	42,996	39,372	39,450
    Exploration expenditures written off	3,872	1,660	1,447
    (Gains) losses on foreign currency transactions and balances	15,243	(559)	(1,197)
    (Gains) losses on sales of assets and other items	(2,704)	(188)	(2,371)
    Termination benefits	0	8,633	0
    Changes in working capital (other than cash and cash equivalents):
    • (Increase) decrease in inventories	2,470	(2,434)	(2,850)
    • (Increase) decrease in trade and other receivables	(1,129)	(6,493)	1,060
    • (Increase) decrease in net current financial derivative instruments	6,708	1,307	(12,450)
    • (Increase) decrease in current financial investments	(6,388)	(2,327)	5,810
    • Increase (decrease) in trade and other payables	(5,466)	10,447	(3,496)
    Taxes paid	(139,604)	(102,422)	(108,174)
    (Increase) decrease in non-current items related to operating activities	6,068	119	128
    Cash flows provided by operating activities	102,533	93,926	88,593
    INVESTING ACTIVITIES
    Additions through business combinations	(13,120)	0	0
    Additions to property, plant and equipment	(58,529)	(63,785)	(45,177)
    Exploration expenditures capitalised	(6,821)	(4,569)	(4,188)
    Additions to other intangibles	(10,828)	(7,186)	(10,507)
    Change in long-term loans granted and other long-term items	(1,910)	(652)	(726)
    Proceeds from sale of assets	5,371	1,080	3,423
    Cash flows used in investing activities	(85,837)	(75,112)	(57,175)
    FINANCING ACTIVITIES
    New long-term borrowings	2,596	1,723	97
    Repayment of long-term borrowings	(2,864)	(2,876)	(2,270)
    Distribution (to)/from minority shareholders	179	(327)	(741)
    Dividend paid *	(27,082)	(25,695)	(17,756)
    Treasury shares purchased	(308)	(217)	(1,012)
    Norsk Hydro ASA merger balance	0	18,687	(10,025)
    Net short-term borrowings, bank overdrafts and other **	10,450	797	329
    Cash flows used in financing activities	(17,029)	(7,908)	(31,378)
    Net increase (decrease) in cash and cash equivalents	(333)	10,906	40
    Effect of exchange rate changes on cash and cash equivalents	707	(160)	42
    Cash and cash equivalents at the beginning of the period	18,264	7,518	7,436
    Cash and cash equivalents at the end of the period	18,638	18,264	7,518
    Interest paid	2,771	3,709	3,611
    Interest received	4,544	2,256	2,296
    * Dividend paid in 2007 includes NOK 6.1 billion charged to Hydro Petroleum from Norsk Hydro ASA under the terms of the merger plan.
    ** Regarding redemption of shares held by the state, StatoilHydro has paid the state NOK 2.4 billion in 2007.

    CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
    							Other reserves
    (in NOK million, except share data)	Number of shares issued	Share capital	Treasury shares	Additional paid-in capital	Additional paid-in capital related to treasury shares	Retained earnings	Available for sale financial assets	Currency translation adjustments	Statoil shareholders' equity	Non-controlling interest	Total
    At 1 January 2007	3,208,805,951	8,022	(54)	44,684	(3,605)	122,153	450	(3,817)	167,833	1,574	169,407
    Net income for the period						44,096			44,096	545	44,641
    Income and expense recognised directly in OCI						211	614	(9,858)	(9,033)		(9,033)
    Total recognised income and expense for the period*											35,608
    Dividend paid						(25,694)			(25,694)		(25,694)
    Cash distributions (to) from non-controlling interest										(327)	(327)
    Merger related adjustments						143			143		143
    Effectuation of annulment	(20,158,848)	(50)	50	(3,426)	3,426				0		0
    Equity settled share based payments
    (net of allocated shares)				112					112		112
    Treasury shares purchased (net of allocated shares)			(2)		(180)				(182)		(182)
    At 31 December 2007	3,188,647,103	7,972	(6)	41,370	(359)	140,909	1,064	(13,675)	177,275	1,792	179,067
    Net income for the period						43,265			43,265	5	43,270
    Income and expense recognised directly in OCI						(9,094)	(1,015)	30,880	20,771		20,771
    Total recognised income and expense for the period*											64,041
    Dividend paid						(27,082)			(27,082)		(27,082)
    Cash distributions (to) from non-controlling interest										179	179
    Equity settled share based payments
    (net of allocated shares)				80					80		80
    Treasury shares purchased (net of allocated shares)			(3)		(227)				(230)		(230)
    At 31 December 2008	3,188,647,103	7,972	(9)	41,450	(586)	147,998	49	17,205	214,079	1,976	216,055

    CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
    							Other reserves
    (in NOK million, except share data)	Number of shares issued	Share capital	Treasury shares	Additional paid-in capital	Additional paid-in capital related to treasury shares	Retained earnings	Available for sale financial assets	Currency translation adjustments	Statoil shareholders' equity	Non-controlling interest	Total
    At 31 December 2008	3,188,647,103	7,972	(9)	41,450	(586)	147,998	49	17,205	214,079	1,976	216,055
    Net income for the period						18,313			18,313	(598)	17,715
    Income and expense recognised directly in OCI						2,432	(49)	(13,637)	(11,254)		(11,254)
    Total recognised income and expense for the period*											6,461
    Dividend paid						(23,085)			(23,085)		(23,085)
    Cash distributions (to) from non-controlling interest										421	421
    Merger related adjustments						251			251		251
    Equity settled share based payments
    (net of allocated shares)				282					282		282
    Treasury shares purchased (net of allocated shares)			(6)		(261)				(267)		(267)
    At 31 December 2009	3,188,647,103	7,972	(15)	41,732	(847)	145,909	0	3,568	198,319	1,799	200,118
    * For detailed information, see Consolidated statement of comprehensive income

    CONSOLIDATED STATEMENT OF CASH FLOWS
    	For the year ended 31 December
    	2009	2008	2007
    (in NOK million)		(restated)	(restated)
    OPERATING ACTIVITIES
    Income before tax	114,890	180,467	146,811
    Adjustments to reconcile net income to net cash flows
    provided by operating activities:
    Depreciation, amortisation and impairment losses	54,056	42,996	39,372
    Exploration expenditures written off	6,998	3,872	1,660
    (Gains) losses on foreign currency transactions and balances	6,512	15,243	(559)
    (Gains) losses on sales of assets and other items	(526)	(2,704)	(188)
    Termination benefits	0	0	8,633
    Changes in working capital (other than cash and cash equivalents):
    • (Increase) decrease in inventories	(5,045)	2,470	(2,434)
    • (Increase) decrease in trade and other receivables	11,036	(1,129)	(6,493)
    • (Increase) decrease in net current financial derivative instruments	(13,038)	11,858	4,277
    • (Increase) decrease in current financial investments	2,725	(6,388)	(2,327)
    • Increase (decrease) in trade and other payables	(1,365)	(5,466)	10,447
    Taxes paid	(100,473)	(139,604)	(102,422)
    (Increase) decrease in non-current items related to operating activities	(2,769)	918	(2,851)
    Cash flows provided by operating activities	73,001	102,533	93,926
    INVESTING ACTIVITIES
    Additions through business combinations	0	(13,120)	0
    Additions to property, plant and equipment	(67,152)	(58,529)	(63,785)
    Exploration expenditures capitalised	(7,203)	(6,821)	(4,569)
    Changes/Additions to other intangibles	(795)	(10,828)	(7,186)
    Change in long-term loans granted and other long-term items	(1,636)	(1,910)	(652)
    Proceeds from sale of assets	1,430	5,371	1,080
    Cash flows used in investing activities	(75,356)	(85,837)	(75,112)

    CONSOLIDATED STATEMENT OF CASH FLOWS
    	For the year ended 31 December
    	2009	2008	2007
    (in NOK million)		(restated)	(restated)
    FINANCING ACTIVITIES
    New long-term borrowings	46,318	2,596	1,723
    Repayment of long-term borrowings	(4,905)	(2,864)	(2,876)
    Distribution (to)/from non-controlling interests	421	179	(327)
    Dividend paid *	(23,085)	(27,082)	(25,695)
    Treasury shares purchased	(343)	(308)	(217)
    Norsk Hydro ASA merger balance	0	0	18,687
    Net short-term borrowings, bank overdrafts and other **	(7,115)	10,450	797
    Cash flows provided by (used in) financing activities	11,291	(17,029)	(7,908)
    Net increase (decrease) in cash and cash equivalents	8,936	(333)	10,906
    Effect of exchange rate changes on cash and cash equivalents	(2,851)	707	(160)
    Cash and cash equivalents at the beginning of the period	18,638	18,264	7,518
    Cash and cash equivalents at the end of the period	24,723	18,638	18,264
    Interest paid	2,912	2,771	3,709
    Interest received	3,962	4,544	2,256
    * Dividend paid in 2007 includes NOK 6.1 billion charged to Hydro Petroleum from Norsk Hydro ASA under the terms of the merger plan.
    ** Regarding redemption of shares held by the state, Statoil has paid the state NOK 2.4 billion in 2007.

     

     Top 

    8.1 Notes to the Consolidated Financial Statements

     Top 

    8.1.1 Organisation

    StatoilHydroStatoil ASA, formerlyoriginally Den Norske Stats Oljeselskap AS, was founded in 1972 and is incorporated and domiciled in Norway. The address of its registered office is Forusbeen 50, N-4035 Stavanger, Norway.

    StatoilHydro's business consists principally of the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products.

    Effective 1 October 2007, Statoil ASA merged with the oil and gas activities of Norsk Hydro ASA (Hydro Petroleum). Statoil ASA's, and the company's name changed to StatoilHydro ASA asASA. As of that date.1 November 2009 the name was changed back to Statoil ASA. The address of its registered office is Forusbeen 50, N-4035 Stavanger, Norway.

    StatoilHydroStatoil's business consists principally of the exploration, production, transportation, refining and marketing of petroleum and petroleum-derived products.

    Statoil ASA is listed on the Oslo Stock Exchange (Norway) and the New York Stock Exchange (USA).

    Statoil's oil and gas activities and net assets on the Norwegian Continental Shelf (NCS) were until 31 December 2008 owned by Statoil ASA and by Statoil Petroleum AS. With effect from 1 January 2009, Statoil ASA transferred the ownership of its NCS net assets to Statoil Petroleum AS, a 100% owned operating subsidiary. Following the transfer, all NCS net assets are owned by Statoil Petroleum AS. As a result of this group internal reorganisation, the nature of the parent company Statoil ASA's operations and transactions were changed so that its functional currency also changed from NOK to USD effective as of the same date and with prospective effect. The functional currency of Statoil Petroleum AS has not changed and remains NOK. The presentation currency for the Statoil group remains NOK.

     Top 

    8.1.2 Significant accounting policies

    Statement of compliance
    The Consolidated financial statements of StatoilHydroStatoil ASA and its subsidiaries (the "group"("Statoil") have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU). The accounting policies applied by the group also comply with IFRSs as issued by the International Accounting Standards Board (IASB).

    Basis of preparation
    The financial statements are prepared on the historical cost basis with some exceptions, as detailed in the accounting policies set out below. These policies have been applied consistently to all periods presented in these consolidated financial statements and in preparing an opening IFRS balance sheet at 1 January 2006 (subject to certain exemptions allowed by IFRS 1) for the purpose of the transition to IFRS. For details of the transition to IFRS see StatoilHydro's Consolidated Financial Statements for 2007.statements.

    Operating expenses in the statements of income are presented as a combination of function and nature in conformity with industry practice. Purchases [net of inventory variation] and Depreciation, amortisation and impairment losses are presented in separate lines by their nature, while Operating expenses and Selling, general and administrative expenses as well as Exploration expenses are presented on a functional basis. Significant expenses such as salaries, pensions, etc. are presented by their nature in the notes to the financial statements.

    Early adoption of standards and interpretations
    The group has elected to adopt the following standards, amendments and interpretations in advance of their effective dates: IAS 23 (Revised) Borrowing Costs (effective for accounting periods beginning on or after 1 January 2009) and IFRS 8 Operating Segments (effective for accounting periods beginning on or after 1 January 2009). The standards have been implemented retrospectively for the periods presented as if the policies have always been applied.

     
    Standards and interpretations in issue, not yet adopted
    At the date of these financial statements other than the standards and interpretations adopted by the group in advance of their effective dates as described above, the following standards and interpretations were in issue but not yet effective:

    The amendments to IAS 1 Presentation of Financial Statements issued in September 2007, which will be effective for annual periods beginning on or after 1 January 2009. This revised IAS introduces certain changes to the statement of recognised income and expense. The group will present a statement of comprehensive income and a statement of changes in equity where currently a statement of income and a statement of recognised income and expense are included. Actuarial gains and losses related to pensions will be presented in other comprehensive income, whereas these are currently presented in the statement of recognised income and expense. There will be no effect on the group's reported net income or equity.

    The revised version of IFRS 3 Business Combinations, issued in January 2008, covers definition, identification, accounting for and disclosure of business combinations, inclusive of business combinations achieved in stages. It will be applicable to business combinations occurring in annual periods beginning on or after 1 July 2009. There willis not expected to be noany material effect on the group'sStatoil's reported net income or equity upon adoption of the revised standard on adoption.1 January 2010.

    The amended version of IAS 27 Consolidated and Separate Financial Statements, issued in January 2008, primarily covers amendments related to accounting for non-controlling interests and the loss of control of a subsidiary, and is effective for annual periods beginning on or after 1 July 2009. There willis not expected to be noany material effect on the group'sStatoil's reported net income or equity on adoption.

    The amendments to IAS 32 Financial Instruments: Presentation and IAS 1 Presentationadoption of Financial Statements issued in February 2008 are effective for annual periods beginningthe amendment on or after 1 January 2009 and will not significantly impact the group's assets, liabilities, or note disclosures.2010.

    The Improvements to IFRS 20082009 issued in May 2008 areApril 2009 include amendments effective for accounting periods beginning on or after 1 July 2009 or 1 January 20092010 respectively, depending on the standard involved, and include amendments to a number of accounting standards. None of the amendments willare expected to significantly impact the group'sStatoil's net profit, or equity or classifications in the Balancebalance sheet or Statementstatement of income.

    The amended version of IFRS 1 First-time adoption of IFRS and IAS 27 Consolidated and Separate9 Financial StatementsInstruments, issued in May 2008November 2009, covers the classification and measurement of financial assets and will be effective from 1 January 2013. IFRS 9 also entails amendments to various other IFRSs effective from the same date. Statoil has not yet determined its adoption date for this standard, and is still evaluating the potential impact of this standard.

    The revised IAS 24 Related Party Disclosures issued in November 2009 defines the term related party and establishes disclosure requirements to be applied, and will be effective forfrom 1 January 2011. Statoil will comply with the revised standard and provide relevant disclosure upon adoption as applicable.

    The amendment to IFRIC 14 Prepayments of a Minimum Funding Requirement issued in November 2009 and effective as of 1 January 2011 is not expected to have any material effect on Statoil's reported net income or equity on adoption.

    The amendment to IAS 32 Classification of Rights Issues issued in November 2009 and effective from accounting periods beginning on1 February 2010 or after 1 January 2009 and will not significantly impactlater, the group's assets, liabilities, or note disclosures.

    The amendmentsamendment to IAS 39 Financial Instruments Recognition and MeasurementsIFRS 2 Group Cash-settled Share-based Payment Transactions issued in July 2008 will have effect from1 July 2009 and will be applied by the group when relevant. There will be no impact on the group's assets, liabilities or net income for periods presented.

    IFRIC 18 Transfers of Assets from Customers, issued in January 2009, is effective from 1 July 2009. The group has not yet completed its evaluation of the effect of the future adoption ofJanuary 2010 and IFRIC 18, but the preliminary assessement indicates that there will be no significant impact on the group's assets, liabilities or net income.

    The amendments to IFRS 7 19 Extinguishing Financial Instruments: Disclosures,Liabilities with Equity Instruments issued in MarchNovember 2009 enhance disclosure requirements about fair value measurements and liquidity risk and is effective for annual periods beginning on or after 1 January 2009. The amendments, which do not require comparative disclosures in the first year of application, is currently being evaluated by the group and will be reflected in the group's note disclosure for the year ended 2009.

    The amendment to IFRS 2 Share-based payment issued in January 2008, (effective 1 January 2009), IFRIC 15 Agreements for the Construction of Real Estate (effective 1 January 2009) and IFRIC 17 Distribution of Non-cash Assets to Owners (effective 1 July 2009)2010 are currently not relevant for Statoil.

    Significant changes in accounting policies
    With effect from 1 January 2009 Statoil adopted amendments to IAS 1 Presentation of Financial Statements issued in September 2007. The Statement of recognised income and expenses has been replaced with the Consolidated statement of comprehensive income and the Consolidated statement of changes in equity, which Statoil previously presented in the Equity note. The Consolidated statement of changes in equity shows changes in non-controlling interests separately.

    Based on amendments to IAS 1 Presentation of Financial Statements included in the improvements to IFRSs effective 1 January 2009, Statoil in 2009 reclassified certain instruments in the IAS 39 Financial Instruments: Recognition and Measurement related held for trading category from current assets or liabilities to non-current assets or liabilities. Statoil's principle as applied in the balance sheet for 31 December 2009 is described in relevant paragraphs below, while information on reclassified amounts is included in note 30. The policy change has been applied retrospectively by adjusting the balance sheets for 31 December 2008 and 1 January 2008 respectively, and in consequence a balance sheet as at 1 January 2008 has been included in these financial statements.

    As of 31 December 2009 Statoil adopted revisions to the group.

    oil and gas estimation and disclosure requirements. For additional information see "Critical accounting judgements and key sources of estimation uncertainty; Proved oil and gas reserves".

    Basis of consolidation
    Subsidiaries
    The consolidated financial statements include the accounts of StatoilHydroStatoil ASA and its subsidiaries. Subsidiaries are entities controlled by the company. Control exists when the groupStatoil has the power, directly or indirectly, to govern the financial and operating policies of an entity so as to obtain benefits from its activities. Subsidiaries are consolidated from the date of their acquisition, being the date on which the groupStatoil obtains control, and continue to be consolidated until the date that such control ceases.

    All intercompany balances and transactions, including unrealised profits and losses arising from intragroupgroup internal transactions, have been eliminated in full. MinorityNon-controlling interests (minority interests) represent the portion of profit or loss and net assets in subsidiaries that isare not directly or indirectly held by the parent company and isare presented separately within equity in the consolidated balance sheet.

    Jointly controlled assets, associates and joint venture entities
    Interests in jointly controlled assets are recognised by including the group'sStatoil's share of assets, liabilities, income and expenses on a line-by-line basis. Interests in jointly controlled entities are accounted for using the equity method. Investments in companies in which the groupStatoil does not have control or joint control, but has the ability to exercise significant influence over operating and financial policies, are classified as associates and are accounted for using the equity method.

    StatoilHydroStatoil as operator of jointly controlled assets
    Indirect operating expencesexpenses such as personnel expenses are accumulated in cost pools. These costs are allocated to business areas and StatoilHydroStatoil operated jointly controlled assets (licenses)(licences) on an hours incurred basis. Costs allocated to the other partners' share of operated jointly controlled assets reduce the costs in the group statementstatements of income. Only StatoilHydro'sStatoil's share of the statement of income and balance sheet items related to StatoilHydroStatoil operated jointly controlled assets are reflected in the Consolidated statement of income and balance sheet.

    Foreign currency

    
    Functional currency
    A group entity's functional currency is the currency of the primary economic environment in which the entity operates.

    Foreign currency translation
    In preparing the financial statements of the individual entities, transactions in foreign currencies (those other than functional currency) are translated at the foreign exchange rate at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency at the foreign exchange rate at the balance sheet date. Foreign exchange differences arising on translation are recognised in the statement of income. Non-monetary assets that are measured in terms of historical cost in a foreign currency are translated using the exchange rate at the date of the transactions.

    Presentation currency
    For the purpose of the consolidated financial statements, the statementstatements of income and balance sheetsheets of each entity are translated into Norwegian kroner (NOK), which is the presentation currency of the consolidated financial statements.

    The assets and liabilities of entities whose functional currencies are other than NOK are translated into NOK at the foreign exchange rate at the balance sheet date. The revenues and expenses of such entities are translated using average monthly foreign exchange rates, which approximates the foreign exchange rates on the dates of the transactions. Foreign exchange differences arising on translation are recognised directly as a separate component of equityseparately in the Statement of recognised income and expense.Other comprehensive income.

    Business combinations and goodwill
    In order to meet the criteria for a business combination to exist, the acquired asset or group of assets must constitute a business (an integrated set of activities and assets conducted and managed for the purpose of providing a return to investors), which generally consists of inputs, processes and outputs.. This requires judgment to be applied on a case by case basis as to whether the acquisition meets the definition of a business combination. AcquiredAcquisitions of exploration and evaluation licences for which no decision has been made to develop are treated as asset purchases based on provisions in IFRS 6. Acquisitions of licences for which a development decision has been made are assessed under the relevant criteria described above to establish whether the transaction represents a business combination or an asset purchase. Acquisitions of licences for which a development decision has not yet been made have largely been concluded to represent asset purchases.

    Business combinations, except for transactions between entities under common control, arehave been accounted for using the purchase method of accounting. The acquired identifiable tangible and intangible assets, liabilities and contingent liabilities are measured at their fair values at the date of the acquisition. Any excess of the cost of purchase over the net fair value of the identifiable assets acquired is recognised as goodwill.

    Goodwill on acquisition is initially measured at cost. Following initial recognition, goodwill is measured at cost less any accumulated impairment losses.

    Goodwill may also arise upon investments in jointly controlled entities and associates, being the surplus of the cost of investment over the group's share of the net fair value of the identifiable assets. Such goodwill is recorded within investments in jointly controlled entities and associates, and any impairment of the goodwill is included in income from jointly controlled entities and associates.

    Revenue recognition
    Revenues associated with sale and transportation of crude oil, natural gas, petroleum and chemical products and other merchandise are recognised when title passesand risk pass to the customer, which is normally at the point of delivery of the goods based on the contractual terms of the agreements.

    Revenues from the production of oil and gas properties in which the group haveStatoil has an interest with other companies are recognised on the basis of volumes lifted and sold to customers during the period (the sales method). Where the groupStatoil has lifted and sold more than the ownership interest, an accrual is recorded for the cost of the overlift. Where the groupStatoil has lifted and sold less than the ownership interest, costs are deferred for the underlift.

    Revenue is presented net of customs, excise taxes and royalties paid in-kind on petroleum products.

    Sales and purchases of physical commodities, which are not settled net, are presented on a gross basis as revenue and cost of goods sold in the statementstatements of income. Activities related to trading and commodity-based derivative instruments are reported on a net basis, with the margin included in Revenue.revenue.

    Transactions with the Norwegian State
    The groupStatoil markets and sells the Norwegian State's share of oil and gas production from the Norwegian Continental SelfShelf (NCS). The Norwegian State's participation in petroleum activities is organised through the State's direct financial interest (SDFI). All purchases and sales of SDFI oil production are recorded as purchases [net of inventory variation] and revenue, respectively. The groupStatoil sells, in its own name, but for the Norwegian State's account and risk, the State's production of natural gas. This sale, and related expenditures refunded by the State, are recorded net in the group'sStatoil's financial statements.

    Employee benefits
    Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are rendered by employees of the group. The accounting policy for share-based payments and pension obligations is described below.

    Share-based payments
    The groupStatoil operates an employee bonus share program. The cost of equity-settled transactions (bonus share awards) with employees is measured by reference to the estimated fair value at the date at which they are granted and is recognised as an expense over the average vesting period of 2.5 years. The awarded shares are accounted for as personnel expense, see note 6 Remuneration, and recorded as an equity transaction (included in additional paid-in capital).

    Research and development
    The groupStatoil undertakes research and development both on a funded basis for licence holders, and unfunded projects at its own risk. The group'sStatoil's share of the licence holdersholders' funding and the total costs of the unfunded projects are development costs that are considered for capitalisation.

    Development costs which are expected to generate probable future economic benefits are capitalised as intangible assets if, and only if, all of the following have been demonstrated: The technical feasibility of completing the intangible asset so that it will be available for use or sale; the intention to complete the intangible asset and use or sell it; the ability to use or sell the intangible asset; how the intangible asset will generate probable future economic benefits; the availability of adequate technical, financial and other resources to complete the development and to use or sell the intangible asset, and the ability to reliably measure reliably the expenditure attributable to the intangible asset during its development. All other research and development expenditure is expensed as incurred.

    Subsequent to initial recognition, capitalised development costs are reported at cost less accumulated amortisation and accumulated impairment losses.

    Income tax
    Income tax in the Consolidated statement of income for the year comprises current and deferred tax expense. Income tax is recognised in the Consolidated statement of income except to the extent that it relates to items recognised directly in equity, in which case it is recognised in equity.Other comprehensive income.

    Current tax is the expected tax payable on the taxable income for the year and any adjustment to tax payable in respect of previous years. Uncertain tax positions and potential tax exposures are analysed individually and the best estimate of the probable amount for liabilities to be paid (unpaid potential tax exposure amounts, including penalties) and virtually certain amount for assets to be received (disputed tax positions for which payment has already been made) in each case is recognised within current tax or deferred tax as appropriate. Interest income and interest expenses relating to tax issues are estimated and recorded in the period in which they are earned or incurred, and are presented as financial items in the statement of income.

    Deferred tax is provided using the balance sheet liability method. Deferred tax assets and liabilities are recognised for the future tax consequences attributable to differences between the carrying amounts of existing assets and liabilities in the financial statements and their respective tax bases, subject to the initial recognition exemption. The amount of deferred tax provided is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantially enacted at the balance sheet date.

    A deferred tax asset is recognised only to the extent that it is probable that future taxable profits will be available against which the asset can be utilised. However, the existence of unused tax losses is strong evidence that future taxable profits may not be available. In order to recognisefor a deferred tax asset to be recognized based on future taxable profits, convincing evidence is required taking into account the existence of contracts, production of oil or gas in the near future based on volumes of proved reserves, observable prices in active markets, expected volatility of trading profits and similar facts and circumstances.

    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%. The special tax is applied to relevant income in addition to the standard 28% income tax, resulting in a 78% marginal tax rate on income subject to Norwegian 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 7.5% per year. The uplift is computed on the basis of the original capitalised cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditures are incurred. Uplift benefit is recorded when the deduction is included in the current year tax return and impacts taxes payable. Unused upliftup lift may b ebe carried forward indefinitely.

    Oil and gas exploration and development expenditure
    The groupStatoil uses the "successful efforts" method of accounting for oil and gas exploration costs. Expenditures to acquire mineral interests in oil and gas properties and to drill and equip exploratory wells are capitalised as exploration and evaluation expenditure within intangible assets until the well is complete and the results have been evaluated. If, following evaluation, the exploratory well has not found proved reserves, the previously capitalised costs are evaluated for derecognition or tested for impairment. Geological and geophysical costs and other exploration expenditures are expensed as incurred.

    For exploration and evaluation asset acquisitions (farm-in arrangements) in which the groupStatoil has made arrangements to fund a portion of the selling partners' (farmor's) exploration and/or future development expenditures, these expenditures are also reflected in the financial statements as and when the exploration and development work progresses, in line with the group's policy.progresses. Exploration and evaluation asset dispositions (farm-out arrangements) are accounted for on a historical cost basis with no gain or loss recognition.

    Exchanges (swaps) of exploration and evaluation assets are accounted for at the carrying amountamounts of the assets given up with no gain or loss recognition.

    Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount, and at least once a year. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether a major capital expenditure can be justified, maywill remain capitalised during the evaluation phase for more than one year. The main conditionsthe exploratory finds. Thereafter it will be considered a trigger for impairment evaluation of the well if no development decision is planned for the near future, and there moreover are that either firmno concrete plans exist for future drilling in the license, or a development decision is planned in the near future.licence. Impairment of unsuccessful wells is reversed, as applicable, to the extent that conditions for impairment are no longer present. Impairment and reversals of impairment of exploration and evaluation assets are charged to Exploration expenses in the statement of income.

    Capitalised exploration and evaluation expenditure, including expenditures to acquire mineral interests in oil and gas properties, related to wells that find proved reserves are transferred from Exploration expenditure (Intangible assets) to Construction in progressAssets under development (Property, plant &and equipment) at the time of sanctioning of the development project.

    Property, plant and equipment
    Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into operation, the initial estimate of anya decommissioning obligation, if any, and, for qualifying assets, borrowing costs. Property, plant and equipment also include assets acquired under the terms of profit sharing agreements (PSAs) in certain countries, and which qualify for recognition as assets of the group. State-owned entities in the respective countries however normally hold the legal title to such PSA-based Property, plant and equipment.

    Exchanges of assets are measured at the fair value of the asset given up unless the exchange transaction lacks commercial substance or the fair value of neither the asset received nor the asset given up is reliably measurable.

    Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where an asset or part of an asset is replaced and it is probable that future economic benefits associated with the item will flow to the group, the expenditure is capitalised. Inspection and overhaul costs associated with major maintenance programs are capitalised and amortised over the period to the next inspection. All other maintenance costs are expensed as incurred.

    Capitalised exploration and evaluation expenditure, development expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and the drilling of development wells, and field-dedicated transport systems for oil and gas are capitalised as producing oil and gas properties within property,Property, plant and equipment and are depreciated using the unit of production method based on proved developed reserves expected to be recovered from the area during the concession or contract period. Capitalised acquisition costs of proved properties are depreciated using the unit of production method based on total proved reserves. Depreciation of other assets and transport systems used by several fields is calculated on the basis of their estimated useful lives, normally using the straight-line method. Each part of an item of property, plant and equipment with a cost that is significant in relation to the total cost of the item is depreciated separately. For explorationex ploration and production (E&P) assets the groupStatoil has established separate depreciation categories for platforms, pipelines, and wells as a minimum.

    The estimated useful lives of property, plant and equipment are reviewed on an annual basis and changes in useful lives are accounted for prospectively. An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected to arise from the continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the item) is included in other income or operating expenses, respectively, in the period the item is derecognised.

    Leases
    Leases in terms of which the groupStatoil assumes substantially all the risks and rewards of the ownership are recordedreflected as finance leases within Property, plant and equipment and Financial liabilities.liabilities, respectively. Assets under development for finance lease purposes, and for which Statoil carries substantially all the risk in the construction period, are recorded as finance leases under development within Property, plant and equipment based on the stage of completion at period end, unless another amount better reflects the realities of the arrangement. All other leases are classified as operating leases and the costs are charged to income on a straight line basis over the lease term, unless another basis is more representative of the benefits of the lease to the group.

    Assets recorded under finance leasesFinance lease assets are statedreflected at an amount equal to the lower of fair value and the present value of the minimum lease payments at inception of the lease, and subsequently reduced by accumulated depreciation and any impairment losses.losses, if any. When an asset leased by a jointly controlled asset in which the groupStatoil participates qualifies as a finance lease, the groupStatoil reflects its proportionate share of the leased asset and related obligations in the balance sheet as Property, plant and equipment and Financial liabilities, respectively. Capitalised leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term using the depreciation methods described under Property, plant and equipment above, depending on the nature of the leased asset.

    The groupStatoil distinguishes between leases, which imply the right to use a specific asset for a period of time, and capacity contracts, which confer on the group the right to and the obligation to pay for certain capacity volume availability related to transport, terminalling, storage etc. Such capacity contracts that do not involve specificspecified single assets or that do not involve substantially all the capacity of an undivided interest in a specific asset are not considered by the group to qualify as leases for accounting purposes. Capacity payments are reflected as Operating expenses in the Consolidated statements of income in the period for which the capacity contractually is available to the group.Statoil.

    Intangible assets
    Intangible assets are stated at cost, less accumulated amortisation and accumulated impairment losses. Intangible assets include expenditure on the exploration for and evaluation of oil and natural gas resources, goodwill and other intangible assets. Intangible assets acquired separately from a business are carried initially at cost. An intangible asset acquired as part of a business combination is recognised separately from goodwill at its fair value if the asset is separable or arises from contractual or other legal rights and its fair value can be measured reliably.

    Intangible assets relating to expenditure on the exploration for and evaluation of oil and natural gas resources are not amortised. These assets areSuch an asset is subject to impairment testing when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount (or at least on an annual basis), and areis reclassified to property, plant and equipment when the decision to develop a particular area is made. Other intangible assets are amortised on a straight-line basis over their expected useful lives. The expected useful lives of the assets are reviewed on an annual basis and changes in useful lives are accounted for prospectively.

    Financial assets
    Financial assets are initially recognised at fair value when the groupStatoil becomes a party to the contractual provisions of the asset. For additional information on fair value methods, refer to the "Measurement of fair value"values" section below. The subsequent measurement of the financial assets depends on whatwhich category they arehave been classified into at inception.

    At initial recognition the group classifies its financial assets into the following three main categories; financial investmentsinstruments at fair value through profit or loss; loans and receivables; and as available-for-sale (AFS) financial assets. The first main category;category, financial investmentsinstruments at fair value through profit or loss, consist further consists of two sub-categories; financial assets that as held for trading and financial assets that on initiallyinitial recognition isare designated as fair value through profit and loss. The latter is furthermay also be referred to as the fair"fair value option.option".

    Financial assets classified in the loans and receivables category are carried at amortised cost using the effective interest method. Gains and losses are recognised in the Consolidated statement of income when the loans and receivables are derecognised or impaired, as well as through the amortisation process. Trade and other receivables are carried at the original invoice amount, less an allowance madea provision for doubtful receivables. Provisionreceivables, which is made when there is objective evidence that the groupStatoil will be unable to recover the balances in full.

    Non-listed equity securities areFinancial assets classified as AFS.AFS mainly include non-listed equity instruments. AFS financial assets are carried on the balance sheet at fair value, with the change in fair value recognised directly into equityin Other comprehensive income until the investment is derecognised or until the investment is determined to be impaired, at which time the cumulative change in fair value previously reported in equityOther comprehensive income is recognised in the statement of income.

    A significant part of the group'sStatoil's commercial papers, bonds and listed equity securities are managed together as an investment portfolio byof the group's captive insurance company and are held in order to comply with specific regulations for capital retention. The investment portfolio is managed and evaluated on a fair value basis in accordance with an investment strategy and is accounted for using the fair value option with changes in fair value recognised through profit or loss.

    Financial assets are presented as current if the asset is expected to be recovered within 12 months after the balance sheet date, whereas assets expected to be recovered more than 12 months after the balance sheet date are classified as non-current, with the exception for derivative financial instruments classified in the held for trading category.

    Financial assets are derecognised when the contractual rights to the cash flows expire or substantially all risk and rewards related to the ownership of the financial asset is transferred in a manner that meet the derecognising criterias.

    Non-current financial investments comprise listed equity securities, non-listed equity securities, commercial papers and bonds.

    Current financial investments comprise commercial papers and money market funds. The current financial investments are at initially recognitionrecognized in the category financial instruments at fair value through profit or loss, either as held for trading or through the group's application of the fair value option. Following from that classification the current financial investments are carried in the balance sheet at fair value with changes in their fair valuevalues recognised in the income statement.statement of income.

    Non-currentFinancial assets are presented as current if they contractually will expire or otherwise are expected to be recovered within 12 months after the balance sheet date, or if they represent derivative financial receivables comprise long term interest bearing receivablesinstruments held for the purpose of being traded. Other financial assets expected to be recovered more than 12 months after the balance sheet date and for which there is no plan of realization are classified as non-current.

    Financial assets are derecognised when the contractual rights to the cash flows expire or substantially all risks and rewards related to the ownership of the financial asset are transferred to a third party.

    Financial assets and financial liabilities are shown separately in the loanbalance sheet unless Statoil has both a legal right and receivables category at initial recognition.

    a demonstrable intention to net settle certain balances payable to and receivable from the same counterparty, in which case they are shown net in the balance sheet. Such offsetting of balances takes place and is reflected within Trade and other receivables are in the category of loans and receivables.

    CashTrade and cash equivalents comprise cash in hand; current balances with banksother payables, and similar institutions;Derivative financial instrument assets and short-term highly liquid investments that are readily convertible to known amounts of cash and have a maturity of three months or less from the date of acquisition.liabilities, respectively.

    Inventories
    Inventories are stated at the lower of cost and net realisable value. Cost is determined by the first-in first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses.

    Impairment
    IntangibleImpairment of intangible assets and property, plant and equipment
    The groupStatoil assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Individual assets are grouped based on the level that there arelevels with separately identifiable and largely independent cash inflows. Normally, separate cash-generating units are individual oil and gas fields or plants. For capitalised exploration expenditure, the cash-generating units are individual wells.

    In assessing whether a write-down is required inof the carrying amount of a potentially impaired asset is required, the asset's carrying amount is compared to the recoverable amount. GenerallyFrequently the recoverable amount of an asset is the group'sproves to be Statoil's estimated value in use, which is determined using a discounted cash flow model. The estimated future cash flows are adjusted for risks specific to the asset and discounted in 2008, 2007 and 2006 using a real post-tax discount rate of 6.5%. The discount rate is calculated based on the group'sStatoil's post-tax weighted average cost of capital (WACC). The groupStatoil considers post taxpost-tax calculations sufficiently objective and consistently applicable across the various tax regimes, while still for all significant purposes leading to the same conclusion that application of thepre tax rates in accordance with IAS 36 Impairment of assets assumed pre tax rates would have yielded.

    If assets are determined to be impaired, the carrying amounts of those assets are written down to the recoverable amount which is the higher of fair value less costs to sell and value in use.

    Impairments are reversed as applicable to the extent that conditions for impairment are no longer present.

    GoodwillImpairment of goodwill
    Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate that the carrying value may be impaired. At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units expected to benefit from the business combination's synergies.

    Impairment is determined by assessing the recoverable amount of the cash-generating unit to which the goodwill relates. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognised, firstly againston goodwill and then pro-rata toon the other assets of that unit. Impairments of goodwill once recorded are not reversed in future periods.

    FinancialImpairment of financial assets
    The groupStatoil assesses at each balance sheet date whether a financial asset or group of financial assets is impaired, except for the financial assets classified in the fair value troughthrough profit and loss category.

    If there is objective evidence that an impairment loss has been incurred for assets carried at amortised cost, the carrying amount of the asset is reduced, with the amount of the loss recognised in the income statement.statement of income. Any subsequent reversal of an impairment loss correspondingly also is recognised in the income statement.statement of income.

    If an available-for-saleAFS financial asset is impaired, i.e. because thea decline in the fair value of an equity instrument has been assessed to be significant or prolonged, the difference between cost and fair value is transferred from equityOther comprehensive income to the income statement.Statement of income. When impairments of equity instruments classified as available-for-saleAFS are reversed this is recognicedrecognised directly to equity.in Other comprehensive income.

    Financial liabilities
    Financial liabilities are initially recognised at fair value when the groupStatoil becomes a party to the contractual provisions of the liability. For additional information on fair value methods, refer to the "Measurement of fair value"values" section below. The subsequent measurement of the financial liabilities depends on whatwhich category they arehave been classified into at inception.into. The categories applicable for the groupStatoil is either financial liabilities at fair value through profit or loss or financial liabilityliabilities measured at amortised cost using the effective interest method. The latter applies to Statoil's non-current bank loans and bonds.

    Trade and other payables are carried at payment or settlement amounts.

    Financial liabilities are presented as current if the liability is due to be settled within 12 months after the balance sheet date, whereasor if they are derivative financial instruments held for the purpose of being traded. Other financial liabilities with the legal right towhich contractually will be settled more than 12 months after the balance sheet date are classified as non-current, with the exception for derivative financial instruments classified at fair value through profit or loss in in the held for trading category.non-current.

    Financial liabilities are derecognised when the contractual obligation expires, is discharged or cancelled. Gains and losses arising on the repurchase, settlement or cancellation of liabilities are recognised either in interestInterest income and other financial items and interestor in Interest and other finance expenses.

    Non-currentDerivative financial liabilitiesinstruments comprise interest-bearing bonds, bank loans,
    Statoil uses derivative financial lease obligationinstruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and other debt.

    Currentcommodity prices. Such derivative financial liabilities comprise collateral liabilities, commercial papers, current portion of non-current financial liabilities, including financial lease obligationsinstruments are initially recognised at fair value on the date on which a derivative contract is entered into and other current debt.

    Tradeare subsequently re-measured at fair value through profit and other payablesloss. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Derivative assets or liabilities expected to be recovered, or with the legal right to be settled more than 12 months after the balance sheet date are classified as non-current, with the exception of derivative financial instruments held for the purpose of being traded.

    Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments, as if the contracts were financial instruments, are accounted for as financial instruments. However contracts that are entered into and continued to be held for the purpose of the receipt or delivery of a non-financial item in accordance with Statoil's expected purchase, sale or usage requirements, also referred to as "own use", are not accounted for as financial instruments. This is applicable to a significant number of contracts for the purchase or sale of crude oil and natural gas, which are recognised upon delivery.

    Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of host contracts and the host contracts are not carried at paymentfair value. Contracts are assessed for embedded derivatives when Statoil becomes a party to them, including at the date of a business combination. Such embedded derivatives are measured at fair value at each period end, and the changes in fair value are recognised in profit or settlement amounts.loss for the period.

    Pension liabilities
    The groupStatoil has pension plans for employees that either provide a defined pension benefit upon retirement, or a pension dependent on defined contributions. For defined benefit schemes, the benefit to be received by employees generally depends on many factors including length of service, retirement date and future salary increases.levels.

    The group'sStatoil's net obligation in respect of defined benefit pension plans is calculated separately for each plan by estimating the amount of future benefit that employees have earned in return for their services in the current and prior periods. That benefit is discounted to determine its present value, and the fair value of any plan assets is deducted. The discount rate is the yield at the balance sheet date reflecting the maturity dates approximating the terms of the group's obligations. The calculation is performed by an external actuary. Current service cost is an element of net periodic pension cost and recognised in the Consolidated statement of income.

    The interest element of the defined benefit cost represents the change in present value of scheme obligations resulting from the passage of time, and is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the obligation during the year. The expected return on plan assets is based on an assessment made at the beginning of the year of long-term market returns on scheme assets, adjusted for the effect on the fair value of plan assets of contributions received and benefits paid during the year. The difference between the expected return on plan assets and the interest cost is recognised in the Consolidated statement of income as a part of the net periodic pension cost.

    Net periodic pension cost is accumulated in cost pools and allocated to business areas and StatoilHydroStatoil operated jointly controlled assets (licenses)(licences) on an hours incurred basis and recognised in the Consolidated statement of income based on the function of the cost.

    Past service cost is recognised immediately when the benefits become vested or on a straight-line basis until the benefits become vested. When a settlement (eliminating all obligations for benefits already accrued) or a curtailment (reducing future obligations as a result of a material reduction in the scheme membership or a reduction in future entitlement) occurs, the obligation and related plan assets are remeasuredre-measured using current actuarial assumptions and the gain or loss is recognised in the Consolidated statement of income during the period in which the settlement or curtailment occurs.

    Actuarial gains and losses are recognised in full in the Consolidated statement of recognisedcomprehensive income and expense in the period in which they occur. Following the parent company Statoil ASA's change in functional currency as of 1 January 2009, the significant part of the group's pension obligations will be payable in a foreign currency (ie. NOK). Actuarial gains and losses related to the parent company's pension obligation as a consequence include the impact of exchange rate fluctuations.

    ContributionContributions to defined contribution schemes are recognised in the Consolidated statement of income in the period in which the contribution amounts are earned by the employees.

    Provisions and contingent assets and liabilities
    Provisions are recognised when the groupStatoil has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as otherOther finance expenses.

    Contingent liabilities arising from past events and for which it is not probable that an outflow of resources will be required to settle the obligation, if any, are not recognised but disclosed with indication of uncertainties relating to amounts and timing involved, unless the possibility of an outflow in settlement is remote.

    Possible assets arising from past events that will only be confirmed by future uncertain events and are not wholly within theStatoil's control of the group,(contingent assets), are not recognised, but are disclosed when an inflow of economic benefits is probable.

    Onerous Contractscontracts
    The groupStatoil recognises as provisions the obligation under contracts defined as onerous. Contracts are deemed to be onerous if the unavoidable cost of meeting the obligations under the contract exceedexceeds the economic benefits expected to be received in relation to the contract. A contract which forms an integral part of the operations of a cash generating unit whose assets are dedicated to that contract, and for which the economic benefits cannot be reliably separated from those of the cash generating unit, is included in impairment considerations for the applicable cash generating unit.unit.  

    Asset retirement obligations (ARO)
    Liabilities for decommissioning costs are recognised when the groupStatoil has an obligation to dismantle and remove a facility or an item of property, plant and equipment and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Cost is estimated upon current regulation and technology, considering relevant risks and uncertainties, to arrive at best estimates. Normally an obligation arises for a new facility, such as an oil and natural gas production or transportation facilities,facility, upon construction or installation. An obligation for decommissioning may also crystallise during the period of operation of a facility through a change in legislation or through a decision to terminate operations. At the time of the obligating event, a decommissioning liability is recognised and classified as Other provisions.Asset retirement obligations, other provisions and other liabilities. The amount recognised is the present value of the estimated future expenditure determined in accordance withw ith local conditions and requirements. Refining a ndand processing plants that are not limited by an expected license periodlicence periods are deemed to have indefinite lives and therefore there isin consequence no measurable asset retirement obligation to behas been recorded. For retail outlets, decommissioning provisions are estimated on a portfolio basis.

    When a liability for decommissioning cost is recognised, a corresponding amount is recorded to increase the related property, plant and equipment. This is subsequently depreciated as part of the costs of the facility or item of property, plant and equipment.

    Any change in the present value of the estimated expenditure is reflected as an adjustment to the provision and the corresponding property, plant and equipment.

    Derivative financial instruments and hedge accounting
    The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and commodity prices. Such derivative financial instruments are initially recognised at fair value on the date on which a derivative contract is entered into and are subsequently re-measured at fair value. Derivatives are carried as assets when the fair value is positive and as liabilities when the fair value is negative. Derivative assets or liabilities expected to be recovered, or with the legal right to be settled more than 12 months after the balance sheet date are classified as non-current, with the exception for derivative financial instruments classified in the held for trading category. For the group it is therefore only derivative financial instruments designated as an effective hedging instrument that is classified as non-current in line with the classification of the hedging object.

    Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments, as if the contracts were financial instruments, are accounted for as financial instruments. However contracts that are entered into and continued to be held for the purpose of the receipt or delivery of a non-financial item in accordance with the group's expected purchase, sale or usage requirements, also referred to as own use, are not accounted for as financial instruments. This is applicable to a significant number of contracts for the purchase or sale of crude oil and natural gas that are accounted for as executory contracts.

    Embedded derivatives
    Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are not closely related to those of host contracts and the host contracts are not carried at fair value. Contracts are assessed for embedded derivatives when the group becomes a party to them, including at the date of a business combination. These embedded derivatives are measured at fair value at each period end, and the changes in fair value are recognised in profit or loss for the period.

    Hedge accounting
    For those derivatives designated as hedging instruments and where hedge accounting is to be applied, the hedging relationship is documented at its inception. This documentation identifies the hedging instrument, the hedged item or transaction, the nature of the risk being hedged and how effectiveness will be assessed throughout its duration. Such hedges are expected at inception to be highly effective.

    Fair value hedges
    Fair value hedges are used by the group when we are hedging the exposure to changes in the fair value of a recognised asset or liability. For fair value hedges, the carrying amount of the hedged item is adjusted for gains and losses attributable to the risk being hedged; the derivative is re-measured at fair value and gains and losses from both the hedging instrument and the hedged item are recognised in the same line in the income statement. For hedged items carried at amortised cost, the adjustment is amortised through the income statement such that it is fully amortised by maturity. The adjustment is included in the amortisation calculation at the time when the hedged item no longer is adjusted for changes in fair value, either because the hedging instruments have expired or the hedge no longer meets the requirements for hedge accounting. The group discontinues fair value hedge accounting if the hedging instrument expires or is sold, terminated or exercised, the hedge no longer meets the cr iteria for hedge accounting or the group revokes the designation.

    Measurement of fair values
    Observable prices quoted in an active market represent the best evidence of fair value, and are used by Statoil in determining the fair values of assets and liabilities to the extent possible.

    A financial instrument is regarded as quoted in an active market if the prices quoted are readily and regularly available, for examplenormally through an exchange, and the prices quoted by the exchange represent actual and regularly occurring market transactions. Thistransactions that in all significant aspects are identical to the instrument being valued. Statoil considers both the actual volume and the timing of recent market transactions in determining whether prices are quoted in a sufficiently active market. Financial instruments quoted in active markets will typically include but is not limited to, commodity based futures, exchange traded option contracts, commercial papers, bonds and equity instruments with quoted market prices obtained from the relevant exchanges or clearing houses. The fair values of quoted financial assets, andfinancial liabilities and derivative instruments are determined by reference to bid and ask prices, at the close of business on the balance sheet date.

    Where there is no active market, fair value is determined using valuation techniques. These include using recent arm's-length market transactions; reference to other instruments that are substantially the same; discounted cash flow analysis; and pricing models. In the valuation techniques the group also takes into consideration counterparty and own credit risk when valuing contracts not traded in an active market.risk. This is either reflected in the discount rate used, or through direct adjustments to the calculated cash flows. Consequently, where the groupStatoil records elements of long-term physical delivery commodity contracts at fair value, such fair value estimates are to the extent possible are based on quoted forward prices in the market and underlying indexes in the contracts, as well as assumptions of forward prices and margins where market prices are not available. Likewise,Similarly, the fair valuevalues of interest and currency swaps isare estimated based on relevant quotations from active markets, quotes of comp arablecomparable instruments, and other appropriate valuation techniques.t echniques.

    Critical accounting judgements and key sources of estimation uncertainty

    
    Critical judgements in applying accounting policies
    The following are the critical judgements, apart from those involving estimations (see below), that the groupStatoil has made in the process of applying the accounting policies and that have the most significant effect on the amounts recognised in the financial statements:

    Revenue recognition - gross versus net presentation of traded SDFI volumes of oil and gas production
    As described under Transactions with the Norwegian State above, the groupStatoil markets and sells the Norwegian State's share of oil and gas production from the NCS. The groupStatoil includes the costs of purchase and proceeds from the sale of the SDFI oil production in its CostPurchases [net of goods soldinventory variation] and Revenue,Revenues, respectively. In making the judgement the groupStatoil considered the detailed criteria for the recognition of revenue from the sale of goods, set out in IAS 18 Revenue, and assessed in particular by analogyassessed whether the risk and reward of the ownership of the goods had been transferred from the SDFI to the group.Statoil.

    As also described above, the groupStatoil sells, in its own name, but for the Norwegian State's account and risk, the State's production of natural gas. This sale, and related expenditures refunded by the State, are recorded net in the group'sStatoil's financial statements. In making the judgment the groupStatoil considered the same criteria as for the oil production and concluded that the risk and reward of the ownership of the gas had not been transferred from the SDFI to the group.Statoil.

    Method of accounting applied for the Hydro Petroleum merger
    The merger between former Statoil ASA and Hydro Petroleum has beenin 2007 was accounted for using the carrying amounts of the assets and liabilities. When making this judgement the groupStatoil considered firstly whether the former Statoil ASA and Hydro Petroleum were under the common control of the Norwegian State, and secondly, given the conclusion that both entities were under the control of the Norwegian State, assessed what method of accounting would provide the most meaningful portrayal of the merger for accounting purposes. StatoilHydroStatoil concluded that such a reorganisation would be best presented using the carrying amounts of assets and liabilities, and restating allit is presented in the financial statements for all periods presented as if the companies had always been combined.

    Key sources of estimation uncertainty
    The preparation of consolidated financial statements requires that management make estimates and assumptions that affect reported amounts of assets and liabilities, income and expenses. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the result of which form the basis of making the judgements about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates. The estimates and underlying assumptions are reviewed on an ongoing basis considering the current and expected future market conditions.

    The groupStatoil is exposed to a number of underlying economic factors, such as liquids prices, natural gas prices, refining margins, foreign exchange rates, interest rates as well as financial instruments with fair valuevalues derived from changes in these factors, which affect the overall results. In addition, theStatoil's results of the group are influenced by the level of production, which in the short term may be influenced by for instance maintenance.maintenance programmes. In the long term, the results are impacted by the success of exploration and field development activities.

    The matters described below are considered to be the most important in understanding the key sources of estimation uncertainty that are involved in preparing these financial statements and the uncertainties that could most significantly impact the amounts reported on the results of operations, financial position and cash flows.

    Proved oil and gas reservesreserves..
    Proved oil and gas reserves have been estimated by internal experts in accordance withon the basis of industry standards and governed by criteria established by regulations of the SEC. The SEC revised Rule 4-10 of Regulation S-X and changed a number of oil and gas reserve estimation requirements effective for the year ending 31 December 2009. This required, on a prospective basis, the use of a price based on a 12-month average for reserve estimation instead of a single end-of-year price and allows for non-traditional sources such as bitumen extracted from oil sands to be included as reserves. The Financial Accounting Standards Board (FASB) also aligned the requirements for supplemental oil and gas disclosures with the changes made by the SEC. Statoil estimates that implementation of the revisions had an immaterial impact on proved reserves as of 31 December 2009 and will have an immaterial impact on unit of production depreciation starting in 2010. However, the comparability of disclosures between years is impact ed by the new requirements.

    Reserves estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbons volumes, the production, historical extraction recovery and processing yield factors and installed plant operating capacitycapacity. For future development projects, proved reserves estimates are included only where there is a significant commitment to project funding and operating approval limits.execution and when relevant governmental and regulatory approvals have been secured or are reasonably certain to be secured. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. An independent third party has evaluated StatoilHydro'sStatoil's proved reserves estimates, and the results of such evaluation do not differ materially from management estimates. Proved oil and gas reserves are the estimatedthose quantities of crude oil naturaland gas, and natural gas liquids which, geological an dby analysis of geoscience and engineering data, demonstratecan be estimated with reasonable certainty to be recoverable in future yearseconomically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and operating conditions, i.e., prices and costs asgovernment regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the dateperiod before 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.contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. 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 and amortisation.

    Expected oil and gas reserves.
    Expected oil and gas reserves have been estimated by internal experts in accordance withon the basis of industry standards and are used for impairment testing purposes and for calculation of asset retirement obligations. Reserves estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbons volumes, the production, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. Future changes in expected oil and gas reserves, for instance as a result of changes in prices, could have a material impact on asset retirement obligations, as well as for the impairment testing of upstream assets, which could have a material adverse effect on operat ingoperating income as a result of increasedchanged impairment charges.

    Exploration and leasehold acquisition costs. The group accounting policy is to capitalise
    Statoil capitalises the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. The groupStatoil also capitalises leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgments onas to whether these expenditures should remain capitalised or written down due to impairment losses in the period may materially affect the operating income for the period.

    Impairment/reversal of impairmentimpairment.. The group
    Statoil has significant investments in property, plant and equipment and intangibles.intangible assets. Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired requiring the book value to be written down to its recoverable amount. Impairments are reversed if the conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgement and may to a large extent depend upon the selection of key assumptions about the future.

    Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount and at least annually. If, following evaluation, an exploratory well has not found proved reserves, the previously capitalised costs are tested for impairment. Exploratory wells that have found reserves, but classificationSubsequent to the initial evaluation phase for a well it will be considered a trigger for impairment testing of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalisedwell if no development decision is planned for more than one year. The main conditions are that either firm plans existthe near future, and there moreover is no concrete plan for future drilling in the license or a development decisionlicence. Impairment of unsuccessful wells is planned inreversed, as applicable, to the near future.extent that conditions for impairment are no longer present.

    Estimating the recoverable amountamounts involves complexity in estimating relevant future cash flows, based on assumptions about the future, assumptions, and discounted to their present value.

    Impairment testing requires long-term assumptions to be made concerning a number of often volatile economic factors such as future market prices, refinery margins, currency exchange rates and future output, discount rates and political and country risk among others, in order to establish relevant future cash flows. Impairment testing frequently also requires judgement to be applied as regards applicable probabilities and probability distributions as well as levels of sensitivity inherent in the establishment of recoverable amount estimates, and consequently in ensuring that the recoverable amount estimates' robustness where relevant is factored sufficiently into the impairment evaluations and reflected in the impairment or reversal of impairment recorded in the financial statements. Long-term assumptions for major factorseconomic f actors are made at group level, and there is a high degree of reasoned judgement involved in establishing these assumptions, in determining other relevant factors such as forward price curves, in estimating production outputs, and in determining the ultimate termination value of an asset.

    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 income, management make a number of critical assumptions affecting these estimates. Most notably, assumptions made onabout 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 potentially material impact on the amounts presented. Significant changes in these assumptions between periods can have a material effect on the accounts.financial statements.

    Asset retirement obligationsobligations.. The group
    Statoil has significant obligations to decommission and remove offshore installations at the end of the production period. Legal obligations associated with the retirement of non-current assets are recognised at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost is capitalised as part of the related non-current 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, considering relevant risks and uncertainties. Most of the removal activities are many years into the future and the removal technology and costs are constantly changing. The estimates include assumptions of both the time required and the day rates for rigs, marine operations and heavy lift vessels that can vary considerably depending on the assumed removal complexity. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgement.

    Derivative financial instruments.
    When not directly observable in active markets, 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. Changes in internal assumptions and forward curves could materially impact the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in corresponding impact on income or loss in the income statement.statement of income.

    Income taxtax.. The group
    Statoil annually incurs significant amounts of income taxes payable to various jurisdictions around the world, and also recognises significant changes to deferred tax assets and deferred tax liabilities, all of which are based on management's interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon management's ability to properly apply at times very complex sets of rules, to recognise changes in applicable rules and, in the case of deferred tax assets, management's ability to project future earnings from activities that may apply loss carry forward positions against future income taxes.

     Top 

    8.1.3 Business combinations

    In December 2008 StatoilHydro acquiredStatoil increased the remaining 50% interest in the Peregrino heavy-oil field offshore Brazil from 50% to 100%, after closing the deal to acquire Anadarko's 50% stake on 10 December 2008. StatoilHydroStatoil paid a cash consideration of USD 1.8 billion, including expenditures incurred in the period 1 January to 1110 December 2008, for 100% of the shares in Anadarko's wholly owned company Anadarko Petroleo Ltda and Anadarko's 50% share of the company South Atlantic Holding BV. Conditional on future oil prices above pre-defined threshold levels, StatoilHydroStatoil will pay an additional maximum pre-tax amount of USD 0.3 billion to be earned by 2020, related to the Peregrino field. The value of the contingent consideration element at the time of closing the deal, estimated to USD 0.2 billion, has been recognised as part of the acquisition price. The Peregrino acquisition has been assessed to constitute a business combination under IFRS 3 and changes in the fair value or final payment of the contingent considera tionconsideration element will be recorded as an adjustment to the book value of the assets acquired. See table below for further details on the purchase price allocation.

    (in NOK million	Carrying amount	Fair value
    Property, plant and equipment	2,518	12,435
    Intangible assets	0	1,543
    Current assets	70	70
    Total assets acquired	2,588	14,048
    Current Liabilities	(316)	(323)
    Net assets acquired	2,272	13,725

    Intangible assets consists of licenses in the exploration and evaluation phase. No part of the purchase price was allocated to goodwill.

    StatoilHydro's original share of 50% in South Atlantic Holding BV has previously been accounted for as an associated company using the equity method. As a result of the business combination, the entity is now consolidated and (in addition to the amounts shown in the table above) the book value of net assets previously accounted for using the equity method has been accounted for as additions through business combinations in note 11 Property, plant and equipment. The transaction has beenwas recorded in the segment International Exploration and Production.

    The acquired business has not generated any revenues and has not incurred significant operating expenses in the period from 1 January 2008 to the acquisition date, or in the period after the acquisition date, as the operations have mainly been related to development and exploration activities, for which the expenditures have been capitalised as intangible assets (exploration) and property, plant and equipment (development).

     Top 

    8.1.4 SignificantAsset acquisitions and dispositionsdisposals

    In November 2008 StatoilHydroStatoil acquired a 32.5% interest in the Marcellus shale gas acreage from Chesapeake Appalachia, L.L.C. The Marcellus shale gas acreage covers 1.8 million net acres (7,300 square kilometres) in the Appalachia region of the Northeastern USA. StatoilHydroStatoil paid a cash consideration of USD 1.3 billion and will payare paying an additional USD 2.1 billion in the form of future funding of 75% of Chesapeake's expenditures for drilling and completion of wells during the period 2009 to 2012. The Marcellus assets are in the exploration and evaluation phase and the funding of Chesapeake's expenditures will on the basis of provisions in IFRS 6, be recorded in the financial statements at the time the expenditures for the wells are incurred. The transaction has beenwas recorded in the segment International Exploration and Production, and was not considered a business combination.Production.

    In February 2008 StatoilHydro'sStatoil's participation in the Petrocedeño project (former Sincor project) was reduced from 15% to 9.677% as a result of the transformation of the Sincor project into the incorporated joint venture Petrocedeño, S.A., which has 60% participation by the Venezuelan state through its wholly owned company PDVSA.Petroleos de Venezuela, S.A. The Petrocedeño project involves the exploitation of extra heavy crude oil from the reservoirs in the Orinoco Belt offshore Venezuela. An accounting gain from the reduction of the participation interest has beenwas recognised in the Consolidated statements of income in 2008 by NOK 1.1 billion net of tax. The transaction has beenwas recorded in the segment International Exploration and Production. The remaining interest in Petrocedeño is reflected in the Consolidated financial statements under the equity method, while the previous interest in the Sincor project was accounted for as a jointly controlled asset consolidated on a line-by-line basis.b asis.

    In the second quarter of 2007 StatoilHydroStatoil acquired all shares of North American Oil Sands Corporation (NAOSC) for a consideration of CAD 2.2 billion, equivalent to USD 2.0 billion. The principle asset in the acquisition was the 257,200 acres (1,110 square kilometres) of oil sands leases that NAOSC operates, located in the Athabasca region of Alberta, north-eastnortheast of Edmonton. The transaction has beenwas recorded in the segment International Exploration and Production, and was not considered a business combination.Production.

    In the first quarter of 2007 StatoilHydroStatoil acquired two of Anadarko Petroleum Corporation's US Gulf of Mexico discoveries and one prospect at a cost of USD 0.9 billion. The assets are located in the Greater Tahiti and Walker Ridge areas. As part of the transaction StatoilHydroStatoil acquired an additional 15% working interest in the Big Foot discovery and has now a 27.5% working interest, including the additions from the transaction mentioned below.interest. The transaction has beenwas recorded in the segment International Exploration and Production. The transaction was not considered a business combination.

    In the fourth quarter of 2006 StatoilHydro acquired working interests in two US Gulf of Mexico deepwater discoveries and one exploration prospect at a cost of USD 0.7 billion. The assets are located in the Greater Tahiti and Walker Ridge areas. StatoilHydro acquired a 17.5% working interest in the Caesar discovery (the Caesar discovery has subsequently been unitised with the Tonga discovery) and a 12.5% working interest in the Big Foot discovery. The transaction has been recorded in the segment International Exploration and Production. The transaction was not considered a business combination.

     Top 

    8.1.5 Segments

    BusinessOperating segments
    StatoilHydroStatoil manages its operations in four businessoperating segments; Exploration and Production Norway, International Exploration and Production, Natural Gas and Manufacturing and Marketing. The Exploration and Production Norway and International Exploration and Production segments explore for, develop and produce crude oil and natural gas, and extract natural gas liquids. The Natural Gas segment transports and markets natural gas and natural gas products. Manufacturing and Marketing is responsible for petroleum refining operations and the marketing of crude oil and refined petroleum products except for natural gas and natural gas products.

    The "Other" section consists of the activities of Corporate services, Corporate center, Group Finance, Technology & New energy and Projects. The "Eliminations" section encompasses elimination of inter-segment sales and related unrealised profits, mainly from the sale of crude oil and products. Inter-segment revenues are based upon estimated market prices.

    Operating segments align with internal management reporting to the company's chief operating decision maker, defined as the Corporate Excecutive Committee (CEC). The operating segments are determined based on differences in the nature of their operations, products, services and geographical location of the activity. The measure of segment profit is Net operating income. Financial items and tax expense are not allocated to the operating segments. The measurement basis for the net operating income for each operating segmentssegment follows the accounting principles used in the financial statementstatements as described in note 2 Significant accounting policies.

    Segment data for the years ended 31 December, 2009, 2008 2007 and 20062007 is presented below:
    

    (in NOK million)	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other	Eliminations	Total	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other	Eliminations	Total
    Year ended 31 December 2008
    Year ended 31 December 2009
    Revenues third party and Other income	2,879	10,289	108,704	530,165	2,700	0	654,737	4,153	12,301	96,973	348,941	1,287	0	463,655
    Revenues inter-segment	216,882	35,031	1,882	966	2,212	(256,973)	0	154,431	28,459	1,241	2,014	2,295	(188,440)	0
    Net income (loss) from associated companies	82	809	225	216	(49)	0	1,283
    Net income from associated companies								79	1,075	399	280	(55)	0	1,778
    Total revenues and other income	219,843	46,129	110,811	531,347	4,863	(256,973)	656,020	158,663	41,835	98,613	351,235	3,527	(188,440)	465,433
    Net operating income	166,907	12,784	12,541	4,548	(731)	2,783	198,832	104,318	2,599	18,488	(541)	(1,146)	(2,078)	121,640
    Significant non-cash items recognised in segment profit or loss:
    Significant non-cash items recognised in segment profit or loss
    - Depreciation and amortisation	24,043	11,619	2,310	2,117	596	0	40,685	25,653	16,231	1,778	2,390	687	0	46,739
    - Impairment losses	0	2,063	0		248	0	2,311	0	873	1,001	5,369	74	0	7,317
    - Inventory valuation	0		24	5,203	0	(1,377)	3,850	0		(24)	(5,171)	0	1,377	(3,818)
    - Commodity derivatives	(109)	0	(1,341)	(1,306)	(37)	0	(2,793)
    - Commodity based derivatives								(1,781)	0	(2,814)	1,072	(122)	0	(3,645)
    - Exploration expenditure written off	749	2,957	0				3,706	1,177	5,821	0				6,998
    Investments in associated companies	149	6,114	4,898	1,063	416	0	12,640	214	4,962	2,829	917	1,134	0	10,056
    Other segment non-current assets*	165,493	160,580	35,735	34,420	3,854	0	400,082
    Non-current assets, not allocated to segments**							20,889
    Other segment non-current assets								175,998	152,678	34,797	28,587	3,028	0	395,088
    Non-current assets, not allocated to segments*														41,312
    Total non-current assets							433,611							446,456
    Additions to PP&E and intangible assets***	34,941	48,694	2,041	8,488	1,256	0	95,420
    Additions to PP&E and intangible assets**								34,875	39,354	2,528	7,618	1,340	0	85,715
    * Excluding investments in associated companies.
    ** Deferred tax assets, post employment benefit assets and financial instruments are not allocated to segments.
    *** Excluding additions due to changes in estimated cost of abandonment and removal.
    * Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.								* Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.
    ** Excluding movements due to changes in abandonment and removal obligations.								** Excluding movements due to changes in abandonment and removal obligations.

     

    (in NOK million)	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other	Eliminations	Total	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other	Eliminations	Total
    Year ended 31 December 2007
    Year ended 31 December 2008
    Revenues third party and Other income	5,925	13,483	72,447	427,342	2,851	140	522,188	2,879	10,289	108,704	530,165	2,700	0	654,737
    Revenues inter-segment	173,259	27,746	927	468	1,600	(204,000)	0	216,882	35,031	1,882	966	2,212	(256,973)	0
    Net income (loss) from associated companies	60	372	60	233	(116)	0	609
    Net income from associated companies								82	809	225	216	(49)	0	1,283
    Total revenues and other income	179,244	41,601	73,434	428,043	4,335	(203,860)	522,797	219,843	46,129	110,811	531,347	4,863	(256,973)	656,020
    Net operating income	123,150	12,161	1,562	3,776	(2,260)	(1,185)	137,204	166,907	12,784	12,541	4,548	(731)	2,783	198,832
    Significant non-cash items recognised in segment profit or loss:
    - Depreciation and amortisation	23,030	9,857	1,595	1,896	564	0	36,942	24,043	11,619	2,310	2,117	596	0	40,685
    - Impairment losses	0	1,246	250	937	(3)	0	2,430	0	2,063	0		248	0	2,311
    - Pension costs*	5,300	738	700		1,300	0	8,738
    - Commodity derivatives	(2,920)	577	3,318	1,031	(88)	0	1,918
    - Inventory valuation								0		24	5,203	0	(1,377)	3,850
    - Commodity based derivatives								(109)	0	(1,341)	(1,306)	(37)	0	(2,793)
    - Exploration expenditure written off	50	1,610	0				1,660	749	2,957	0				3,706
    Investments in associated companies	125	2,253	4,516	1,066	461	0	8,421	149	6,114	4,898	1,063	416	0	12,640
    Other segment non-current assets**	153,115	107,261	35,552	27,627	2,933	0	326,488
    Non-current assets, not allocated to segments***							18,519
    Other segment non-current assets								165,493	160,580	35,735	34,420	3,854	0	400,082
    Non-current assets, not allocated to segments*														20,889
    Total non-current assets							353,428							433,611
    Additions to PP&E and intangible assets****	31,100	36,200	2,100	4,800	800	0	75,000
    Additions to PP&E and intangible assets**								34,941	48,694	2,041	8,488	1,256	0	95,420
    * Pension cost includes early retirement cost (exclusive of curtailment effects) and past service cost.
    ** Excluding investments in associated companies.
    ***Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.
    **** Excluding additions due to changes in estimated cost of abandonment and removal.
    * Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.								* Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.
    ** Excluding movements due to changes in abandonment and removal obligations.								** Excluding movements due to changes in abandonment and removal obligations.

     

    (in NOK million)	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other	Eliminations	Total	Exploration and Production Norway	International Exploration and Production	Natural Gas	Manufacturing and Marketing	Other	Eliminations	Total
    Year ended 31 December 2006
    Year ended 31 December 2007
    Revenues third party and Other income	3,576	11,987	96,040	410,689	1,778	(3,267)	520,803	5,925	13,483	72,447	427,342	2,851	140	522,188
    Revenues inter-segment	175,544	20,608	832	899	1,986	(199,869)	0	173,259	27,746	927	468	1,600	(204,000)	0
    Net income (loss) from associated companies	79	7	197	402	(6)	0	679
    Net income from associated companies								60	372	60	233	(116)	0	609
    Total revenues and other income	179,199	32,602	97,069	411,990	3,758	(203,136)	521,482	179,244	41,601	73,434	428,043	4,335	(203,860)	522,797
    Net operating income	135,140	3,917	21,693	7,280	(1,427)	(439)	166,164	123,150	12,161	1,562	3,776	(2,260)	(1,185)	137,204
    Significant non-cash items recognised in segment profit or loss
    - Depreciation, amortisation and impairment losses	20,708	9,468	1,425	2,223	437	0	34,261
    Significant non-cash items recognised in segment profit or loss:
    - Depreciation and amortisation								23,030	9,857	1,595	1,896	564	0	36,942
    - Impairment losses	230	4,902	0	57	0		5,189	0	1,246	250	937	(3)	0	2,430
    - Commodity derivatives	69	(354)	(6,894)	(136)	12	0	(7,303)
    - Pension costs*								5,300	738	700		1,300	0	8,738
    - Commodity based derivatives								(2,920)	577	3,318	1,031	(88)	0	1,918
    - Exploration expenditure written off	177	1,270	0				1,447	50	1,610	0				1,660
    Investments in associated companies	235	2,381	4,771	964	205	0	8,556	125	2,253	4,516	1,066	461	0	8,421
    Other segment non-current assets*	151,503	95,980	30,103	25,171	2,873	0	305,630
    Other segment non-current assets								153,115	107,261	35,552	27,627	2,933	0	326,488
    Non-current assets, not allocated to segments**							18,462							18,519
    Total non-current assets							332,648							353,428
    Additions to PP&E and intangible assets***	29,200	28,900	3,200	2,500	500	0	64,300	31,100	36,200	2,100	4,800	800	0	75,000
    * Excluding investments in associated companies
    ** Deferred tax assets, post employment benefit assets and financial instruments are not allocated to segments.
    *** Excluding additions due to changes in estimated cost of abandonment and removal.
    * Pension cost includes early retirement cost (exclusive of curtailment effects) and past service cost.								* Pension cost includes early retirement cost (exclusive of curtailment effects) and past service cost.
    ** Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.								** Deferred tax assets, post employment benefit assets and non-current financial instruments are not allocated to segments.
    *** Excluding movements due to changes in abandonment and removal obligations.								*** Excluding movements due to changes in abandonment and removal obligations.

    For the year ending 31 December 2009, the International Exploration and Production segment recognised net impairment losses of NOK 6.3 billion, mainly related to assets in the Gulf of Mexico. The net impairment losses consist of impairment losses of NOK 8.0 billion and reversals of previous periods impairment losses of NOK 1.7 billion. The net impairment losses have been presented as Exploration expenses of NOK 5.4 billion and Depreciation, amortisation and net impairment losses of NOK 0.9 billion on the basis of their nature as intangible assets (exploration assets) and property, plant and equipment (development and producing assets), respectively.

    In 2009, Statoil also recognised impairment losses of NOK 5.4 billion related to refinery assets in the Manufacturing and Marketing segment. The basis for the impairment losses are value in use estimates triggered by decreasing expectations on refining margins in NOK. The impairment losses have been presented as Depreciation, amortisation and net impairment losses. In addition, Statoil has recognised an impairment loss of NOK 1.4 billion in 2009 related to an investment in a refinery company which was classified as an available for sale financial asset. This impairment loss was not allocated to a specific segment but was presented as a financial item.

    In 2008, Statoil recognised net impairment losses of NOK 4.5 billion in the International Exploration and Production segment, of which the main part relates to assets in the Gulf of Mexico. The impairment charges have been presented as Exploration expenses of NOK 2.4 billion and Depreciation, amortisation and impairment losses of NOK 2.1 billion.

    In 2007, the International Exploration and Production segment recognised net impairment losses of NOK 1.2 billion, of which the main part related to exploration and production assets (Intangible assets and Property, plant and equipment) in the Gulf of Mexico while the Manufacturing and Marketing segment recognised an impairment loss of NOK 0.9 billion related to property plant and equipment and intangible assets in the Energy and Retail business in Sweden.

    In assessing the need for impairment of the carrying amount of a potentially impaired asset, the asset's carrying amount is compared to the recoverable amount. The recoverable amount is the higher of fair value less costs to sell and estimated value in use. When preparing a value in use calculation the estimated future cash flows are adjusted for risks specific to the asset and discounted using a real post-tax discount rate adjusted for asset specific differences, such as tax rates and horizon of cash flows. The discount rate is 6.5% real after tax in a 28% tax regime and is derived from Statoil's weighted average cost of capital.

    With effect from 1 January 2008, the internal price for natural gas sold between the segments Exploration and Production Norway and Natural Gas was updated to better reflect changes in the markets for competing energies.

    The 2007 Financial Statementsstatements included an expense of NOK 10.7 billion before tax related to restructuring expenses and other expenses related to the merger between Statoil and Hydro's oil and gas division in 2007. The major part of these expenses was related to pensions and early retirement packages offered to all employees above the age of 58 years. The total expense impacted the net operating income of all segments, and most significantly the segment Exploration and Production Norway. Based on a settlement and estimate changes in 2008, StatoilHydro hasStatoil recognised NOK 1.7 billion before tax as a cost reduction in 2008. The main part of this amount relates to the segment Exploration and Production Norway.

    In the International Exploration and Production segment, the Group recognised an impairment loss of NOK 4.5 billion in 2008, of which the main part relates to assets in the Gulf of Mexico. The impairment charges have been presented as Exploration expenses of NOK 2.4 billion and Depreciation, amortisation and impairment losses of NOK 2.1 billion on the basis of their nature as intangible assets (exploration assets) and fixed assets (development and producing assets), respectively.

    In 2007, the International Exploration and Production segment recognised an impairment loss of NOK 1.2 billion in 2007, of which the main part related to exploration and production assets (Property, plant and equipment) in the Gulf of Mexico while the Manufacturing and Marketing segment recognised an impairment loss of NOK 0.9 billion related to property plant and equipment and intangible assets in the Energy and Retail business in Sweden.

    Impairments of NOK 4.9 billion before tax in the International Exploration and Production segment in 2006 were related to Gulf of Mexico property, plant and equipment.

    With effect from 1 January 2008, the internal price for natural gas sold between the segments Exploration and Production Norway and Natural Gas has been updated to better reflect changes in the markets for competing energies.
    
    Geographical areas
    StatoilHydroStatoil is present in 4442 countries, and manages its four business segments on a worldwide basis. In presenting information on the basis of geographical areas, revenues from external customers are attributed to the country of the legal entity executing the external sale.

    Assets are based on the geographical location of the assets.

    Geographical data for the year ended 31 December 2009, 2008 2007 and 20062007 is presented below:

    (in NOK million)	Crude oil	Gas	NGL	Refined products	Other	Total sale	Crude oil	Gas	NGL	Refined products	Other	Total sale
    Year ended 31 December 2008
    Year ended 31 December 2009
    Norway	260,171	79,813	44,536	79,739	31,025	495,284	182,353	80,018	34,655	45,927	18,137	361,090
    United States	24,712	8,795	1,660	20,182	2,545	57,894
    USA							19,836	5,555	117	14,017	672	40,197
    Sweden	0			21,982	4,064	26,046	0			16,556	3,795	20,351
    Denmark	0			21,170	(1,754)	19,416	0			15,105	1,957	17,062
    Singapore	11,203	1,906	0			13,109
    UK	1,982	10,878	2	0	2,800	15,662
    Other	7,305	930	198	16,885	2,008	27,326	9,978	2,959	154	10,762	1,102	24,955
    Total revenues (excluding net income from associated companies)	305,373	102,322	46,396	159,958	40,688	654,737	212,167	88,532	34,926	102,367	25,663	463,655

     

    (in NOK million)	Crude oil	Gas	NGL	Refined products	Other	Total sale	Crude oil	Gas	NGL	Refined products	Other	Total sale
    Year ended 31 December 2007
    Year ended 31 december 2008
    Norway	209,764	62,911	47,119	52,772	14,107	386,673	260,171	79,813	44,536	79,659	31,105	495,284
    United States	24,142	5,269	1,766	22,823	(864)	53,136	24,712	8,795	1,660	20,182	2,545	57,894
    Sweden	0			16,378	6,731	23,109	0			23,428	2,618	26,046
    Denmark	0			16,958	(2,038)	14,920	0			16,858	2,558	19,416
    Singapore	13,861	0		367	0	14,228	11,203	1,906	0			13,109
    UK							1,982	10,878	2	0	2,800	15,662
    Other	13,290	2,485	139	11,517	2,691	30,122	7,305	930	198	16,885	2,008	27,326
    Total revenues (excluding net income from associated companies)	261,057	70,665	49,024	120,815	20,627	522,188	305,373	102,322	46,396	157,012	43,634	654,737

     

    (in NOK million)	Crude oil	Gas	NGL	Refined products	Other	Total sale	Crude oil	Gas	NGL	Refined products	Other	Total sale
    Year ended 31 December 2006
    Year ended 31 December 2007
    Norway	200,536	72,831	46,447	49,475	23,998	393,287	209,764	62,911	47,119	52,537	14,342	386,673
    United States	21,070	3,731	2,089	17,436	1,296	45,622	24,142	5,269	1,766	22,823	(864)	53,136
    Sweden	0			15,431	6,304	21,735	0			15,217	7,892	23,109
    Denmark	0			14,552	87	14,639	0			13,161	1,759	14,920
    Singapore	8,218	0		425	3	8,646	13,861	0		367	0	14,228
    Other	10,768	7,157	3	15,999	2,947	36,874	13,290	2,485	139	11,517	2,691	30,122
    Total revenues (excluding net income from associated companies)	240,592	83,719	48,539	113,318	34,635	520,803	261,057	70,665	49,024	115,622	25,820	522,188

     

    Assets by geographic areas
    (in NOK million)	2008		2007		2006	2009	2008	2007
    Norway	220,794		204,401		200,220	228,153	220,794	204,401
    United States	50,587		38,672		33,841	38,993	50,587	38,672
    Brazil						29,549	15,743	2,266
    Angola	23,807		15,906		16,371	23,345	23,807	15,906
    Canada						20,533	17,151	14,423
    Azerbaijan	21,396		16,279		17,444	17,331	21,396	16,279
    Canada	17,151		14,423		3,160
    Brazil	15,743		2,266		2,444
    Algeria	11,270		8,371		9,699	9,265	11,270	8,371
    Other areas	47,769		31,305		28,745	37,975	47,769	31,305
    Total non-current asset (excluding deferred tax asset, pension and financial non-current items) at 31 December	408,517		331,623		311,924	405,144	408,517	331,623

    Major customers
    StatoilHydroStatoil does not have transactions with single external customers where revenues amount to more than 10% of the group's total revenues.

     Top 

    8.1.6 Financial risk management

    General information relevant to risks
    Statoil's business activities naturally expose the group to financial risk. The group's approach to risk management includes identifying, evaluating, and managing risk in all activities using a top-down approach with the purpose of avoiding sub-optimisation and utilising correlations observed from a group perspective. Only summing up the different market risks without including the correlations will overestimate our total market risk. Due to this the group utilises correlations between all the most important market risks, such as oil and natural gas prices, product prices, currencies, and interest rates, to calculate the overall market risk and thereby utilise the natural hedges embedded in our portfolio. This approach also reduces the number of unnecessary transactions which reduces transaction costs and avoids sub-optimisation.

    In order to achieve the above results, the group has centralised trading mandates such that all major/strategic transactions are co-ordinated through our Corporate Risk Committee. Local mandates are relatively small.

    The group's Corporate Risk Committee, which is headed by the Chief Financial Officer and includes representatives from the principal business segments, is responsible for defining, developing, and reviewing the group's risk policies. The Chief Financial Officer assisted by the Corporate Risk Committee is also responsible for overseeing and developing Statoil's Enterprise-Wide Risk Management and proposing appropriate measures to adjust risk at the corporate level. The Committee meets at least six times per year and regularly receives risk information relevant for the group from our Corporate Risk Department.

    Financial risks
    Statoil's activities expose the group to financial risks as defined by IFRS 7:

    • Market risk (including commodity price risk, interest rate risk, currency risk and equity price risk)
    • Liquidity risk
    • Credit risk

    Market risk
    Statoil operates in the worldwide crude oil, refined products, natural gas, and electricity markets and is exposed to market risks including fluctuations in hydrocarbon prices, foreign currency rates, interest rates and electricity prices that can affect the revenues and costs of operating, investing and financing. These risks are managed primarily on a short-term basis with a focus on achieving the highest risk adjusted returns for the group within the given mandate. Long-term positions, defined as having a time horizon of six months or more, are managed at the corporate level while short-term positions are managed at segment and lower levels according to trading strategies and mandates approved by the group's Corporate Risk Committee.

    The group has established guidelines for entering into contractual arrangements (derivatives) in order to manage our commodity price, foreign currency rate, and interest rate risks. The group uses both financial and commodity-based derivatives to manage the risks in revenues, financial items and the present value of future cash flows.

    Commodity price risk
    Commodity price risk represents the group's most important short-term market risk and is monitored every day against established mandates as defined by the group's governing policies. To manage short-term commodity risk, the group enters 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 Inter Continental Exchange (ICE) in London, the New York Mercantile Exchange (NYMEX), 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 ICE.

    The term of oil and refined oil products derivatives is usually less than one year and the term for natural gas and electricity derivatives is usually three years or less.

    Currency risk
    Statoil's operating results and cash flows are affected by price developments of its main products, oil and gas, in addition to foreign currency fluctuations of the most significant currencies, the NOK, EUR and GBP, against the USD.

    Statoil is managed as a USD company for currency management purposes. Foreign exchange risk is managed at corporate level in accordance with policies and mandates.

    The group's cash flows derived from oil and gas sales, operating expenses and capital expenditures are mainly in USD, but taxes and dividends are mainly in NOK. Accordingly, the group's currency management is primarily linked to secure tax and dividend payments in NOK. This means that the group regularly purchase substantial NOK amounts on a forward basis using conventional derivative instruments.

    Interest rate risk
    Statoil has assets and liabilities with variable interest rate that expose the group to cash flow risk caused by market interest rate fluctuations. The group enters into interest rate derivatives, particularly interest rate swaps, to alter interest rate exposures, to lower expected funding costs over time and to diversify sources of funding. By using the fixed interest rate debt market when issuing new debt and at the same time altering the interest rate exposure by entering into interest rate swaps, funding sources becomes more diversified than by only being able to use the US floating rate debt market.

    Statoil principally manages the group's interest rates by converting cash flows from the long-term debt portfolio issued with fixed coupon rates into floating rate interest payments. Bonds are normally issued at fixed rates in local currency (JPY, EUR, CHF, GBP and USD). These bonds are converted to floating USD bonds by using interest rate- and currency swaps. The group's interest rate policy also includes a mandate to deviate from base policy and keep part of the long term debt in fixed interest rates.

    Equity price risk
    The group's captive insurance company holds listed equity securities as a part of its portfolio. In addition, the group holds some other non-listed equity securities for long-term strategic purposes. By holding these assets the group is exposed to equity price risk, defined as the risk of declining equity prices, which can result in a decline in the carrying value of the group's assets recognised in the balance sheet. The equity price risk in the portfolio held by the group's captive insurance company is managed, with the aim of maintaining a moderate risk profile, through geographical diversification and the use of broad benchmark indexes.

    Liquidity risk
    Liquidity risk is the risk that Statoil will not be able to meet obligations associated with financial liabilities when due. The purpose of liquidity and current liability management is to make certain that the group has sufficient funds available at all times to cover its financial obligations.

    Statoil manages liquidity and funding at the corporate level, ensuring adequate liquidity to cover group operational requirements. The challenging market conditions during the last couple of years have led to an increased focus and attention on credit and liquidity risk throughout Statoil's entire organisation. Planned capital expenditures have been adjusted and Statoil has, and will continue, to implement initiatives to cut costs. In order to secure necessary financial flexibility, which includes meeting the group's financial obligations, Statoil maintains what is believed to be a conservative liquidity management policy. To secure financial flexibility and identify future long-term financing needs, Statoil carries out three-year cash forecasts at least on a monthly basis.

    Statoil's operating cash flows are significantly impacted by the volatility in the oil and gas prices; however, during 2009 the group's overall liquidity position remained strong and the policies for managing liquidity remained unchanged.

    The main cash outflows are the annual dividend payment and Norwegian Petroleum Tax payments six times per year. If liquid assets one month after tax- and dividend payment dates are below defined policy level, new long-term funding will be considered.

    Current funding needs will normally be covered by using the US Commercial Papers Programme (CP), USD 4 billion which is backed by a revolving credit facility of USD 2 billion, supported by 17 core banks. The facility is undrawn and provides secure access to funding, supported by best available (A1/P1) short-term rating. This credit facility matures in December 2011 and is expected to be renewed and increased during 2010.

    For non-current funding purposes Statoil raises debt in all main capital markets (USA, Europe and Japan). In order to comply with the group's financial policies, Statoil uses derivatives such as currency and interest rate swaps to convert cash flows into floating rate USD interest payments. Our policy is to have a smooth maturity profile with repayments not exceeding 5% of capital employed in any year for the nearest five years. Statoil's long term debt has an average maturity of approximately 10 years.

    For more information about the group's non-current financial liabilities see note 22 Non-current financial liabilities.

    The table below shows a maturity analysis of the group's financial liabilities and financial assets held to manage liquidity risk based on undiscounted contractual cash flows. Included in the assets held to manage liquidity risk are certain foreign currency derivative instruments.

    (in NOK million)	Due within 1 year	Due between 1 and 2 years	Due between 3 and 4 years	Due between 5 and 10 years	Due after 10 years	Total specified
    At 31 December 2009
    Non-derivative financial liabilities	(72,540)	(17,910)	(24,854)	(49,836)	(52,349)	(217,489)
    Derivative financial instruments	(613)	24	(766)	(1,672)	(1,064)	(4,091)
    Financial assets held for managing liquidity risk
    Current derivative financial instruments	335	0	0	0	0	335
    Current financial investments	7,022	0	0	0	0	7,022
    Cash & cash equivalent	24,723	0	0	0	0	24,723
    Total asset held	32,080	0	0	0	0	32,080
    At 31 December 2008
    Non-derivative financial liabilities	(98,820)	(8,197)	(11,150)	(13,056)	(28,073)	(159,296)
    Derivative financial instruments	(13,634)	(120)	(73)	(174)	(421)	(14,422)
    Financial assets held for managing liquidity risk
    Current derivative financial instruments	173	0	0	0	0	173
    Current financial investments	9,747	0	0	0	0	9,747
    Cash & cash equivalent	18,638	0	0	0	0	18,638
    Total asset held	28,558	0	0	0	0	28,558

    As of 31 December 2009 Statoil's liquid assets amounted to NOK 31.7 billion and total liquidity reserve, defined as the total of the group's liquid assets and unused credit facility, amounted to NOK 43.3 billion .

    Credit risk
    Credit risk is the risk that the group's customers or counterparties will cause the group financial loss by failing to honour their obligations. Credit risk arises from credit exposures with customer accounts receivables as well as from financial investments, derivative financial instruments and deposits with financial institutions. Theoretically, the group's maximum credit exposure for financial assets is the aggregated balance sheet carrying amounts of financial investments (excluding equity investments of NOK 6.5 billion in 2009 and NOK 6.5 billion in 2008), derivative financial instruments, financial receivables, trade and other receivables, and cash and cash equivalents.

    Key elements of our credit risk management approach include:

    • A global credit risk policy
    • Credit mandates
    • An internal credit rating process
    • Credit risk mitigation tools
    • Continuous monitoring and managing credit exposures

    Prior to entering into transactions with new counterparties, the group's credit policy requires all counterparties to be formally identified, approved, and assigned internal credit ratings as well as exposure limits. Once established, all counterparties are re-assessed at a minimum annually and monitored continuously. Counterparty risk assessments are based on a quantitative and qualitative analysis of recent financial statements and other relevant business information. In addition, Statoil evaluates any past payment performance, the counterparties' size and business diversification, and the inherent industry risk. The internal credit ratings reflect our assessment of the counterparties' credit risk. Exposure limits are determined based on assigned internal credit ratings combined with other factors, such as expected transaction and industry characteristics. Credit mandates define acceptable credit risk thresholds and are endorsed by management and regularly reviewed with regard to changes in market conditions.

    The group uses risk mitigation tools to reduce or control credit risk both on a counterparty and portfolio level. The main tools are variations of bank and parental guarantees, prepayments and cash collateral. For bank guarantees only investment grade international banks are accepted.

    The group has pre-defined limits for the minimum average credit rating allowed at any given time on the group portfolio level as well as maximum credit exposures for individual counterparties. The group monitors the portfolio on a regular basis and individual exposures against limits on a daily basis. The total credit exposure portfolio of Statoil is geographically diversified among a number of counterparties within the oil and energy sector, as well as larger oil and gas consumers and financial counterparties. The majority of the group's credit exposure is with investment grade counterparties.

    The following table contains the carrying amount of Statoil's financial receivables and derivative financial instruments that are neither past due nor impaired split by the group's assessment of the counter-party's credit risk. Included in current and non-current derivative financial instruments are only non exchange traded instruments.

    	Non-current	Trade and  other	Current derivative	Non-current derivative
    (in NOK million)	financial receivables	receivables	financial instruments	financial instruments
    At 31 December 2009
    Investment grade, rated A or above	1,081	25,119	3,501	10,975
    Other investment grade	1,387	5,417	1,060	6,669
    Non-investment grade or not rated	696	22,471	635	-
    Total financial asset	3,164	53,007	5,196	17,644
    At 31 December 2008
    Investment grade, rated A or above	1,360	33,737	6,243	15,484
    Other investment grade	3	8,431	1,296	5,798
    Non-investment grade or not rated	1,408	24,476	761	-
    Total financial asset	2,771	66,644	8,300	21,282

    As of 31 December 2009, NOK 4.7 billion is received in cash as collateral to offset a portion of this group credit exposure. See note 26 Current financial liabilities for more information on collateral held.

     Top 

    8.1.7 Capital management

    Capital management
    Statoil's capital management policy is to maximise value creation over time, while maintaining a strong financial position and a long-term credit rating at least within the single A category.

    Management makes regular use of Free funds from operations over Net adjusted debt (FFO/ND) and Net adjusted debt over Capital employed (ND/CE) ratios in its assessment of Statoil's financial flexibility and ability to incur additional debt.

    FFO is net operating cash flows from operations after tax with the addition of certain adjustments employed by major rating agencies. These adjustments include cash effects from operating leases, post retirement benefit obligations, capitalised interest, asset retirement obligations and reclassifications of working capital cash flow changes.

    ND in this respect is defined as Statoil's current and non-current interest bearing debt adjusted for Statoil's liquidity positions and adjusted for the adjustments defined above. In addition certain adjustments are made through the addition of project financing, balances related to the Marketing instruction, and balances held by the group's captive insurance company.

    CE is Statoil's total equity plus net interest bearing debt, including debt adjustments defined above.

    Credit rating
    Credit rating is important for Statoil to provide necessary financial flexibility to support a dynamic strategy and provide flexibility through economic and market cycles. Statoil have credit ratings from Moody's and Standard & Poor's and our stated objective is to have credit ratings at least within the single A category. This rating ensures necessary predictability when it comes to funding access to relevant capital markets at favourable terms and conditions. Our current long-term credit ratings are Aa2 and AA- from Moody's and Standard & Poor's respectively. The short-term rating from Moody's is P-1 and A-1+ from Standard & Poor's. We have the intention to keep financial ratios that we consider adequate for maintaining credit ratings at levels consistent with our rating target.
       
    Funding of subsidiaries, associates and jointly controlled entities
    Normally the parent company, Statoil ASA, incurs debt and then extends loans or equity to fully owned subsidiaries to fund capital requirements within the group. With effect from 1 January 2009, Statoil ASA transferred the ownership of its Norwegian Continental Shelf (NCS) net assets to Statoil Petroleum AS. Following the transfer, the majority of corporate assets are owned by Statoil Petroleum AS. Effective from the same date, Statoil Petroleum AS became co-obligor or guarantor of existing debt securities and other loan arrangements of Statoil ASA. As co-obligor, Statoil Petroleum AS assumes and agrees to perform, jointly and severally with Statoil ASA, all payment and covenant obligations for this debt.

    When partially owned subsidiaries or investments in associates and jointly controlled entities are financed, it is Statoil's policy to finance according to ownership share and on equal terms with the other owners. All financing of subsidiaries, associates and jointly controlled entities is based on arm's-length principles. Project specific financing may also be used with the primary objective to mitigate risk.
     
    Capital distribution
    Shareholder return consists of dividend payments, share buy-backs and share price development. Present dividend policy reflects:

    It is Statoil's ambition to grow the annual cash dividend, measured in NOK per share in line with long-term underlying earnings. When deciding the annual dividend level, Statoil will take into consideration expected cash flows, capital expenditure plans, financing requirements and appropriate financial flexibility. In addition to cash dividend, Statoil might buy back shares as part of total distribution of capital to the shareholders.

    The direct link to the IFRS net income has been removed, and the focus will be on growing the annual cash dividend per share in line with long-term underlying earnings. The new policy does not imply a change in the long-term dividend level, including potential share buy-backs, compared to the previous policy. Statoil emphasises the importance of maintaining an attractive dividend level also in the future.

     Top 

    8.1.8 Remuneration

    	For the year ended 31 December
    (in NOK million, except number of man-labour year)	2008	2007	2006
    Salaries	18,670	17,243	15,980
    Pension cost*	2,851	3,131	2,281
    Payroll tax	2,676	2,930	2,368
    Other social benefits	2,102	1,997	1,567
    Total payroll costs	26,299	25,301	22,196
    Average man-labour year	28,001	27,641	26,899

    	For the year ended 31 December
    (in NOK million except number of man-labour year)	2009	2008	2007
    Salaries**	18,472	18,670	17,243
    Pension costs	3,538	2,851	3,131
    Payroll tax	3,023	2,676	2,930
    Other compensations and social costs	2,177	2,102	1,997
    Total payroll costs	27,210	26,299	25,301*
    Average man-labour year	28,107	28,001	27,641

    *PensionTotal payroll cost for 2007 is exclusive of termination benefits.
    ** Salaries are exclusive of reimbursement from the The Norwegian Labour and Welfare Administration.

    Total payroll expenses are accumulated in cost-pools and partly charged to partners of StatoilHydro-operatedStatoil-operated licences on an hours incurred basis.

    The calculation of pension costs and pension assets/liabilities is described in note 2123 Pension liabilities.

    Share based compensation
    StatoilHydro's Share Saving PlanStatoil's share saving plan provides employees with the opportunity to purchase StatoilHydroStatoil shares through monthly salary deductions and a contribution by StatoilHydro.Statoil. If the shares are kept for two full calendar years of continued employment, the employees will be allocated one bonus share for each one they have purchased.

    Estimated compensation expense including the contribution by StatoilHydroStatoil for purchased shares, amount vested for bonus shares granted and related social security tax was NOK 388,370, NOK 246340 and NOK 96246 million related to the 2009, 2008 2007 and 20062007 programs, respectively. For the 20092010 program (granted in 2008)2009) the estimated compensation expense is NOK 370427 million. At 31 December 20082009 the amount of compensation cost yet to be expensed throughout the vesting period is NOK 773816 million.

     Top 

    8.1.78.1.9 Other expenses

    Auditors' remuneration
    

    (in NOK million, excluding VAT)	Audit fee	Audit related and Other service fees	Total
    2008
    Ernst & Young - Norway	35.0	5.0	40.0
    Ernst & Young - outside Norway	25.3	3.9	29.2
    Total	60.3	8.9	69.2
    2007
    Ernst & Young - Norway	20.7	7.4	28.1
    Ernst & Young - outside Norway	24.1	1.1	25.2
    Total	44.8	8.5	53.3
    2006
    Ernst & Young - Norway	15.9	4.2	20.1
    Ernst & Young - outside Norway	19.9	2.4	22.3
    Total	35.8	6.6	42.4

    (in NOK million, excluding VAT)	Audit fee	Audit related fee	Other service fee	Total
    2009
    Ernst & Young - Norway	34.2	5.3	3.7	43.2
    Ernst & Young - outside Norway	27.1	1.5	0.9	29.5
    Total	61.3	6.8	4.6	72.7
    2008
    Ernst & Young - Norway	35.0	4.9	0.1	40.0
    Ernst & Young - outside Norway	25.3	3.8	0.1	29.2
    Total	60.3	8.7	0.2	69.2
    2007
    Ernst & Young - Norway	20.7	7.3	0.1	28.1
    Ernst & Young - outside Norway	24.1	0.8	0.3	25.2
    Total	44.8	8.1	0.4	53.3

     

    In addition to the figures in the table above, for 2006the audit feefees and other fees to Deloitte amount to NOK 39.4 and NOK 5.6 million, respectively and audit related fees to Ernst & Young related to StatoilHydro-operated licensesStatoil-operated licences amount to NOK 8.9, NOK 8.5 and NOK 6.1 and NOK 4.0 million for 2009, 2008 2007 and 2006,2007, respectively.

    The increasesincrease in audit fees and audit related and other fees from 2006 to 2007 and from 2007 to 2008 are mainly due to the increase in activity in connection with the merger with Hydro Petroleum.

    Research and Development (R&D)development expenditures
    Research and Development (R&D)development expenditures were NOK 2,073, NOK 2,243 and NOK 1,969 and NOK 1,616 million in 2009, 2008 2007 and 2006,2007, respectively. R&D expenditures are partly financed by partners of StatoilHydro-operated licenses. StatoilHydro'sStatoil-operated licences. Statoil's share of the expenditures has been recognised as expense in the Consolidated statementStatement of income.

     Top 

    8.1.88.1.10 Financial items

    	For the year ended 31 December
    (In NOK million)	2008	2007		2006
    					For the year ended 31 December
    (in NOK million)					2009	2008	2007
    Foreign exchange gains (losses) non-current financial liabilities	(11,252)	5,944		3,190	0	(11,252)	5,944
    Foreign exchange gains (losses) derivative financial instruments	(25,001)	8,276		3,299	9,722	(25,001)	8,276
    Foreign exchange gains (losses) taxes payable					(1,930)	-
    Other foreign exchange gains (losses)	3,690	(4,177)		(2,032)	(5,799)	3,690	(4,177)
    Net foreign exchange gains (losses)	(32,563)	10,043		4,457	1,993	(32,563)	10,043
    Dividends received	290	523		554	66	290	523
    Gains (losses) financial investments	4,796	(723)		646	875	4,796	(723)
    Interest income financial investments	975	338		612	354	975	338
    Interest income non-current financial receivables	130	197		204	106	130	197
    Interest and other financial income current financial assets	6,016	1,970		1,659
    Interest income current financial assets and other financial income					2,307	6,016	1,970
    Interest income and other financial items	12,207	2,305		3,675	3,708	12,207	2,305
    Capitalised borrowing costs	1,225	2,680		3,255	1,351	1,225	2,680
    Accretion expense asset retirement obligation	(2,107)	(2,099)		(1,304)	(2,432)	(2,107)	(2,099)
    Interest expense non-current financial liabilities	(2,743)	(2,795)		(3,059)
    Interest expense non-current financial liabilities incl. derivatives					(2,386)	(1,850)	(2,447)
    Gains (losses) derivative financial instruments	6,708	847		(365)	(6,593)	5,632	513
    Interest and other financial expenses current financial liabilities	(1,092)	(1,374)		(1,587)
    Interest and other financial expense	1,991	(2,741)		(3,060)
    Net financial Items	(18,365)	9,607		5,072
    Interest expense current financial liabilities and other finance expenses					(2,391)	(909)	(1,388)
    Interest and other finance expenses					(12,451)	1,991	(2,741)
    Net financial items					(6,750)	(18,365)	9,607

    Included in the

    Foreign exchange gains (losses) derivative financial instruments classification areinclude fair value changes in the fair values of currency swap contractsderivatives related to liquidity and currency risk management. TheWeakening of USD versus NOK for the year ended 31 December 2009 resulted in fair value gains on these positions which are recognised in the statement of income. Correspondingly, strengthening of USD versus the NOK for the year ended 31 December 2008 resulted in fair value losses and weakening of USD versus NOK for the year ended 31 December 2007 resulted in fair value gains.

    For comparison of Other foreign exchange gains and (losses) in 2009 with 2008 and 2007, one need to take into account that the parent company Statoil ASA changed its functional currency from NOK versusto USD effective from 1 January 2009. For further information see note 1 Organisation.

    Gains (losses) derivative financial instruments include fair value changes of interest rate derivatives which are used to manage the interest rate risk of the loan portfolio. Increasing USD during 2008interest rates for the year ended 31 December 2009 resulted in fair value losses on these positions recognisedpositions. Correspondingly, decreasing USD interest rates for the year ended 31 December 2008 and the year ended 31 December 2007 resulted in the annual figures for 2008.fair value gains.

    IncreaseIncluded in Gains (losses)Interest expense current financial investments in 2008liabilities and other finance expenses is mainlyan impairment loss of NOK 1.4 billion related to currency effects, included in Fair value changes.

    Increase in Interest and other financial income current financial assets in 2008 is mainly related to interest on currency swap contracts due to increased interest rate spread and accrued interest on prepaid tax.the Pernis refinery investment for the year ended 31 December 2009.

    Capitalised borrowing costs arewere reduced due to more fields going into production in 2009 and 2008 compared to 2007.

    IncludedAll hedge accounting relationships, which related to a portion of the non-current debt portfolio, were discontinued in the first quarter of 2009. Fair value hedge adjustments of NOK 2.5 billion are amortised over the remaining life of these loans (14 to 19 years). The amortised income recognised in Gains (losses) derivative financial instruments are changes inis NOK 198 million for the fair values of swap positions which are used to manage the currency and interest rate risk on external loans. Decreasing USD interest rates during 2008 resulted in fair value gains on these positions. This resulted in a net financial income of NOK 2.0 billion reported on the Interest and other financial expenses classification in the annual figures for 2008.year ended 31 December 2009.

    The negative change in fair value of financial assets available for sale, included in non-listed equity securities in the balance sheet, recognised directly in equity was NOK 1,362 million in 2008, compared to a positive change in fair value of NOK 1,039 million in 2007 and a negative change in fair value of NOK 524 million in 2006.

     Top 

    8.1.98.1.11 Income taxes

    Income before income taxes consists of
    

    (in NOK million)	2008	2007	2006
    Norway offshore	171,150	124,707	151,556
    Norway onshore	(6,260)	7,331	6,402
    Other countries upstream 1)	14,610	13,727	7,038
    Other countries downstream 1)	967	1,046	6,240
    Income before tax	180,467	146,811	171,236

    Significant components of income tax expense were as follows
    

    (in NOK million)	2009	2008	2007
    Norway offshore	80,944	124,775	93,838
    Norway onshore	4,027	3,378	1,924
    Other countries upstream (1)	5,149	9,704	9,928
    Other countries downstream (1)	770	306	535
    Current income tax expense	90,890	138,163	106,225
    Norway offshore	9,358	3,567	(555)
    Norway onshore	242	(4,992)	373
    Other countries upstream (1)	(3,094)	993	(3,688)
    Other countries downstream (1)	(221)	(534)	(185)
    Deferred tax expense	6,285	(966)	(4,055)
    Income tax expense	97,175	137,197	102,170
    (1) Includes Norwegian taxes on income in other countries.

    (in NOK million)	2008	2007	2006
    Norway offshore	124,775	93,838	107,336
    Norway onshore	3,378	1,924	1,149
    Other countries upstream 1)	9,704	9,928	628
    Other countries downstream 1)	306	535	5,434
    Current income tax expense	138,163	106,225	114,547
    Norway offshore	3,567	(555)	6,065
    Norway onshore	(4,992)	373	856
    Other countries upstream 1)	993	(3,688)	(2,669)
    Other countries downstream 1)	(534)	(185)	589
    Deferred tax expense	(966)	(4,055)	4,842
    Income tax expense	137,197	102,170	119,389
    (1) Includes Norwegian taxes on income in other countries.

    Reconciliation of Norwegian nominal statutory tax rate of 28% to effective tax rate

    (in NOK million)	2008	2007	2006	2009	2008	2007
    Norway offshore	171,150	124,707	151,556	122,074	171,150	124,707
    Norway onshore	(6,260)	7,331	6,402	(10,700)	(6,260)	7,331
    Other countries upstream	14,610	13,727	7,038	2,733	14,610	13,727
    Other countries downstream	967	1,046	6,240	783	967	1,046
    Total income before tax	180,467	146,811	171,236	114,890	180,467	146,811
    Calculated income taxes at statutory rates:
    Calculated income taxes at statutory rate (Norwegian statutory tax rate 28%)	50,531	41,107	47,946	32,169	50,531	41,107
    Petroleum surtax at statutory rate (Norwegian special tax rate 50%)*	85,575	62,353	75,357	61,037	85,575	62,353
    Uplift*	(5,047)	(4,365)	(3,759)	(5,052)	(5,047)	(4,365)
    Other countries upstream (average statutory tax rates)	6,606	2,397	1,019
    Other countries downstream (average statutory tax rates)	(497)	57	(754)
    Other countries upstream				1,289	6,606	2,397
    Other countries downstream				330	(497)	57
    Permanent differences caused by USD as functional currency				6,935	0
    Other items	29	621	(420)	467	29	621
    Income tax expense	137,197	102,170	119,389	97,175	137,197	102,170
    Effective tax rate (%)	76.02	69.59	69.72	84.58	76.02	69.59

    *Income from oil and gas activities on the NCS is taxed according to the Norwegian Petroleum Tax Act. In addition to normal corporation tax, a special tax of 50% is levied after deducting uplift, an investment tax credit. Uplift is deducted by 7.5% per year for four years, as from the year of investment. At the end of 20082009 and 20072008 unrecognised uplift credits amounted to NOK 15.115.5 and 17.315.1 billion, respectively.

    The increasehigher tax rate for the year ended 31 December 2009 compared to 2008 is mainly caused by significant taxable exchange gains in the NOK based tax rate was mainly related to the net loss on financial items (mainly included in Norway onshorereturn in the table above) whichparent company. These taxable exchange gains do not impact the Statement of income in the parent company, whose functional currency is tax deductible at a lower tax rate than the average rate.USD. The effect amounts to NOK 6.9 billion.

    Deferred tax assets and liabilities comprise
    

    (in NOK million)	Inventory	Other current items	Tax losses carried forwards	Property, plant and equipment	Exploration expenditure	ARO	Pensions	Other non-current items	Total
    Deferred tax at 31 December 2008
    Deferred tax assets	1,356	5,970	3,505	1,864	0	28,195	10,607	5,693	57,190
    Deferred tax liabilities	0	(9,063)	0	(91,816)	(18,528)	0	0	(4,625)	(124,032)
    Net asset (liability) at 31 December 2008	1,356	(3,093)	3,505	(89,952)	(18,528)	28,195	10,607	1,068	(66,842)
    Deferred tax at 31 December 2009
    Deferred tax assets	907	2,123	3,098	10,162	0	34,072	8,148	2,668	61,178
    Deferred tax liabilities	0	(9,014)	0	(96,799)	(20,091)	0	0	(9,636)	(135,540)
    Net asset (liability) at 31 December 2009	907	(6,891)	3,098	(86,637)	(20,091)	34,072	8,148	(6,968)	(74,362)

    (in NOK million)	Inventory	Other current items	Tax losses carried forwards	Property, plant and equipment	Exploration expenditure	ARO	Pensions	Other non-current items	Total
    Deferred tax at 31 December 2007
    Deferred tax assets	1,257	4,429	2,888	6,361	0	30,238	10,491	2,477	58,141
    Deferred tax liabilities	0	(7,135)	0	(91,474)	(17,511)	0	0	(8,705)	(124,825)
    Net asset/(liability) at 31 December 2007	1,257	(2,706)	2,888	(85,113)	(17,511)	30,238	10,491	(6,228)	(66,684)
    Deferred tax at 31 December 2008
    Deferred tax assets	1,356	5,970	3,505	1,864	0	28,195	10,607	5,693	57,190
    Deferred tax liabilities	0	(9,063)	0	(91,816)	(18,528)	0	0	(4,625)	(124,032)
    Net asset/(liability) at 31 December 2008	1,356	(3,093)	3,505	(89,952)	(18,528)	28,195	10,607	1,068	(66,842)
    Analysis of movements during the year							2008	2007	2006
    Deferred tax liability at 1 January							66,684	71,276	69,300
    Charged/(credited) to the Consolidated statements of income							(966)	(4,055)	4,842
    Charged/(credited) to Equity							802	175	(2,321)
    Translation differences and other							322	(712)	(545)
    Deferred tax liability at 31 December							66,842	66,684	71,276

    Analysis of movements during the year	2009	2008	2007
    Deferred tax liability at 1 January	66,842	66,684	71,276
    Charged (credited) to the Consolidated statement of income	6,285	(966)	(4,055)
    Other comprehensive income	759	1,166	364
    Charged (credited) to Equity	155	(364)	(189)
    Translation differences and other	321	322	(712)
    Deferred tax liability at 31 December	74,362	66,842	66,684

    Deferred tax assets and liabilities are offset to the extent that the deferred taxes relate to the same fiscal authority and there is a legally enforceable right to offset current tax assets against current tax liabilities.

    Following the internal group reorganisation effective 1 January 2009, see note 31 Merger with Hydro Petroleum, StatoilHydro ASA is no longer subject to the special petroleum tax. As a consequence, the tax assets related to pension liabilities in StatoilHydro ASA have effective 31 December 2008 been recognised at 28%, which is the tax rate expected to be in effect at the realisation date. Previously the estimated tax rate was 56%, based on assumed amounts expected to be realised under the petroleum tax regime and the general tax regime, respectively. The effect is a reduction of the deferred tax assets on pensions and retained earnings by NOK 5.4 billion as of 31 December 2008.

    Deferred tax assets
    At the end of 2008, StatoilHydro2009, Statoil had recognised net deferred tax assets of NOK 1.31.96 billion, primarily in the International Exploration and Production segment, as it is considered probable that taxable profit will be available to utilise the deferred tax assets.

    Unrecognised deferred tax assets

    	At 31 December
    (in NOK million)	2009	2008
    Deductible temporary differences	14,519	8,016
    Tax losses carry forward	4,461	4,744

    	31 December
    (in NOK million)	2008	2007
    Deductible temporary differences	8,016	3,860
    Tax losses carry forward	4,744	3,143

    The tax losses carry-forwards that have not been recognised, primarily in the US, expire in the period 2019-2025. The unrecognised deductible temporary differences, primarily in Angola, do not expire under the current tax legislation. Deferred tax assets have not been recognised in respect of these items because evidence as required by prevailing accounting standards is currently not sufficient to support that future taxable profits will be available to secure utilisation of the benefits.

     Top 

    8.1.108.1.12 Earnings per share

    Basic earnings per share
    The calculation of basic earnings per share is based on the net income attributable to ordinary shareholders of the parent company and a weighted average number of ordinary shares outstanding during the years ended 31 December 2009, 2008 and 2007 respectively, calculated as follows:

    	2009	2008	2007
    Net income attributable to equity holders of the parent company (in NOK million)	18,313	43,265	44,096
    Weighted average number of ordinary shares outstanding (in thousands of shares):
    Issued ordinary shares at 1 January	3,189,902	3,188,647	2,166,144
    Effect of own shares held	(6,029)	(2,693)	(21,681)
    Effect of shares issued in the merger with Hydro Petroleum	-	-	1,051,404
    Weighted average number of ordinary shares at 31 December	3,183,874	3,185,954	3,195,867
    Earnings per share for income attributable to equity holders of the company - basic and diluted (NOK)	5.75	13.58	13.80

    The group has no share programs with significant dilutive effects and the calculated diluted earnings per share rounds to be the same amount as the calculated basic earnings per share.

    For the purposes of calculating earnings per share in connection with the merger with Hydro Petroleum, weighted average number of ordinary shares outstanding was set as the total of former Statoil's weighted average number of ordinary shares outstanding and Hydro's weighted average number of outstanding shares multiplied by the number of Statoil's ordinary shares which Hydro shareholders received for each Hydro share in connection with the merger.

    The calculation of basic earnings per share is based on the net income attributable to ordinary shareholders of the parent company and a weighted average number of ordinary shares outstanding during the years ended 31 December 2008, 2007 and 2006 respectively, calculated as follows:
    

    	2008		2007		2006
    Net income attributable to equity holders of the parent company (in NOK million)	43,265		44,096		51,117
    Weighted average number of ordinary shares outstanding (in thousands of shares):
    Issued ordinary shares at 1 January	3,188,647		2,166,144		2,189,586
    Effect of own shares held	(2,693)		(21,681)		(28,558)
    Effect of shares issued in the merger with Hydro Petroleum	-		1,051,404		1,069,822
    Weighted average number of ordinary shares	3,185,954		3,195,867		3,230,850
    Earnings per share for income attributable to equity holders of the company - basic and diluted (NOK)	13.58		13.80		15.82

    The group has no share programs with significant dilutive effects and the calculated diluted earnings per share rounds to be the same amount as the calculated basic earnings per share.

     Top 

    8.1.118.1.13 Property, plant and equipment

    (in NOK million)	Machinery, equipment and transportation equipment	Production plants oil and gas, incl. pipelines	Refining and manufacturing plants	Buildings and land	Vessels	Assets under development	Total	Machinery, equipment and transportation equipment	Production plants oil and gas, incl. pipelines	Refining and manufacturing plants	Buildings and land	Vessels	Assets under development	Total
    Cost at 31 December 2006	12,890	470,361	41,220	14,885	2,754	67,861	609,971
    Cost at 31 December 2007								14,041	521,542	41,162	14,742	4,647	49,110	645,244
    Acquisitions through business combinations								160	0				14,068	14,228
    Additions and transfers	1,579	63,879	1,661	1,196	2,174	(15,158)	55,331	3,139	47,327	3,234	1,103	819	9,627	65,249
    Disposals assets at cost	(230)	(2,829)	(162)	(1,161)	(160)	(23)	(4,565)	(1,265)	(7,907)	(4,622)	(546)	(33)	(1,089)	(15,462)
    Effect of movements in foreign exchange - assets	(198)	(9,869)	(1,557)	(178)	(121)	(3,570)	(15,493)	2,149	21,104	1,710	1,229	171	6,167	32,530
    Cost at 31 December 2007	14,041	521,542	41,162	14,742	4,647	49,110	645,244
    Cost at 31 December 2008								18,224	582,066	41,484	16,528	5,604	77,883	741,789
    Accumulated depr. and impairment losses at 31 December 2007								(9,745)	(323,491)	(25,761)	(5,487)	(430)	(1,978)	(366,892)
    Depreciation and amortisation								(1,005)	(36,872)	(1,607)	(672)	(396)	0	(40,552)
    Transfers								0	(2,343)	0			2,343	0
    Net impairment losses								0	(735)	0			(1,409)	(2,144)
    Accumulated depreciation and impairment disposed assets								1,138	6,667	1,446	336	0	117	9,704
    Effect of movements in foreign exchange – depreciation and impairment losses								(1,241)	(8,801)	(897)	(488)	(43)	(594)	(12,064)
    Accumulated depr. and impairment losses at 31 December 2006	(9,200)	(295,391)	(24,956)	(5,606)	(386)	(2,269)	(337,808)
    Depreciation, depletion and amortisation for the year	(889)	(33,875)	(1,356)	(660)	(230)	0	(37,010)
    Impairment losses for the year	0	(1,470)	(105)	0			(1,575)
    Accumulated depreciation and impairment disposed assets	174	2,820	118	618	158	(16)	3,872
    Effect of movements in foreign exchange – depreciation	170	4,425	538	161	28	307	5,629
    Accumulated depr. and impairment losses at 31 December 2007	(9,745)	(323,491)	(25,761)	(5,487)	(430)	(1,978)	(366,892)
    Accumulated depr. and impairment losses at 31 December 2008								(10,853)	(365,575)	(26,819)	(6,311)	(869)	(1,521)	(411,948)
    Carrying amount at 31 December 2007	4,296	198,051	15,401	9,255	4,217	47,132	278,352
    Carrying amount at 31 December 2008								7,371	216,491	14,665	10,217	4,735	76,362	329,841
    Estimated useful lives (years)	3 - 10	*	15-20	20 - 33	20 - 25			3 - 10	*	15 - 20	20 - 33	20 - 25

     

    (in NOK million)	Machinery, equipment and transportation equipment	Production plants oil and gas, incl. pipelines	Refining and manufacturing plants	Buildings and land	Vessels	Assets under development	Total	Machinery, equipment and transportation equipment	Production plants oil and gas, incl. pipelines	Refining and manufacturing plants	Buildings and land	Vessels	Assets under development	Total
    Cost at 31 December 2007	14,041	521,542	41,162	14,742	4,647	49,110	645,244
    Acquisitions through business combinations	160	0				14,068	14,228
    Cost at 31 December 2008								18,224	582,066	41,484	16,528	5,604	77,883	741,789
    Additions and transfers	3,139	47,327	3,234	1,103	819	9,627	65,249	4,379	58,269	2,528	1,431	(788)	20,068	85,887
    Disposals assets at cost	(1,265)	(7,907)	(4,622)	(546)	(33)	(1,089)	(15,462)	(1,411)	(514)	(223)	(348)	0		(2,496)
    Effect of movements in foreign exchange - assets	2,149	21,104	1,710	1,229	171	6,167	32,530	(2,650)	(21,334)	(435)	(1,876)	(737)	(8,730)	(35,762)
    Cost at 31 December 2008	18,224	582,066	41,484	16,528	5,604	77,883	741,789
    Accumulated depr. and impairment losses at 31 December 2007	(9,745)	(323,491)	(25,761)	(5,487)	(430)	(1,978)	(366,892)
    Depreciation, depletion and amortisation for the year	(1,005)	(36,872)	(1,607)	(672)	(396)	0	(40,552)
    Transfers	0	(2,343)	0			2,343	0
    Impairment losses for the year	0	(735)	0			(1,409)	(2,144)
    Cost at 31 December 2009								18,542	618,487	43,354	15,735	4,079	89,221	789,418
    Accumulated depr. and impairment losses at 31 December 2008								(10,853)	(365,575)	(26,819)	(6,311)	(869)	(1,521)	(411,948)
    Depreciation and amortisation								(1,305)	(42,347)	(1,994)	(617)	(333)	0	(46,596)
    Net impairment losses								(2,162)	(1,223)	(3,248)	0		319	(6,314)
    Accumulated depreciation and impairment disposed assets	1,138	6,667	1,446	336	0	117	9,704	867	513	139	214	0	0	1,733
    Effect of movements in foreign exchange – depreciation and impairment losses	(1,241)	(8,801)	(897)	(488)	(43)	(594)	(12,064)	1,252	11,041	219	711	184	1,135	14,542
    Accumulated depr. and impairment losses at 31 December 2008	(10,853)	(365,575)	(26,819)	(6,311)	(869)	(1,521)	(411,948)
    Carrying amount at 31 December 2008	7,371	216,491	14,665	10,217	4,735	76,362	329,841
    Accumulated depr. and impairment losses at 31 December 2009								(12,201)	(397,591)	(31,703)	(6,003)	(1,018)	(67)	(448,583)
    Carrying amount at 31 December 2009								6,341	220,896	11,651	9,732	3,061	89,154	340,835
    Estimated useful lives (years)	3 - 10	*	15-20	20 - 33	20 - 25			3 - 10	*	15 - 20	20 - 33	20 - 25

    In 20082009 and 2007,2008, capitalised borrowing cost amounted to NOK 1.21.4 and NOK 2.71.2 billion, respectively. In addition to depreciation, amortisation and impairment losses specified above, certain intangible assets, see note 1214 Intangible assets, have been amortised by NOK 3001.2 and NOK 787 million0.3 billion in 20082009 and 2007,2008, respectively.

    Transfer of assets to Property, plant and equipment from Intangible assets in 20082009 and 20072008 amounted to NOK 1.54.9 and NOK 3.21.5 billion, respectively.

    *Depreciation according to Unit of production method, see note 2 Significant accounting policies.

    See note 5 Segments for description of asset impairments.

     Top 

    8.1.128.1.14 Intangible assets

    (in NOK million)	Exploration expenditure	Other	Total	Exploration expenditure	Other	Total
    Cost at 31 December 2006	26,096	6,830	32,926
    Additions	23,237	742	23,979
    Disposals intangible assets at cost	0	(191)
    Transfers of intangible assets	(3,090)	(79)	(3,169)
    Expensed exploration expenditures previously capitalised	(2,061)	0	(2,061)
    Reversal of impaired exploration wells previously capitalised	134	0	134
    Effect of movements in foreign exchange – intangible assets	(3,805)	(704)	(4,509)
    Cost at 31 December 2007	40,511	6,598	47,109
    Accumulated amortisation and impairment losses at 31 December 2006	0	(1,721)
    Depreciation, impairments and amortisation for the year	0	(787)
    Disposals amortisation and impairment losses	0	191
    Effect of movements in foreign exchange - amortisation and impairment losses	0	58
    Accumulated amortisation and impairment losses at 31 December 2007	0	(2,259)
    Carrying amount at 31 December 2007	40,511	4,339	44,850
    (in NOK million)	Exploration expenditure	Other	Total
    Cost at 31 December 2007	40,511	6,598	47,109	40,511	6,598	47,109
    Acquisitions through business combinations	1,748	0	1,748	1,748	0	1,748
    Other additions	17,472	176	17,648	17,472	176	17,648
    Disposals intangible assets at cost	(160)	(1,696)	(1,856)	(160)	(1,696)	(1,856)
    Transfers of intangible assets	(1,464)	12	(1,452)	(1,464)	12	(1,452)
    Expensed exploration expenditures previously capitalised	(3,706)	0	(3,706)	(3,706)	0	(3,706)
    Effect of movements in foreign exchange – intangible assets	7,087	441	7,528
    Effect of movements in foreign exchange				7,087	441	7,528
    Cost at 31 December 2008	61,488	5,531	67,019	61,488	5,531	67,019
    Accumulated amortisation and impairment losses at 31 December 2007	0	(2,259)			(2,259)
    Depreciation, impairments and amortisation for the year	0	(300)			(300)
    Disposals amortisation and impairment losses	0	1,686			1,686
    Effect of movements in foreign exchange - amortisation and impairment losses	0	(110)
    Effect of movements in foreign exchange - amortisation and imp. losses					(110)
    Accumulated amortisation and impairment losses at 31 December 2008	0	(983)			(983)
    Carrying amount at 31 December 2008	61,488	4,548	66,036	61,488	4,548	66,036

    (in NOK million)	Exploration expenditure	Other	Total
    Cost at 31 December 2008	61,488	5,531	67,019
    Other additions	7,816	1,614	9,430
    Disposals intangible assets at cost	(774)	(49)	(823)
    Transfers of intangible assets	(4,888)	10	(4,878)
    Expensed exploration expenditures previously capitalised	(6,998)	0	(6,998)
    Effect of movements in foreign exchange	(7,284)	(457)	(7,741)
    Cost at 31 December 2009	49,360	6,649	56,009
    Accumulated amortisation and impairment losses at 31 December 2008		(983)	(983)
    Depreciation, impairments and amortisation for the year		(1,161)	(1,161)
    Disposals amortisation and impairment losses		15	15
    Effect of movements in foreign exchange - amortisation and imp. losses		373	373
    Accumulated amortisation and impairment losses at 31 December 2009		(1,756)	(1,756)
    Carrying amount at 31 December 2009	49,360	4,893	54,253

    The useful lives of intangible assets are assessed to be either finite or indefinite. Intangible assets with finite useful lives are amortised systematicalysystematically over their estimated economic lives, ranging between 10-20 years.

    AdditionsIncluded in Other intangible assets is goodwill of NOK 4.0 billion as of 31 December 2009 (NOK 3.0 billion as of 31 December 2008 and as of 31 December 2007).

    See note 5 Segments for description of asset impairments.

    For 2008, additions in Intangible assets of NOK 19.4 billion include acquisition of business from Anadarko Petroleum Corporation and assets acquired from Chesapeake Energy Corporation in addition to other exploration activity capitalised during 2008. See note 3 Business combinations and note 4 SignificantAsset acquisitions and dispositionsdisposals for details on the acquisitions during 2008. For 2007, acquisition of assets from Anadarko Petroleum Corporation and North American Oil Sands Corporation were included in this line in addition to other exploration activity capitalised during 2007.

    Included in Other Intangibles is goodwill of NOK 3 billion at 31 December 2008.

    Impairment charges of NOK 2.4 billion relates to impairments of capitalised exploration mainly in the Gulf of Mexico and is classified as exploration expenses in the Statement of income. Amortisation and impairment charges relating to other intangible assets are recognised as depreciation, amortisation and impairment losses in the Consolidated statement of income. Reference is made to information in note 2 Significant accounting policies, regarding method and assumptions used in impairment tests performed.

     Top 

    8.1.138.1.15 Investments in associated companies

    (in NOK million)	2008	2007
    Carrying amount associated companies at 31 December	12,640	8,421
    Net income (loss) from associated companies	1,283	609

    (in NOK million)	2009	2008
    Carrying amount associated companies at 31 December	10,056	12,640
    Net income from associated companies	1,778	1,283

    The most significant associated companies included in the table above are South Caucasus PHC LtdPetrocedeño S.A (ownership share 25,5%9.68%), BTC Pipeline company (ownership share 8,71%8.71%) and Petrocedeño S.ASouth Caucasus PHC Ltd (ownership share 9,68%25.5%). ThroughStatoil has assessed that through contractual agreements the group has significant influence also over the BTC Pipeline company and Petrocedeño S.A,S.A., and consequently the ownership interests in these companies are accounted for using the equity method.

     Top 

    8.1.148.1.16 Non-current financial assets

    Non-current financial investments
    	At 31 December
    (in NOK million)	2008	2007
    Commercial papers	0	605
    Bonds	9,984	7,140
    Listed equity securities	2,276	4,230
    Non-listed equity securities	4,205	3,291
    Financial investments	16,465	15,266

    	At 31 December
    (in NOK million)	2009	2008
    Bonds	6,726	9,984
    Listed equity securities	4,318	2,276
    Non-listed equity securities	2,223	4,205
    Financial investments	13,267	16,465

    Of the non-current financialFinancial investments at 31 December 2009, NOK 12,301 million11.1 billion relate to the investment portfolioportfolios held by the group's captive insurance subsidiarycompany and is accounted for using the fair value option. Correspondingly NOK 80 million of12.3 billion were related to the group's captive insurance subsidiary portfolio is used as collateral for trading with OTC instruments.

    StatoilHydro's acquisition of the Jet automated petrol retail station network was approved by the European Commission (EC) in October 2008. Atportfolios at 31 December 2008 it has been classified as2008.

    All non-listed equity securities in the balance sheet,above table are classified as available for sale assets and changes in accordance with IAS 39, caused by certain divestment requirements set out by the EC which implies holding the activity ringfenced and thereby without StatoilHydro retaining the control prior to fulfilling the divestment requirement.

    All non-current financial investments are measured at fair value. Fair value changes for non-listed equity securities are recognised in Equity - other reserves. Fair value changesOther comprehensive income except for Commercial papers, Bonds and Listed equity securitiesimpairment losses which are recognised in the statementStatement of income.

    When an active market exists, financial instruments are valued on the basis of quoted prices. The following table summarises the source for the group's fair value measurement of the non-current financial investments. Of the total fair valuechange of NOK 6,402 million that2.0 billion in 2009 is measured based on prices quoted inmainly caused by an active market,impairment loss of NOK 4,126 million are government bonds.

    Source of fair value	Commercial	Bonds	Listed equity	Non-listed equity	Total
    (in NOK million)	papers		securities	securities	fair value
    At 31 December 2008
    Fair value based on prices quoted in active market	-	4,126	2,276	-	6,402
    Fair value based on price inputs from observable market transactions	-	5,858	-	717	6,575
    Fair value based on inputs from other sources	-	-	-	3,488	3,488
    Total fair value	-	9,984	2,276	4,205	16,465
    At 31 December 2007
    Fair value based on prices quoted in active market	-	3,377	4,230	-	7,607
    Fair value based on price inputs from observable market transactions	605	3,763	-	373	4,741
    Fair value based on inputs from other sources	-	-	-	2,918	2,918
    Total fair value	605	7,140	4,230	3,291	15,266

    The table below contains the fair value and1.4 billion related equity price risk sensitivity of our listed and non-listed equity instruments, as accounted for under IAS 39. In 2008 the sensitivities have been calculated by using a 20% change for Listed equity securities and 40% change for Non-listed equity securities. Compared to the sensitivity calculated for 2007 the group's view of what is assessed to be reasonable possible changes for the coming yearPernis refinery investment.

    During 2009 NOK 0.07 billion has been updated duetransferred out of Other comprehensive income. For 2008 a loss of NOK 1.4 billion was recognised in Other comprehensive income.

    	At 31 December
    (in NOK million)	2009	2008
    Financial receivables interest bearing	3,164	2,771
    Non-financial receivables	2,583	2,143
    Financial receivables	5,747	4,914

    Included in Financial receivables interest bearing are project financing related to the changes taking placeassociated company BTC, Petrocedeño (former Sincor) and Naturkraft.

    Included in the financial market.

    Equity risk
    		-20%	20%
    (in NOK million)	Fair value	sensitivity	sensitivity
    At 31 December 2008
    Listed equity securities	2,276	(455)	455
    		-40%	40%
    (in NOK million)	Fair value	sensitivity	sensitivity
    At 31 Decenber 2008
    Non-listed equity securities	4,205	(1,682)	1,682
    		-10%	10%
    (in NOK million)		sensitivity	sensitivity
    At 31 December 2007
    Listed equity securities	4,230	(423)	423
    Non-listed equity securities	3,291	(329)	329

    Non-current financial receivables
    	At 31 December
    (in NOK million)	2008	2007
    Interest bearing receivables	2,736	2,784
    Non-interest bearing receivables	2,178	731
    Financial receivables	4,914	3.515

    Of the interest bearingNon-financial receivables at 31 December 2008 a balance of NOK 1,070 million relates to the BTC project financing structure and NOK 1,145 million relates to the PetroCedeño project financing structure. The receivable related to PetroCedeno SA is subordinated to the bank loan, if PetroCedeno SA is in default. Corresponding balances for 31 December 2007 were NOK 934 million for BTC and NOK 1,086 million for PetroCedeño.are long term prepayments.

    Of the non-interest bearingFinancial receivables at 31 December 2008 NOK 1,024 relates to a reimbursement of a contingent liability pending the settlement of a dispute in which StatoilHydro3.2 billion is not a direct part. The contingent liability is included in other provisions.

    All non-current financial receivables are classified in the loan and receivables category, andthe remaining is classified as non-financial assets. Financial receivables' carrying amounts reasonably approximate fair value. The following table summarises the source for the group's fair value measurement of the non-current financial receivables.

    Source of fair value	Interest bearing	Non-interest bearing	Total
    (in NOK million)	receivables	receivables	fair value
    At 31 December 2008
    Fair value based on prices quoted in active market	-	-	-
    Fair value based on price inputs from observable market transactions	2,736	998	3,734
    Fair value based on inputs from other sources	-	1,180	1,180
    Total fair value	2,736	2,178	4,914
    At 31 December 2007
    Fair value based on prices quoted in active market	-	-	-
    Fair value based on price inputs from observable market transactions	2,784	691	3,475
    Fair value based on inputs from other sources	-	40	40
    Total fair value	2,784	731	3,515

     

     Top 

    8.1.158.1.17 Inventories

    Inventories are valued at the lower of cost and net realisable value. Inventories of crude oil, refined products and non-petroleum products are determined under the first-in, first-out (FIFO) method.

    The carrying amount of inventory at the beginning of the year has in all material respects been recognised as an expense through Purchases [net of inventory variation] during the year.
    

    	At 31 December
    (in NOK million)	2008		2007
    Crude oil	7,249		8,097
    Petroleum products	6,338		7,186
    Other	1,564		2,413
    Inventories	15,151		17,696

    	At 31 December
    (in NOK million)	2009	2008
    Crude oil	11,371	7,249
    Petroleum products	7,778	6,338
    Other	1,047	1,564
    Inventories	20,196	15,151

    A write-down of inventory to net realisable value of NOK 3.9 billion has been recognised as Purchases [net of inventory variation]an expense in the period. The write-down was insignificant at year end 2008 (02009 and amounted to NOK 3.9 billion at year end 2007).2008.

     Top 

    8.1.16 Trade and other receivables

    	At 31 December
    (in NOK million)	2008	2007
    Trade receivables	61,083	62,060
    Receivables joint ventures	7,131	6,115
    Receivables associated companies and other related parties	1,717	1,203
    Trade and other receivables	69,931	69,378

     

     Top 

    8.1.178.1.18 Trade and other receivables

    	At 31 December
    (in NOK million)	2009	2008
    Financial trade and other receivables:
    Trade receivables	48,827	57,796
    Receivables joint ventures	3,579	7,131
    Receivables associated companies and other related parties	601	1,717
    Total financial trade and other receivables	53,007	66,644
    Non-financial trade and other receivables	5,888	3,287
    Trade and other receivables	58,895	69,931

    For more information about the credit quality of Statoils financial assets see note 6 Financial risk management. For currency sensitivities see note 31 Financial instruments: measurement and market risk sensitivities.

     Top 

    8.1.19 Current financial investments

    Current financial investments
    	At 31 December
    (in NOK million)	2008	2007
    Commercial papers	7,131	3,204
    Money market funds	2,602	155
    Other	14	-
    Financial investments	9,747	3,359

    	At 31 December
    (in NOK million)	2009	2008
    Commercial papers	5,356	7,131
    Money market funds	1,584	2,602
    Other	82	14
    Financial investments	7,022	9,747

    All balancesCurrent financial investments at 31 December 2009 are classified as held for trading, investments, except fromfor NOK 1,858 million at 31 December 20085.0 billion related to the investment portfolioportfolios held by the group's captive insurance subsidiarycompany which isare accounted for using the fair value option. The corresponding balance at 31 December 2008 was NOK 1.9 billion accounted for using the fair value option.

    All currentCurrent financial investments at 31 December 2009 and 2008 are measured at fair value with gains and losses recognised in the Consolidated statementsstatement of income. When an active market exists, financial instruments are valued on the basis of quoted prices. The following table summarises the source for the group's fair value measurement of the financial instruments.

    Source of fair value	Commercial	Money market	Other	Total
    (in NOK million)	papers	funds		fair value
    At 31 December 2008
    Fair value based on prices quoted in active market	1,744	-	-	1,744
    Fair value based on price inputs from observable market transactions	5,387	2,602	14	8,003
    Fair value based on inputs from other sources	-	-	-	-
    Total fair value	7,131	2,602	14	9,747
    At 31 December 2007
    Fair value based on prices quoted in active market	-	-	-	-
    Fair value based on price inputs from observable market transactions	3,204	155	-	3,359
    Fair value based on inputs from other sources	-	-	-	-
    Total fair value	3,204	155	-	3,359

     

     Top 

    8.1.188.1.20 Cash and cash equivalents

    	At 31 December
    (in NOK million)	2008		2007
    Cash at bank	12,165		3,837
    Time deposits and collateral deposits	6,473		14,427
    Cash and cash equivalents	18,638		18,264

    	At 31 December
    (in NOK million)	2009	2008
    Cash at bank	9,872	12,165
    Time deposits and collateral deposits	14,851	6,473
    Cash and cash equivalents	24,723	18,638

    Cash and cash equivalents at 31 December 20082009 include restricted cash of NOK 4,073 million1.8 billion related to trading activities.activities, correspondingly restricted cash at 31 December 2008 was NOK 4.1 billion. This restricted cash is related to certain collateral requirements set out by exchanges where the group is participating. The terms and conditions related to these requirements are determined by the respective exchanges.

    The overdraft bank balances and overdraft facilities are included underin note 2426 Current financial liabilities. For reconciliation of Cash and cash equivalents reported in the statement of financial position,Consolidated balance sheet, see Consolidated statementsstatement of cash flows.

     Top 

    8.1.19 Shareholder's8.1.21 Transactions impacting shareholders equity

    							Other reserves
    (in NOK million, except share data)	Number of shares issued	Share capital	Treasury shares	Additional paid-in capital	Additional paid-in capital related to treasury shares	Retained earnings	Available for sale financial assets	Currency translation adjustments	StatoilHydro shareholders' equity	Minority interest	Total
    At 1 January 2006	3,232,247,836	8,081	(60)	44,623	(96)	101,518	727	0	154,793	1,592	156,385
    Net income for the period						51,117			51,117	730	51,847
    Income and expense recognised directly in equity						(958)	(277)	(3,817)	(5,052)		(5,052)
    Total recognised income and expense for the period*											46,795
    Dividend paid						(17,756)			(17,756)		(17,756)
    Cash distributions (to) from minority shareholders										(748)	(748)
    Reduction of share capital	(23,441,885)	(59)	59						0		0
    Merger related adjustments
    consist of change in merger
    balance with Norsk Hydro ASA						(11,768)			(11,768)		(11,768)
    Equity settled share based payments				61					61		61
    Treasury shares purchased (net of allocated shares)			(53)		(3,509)				(3,562)		(3,562)
    At 31 December 2006	3,208,805,951	8,022	(54)	44,684	(3,605)	122,153	450	(3,817)	167,833	1,574	169,407
    Net income for the period						44,096			44,096	545	44,641
    Income and expense recognised directly in equity						211	614	(9,858)	(9,033)		(9,033)
    Total recognised income and expense for the period*											35,608
    Dividend paid						(25,694)			(25,694)		(25,694)
    Cash distributions (to) from minority shareholders										(327)	(327)
    Merger related adjustments						143			143		143
    Effectuation of annulment	(20,158,848)	(50)	50	(3,426)	3,426				0		0
    Equity settled share based payments
    (net of allocated shares)				112					112		112
    Treasury shares purchased (net of allocated shares)			(2)		(180)				(182)		(182)
    At 31 December 2007	3,188,647,103	7,972	(6)	41,370	(359)	140,909	1,064	(13,675)	177,275	1,792	179,067

    							Other reserves
    (in NOK million, except share data)	Number of shares issued	Share capital	Treasury shares	Additional paid-in capital	Additional paid-in capital related to treasury shares	Retained earnings	Available for sale financial assets	Currency translation adjustments	StatoilHydro shareholders' equity	Minority interest	Total
    At 31 December 2007	3,188,647,103	7,972	(6)	41,370	(359)	140,909	1,064	(13,675)	177,275	1,792	179,067
    Net income for the period						43,265			43,265	5	43,270
    Income and expense recognised directly in equity						(9,094)	(1,015)	30,880	20,771		20,771
    Total recognised income and expense for the period*											64,041
    Dividend paid						(27,082)			(27,082)		(27,082)
    Cash distributions (to) from minority shareholders										179	179
    Equity settled share based payments
    (net of allocated shares)				80					80		80
    Treasury shares purchased (net of allocated shares)			(3)		(227)				(230)		(230)
    At 31 December 2008	3,188,647,103	7,972	(9)	41,450	(586)	147,998	49	17,205	214,079	1,976	216,055

    * For detailed information, see Consolidated statements of recognised income and expense.

    The NOK 9,094 million reduction in retained earnings in 2008, in the line item Income and expense recognised directly in equity, consist of actuarial losses, net of increase in the related deferred tax asset of NOK 3,704 million, and a reduction in deferred tax assets of NOK 5,390 million due to internal reorganisations, see note 32 Subsequent events for more details on the reorganisations.

    The currency translation adjustments in 2008, on the line item Income and expense recognised directly in equity, relates to the translation of significant net assets amounts in subsidiaries, mainly whose functional currencies are USD and EUR, and are caused by the weakening of the NOK to the USD and EUR.

    For information regarding changes in equity related to the merger with Hydro Petroleum, see information in note 3132 Merger with Hydro Petroleum.

    In 2001, 25,000,000 treasury shares were issued. During 2002 and 2003 a total of 1,558,115 of the treasury shares were distributed as bonus shares in favour of retail investors in the initial public offering in 2001. On 10 May 2006 the annual General Meeting resolved to reduce the company's share capital by a total of NOK 58,604,712.50 through the annulment of the rest of these treasury shares.

    The annual General Meetinggeneral meeting in 2006 authorised the Boardboard of Directorsdirectors to acquire treasury shares for subsequent annulment. Under an agreement with the Norwegian State a proportion of the State's shares should later be redeemed and annulled, so that the State's ownership interest remained unchanged. Both the acquired shares and the firm obligation have been included in Treasury shares since the date the treasury shares have been acquired in the market according to the authorisation. The extraordinary General Meetinggeneral meeting on 5 July 2007 approved a reduction of the share capital by NOK 50,397,120 through the annulment of 5,867,000 acquired treasury shares, and redemption and annulment of an additional 14,291,848 shares held by the State. The State, represented by the Ministry of Petroleum and Energy, received a payment of NOK 2,441,899,894 for the shares. The amount corresponded to the average volume-weighted price of the Company'scompany's treasury shares acquired in the market with the addition of interest. As of 31 December 20082009 the Norwegian State had an ownership interest in StatoilHydroStatoil of 66.42%67% (excluding Folketrygdfondet of 3.42% (Norwegian national insurance fund) of 3.26%). The Norwegian State is defined as a related party, see note 2729 Related parties.

    After the annulment in 2007, StatoilHydro'sStatoil share capital of NOK 7,971,617,757.50 comprised 3,188,647,103 shares at a nominal value of NOK 2.50.

    The Boardboard of Directorsdirectors is authorised on behalf of the Companycompany to acquire StatoilHydroStatoil shares in the market. The authorisation may be used to acquire StatoilHydroStatoil shares with an overall nominal value of up to NOK 15 million. The Board decides the manner in which the acquisition of StatoilHydro shares in the market will take place. Such shares acquired in accordance with the authorisation may only be used for sale and transfer to employees of the StatoilHydro GroupStatoil group as part of the Group'sgroup's share saving plan approved by the Board.board. The lowestminimum and maximum amount whichthat may be paid per share iswill be NOK 50 the highest amount which may be paid per share is a maximum NOK 500.and 500, respectively. The authorisation is valid until the next ordinary General Meeting.general meeting.

    During 20082009 a total of 2,106,2232,663,357 treasury shares were purchased for NOK 308343 million. At 31 December 2008 StatoilHydro2009 Statoil had 3,781,2096,028,607 treasury shares all of which are related to the group's share saving plan.

    StatoilHydroStatoil ASA has only one class of shares and all shares have voting rights. The holders of ordinary shares are entitled to receive dividends as declared from time to time and are entitled to one vote per share at general meetings of the Company.company.

    Dividends declared and paid per share were NOK 8.507.25 in 20082009 for StatoilHydroStatoil ASA and NOK 9.128.50 and NOK 8.209.12 in 2008 2007 and 2006,2007, respectively for the former Statoil ASA. In addition, under terms of the merger plan Hydro Petroleum was charged the dividend payment of NOK 6.1 billion paid by Norsk Hydro ASA to its shareholders in 2007. Dividend payments for 2007 included in StatoilHydro'sStatoil's equity include both the former Statoil ASA and Hydro Petroleum dividend payments. A dividend for 20082009 of NOK 7.256.00 per share, amounting to a total dividend of NOK 23.119.1 billion, will be proposed at the Annual General Meetingannual general meeting in May 2009.2010. The proposed dividend is not recognised as a liability in the financial statements.

    Retained earnings available for distribution of dividends at 31 December 20082009 is limited to the retained earnings of the parent company based on Norwegian accounting principles and legal regulations and amounted to NOK 120,168117,160 million (before provisions for proposed dividend for the year ended 31 December 20082009 of NOK 23,09019,100 million). This differs from retained earnings in the consolidatedConsolidated financial statements of NOK 147,998145,909 million. In accordance with legal requirements dividends is not allowed to reduce the shareholders' equity of the parent company below 10% of total assets.

     Top 

    8.1.208.1.22 Non-current financial liabilities

    	Weighted average interest rates in %		Carrying amount in NOK million at 31 December		Fair value in NOK million at 31 December
    	2009	2008	2009	2008	2009	2008
    Financial liabilities measured at amortised cost
    Unsecured bonds
    US dollar (USD)	5.85	6.84	40,610	23,617	43,632	25,312
    Euro (EUR)	5.13	5.58	27,515	6,101	30,397	6,458
    Swiss franc (CHF)		4.01	-	1,023	-	1,032
    Japanese yen (JPY)	1.66	1.65	312	388	322	376
    Great Britain Pound (GBP)	6.71	6.13	9,556	2,271	11,391	1,935
    Total			77,993	33,400	85,742	35,113
    Unsecured loans
    US dollar (USD)	0.71	2.74	5,697	6,899	5,639	6,726
    Japanese yen (JPY)	1.65	1.65	501	620	516	607
    Secured bank loans
    US dollar (USD)	3.74	5.86	864	1,252	894	1,262
    Other currencies	4.63	6.82	135	63	135	63
    Financial lease liabilities			13,747	5,665	13,747	5,665
    Other liabilities			293	864	293	855
    Total			21,237	15,363	21,224	15,178
    Financial liabilities measured at amortised cost
    subject for hedge accounting
    US dollar (USD)		5.94	-	9,957	-	7,403
    Euro (EUR)		5.13	-	2,097	-	2,050
    Total			-	12,054	-	9,453
    Grand total liabilities outstanding			99,230	60,817	106,966	59,744
    Less current portion			3,268	6,211	3,268	6,183
    Financial liabilities			95,962	54,606	103,698	53,561

    On 11 March 2009 Statoil ASA executed the issuance of a GBP 0.8 billion bond maturing in March 2031, a EUR 1.2 billion bond maturing in March 2021 and a EUR 1.3 billion bond maturing in March 2015. All bonds were issued under Statoil ASA's Euro Medium Term Note Programme and have been listed on the London Stock Exchange.

    On 23 April 2009 Statoil ASA executed the issuance of a USD 0.5 billion bond maturing in April 2014 and a USD 1.5 billion bond maturing in April 2019. These registered bonds were issued under the Registration Statement on Form F-3 ("Shelf Registration") filed with the SEC in the United States.

    On 15 October 2009 Statoil ASA executed the issuance of a USD 0.9 billion bond maturing in October 2014. The registered bond was issued under the Registration Statement on Form F-3 ("Shelf Registration") filed with the SEC in the United States.

    Non-current financial liabilities include financial lease obligations. More information is given in note 27 Leases.

    	Weighted average interest rates in %		Carrying amount in NOK million at 31 December		Fair value in NOK million at 31 December
    	2008	2007	2008	2007	2008	2007
    Financial liabilities measured at amortised cost
    Unsecured bonds
    US dollar (USD)	6.78	7.00	24,202	17,418	25,709	20,016
    Norwegian kroner (NOK)	-	6.21	-	500	-	501
    Euro (EUR)	5.58	5.62	6,101	5,316	6,458	5,634
    Swiss franc (CHF)	4.01	-	1,023	-	1,032	-
    Japanese yen (JPY)	1.65	1.50	1,008	869	983	878
    Great Britain Pound (GBP)	6.13	6.13	2,271	2,429	1,935	2,543
    Total (A)			34,605	26,532	36,117	29,572
    Unsecured bank loans
    US dollar (USD)	2.60	5.09	6,314	2,530	6,329	2,549
    Secured bank loans
    US dollar (USD)	5.86	7.45	1,252	2,683	1,262	2,792
    Other currencies	6.82	6.57	63	80	63	80
    Financial lease liabilities			5,665	4,011	5,665	3,738
    Other liabilities			864	38	855	38
    Total (B)			14,158	9,342	14,174	9,197
    Financial liabilities measured at amortised cost
    subject for hedge accounting
    US dollar (USD)	5.94	6.29	9,957	7,845	7,403	7,849
    Euro (EUR)	5.13	5.13	2,097	1,627	2,050	1,636
    Swiss franc (CHF)	-	4.01	-	982	-	979
    Japanese yen (JPY)	-	0.47	-	241	-	241
    Total (C)			12,054	10,695	9,453	10,705
    Grand total liabilities outstanding (A+B+C)			60,817	46,569	59,744	49,474
    Less current portion			6,211	2,196	6,183	2,196
    Financial liabilities			54,606	44,373	53,561	47,278

    The third section of the table above contains bonds valued at amortised cost as adjusted for the fair value of hedged interest rate risk for the bonds that qualify for hedge accounting. As of 1 January 2009 no bonds are subject to hedge accounting. The table does not illustrate the economic effects of agreements entered into to swap the various currencies into USD. For further information see note 2930 Financial instruments by category.

    Weighted average interest rates are calculated based on the contractual rates on the loans per currency at 31 December and do not reflect swap agreements.

    Fair value is calculated by discounting cash flows based on year-end market interest rates from external sources. Year-end market interest rates used as discount rates are derived from LIBOR and EURIBOR adjusted for credit premiums. Credit premiums are based on indicative pricing from external financial institutions.

    Details of largest unsecured bonds
    	Fixed interest rate	Maturity (year)	Carrying amount in NOK million at 31 December
    Bond agreement			2008	2007
    USD 500 million	6.500 %	2028	3,462	2,675
    USD 500 million	5.125 %	2014	3,498	2,704
    USD 480 million	7.250 %	2027	3,363	2,600
    USD 375 million	5.750 %	2009	2,624*	2,026*
    USD 300 million	7.750 %	2023	2,100	1,623
    USD 300 million	6.360 %	2009	2,100	1,623
    EUR 500 million	5.125 %	2011	4,915	3,961
    EUR 300 million	6.250 %	2010	2,960	2,388
    GBP 225 million	6.125 %	2028	2,277	2,432

    * Net after buy-backs NOK 2,288 million and NOK 1,765 million in 2008 and 2007, respectively.

    Details of largest unsecured bonds:
    				Carrying amount in NOK million at 31 December
    Bond agreement	Fixed interest rate	Issued (year)	Maturity (year)	2009	2008
    USD 1500 million	5.250%	2009	2019	8,613	-
    USD 900 million	2.900%	2009	2014	5,174	-
    USD 500 million	3.875%	2009	2014	2,870	-
    USD 500 million	5.125%	2004	2014	2,887	3,498
    USD 500 million	6.500%	1998	2028	2,859	3,462
    USD 481 million	7.250%	2000	2027	2,776	3,363
    USD 300 million	7.750%	1993	2023	1,733	2,100
    EUR 1300 million	4.375%	2009	2015	10,782	-
    EUR 1200 million	5.625%	2009	2021	9,887	-
    EUR 500 million	5.125%	1999	2011	4,148	4,915
    EUR 300 million	6.250%	1999	2010	2,494	2,960
    GBP 800 million	6.875%	2009	2031	7,421	-
    GBP 225 million	6.125%	1998	2028	2,096	2,277

    Currency swaps are used for risk management purposes. Unsecured bonds are either denominated in US dollar, amounting to NOK 34,159 million41.1 billion or the amountsbonds are swapped into US dollar, amounting to NOK 12,500 million. As a result of this the total portfolio is exposed to changes in the USDNOK exchange rate. None of the US dollar currency swaps entered into as economic hedges meet the criteria for hedge accounting.37.9 billion. Interest rate swaps are used to manage the interest rate risk on the unsecured bond contracts with fixed interest rates. As a result of thisresul the majority of the portfolio is swapped from fixed to floating interest rate.

    Substantially all unsecured bond and unsecured bank loan agreements contain provisions restricting the pledging of assets to secure future borrowings without granting a similar secured status to the existing bondholders and lenders.

    The group's secured bank loans in USD have been secured by mortgage of shares in a subsidiary and investments in associated companies with a combined book value of NOK 2,908 million, collateral in bank deposits with book value of NOK 1,070 million,2.3 billion, and the group's pro-rata share of income from certain applicable projects.

    The group has 2427 unsecured bond agreements outstanding, which contain provisions allowing the group to call the debt prior to its final redemption at par or at certain specified premiums if there are changes to the Norwegian tax laws. The agreements carrying value isare NOK 42,722 million75.9 billion at the 31 December 20082009 closing rate.
    
    The group has an agreement with an international bank syndicate for a committed non-current revolving credit facility totalling USD 2.0 billion, all undrawn at the 31 December 2008. The commitment feesupported by core banks. For more information see note 6 Financial risk management.

    Non-current financial liabilities maturity profile
    	At 31 December
    (in NOK million)	2009	2008
    Year 2 and 3	11,757	9,653
    Year 4 and 5	11,496	9,739
    After 5 years	72,709	35,214
    Total repayment of non-current financial liabilities	95,962	54,606

    Redemption profile for undiscounted cash flows is 0.0575% per annum.shown in note 6 Financial risk management.

    Non-current financial liabilities maturity profile
    	At 31 December
    (undiscounted cash flows in NOK million)	2008	2007
    1-3 years	14,635	13,112
    3-5 years	14,095	13,651
    After 5 years	53,324	46,438
    Total repayment of non-current financial liabilities	82,055	73,201

     

    Financial liabilities
    	At 31 December
    	2008	2007
    Non-current financial liabilities (in NOK million)	54,606	44,373
    Weighted average maturity (years)	9	10
    Weighted average annual interest rate (%)	5.64	6.11

    Non-current financial liabilities
    	At 31 December
    (in NOK million)	2009	2008
    Non-current financial liabilities	95,962	54,606
    Weighted average maturity	9	9
    Weighted average annual interest rate	4.77	5.64

     

     Top 

    8.1.218.1.23 Pension liabilities

    The Norwegian companies in the group are obligated to follow the Act on Mandatory company pensions. The company's pension scheme follows the requirement as included in the Act.

    StatoilHydroStatoil ASA and many of its subsidiaries have defined benefit retirement plans, which cover substantially all of their employees. Plan benefits are generally based on years of service and final salary level. The cost of pension benefit plans is expensed over the period that the employee renders services and becomes eligible to receive benefits. The obligations related to defined benefit plans are calculated by external actuaries.

    
     
    Some companies in the groupStatoil have defined contribution plans. The period's contributions are recognised in the Consolidated StatementsStatement of Incomeincome as the pension cost for the period.

    In Norway, the groupStatoil is - due to National agreements - a member of the "agreement-based early retirement plan" (AFP). WhenThe members pay an employee retires through AFP the group has an obligation to pay a percentage of the benefits.annual fee per active employee. This part of the plan is defined as a multi-employer plan. The administrator of this plan is not able to calculate the group'smembers' share of assets and liabilities and this plan is consequently accounted for as a defined contribution plan. In addition the members have an obligation to pay a percentage of the benefits when an employee retires through AFP. This obligation is accounted for as a defined benefit plan. When an employee retires through AFP, the groupStatoil also offers a gratuity from the company.gratuity. This is also a defined benefit plan, and included in the accrued obligationsprovision related to the defined benefit plans.

    A new legislation on the AFP was passed by the Norwegian Parliament 19 February 2010. This law is one part of the Norwegian pension and insurance reform effective from 1 January 2011. Several new laws affecting Norwegian pension and insurance schemes will be passed during 2010. Together with the revised national state pension and insurance legislation this forthcoming legislation will establish a new framework for private sector pension schemes in Norway which requires review and adaptations of existing schemes. Statoil will undertake a review of the total pension scheme during 2010 as a basis for deciding a revised model based on the new legislation.

    The obligations related to the defined benefit plans were measured at 31 December, 20082009 and 2007.2008. The present values of the projected defined benefit obligation and the related current service cost and past service cost are measured using the projected unit credit method. The assumptions for salary increases, increases in pension payments and social security base amount have been tested against historical observations. At 31 December 20082009 the discount rate for the defined benefit plans in Norway was estimated to be 4.5%4.75% based on the long-term interest rate on Norwegian government bonds extrapolated based on a 3020 year yield curve to match StatoilHydro'sStatoil's payment portfolio for earned benefits.

    The longest duration of Norwegian government bonds are 10 years. It is StatoilHydro's opinion that the most appropriate method to extrapolate the 10 years rate to a 30 year rate is based on the yield curves with reference to European and USA interest rates (equally weighted). In a long term perspective, these countries are assumed to have similar market trends and interest levels as Norway.

    Actuarial gains and losses are recognisedrecorded directly in retained earnings, outside the Consolidated Statements of Income,Other comprehensive income in the period in which they occur, and are presented inoutside the statementStatement of recognised income and expense.income. Actuarial gains and losses related to the accrualprovision for termination benefits are recognised in the Consolidated StatementsStatement of Incomeincome in the period in which they occur.

    PayrollSocial security tax is calculated based on the pension plan's net unfunded status. PayrollSocial security tax is included in the projected benefit obligation.

    StatoilHydroStatoil has more than one defined benefit plan but the disclosure is made in total since the plans are not subject to materially different risks. Pension plans outside Norway are insignificant and not disclosed separately.
    

    Net periodic pension cost				Net periodic pension cost
    (in NOK million)	2008	2007	2006	2009	2008	2007
    Current service cost	2,361	2,611	2,065	2,747	2,361	2,611
    Interest cost on prior years' benefit obligation	2,456	1,713	1,421	2,550	2,456	1,713
    Expected return on plan assets	(2,101)	(1,829)	(1,407)	(1,896)	(2,101)	(1,829)
    Amortisation of actuarial gain or loss related to termination benefits	(215)	0		(172)	(215)	0
    Amortisation of past service cost	17	2,075	0	0	17	2,075
    Losses (gains) from curtailment or settlement	(7)	(1,641)	0	0	(7)	(1,641)
    Defined benefit plans	2,511	2,929	2,079	3,229	2,511	2,929
    Defined contribution plans	268	160	155	240	268	160
    Multi-employer plans	72	42	47	69	72	42
    Termination benefits	0	8,633	49	0	0	8,633
    Net pension cost	2,851	11,764	2,330
    Total net pension cost				3,538	2,851	11,764

    Pension cost includes payrollsocial security tax.

    Pension cost is partly charged to partners of StatoilHydroStatoil operated licences.

    For information regarding pension benefits for key management personnel, see note 2729 Related parties.

    In 2007, StatoilHydroStatoil ASA offered early retirement (termination benefits) to employees above the age of 58 years (contingent upon certain conditions). The expenses related to termination benefits of NOK 5.6 billion and NOK 3.0 billion were recognised as Operating expenses and Selling, general and administrationadministrative expenses, respectively.

    Change in projected benefit obligation (PBO)
    (in NOK million)	2008	2007
    Projected benefit obligation at 1 January	52,791	40,185
    Current service cost	2,361	2,611
    Interest cost on prior years' benefit obligation	2,456	1,713
    Actuarial loss (gain)	3,581	198
    Past service cost	18	2,075
    Benefits paid	(1,302)	(605)
    Curtailments	0	(1,641)
    Early retirement	0	8,633
    Sale of subsidiary	(670)	0
    Settlement	0	(329)
    Foreign currency translation	(29)	(49)
    Projected benefit obligation at 31 December	59,206	52,791
    Change in pension plan assets
    (in NOK million)	2008	2007
    Fair value of plan assets at 1 January	35,158	30,110
    Expected return on plan assets	2,101	1,829
    Actuarial gain (loss)	(4,149)	(236)
    Company contributions (including payroll tax)	1,377	3,777
    Benefits paid	(346)	(338)
    Sale of subsidiary	(443)	11
    Foreign currency translation	0	5
    Fair value of plan assets at 31 December	33,698	35,158

     

    Change in net pension liabilities
    (in NOK million)	2008	2007
    Net pension liabilities at 1 January	(17,633)	(10,078)
    Net periodic pension costs defined benefit plans	(2,511)	(2,929)
    Net actuarial loss (gain) recognised in SORIE	(7,945)	(434)
    Less employer contributions	1,377	3,777
    Less benefit paid during year	956	259
    Acquisition and sale	227	11
    Settlement	0	340
    Foreign currency translation and other changes	21	54
    Termination benefits	0	(8,633)
    Net pension liabilities at 31 December	(25,508)	(17,633)

    Change in projected benefit obligation (PBO)
    (in NOK million)	2009	2008
    Projected benefit obligation at 1 January	59,206	52,791
    Current service cost	2,747	2,361
    Interest cost on prior years' benefit obligation	2,550	2,456
    Actuarial loss (gain)	(1,308)	3,581
    Past service cost	0	18
    Benefits paid	(1,520)	(1,302)
    Acquisition and sale	0	(670)
    Foreign currency translation	(248)	(29)
    Projected benefit obligation at 31 December	61,427	59,206

     

    Surplus (deficit) at 31 December for the current and previous two periods are as follow:
    (in NOK million)	2008	2007	2006
    Surplus (deficit) at 31 December	(25,508)	(17,633)	(10,078)
    Represented by:
    Asset recognised as pension asset	30	1,622	1,113
    Liability recognised as non-current pension liability	(25,538)	(19,092)	(11,028)
    Liability recognised as current liability	0	(163)	(163)
    The defined benefit obligation may be analysed as follows:
    (in NOK million)		2008	2007
    Funded pension plans		(37,446)	(33,278)
    Unfunded pension plans		(21,760)	(19,513)
    Projected benefit obligation at 31 December		(59,206)	(52,791)

    Change in pension plan assets
    (in NOK million)	2009	2008
    Fair value of plan assets at 1 January	33,698	35,158
    Expected return on plan assets	1,896	2,101
    Actuarial gain (loss)	2,819	(4,149)
    Company contributions (including payroll tax)	4,956	1,377
    Benefits paid	(385)	(346)
    Acquisition and sale	0	(443)
    Foreign currency translation	(5)	0
    Fair value of plan assets at 31 December	42,979	33,698

    The tables above for Change in projected benefit obligation (PBO) and Change in pension plan assets do not include currency effects for Statoil ASA. For more information see table Actuarial gains and losses recognised directly in Other comprehensive income below.

    Total provision for pensions
    (in NOK million)	2009	2008
    Balance sheet provision at 1 January	(25,508)	(17,633)
    Net periodic pension costs defined benefit plans	(3,229)	(2,511)
    Net actuarial (loss) gain recognised in Other Comprehensive Income	3,191	(7,945)
    Less employer contributions/benefit paid during year	4,956	1,377
    Less benefit paid during year	1,135	956
    Acquisition and sale	0	227
    Foreign currency translation and other changes	1,007	21
    Balance sheet provision at 31 December	(18,448)	(25,508)

     

    Actuarial gains and losses recognised directly in retained earnings:
    (in NOK million)	2008	2007	2006
    Unrecognised actuarial losses (gains) at 1 January	0	0	0
    Actuarial losses (gains) on plan assets occur during the year	4,149	(272)	(1,139)
    Actuarial losses (gains) on benefit obligation occur during the year	3,581	198	4,169
    Recognised in the income statement during the year	215	0	0
    Recognised in SORIE during the year	(7,945)	74	(3,030)
    Unrecognised actuarial losses (gains) at 31 December	0	0	0
    Actual return on plan assets
    (in NOK million)	2008	2007	2006
    Actual return on plan assets	(2,048)	1,593	2,546

    Surplus (deficit) at 31 December
    (in NOK million)	2009	2008	2007
    Surplus (deficit) at 31 December	(18,448)	(25,508)	(17,633)
    Represented by:
    Asset recognised as non-current pension asset	2,694	30	1,622
    Liability recognised as non-current pension liability	(21,142)	(25,538)	(19,092)
    Liability recognised as current liability	0	0	(163)

     

    History of experience gains and losses for the current and previous two periods are as follow:
    (in NOK million)	2008		2007		2006
    Actual return less expected return on plan assets (NOK million)	(4,149)		272		1,139
    As % of plan assets at beginning of year	(11.80%)		0.90%		4.45%
    Experience gains/(losses) on plan liabilities (NOK million)	(3,581)		(198)		(4,169)
    As % of present value of plan liabilities at beginning of year	(6.78%)		(0.49%)		(12.60%)
    Total actuarial gain/(loss) (NOK million)	(7,730)		74		(3,030)
    As % of present value of plan liabilities at beginning of year	(14.64%)		0.25%		(9.16%)

    Projected benefit obligation splitted on funded and unfunded plans
    (in NOK million)	2009	2008	2007
    Funded pension plans	(40,212)	(37,446)	(33,278)
    Unfunded pension plans	(21,215)	(21,760)	(19,513)
    PBO at 31 December	(61,427)	(59,206)	(52,791)

    Actuarial gains and losses recognised directly in Other comprehensive income
    (in NOK million)	2009	2008	2007
    Unrecognised actuarial losses (gains) at 1 January	0	0	0
    Actuarial losses (gains) on plan assets occurred during the year	(2,819)	4,149	(272)
    Actuarial losses (gains) on benefit obligation occurred during the year	(1,308)	3,581	198
    Actuarial losses (gains) related to currency effects on net obligation	3,867	0	0
    Foreign exchange translation	(3,103)	0	0
    Recognised in the income statement during the year	172	215	0
    Recognised in Other comprehensive income during the year	3,191	(7,945)	74
    Unrecognised actuarial losses (gains) at 31 December	0	0	0

    Statoil ASA changed its functional currency as of 1 January 2009, for further information see note 1 Organisation and note 2 Significant accounting policies. In the table above Actuarial losses (gains) related to currency effects on net obligation refer to translation of the net pension obligation in ASA in NOK to the functional currency US dollar. The line Foreign exchange translation refer to translation from functional currency US dollar to presentation currency NOK.

    Actual return on plan assets
    (in NOK million)	2009	2008	2007
    Actual return on plan assets	4,715	(2,048)	1,593

    History of experience gains and losses

    (in NOK million)	2009
    Difference between the expected and actual return on plan assets
    a) Amount	(2,819)
    b) Percentage of plan assets	(6.56%)
    Experience (gain) loss on plan liabilities
    a) Amount	(1,996)
    b) Percentage of present value of plan liabilities	(3.40%)

    The cumulative amount of actuarial gains and losses recognised directly in the Statement of recognisedOther comprehensive income and expense amounted to NOK 10.9, NOK 13.3 and NOK 4.2 billion and NOK 4.5 billion net of tax (negative effect on retained earnings)Other comprehensive income) in 2009, 2008 and 2007, and 2006, respectively.
    

    Assumptions for the year ended (Profit and Loss items) in %	2008		2007
    Discount rate	5.00		4.50
    Expected return on plan assets	6.25		5.75
    Rate of compensation increase	4.50		4.25
    Expected rate of pension increase	3.25		2.75
    Expected increase of social security base amount (G-amount)	4.25		4.00
    Expected inflation	2.25		2.25
    Assumptions at end of year (Balance sheet items) in %	2008		2007
    Discount rate	4.50		5.00
    Expected return on plan assets	5.75		6.25
    Rate of compensation increase	4.00		4.50
    Expected rate of pension increase	2.75		3.25
    Expected increase of social security base amount (G-amount)	3.75		4.25
    Inflation	2.00		2.25
    Average remaining service period in years	15		15

    Weighted-average assumptions for the year ended (Profit and Loss items) in %	2009	2008
    Discount rate	4.50	5.00
    Expected return on plan assets	5.75	6.25
    Rate of compensation increase	4.00	4.50
    Expected rate of pension increase	2.75	3.25
    Expected increase of social security base amount (G-amount)	3.75	4.25
    Inflation	2.00	2.25
    Weighted-average assumptions at end of year (Balance sheet items) in %	2009	2008
    Discount rate	4.75	4.50
    Expected return on plan assets	6.00	5.75
    Rate of compensation increase	4.25	4.00
    Expected rate of pension increase	3.00	2.75
    Expected increase of social security base amount (G-amount)	4.00	3.75
    Inflation	2.25	2.00
    Average remaining service period in years	15	15

    The assumptions presented are for the Norwegian companies in the groupStatoil which are members of StatoilHydro'sStatoil's pension fund. The defined benefit plans of other subsidiaries are not significant to the consolidated pension assets and liabilities of the group.liabilities.

    Expected turnoverattrition at 31 December 2009 was 2.0%, 2.0%, 1.5%, 0.5% and 0.0% for the employees under 30 years, 30-39 years, 40-49 years, 50-59 years and 60-67 years, respectively. Expected attrition at 31 December 2008 was 2.0%, 2.0%, 1.5%, 0.5% and 0.0% for the employees under 30 years, 30-39 years, 40-49 years, 50-59 years and 60-67 years, respectively. Expected turnover at 31 December 2007 was 4.0%, 1.5%, 1.3%, 0.5% and 0.0% for the employees under 30 years, 30-39 years, 40-49 years, 50-59 years and 60-67 years, respectively.

    Expected utilisation of Agreement-based early retirement pension (AFP)AFP is 50% for employees at 62 years and 30% for the remaining employees at 63-66 years.

    For the population in Norway, the mortality table K 2005 plus one extra yearincluding the minimum requirements from The Financial Supervisory Authority of livingNorway (Finanstilsynet), hence reducing the mortality rate with a minimum of 15% for male and 10% for female for each employee is used as the best mortality estimate. The disability table, KU, developed by the insurance company Storebrand, aligns with the actual disability risk for StatoilHydroStatoil in Norway.

    Below is shown a selection related to demographic assumptions used at 31 December 2008.2009. The table shows the probability of disability or death, within one year, by age groups as well as expected lifetime.
    

    	Disability in %		Mortality in %		Expected lifetime		Disability in %		Mortality in %		Expected lifetime
    Age	Men	Women	Men	Women	Men	Women	Men	Women	Men	Women	Men	Women
    20	0.12	0.15	0.015		81.51	85.35	0.12	0.15	0.02		82.46	85.24
    40	0.21	0.35	0.083	0.046	81.83	85.60	0.21	0.35	0.09	0.05	82.74	85.47
    60	1.48	1.94	0.716	0.386	83.27	86.51	1.48	1.94	0.75	0.41	84.02	86.31
    80	N/A		6.550	4.142	88.97	90.74	N/A		6.69	4.31	89.26	90.29

    Sensitivity analysis
    The table below shows an estimate of the potential effects of changes in the key assumptions for the defined benefit plans. The following estimates are based on facts and circumstances as of 31 December 2008.2009. Actual results may materially deviate from these estimates.
    

    	Discount rate		Rate of compensation increase		Social security base amount		Expected rate of pension increase		Discount rate		Rate of compensation increase		Social security base amount		Expected rate of pension increase
    (in NOK billion)	0.5%	-0.5%	0.5%	-0.5%	0.5%	-0.5%	0.5%	-0.5%	0,25%	-0,25%	0,25%	-0,25%	0,25%	-0,25%	0,25%	-0,25%
    Changes in:									Changes in:
    Projected benefit obligation at 31 December 2008	(4.8)	5.5	3.9	(3.5)	(1.5)	1.5	3.1	(2.8)
    Service cost 2009	(0.3)	0.4	0.3	(0.3)	(0.1)	0.1	0.2	(0.2)
    Projected benefit obligation at 31 December 2009									(2.07)	2.21	0.91	(0.92)	(1.86)	2.06	1.00	(0.95)
    Service cost 2010									(0.14)	0.15	0.06	(0.06)	(0.13)	0,15	0.06	(0.06)

    Pension assets
    The plan assets related to the defined benefit plans were measured at fair value at 31 December 20082009 and 2007.2008. The long-term expected return on pension assets is based on long-term risk-free interest rate adjusted for the expected long-term risk premium for the respective investment classes. A risk free interest rate (the Norwegian Government bond with a life of 10 year included markup for estimating a longer interest rate than ten year) is applied as a starting point for calculation of return on plan assets. The return in the money market is calculated by taking a deduction on bond yield. Based on historical data, equities and real estate are expected to give a long-term additional return above money market.

    In its asset management, the pension fund aims at achieving long-term returns which contribute towards meeting future pension liabilities. Assets are managed to achieve a return as high as possible within a framework of public regulation and risk management policies. The pension fund's target returns require investments in assets with a higher risk than risk-free investments. Risk is reduced through maintaining a well diversified asset portfolio. Assets are diversified both in terms of location and different asset classes. Derivatives are used within set limits to facilitate effective asset management.

    Pension assets allocated on respective investments classes
    (in %)	2008	2007
    Equity securities	19.10	31.90
    Debt securities	70.20	50.50
    Commercial papers	3.30	8.60
    Real estate	6.90	6.90
    Other assets	0.50	2.10
    Total	100.00	100.00

    Pension assets allocated on respective investments classes
    (in %)	2009	2008
    Equity securities	39.60	19.10
    Bonds	39.40	70.20
    Commercial papers	14.70	3.30
    Real estate	5.10	6.90
    Other assets	1.20	0.50
    Total	100.00	100.00

    Properties owned by StatoilHydro pensionStatoil Pension fund amounted to NOK 2.22.1 billion and NOK 2.32.2 billion of total pension assets at 31 December 20082009 and 2007,2008, respectively, and are rented to companies in the group.Statoil companies.

    
    
    StatoilHydro'sStatoil's pension fund invests in both financial assets and real estate. The expected rate of return on real estate is expected to be between the rate of return on equity securities and debt securities. The table below presents the portfolio weight and expected rate of return of the finance portfolio as approved by the Board of the StatoilHydroStatoil pension fund for 2009.2010. The portfolio weight during a year will depend on the risk capacity.

    Finance portfolio StatoilHydro's pension funds
    

    Finance portfolio Statoil's pension funds
    (All figures in %)	Portfolio weight 1)		Expected rate of return
    (All figures in %)
    Equity securities	40.00	(+/- 5)	X + 4
    Debt securitiesBonds	59.50	(+/- 5)	X
    CertificatesCommercial papers	0.50	(+(+15/-0.5)- 0.5)	X -0,4- 0.4
    Total finance portfolio	100.00

    1) The brackets express the scope of tactical deviation by Statoil Kapitalforvaltning ASA (the asset manager).
    X) Long-term rate of return on debt securities.

    Contributions to pension plans may either be paid in cash or be deducted from the pension premium fund. The pension premium fund amounted to NOK 4.57.2 billion and NOK 7.34.5 billion at 31 December 20082009 and 2007,2008, respectively. The decision whether to pay in cash or deduct from the pension premium fund is made on an annual basis. In 2009 a pension premium amounting to NOK 4.1 billion was paid. In addition Statoil intends to pay to the pension premium fund approximately NOK 3.3 billion late March 2010. In 2008, NOK 2.9 billion was deducted from the pension premium fund. The company contribution in 2008, paid in cash, was NOK 0.2 billion (exclusive payrollsocial security tax). In addition, NOK 1.2 billion was paid to StatoilHydroStatoil pension fund as a capital increase in 2008. In 2007, the company contribution, paid in cash, was NOK 3.4 billion (exclusive payroll tax) of which NOK 1.0 billion was a voluntary payment to the premium fund.

    The expected company contribution related to 20092010 amounts to NOK 2.52.1 billion.

     Top 

    8.1.228.1.24 Asset retirement obligations, other provisions and other liabilities

    (in NOK million)
    Asset retirement obligations at 1 January 20072008	39,912  39,581
    Liabilities incurred/revision in estimates	(1,644)  5,470
    Amounts used and charged against provisionprovisions	(636)  (675)
    Unused amounts reversed	-0
    Effects of change in the discount rate	443  (2,234)
    Reduction due to disposals	(120)  (1,402)
    Accretion	2,099   2,107
    Currency exchange difference	(473)  1,239
    Asset retirement obligationobligations at 31 December 20072008	39,581  44,086
    Current portion of asset retirement obligations	575  905
    Analysis of provisions and other liabilities at 31 December 2007:2008:
    Non-current portion of asset retirement obligations	39,006
    Other provisions and other liabilities	4,839
    Asset retirement obligations, other provisions and other liabilities	43,845
    Asset retirement obligations at 1 January 2008	39,581
    Liabilities incurred/revision in estimates	5,470
    Amounts used and charged against provision	(675)
    Unused amounts reversed	-
    Effects of change in the discount rate	(2,234)
    Reduction due to disposals	(1,402)
    Accretion	2,107
    Currency exchange difference	1,239
    Asset retirement obligations at 31 December 2008	44,086
    Current portion of asset retirement obligations	905
    Analysis of provisions and other liabilities at 31 December 2008:
    Non current portion of asset retirement obligations	43,181
    Other provisions	11,178
    Asset retirement obligations, other provisions and other liabilities at 31 December 2008	54,359

    (in NOK million)	Asset retirement obligations	Other provisions	Other liabilities	Total Provisions
    Non-current portion at 1 January 2009	43,181	9,660	1,518	54,359
    Current portion at 1 January 2009	1,260	500	0	1,760
    Provisions at 1 January 2009	44,441	10,160	1,518	56,119
    Liabilities incurred/revision in estimates	1,853	(2,002)	15	(134)
    Amounts used and charged against provisions	(523)	(608)	0	(1,131)
    Unused amounts reversed	0	(153)	0	(153)
    Effects of change in the discount rate	3,090	0	0	3,090
    Reduction due to disposals	(767)	0	0	(767)
    Accretion	2,432	0	0	2,432
    Currency exchange difference	(1,599)	(171)	0	(1,770)
    Provisions at 31 December 2009	48,927	7,226	1,533	57,686
    Current portion at 31 December 2009	515	1,044	0	1,559
    Long term interest bearing provisions reported as financial liability	0	293	0	293
    Non-current portion at 31 December 2009	48,412	5,889	1,533	55,834

    Asset retirement obligations
    A majority of expenditures related to asset retirement obligations are currently expected to be paid in the period between 2015 and 2025. Only a minor portion of expenditures are expected to be paid in the next five years. The timing depends primarily on when the production ceases at the various facilities. For further discussion of methods applied and estimates required, see note 2 Significant accounting policies.

    Obligations related to environmental remediation and cleanup related to oil and gas producing assets are included in the estimated asset retirement obligations.

     Top 

    8.1.238.1.25 Trade and other payables

    	At 31 December
    (in NOK million)	2008	2007
    Trade payables	15,582	21,776
    Non-trade payables, accrued expenses and provisions	38,155	29,918
    Payables to associated companies and other related parties	7,463	12,930
    Trade and other payables	61,200	64,624

    	At 31 December
    (in NOK million)	2009	2008
    Financial trade and other payables:
    Trade payables	17,362	15,582
    Non-trade payables and accrued expenses	31,542	35,945
    Payables to associated companies and other related parties	9,144	7,463
    Total financial trade and other payables	58,048	58,990
    Non-financial trade and other payables	1,753	2,210
    Trade and other payables	59,801	61,200

    Non-trade payables and accrued expenses include provisions for certain claims and litigations that are further described in note 2628 Other commitments and contingencies.

    For currency sensitivities see note 31 Financial instruments: measurement and market risk sensitivities.

     Top 

    8.1.248.1.26 Current financial liabilities

    	At 31 December,
    (in NOK million)	2008	2007
    Current financial liabilities measured at amortised cost
    Bank loans and overdraft facilities	906	1,100
    Collateral liabilities	10,123	2,797
    Commercial paper liabilities	2,989	-
    Current portion of non-current financial liabilities	5,604	1,919
    Current portion of financial lease obligations	607	277
    Other	466	73
    Financial liabilities	20,695	6,166
    Weighted interest rate	2.50%	5.56%

    	At 31 December
    (in NOK million)	2009	2008
    Bank loans and overdraft facilities	196	906
    Collateral liabilities	4,654	10,123
    Commercial paper liabilities	0	2,989
    Current portion of non-current loans	2,686	5,604
    Current portion of financial lease obligations	582	607
    Other financial liabilities	32	466
    Financial liabilities	8,150	20,695
    Weighted interest rate (%)	2.24	2.50

    Carrying amount for Current financial liabilities' carrying amountsliabilities, at amortised cost and accrued interest reasonably approximate fair value. Fair value is based on price inputs from observable markte transactions.

    Collateral liabilities relatesrelate to cash received in order to offsetas security for a portion of the groupgroup's credit exposure.

    Commercial paper liabilities relatesrelate to the US Commercial Paper (CP) program available for short term funding. StatoilHydro can borrow maximum USD 4 billion under the current CP programme.For more information see note 6 Financial risk management.

    At 31 December 20082009 and 20072008 the group had no committed short-term credit facilities available or drawn.

    
    
    

     Top 

    8.1.258.1.27 Leases

    StatoilHydroStatoil leases certain assets, notably vessels and drilling rigs.
    
    StatoilHydroStatoil has entered into certain operational lease contracts for a number of drilling rigs as of 31 December 2008.2009. The remaining significant contracts' terms range from three months to fivefour years. Certain contracts contain renewal options. Rig lease agreements are for the most part based on fixed day rates. StatoilHydro'sStatoil's rig leases have been entered into in order to ensure drilling capacity for sanctioned projects and planned wells and to secure long-term strategic capacity for future exploration and production drilling. Certain rigs have been subleased in whole or for parts of the lease term for the most part to StatoilHydro-operated licensesStatoil-operated licences on the Norwegian Continental Shelf (NCS).NCS. These leases are shown gross as operating leases in the table below. However, for rig leases where the joint venture is the original lessee, StatoilHydroStatoil only includes its proportional share of the rig lease.
    
    As a member of the Snøhvit sellers' group StatoilHydroStatoil has entered into leasing arrangements for three LNG vessels on behalf of StatoilHydroStatoil and the SDFI respectively. StatoilHydroSDFI. Statoil accounts for the combined StatoilHydroStatoil and the SDFI share of these agreements as financialfinance leases in the balance sheet, and further accounts for the SDFI related portion as operating sub-leases. The finance leases included in the balance sheet reflect a leasingthe original lease term of 20 years.years from 2006. In addition, StatoilHydroStatoil has the option to extend the leases for two additional periods of five years each.

    In 2008,2009, net rental expense was NOK 10.9 billion (NOK 10.2 billion (NOKin 2008 and NOK 5.7 billion in 2007 and NOK 4.9 billion in 2006)2007) of which minimum lease payments were NOK 12.7 billion (NOK 11.8 billion (NOKin 2008 and NOK 7.1 billion in 2007 and NOK 5.9 billion in 2006)2007) and sublease payments received were NOK 1.8 billion (NOK 1.7 billion (NOKin 2008 and NOK 1.5 billion in 2007 and NOK 1.0 billion in 2006)2007). No material contingent rents have been expensed in 2009, 2008 2007 or 2006.2007.

    The information in the table below shows future minimum lease payments under non-cancellable leases at 31 December 2008.2009.
    
    Amounts related to financialfinance leases include future minimum lease payments for assets recognised in the financial statements at year-end 2008.2009.

    				Financial lease
    (in NOK million)	Operating Leases	Operating subleases		Minimum lease payments	Interest	Net present value minimum lease payments
    2009	16,101	(2,161)		742	(101)	641
    2010	13,400	(1,274)		684	(110)	574
    2011	9,107	(138)		700	(115)	585
    2012	6,383	(131)		694	(107)	587
    2013	4,375	(131)		469	(108)	361
    Thereafter	3,955	(1,203)		4,731	(1,815)	2,916
    Total future minimum lease payments	53,321	(5,038)		8,020	(2,356)	5,664

    			Financial lease
    (in NOK million)	Operating leases	Operating sublease	Minimum lease payments	Interest	Net present value minimum lease payments
    2010	14.017	(1,560)	627	(93)	534
    2011	10.929	(736)	638	(106)	532
    2012	7.990	(585)	636	(105)	531
    2013	5.262	(589)	444	(107)	337
    2014	1.860	(146)	431	(116)	315
    Thereafter	3.097	(1,324)	3,992	(1,477)	2,515
    Total future minimum lease payments	43,155	(4,940)	6,768	(2,004)	4,764

    In addition to the Net present value of minimum lease payments set out above (NOK 4,764 million), total finance lease obligations include an amount of NOK 8,983 million relating to leased assets under development. When calculating the obligations for leased assets under development, the net present value presented reflects the assets' estimated percentage of completion, unless another value better reflects the realities of the obligation.

    Property, plant and equipment include the following amounts for leases that have been capitalised at 31 December 20082009 and 2007:
    2008:

    (in NOK million)	2008	2007
    Vessels and equipment	6,501	5,503
    Accumulated depreciation	(1,205)	(836)
    Capitalised amount	5,296	4,667

    (in NOK million)	2009	2008
    Leased assets under development	8,983	0
    Vessels and equipment	4,876	6,501
    Accumulated depreciation	(1,404)	(1,205)
    Capitalised amount	12,455	5,296

     

     Top 

    8.1.268.1.28 Other commitments and contingencies

    Contractual commitments
    

    (in NOK million)	2010	2011	Thereafter	Total
    Joint Venture related:
    Construction in progress	12,136	8,643	6,756	27,535
    Property, plant and equipment and other investments	1,946	68	3	2,017
    Acquisition of intangible assets	253	9	0	262
    Subtotal joint venture related commitments	14,335	8,720	6,759	29,814
    Non Joint Venture related:
    Construction in progress	734	0	0	734
    Total	15,069	8,720	6,759	30,548

    (in NOK million)	2009	2010	Thereafter	Total
    Joint Venture related:
    Construction in progress	12,005	5,559	3,866	21,430
    Property, plant and equipment and other investments	3,161	4,176	10,110	17,447
    Acquisition of intangible assets	2,881	173	15	3,069
    Subtotal joint venture related commitments	18,047	9,908	13,991	41,946
    Non Joint Venture related:
    Construction in progress	3,004	2,150	309	5,463
    Total	21,051	12,058	14,300	47,409

    The contractual commitments reflect StatoilHydro'sStatoil's share and mainly comprise construction and acquisition of property, plant and equipment.

    Other long-term commitments
    StatoilHydroStatoil has entered into various long-term agreements for pipeline transportation as well as terminal, processing, storage and entry/exit capacity commitments and commitments related to specific purchase agreements. The agreements ensure the rights to the capacity or volumes in question, but also impose on the group the obligation to pay for the agreed-upon service or commodity, irrespectively of actual use. The contracts' terms vary, with duration of up to 3130 years.

    Take-or-pay contracts for the purchase of commodity quantities are only included in the tables below if their contractually agreed pricing is of a nature that will or may deviate from the obtainable market prices for the commodity at the time of delivery.

    Obligations payable by the group to unconsolidatedentities accounted for using the equity associatesmethod are included gross in the tables below. WhereAs regards assets (e.g. pipelines) that the group reflects both ownership interestsaccounts for by including its share of assets, liabilities, income and transport capacity cost forexpenses (capacity costs) on a pipeline or other assetline-by-line basis in the consolidated accounts,Consolidated financial statements, the amounts in the table include the net commitment payable for StatoilHydro.by Statoil (gross commitment less Statoil's ownership share).

    Nominal minimum commitments at 31 December 2008:
    2009:

    (in NOK million)	Transport and terminal commitments	Refinery related commitments	Total	Transport and terminal commitments	Refinery related commitments	Total
    2009	7,847	127	7,974
    2010	7,851	262	8,113	8,676	715	9,391
    2011	8,201	271	8,472	8,266	740	9,006
    2012	7,310	292	7,602	7,121	938	8,059
    2013	6,196	314	6,510	6,898	955	7,853
    2014				5,881	971	6,852
    Thereafter	41,653	21,561	63,214	37,558	21,670	59,228
    Total	79,058	22,827	101,885	74,400	25,989	100,389

    The above table outlines nominal minimum obligations for future years, and mainly includes commitments within StatoilHydro'sStatoil's natural gas operations in addition to various other transport and similar commitments. StatoilHydroStatoil has entered into pipeline transportation for most of its prospective gas sales contracts. These agreements ensure the right to transport the production of gas through the pipelines, while also imposing an obligation to pay for booked capacity.

    StatoilHydroStatoil has contractual commitments to the US-based energy company Dominion for terminal capacity at the Cove Point liquefied natural gas terminal in the USA. As ofAt year end 2009 the commitment will includeincludes an annual capacity of approximately 10.1 bcm for a 20 year period.remaining period of 19 years. Such commitments have been included in full in the table above, but have been made in part on behalf of and for the account and risk of the SDFI. StatoilHydro'sStatoil's and the SDFI's respective future shares of the Cove Point terminal capacity and related commitments are subjectdepend on actual usage of the terminal. Statoil will cover substantially all the cost of unused capacity, if any, while the cost of used capacity will be split in proportion to future consideration,the produced natural gas volumes of Statoil and the outcome may consequently impact the extent of the future net terminal capacity and related net commitments assumed by StatoilHydro.

    In 2008 Sonatrach and StatoilHydro signed an agreement under the terms of which Sonatrach will receive access to an annual of 2 bcm of StatoilHydro's regasification capacity at the Cove Point terminal for 15 years from the beginning of 2009. This arrangement which reduces StatoilHydro's net exposure at the Cove Point terminal has however not been substracted from the above table.SDFI, respectively.

    The Mongstad refinery has entered into a long-term take-or-pay contract related to purchase of heat from the Troll licence partners. The contract term expires in 2040, and future expected minimum annual obligations under this contract represents the most significant part of Refinery related commitments included in the table above.

    StatoilHydroStatoil has entered into a number of general or field specific long-term frame agreements mainly related to crude oil loading and transport capacity availability. The main contracts run up until the end of the respective field lives. Such contracts have not been included in the above table of contractual commitments unless they entail specific minimum payment obligations.

    Guarantees
    Statoil Detaljhandel has issued guarantees amounting to a total of SEK 1.0 billion (NOK 0.9 billion), the main part of which relates to financial guarantee commitments on behalf of retailers. The liability recognized at fair value under IAS 39 related to these guarantee commitments is immaterial at year end.

    StatoilHydro has guaranteed certain recoverable reserves of crude oil in the Veslefrikk field on the NCS as part of an asset exchange with Petro Canada in 1996. Under the guarantee, StatoilHydroStatoil is obligated to deliver indemnity reserves to Petro Canada in the event that recoverable reserves prove lower than a specified volume. At year end 2008 the value of the remaining volume covered by the guarantee has been estimated to a total of NOK 2.1 billion at current market prices.1.7 billion. A provision of NOK 0.80.3 billion has been recognised at year end 20082009 related to this guarantee.

    Statoil has guaranteed for 50%, corresponding to its ownership percentage, of the contractual commitments entered into by Scira Offshore Energy Ltd. (Scira) in connection with the development of the Sheringham Shoal Offshore Wind Farm in the UK. Scira is included in the group financial statements using the equity method. At year end 2009 the maximum exposure under Statoil's guarantee has been estimated to NOK 3.0 billion. The carrying amount of the guarantee is immaterial.

    Under the Norwegian public limited companies act section 14-11, StatoilHydroStatoil and Norsk Hydro are jointly and severally liable for certain guarantee commitments entered into by Norsk Hydro prior to the merger between Statoil and Hydro Petroleum in 2007. The total amount StatoilHydroStatoil is jointly liable for is approximately NOK 6.63.8 billion with terms extending until 2050. As of the current date, the probability that these guarantee commitments will impact StatoilHydroStatoil is deemed to be remote. No liability has been recognised in the accountsfinancial statements at year end 2008.2009.
    
    Insurance
    The group has taken out insurance to cover certain potential liabilities arising from its operations world wide. This coversincludes liabilities for claims arising from pollution damage. Most of the group's production installations are covered through Statoil Forsikring a.s, which reinsures parts of the risk in the international insurance market. As all significant activities of Statoil Forsikring a.s. relatesrelate to insurance for entities and operations consolidated in the group accounts,financial statements, IFRS 4 has not been applied to such activities in the group financial statements.
    
    Statoil Forsikring a.s is member of two mutual insurance companies, Oil Insurance Ltd and sEnergy Insurance Ltd. sEnergy ceased operations on 15 May 2006 and the company is in the wind-up phase. Membership in 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 companies have joint and several liability for any losses that arise within the insurance pool.

    Other commitments and contingencies
    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 2008, StatoilHydro2009, Statoil was committed to participate in 2216 wells in Norway and 5337 wells outside Norway, with an average ownership interest of approximately 46%40%. StatoilHydro'sStatoil's share of estimated expenditures to drill these wells amounts to approximately NOK 129 billion. Additional wells that StatoilHydroStatoil may become committed to participate in depending on future discoveries in certain licenses are not included in these numbers.

    StatoilHydroStatoil ASA issued a declaration to the Norwegian Ministry of Petroleum and Energy (MPE) in 1999 in connection with a dispute between four Åsgard partners and StatoilHydroStatoil related to the construction of new facilities for the Åsgard development at the Kårstø Terminal. The declaration confirmed that the MPE will receive similar treatment as the four Åsgard partners with respect to the disputed issues. On the basis of the declaration, the MPE alleged the right to compensation and initiated legal proceedings against Statoil on 29 April 2008 issuedin a writ involving a multi-component compensation claim, theclaim. The aggregate principal exposure of which for StatoilHydro approximatesthe claim is estimated to be between NOK 4 and 7 billion after tax. In NovemberFollowing a verdict in Stavanger district court on 15 January 2010, Statoil and the MPE on 5 March 2010 reached an amicable settlement of the case in which both parties waived their rights to appeal the court verdict. Under the settlement Statoil agreed to pay the MPE a cash compensatio n of NOK 500 million after tax, and NOK 375 million in pre-tax interest, corresponding to NOK 270 million after tax.

    During the fourth quarter of 2008 ExxonMobil, the final Åsgard partner at the time of the original dispute, has issued a similar writ with a compensation claim approximating an estimated exposure of up to NOK 1 billion after tax. StatoilHydro rejects both claims.

    The price reviewsdispute with ExxonMobil was settled in October 2009. The impact of two long-term natural gas contracts previously in arbitration have been settled during 2008 without any significant effectthis settlement on the income statement.Consolidated financial statements was not material.

    StatoilHydro ASA has offered early retirement packages to employees above the age of 58 years (contingent upon certain conditions). The offer is divided into two phases; employees working onshore (first phase) and employees working offshore and on onshore plants and terminals (second phase). A settlement concerning restructuring cost charges related to the first phase has been reached between StatoilHydro and the partners on the Norwegian continental shelf, see further in note 5 Segments. Contingent receivables related to the second phase remain unrecorded.

    StatoilHydroStatoil was informed on 26 September 2007 of possible consultancy agreements and transactions associated with Hydro's petroleum activities in Libya, which were transferred to StatoilHydroStatoil as of 1 October 2007 as part of the merger with Hydro Petroleum, and which could be in conflict with applicable Norwegian and US anti-corruption legislation. Following a preliminary assessment by StatoilHydro,Statoil, an external review of the relevant aspects was initiated. The external US and Norwegian legal counsels that have conducted the review delivered their report to StatoilHydroStatoil ASA's CEO on 6 October 2008. The report has also been delivered to the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim), the US Department of Justice, the US Securities and Exchange Commission and Libyan authorities. The report does not draw any legal conclusions. In accordance with the mandate for the review, the report entails the facts relevant to applicable Norwegian and US anti-corruptionant i-corruption legislation to which StatoilHydroStatoil ASA may be subject as a result of the merger. Økokrim informed on 15 May 2009 that there will be no investigation related to the international activities of former Hydro Oil & Energy. Neither US authorities nor Libyan authorities have as of today initiated any steps in relation to the matters described in the investigation reports.

    During the normal course of its business StatoilHydroStatoil is involved in legal proceedings, and several other unresolved claims are currently outstanding. The ultimate liability or asset respectively, in respect of such litigation and claims cannot be determined at this time. StatoilHydroStatoil has provided in its accountsfinancial statements for probable liabilities related to litigation and claims based on the Company'sgroup's best judgement. StatoilHydroStatoil does not expect that the financial position, results of operations or cash flows will be materially affected by the resolution of these legal proceedings.
    
    

     Top 

    8.1.278.1.29 Related parties

    Transactions with the Norwegian State
    The Norwegian State is the majority shareholder of StatoilHydroStatoil and also holds major investments in other entities.Norwegian companies. This ownership structure means that StatoilHydroStatoil participates in transactions with many parties that are under a common ownership structure and therefore meet the definition of a related party. All transactions are considered to be on a normal arms-lengtharm's length basis.

    The ownership interests of the Norwegian State in StatoilHydroStatoil are heldadministrated by the Norwegian Ministry of Petroleum and Energy (MPE). The following transactions with SDFI volumes were made between StatoilHydroStatoil and MPE for the years presented:

    Total purchases of oil and natural gas liquid from the Norwegian State amounted to NOK 74,338 million (204 million barrels oil equivalents), NOK 112,682 million (223 million barrels oil equivalents), and NOK 98,498 million (237 million barrels oil equivalents) in 2009, 2008 and NOK 104,628 (254 million barrels oil equivalents) in 2008, 2007, and 2006, respectively. Purchases of natural gas from the Norwegian State (excluding purchases from licenses) amounted to NOK 265 million, NOK 375 million and NOK 287 million in 2009, 2008 and NOK 293 million in 2008, 2007, and 2006, respectively. The significant amounts included in the line item Payables to associated companies and other related parties in note 25 Trade and other payables, see note 23 Related parties, are amounts payable to the Norwegian State for these purchases.

    The State's natural gas production, which StatoilHydroStatoil is selling, in its own name, but for the Norwegian State's account and risk as well as related expenditures refunded by the State, are presented at net value in StatoilHydro'sStatoil's financial statements.

    Other transactions
    In relation to its ordinary business operations such as pipeline transport, gas storage and processing of petroleum products, StatoilHydroStatoil also has regular transactions with certain unconsolidated affiliated entities. Such transactions are carried out on an arm's length basis, and are included within the applicable captions in the Statements of income.

    Compensation of key management personnel
    The remuneration to key management personnel (members of Boardboard of Directorsdirectors and Executive Committee)the corporate executive committee) during the year was as follows:

    (in NOK thousand)	2008	2007	2006
    Current benefits	50,949	44,463	41,602
    Post-employment benefits	12,534	12,764	13,938
    Other non-current benefits	129	111	135
    Share based payment benefits	278	94	40
    Total	63,890	57,432	55,715

    (in NOK thousand)	2009	2008	2007
    Current benefits	50,573	50,949	44,463
    Post-employment benefits	11,391	12,534	12,764
    Other non-current benefits	137	129	111
    Share based compensation benefits	444	278	94
    Total	62,545	63,890	57,432

    Loans to key management total less than NOK 0.30.2 million.

     Top 

    8.1.28 Financial risk management

    General information relevant to risks
    StatoilHydro's business activities naturally expose the group to risk. The group's approach to risk management includes identifying, evaluating, and managing risk in all activities using a top-down approach with the purpose of avoiding sub-optimisation and utilising correlations observed from a group perspective. Only summing up the different market risks without including the correlations will overestimate our total market risk. Due to this the group utilises correlations between all the most important market risks, such as oil and natural gas prices, product prices, currencies, and interest rates, to calculate the overall market risk (i.e. utilize the natural hedges embedded in our portfolio). This approach also reduces the number of unnecessary transactions (i.e. reducing transaction costs and avoiding sub-optimisation).

    In order to achieve the above effects, the group has centralized trading mandates such that all major/strategic transactions are co-ordinated through our Corporate Risk Committee. This implies that local trading mandates are relatively small.

    The group's Corporate Risk Committee which is headed by the Chief Financial Officer and which includes, among others, representatives from the principal business segments is responsible for defining, developing, and reviewing the group's risk policies. The Chief Financial Officer in co-operation with the Corporate Risk Committee is also responsible for overseeing and developing StatoilHydro's Enterprise-Wide Risk Management and proposing appropriate risk adjusting measures at the corporate level. To help facilitate its role, the Committee meets at least six times per annum and regularly receives risk information relevant for the group from our Corporate Risk Department.

    Financial risks
    StatoilHydro's activities expose the group to financial risks as defined by IFRS 7:

    • Market risk (including commodity price risk, interest rate risk, currency risk, and equity price risk)
    • Liquidity risk
    • Credit risk

    Market risk
    StatoilHydro operates in the worldwide crude oil, refined products, natural gas, and electricity markets and are exposed to such market risks as fluctuations in hydrocarbon prices, foreign currency rates, interest rates, and electricity prices that can affect the revenues and costs of operating, investing and financing. These risks are managed primarily on a short-term basis with focus on achieving the highest risk adjusted returns for the group within the given mandate. Long-term is generally viewed as risks managed at the corporate level and (or) normally having a six months or longer time horizon for significant volumes while short term is generally viewed as risks managed at segment and lower levels according to trading strategies and pre-defined mandates.

    The group has established guidelines for entering into contractual arrangements (derivatives) in order to manage our commodity price, foreign currency rate, and interest rate risk. The group uses both financial and commodity-based derivatives to manage the risks in overall earnings and the future value of cash flows.

    Commodity price risk
    Commodity price risk represents the group's most important short-term market risk and is monitored everyday against established mandates as defined by the group's governing policies. To manage short-term commodity risk, the group enters 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 InterContinental Exchange (ICE) in London, the New York Mercantile Exchange (NYMEX), 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 ICE.

    The term of oil and refined oil products derivatives is usually less than one year and the term for natural gas and electricity derivatives is usually three years or less.

    Currency risk
    Fluctuations in exchange rates can have significant effects on the group's results. Foreign exchange risk is assessed on a portfolio basis in accordance with approved strategies and mandates and the group uses only well-understood, conventional derivative instruments which include futures and options traded on regulated exchanges, OTC-swaps, -options and forward contracts.

    The group's cash inflows are largely influenced by USD while the group's cash outflows are to a large extent, tax and dividend payments in NOK, as well as certain investments, payment of salaries and various other costs payable in NOK. Accordingly, a significant portion of our exposure to foreign currency rates exists with USD versus NOK. StatoilHydro seeks to manage this currency mismatch by issuing or swapping non-current financial debt into USD.

    The group further seeks to manage short-term currency mismatches by using derivative instruments both for currency and liquidity management purposes. Typically, the group purchases NOK during the course of a calendar year in order to cover projected NOK payments of Norwegian income taxes and dividends in the first half of a subsequent year. This means, from time to time, the group purchases substantial NOK amounts on a forward basis using derivative instruments.

    Interest rate risk
    The existence of assets earning and liabilities owing variable rates of interest expose the group to cash flow risk caused by market interest rate fluctuations. The group enters into various types of interest rate contracts in managing interest rate risk. The group enters into interest rate derivatives, particularly interest rate swaps, to alter interest rate exposures, to lower expected funding costs over time and to diversify sources of funding. Under interest rate swaps, the group agrees 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.

    StatoilHydro principally manages the group's interest rates on the basis that the non-current debt portfolio has floating rate interest payments. The modified duration (the percentage change in value for one percentage point change in yield) expresses the way the group monitors the interest rate risk. Generally, the group's modified duration is to be between 0 and 1.0%. Other strategies can be approved from time to time if justified by factors such as corporate risk considerations, tax considerations, large non-recurring transactions, credit rating concerns, etc.

    Liquidity risk
    Liquidity risk is the risk that StatoilHydro will not be able to meet obligations when due. The purpose of liquidity and short term liability management is to make certain that the group at all times has sufficient funds available to cover financial obligations.

    StatoilHydro's operating cashflows are negatively impacted by declines in oil and gas prices, however, during 2008 the group's overall liquidity position remained strong and the policies for managing liquidity remained unchanged.

    StatoilHydro's business activities normally generate, on a monthly basis, a positive cashflow from operations. However, in months when taxes are paid (February, April, June, August, October and December) or annual dividend is paid (typically in May/June) cashflows are typically limited. In the period following tax and dividend payments the amount of liquid assets will often be significantly reduced. A need for short-term funding will then be triggered for a period until the debt is repaid and subsequently followed by a new accumulation of liquid assets.

    Short-term financing can be carried out bilaterally through direct borrowing from banks, insurance companies, etc. An alternative is to issue short term debt securities under one of the existing financing programmes or under documentation established ad hoc. These financing programmes are as follows:

    • A USD 4 billion US commercial paper programme. This is the most flexible programme used for working capital, including timing issues on corporate tax and dividend payments, as well as for periodic acquisition financing.
    • A USD 2 billion committed multi-currency revolving credit facility from international banks, including a USD 500 million swing-line facility. The facility was entered into in 2004, and is available for draw-downs until December 2011. This facility is primarily intended as a "back-up" facility for the US commercial paper programme, and should be regarded as support for the credit rating of this programme.
    • Uncommitted credit lines. Short-term financing source occasionally required beyond the other short-term programmes and accumulated cash.

    In order to have access to sufficient liquidity at all times, StatoilHydro defines and continuously maintains a minimum liquidity reserve which comprises unused committed external credit facilities, cash and cash equivalents, and current financial investments excluding the current portion of the investment portfolio held by the group's captive insurance subsidiary.

    Capital and liability management
    As a basic principle, StatoilHydro separates investment decisions from financing decisions. Financing needs arise as a result of the group's general business activity. The main rule is to establish financing at corporate level. Project financing may be applied in cases involving joint ventures with other companies.

    The group aims at all times to maintain access to a variety of financing sources, both in respect of instruments and geography, and maintain relationships with a core group of international banks that provide various kinds of banking and financing services.

    The group has credit ratings from Moody's and Standard & Poor's and the stated objective is to have a rating at least within the single A category. This rating ensures necessary predictability when it comes to funding access at favourable terms and conditions. The group's current long-term ratings are Aa2 and AA- from Moody's and Standard & Poor's respectively. The short-term rating from Moody's is P-1 and A-1+ from Standard & Poor's. The group intends to keep financial ratios relating to debt at levels consistent with objectives for maintaining the group's long-term credit rating at least within the single A category. In managing the group's capital structure and thus seeking to maintain a credit rating of at least single A, the group partly relies on the use of Standard & Poor's guidelines to test, among others, the key ratios free funds from operations over net debt and the debt ratio.

    In order to control the group's refinancing risk, the maturity and redemption profile of non-current debt issued is managed within certain limitations. The limits are expressed as maximum annual mandatory redemptions as a share of StatoilHydro's capital employed.

    Liquidity forecasts serve as tools for financial planning. In order to maintain necessary financial flexibility, StatoilHydro has requirements for maximum (forecasted) current debt and minimum (forecasted) liquidity reserve. Issuance of long-term debt is used as a tool for reducing current debt and/or increasing the liquidity reserve. New non-current funding will be initiated if liquidity forecasts reveal non-compliance with given limits, unless further detailed considerations indicate that the non-compliance is likely to be very temporary. In this case, the situation will be further monitored before additional non-current debt is drawn.

    For further information on the group's debenture bonds, bank loans, and other debt portfolio profile, see note 20 Non-current financial liabilities.

    StatoilHydro's dividend policy includes providing a return to the group's shareholders through cash dividends and share repurchases. The level of cash dividends and share repurchases in any one year can fluctuate depending on the group's assessment of future cashflows, capital expenditure plans, financing requirements, and appropriate financial flexibility. See note 19 Shareholders equity for additional information on the group's dividend policy.

    Credit risk
    Credit risk is the risk that the group's customers or counterparties to financial instruments will cause the group financial loss by failing to honour their obligation. Credit risk arises from credit exposures with customer accounts receivables as well as from derivative financial instruments and deposits with financial institutions. Theoretically, the group's maximum credit exposure for financial assets is the aggregated balance sheet carrying amounts of financial investments (excluding equity investments of NOK 6.5 billion in 2008 and NOK 7.5 billion in 2007), derivative financial instruments, financial receivables, trade and other receivables, and cash and cash equivalents. The group manages this exposure through its credit risk management policies and procedures.

    The current financial crisis has brought into focus the need for all entities to have robust credit policies with close monitoring of associated risks. Over the years, we have established a clear credit policy which has proven especially valuable during this period of widespread financial pressure. The tools StatoilHydro uses to manage and monitor credit risk have been tested by the continuing crisis and no significant credit losses have materialised for the group during 2008.

    Key elements of our credit risk management approach include

    • A global credit risk policy
    • Credit mandates
    • Internal credit rating process
    • Credit risk mitigation tools
    • Continuously monitoring and managing credit exposures

    Prior to entering into transactions with new counterparties, the group's credit policy requires all counterparties to be formally identified, approved, and assigned internal credit ratings as well as exposure limits. Once established, all counterparties are re-assessed minimum annually with high risk counterparties reviewed more frequently. The internal credit ratings reflect our assessment of the counterparties' credit risk and are similar to rating categories used by well known credit rating agencies, Standard & Poor's and Moody's. Exposure limits are determined based on assigned internal credit ratings combined with other factors, such as expected transaction and industry characteristics, as outlined in our credit policy. The mandate for setting credit limits is regularly reviewed with regard to changes in market conditions.

    There are several instruments available to the group to reduce or control credit risk both on an individual counterparty and portfolio level. The main tools used by StatoilHydro are variations of bank and parental guarantees, prepayments and cash collateral. For bank guarantees only investment grade international banks are accepted.

    StatoilHydro manages credit risk both on a portfolio and counterparty level. The group has pre-defined limits regarding the minimum average credit rating allowed at any given time on the group portfolio level as well as maximum credit exposures for individual counterparties. The group monitors the portfolio on a regular basis and individual exposures versus limits on a daily basis. The total credit exposure portfolio of StatoilHydro is well diversified with respect to number and quality of counterparties, industries and geographically. The majority of the group's credit exposure is typically with investment grade counterparties.

    The following table contains the fair market value of open non-exchange traded derivative assets split by the group's assessment of the counter-party's credit risk.
    

    (in NOK million)	At 31 December
    	2008	2007
    Counter-party rated:
    Investment grade, rated A or above	21,727	19,647
    Other investment grade	7,094	928
    Non-investment grade or not rated	761	689

    As of 31 December 2008, NOK 10.1 billion is received in cash as collateral to offset a portion of this group credit exposure. See note 24 Current financial liabilities for more information on collateral held.

    Consistent with our policies, commodity derivative counter-parties have been assigned credit ratings corresponding to those of their respective parent companies. If the parent company is highly rated, it may not be necessary to obtain a parent company guarantee from such a counter-party.

     Top 

    8.1.298.1.30 Financial instruments by category

    Reclassification of derivative financial instruments
    Statoil has, as further described in the Significant changes in accounting policies section of note 2 Significant accounting policies, in 2009 reclassified from current assets and liabilities to non-current assets and liabilities certain derivative financial instruments (mainly earn-out agreements, certain embedded derivative contracts and interest rate swap agreements) classified as held for trading in accordance with IAS 39 Financial instruments: Recognition and Measurement, as provided for in the amended version of IAS 1 Presentation of Financial Statements, which became effective 1 January 2009. This affects the classification between current and non-current assets and liabilities of the line items, "Derivative financial instruments". The following table sets forth the restatement of derivative financial instruments between current assets and liabilities and non-current assets and liabilities in the 31 December and 1 January 2008 balance sheets.

    (in NOK million)	As earlier reported	Reclassification	As reclassified
    31 December 2008
    Non-current assets
    Derivative financial instruments	2,383	18,899	21,282
    Total non-current assets	433,611	18,899	452,510
    Current assets
    Derivative financial instruments	27,505	(18,139)	9,366
    Total current assets	144,812	(18,139)	126,673
    TOTAL ASSETS	578,423	760	579,183
    Non-current liabilities
    Derivative financial instruments	0	1,617	1,617
    Total non-current liabilities	202,647	1,617	204,264
    Current liabilities
    Derivative financial instruments	20,752	(857)	19,895
    Total current liabilities	159,721	(857)	158,864
    TOTAL EQUITY AND LIABILITIES	578,423	760	579,183

    (in NOK million)	As earlier reported	Reclassified	As restated
    1 January 2008
    Non-current assets
    Derivative financial instruments	609	12,159	12,768
    Total non-current assets	353,428	12,159	365,587
    Current assets
    Derivative financial instruments	21,093	(12,291)	8,802
    Total current assets	129,790	(12,291)	117,499
    TOTAL ASSETS	483,218	(132)	483,086
    Non-current liabilities
    Derivative financial instruments	0	27	27
    Total non-current liabilities	174,788	27	174,815
    Current liabilities
    Derivative financial instruments	7,632	(159)	7,473
    Total current liabilities	129,363	(159)	129,204
    TOTAL EQUITY AND LIABILITIES	483,218	(132)	483,086

    Financial instruments by IAS 39 category
    The following tables provide a view of financial instruments and their carrying amounts as defined by IAS 39 categories. All financial instruments' carrying amounts are measured at fair value or their carrying amounts reasonably approximate fair value except non-current financial liabilities. See note 2022 Non-current financial liabilities for fair value information of non-current financial liabilities.

    See also note 2 Significant accounting policies for further information regarding measurement of fair values.

    						Fair value through profit or loss										Fair value through profit or loss
    												Total										Total
    		Loans and		Available-		Held for		Hedge		Fair value		carrying		Loans and	Available-	Held for		Hedge		Fair value	Non-financial	carrying
    (in NOK million)	Note	receivables		for-sale		trading		accounting		option		amount	Note	receivables	for-sale	trading		accounting		option	assets	amount
    31 December 2008
    31 December 2009
    Assets
    Non-current financial investments	14	-		4,164		-		-		12,301		16,465	16	-	2,223	-		-		11,044	-	13,267
    Non-current derivative financial instruments	30	-		-		-		2,383		-		2,383	31	-		17,644		-		-		17,644
    Non-current financial receivables	14	4,914		-		-		-		-		4,914	16	3,164	-			-		-	2,583	5,747
    Current trade and other receivables	16	69,931		-		-		-		-		69,931	18	53,007	-			-		-	5,888	58,895
    Current derivative financial instruments	30	-		-		27,436		69		-		27,505	31	-		5,369		-		-		5,369
    Current financial investments	17	15		-		7,874		-		1,858		9,747	19	55	-	1,962		-		5,005	-	7,022
    Cash and cash equivalents	18	18,638		-		-		-		-		18,638	20	24,723	-	-		-		-		24,723
    Total		93,498		4,164		35,310		2,452		14,159		149,583		80,949	2,223	24,975		-		16,049	8,471	132,667

     

    						Fair value through profit or loss										Fair value through profit or loss
    												Total										Total
    		Loans and		Available-		Held for		Hedge		Fair value		carrying		Loans and	Available-	Held for		Hedge		Fair value	Non-financial	carrying
    (in NOK million)	Note	receivables		for-sale		trading		accounting		option		amount	Note	receivables	for-sale	trading		accounting		option	assets	amount
    31 December 2007
    31 December 2008
    Assets
    Non-current financial investments	14	-		3,291		-		-		11,975		15,266	16	-	4,164	-		-		12,301	-	16,465
    Non-current derivative financial instruments	30	-		-		-		609		-		609	31	-		18,899		2,383		-	-	21,282
    Non-current financial receivables	14	3,515		-		-		-		-		3,515	16	2,771	-			-		-	2,143	4,914
    Current trade and other receivables	16	69,378		-		-		-		-		69,378	18	66,644	-			-		-	3,287	69,931
    Current derivative financial instruments	30	-		-		21,051		42		-		21,093	31	-		9,297		69		-		9,366
    Current financial investments	17	-		-		3,359		-		-		3,359	19	15	-	7,874		-		1,858	-	9,747
    Cash and cash equivalents	18	18,264		-		-		-		-		18,264	20	18,638	-			-		-		18,638
    Total		91,157		3,291		24,410		651		11,975		131,484		88,068	4,164	36,070		2,452		14,160	5,430	150,343
    										Fair value		Total
    						Amortised		Hedge		through		carrying
    (in NOK million)	Note					cost		accounting		profit or loss		amount
    31 December 2008
    Liabilities
    Non-current financial liabilities	20					52,065		2,541		-		54,606
    Current trade and other payables	23					61,200		-		-		61,200
    Current financial liabilities	24					20,695		-		-		20,695
    Current derivative financial instruments	30					-		-		20,752		20,752
    Total						133,960		2,541		20,752		157,253
    										Fair value		Total
    						Amortised		Hedge		through		carrying
    (in NOK million)	Note					cost		accounting		profit or loss		amount
    31 December 2007
    Liabilities
    Non-current financial liabilities	20					43,649		724		1		44,374
    Current trade and other payables	23					64,624		-		-		64,624
    Current financial liabilities	24					6,166		-		-		6,166
    Current derivative financial instruments	30					-		-		7,632		7,632
    Total						114,439		724		7,633		122,796

    Included in Current trade and other payables are provisions for certain claims and litigations in accordance with IAS 37 which are further described in note 26 Other commitments and contingencies.

    				Fair value through profit or loss
    										Total
    		Loans and	Available-	Held for		Hedge		Fair value	Non-financial	carrying
    (in NOK million)	Note	receivables	for-sale	trading		accounting		option	assets	amount
    1 January 2008
    Assets
    Non-current financial investments	16	-	3,291	-		-		11,975	-	15,266
    Non-current derivative financial instruments	31	-	-	12,159		609		-	-	12,768
    Non-current financial receivables	16	3,515	-	-		-		-	-	3,515
    Current trade and other receivables	18	69,378	-	-		-		-	-	69,378
    Current derivative financial instruments	31	-	-	8,760		42		-	-	8,802
    Current financial investments	19	-	-	3,359		-		-	-	3,359
    Cash and cash equivalents	20	18,264	-	-		-		-	-	18,264
    Total		91,157	3,291	24,278		651		11,975	-	131,352

    (in NOK million)	Note	Amortised cost	Hedge accounting	Fair value through profit or loss	Non-financial liabilities	Total carrying amount
    31 December 2009
    Liabilities
    Non-current financial liabilities	22	95,962	-	-	-	95,962
    Non-current derivative financial instruments	31	-	-	1,657	-	1,657
    Current trade and other payables	25	58,048	-	-	1,753	59,801
    Current financial liabilities	26	8,150	-	-	-	8,150
    Current derivative financial instruments	31	-	-	2,860	-	2,860
    Total		162,160	-	4,517	1,753	168,430

    (in NOK million)	Note	Amortised cost	Hedge accounting	Fair value through profit or loss	Non-financial liabilities	Total carrying amount
    31 December 2008
    Liabilities
    Non-current financial liabilities	22	52,065	2,541	-	-	54,606
    Non-current derivative financial instruments	31	-	-	1,617	-	1,617
    Current trade and other payables	25	58,990	-	-	2,210	61,200
    Current financial liabilities	26	20,695	-	-	-	20,695
    Current derivative financial instruments	31	-	-	19,895	-	19,895
    Total		131,750	2,541	21,512	2,210	158,013

    (in NOK million)	Note	Amortised cost	Hedge accounting	Fair value through profit or loss	Non-financial liabilities	Total carrying amount
    1 January 2008
    Liabilities
    Non-current financial liabilities	22	43,649	724	-	-	44,373
    Non-current derivative financial instruments	31	-		27	-	27
    Current trade and other payables	25	64,624	-	-	-	64,624
    Current financial liabilities	26	6,166	-	-	-	6,166
    Current derivative financial instruments	31	-	-	7,473	-	7,473
    Total		114,439	724	7,500	-	122,663

    heThe following tables include amounts from the Consolidated statements of income related to financial instruments. Excluded from Net financial items is accretion expense on our asset retirement obligations of NOK 2,107, NOK 2,099 and NOK 1,304 million for the years ended 2008, 2007 and 2006, respectively. See note 8, Financial items, for additional information on the Net financial items.

    	Fair value through profit or loss
    						Available-
    	Held for	Hedge	Fair value	Loans &	Financial liabilities	for-sale
    (in NOK million)	trading	accounting	option	receivables	at amortised cost	assets	Total
    For the year ended 31 December 2008
    Operating income	19,917	-	-	-	-	-	19,917
    Net financial items
    Net foreign exchange gains (losses)	(23,061)	-	(1,256)	3,900	(12,145)	-	(32,563)
    Interest income and other financial items	8,927	-	(213)	3,461	-	31	12,207
    Interest and other finance expenses	6,725	(27)	(1)	-	(2,599)	-	4,098
    Total	12,508	(27)	(1,470)	7,361	(14,744)	31	3,659
    	Fair value through profit or loss
    						Available-
    	Held for	Hedge	Fair value	Loans &	Financial liabilities	for-sale
    (in NOK million)	trading	accounting	option	receivables	at amortised cost	assets	Total
    For the year ended 31 December 2007
    Operating income	(2,043)	-	-	-	-	129	(1,914)
    Net financial items
    Net foreign exchange gains (losses)	8,610	-	596	(8,630)	9,467	-	10,043
    Interest income and other financial items	(82)	-	139	1,820	-	428	2,305
    Interest and other finance expenses	361	9	(40)	-	(972)	-	(642)
    Total	6,846	9	695	(6,810)	8,495	557	9,792
    	Fair value through profit or loss
    						Available-
    	Held for	Hedge	Fair value	Loans &	Financial liabilities	for-sale
    (in NOK million)	trading	accounting	option	receivables	at amortised cost	assets	Total
    For the year ended 31 December 2006
    Operating income	7,303	-	-	-	-	-	7,303
    Net financial items
    Net foreign exchange gains (losses)	3,947	-	112	(1,067)	1,465	-	4,457
    Interest income and other financial items	780	-	965	1,751	(79)	258	3,675
    Interest and other finance expenses	(1,352)	(7)	(27)	-	(349)	(21)	(1,756)
    Total	10,678	(7)	1,050	684	1,037	237	13,679

    	Fair value through profit or loss
    					Financial	Available-	Non-financial
    	Held for	Hedge	Fair value	Loans &	liabilities at	for-sale	assets  or
    (in NOK million)	trading	accounting	option	receivables	amortised cost	assets	liabilities	Total
    For the year ended 31 December 2009
    Net operating income	12,337	-	-	-	-	(159)	109,462	121,640
    Net financial items
    Net foreign exchange gains (losses)	16,661	-	-	(10,568)	(4,076)	-	(24)	1,993
    	-	-	-	-	-	-	-
    Interest income	1,290	-	326	1,088	-	-	-	2,704
    Other financial items	518	-	403	111	-	(28)	-	1,004
    Interest income and other financial items	1,808	-	729	1,199	-	(28)	-	3,708
    Interest  expenses	2,123	-	-	-	(3,748)	-	-	(1,625)
    Impairment loss recognised	-	-	-	-	-	(1,404)	-	(1,404)
    Other financial expenses	(6,807)	-	-	-	(183)	-	(2,432)	(9,422)
    Interest and other financial expenses	(4,684)	-	-	-	(3,931)	(1,404)	(2,432)	(12,451)
    Net financial items	13,785	-	729	(9,369)	(8,007)	(1,432)	(2,456)	(6,750)
    Total	26,122	-	729	(9,369)	(8,007)	(1,591)	107,006	114,890

    	Fair value through profit or loss
    					Financial	Available-	Non-financial
    	Held for	Hedge	Fair value	Loans &	liabilities at	for-sale	assets  or
    (in NOK million)	trading	accounting	option	receivables	amortised cost	assets	liabilities	Total
    For the year ended 31 December 2008
    Net operating income	19,917	-	-	-	-	(346)	179,261	198,832
    Net financial items
    Net foreign exchange gains (losses)	(24,266)	-	-	3,848	(12,145)	-	-	(32,563)
    Interest income	3,230	-	437	3,392	-	-	-	7,059
    Other financial items	6,006	-	(971)	52	-	61	-	5,148
    Interest income and other financial items	9,236	-	(534)	3,444	-	61	-	12,207
    Interest  expenses	959	-	-	-	(2,243)	-		(1,284)
    Other financial expenses	5,660	(27)	-	-	(251)	-	(2,107)	3,275
    Interest and other financial expenses	6,619	(27)	-	-	(2,494)	-	(2,107)	1,991
    Net financial items	(8,411)	(27)	(534)	7,292	(14,639)	61	(2,107)	(18,365)
    Total	11,506	(27)	(534)	7,292	(14,639)	(285)	177,154	180,467

    	Fair value through profit or loss
    					Financial	Available-	Non-financial
    	Held for	Hedge	Fair value	Loans &	liabilities at	for-sale	assets  or
    (in NOK million)	trading	accounting	option	receivables	amortised cost	assets	liabilities	Total
    For the year ended 31 December 2007
    Net operating income	(2,043)	-	-	-	-	129	139,118	137,204
    Net financial items
    Net foreign exchange gains (losses)	9,092	-	-	(8,516)	9,467	-	-	10,043
    Interest income	234	-	281	1,390	-	-	-	1,905
    Other financial items	(313)	-	(185)	541	-	357	-	400
    Interest income and other financial items	(79)	-	96	1,931	-	357	-	2,305
    Interest  expenses	(379)	-	-	-	(584)	-		(963)
    Other financial expenses	504	9	-	-	(192)	-	(2,099)	(1,778)
    Interest and other financial expenses	125	9	-	-	(776)	-	(2,099)	(2,741)
    Net financial items	9,138	9	96	(6,585)	8,691	357	(2,099)	9,607
    Total	7,095	9	96	(6,585)	8,691	486	137,019	146,811

     

     Top 

    8.1.308.1.31 Financial instrumentsinstruments: measurement and hedgingmarket risk sensitivities

    Fair value hedges
    Fair value hedges are hedges of StatoilHydro's exposure to changes in the fair value of a recognised asset and liability. StatoilHydro has designated certain interest rate swaps asThe fair value hedge torelationships for which Statoil in 2007 and 2008 applied hedge against changesaccounting have been discontinued since the group revoked the designation in the fair value, due to changes in the interest rates,first quarter of certain parts of the group's financial liabilities. The net loss recognised in earnings in Income before tax during the year for ineffectiveness of fair value hedges was insignificant.

    2009. The fair value adjustment total of NOK 2.5 billion recognised in the Consolidated balance sheet at 31 December 2008 is being amortised over the remaining duration, 14 to 19 years, of the loans that were originally identified as hedging instruments and the hedged item subject toobjects in these hedge accounting are presented below together with related annual gains and losses.relationships.

    (in NOK million)	Fair value	Gains /(losses)
    At 31 December 2008
    Hedging instruments	2,452	2,036
    Hedged item	(2,541)	(2,063)
    At 31 December 2007
    Hedging instruments	651	221
    Hedged item	(724)	(212)
    At 31 December 2006
    Hedging instruments	430	(459)
    Hedged item	(512)	452

    Fair value measurement of derivative financial instruments

    Derivative financial instruments
    The groupStatoil recognises all derivative financial instruments in the balance sheet at fair value. Changes in the fair value of these derivativesthe derivative financial instruments are includedrecognised in the Consolidated statementsStatement of income, within Revenues or within Net financial items, respectively, depending on their nature as commodity based derivative contracts or interest rate and foreign exchange rate derivative instruments.

    When calculating fair value of derivative financial instruments Statoil uses prices quoted in an active market for identical assets to the extent possible. When such prices are not available Statoil uses inputs that are observable either in revenuedirectly or inindirectly. The valuation techniques most frequently used by Statoil when valuing derivative financial items.instruments are mark to market calculation or a net present value calculation of expected future cash flows. For more information about the methodology and assumption used when calculating the fair value of ourStatoil's derivative financial instruments see note 2 Significant accounting policies.

    The following table contains the estimated fair values and net carrying amounts of Statoil's derivative financial instruments including certain derivative commodity contracts.instruments. Of the total ending balance at 31 December 20082009 NOK 9.713.0 billion relates to certain earn-out agreements and embedded derivatives recognised as derivative financial instruments in accordance with IAS 39. At the end of 20072008 the estimated fair value of these agreements werewas NOK 9.69.4 billion.

    (in NOK million)	Fair value of assets	Fair value of liabilities	Net carrying amount
    At 31 December 2009
    Debt-related instruments	6,405	(1,708)	4,697
    Non-debt-related instruments	347	(867)	(520)
    Crude oil and refined products	8,034	(842)	7,192
    Natural gas and electricity	8,227	(1,100)	7,127
    Total	23,013	(4,517)	18,496
    At 31 December 2008
    Debt-related instruments	13,083	(989)	12,094
    Non-debt-related instruments	403	(14,032)	(13,629)
    Crude oil and refined products	13,136	(2,491)	10,645
    Natural gas and electricity	4,026	(4,000)	26
    Total	30,648	(21,512)	9,136

    Financial investments
    Statoil recognises all financial investments in the balance sheet at fair value. Statoil's financial investments consist of the portfolios held by the group's captive insurance company (mainly bonds, listed equity securities and commercial papers) and investments in money market funds held for liquidity management purposes. The group also holds some other non-listed equity securities for long term strategic purposes. These are classified as available-for-sale assets (AFS). Changes in fair value of the financial investments are recognised in the Statement of income within Net financial items, with the exception of the investments that are classified as AFS assets. Changes in fair value of these investments are recognised in the Statement of comprehensive income, while any impairment losses are recognised in the Statement of income within Net financial items.

    (in NOK million)	Fair value of assets	Fair value of liabilities	Net carrying amount
    At 31 December 2008
    Debt-related instruments	13,083	(989)	12,094
    Non-debt-related instruments	403	(14,032)	(13,629)
    Crude Oil and Refined products	13,136	(2,491)	10,645
    Gas and Electricity	3,267	(3,239)	28
    At 31 December 2007
    Debt-related instruments	4,676	(125)	4,551
    Non-debt-related instruments	1,802	(163)	1,639
    Crude Oil and Refined products	11,115	(2,533)	8,582
    Gas and Electricity	4,219	(4,921)	(702)

    WhereWhen calculating fair value of financial investments, the group uses prices quoted in an active market exists, derivativefor identical assets to the extent possible. This will typically be for listed equity securities and government bonds. Where there is no active market, fair value is determined using valuation techniques such as net present value calculations of expected future cash flows. For more information about methodology and assumptions used when calculating fair value of the group's financial instruments are valued oninvestments see note 2 Significant accounting policies. For information about fair values of the group's financial investments recognised in the basis of quoted information from the active market. balance sheet see note 16 Non-current financial assets and note 19 Current financial investments.

    Fair value hierarchy
    The following table summarises each class of financial instruments which are recognised in the balance sheet at fair value, split by the group's basis for the group's fair value estimation and the maturity of our derivative financial instruments.measurement.

    (in NOK million)	Maturity less than 1 year	Maturity 1-3 years	Maturity 4-5 years		Maturity in excess of 5 years	Total fair value
    At 31 December 2008
    Fair value based on prices quoted in an active market	55	(180)	(20)		0	(145)
    Fair value based on price inputs from observable market transactions	(11,330)	4,287	2,229		8,297	3,483
    Fair value based on inputs from other sources	348	485	729		4,236	5,798
    At 31 December 2007
    Fair value based on prices quoted in an active market	175	1,731	178		2,108	4,192
    Fair value based on price inputs from observable market transactions	5	7	0		0	12
    Fair value based on inputs from other sources	13	(1)	(1)		9,854	9,865

    (in NOK million)	Non-current financial investment	Non-current derivative financial instruments-assets	Current financial investments	Current derivative  financial instruments-assets	Non-current derivative financial instruments-liabilities	Current derivative  financial instruments-liabilities	Net fair value
    At 31 December 2009
    Fair value based on prices quoted in an active market for identical assets or liabilities (Level 1)	6,663	0	4,339	42	0	(18)	11,026
    Fair value based on price inputs other than quoted prices but are from observable market transactions (Level 2)	4,683	6,191	2,683	3,827	(1,657)	(2,756)	12,971
    Fair value based on unobservable inputs (Level 3)	1,921	11,453	0	1,500	0	(86)	14,788
    Total fair value	13,267	17,644	7,022	5,369	(1,657)	(2,860)	38,785
    At 31 December 2008
    Fair value based on prices quoted in an active market for identical assets or liabilities (Level 1)	6,402	0	1,744	399		(544)	8,001
    Fair value based on price inputs other than quoted prices but are from observable market transactions (Level 2)	6,575	12,430	8,003	7,648	(857)	(19,260)	14,539
    Fair value based on unobservable inputs (Level 3)	3,488	8,852	0	1,319	(760)	(91)	12,808
    Total fair value	16,465	21,282	9,747	9,366	(1,617)	(19,895)	35,348

    The first level in the above table, Fair value based on prices quoted in an active market refers to values generated for standardised productsidentical assets or liabilities, includes financial instruments actively traded where ourand for which the values isrecognised in Statoil's balance sheet are calculated based on observable prices on equal product.identical instruments. This category will, in most cases, only be relevant for exchange traded contracts.financial instruments.

    The second level in the above table, Fair value based on price inputs, other than quoted prices, which are derived from observable market transactions, is usedincludes Statoil's non-standardised contracts for which fair values that are calculated for our non-standardised contracts based on the basis of price inputs that are from observable market transaction.transactions. This will typically be when we usethe group uses forward prices on crude oil, natural gas, interest rates, and foreign exchange rates as inputs into ourto the valuation models.

    The third level in the above table, Fair value based on input from other sources refers tounobservable inputs, includes financial instruments for which fair values are calculated based on the basis of input and assumptions that are not from observable market transactions. The fair values presented in this category willare mainly be based on internal assumptions. The internal assumptions are only used due toin the absence of quoted priceprices from an active market or other observable price inputs for the financial instruments subject to the valuation.

    Even though theThe major part of the fair value fromof certain earn-out agreements and embedded derivative contracts are calculated with price inputs from observable market transaction theytransactions. They have been classified in their entirety in the third category within Current and Non-current derivative financial instruments - assets in the above table, due to part ofas the value beingis partly derived from internalinternally generated assumptions. Another reasonable assumption, to bewhich could have been used when calculating the fair value of these contracts, mightcould be to extrapolate the last observed forward prices. By extrapolating the forward curves with inflation, the fair value of the contracts included will decreasewould have increased by approximately NOK 1.01.5 billion. This decreasedSuch a change in fair value would behave been recognised in the Consolidated statementsStatement of income.

    There are significant measurement risks associated with estimatingThe reconciliation of the changes in fair value during 2009 for all financial assets and liabilities classified in the third level in the hierarchy are presented in the following table.

    (in NOK million)	Non-current financial investment	Non-current derivative financial instruments-assets	Current derivative  financial instruments-assets	Non-current derivative  financial instruments-liabilities	Current derivative  financial instruments-liabilities
    For the year ended 31 December 2009
    Opening balance	3,488	8,852	1,319	(760)	(91)
    Total gains and losses recognised
    - in income statement	(1,499)	2,601	1,500	760	(86)
    - in other comprehensive income	0	0	0	0	0
    Purchases	941	0	0	0	0
    Settlement	(327)	0	(1,319)	0	91
    Transfer into level 3	307	0	0	0	0
    Transfer out of level 3	(989)	0	0	0	0
    Closing balance	1,921	11,453	1,500	0	(86)

    Practically all gains and losses recognised in the Statement of financial instruments thatincome during 2009 are not tradedrelated to assets and liabilities held by the group at the end of 2009.

    Certain divestment requirements were set out by the European Commission (EC) in active markets. While these are StatoilHydro's best estimates of fair value, other assumptions may be made by other parties for instance with respectrelation to future commodity prices, exchange rates and interest rates. The sensitivityStatoil's acquisition of the fair valueJet automated petrol retail station network in 2008. As a consequence the investment was classified as an available for sale asset at end 2008. During 2009 the divestment requirements have been fulfilled. By end of all commodity-based contracts on changes2009 the remaining Jet activity is fully consolidated and the values previously included in commodity prices is illustratedlevel 3 in the sensitivityabove table below. Changes in the fair value of commodity-based financial instruments due to different assumptions made on future exchange rates and interest rates are deemed immaterial.have been transferred out.

    Market risk sensitivities
    

    Commodity price risk
    The table below contains the fair value and related commodity price risk sensitivitysensitivities of ourStatoil's commodity based derivatives contracts, as accounted for under IAS 39.contracts. For further information related to the type of commodity risks and how the group manages these risks see note 286 Financial risk management.

    Substantially all of these fair valueStatoil's assets and liabilities resulting from commodity based derivatives contracts are mainly related to non-exchange traded derivative instruments, including embedded derivatives that in accordance with IAS 39 have been bifurcated and recognised with fair value in the balance sheet. Included in the fair values and basis for sensitivity figures are immaterial derivative positions held for speculative trading purposes.

    Price risk sensitivities by end of 20082009 have been calculated by assuming a 50%30% change in all commoditycrude oil, refined products and electricity prices, and 50% for natural gas prices. Compared to the sensitivitysensitivities calculated by end of 20072008 and 20062007, the group's assessment of what are reasonablereasonably possible changes in the commodity prices for the coming year, have been changed due tofollowing an assessment of the changes taking placerecent developments in the markets where we operate.in which Statoil operates. By end of 2008 and 2007 and 2006 this sensitivity wasthese sensitivities were calculated by assuming a 50% and 10% change in all commodity prices.respectively.

    Since none of the derivative financial instruments included in the table below are part of a hedging relationship,relationships, any changes in the fair value will be recognised in the Consolidated statementsStatement of income.

    (in NOK million)	Fair value asset	Fair value liability	-50% sensitivity	50% sensitivity	Net fair value	-30% sensitivity	30% sensitivity
    At 31 December 2009
    Crude Oil and Refined Products					7,192	(2,087)	1,580
    						-50% / -30% sensitivity	50% / 30% sensitivity
    At 31 December 2009
    Natural Gas and Electricity					7,127	3,871	(3,886)
    						-50% sensitivity	50% sensitivity
    At 31 December 2008
    Crude Oil and Refined Products	13,136	(2,491)	(4,124)	4,440	10,645	(4,124)	4,440
    Natural Gas and Electricity	3,267	(3,239)	3,447	(3,431)	26	3,447	(3,431)
    						-10% sensitivity	10% sensitivity
    			-10% sensitivity	10% sensitivity
    At 31 December 2007
    Crude Oil and Refined Products	11,115	(2,533)	(651)	652	8,582	(651)	652
    Natural Gas and Electricity	4,219	(4,921)	1,530	(1,522)	(702)	1,530	(1,522)
    At 31 December 2006
    Crude Oil and Refined Products	7,593	(797)	(466)	410
    Natural Gas and Electricity	7,501	(4,432)	1,742	(1,671)

    As part of the tools to monitor and manage risk, the group uses the value at risk (VaR) method for certain parts of its commodity trading activity within the Natural Gas and Manufacturing and Marketing segment.segments.

    Oil sales, trading and supply (OTS), within the Manufacturing and Marketing segment, uses the historical simulation method where daily percentage market price and volatility changes for all significant products in the OTS portfolio over a given time period are applied to the current portfolio value, in order to estimate a probability distribution of future market value changes for the portfolio. Non-linear instruments such as options are revalued on a daily basis over the simulation interval using the historical price and volatility inputs; and the daily historical value changes are an integral part of the portfolio value changes. The relationship between VaR estimates and actual portfolio value changes are monitored on a monthly basis using a 12 month rolling observation window and input parameters such as simulation intervals are recalibrated when model performance moves outside acceptable bounds.

    The Natural Gas segment mainly measures its market risk exposure using a variance/covariance VaR model.method. Furthermore a 95% confidence interval and a one day holding period is applied. The variance/covariance modelmethod is applied to the current portfolio in order to quantify portfolio movements caused by possible future changes in the market prices over a 24-hour holding period. The variance/covariance modelmethod calculates the VaR as a function of standard deviation per instrument in the portfolio and the correlation between the instruments. The practical understanding is that there is a 95% probability that the value of the portfolio will change by less than the calculated VaR number during the next trading day. VaR does not quantify the worst case loss.

    The variance/covariance modelmethod calculates the VaR as a function of the standard deviation per instrument in the portfolio and the correlation between the instruments while theinstruments. The historical simulation method is based on derivingderives daily percentage market price and volatility changes for all significant products in the portfolio over a given time period are appliedand apply those to the current portfolio value, in order to estimate a probability distribution of future market value changes for the portfolio. Different VaR-methods are used within OTS and the Natural Gas segment to best reflect the nature of the relevant commodity markets.

    Within the OTS all physical and financial contracts that are managed together for risk management purposes are subject to VaR limits, independently of how they are recognised in the group'sStatoil's Consolidated balance sheet. Within Natural Gas embedded derivatives as well as certain physical forward contracts recognised as derivative financial instrument that isare not held as part of a trading position isare not included in the portfolio subject to VaR limits.

    The calculated VaR numbers for 2009 and 2008 and a summary of the assumptions used are presented in the following table.
    

    (in NOK million)	High	Low	Average
    Crude Oil and Refined Products	143	28	79
    Natural Gas and Electricity	392	88	216
    Assumptions used	Method used	Confidence level	Holding Period
    Crude Oil and Refined Products	Historical simulation VaR	95%	1 day
    Natural Gas and Electricity	Variance /Covariance	95%	1 day

    (in NOK million)	High	Low	Average
    For the year ended 31 December 2009
    Crude Oil and Refined Products	189	42	103
    Natural Gas and Electricity	219	8	80
    For the year ended 31 December 2008
    Crude Oil and Refined Products	143	28	79
    Natural Gas and Electricity	218	40	116
    Assumptions used	Method used	Confidence level	Holding period
    Crude Oil and Refined Products	Historical simulation VaR	95%	1 day
    Natural Gas and Electricity	Variance/Covariance	95%	1 day

    Interest rate and currency risk.risk
    Interest rate and currency risks constitute significant financial risks for the StatoilHydroStatoil group. Total exposure is managed at a portfolio level, in accordance with approved strategies and mandates, on a regular basis.

    The following currency risk sensitivities by end of 2008 have been calculated by assuming a 20% change foreign exchange rates. Compared to the sensitivity calculated by end of 2007 and 2006 the group's assessment of what are reasonable possible changes in foreign currencies we are exposed to for the coming year have been changed due to the changes taken place in the world financial markets. By end for 2007 and 2006 a 10% change was assumed in the calculation. Included in currency risk calculations are financial assets, financial liabilities and financial derivatives exclusive commodity derivatives. For the interest rate risk sensitivity a one percentage point change in the interest rates have been used in the calculation which is the same as by end of 2007 and 2006. The estimated gains and losses that will impact our income statement are presented in the following table.
    

    (in NOK million)	Gains	Losses
    At 31 December 2008
    Currency risk (20% sensitivity)	28,116	(28,116)
    Interest rate risk (1 percentage point sensitivity)	3,395	(3,395)
    At 31 December 2007
    Currency risk (10% sensitivity)	10,387	(10,387)
    Interest rate risk (1 percentage point sensitivity)	2,714	(2,714)
    At 31 December 2006
    Currency risk (10% sensitivity)	7,620	(7,620)
    Interest rate risk (1 percentage point sensitivity)	2,354	(2,354)

    For further information related to the interest and currency risks and how the group manages these risks see note 286 Financial risk management.

    EquityBy end of 2009 the following currency risk
    Listed equity securities, consisting mainly sensitivities have been calculated by assuming a 12 % change in foreign exchange rates that the group is exposed to. Compared to the sensitivities calculated by end of the portfolio held by2008 and 2007 the group's captive insurance company,assessment of what are recorded at fair valuereasonably possible changes in foreign exchange rates for the coming year have been changed. By end of 2008 and 2007 a 20% and a 10% change respectively, was assumed in the calculation.

    As of 1 January 2009 Statoil ASA's functional currency changed from NOK to USD, see note 1 Organisation. The change of functional currency has impacted the currency risk sensitivities when comparing 2009 with previous years.

    (in NOK million)		USD	EUR	GBP	CAD	NOK	SEK	DKK
    At 31 December 2009
    Net gains (losses) (12% sensitivity)		(3,589)	(323)	365	(299)	2,423	558	861
    Net gains (losses) (-12% sensitivity)		3,589	323	(365)	299	(2,423)	(558)	(861)
    At 31 December 2008
    Net gains (losses) (20% sensitivity)		(31,369)	(11,906)	11	(170)	39,856	1,976	1,636
    Net gains (losses) (-20% sensitivity)		31,369	11,906	(11)	170	(39,856)	(1,976)	(1,636)
    At 31 December 2007
    Net gains (losses) (10% sensitivity)		(9,391)	(3,541)	926	(297)	11,567	129	591
    Net gains (losses) (-10% sensitivity)		9,391	3,541	(926)	297	(11,567)	(129)	(591)

    For the interest rate risk sensitivity a 1.5 percentage point change in the interest rates have exposure to price risk. The fair value of listed equity securities is based on quoted market prices. In additionbeen used in the calculation. Compared to the portfolio heldsensitivities calculated by the group's captive insurance company,end of 2008 and 2007 Statoil's assessment of what are reasonably possible changes in interest rates that the group alsois exposed to for the coming year has some other non-listed equity securities classified as Available for sale investments in accordance with IAS 39.

    For more information about the fair values recognisedbeen changed. By end of 2008 and 2007 a one percentage point change in the balance sheet,interest rates was used. The estimated gains following from a decline in the assumption used when calculatinginterest rates and the estimated losses following from an interest rate increases that would impact the Statement of income are presented in the following table.

    (in NOK million)	Gains	Losses
    At 31 December 2009
    Interest rate risk (1.5 percentage point sensitivity)	8,456	(8,456)
    At 31 December 2008
    Interest rate risk (1 percentage point sensitivity)	3,395	(3,395)
    At 31 December 2007
    Interest rate risk (1 percentage point sensitivity)	2,714	(2,714)

    Equity risk
    The following table contains the fair value and therelated equity price risk sensitivitiessensitivity of Statoil's listed and non-listed equity securities. The equity price risk sensitivity has been calculated based on what Statoil views to be reasonably possible changes in the equity securities see note 14 Non-current financial assets.

    Liquidity risk
    The liquidity risk in terms of crude oil and refined products derivative contracts is usually less than one year. The term of natural gas forwards is usually three years or less. In the table below the maturity profileprices for the coming year. For 2009, as for 2008, the group's financial liability related to exchange tradedview is a 20% and non-exchange traded commodity based derivatives together with financial derivatives is presented. The maturity profile is based on the underlying delivery period of the contracts included40% change in the portfolio. equity price for the listed and non-listed equity securities respectively. In 2007 a 10% change in the equity price was used.

    For further information on managementthe listed equity securities changes in fair values would be recognised as gains or losses in the Statement of income. While for the liquidity risk, see note 28 Financial risk management.
    non-listed equity securities that are classified as available for sale assets, a decline in the fair value would be recognised in the Statement of income as an impairment loss, while an increase in the fair value would be recognised in Other comprehensive income.

    (in NOK million)	2008	2007
    Less than 1 year	(18,194)	(5,279)
    1 - 3 years	(1,551)	(2,094)
    4 - 5 years	(276)	(113)
    After 5 years	(698)	(147)
    Derivative financial instruments	(20,719)	(7,633)

    (in NOK million)	Fair value	-20% sensitivity	20% sensitivity
    At 31 December 2009
    Listed equity securities	4,318	(864)	864
    At 31 December 2008
    Listed equity securities	2,276	(455)	455
    		-40%	40%
    (in NOK million)	Fair value	sensitivity	sensitivity
    At 31 December 2009
    Non-listed equity securities	2,223	(889)	889
    At 31 December 2008
    Non-listed equity securities	4,205	(1,682)	1,682
    (in NOK million)	Fair value	-10% sensitivity	10% sensitivity
    At 31 December 2007
    Listed equity securities	4,230	(423)	423
    Non-listed equity securities	3,291	(329)	329

     

     Top 

    8.1.318.1.32 Merger with Hydro Petroleum

    The shareholders of Statoil ASA and Norsk Hydro ASA (Hydro) at extraordinary General Meetings on 5 July 2007 approved a merger between Statoil ASA and the oil and gas activities of Norsk Hydro ASA (Hydro Petroleum). The merger was effective 1 October 2007.

    As a result of the merger in 2007 StatoilHydro'sStatoil's share capital increased by NOK 2,606,655,590 from NOK 5,364,962,167.50 to NOK 7,971,617,757.50 from the issuing of 1,042,662,236 shares with a nominal value of NOK 2.50 to Hydro's shareholders. Hydro's shareholders received 0.8622 shares in the merged company for each Hydro share. After the increase Hydro's shareholders held 32.7% and former Statoil's shareholders held 67.3% of the merged company, StatoilHydroStatoil ASA.

    Given that both Statoil ASA and Norsk Hydro ASA were under the control of the Norwegian State, the merger was accounted for as a business combination between entities under common control. Management concluded that for a merger of entities under common control, the most meaningful portrayal for accounting purposes was to combine StatoilHydroStatoil and Hydro Petroleum using the carrying amounts of assets and liabilities and restating the financial statements for all periods presented as if the companies had always been combined. Consistent with this accounting treatment, the financial statements of Hydro Petroleum were adjusted to conform to the accounting policies of Statoil ASA for the tax benefit of uplift in Norway, the sales method of accounting for revenues for over- and underlift in the production of oil and gas and pension accounting. The combined impact of these changes was to decrease net equity by approximately NOK 3 billion for the year ended 31 December 2006.

    Under provisions of the merger plan, an inter-company balance was established between former Statoil and Norsk Hydro ASA as of 31 December 2006 that provides that debt less cash and short term investments of Hydro Petroleum be set at a defined level by an adjustment to a merger payable or receivable between the companies. This resulted in StatoilHydroStatoil having a merger receivable from Norsk Hydro ASA that was included in the 2007 cash flows upon its settlement.

    Hydro Petroleum was not a separate legal entity from Hydro and, therefore, had combined cash and equity balances with Hydro. As a consequence in accounting for the merger, certain cash flows to or from Hydro were treated as equity distributions or injections to or from Hydro. This is reflected in the consolidatedConsolidated statements of cash flows as "Norsk Hydro ASA merger balance" and in the consolidatedConsolidated shareholders equity of StatoilHydroStatoil as "Merger related adjustments", see note 19 Shareholdersthe Consolidated statement of changes in equity.

    StatoilHydro,Statoil, subsequent to the merger, recorded a total expense in 2007 of NOK 10.7 billion before tax related to restructuring expenses and other expenses related to the merger. The major part of these expenses was related to pensions and early retirement packages offered to employees in StatoilHydroStatoil ASA above the age of 58 years (contingent upon certain conditions).

     Top 

    8.1.33 Subsequent events

    BelowStatoil's board of directors has approved a proposal to create a stand-alone Energy & Retail (E&R) business through an initial public offering (IPO) on the Oslo Stock Exchange. The IPO will take place at the earliest in the fourth quarter of 2010 or at a time when the capital market is deemed favourable for such an offering.

    Statoil intends to remain a table showingmajority shareholder of E&R at the effectstime of the merger on the Statementinitial public offering and listing. The size and time horizon of IncomeStatoil's future ownership in E&R will be tailored to support and develop company value both for E&R and for the year ended 31 December 2006. The column "Hydro Petroleum" includes the IFRS financial information derived from the audited carve-out combined financial statements of Hydro Petroleum. The column "Former Statoil group" is derived from the IFRS transition document of Statoil ASA. The column " Merger adjustments and other eliminations" includes StatoilHydro's managements consolidation entries and adjustments to a) conform the Hydro Petroleum IFRS financial information to the accounting policies of StatoilHydro and b) eliminate internal transactions between the merged companies.

    Condensed Statements of Income
    	For the year ended 31 December 2006
    			Merger adjustments and other eliminations
    	Hydro	Former		StatoilHydro
    (in NOK million)	Petroleum	Statoil group		group
    Total revenues and other income	97,910	433,966	(10,394)	521,482
    Total operating expenses	(51,192)	(315,009)	10,883	(355,318)
    Net financial items	563	3,797	712	5,072
    Income tax	(36,188)	(81,889)	(1,312)	(119,389)
    Net income	11,093	40,865	(111)	51,847

    Group.

     Top 

    8.1.32 Subsequent events

    Effective 1 January 2009, StatoilHydro completed an internal group reorganisation in which the parts of the Exploration and Production Norway segment activities and assets previously owned by StatoilHydro ASA, excluding employees employed by StatoilHydro ASA, were transferred to the wholly owned subsidiary StatoilHydro Petroleum AS. Some parts of the Natural Gas segment activities and assets, but no employees, were also transferred. Following these reorganisations the operations of StatoilHydro ASA is no longer subject to the special petroleum tax on the Norwegian Continental Shelf. As a consequence, the tax assets related to pension liabilities in StatoilHydro ASA have effective 31 December 2008 been recognised at 28%, which is the tax rate expected to be in effect at the realisation date. Previously the estimated tax rate was 56%, based on assumed amounts expected to be realised under the petroleum tax regime and the general tax regime, respectively. The effect is a reduction of the deferre d tax assets related to pensions and a corresponding reduction to retained earnings by NOK 5.4 billion as of 31 December 2008.

    The 1 January 2009 internal group reorganisation has also resulted in a change of functional currency from NOK to USD in StatoiHydro ASA effective from the same date and with prospective effect. The functional currency of StatoilHydro Petroleum AS has not changed and remains NOK. The change of functional currency in StatoilHydro ASA has no impact on the consolidated financial statements for 2008. The presentation currency for the StatoiHydro group will remain NOK.

    On 4 March 2009 StatoilHydro ASA issued a GBP 0.8 billion bond maturing in 22 years, a EUR 1.2 billion bond maturing in 12 years and a EUR 1.3 billion bond maturing in six years. All three bonds were fully subscribed. The bonds are issued under StatoilHydro ASA's Euro Medium Term Note Programme and will be listed on London Stock Exchange. The bonds have been guaranteed by StatoilHydro Petroleum AS.

     Top 

    8.1.338.1.34 Condensed consolidating financial information related to guaranteed debt securities issued by parent company

    At 31 December 2008, StatoilHydro'sStatoil's oil and gas activities and net assets on the Norwegian Continental Shelf (NCS) were owned by StatoilHydroStatoil ASA and by StatoilHydroStatoil Petroleum AS. With effect from 1 January 2009, StatoilHydroStatoil ASA has transferred the ownership of its NCS net assets to StatoilHydroStatoil Petroleum AS, a 100% owned operating subsidiary. Following the transfer, all NCS net assets are owned by StatoilHydroStatoil Petroleum AS. Effective from the same date, StatoilHydroStatoil Petroleum AS became the co-obligor of certain existing debt securities of StatoilHydroStatoil ASA and guarantorthat are registered under the US Securities Act of certain other1933 ("US registered debt securities of StatoilHydro ASAsecurities"). As co-obligor, Statoil Petroleum AS fully, unconditionally and irrevocably assumeassumes and agreeagrees to perform, jointly and severally with Statoil ASA, the payment and covenant obligations for the relatedthese US registered debt securities. StatoilHydroIn addition, Statoil ASA also became the co-obligor of a US registered debt security of Statoil Petroleum AS. As co-obligor, Statoil ASA fully, unconditionall y and irrevocably assumes and agrees to perform, jointly and severally with Statoil Petroleum AS, the payment and covenant obligations of that security.

    During 2009, Statoil ASA issued three additional US registered debt securities which are fully and unconditionally guaranteed by Statoil Petroleum AS, with Statoil Petroleum AS being the sole guarantor of such securities. In the future, Statoil ASA may issue future US registered debt securities from time to time pursuant to registration statements filed with the SEC for which StatoilHydrodebt securities Statoil Petroleum AS iswill be the co-obligor or guarantor of such debt securities.guarantor.

    The following financial information on a condensed consolidating basis provides investors with financial information about StatoilHydroStatoil ASA, StatoilHydroas issuer and co-obligor, Statoil Petroleum AS, as co-obligor and guarantor, and all other subsidiaries as required by SEC Rule 3-10 of Regulation S-X as of 1 January 2009.S-X. The transfer of ownership of the NCS net assets from StatoilHydroStatoil ASA to StatoilHydroStatoil Petroleum AS was a common control transaction. StatoilHydroStatoil ASA accounts for common control transactions by recognising the carrying amounts of assets and liabilities transferred and restating the financial statements for all periods presented to reflect the transaction as if it at occurred at the beginning of the periods presented. The condensed consolidating information presented below reflects the transfer of NCS assets to the Co-obligorStatoil Petroleum AS for all periods presented. The condensed consolidating information is prepared in accordance with the group's IFRS accounting policies as described in note 2 Significant accounting policies, exceptexcep t that investments in subsidiaries are accounted for using the equity method of accounting as required by Rule 3-10. The functional currency for StatoilHydro ASA figures presented is NOK.

    The following is condensed consolidated financial information as of 31 December, 20082009 and 20072008 and for the years ended 31 December 2009, 2008 2007, and 2006.2007.

    CONSOLIDATED STATEMENTS OF INCOME
    CONSOLIDATED STATEMENT OF INCOME
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments		Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    2008 (in NOK million)					Group
    2009 (in NOK million)						Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments	Group
    REVENUES AND OTHER INCOME	REVENUES AND OTHER INCOME
    Revenues	389,618	249,432	242,995	( 230,068)	651,977	313,684	195,318	155,555	( 202,265)	462,292
    Net income (loss) from equity associated companies	57,648	4,408	1,105	( 61,878)	1,283
    Net income from associated companies						28,187	( 3,693)	3,313	( 26,029)	1,778
    Other income	521	20	2,572	( 353)	2,760	5	1,121	237	0	1,363
    Total revenues and other income	447,787	253,860	246,672	( 292,299)	656,020	341,876	192,746	159,105	( 228,294)	465,433
    OPERATING EXPENSES	OPERATING EXPENSES
    Purchases [net of inventory variation]	( 360,897)	( 4,045)	( 181,803)	217,563	( 329,182)	( 294,442)	( 5,276)	( 93,256)	187,104	( 205,870)
    Operating expenses	( 13,718)	( 37,081)	( 14,293)	5,743	( 59,349)	( 10,649)	( 34,979)	( 13,247)	2,015	( 56,860)
    Selling, general and administrative expenses	( 11,500)	36	( 8,789)	9,289	( 10,964)	( 7,928)	( 610)	( 12,112)	10,329	( 10,321)
    Depreciation, amortisation and impairment losses	( 693)	( 26,215)	( 16,088)	0	( 42,996)
    Depreciation, amortisation and net impairment losses						( 814)	( 27,316)	( 25,926)	0	( 54,056)
    Exploration expenses	( 551)	( 5,540)	( 8,606)	0	( 14,697)	( 861)	( 5,187)	( 10,638)	0	( 16,686)
    Total operating expenses	( 387,359)	( 72,845)	( 229,579)	232,595	( 457,188)	( 314,694)	( 73,368)	( 155,179)	199,448	( 343,793)
    Net operating income	60,428	181,015	17,093	( 59,704)	198,832	27,182	119,378	3,926	( 28,846)	121,640
    FINANCIAL ITEMS
    Net foreign exchange gains (losses)	( 38,112)	2,154	3,395	0	( 32,563)	10,608	( 4,632)	3,002	( 6,985)	1,993
    Interest income and other financial items	10,449	1,895	10,740	( 10,877)	12,207	4,693	1,017	( 9,995)	7,993	3,708
    Interest and other net finance expenses	1,025	( 4,705)	( 5,206)	10,877	1,991
    Interest and other finance expenses						( 10,629)	( 4,118)	( 5,059)	7,355	( 12,451)
    Net financial items	( 26,638)	( 656)	8,929	0	( 18,365)	4,672	( 7,733)	( 12,052)	8,363	( 6,750)
    Income before tax	33,790	180,359	26,022	( 59,704)	180,467	31,854	111,645	( 8,126)	( 20,483)	114,890
    Income tax	9,476	( 132,310)	( 13,612)	( 751)	( 137,197)	( 6,556)	( 88,266)	( 3,141)	788	( 97,175)
    Net income	43,266	48,049	12,410	( 60,455)	43,270	25,298	23,379	( 11,267)	( 19,695)	17,715

     

    CONSOLIDATED STATEMENTS OF INCOME
    CONSOLIDATED STATEMENT OF INCOME						CONSOLIDATED STATEMENT OF INCOME
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments		Statoil ASA	Statoil  Petroleum AS	Other subsidiaries	Consolidation adjustments
    2007 (in NOK million)					Group
    2008 (in NOK million)						Statoil ASA	Statoil  Petroleum AS	Other subsidiaries	Consolidation adjustments	Group
    REVENUES AND OTHER INCOME
    Revenues	272,614	200,680	197,452	( 149,081)	521,665	389,618	249,432	242,995	( 230,068)	651,977
    Net income (loss) from equity associated companies	38,221	847	667	( 39,126)	609
    Net income from associated companies						57,648	4,408	1,105	( 61,878)	1,283
    Other income	2	165	356	0	523	521	20	2,572	( 353)	2,760
    Total revenues and other income	310,837	201,692	198,475	( 188,207)	522,797	447,787	253,860	246,672	( 292,299)	656,020
    OPERATING EXPENSES
    Purchases [net of inventory variation]	( 257,608)	( 3,739)	( 135,677)	136,628	( 260,396)	( 360,897)	( 4,045)	( 181,803)	217,563	( 329,182)
    Operating expenses	( 10,149)	( 42,166)	( 12,604)	4,601	( 60,318)	( 13,718)	( 37,081)	( 14,293)	5,743	( 59,349)
    Selling, general and administrative expenses	( 9,656)	( 1,534)	( 9,422)	6,438	( 14,174)	( 11,500)	36	( 8,789)	9,289	( 10,964)
    Depreciation, amortisation and impairment losses	( 631)	( 24,747)	( 13,994)	0	( 39,372)
    Depreciation, amortisation and net impairment losses						( 693)	( 26,215)	( 16,088)	0	( 42,996)
    Exploration expenses	( 713)	( 4,074)	( 6,546)	0	( 11,333)	( 551)	( 5,540)	( 8,606)	0	( 14,697)
    Total operating expenses	( 278,757)	( 76,260)	( 178,243)	147,667	( 385,593)	( 387,359)	( 72,845)	( 229,579)	232,595	( 457,188)
    Net operating income	32,080	125,432	20,232	( 40,540)	137,204	60,428	181,015	17,093	( 59,704)	198,832
    FINANCIAL ITEMS
    Net foreign exchange gains (losses)	15,979	( 639)	( 5,297)	0	10,043	( 38,112)	2,154	3,395	0	( 32,563)
    Interest income and other financial items	4,134	241	3,875	( 5,945)	2,305	10,449	1,895	10,740	( 10,877)	12,207
    Interest and other net finance expenses	( 5,128)	( 2,208)	( 1,350)	5,945	( 2,741)
    Interest and other finance expenses						1,025	( 4,705)	( 5,206)	10,877	1,991
    Net financial items	14,985	( 2,606)	( 2,772)	0	9,607	( 26,638)	( 656)	8,929	0	( 18,365)
    Income before tax	47,065	122,826	17,460	( 40,540)	146,811	33,790	180,359	26,022	( 59,704)	180,467
    Income tax	( 2,971)	( 92,897)	( 6,730)	428	( 102,170)	9,476	( 132,310)	( 13,612)	( 751)	( 137,197)
    Net income	44,094	29,929	10,730	( 40,112)	44,641	43,266	48,049	12,410	( 60,455)	43,270

     

    CONSOLIDATED STATEMENTS OF INCOME
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments
    2006 (in NOK million)					Group
    REVENUES AND OTHER INCOME
    Revenues	244,497	211,007	182,013	( 118,557)	518,960
    Net income (loss) from equity associated companies	52,196	( 359)	208	( 51,366)	679
    Other income	9	657	1,177	0	1,843
    Total revenues and other income	296,702	211,305	183,398	( 169,923)	521,482
    OPERATING EXPENSES
    Purchases [net of inventory variation]	( 227,983)	( 2,155)	( 127,118)	107,663	( 249,593)
    Operating expenses	( 10,936)	( 30,183)	( 10,245)	6,563	( 44,801)
    Selling, general and administrative expenses	( 5,141)	( 950)	( 8,724)	3,991	( 10,824)
    Depreciation, amortisation and impairment losses	( 345)	( 22,443)	( 16,662)	0	( 39,450)
    Exploration expenses	( 489)	( 3,780)	( 6,381)	0	( 10,650)
    Total operating expenses	( 244,894)	( 59,511)	( 169,130)	118,217	( 355,318)
    Net operating income	51,808	151,794	14,268	( 51,706)	166,164
    FINANCIAL ITEMS
    Net foreign exchange gains (losses)	5,665	555	( 1,763)	0	4,457
    Interest income and other financial items	1,137	461	5,021	( 2,944)	3,675
    Interest and other net finance expenses	( 6,147)	( 1,022)	1,165	2,944	( 3,060)
    Net financial items	655	( 6)	4,423	0	5,072
    Income before tax	52,463	151,788	18,691	( 51,706)	171,236
    Income tax	( 1,345)	( 115,362)	( 2,783)	101	( 119,389)
    Net income	51,118	36,426	15,908	( 51,605)	51,847

    CONSOLIDATED BALANCE SHEETS
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2008 (in NOK million)					Group
    ASSETS
    Non-current assets
    Property, plant and equipment	5,698	187,739	136,404	0	329,841
    Intangible assets	7	6,888	59,141	0	66,036
    Shares in subsidiaries	314,779	69,586	4,750	(389,115)	0
    Equity accounted investments	845	1,070	11,078	(353)	12,640
    Deferred tax assets	7,187	0	1,302	(7,187)	1,302
    Pension assets	0	0	30	0	30
    Financial investments	12	7	16,446	0	16,465
    Derivative financial instruments	2,383	0	0	0	2,383
    Financial receivables	343	539	4,032	0	4,914
    Financial receivables from subsidiaries	44,148	56	26,332	(70,536)	0
    			0
    Total non-current assets	375,402	265,885	259,515	(467,191)	433,611
    Current assets
    Inventories	5,884	942	9,858	(1,533)	15,151
    Trade and other receivables	36,394	12,918	20,619	0	69,931
    Current tax receivables	2,959	881	0	0	3,840
    Receivables from subsidiaries	10,740	39,059	97,912	(147,711)	0
    Derivative financial instruments	14,298	9,751	3,456	0	27,505
    Financial investments	2,616	0	7,131	0	9,747
    Cash and cash equivalents	6,272	0	12,366	0	18,638
    Total current assets	79,163	63,551	151,342	(149,244)	144,812
    TOTAL ASSETS	454,565	329,436	410,857	(616,435)	578,423
    EQUITY AND LIABILITIES
    Equity
    Paid in Capital and Retained Earnings	196,825	104,827	265,445	(370,272)	196,825
    Other reserves	17,254	2,738	17,254	(19,992)	17,254
    StatoilHydro shareholders' equity	214,079	107,565	282,699	(390,264)	214,079
    Minority interest	0	0	1,976	0	1,976
    			0
    Total equity	214,079	107,565	284,675	(390,264)	216,055
    Non-current liabilities
    Financial liabilities	49,858	767	3,981	0	54,606
    Non-current liabilities to subsidiaries	37	42,623	27,897	(70,557)	0
    Deferred tax liabilities	0	69,722	5,948	(7,526)	68,144
    Pension liabilities	20,649	4,312	577	0	25,538
    Other provisions	1,233	34,838	18,686	(398)	54,359
    Total non-current liabilities	71,777	152,262	57,089	(78,481)	202,647
    Current liabilities
    Trade and other payables	22,992	16,966	21,242	0	61,200
    Income taxes payable	1,896	50,746	4,432	0	57,074
    Financial liabilities	18,784	255	1,656	0	20,695
    Derivative financial instruments	18,814	20	1,918	0	20,752
    Current liabilities to subsidiaries	106,223	1,622	39,845	(147,690)	0
    Total current liabilities	168,709	69,609	69,093	(147,690)	159,721
    Total liabilities	240,486	221,871	126,182	(226,171)	362,368
    TOTAL EQUITY AND LIABILITIES	454,565	329,436	410,857	(616,435)	578,423

    CONSOLIDATED STATEMENT OF INCOME
    	Statoil  ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    2007 (in NOK million)					Group
    REVENUES AND OTHER INCOME
    Revenues	272,614	200,680	197,452	( 149,081)	521,665
    Net income from associated companies	38,221	847	667	( 39,126)	609
    Other income	2	165	356	0	523
    Total revenues and other income	310,837	201,692	198,475	( 188,207)	522,797
    OPERATING EXPENSES
    Purchases [net of inventory variation]	( 257,608)	( 3,739)	( 135,677)	136,628	( 260,396)
    Operating expenses	( 10,149)	( 42,166)	( 12,604)	4,601	( 60,318)
    Selling, general and administrative expenses	( 9,656)	( 1,534)	( 9,422)	6,438	( 14,174)
    Depreciation, amortisation and net impairment losses	( 631)	( 24,747)	( 13,994)	0	( 39,372)
    Exploration expenses	( 713)	( 4,074)	( 6,546)	0	( 11,333)
    Total operating expenses	( 278,757)	( 76,260)	( 178,243)	147,667	( 385,593)
    Net operating income	32,080	125,432	20,232	( 40,540)	137,204
    FINANCIAL ITEMS
    Net foreign exchange gains (losses)	15,979	( 639)	( 5,297)	0	10,043
    Interest income and other financial items	4,134	241	3,875	( 5,945)	2,305
    Interest and other finance expenses	( 5,128)	( 2,208)	( 1,350)	5,945	( 2,741)
    Net financial items	14,985	( 2,606)	( 2,772)	0	9,607
    Income before tax	47,065	122,826	17,460	( 40,540)	146,811
    Income tax	( 2,971)	( 92,897)	( 6,730)	428	( 102,170)
    Net income	44,094	29,929	10,730	( 40,112)	44,641

     

    CONSOLIDATED BALANCE SHEETS
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2007 (in NOK million)					Group
    ASSETS
    Non-current assets
    Property, plant and equipment	5,317	179,446	93,589	0	278,352
    Intangible assets	8	4,946	39,896	0	44,850
    Shares in subsidiaries	201,251	53,208	2,811	(257,270)	0
    Equity accounted investments	952	1,470	5,999	0	8,421
    Deferred tax assets	0	0	3,610	(2,817)	793
    Pension assets	1,561	0	61	0	1,622
    Financial investments	13	15	15,238	0	15,266
    Derivative financial instruments	609	0	0	0	609
    Financial receivables	214	337	2,964	0	3,515
    Financial receivables from subsidiaries	46,774	31	52	(46,857)	0
    Total non-current assets	256,699	239,453	164,220	(306,944)	353,428
    Current assets
    Inventories	7,296	1,526	12,536	(3,662)	17,696
    Trade and other receivables	38,939	9,587	20,852	0	69,378
    Receivables from subsidiaries	10,271	10,999	48,941	(70,211)	0
    Derivative financial instruments	7,327	9,704	4,062	0	21,093
    Financial investments	155	0	3,204	0	3,359
    Cash and cash equivalents	21	(7)	18,250	0	18,264
    Total current assets	64,009	31,809	107,845	(73,873)	129,790
    TOTAL ASSETS	320,708	271,262	272,065	(380,817)	483,218
    EQUITY AND LIABILITIES
    Equity
    Paid in Capital and Retained Earnings	189,886	76,111	200,826	(276,937)	189,886
    Other reserves	(12,611)	(4,484)	(12,611)	17,095	(12,611)
    StatoilHydro shareholders' equity	177,275	71,627	188,215	(259,842)	177,275
    Minority interest	0	0	1,792	0	1,792
    Total equity	177,275	71,627	190,007	(259,842)	179,067
    Non-current liabilities
    Financial liabilities	35,425	4,615	4,334	0	44,374
    Non-current liabilities to subsidiaries	27	42,670	4,162	(46,859)	0
    Deferred tax liabilities	468	63,683	7,233	(3,907)	67,477
    Pension liabilities	18,384	0	708	0	19,092
    Other provisions	2,001	32,941	8,903	0	43,845
    Total non-current liabilities	56,305	143,909	25,340	(50,766)	174,788
    Current liabilities
    Trade and other payables	33,668	13,701	17,255	0	64,624
    Income taxes payable	6,261	40,542	4,138	0	50,941
    Financial liabilities	4,718	13	1,435	0	6,166
    Derivative financial instruments	3,901	531	3,200	0	7,632
    Current liabilities to subsidiaries	38,580	939	30,690	(70,209)	0
    Total current liabilities	87,128	55,726	56,718	(70,209)	129,363
    Total liabilities	143,433	199,635	82,058	(120,975)	304,151
    TOTAL EQUITY AND LIABILITIES	320,708	271,262	272,065	(380,817)	483,218

    CONSOLIDATED BALANCE SHEET
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2009 (in NOK million)					Group
    ASSETS
    Non-current assets
    Property, plant and equipment	4,771	197,537	138,527	0	340,835
    Intangible assets	29	8,365	45,859	0	54,253
    Shares in subsidiaries	290,648	87,156	(0)	(377,804)	0
    Investments in associated companies	605	823	9,416	(788)	10,056
    Deferred tax assets	2,380	3,732	0	(4,153)	1,960
    Pension assets	2,665	0	29	0	2,694
    Financial investments	11	5	13,251	0	13,267
    Derivative financial instruments	7,132	10,512	0	0	17,644
    Financial receivables	1,285	1,323	3,139	0	5,747
    Financial receivables from subsidiaries	47,651	97	30,327	(78,076)	0
    Total non-current assets	357,177	309,551	240,549	(460,821)	446,456
    Current assets
    Inventories	11,976	50	12,124	(3,954)	20,196
    Trade and other receivables	31,983	9,354	17,558	0	58,895
    Current tax receivables	179	0	0	0	179
    Receivables from subsidiaries	0	4,184	129,227	(133,411)	0
    Derivative financial instruments	3,888	1,200	281	0	5,369
    Financial investments	1,905	0	5,117	0	7,022
    Cash and cash equivalents	14,460	3	10,260	0	24,723
    Total current assets	64,391	14,792	174,566	(137,365)	116,384
    TOTAL ASSETS	421,568	324,344	415,114	(598,186)	562,840

     

    CASH FLOW STATEMENT
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2008 (in NOK million)					Group
    Cash flows provided by operating activities	( 11,182)	75,887	44,181	( 6,353)	102,533
    Cash flows used in investing activities	( 70,188)	( 52,003)	( 36,492)	72,846	( 85,837)
    Cash flows used in financing activities	87,618	( 23,879)	( 14,275)	( 66,493)	( 17,029)
    Net increase (decrease) in cash and cash equivalents	6,248	5	( 6,586)	0	( 333)
    Effect of exchange rate changes on cash and cash equivalents	0	( 5)	712	0	707
    Cash and cash equivalents at the beginning of the period	23		18,241	0	18,264
    Cash and cash equivalents at the end of the period	6,271	0	12,367	0	18,638
    CASH FLOW STATEMENT
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2007 (in NOK million)					Group
    Cash flows provided by operating activities	15,343	56,394	34,902	( 12,713)	93,926
    Cash flows used in investing activities	( 29,400)	( 46,679)	( 27,910)	28,877	( 75,112)
    Cash flows used in financing activities	14,084	( 9,728)	3,900	( 16,164)	( 7,908)
    Net increase (decrease) in cash and cash equivalents	27	( 13)	10,892	0	10,906
    Effect of exchange rate changes on cash and cash equivalents	0	0	( 160)	0	( 160)
    Cash and cash equivalents at the beginning of the period	( 4)	8	7,514	0	7,518
    			0
    Cash and cash equivalents at the end of the period	23	( 5)	18,246	0	18,264
    CASH FLOW STATEMENT
    	StatoilHydro ASA	StatoilHydro Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2006 (in NOK million)					Group
    Cash flows provided by operating activities	1,724	72,066	22,198	( 7,395)	88,593
    Cash flows used in investing activities	( 6,491)	( 35,582)	( 20,726)	5,624	( 57,175)
    Cash flows used in financing activities	4,580	( 36,496)	( 1,233)	1,771	( 31,378)
    Net increase (decrease) in cash and cash equivalents	( 187)	( 12)	239	0	40
    Effect of exchange rate changes on cash and cash equivalents	0	0	42	0	42
    Cash and cash equivalents at the beginning of the period	183	20	7,233	0	7,436
    Cash and cash equivalents at the end of the period	( 4)	8	7,514	0	7,518

    CONSOLIDATED BALANCE SHEET
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2009 (in NOK million)					Group
    EQUITY AND LIABILITIES
    Equity
    Paid in Capital and Retained Earnings	201,736	105,975	295,004	(407,964)	194,751
    Other reserves	(3,417)	(4,543)	(15,012)	26,540	3,568
    Statoil shareholders' equity	198,319	101,432	279,992	(381,424)	198,319
    Non-controlling interest (Minority interest)	0	0	1,799	0	1,799
    Total equity	198,319	101,432	281,791	(381,424)	200,118
    Non-current liabilities
    Financial liabilities	83,443	292	12,227	0	95,962
    Non-current liabilities to subsidiaries	50	46,545	31,480	(78,076)	0
    Derivative financial instruments	1,657	0	0	0	1,657
    Deferred tax liabilities	0	80,740	862	(5,280)	76,322
    Pension liabilities	20,682	0	460	0	21,142
    Asset retirement obligations, other provisions and other liabilities	1,916	40,138	13,780	0	55,834
    Total non-current liabilities	107,748	167,715	58,809	(83,356)	250,917
    Current liabilities
    Trade and other payables	27,243	14,104	18,454	0	59,801
    Current tax payable	4,182	33,472	3,340	0	40,994
    Financial liabilities	7,386	0	764	0	8,150
    Derivative financial instruments	2,530	18	312	0	2,860
    Current liabilities to subsidiaries	74,160	7,602	51,644	(133,406)	0
    Total current liabilities	115,501	55,196	74,514	(133,406)	111,805
    Total liabilities	223,249	222,912	133,323	(216,762)	362,722
    TOTAL EQUITY AND LIABILITIES	421,568	324,344	415,114	(598,186)	562,840

    As of 1 January 2009, StatoilHydro Petroleum AS has become a co-obligor of the following securities of StatoilHydro ASA: USD 300,000,000 aggregate principal amount 6.36% Notes due 2009, USD 350,000,000 aggregate principal amount 9.00% Debentures due 2012, USD 99,522,000 aggregate principal amount 9.125% Debentures due 2014, USD 300,000,000 aggregate principal amount 7.50% Debentures due 2016, USD 250,000,000 aggregate principal amount 6.70% Debentures due 2018, USD 300,000,000 aggregate principal amount 7.75% Debentures due 2023, USD 250,000,000 aggregate principal amount 7.15% Debentures due 2025, USD 480,512,000 aggregate principal amount 7.25% Debentures due 2027, USD 250,000,000 aggregate principal amount 6.80% Debentures due 2028 and USD 275,000,000 aggregate principal amount 7.15% Debentures due 2029, each issued under an Indenture dated as of April 15, 1992. As amended; USD 500,000,000 aggregate principal amount 7.25% Debentures due 2027 issued under an Indenture dated as of July 8, 1 994. As amended; the USD 500,000,000 aggregate principal amount 5.125% Notes due 2014, USD 250,000,000 aggregate principal amount 7.375% Debentures due 2016 and USD 500,000,000 aggregate principal amount 6.50% Debentures due 2028, issued under the Fiscal and Paying Agency Agreements dated as of 27 April 2004, 7 May 1996, and 14 December 1998, respectively.

    CONSOLIDATED BALANCE SHEET
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2008 (in NOK million)					Group
    ASSETS
    Non-current assets
    Property, plant and equipment	5,698	187,739	136,404	0	329,841
    Intangible assets	7	6,888	59,141	0	66,036
    Shares in subsidiaries	314,779	69,586	4,750	(389,115)	0
    Investments  in associated companies	845	1,070	11,078	(353)	12,640
    Deferred tax assets	7,187	0	1,302	(7,187)	1,302
    Pension assets	0	0	30	0	30
    Financial investments	12	7	16,446	0	16,465
    Derivative financial instruments	12,430	8,852	0	0	21,282
    Financial receivables	343	539	4,032	0	4,914
    Financial receivables from subsidiaries	44,148	56	26,332	(70,536)	0
    			0
    Total non-current assets	385,449	274,737	259,515	(467,191)	452,510
    Current assets
    Inventories	5,884	942	9,858	(1,533)	15,151
    Trade and other receivables	36,394	12,918	20,619	0	69,931
    Current tax receivables	2,959	881	0	0	3,840
    Receivables from subsidiaries	10,740	39,059	97,912	(147,711)	0
    Derivative financial instruments	5,011	899	3,456	0	9,366
    Financial investments	2,616	0	7,131	0	9,747
    Cash and cash equivalents	6,272	0	12,366	0	18,638
    Total current assets	69,876	54,699	151,342	(149,244)	126,673
    TOTAL ASSETS	455,325	329,436	410,857	(616,435)	579,183

    StatoilHydro Petroleum AS will be a guarantor of the following securities of StatoilHydro ASA: the USD 250,000,000 aggregate principal amount 7.875% notes due 2022 and USD 100,000,000 aggregate principal amount 6.50% notes due 2023, each issued under the Agency Agreement dated as of July 7, 1988. As amended; the GBP 225,000,000 aggregate principal amount 6.50% Notes due 2021 and EUR 400,000,000 aggregate principal amount 6.25% Notes due 2010 issued under the Trust Deed dated as of January 22, 1999; the EUR 20,000,000 aggregate principal amount Step-up Notes due 2029, GBP 225,000,000 aggregate principal amount 6.125% notes due 2028, JPY 5,000,000,000 aggregate principal amount Fixed Rate Notes due 2012, EUR 500,000,000 aggregate principal amount 5.125% notes due 2011, and USD 375,000,000 aggregate principal amount 5.75%. Notes due 2009, each issued under StatoilHydro ASA's EMTN program; and the CHF 200,000,000 aggregate principal amount 4% Bonds 1999-2009.

    CONSOLIDATED BALANCE SHEET
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2008 (in NOK million)					Group
    EQUITY AND LIABILITIES
    Equity
    Paid in Capital and Retained Earnings	196,825	104,827	281,473	(386,300)	196,825
    Other reserves	17,254	2,738	1,226	(3,964)	17,254
    Statoil shareholders' equity	214,079	107,565	282,699	(390,264)	214,079
    Non-controlling interest (Minority interest)	0	0	1,976	0	1,976
    Total equity	214,079	107,565	284,675	(390,264)	216,055
    Non-current liabilities
    Financial liabilities	49,858	767	3,981	0	54,606
    Non-current liabilities to subsidiaries	37	42,623	27,897	(70,557)	0
    Derivative financial instruments	1,617	0	0	0	1,617
    Deferred tax liabilities	0	69,722	5,948	(7,526)	68,144
    Pension liabilities	20,649	4,312	577	0	25,538
    Asste retirement obligations, other provisions and other liabilities	1,233	34,838	18,686	(398)	54,359
    Total non-current liabilities	73,394	152,262	57,089	(78,481)	204,264
    Current liabilities
    Trade and other payables	22,992	16,966	21,242	0	61,200
    Current tax payable	1,896	50,746	4,432	0	57,074
    Financial liabilities	18,784	255	1,656	0	20,695
    Derivative financial instruments	17,957	20	1,918	0	19,895
    Current liabilities to subsidiaries	106,223	1,622	39,845	(147,690)	0
    Total current liabilities	167,852	69,609	69,093	(147,690)	158,864
    Total liabilities	241,246	221,871	126,182	(226,171)	363,128
    TOTAL EQUITY AND LIABILITIES	455,325	329,436	410,857	(616,435)	579,183

    StatoilHydro Petroleum AS also became the guarantor or co-obligor as of 1 January 2009 of certain non registered debt securities sold outside the US. The company may also issue future non registered debt securities from time to time that are offered to non US investors for which StatoilHydro Petroleum AS is the guarantor or co-obligor of such debt securities.

    CONSOLIDATED BALANCE SHEET
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 1 January 2008 (restated, in NOK million)					Group
    ASSETS
    Non-current assets
    Property, plant and equipment	5,317	179,446	93,589	0	278,352
    Intangible assets	8	4,946	39,896	0	44,850
    Shares in subsidiaries	201,251	53,208	2,811	(257,270)	0
    Investments in associated companies	952	1,470	5,999	0	8,421
    Deferred tax assets	0	0	3,610	(2,817)	793
    Pension assets	1,561	0	61	0	1,622
    Financial investments	13	15	15,238	0	15,266
    Derivative financial instruments	3,155	9,613	0	0	12,768
    Financial receivables	214	337	2,964	0	3,515
    Financial receivables from subsidiaries	46,774	31	52	(46,857)	0
    Total non-current assets	259,245	249,066	164,220	(306,944)	365,587
    Current assets
    Inventories	7,296	1,526	12,536	(3,662)	17,696
    Trade and other receivables	38,939	9,587	20,852	0	69,378
    Current tax receivables	0	0	0	0	0
    Receivables from subsidiaries	10,271	10,999	48,941	(70,211)	0
    Derivative financial instruments	4,649	91	4,062	0	8,802
    Financial investments	155	0	3,204	0	3,359
    Cash and cash equivalents	21	(7)	18,250	0	18,264
    Total current assets	61,331	22,196	107,845	(73,873)	117,499
    TOTAL ASSETS	320,576	271,262	272,065	(380,817)	483,086

    StatoilHydro ASA has become a co-obligor under StatoilHydro Petroleum AS' USD 100,000,000 aggregate principal amount 9.125% Debentures due 2014 issued under an Indenture dated as of July 8, 1994, as amended.

    CONSOLIDATED BALANCE SHEET
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 1 January 2008 (restated, in NOK million)					Group
    EQUITY AND LIABILITIES
    Equity
    Paid in Capital and Retained Earnings	189,886	76,111	188,292	(264,401)	189,888
    Other reserves	(12,611)	(4,484)	(77)	4,559	(12,613)
    Statoil shareholders' equity	177,275	71,627	188,215	(259,842)	177,275
    Non-controlling interest (Minority interest)	0	0	1,792	0	1,792
    Total equity	177,275	71,627	190,007	(259,842)	179,067
    Non-current liabilities
    Financial liabilities	35,425	4,615	4,334	0	44,374
    Non-current liabilities to subsidiaries	27	42,670	4,162	(46,859)	0
    Derivative financial instruments	27	0	0	0	27
    Deferred tax liabilities	468	63,683	7,233	(3,907)	67,477
    Pension liabilities	18,384	0	708	0	19,092
    Asset retirement obligations, other provisions and other liabilities	2,001	32,941	8,903	0	43,845
    Total non-current liabilities	56,332	143,909	25,340	(50,766)	174,815
    Current liabilities
    Trade and other payables	33,668	13,701	17,255	0	64,624
    Current tax payable	6,261	40,542	4,138	0	50,941
    Financial liabilities	4,718	13	1,435	0	6,166
    Derivative financial instruments	3,742	531	3,200	0	7,473
    Current liabilities to subsidiaries	38,580	939	30,690	(70,209)	0
    Total current liabilities	86,969	55,726	56,718	(70,209)	129,204
    Total liabilities	143,301	199,635	82,058	(120,975)	304,019
    TOTAL EQUITY AND LIABILITIES	320,576	271,262	272,065	(380,817)	483,086

    CASH FLOW STATEMENT
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2009 (in NOK million)					Group
    Cash flows provided by operating activities	( 3,547)	64,133	27,711	( 15,296)	73,001
    Cash flows used in investing activities	21,639	( 62,931)	( 44,366)	10,302	( 75,356)
    Cash flows provided by (used in) financing activities	( 8,809)	( 1,199)	16,305	4,994	11,291
    Net increase (decrease) in cash and cash equivalents	9,283	3	( 350)	0	8,936
    Effect of exchange rate changes on cash and cash equivalents	( 1,095)	0	( 1,756)	0	( 2,851)
    Cash and cash equivalents at the beginning of the period	6,272	0	12,366	0	18,638
    Cash and cash equivalents at the end of the period	14,460	3	10,260	0	24,723
    CASH FLOW STATEMENT
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2008 (in NOK million)					Group
    Cash flows provided by operating activities	( 11,182)	75,887	44,181	( 6,353)	102,533
    Cash flows used in investing activities	( 70,188)	( 52,003)	( 36,492)	72,846	( 85,837)
    Cash flows provided by (used in) financing activities	87,618	( 23,879)	( 14,275)	( 66,493)	( 17,029)
    Net increase (decrease) in cash and cash equivalents	6,248	5	( 6,586)	0	( 333)
    Effect of exchange rate changes on cash and cash equivalents	0	( 5)	712	0	707
    Cash and cash equivalents at the beginning of the period	23		18,241	0	18,264
    Cash and cash equivalents at the end of the period	6,271	0	12,367	0	18,638
    CASH FLOW STATEMENT
    	Statoil ASA	Statoil Petroleum AS	Other subsidiaries	Consolidation adjustments
    At 31 December 2007 (in NOK million)					Group
    Cash flows provided by operating activities	15,343	56,394	34,902	( 12,713)	93,926
    Cash flows used in investing activities	( 29,400)	( 46,679)	( 27,910)	28,877	( 75,112)
    Cash flows provided by (used in) financing activities	14,084	( 9,728)	3,900	( 16,164)	( 7,908)
    Net increase (decrease) in cash and cash equivalents	27	( 13)	10,892	0	10,906
    Effect of exchange rate changes on cash and cash equivalents	0	0	( 160)	0	( 160)
    Cash and cash equivalents at the beginning of the period	( 4)	8	7,514	0	7,518
    Cash and cash equivalents at the end of the period	23	( 5)	18,246	0	18,264

     Top 

    8.1.348.1.35 Supplementary oil and gas information (UNAUDITED)(unaudited)

    In accordance with Statement of FinancialFASB Accounting Standards No. 69 "Disclosures aboutCodification "Extractive Activities - Oil and Gas Producing Activities" (FAS 69)Gas" (Topic 932), StatoilHydroStatoil is making certain supplemental disclosures about oil and gas exploration and production operations.operations as previously required by Statement of Financial Accounting Standards No. 69 " Disclosures about Oil and Gas Producing Activities" (FAS 69). While this information is developed with reasonable care and disclosed in good faith, it is emphasised that some of the data is necessarily imprecise and represents only approximate amounts because of the subjective judgment involved in developing such information. Accordingly, this information may not necessarily represent the present financial condition of StatoilHydroStatoil or its expected future results.

    Certain reclassifications have been made to prior periods' figures to be consistentFinancial Accounting Standard Board aligned in January 2010 the oil and gas reserves estimation and disclosure requirements of "Extractive Activities - Oil and Gas" (Topic 932) with the current period's classifications.requirements in the Securities and Exchange Commission's final rule, "Modernization of the Oil and Gas Reporting Requirements" (the Final Rule) issued December 2008. Our reporting in 2009 is in accordance with the updated requirements. Prior period disclosures are not adjusted. For further information regarding revision of the reserves estimation requirement see note 2 Significant accounting policies - Critical judgement and key sources of estimation uncertainty - Proved oil and gas reserves.

    No events have occurred since 31 December 2009 that would mean a significant change in the estimated proved reserves or other figures reported as of that date.

    The subtotals and totals in some of the tables may not equal the sum of the amounts shown due to rounding.

    Oil and gas reserve quantities
    StatoilHydro'sStatoil's oil and gas reserves have been estimated by its experts in accordance with industry standards under the requirements of the US Securities and Exchange Commission (SEC), Rule 4-10 of Regulation S-X. Reserves are net of royalty oil paid in kind and quantities consumed during production. Statements of reserves are forward-looking statements.

    The determination of these reserves is part of an ongoing process subject to continual revision as additional information becomes available. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, identified reserves and contingent resources that may become proved in the future, are excluded from the calculations.

    ProvedIn 2002, Statoil entered into a buy-back contract in Iran. Statoil also participates in a number of production sharing agreements (PSAs) in Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia. Reserves from such agreements are based on the volumes to which Statoil has access (cost oil and profit oil), limited to available market access. Proved reserves at end of year associated with PSA and buy-back agreements are disclosed separately in the following tables.

    Statoil is recording, as proved reserves, volumes equivalent to our tax liabilities payable in-kind under negotiated fiscal arrangements (production sharing agreements or income sharing agreements).

    Rule 4-10 of Regulation S-X requires that the appraisal of reserves is based on existing economical conditions including a 12-month average price. Reserves at year-end 2009 have been determined based on a 12-month average 2009 Brent price equivalent to $59.9/bbl. The increase in oil price from year end 2008 (Brent blend price of $36.6/bbl) to an average 2009 price has increased the profitable oil to be recovered from the accumulations while Statoil's proved oil reserves under PSAs and similar contracts have as a result decreased. The gas prices have in general, decreased from year end 2008 to an average 2009 price and has affected the profitable 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 ofrecovered accordingly. These changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

    1. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.
    2. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed programrevision category in the reservoir, provides support for the engineering analysis on which the project or program was based.
    3. Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

    Proved developed oil and gas reserves are proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Over time, undeveloped reserves will be reclassified to proved developed reserves as new wells are drilled, existing wells are recompleted or facilities to produce from existing wells and planned wells comes in operation.

    Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.tables below.

    From the Norwegian Continental Shelf (NCS) StatoilHydroStatoil is required, on behalf of the Norwegian State's direct financial interest (SDFI), to manage, transport and sell the Norwegian State's oil and gas. These reserves are sold in conjunction with our own reserves. As part of this arrangement, StatoilHydroStatoil will deliver gas to customers in accordance with various types of sales contracts. In order to fulfil the commitments, StatoilHydroStatoil will utilise a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between StatoilHydroStatoil and SDFI.
    
    As of 31 December 2008, the StatoilHydro / SDFI arrangement amounted to a total of 31.9 tcf in total expected gas commitments on the NSC. The principles for booking of proved reserves are limited to contracted gas sales and gas with access to a market.

    The majority of StatoilHydro's gas volumes are sold under long term contracts with Take or Pay clauses. For each individual year, StatoilHydro and SDFI express their delivery commitments as the sum of the Annual Contract Quantity (ACQ). In the contract years 2008 to 2011, the joint ACQ for the respective years are; 2.66, 2.59, 2.62, and 2.56 tcf. The majority of delivery commitments will be fulfilled by expected production of proved reserves from fields were StatoilHydro and/or SDFI participates, while potential shortfalls will be covered by sourcing existing gas markets.

    StatoilHydro experiences a situation with reduced supply of LNG due to production problems at the Snøhvit LNG liquefaction plant in Norway. Actions and efforts have been carried out in order to mitigate the effect of the reduced supply. The production problems contributed to a shortfall of approximately 2.0% of StatoilHydro's delivery commitments throughout the year 2008. The effect of the production problems may also result in some shortfalls in LNG supply for 2009.

    StatoilHydroStatoil and SDFI receive income from the joint natural gas sales portfolio based upon their respective share in the supply volumes. For sales of the SDFI natural gas, both to StatoilHydroStatoil and to third parties, the payment to the Norwegian State is based on either achieved prices, a net back formula calculated price or market value. All of the Norwegian State's oil and NGL is acquired by StatoilHydro.Statoil. Pricing of the crude oil is based on market reflective prices; NGL prices are either based on achieved prices, market value or market reflective prices.

    The owner's instruction may be changed or withdrawn by the StatoilHydroStatoil general meeting. Due to this uncertainty and the Norwegian State's estimate of proved reserves not being available to StatoilHydro,Statoil, it is not possible to determine the total quantities to be purchased by StatoilHydroStatoil under the owner's instruction from properties in which it participates in the operations.

    In 2002, StatoilHydro entered into a buy-back contract in Iran. StatoilHydro also participates in a number of production sharing agreements (PSAs) in Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia. Reserves from such agreements are based onTopic 932 requires the volumes to which StatoilHydro has access (cost oil and profit oil), limited to available market access. Proved reserves at end of year associated with PSA and buy-back agreements are disclosed separately in the following table.

    Rule 4-10 of Regulation S-X requires that the appraisalpresentation of reserves is based on the economic environment and operating conditions existing at year end. Reserves at year-end 2008 have been determined based on the Brent price on 31 December 2008 ($36.55/bbl). The reduction in oil price from year-end 2007 (Brent blend price of $96.02/bbl) to year-end 2008 has lowered the profitablecertain other supplemental oil and gas disclosures by geographical area, defined as country or continent containing 15% or more of total proved reserves. Norway contains 80% of total proved reserves at 31 December 2009 and no other country or continent contains reserves approaching 15% of total proved reserves. Accordingly, management has determined that the most meaningful presentation of geographical areas would be to be recovered frominclude Norway and the accumulations while StatoilHydro'scontinents of Eurasia (excluding Norway), Africa and America.

    The following tables reflect the estimated proved reserves of oil and gas reserves under PSAsat 31 December 2006 to 2009, and similar contracts have as a result increased. Thesethe changes are included in the revisions category in the table below.therein.

    	Net proved oil and NGL reserves in million barrels			Net proved gas reserves in billion standard cubic feet			Net proved oil, NGL and gas reserves in million barrels oil equivalent
    	Norway	Outside Norway	Total	Norway	Outside Norway	Total	Norway	Outside Norway	Total
    Reserves in consolidated companies
    At 31 December 2006	1,667	756	2,423	19,129	1,567	20,696	5,068	1,032	6,101
    Of which:
    Proved developed reserves	1,188	334	1,523	13,378	283	13,661	3,566	385	3,951
    Proved reserves under PSA and buy-back agreements	0	441	441	0	1,169	1,169	0	649	649
    Production from PSA and buy-back agreements	0	47	47	0	56	56	0	57	57
    Revisions and improved recovery	197	16	214	598	(27)	571	311	14	325
    Extensions and discoveries	38	105	143	405	0	405	110	105	215
    Purchase of reserves-in-place	0	0	0	0	0	0	0	0	0
    Sales of reserves-in-place	0	0	0	0	0	0	0	0	0
    Production	(299)	(92)	(391)	(1,238)	(114)	(1,352)	(519)	(112)	(632)
    At 31 December 2007	1,604	785	2,389	18,893	1,426	20,319	4,971	1,039	6,010
    Of which:
    Proved developed reserves	1,187	323	1,510	15,084	748	15,832	3,875	456	4,331
    Proved reserves under PSA and buy-back agreements	0	387	387	0	977	977	0	561	561
    Production from PSA and buy-back agreements	0	67	67	0	80	80	0	82	82
    Revisions and improved recovery	81	95	177	7	141	148	83	120	203
    Extensions and discoveries	12	0	12	29	0	29	17	0	17
    Purchase of reserves-in-place	0	69	69	0	0	0	0	69	69
    Sales of reserves-in-place	0	(3)	(3)	0	(43)	(43)	0	(10)	(10)
    Transfer to associated company *	0	(191)	(191)	0	0	0	0	(191)	(191)
    Production	(302)	(78)	(380)	(1,348)	(121)	(1,469)	(542)	(100)	(642)
    At 31 December 2008	1,396	677	2,074	17,581	1,403	18,984	4,529	927	5,456
    Of which:
    Proved developed reserves	1,113	381	1,494	14,482	727	15,209	3,693	510	4,204
    Proved reserves under PSA and buy-back agreements	0	433	433	0	1,106	1,106	0	630	630
    Production from PSA and buy-back agreements	0	66	66	0	88	88	0	82	82

    	Net proved oil and NGL reserves in million barrels			Net proved gas reserves in billion standard cubic feet			Net proved oil, NGL and gas reserves in million barrels oil equivalent
    	Norway	Outside Norway	Total	Norway	Outside Norway	Total	Norway	Outside Norway	Total
    Reserves in associated companies
    Remaining reserves after transfer*	0	123	123	0	0	0	0	123	123
    Revisions and improved recovery	0	11	11	0	0	0	0	11	11
    Production	0	(6)	(6)	0	0	0	0	(6)	(6)
    At 31 December 2008	0	127	127	0	0	0	0	127	127
    Total Proved Reserves including reserves in associated companies at 31 December 2008	1,396	805	2,201	17,581	1,403	18,984	4,529	1,055	5,584
    Of which:
    Proved developed reserves	1,113	406	1,519	14,482	727	15,209	3,693	536	4,229
    *Sincor to Petrocedeño; reduction from 15% to 9.677% interest

    The transformation process of the Sincor joint venture in Venezuela, into the new mixed company Petrocedeño was finalised in February 2008 reducing StatoilHydro'sStatoil's shareholding interest from 15.0%15.0 % in the Sincor joint venture to 9.677%9.677 % in PetrocedeñPeterocedeño. The change in StatoilHydroStatoil share has resulted in a reduction of proved reserves corresponding to 68 million boe in 2008.

    StatoilHydroStatoil acquired Anadarco's 50.0 %50.0% share in Peregrino, Brazil, in 2008 resulting in a 100 %100% ownership of thisthe asset, and becoming the operator. The related increase in proved reserves was 69 million boe.

    The acquisition of a 32.5 % interest in the Chesapeake's Marcellus shale gas acreage in the Appalachia region of the northeastern USA was completed in November 2008. Few wells are currently in production and the nature of shale gas deposits limits the reserves that can currently be booked as proved. Proved gas reserves at year-end 2008 related to this ownership is immaterial compared to StatoilHydro's total proved reserves and hence not included.

    	Net proved oil and NGL reserves in million barrels
    	Norway	Eurasia excluding Norway	Africa	America	Total
    Reserves in consolidated companies
    At 31 December 2008	1,396	177	265	235	2,074
    Revisions and improved recovery	195	(22)	64	6	243
    Extensions and discoveries	39	6	44	45	134
    Purchase of reserves-in-place	0	0	0	0	0
    Sales of reserves-in-place	0	(4)	0	0	(4)
    Production	(279)	(19)	(63)	(15)	(376)
    At 31 December 2009	1,351	138	310	272	2,070
    Of which:
    Proved developed reserves	1,028	94	208	83	1,413
    Proved reserves under PSA and buy-back agreements	0	124	310	0	434
    Production from PSA and buy-back agreements	0	17	63	0	80
    Reserves in associated companies
    At 31 December 2008	0	0	0	127	127
    Revisions and improved recovery	0	0	0	(18)	(18)
    Extensions and discoveries	0	0	0	0	0
    Purchase of reserves-in-place	0	0	0	0	0
    Sales of reserves-in-place	0	0	0	0	0
    Production	0	0	0	(5)	(5)
    At 31 December 2009	0	0	0	105	105
    Total Proved Oil and NGL Reserves including reserves in associated companies at 31 December 2009	1,351	138	310	376	2,174
    Of which:
    Proved developed reserves	1,028	94	208	111	1,442

    	Net proved gas reserves in billion standard cubic feet
    	Norway	Eurasia excluding Norway	Africa	America	Total
    Reserves in consolidated companies
    At 31 December 2008	17,581	827	481	95	18,984
    Revisions and improved recovery	690	(31)	(89)	(9)	561
    Extensions and discoveries	35	0	0	87	122
    Purchase of reserves-in-place	0	0	0	0	0
    Sales of reserves-in-place	0	0	0	0	0
    Production	(1,367)	(49)	(54)	(48)	(1,519)
    At 31 December 2009	16,938	747	338	125	18,148
    Of which:
    Proved developed reserves	14,138	523	256	73	14,990
    Proved reserves under PSA and buy-back agreements	0	548	338	0	886
    Production from PSA and buy-back agreements	0	46	54	0	101
    Reserves in associated companies
    At 31 December 2008	0	0	0	0	0
    Revisions and improved recovery	0	0	0	0	0
    Extensions and discoveries	0	0	0	0	0
    Purchase of reserves-in-place	0	0	0	0	0
    Sales of reserves-in-place	0	0	0	0	0
    Production	0	0	0	0	0
    At 31 December 2009	0	0	0	0	0
    Total Proved Gas Reserves including reserves in associated companies at 31 December 2009	16,938	747	338	125	18,148
    Of which:
    Proved developed reserves	14,138	523	256	73	14,990

    	Net proved oil, NGL and gas reserves in million barrels oil equivalent
    	Norway	Eurasia excluding Norway	Africa	America	Total
    Reserves in consolidated companies
    At 31 December 2008	4,529	324	351	252	5,456
    Revisions and improved recovery	318	(28)	48	5	343
    Extensions and discoveries	45	6	44	60	155
    Purchase of reserves-in-place	0	0	0	0	0
    Sales of reserves-in-place	0	(4)	0	0	(4)
    Production	(523)	(28)	(73)	(24)	(647)
    At 31 December 2009	4,369	271	370	294	5,304
    Of which:
    Proved developed reserves	3,548	187	254	96	4,084
    Proved reserves under PSA and buy-back agreements	0	222	370	0	592
    Production from PSA and buy-back agreements	0	25	73	0	98
    Reserves in associated companies
    At 31 December 2008	0	0	0	127	127
    Revisions and improved recovery	0	0	0	(18)	(18)
    Extensions and discoveries	0	0	0	0	0
    Purchase of reserves-in-place	0	0	0	0	0
    Sales of reserves-in-place	0	0	0	0	0
    Production	0	0	0	(5)	(5)
    At 31 December 2009	0	0	0	105	105
    Total Proved Reserves including reserves in associated companies at 31 December 2009	4,369	271	370	398	5,408
    Of which:
    Proved developed reserves	3,548	187	254	124	4,113

    StatoilHydro is booking, as proved reserves, volumes equivalent to our tax liabilities payable in-kind under negotiated fiscal arrangements (production sharing agreements or income sharing agreements).

    The following table reflects the estimatedStatoil's proved reserves of extra heavy oil in Venezuela and gas at 31 December 2005 to 2008, andCanada are included as oil in the changes therein. tables above.

    	Net proved oil and NGL reserves in million barrels			Net proved gas reserves in billion standard cubic feet			Net proved oil, NGL and gas reserves in million barrels oil equivalent
    	Norway	Outside Norway	Total	Norway	Outside Norway	Total	Norway	Outside Norway	Total
    At December 31, 2005	1,835	779	2,614	19,595	1,392	20,986	5,316	1,025	6,341
    Of which:
    Proved developed reserves	1,363	295	1,659	13,899	208	14,107	3,833	332	4,165
    Proved reserves under PSA and buy-back agreements	-	433	433	-	973	973	-	606	606
    Production from PSA and buy-back agreements	-	46	46	-	83	83	-	61	61
    Revisions and improved recovery	122	37	159	529	250	780	219	81	300
    Extensions and discoveries	26	12	38	256	9	265	72	13	86
    Purchase of reserves-in-place	-	-	-	-	-	-	-	-	-
    Sales of reserves-in-place	-	(2)	(3)	-	-	-	-	(2)	(3)
    Production	(315)	(70)	(385)	(1,250)	(84)	(1,335)	(539)	(85)	(624)
    At December 31, 2006	1,667	756	2,423	19,129	1,567	20,696	5,068	1,032	6,101
    Of which:
    Proved developed reserves	1,188	334	1,523	13,378	283	13,661	3,566	385	3,951
    Proved reserves under PSA and buy-back agreements	-	441	441	-	1,169	1,169	-	649	649
    Production from PSA and buy-back agreements	-	47	47	-	56	56	-	57	57
    Revisions and improved recovery	197	16	214	598	(27)	571	311	14	325
    Extensions and discoveries	38	105	143	405	-	405	110	105	215
    Purchase of reserves-in-place	-	-	-	-	-	-	-	-	-
    Sales of reserves-in-place	-	-	-	-	-	-	-	-	-
    Production	(299)	(92)	(391)	(1,238)	(114)	(1,352)	(519)	(112)	(632)
    At December 31, 2007	1,604	785	2,389	18,893	1,426	20,319	4,971	1,039	6,010
    Of which:
    Proved developed reserves	1,187	323	1,510	15,084	748	15,832	3,875	456	4,331
    Proved reserves under PSA and buy-back agreements	-	387	387	-	977	977	-	561	561
    Production from PSA and buy-back agreements	-	67	67	-	80	80	-	82	82
    Revisions and improved recovery	81	95	177	7	141	148	83	120	203
    Extensions and discoveries	12	-	12	29	-	29	17	-	17
    Purchase of reserves-in-place	-	69	69	-	-	-	-	69	69
    Sales of reserves-in-place	-	(3)	(3)	-	(43)	(43)	-	(10)	(10)
    Transfer to affiliated company *	-	(191)	(191)	-	-	-	-	(191)	(191)
    Production	(302)	(78)	(380)	(1,348)	(121)	(1,469)	(542)	(100)	(642)
    At December 31, 2008	1,396	677	2,074	17,581	1,403	18,984	4,529	927	5,456
    Of which:
    Proved developed reserves	1,113	381	1,494	14,482	727	15,209	3,693	510	4,204
    Proved reserves under PSA and buy-back agreements	-	433	433	-	1,106	1,106	-	630	630
    Production from PSA and buy-back agreements	-	66	66	-	88	88	-	82	82
    Reserves in affiliates
    Remaining reserves after transfer*	-	123	123	-	-	-	-	123	123
    Revisions and improved recovery	-	11	11	-	-	-	-	11	11
    Production	-	(6)	(6)	-	-	-	-	(6)	(6)
    At December 31, 2008	-	127	127	-	-	-	-	127	127
    Total Proved Reserves including reserves in affiliates as of December 31, 2008	1,396	805	2,201	17,581	1,403	18,984	4,529	1,055	5,584
    Of which:
    Proved developed reserves	1,113	406	1,519	14,482	727	15,209	3,693	536	4,229
    *Sincor to Petrocedeño; reduction from 15% to 9.677% interest

    The conversion rates used are 1 standard cubic meter = 35.3 standard cubic feet, 1 standard cubic meter oil equivalent = 6.29 barrels of oil equivalent (boe) and 1,000 standard cubic meter gas = 1 standard cubic meter oil equivalent.

    Capitalised expenditures related to Oil and Gas producing activities
    	At 31 December
    (in NOK million)	2008	2007	2006
    Unproved properties	61,484	40,513	26,096
    Proved properties, wells, plants and other equipment	611,251	526,634	501,472
    Total capitalised expenditures	672,735	567,147	527,568
    Accumulated depreciation, depletion, amortisation and valuation allowances	(349,428)	(309,527)	(283,428)
    Net capitalised expenditures	323,307	257,620	244,140

    Capitalised cost related to Oil and Gas production activities

    Consolidated companies
    	At 31 December
    (in NOK million)	2009	2008	2007
    Unproved Properties	49,497	61,484	40,513
    Proved Properties, wells, plants and other equipment	655,886	611,251	526,634
    Total Capitalised cost	705,383	672,735	567,147
    Accumulated depreciation, depletion, amortisation and valuation allowances	(379,575)	(349,428)	(309,527)
    Net Capitalised cost	325,808	323,307	257,620

    Net capitalised expenditurescost related to affiliatesassociated companies as of 31 December 20082009 was NOK 3.7 billion, NOK 4.6 billion.billion in 2008 and 0 in 2007.

    Expenditures incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
    These expenditures include both amounts capitalised and expensed
    for 2009.

    Consolidated companies						Consolidated companies
    (in NOK million)	(in NOK million)		Norway	Outside Norway	Total	Norway	Eurasia excluding Norway	Africa	America	Total
    Year ended 31 December 2008
    Year ended 31 December 2009
    Exploration costs	Exploration costs		8,672	9,136	17,808	8,170	1,310	2,465	4,950	16,895
    Development costs 1), 2)			29,478	14,215	43,693
    Acquired proved properties 3)			-	12,435
    Acquired unproved properties 4)			1,255	12,323	13,578
    Total			39,405	48,109	87,514
    Year ended 31 December 2007
    Exploration costs			5,749	8,499	14,248
    Development costs 1), 2)			28,428	13,330	41,758
    Development costs 1)						30,704	3,611	10,627	11,958	56,900
    Acquired unproved properties	Acquired unproved properties		-	17,133		0		12	1,313	1,325
    Total			34,177	38,962	73,139	38,874	4,921	13,104	18,221	75,120
    Year ended 31 December 2006
    Exploration costs			4,649	9,484	14,133
    Development costs 1), 2)			27,303	14,009	41,312
    Acquired unproved properties			511	9,588	10,099
    Total			32,463	33,081	65,544

    Expenditures incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
    These expenditures include both amounts capitalised and expensed in 2008 and 2007
    (in NOK million)				Norway	Outside Norway	Total
    Year ended 31 December 2008
    Exploration costs				8,672	9,136	17,808
    Development costs 1)				29,478	14,215	43,693
    Acquired proved properties 2)				0	12,435	12,435
    Acquired unproved properties 3)				1,255	12,323	13,578
    Total				39,405	48,109	87,514
    Year ended 31 December 2007
    Exploration costs				5,749	8,499	14,248
    Development costs 1)				28,428	13,330	41,758
    Acquired unproved properties				0	17,133	17,133
    Total				34,177	38,962	73,139

    (1) Development costs include investments in Norway in facilities for liquefaction of natural gas and storage of LNG amounting to NOK 90 million in 2008, NOK 661 million in 2007 and NOK 112 million in 2006.
    (2) Includes minor development costs in unproved properties.
    (3)(2) Includes the acquisition of Anadarco's 50% share in Peregrino, Brazil.
    (4)(3) Includes signature bonuses and the acquisition of a share in Goliat and Marcellus shale gas development.

    Expenditures incurred in Oil and Gas Development Activities related to affiliatesassociated companies in 2009 was NOK 286 million, NOK 448 million in 2008 was NOK 448 million.and 0 in 2007.

    Results of Operation for Oil and Gas Producing Activities
    As required by FAS 69,Topic 932, the revenues and expenses included in the following table reflect only those relating to the oil and gas producing operations of StatoilHydro.Statoil.

    Activities included in StatoilHydro'sStatoil's segment disclosures in note 5 Segments to the financial statements but excluded from the table below relates to gas trading activities, commodity based derivatives, transportation, and business development as well as effects of disposals of oil and gas interests.

    Income tax expense is calculated on the basis of statutory tax rates in addition to uplift and tax credits only. No deductions are made for interest or overhead.

    (in NOK million)	Norway	Outside Norway	Total
    Year ended December 2008
    Sales	151	8,274	8,425
    Transfers	216,809	34,718	251,527
    Total revenues	216,960	42,992	259,952
    Exploration expense	(5,536)	(9,157)	(14,693)
    Production costs	(19,744)	(6,009)	(25,753)
    Depreciation, depletion and amortisation (DD&A)	(24,043)	(13,689)	(37,732)
    Total operating expenses	(49,323)	(28,855)	(78,178)
    Results of operations before tax	167,637	14,137	181,774
    Tax expense	(124,564)	(9,710)	(134,274)
    Result of operations	43,073	4,427	47,500
    Year ended December 2007
    Sales	36	13,064	13,100
    Transfers	173,238	27,705	200,943
    Total revenues	173,274	40,769	214,043
    Exploration expense	(3,638)	(7,695)	(11,333)
    Production costs	(22,793)	(7,132)	(29,925)
    DD&A	(23,030)	(11,103)	(34,133)
    Total operating expenses	(49,461)	(25,930)	(75,391)
    Results of operations before tax	123,813	14,839	138,651
    Tax expense	(92,058)	(4,327)	(96,385)
    Result of operations	31,754	10,512	42,266
    Year ended December 2006
    Sales	143	10,640	10,784
    Transfers	175,476	20,523	195,999
    Total revenues	175,619	31,163	206,783
    Exploration expense	(3,480)	(7,170)	(10,650)
    Production costs	(12,774)	(4,176)	(16,950)
    DD&A	(20,938)	(14,370)	(35,308)
    Total operating expenses	(37,192)	(25,716)	(62,908)
    Results of operations before tax	138,427	5,447	143,874
    Tax expense	(98,994)	(2,133)	(101,127)
    Result of operations	39,433	3,314	42,748

    Consolidated companies
    (in NOK million)	Norway	Eurasia excluding Norway	Africa	America	Total
    Year ended December 2009
    Sales	5	2,968	7,950	689	11,612
    Transfers	154,440	5,320	16,877	6,085	182,722
    Total revenues	154,445	8,288	24,827	6,774	194,334
    Exploration expenses	(5,187)	(1,047)	(2,238)	(8,218)	(16,690)
    Production costs	(19,395)	(1,440)	(3,432)	(1,768)	(26,035)
    Depreciation, amortisation and impairment losses	(25,566)	(2,464)	(9,721)	(4,902)	(42,653)
    Total costs	(50,148)	(4,951)	(15,391)	(14,888)	(85,378)
    Results of operations before tax	104,297	3,337	9,436	(8,114)	108,956
    Tax expense	(75,690)	(102)	(3,182)	1,684	(77,290)
    Result of operations	28,607	3,235	6,254	(6,430)	31,666

    (in NOK million)			Norway	Outside Norway	Total
    Year ended December 2008
    Sales			151	8,274	8,425
    Transfers			216,809	34,718	251,527
    Total revenues			216,960	42,992	259,952
    Exploration expense			(5,536)	(9,157)	(14,693)
    Production costs			(19,744)	(6,009)	(25,753)
    Depreciation, depletion and amortisation (DD&A)			(24,043)	(13,689)	(37,732)
    Total costs			(49,323)	(28,855)	(78,178)
    Results of operations before tax			167,637	14,137	181,774
    Tax expense			(124,564)	(9,710)	(134,274)
    Result of operations			43,073	4,427	47,500
    Year ended December 2007
    Sales			36	13,064	13,100
    Transfers			173,238	27,705	200,943
    Total revenues			173,274	40,769	214,043
    Exploration expense			(3,638)	(7,695)	(11,333)
    Production costs			(22,793)	(7,132)	(29,925)
    DD&A			(23,030)	(11,103)	(34,133)
    Total costs			(49,461)	(25,930)	(75,391)
    Results of operations before tax			123,813	14,839	138,651
    Tax expense			(92,058)	(4,327)	(96,385)
    Result of operations			31,754	10,512	42,266

    The results of operations for oil and gas producing activities of affiliatesequity method investees outside of Norway amounts to NOK 26 million in the year ended December 2009, NOK 428 million in the year ended December 2008.

    Corrections increasing2008 and NOK 0 in the results of operations for 2007 and 2006 by NOK 9.0 and 10.3 billion, respectively, were made to the previously reported figures.year ended December 2007.

    Standardised measure of discounted future net cash flows relating to proved oil and gas reserves
    The table below shows the standardised measure of future net cash flows relating to proved reserves presented.reserves. The analysis is computed in accordance with FAS 69,Topic 932, by applying average market prices for 2009 and year end market prices for 2008 and 2007 as defined by the SEC, year end costs, year end statutory tax rates, and a discount factor of 10% to year end quantities of net proved reserves. The standardised measure of discounted future net cash flows is a forward-looking statement.

    Future price changes are limited to those provided by contractual arrangements in existence at the end of each reporting year. Future development and production costs are those estimated future expenditures necessary to develop and produce year end estimated proved reserves based on year end cost indices, assuming continuation of year end economic conditions. FuturePre-tax future net cash flow pre-tax is net of decommissioning and removal costs. Estimated future income taxes are calculated by applying the appropriate year end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pretax net cash flows, less the tax basis of related assets. Discounted future net cash flows are calculated using a discount rate of 10% per year. Discounting requires a year-by-year estimate of when future expenditures will be incurred and when reserves will be produced. The information provided does not represent management's estimate of StatoilHydro's expected future c ash flows or value of proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as new information becomes available. Moreover, identified reserves and contingent resources that may become proved in the future, are excluded from the calculations. The standardised measure of discounted future net cash flows prescribed under FAS 69Topic 932 requires assumptionsassu mptions as to the timing and amount of future development and production costs and income from the production of proved reserves. ThisThe information does not reflectrepresent management's judgmentestimate or Statoil's expected future cash flows or the value of its proved reserves and therefore should not be relied upon as an indication of StatoilHydro'sStatoil's future cash flow or value of its proved reserves.

    (in NOK million)	Norway	Outside Norway	Total	Norway	Eurasia excluding Norway	Africa	America	Total
    At 31 December 2008
    At 31 December 2009
    Consolidated companies
    Future net cash inflows	1,738,693	204,808	1,943,501	1,387,084	66,055	113,642	90,548	1,657,329
    Future development costs	(109,456)	(44,920)	(154,376)	(118,505)	(12,362)	(22,047)	(12,095)	(165,009)
    Future production costs	(412,340)	(77,398)	(489,738)	(437,396)	(22,806)	(33,665)	(42,932)	(536,799)
    Future income tax expenses	(919,740)	(30,118)	(949,858)	(624,221)	(3,033)	(21,199)	(7,642)	(656,095)
    Future net cash flows	297,157	52,372	349,529	206,962	27,854	36,731	27,879	299,426
    10 % annual discount for estimated timing of cash flows	(150,919)	(15,019)	(165,938)	(94,462)	(11,806)	(11,479)	(7,537)	(125,284)
    Standardised measure of discounted future net cash flows	146,238	37,353	183,591	112,500	16,048	25,252	20,342	174,142
    Standardised measure of discounted future net cash flows related to affiliates	-	2,024
    Total Standardised measure of discounted future net cash flows including affiliates	146,238	39,377	185,615
    At 31 December 2007
    Future net cash inflows	1,788,440	429,335	2,217,775
    Future development costs	(107,966)	(57,332)	(165,298)
    Future production costs	(338,834)	(102,838)	(441,672)
    Future income tax expenses	(1,009,179)	(97,850)	(1,107,029)
    Future net cash flows	332,461	171,315	503,776
    10 % annual discount for estimated timing of cash flows	(135,717)	(67,289)	(203,006)
    Associated companies
    Standardised measure of discounted future net cash flows	196,744	104,026	300,770	0			2,097
    At 31 December 2006
    Future net cash inflows	1,643,982	310,129	1,954,111
    Future development costs	(113,121)	(36,496)	(149,617)
    Future production costs	(321,208)	(53,377)	(374,585)
    Future income tax expenses	(939,061)	(70,481)	(1,009,542)
    Future net cash flows	270,592	149,775	420,367
    10 % annual discount for estimated timing of cash flows	(116,469)	(58,184)	(174,653)
    Standardised measure of discounted future net cash flows	154,123	91,591	245,714
    Total Standardised measure of discounted future net cash flows including associated companies				112,500	16,048	25,252	22,439	176,239

    Of the NOK 154,376 million of expected future development costs as of 31 December 2008, NOK 92,010 million is expected to be expended within the next three years, as allocated in the table below.
    
    Future development cost

    (in NOK million)	2009	2010	2011	Total
    Norway	29,904	22,981	15,572	68,457
    Outside Norway	11,968	6,558	5,027	23,553
    Total	41,872	29,539	20,599	92,010
    Future development cost expected to be spent on proved undeveloped reserves	28,224	20,125	12,556	60,905

    (in NOK million)	Norway	Outside Norway	Total
    At 31 December 2008
    Consolidated companies
    Future net cash inflows	1,738,693	204,808	1,943,501
    Future development costs	(109,456)	(44,920)	(154,376)
    Future production costs	(412,340)	(77,398)	(489,738)
    Future income tax expenses	(919,740)	(30,118)	(949,858)
    Future net cash flows	297,157	52,372	349,529
    10 % annual discount for estimated timing of cash flows	(150,919)	(15,019)	(165,938)
    Standardised measure of discounted future net cash flows	146,238	37,353	183,591
    Associated companies
    Standardised measure of discounted future net cash flows	0	2,024	2,024
    Total standardised measure of discounted future net cash flows including associated companies	146,238	39,377	185,615
    At 31 December 2007
    Future net cash inflows	1,788,440	429,335	2,217,775
    Future development costs	(107,966)	(57,332)	(165,298)
    Future production costs	(338,834)	(102,838)	(441,672)
    Future income tax expenses	(1,009,179)	(97,850)	(1,107,029)
    Future net cash flows	332,461	171,315	503,776
    10 % annual discount for estimated timing of cash flows	(135,717)	(67,289)	(203,006)
    Standardised measure of discounted future net cash flows	196,744	104,026	300,770

    In 2008, StatoilHydro incurred NOK 56,128 million in development costs, of which NOK 36,955 million related to proved undeveloped reserves.

    Changes in the standardised measure of discounted future net cash flows from proved reserves

    (in NOK million)	2008	2007
    Standardised measure at beginning of year	300,770	245,714
    Net change in sales and transfer prices and in production (lifting) costs related to future production	(74,453)	239,091
    Changes in estimated future development costs	(56,924)	(30,740)
    Sales and transfers of oil and gas produced during the period, net of production cost	(234,199)	(189,992)
    Net change due to extensions, discoveries, and improved recovery	1,866	15,967
    Net change due to purchases and sales of minerals in place	(4,936)	-
    Net change due to revisions in quantity estimates	51,574	78,122
    Previously estimated development costs incurred during the period	56,128	41,758
    Accretion of discount	50,960	(54,374)
    Net change in income taxes	92,805	(44,776)
    Total change in the standardised measure during the year	(117,179)	55,056
    Standardised measure at end of year	183,591	300,770
    Change in the standardised measure related to affiliates	2,024
    Standardised measure at end of year including affiliates	185,615	300,770

    Operational statistics
    Productive oil and gas wells and developed and undeveloped acreage
    The following tables show the number of gross and net productive oil and gas wells and total gross and net developed and undeveloped oil and gas acreage in which StatoilHydro had interests at 31 December 2008.

    A "gross" value reflects wells or acreage in which StatoilHydro has interests (presented as 100%). The net value corresponds to the sum of whole or fractional working interest for StatoilHydro in gross wells or acreage.

    At 31 December 2008		Norway	Outside Norway	Total
    Number of productive oil and gas wells
    Oil wells	— gross	927	882	1,809
    	— net	368	130	498
    Gas wells	— gross	163	100	263
    	— net	72	33	105

    The total gross number of productive wells as of end 2008 includes 354 oil wells and 15 gas wells with multiple completions or wells with more than one branch.

    At 31 December 2008 (in thousands of acres)		Norway	Outside Norway	Total
    Developed and undeveloped oil and gas acreage
    Acreage developed	— gross	876	1,323	2,199
    	— net	328	405	733
    Acreage undeveloped	— gross	15,973	71,617	87,590
    	— net	8,099	35,231	43,330

    Remaining terms of leases and concessions are between one and 37 years.

    Net productive and dry oil and gas wells drilled
    The following tables show the net productive and dry exploratory and development oil and gas wells completed or abandoned by StatoilHydro in the past two years. Productive wells include wells in which hydrocarbons were found, and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing sufficient quantities to justify completion as an oil or gas well.

    	Norway	Outside Norway	Total
    Year 2008
    Net productive and dry exploratory wells drilled	26.1	12.1	38.2
    — Net dry exploratory wells drilled	7.2	5.8	13.0
    — Net productive exploratory wells drilled	18.9	6.3	25.2
    Net productive and dry development wells drilled	27.9	23.7	51.6
    — Net dry development wells drilled	0.5	0.0	0.5
    — Net productive development wells drilled	27.4	23.7	51.1
    Year 2007
    Net productive and dry exploratory wells drilled	13.2	14.0	27.1
    — Net dry exploratory wells drilled	4.5	5.9	10.4
    — Net productive exploratory wells drilled	8.7	8.0	16.7
    Net productive and dry development wells drilled	34.7	19.7	54.4
    — Net dry development wells drilled	0.7	1.0	1.7
    — Net productive development wells drilled	34.0	18.7	52.7
    Year 2006
    Net productive and dry exploratory wells drilled	11.1	15.1	26.2
    — Net dry exploratory wells drilled	6.4	7.3	13.7
    — Net productive exploratory wells drilled	4.7	7.8	12.5
    Net productive and dry development wells drilled	21.1	14.0	35.1
    — Net dry development wells drilled	0.8	-	0.8
    — Net productive development wells drilled	20.3	14.0	34.3

    Exploratory and development drilling in process
    The following table shows the number of exploratory and development oil and gas wells in the process of being drilled by StatoilHydro at December 31, 2008.

    At 31 December 2008		Norway	Outside Norway	Total
    Number of  wells in progress
    Developement Wells	— gross	32	47	79
    	— net	13.6	7.7	21.3
    Exploratory Wells	— gross	7	9	16
    	— net	4.3	2.9	7.2

    Average sales price and unit production cost

    	Norway	Outside Norway
    Year ended 31 December 2008
    Average sales price liquids in USD per bbl	91.5	88.7
    Average sales price natural gas in NOK per Sm3	2.4	1.3
    Average production costs, in NOK per boe	37.3	42.2
    Year ended 31 December 2007
    Average sales price liquids in USD per bbl	70.9	69.1
    Average sales price natural gas in NOK per Sm3	1.69	1.17
    Average production costs, in NOK per boe	46.3	34.4
    Year ended 31 December 2006
    Average sales price liquids in USD per bbl	63.6	60.9
    Average sales price natural gas in NOK per Sm3	1.94	1.64
    Average production costs, in NOK per boe	26.9	37.5

    (in NOK million)	2009	2008	2007
    Consolidated companies
    Standardised measure at beginning of year	183,591	300,770	245,714
    Net change in sales and transfer prices and in production (lifting) costs related to future production	(288,973)	(74,453)	239,091
    Changes in estimated future development costs	(48,980)	(56,924)	(30,740)
    Sales and transfers of oil and gas produced during the period, net of production cost	(179,072)	(234,199)	(189,992)
    Net change due to extensions, discoveries, and improved recovery	9,403	1,866	15,967
    Net change due to purchases and sales of minerals in place	(530)	(4,936)	0
    Net change due to revisions in quantity estimates	101,298	51,574	78,122
    Previously estimated development costs incurred during the period	56,900	56,128	41,758
    Accretion of discount	214,065	50,960	(54,374)
    Net change in income taxes	126,440	92,805	(44,776)
    Total change in the standardised measure during the year	(9,449)	(117,179)	55,056
    Standardised measure at end of year	174,142	183,591	300,770
    Associated companies
    Standardised measure at end of year	2,097	2,024	0
    Standardised measure at end of year including associated companies	176,239	185,615	300,770

     

     Top 

    8.2 Report of independent registered public accounting firms

     Top 

    8.2.1 Report of Ernst & Young AS on the financial statements of StatoilHydroStatoil ASA

    Report of Independent Registered Public Accounting Firm

    The Board of Directors and Shareholders of StatoilHydroStatoil ASA

    We have audited the accompanying consolidated balance sheets of StatoilHydroStatoil ASA and subsidiaries ("StatoilHydro") as of 31 December 2009, 2008 and 2007,1 January 2008, and the related consolidated statements of income, recognisedcomprehensive income, and expense,changes in equity and cash flows for each of the three years in the period ended 31 December 2008.2009. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the 2006 financial statements of Hydro Petroleum, a consolidated business (see note 31 to the consolidated financial statements), which statements reflect total revenue and net income of NOK 97,910 million and NOK 11,093, respectively, for the year ended 31 December 2006. Those statements were audited by other auditors whose report, which has been furnished to us, included an explanatory paragraph that refers to certain allocations that were required to prepare such financial statements. Ou r opinion, as of 31 December 2006, insofar as it relates to the amounts included for Hydro Petroleum, is based solely on the report of the other auditors.

    We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and, for 2006, the report of other auditors provide a reasonable basis for our opinion.

    In our opinion, based upon our audits and, for 2006, the report of the other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of StatoilHydroStatoil ASA at 31 December 2009, 2008 and 2007,1 January 2008, and the consolidated results of their operations and their cash flows for each of the three years in the period ended 31 December 2008,2009, in conformity with International Financial Reporting Standards as issued by the International Accounting Standards Board and International Financial Reporting Standards as adopted by the European Union.

    As discussed in Note 8.1.2, Significant changes in accounting policies, to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

    We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), StatoilHydro'sStatoil ASA's internal control over financial reporting as of 31 December 2008,2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated 17 March 20092010 expressed an unqualified opinion thereon.

    Ernst & Young AS
    Stavanger, Norway
    17 March 2009
    except for Note 33, as to which the date is
    24 March 20092010

     Top 

    8.2.2 Report of Ernst & Young AS on StatoilHydro'sStatoil's internal control over financial reporting

    Report of Independent Registered Public Accounting Firm

    The Board of Directors and Shareholders of StatoilHydroStatoil ASA

    We have audited StatoilHydroStatoil ASA's ("StatoilHydro"Statoil") internal control over financial reporting as of 31 December 2008,2009, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("the COSO criteria"). StatoilHydro'sStatoil's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's report on internal control of financial reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

    We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

    A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

    Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

    In our opinion, StatoilHydroStatoil maintained, in all material respects, effective internal control over financial reporting as of 31 December 2008,2009, based on the COSO criteria.

    We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of StatoilHydroStatoil ASA and subsidiaries as of 31 December 31,2009, 2008 and 2007,1 January 2008, and the related consolidated statements of income, recognisedcomprehensive income, and expense,changes in equity and cash flows for each of the three years in the period ended 31 December 31, 20082009 and our report dated 17 March 20092010 expressed an unqualified opinion thereon.

    Ernst & Young AS

    Stavanger, Norway
    17 March 2009
    except for Note 33, as to which the date is
    24 March 2009

    2010

     Top 

    8.2.3 Report of Deloitte AS on the carve-out financial statements of Hydro Petroleum

    REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

    To the Board of Directors and shareholders of Norsk Hydro ASA

    We have audited the carve-out combined statements of income, statements of comprehensive income, and cash flows of Hydro Petroleum for the year ended 31 December 2006 (not presented separately herein). These carve-out combined financial statements are the responsibility of Norsk Hydro ASA's management. Our responsibility is to express an opinion on these carve-out combined financial statements based on our audit.

    We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Hydro Petroleum is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Hydro Petroleum's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating t he overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

    In our opinion, such carve-out combined financial statements present fairly, in all material respects, the results of its operations and its cash flows of Hydro Petroleum for the year ended 31 December 2006, in conformity with accounting principles generally accepted in the United States of America.

    As discussed in Note 1, the 2006 financial statements have been restated.

    As discussed in Note 1 to the financial statements, the carve-out combined financial statements also include certain allocations from Norsk Hydro ASA. These allocations may not be reflective of the actual level of costs or debt which would have been incurred had Hydro Petroleum operated as a separate entity apart from Norsk Hydro ASA. Hydro Petroleum also changed its method of accounting for the recognition of over/under funded status of retirement plans in 2006 to conform to newly adopted accounting principles.

    As discussed in Note 27 to the financial statements, International Financial Reporting Standards as published by the International Accounting Standards Board vary in certain significant respects from accounting principles generally accepted in the United States of America. Information relating to the nature and effect of such differences is presented in Note 27 to the carve-out combined financial statements.

    Deloitte AS

    Oslo, Norway

    29 March 2007 (08 May 2007 as to the effects of the restatement discussed in Note 1 and 21 February 2008 for Note 27)

    9 Terms and definitions

    Organisational abbreviations:

    An overview of organisational abbreviations.

    • ACG - Azeri-Chirag-Gunashli
    • ACQ - Annual Contract Quantity
    • APA - Awards in Predefined Areas
    • AFP - Agreement-based Early Retirement Plan
    • AnLNG - Angola LNG
    • BTC - Pipeline Baku-Tbilisi-Ceyhan
    • BTL - Biomass-to-liquids Process
    • CCS - Carbon Capture and Storage
    • CHP - Combined heat and power plant
    • CO2 - Carbon Dioxide
    • E&P - Exploration & Production
    • EEA - European Economic Agreement
    • EFTA - European Free Trade Association
    • EGR - Exhaust Gas Recirculation
    • EMTN - Euro Medium Term Note
    • EPN - Exploration & Production Norway Business Area
    • EPSA - Exploration Production Sharing Agreement
    • FCC - Fluid Catalytic Cracking
    • FPSO - Floating Production Storage Offloading
    • FDP - Field Development Plan
    • GBS - Gravity-Based Structure
    • GDP - Gross Domestic Product
    • GEP - Gas Export Project
    • GoM - Gulf of Mexico
    • GTL - Gas to Liquids
    • HSE - Health, Safety, Environment
    • HTHP - High-temperature/high pressure
    • IASB - International Accounting Standards Board
    • IEA - International Energy Agency
    • IFRS - International Financial Reporting Standards
    • INT - International Exploration & Production business area
    • IO - Integrated Operations
    • IOR - Increased Oil Recovery
    • ISG - In Salah Gas
    • KEP2010 - KarstøKårstø Upgrading Project
    • LNG - Liquefied Natural Gas
    • LPG - Liquefied Petroleum Gas
    • M&M - Manufacturing and Marketing business area
    • MPE - Norwegian Ministry of Petroleum and Energy
    • NAOSC - North American Oil Sands Corporation
    • NCS - Norwegian Continental Shelf
    • NG - Natural Gas Business Area
    • NGO - Non Governmental Organization
    • NIOC - National Iranian Oil Company
    • NOC - National Oil Companies
    • NOK - Norwegian Kroner
    • NOx- Nitrogen Oxide
    • NSAB - Norwegian Standard Accounting Board
    • OECD - Organisation of Economic Co-Operation and Development
    • OTC - Over the Counter
    • OTS - Oil Trading and Supply Department
    • PBO - Project Benefit Obligation
    • PDO - Plan for Development and Operation
    • PRO - Projects Functional Area
    • PSA - Production Sharing Agreement
    • R&D - Research and Development
    • ROACE - Return on Average Capital Employed
    • RSS - Rotary Steerable System
    • SAGD - Steam Assisted Gravity Drainage
    • SCP - South Caucasus Pipeline System
    • SDFI - Norwegian State's Direct Financial Interest
    • SORIE - Statement of Recognised Income and Expense
    • TAP - Trans Adriatic Pipeline
    • TNE - Technology & New energy Functional Area
    • TSP - Technical Service Provider
    • UKCS - UK Continental Shelf
    • USD - United States Dollar
    • ÅTS - Åsgard Transport System

    Metric abbreviations etc:

    • bbl - barrel
    • mbbl - thousand barrels
    • mmbbl - million barrels
    • boe - barrels-of-oil equivalent
    • mboe - thousand barrels-of-oil equivalent
    • mmboe - million barrels-of-oil equivalent
    • mmcf - million cubic feet
    • bcf - billion cubic feet
    • tcf - trillion cubic feet
    • scm - standard cubic metre
    • mcm - thousand cubic metres
    • mmcm - million cubic metres
    • bcm - billion cubic metres
    • mmtpa - million tonnes per annum
    • km - kilometre
    • ppm - part per million
    • one billion - one thousand million

    Equivalent measurements are based upon:

    • 1 barrel equals 0.134 tonnes of oil (33 degrees API)
    • 1 barrel equals 42 US gallons
    • 1 barrel equals 0.159 standard cubic metres
    • 1 barrel of oil equivalent equals 1 barrel of crude oil
    • 1 barrel of oil equivalent equals 159 standard cubic metres of natural gas
    • 1 barrel of oil equivalent equals 5,612 cubic feet of natural gas
    • 1 barrel of oil equivalent equals 0.0837 tonnes of NGLs
    • 1 billion standard cubic metres of natural gas equals 1 million standard cubic metres of oil equivalent
    • 1 cubic metre equals 35.3 cubic feet
    • 1 kilometre equals 0.62 miles
    • 1 square kilometre equals 0.39 square miles
    • 1 square kilometre equals 247.105 acres
    • 1 cubic metre of natural gas equals one standard cubic metre of natural gas
    • 1000 standard cubic metres of natural gas equals 6.29 boe
    • 1 standard cubic foot equals 0.0283 standard cubic metres
    • 1 standard cubic foot equals 1000 British thermal units (btu)
    • 1 tonne of NGLs equals 1.9 standard cubic metres of oil equivalents
    • 1 degree Celsius equals minus 32 plus five-ninths of the number of degrees Fahrenheit

    Miscellaneous terms:

    • Biofuel: A solid, liquid or gaseous fuel derived from relatively recently dead biological material and is distinguished from fossil fuels, which are derived from long dead biological material.
    • BOE: Barrels of oil-equivalent A measure to quantify crude oil, natural gas liquids and natural gas amounts using the same basis. Natural gas volumes are converted to barrels on the basis of energy content.
    • Carbon footprint: Total set of greenhouse gas emissions caused directly and indirectly by an individual, organization, event or product.
    • Condensates: The heavier natural gas components, such as pentane, hexane, iceptane and so forth, which are liquid under atmospheric pressure - also called natural gasoline or naphtha
    • Crude oil, or oil: Includes condensate and natural gas liquids
    • Development: The drilling, construction, and related activities following discovery that are necessary to begin production of crude oil and natural gas fields.
    • Downstream: The selling and distribution of products derived from upstream activties.
    • Equity and entitlement volumes of oil and gas: Equity volumes represent volumes produced under a Production Sharing Agreement (PSA) that correspond to StatoilHydro'sStatoil's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent StatoilHydro'sStatoil's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes such as those in Norway, the UK, Canada and Brazil. The overview of equity production provides additional information for readers, as certain costs described in the profit and loss analysis were directly associated with equity vol umesvolumes produced during the reported years.
    • FCC: Fluid catalytic cracking A process used to convert the high-boiling hydrocarbon fractions of petroleum crude oils to more valuable gasoline, gases and other products.
    • GTL: Gas to liquids, means the technology used for chemical conversion of natural gas into transportable liquids (diesel and naphtha) and specialty products (base oils).
    • Heavy Oil: Crude oil with high viscosity (typically above 10 cp), and high specific gravity. The API classifies heavy oil as crudes with a gravity below 22.3° API. In addition to high viscosity and high specific gravity, heavy oils typically have low hydrogen-to-carbon ratios, high asphaltene, sulfur, nitrogen, and heavy-metal content, as well as higher acid numbers.
    • High Grade: Relates to selectively harvesting goods, to cut the best and leave the rest. In reference to exploration and production this entails strict prioritizationprioritisation and sequencing of drilling targets.
    • Hydro: A reference to the oil and energy activities of Norsk Hydro ASA which merged with Statoil ASA to form StatoilHydro.ASA.
    • IOR: Increased oil recovery is used about actual measures resulting in an increased oil recovery factor fromjfrom a reservoir as compared with the expected value at a certain reference point in time. IOR comprises both of conventional and emerging technologies.
    • Liquids: Refers to oil, condensates and NGL.
    • LNG: Liquefied Natural Gas,lean gas - primarily methane - converted to liquid form through refrigeration to minus 163 degrees Celsius under atmospheric pressure. pressures
    • LPG: Liquefied petroleum gas and consists primarily of propane and butane, which turn liquid under a pressure of six to seven atmospheres. LPG is shipped in special vessels.
    • Midstream: Processing, storage, and transport of crude oil, natrualnatural gas, natural gas liquids and sulphur.
    • Naphtha is an inflammable oil obtained by the dry distillation of petroleum
    • Natural gas: Petroleum that consists principally of light hydrocarbons. It can be divided into 1) lean gas, primarily methane but often containing some ethane and smaller quantities of heavier hydrocarbons (also called sales gas) and 2) wet gas, primarily ethane, propane and butane as well as smaller amounts of heavier hydrocarbons; partially liquid under atmospheric pressure
    • NGL: Natural gas liquids, light hydrocarbons mainly consisting of ethane, propane and butane which are liquid under pressure at normal temperature
    • Oil sands: A naturally occurring mixture of bitumen, water, sand, and clay. A heavy viscous form of crude oil.
    • Petroleum: A collective term for hydrocarbons, whether solid, liquid or gaseous. Hydrocarbons are compounds formed from the elements hydrogen (H) and carbon (C). The proportion of different compounds, from methane and ethane up to the heaviest components, in a petroleum find varies from discovery to discovery. If a reservoir primarily contains light hydrocarbons, it is described as a gas field. If heavier hydrocarbons predominate, it is described as an oil field. An oil field may feature free gas above the oil and contain a quantity of light hydrocarbons, also called associated gas.
    • Proved reserves: Proved reserves are those reserves claimed to have a reasonable certainty (normally at least 90% confidence) of being recoverable under existing economic and political conditions, and using existing technology. They are the only type the U.S. Securities and Exchange Commission allows oil companies to report.
    • Share turnover: Turnover of shares is a measure of stock liquidity calculated by dividing the total number of shares traded over a period by the average number of shares outstanding for the period. The higher the share turnover, the more liquid the share of the company.
    • Syncrude: The output from bitumen extra heavy oil upgrader facility used in connection with oil sand production.
    • Upstream: Includes the searching for potential underground or underwater oil and gas firleds,fields, drilling of exploratory wells, subsequent operating wells which bring the liquids and or natural gas to the surface.
    • VOC: IncludesVolatile Organic Compounds, are organic chemical compounds that have high enough vapor pressures under normal conditions to significantly vaporise and enter the searching for potential underground or underwater oilearth's atmosphere, e.g. gasses formed under loading and gas firleds, drillingoffloading of exploratory wells, subsequent operating wells which bring the liquids and or natural gas to the surface.crude oil.
    • Økokrim: Prosecution of Economic and Environmental Crime in Norway
     Top 

    10 Forward looking statements

    This Annual Report on Form 20-F contains certain forward-looking statements that involve risks and uncertainties, in particular in the sections "Business overview" and "Operational review". In some cases, we use words such as "aim", "anticipate", "believe", "continue", "estimate", "expect", "goal", "intend", "likely", "may", "objective", "plan", "seek", "should", "target", "will" and similar expressions to identify forward-looking statements. All statements other than statements of historical fact, including, among others, statements regardingsuch as those regarding: goals and objectives relating to employees, recruitment of employees and employee compensation; future ability to identify, develop and apply existing and new technologies; efficiency and productivity goals for future operations and projects; our future response to climate c hange; environmental objectives; our future financial position; our future market position; business strategy; projected impact of economic downturn;expected changes in ownership interests and structures; restructuring plans; competitive position; expectationsbudgets; expected project development expenditures; plans for future development (including redevelopment) and operation of the synergies produced by our recent acquisitions, such as our interest in the Marcellus shale gas development and Peregrino field; budgets;projects; reserve information; reserve replacement rates; reserve recovery factors; future ability to utilise and develop our expertise; projected levels of capacity; anticipated growth in geographical areas and market segments; oil and gas production forecasts; anticipated areas of market growth and decline; production growth; oil, gasfuture composition of our exploration and alternative fuel prices; oil, gas and alternative fuel supply and demand; renewable energy industry outlook; projected operating costs;project portfolios; exploration expenditure; estimates of capital expenditure; expected exploration and development activities and plans; expected costs of decommissioning and removal activities; impact of facility maintenance activities; our ability to create value; planned turnarounds; expected unit production cost for equity volumes; expectations , objectives and plans for the employee pension plans; expected refining margins; expected start-up dates for upstreamprojects and downstream activities;expected production and capacity of projects; projected impact of laws and regulations (including taxation laws and HSE regulations;regulations); HSE goals and objectives of management for future operations; plans for share repurchases; plans for payment of dividends and amounts of dividendsdividends; plans for marketing our products; expectations of the synergies produced by our recent acquisitions and our merger with Hydro; the impact of the uncertain world economy; expected capital expenditures; our expected ability to obtain short term and long term financing; our ability to manage our risk exposure; the projected levels of risk exposure with respect to financial counterparties; our ability to lower our funding costs; the expected impact of USD/NOK exchange rate fluctuations on our financial position; oil, gas and alternative fuel price levels and volatility; oil, gas and alternative fuel supply and dema nd; the markets for oil, gas and alternative fuel; renewable energy industry outlook; alternate fuel market outlook; projected operating costs; expected useful and economic lives of assets; the completion of acquisitions; obtaining licenses; obtaining licenses in the future; and the obtaining of regulatory and contractual approvals, are forward-looking statements. You should not place undue reliance on these forwardlookingforward-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 "Risk review", and in "Operational review", and elsewhere in this Annual Report on Form 20-F.

    These forward-looking statements reflect current views aboutwith 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; interest rates; trading activities; the 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; changes in laws and governmental regulations; the lack of necessary transportation infrastructure when a field is in a remote location; the timing of bringing new fields on stream; material differences from reserves estimates;est imates; an inability to find and develop reserves; adverse changes in tax regimes; the development and use of new technolog y;technology; geological or technical difficulties; operational problems; security breaches; the actions of competitors; our ability to successfully exploit growth opportunities; the actions of field partners; industrial actions by workers; failing to attract and retain senior management and skilled personnel; failing to meet our ethical and social standards; natural disasters and adverse weather conditions 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 make them conform to actual results or changes in our expectations.

     Top 

    11 Signature page

    The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this Annual Report on its behalf.

    	STATOILHYDROStatoil ASA (Registrant)
    	By:/s/  Eldar Sætre
    	Name: Title:	Eldar Sætre Chief Financial Officer
    Dated: 2426 March, 20092010

     

     Top 

    12 Exhibits

    The following exhibits are filed as part of this Annual Report:

    Exhibit no	Description
    Exhibit 1	Articles of Association of StatoilHydroStatoil ASA, as amended, effective from 2 November 2009. (English translation) (incorporated by reference to Exhibit 1 to Statoil's Annual Report and Form 20-F/A for the fiscal year ended December 31, 2006 File No. 1-15200.)
    Exhibit 4(a)(i)	Technical Services Agreement between Gassco AS and Statoil ASA, dated February 27, 2002 (incorporated by reference to Exhibit 44(a)(i) to Statoil'sStatoil’s Annual Report and Form 20-F for the fiscal year ended December 31, 2001 File(File No. 1-15200.1-15200)).
    Exhibit 4(b)	Merger Plan (included as Appendix A to the circular/prospectus contained in Amendment No. 3 to the Registration Statement on Form F-4/AF-4 filed on May 22, 2007 File(File No. 333-141445.333-141445)).
    Exhibit 4(c)(i)	Employment agreement with Helge Lund (English translation) (incorporated by reference to Exhibit 4(c) to Statoil'sStatoil’s Annual Report and Form 20-F for the fiscal year ended December 31, 2003 (File No. 1-15200.1-15200)).
    Exhibit 7	Calculation of ratio of earnings to fixed charges.
    Exhibit 8	Subsidiaries (see Section 3.7.83.7.4 “Organisational Structure” included in this Annual Report).
    Exhibit 12.1	Rule 13a-14(a) Certification of Chief Executive Officer.
    Exhibit 12.2	Rule 13a-14(a) Certification of Chief Financial Officer.
    Exhibit 13.1	Rule 13a-14(b) Certification of Chief Executive Officer.*
    Exhibit 13.2	Rule 13a-14(b) Certification of Chief Financial Officer.*
    Exhibit 15(a)(i)	Consent of Ernst & Young AS.
    Exhibit 15(a)(ii)	Consent of Deloitte AS relating to the financial statements of Hydro Petroleum.DeGolyer and MacNaughton.
    Exhibit 15(a)(iii)	ConsentReport of DeGolyer and MacNaughton.

    * Furnished only

    
    The total amount of long-term securities of the Registrant and its subsidiaries authorized under any one instrument does not exceed 10% of the total assets of StatoilHydroStatoil ASA and its subsidiaries on a consolidated basis. The company agrees to furnish copies of any or all such instruments to the Securities and Exchange Commission upon request.

     Top 

    13 Cross reference to Form 20-F

    PageSections Item 1. Identity of Directors, Senior Management and AdvisorsAdvisers n/aN/A Item 22. Offer Statistics and Expected Timetable n/aN/A Item 3. Key Information     A.   Selected financial dataFinancial Data 2; 170-1711.2;  1.4;  4.1.2; 6;  6.1;  6.8   B.   Capitalization and indebtednessIndebtedness n/aN/A   C.   Reasons for the offerOffer and useUse of proceedsProceeds n/aN/A   D.   Risk factorsFactors 145-1525.1 Item 44. Information on the Company     A.   History and developmentDevelopment of the Company 5-9; 32-35; 110; 112; 114; 118; 121; 124; 134-1362.1;  2.2;  3.1-3.6;  3.1.5;  3.2.1;  4.1.6;  4.2.5;  8.1.4   B.   Business overviewOverview 10-87; 93-102; 112-114; 124-1262;  3;  4.1.3;  4.1.4   C.   Organizational structureStructure 872.1;  3.7.4   Appendix A to Item 4DProperty, Plants and Equipment 30-32; 46-49; 90-91; 267-2773.1- 3.5;  3.8;  3.12   D.   Property, plantsOil and equipmentGas Disclosures 27-83; 101-1022; 3;  8.1.2;  8.1.35;  Exhibit 15(a)(iii) Item 4A. Unresolved Staff Comments None Item 5. Operating and Financial Review and Prospects     A.   Operating resultsResults 93-101; 103-128; 137; 152; 1553.10;  4.1;  4.2.8;  5.1.1;  5.1.2;  5.1.3;  5.2.1   B.   Liquidity and capital resourcesCapital Resources 128-136; 140-1444.2.1;  4.2.3;  4.2.5;  5.2.1;  5.2.2;  8.1.22;  8.1.26;  8.1.30;  8.1.31   C.   Research and development, patentPatents and licensesLicenses, etc. 76-773.5;  8.1.9   D.   Trend informationInformation 11-14; 26; 32-39; 59-60; 68; 76; 80; 112; 117-118; 120-121; 123-124; 126-1272.4;  2.5.2;  2.6.2;  2.7.2;  2.8.2;  2.9.2;  2.10.2;  3.1.5;  3.2.2;  3.2.5;  3.3.1;  3.3.2;  3.5;  3.11;  4.1.3;  4.1.5.2;  4.1.6.2;  4.1.7.2;  4.1.8.2;  4.2;  5.1;  5.2;  5.3;  8.1.28   E.   Off-balance sheet arrangementsOff-Balance Sheet Arrangements 134-135; 140; 241-2444.2.4;  4.2.6;  8.1.28   F.    Tabular disclosureDisclosure of contractual commitmentsContractual Obligations 134-1354.2.4   G.   Safe harbourHarbor 28410 Item 6. Directors, Senior Management and Employees     A.   Directors and senior managementSenior Management 175-179; 182-1857.6;  7.8   B.   Compensation 187-1897.9   C.   Board practicesPractices 175-180; 182-185;7.5;  7.6;  7.8   D.   Employees 84-863.7   E.   Share ownershipOwnership 174-175; 1897.5;  7.10 Item 7. Major Shareholders and Related Party Transactions     A.   Major shareholdersShareholders 163-1656.4   B.   Related party transactionsParty Transactions 1023.13;  7.6   C.   Interests of expertsExperts and counselCounsel n/aN/A Item 8. Financial Information     A.   Consolidated financial statementsStatements and other financial information Other Financial Information 114; 158; 160-161; 191-2805.3;  6.1;  8   B.   Significant changesChanges 2568.1.33;  8.1.35 Item 9. The Offer and Listing     A.   Offer and listing detailsListing Details 166-1676.5   B.   Plan of distributionDistribution n/aN/A   C.   Markets 9; 163; 165-1666;  7.7   D.   Selling shareholdersShareholders n/aN/A   E.   Dilution n/aN/A   F.    Expenses of the issueIssue n/aN/A Item 10. Additional Information     A.   Share capitalCapital n/aN/A Memorandum and Articles of Association 6.1;  6.4;  7.2;  7.3;  7.10;  8.1.21 Material Contracts 4.2.7 Exchange Controls 6.7 Taxation 3.10.5;  6.6;  8.1.2 Dividends and Paying Agents N/A Statements by Experts N/A Documents On Display 1.3 Subsidiary Information N/A Item 11. Quantitative and Qualitative Disclosures About Market Risk 5;  8.1.6;  8.1.7;  8.1.30;  8.1.31 Item 12. Description of Securities Other than Equity Securities A.        Debt Securities N/A   B.        MemorandumWarrants and articles of associationRights 172-174N/A   C.        Material contractsOther Securities 102; 137N/A   D.        Exchange controlsAmerican Depositary Shares 1706.5.2  E.   Taxation 167-170 F.    Dividends and paying agents n/a G.   Statements by experts n/a H.   Documents on display 4 I.    Subsidiary information n/a Item 11. Quantitative and Qualitative Disclosures about Market Risk 152-158; 245-254 Item 12 Description of securities other than equity securities n/a Item 13. Defaults, Dividend Arrearages and Delinquencies None Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds None Item 15. Controls and Procedures 1907.12;  8.2.2 Item 16A. Audit Committee Financial Expert 1807.6.1.1 Item 16B. Code of Ethics 1727.1 Item 16C. Principal Accountant Fees and Services 186-1877.11 Item 16D. Exemptions from the Listing Standards for Audit Committees 1807.7 Item 16E. Purchases of Equity Securities by the Issuer and Affiliated Purchases 161-1626.1.1;  6.2 Item 16G16F. Changes in Registrant’s Certifying Accountant N/A Item 16G. Corporate governance practicesGovernance 171-1727.7 Item 17. Financial Statements n/aN/A Item 18. Financial Statements 191-2808 Item 19. Exhibits Exhibit Index12