Commission File No. 1-15200
Statoil 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)
Torgrim Reitan
Chief Financial Officer
Statoil 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          3,188,647,103

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

If this report is 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.

Note – Checking the box above will not relieve any registrant required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 from their obligations under those Sections.

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or 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.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).**

**This requirement does not apply to the registrant in respect of this filing.

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

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 __

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

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).

Annual report on Form 20-F 2011

Table of content

1 Introduction

1.1 Key figures

This section presents our performance in the following important areas: Income, cash flow, return, proved reserves, oil production and price, gas production and price, serious incidents, total recordable injuries and carbon dioxide emissions.

1.2 About the report

Statoil's Annual Report on Form 20-F for the year ended 31 December 2011 ("Annual Report on Form 20-F") is available online at www.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, Statoil 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.

Statoil discloses on its website at http://www.statoil.com/en/about/corporategovernance/statementofcorporategovernance/pages/default.aspx, and in its Annual Report on Form 20-F (Item 16G) 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.

1.3 Financial highlights

In 2011, Statoil delivered record net operating income. The value-creating Peregrino, Leismer and Gassled transactions, combined with strong oil and gas prices throughout the year, contributed to the strong financial results.

In 2011, production volumes were in line with expectations. Production start-up of new fields and ramp-up of production on existing fields combined with strong oil and gas prices enabled Statoil to deliver strong financial results and cash flows.

Statoil publishes financial data in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU).

1.4 A glance at 2011

Statoil delivered strong financial results and cash flows in 2011 as a result of production in line with expectations and high gas and liquids prices. We presented a technology-focused upstream strategy, we further streamlined the portfolio through divestments and acquisitions, and we delivered historic exploration results.

January
Effective from 1 January 2011, we have reported our business through the following reporting segments: Development and Production Norway; Development and Production International; Marketing, Processing and Renewable Energy; Fuel & Retail; Other.

We were awarded interests in 11 production licenses on the NCS, and will be operator for eight of these licenses. One of the operatorships is in the Barents Sea, one in the Norwegian Sea and six are in the North Sea.

In Angola, the national oil company Sonangol announced that Statoil had been selected for operatorship and participation in several offshore pre-salt blocks.

We announced first oil production from the Leismer Demonstration Project in Canada. Statoil's oil sands leases are located in north east Alberta.

February
Statoil's internal investigation into the gas leakage on the Gullfaks B platform in the North Sea on 4 December 2010 was concluded and the report presented to the Petroleum Safety Authority Norway.

March
Statoil and ExxonMobil agreed to explore three Faroese offshore licenses jointly.

The Norwegian government decided to gather more facts relevant to a possible future impact assessment for Lofoten and Vesterålen. At the same time the government decided not to carry out an impact assessment for the duration of the current Norwegian parliament.

The Vega field in the North Sea and the Tyrihans subsea field in the Norwegian Sea were officially opened. The fields are expected to make important contributions to our production on the NCS.

At a ceremony in Bangkok, Statoil signed a Memorandum of Understanding (MoU) with PTT Exploration and Production of Thailand. Under the MoU, the companies will seek to cooperate in the areas of conventional and unconventional resources and liquefied natural gas (LNG) in a global setting.

In the Statfjord A operating plans, Statoil assumed that production shutdown may take place in 2014. Therefore we outlined a draft program for an impact analysis of platform removal, including a description of plans for cessation and decommissioning.

Statoil received the investigation report from the Petroleum Safety Authority Norway on the Gullfaks B gas leak on 4 December 2010. Statoil published its own investigation of the incident in February.

Two new fast-track development projects were launched on the NCS, namely Gamma/Harepus and Snorre B template.

Statoil and KazMunayGas signed a Heads of Agreement (HoA) on the Abay block in the Kazakhstani sector of the Caspian Sea. Under the HoA, the parties will conduct an evaluation of the hydrocarbon potential of the Abay block.

April
Statoil, along with partners Eni Norway and Petoro, made a significant oil discovery on the Skrugard prospect in the Barents Sea. The discovery was one of the most important finds on the NCS of the decade, and opened a new oil province that could provide additional resource growth.

We started oil production on the Peregrino field offshore Brazil. This marked a safe and efficient start-up of Statoil's largest international operatorship to date.

A new oil find was made by Statoil immediately adjacent to the Peregrino field in the Campos Basin offshore Brazil.

May
Statoil released its inaugural 2010 Canadian Oil Sands Report Card, containing performance indicators for the Leismer Demonstration Project (LDP) and surrounding Kai Kos Dehseh leases in northern Alberta and our actions to improve environmental performance as the leases are developed.

Statoil farmed in to three offshore exploration licenses in Indonesia, significantly expanding our presence in the country.

Statoil and Petrobras signed a letter of intent to expand the cooperation between the companies in respect of exploration, and to assess how the two companies can benefit from operational synergies.

Statoil's first fast-track-project - Visund South - moved ahead as planned. The seabed template commenced its journey out to the field located south of Gullfaks in the North Sea.

Statoil and Sintef, an independent research organisation in Scandinavia, signed a new and comprehensive research framework agreement.

June
Statoil decided to divest a 24.1% direct and indirect stake in the Gassled natural gas transportation infrastructure joint venture for a consideration of NOK 17.35 billion. Following this transaction, Statoil will continue to own 5.0% in the joint venture.

The plan for development and operation of the Valemon gas and condensate field in the North Sea was approved by the Norwegian parliament. Production start-up is expected in 2014.

Statoil celebrated its 10th anniversary as a listed company. We presented a technology-focused upstream strategy.

Statoil signed two agreements for the sale of the major part of Statoil's onshore wind power activities in Norway, enabling the group to focus more of its efforts on offshore wind projects.

July
Statoil and Gassnova invited suppliers to take part in a technology qualification program for full-scale carbon capture at Mongstad.

Statoil awarded the contract for construction of two new drilling rigs specifically designed for use on mature fields on the NCS.

August
The steel support structure for the Gudrun platform came into place on the North Sea field, completing the first phase of the extensive installation work carried out there.

Statoil and partners Petoro AS, Det norske oljeselskap ASA and Lundin Norway AS made a significant oil discovery on the Aldous Major South prospect (PL 265) in the North Sea. Communication between the Aldous and Avaldsnes (PL 501) oil discoveries in the North Sea was confirmed, indicating that this is one field.

September
Statoil and its partners in the Troll license decided to invest NOK 11 billion in two new compressors on Troll A. The compressors would enable the production of gas from the field at commercial volumes until 2063.

Lundin Norway AS, as operator for license PL501 located in the North Sea, announced increased estimated recoverable resources within the Avaldsnes discovery in production license PL501. Statoil confirmed a significant upside potential and that it would continue to collect and analyze data before concluding on updated estimates.

October
Statoil called off the search for a 48-year-old man reported missing on the Visund platform in the North Sea on Thursday 6 October. An extensive search of the seabed around the platform had been unsuccessful.

Statoil and Brigham Exploration Company announced that they had entered into a merger agreement for Statoil to acquire all of the outstanding shares of Brigham through an all-cash tender offer. The total equity value was approximately USD 4.4 billion. The US unconventional plays hold a substantial resource base and represent an increasingly important part of future energy supplies.

Statoil, together with partners Petoro AS, Det norske oljeselskap ASA and Lundin Norway AS, confirmed significant additional volumes in its appraisal well in the Aldous Major South discovery (PL265) in the North Sea.

November
Statoil signed an agreement to acquire Hess's 3.26% ownership in the Barents Sea Snøhvit Unit and adjacent production licenses.

Statoil, Chevron Canada and Repsol E&P Canada were named successful bidders for exploration rights on two land parcels in the Flemish Pass Basin, offshore Newfoundland and Labrador, Canada.

Statoil raised a total of USD 1.75 billion of debt in the capital markets. The transactions are expected to increase the financial flexibility of the company.

Statoil acquired a 30% participating interest from Tullow Oil in block 47 offshore Suriname.

Statoil decided to farm down three and exit five assets on the NCS for a total consideration of USD 1.625 billion. The buyer is Centrica, a UK based energy company and an established NCS player.

Statoil and Centrica entered into a long term gas sales agreement for the delivery of 5 billion cubic meters (bcm) per year from 2015 to 2025 to the UK market.

Statoil was awarded the operatorship and a substantial working interest in a large offshore exploration license in eastern Indonesia.

December
Statoil and Brigham Exploration Company announced that more than 92.2 percent of the outstanding shares of Brigham's common stock had been tendered to Statoil (excluding shares purchased by Statoil from Brigham). Statoil has since effected a short-form merger under Delaware law.

Statoil increased its sponsorship of the FIRST® (For Inspiration and Recognition of Science and Technology) LEGO League, involving the building of LEGO-based robots by young students. As part of the group's Heroes of Tomorrow sponsorship programme, the agreement represents the group's first global sponsorship agreement.

Statoil announced broad efforts to identify the direct and underlying causes of the Gullfaks C well control event on 19 May 2010. This was in response to post-incident orders from the Petroleum Safety Authority Norway.

2 Business overview and strategy

2.1 Our business

Statoil is an integrated energy company that is primarily engaged in oil and gas exploration and production activities. Statoil's headquarters are in Norway, and the company has business operations in 41 countries and territories.

Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of the Norwegian act relating to public limited liability companies (the Norwegian Public Limited Companies Act). Statoil is the leading operator on the Norwegian continental shelf (NCS). It is also expanding its international activities.

Entitlement oil and gas production outside Norway accounted for 19.6% of our total production, which averaged 1,650 mmboe per day in 2011.

As of 31 December 2011, we had proved reserves of 2,276 mmbbl of oil and 3,150 bcm (equivalent to 17,681 tcf) of natural gas, corresponding to aggregate proved reserves of 5,426 mmboe.

We have business operations in 41 countries and territories. As of 31 December 2011, there were 31,715 employees in the Statoil group. Of this total, 10,385 were employees of the Statoil Fuel & Retail group, in which we held a 54% majority ownership interest as of 31 December 2011.

We are 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 also have substantial processing and refining operations. We are contributing to the development of new energy resources, have ongoing activities in the areas of offshore wind and biofuels, and are at the forefront of the implementation of technology for carbon capture and storage (CCS).

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

Business address
Our business address is Forusbeen 50, N-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Our largest locations in terms of the number of employees are in Stavanger, Bergen and Oslo, Norway.

The Statoil group, the main business areas and staff functions are presented in the following sections of this report.

The figure below provides an overview of the countries and territories in which Statoil has business operations.

2.2 Our history

Statoil was formed in 1972 by a decision of the Norwegian Storting (parliament). It was listed on the stock exchanges in Oslo and New York in 2001.

Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap AS on 18 September 1972. As a company wholly owned by the Norwegian State, Statoil'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 it changed its name to Statoil ASA. On 1 October 2007, the oil and gas division of Norsk Hydro ASA was merged with Statoil, and the company was given the temporary name of StatoilHydro. On 1 November 2009, the company changed its name back to Statoil.

We have grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, our operations primarily focused on exploration for and the production and development of oil and gas on the Norwegian continental shelf (NCS) as a partner.

In the 1970s, we commenced our own operations, made important discoveries and began oil refining operations, which have been of great importance to the further development of the NCS.

We grew substantially in the 1980s through the development of large fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). We also became a major player in the European gas market by securing large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, we were involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations.

The 1990s were characterised by substantial improvements in the production performance of our large fields. This was the result of intense technological development on the NCS. We laid the foundation for future improvements by becoming a leading company in the fields of floating production facilities and subsea development. The company grew strongly, expanded in new product markets and increased its commitment to international exploration and production.

Since 2000, our business has grown as a result of substantial investments on the NCS and internationally. Our ability to fully realise the potential of the NCS was strengthened through the merger with Hydro's oil and gas division, which also bolstered our global competitiveness.

In recent years, we have utilised our expertise to design and manage operations in various environments in order to grow our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects.

In October 2010, we successfully carried out an initial public offering (IPO) of Statoil Fuel & Retail ASA on the Oslo stock exchange (Oslo Børs), partially divesting and reducing our interest in the business relating to service stations.

2011 was a very significant year for Statoil. It started with the implementation of a new organisational model and reporting segments. Throughout the year, we delivered strong financial results and cash flows as a result of strong production in line with expectations and high gas and liquids prices. We delivered historic exploration results, particularly through the Skrugard prospect in the Barents Sea the Johan Sverdrup discovery in the North Sea and the Peregrino South discovery in Brazil. We also started oil production on the large Peregrino field off the coast of Brazil - Statoil's largest international operatorship to date.

We further streamlined our portfolio in 2011. On the divestment side, Statoil decided to divest a 24.1% direct and indirect stake in the Gassled natural gas transportation infrastructure joint venture, and entered into an agreement to farm down three and exit five assets on the NCS. On the acquisition side, Statoil and Brigham Exploration Company announced an agreement for Statoil to acquire all of the outstanding shares in Brigham. The transaction was completed in 2011.

The US unconventional plays constitute a substantial resource base and represent an increasingly important part of future energy supplies. Statoil has progressively developed industrial capabilities through early entrance into the Marcellus and Eagle Ford shale plays. Entering the Bakken and Three Forks tight oil plays and taking on operatorship is a significant new step for Statoil. We aim to position ourselves as a leading player in the fast-growing US onshore oil and gas industry.

Although petroleum-related activities on the NCS and internationally have accounted for the bulk of our business, we are increasingly participating in projects that focus on other forms of energy - such as offshore wind and carbon capture and storage (CCS) - in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.

2.3 Our competitive position

Information about Statoil's competitive position relies on a range of sources, including analyst reports, independent market studies and our internal assessments of our market share.

The information about Statoil's competitive position in the business overview and strategy, and operational review sections is based on a number of sources - including investment analyst 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.

We have endeavoured to be accurate in our presentation of information based on other sources, but have not independently verified such information.

2.4 Organisational structure

A new corporate structure was implemented with effect from 1 January 2011. The changes were made in order to simplify the organisation, enhance value creation and clarify internal accountability.

The figure below illustrates the new corporate structure:

Development and Production Norway (DPN)
DPN comprises our upstream activities on the Norwegian continental shelf (NCS). DPN aims to continue its leading role and ensure maximum value creation on the NCS. Through excellent HSE and improved operational performance and cost, DPN strives to maintain and strengthen Statoil's position as a world-leading operator of producing offshore fields. DPN seeks to open new acreage and to mature improved oil recovery and exploration prospects. New and existing fields are primarily developed using an industrial approach, where speed of delivery and cost improvements through standardisation and repeated use of proven solutions are key elements.

Development and Production International (DPI)
DPI comprises our worldwide upstream activities that are not included in the DPN and DPNA business areas. DPI's ambition is to build a large and profitable international production portfolio covering activities ranging from accessing new opportunities to delivering on existing projects and managing a production portfolio. DPI endeavours to ensure the delivery of profitable projects in a range of complex technical and stakeholder environments, and it manages a broad non-operated production portfolio that will be complemented with operated positions.

Development and Production North America (DPNA)
DPNA comprises our upstream activities in North America. DPNA's ambition is to develop a material and profitable position in North America, including the deepwater regions of the Gulf of Mexico and unconventional oil and gas and oil sands in the USA and Canada. In doing this, we aim to further strengthen our capabilities in deep water, unconventional gas operations and carbon-efficient oil sands extraction.

Marketing, Processing and Renewable Energy (MPR)
MPR comprises our marketing and trading of oil products and natural gas; transportation, processing and manufacturing; the development of oil and gas value chains; and renewable energy. MPR's ambition is to maximise value creation in Statoil's midstream, marketing and renewable energy business.

Technology, Projects and Drilling (TPD)
TPD's ambition is to provide safe, efficient and cost-competitive global well and project delivery, technology excellence and R&D. Cost-competitive procurement is an important contributory factor, although group-wide procurement services are also expected to help to drive down costs in the group.

Exploration (EXP)
EXP's ambition is to position Statoil as one of the leading global exploration companies. This is achieved through accessing high potential new acreage in priority basins, globally prioritising and drilling more significant wells in growth and frontier basins, delivering near-field exploration on the NCS and other select areas, and achieving step-change improvements in performance.

Global Strategy and Business Development (GSB)
GSB sets the corporate strategy, business development, and merger and acquisition activities (M&A) for Statoil. The ambition of the new GSB business area is to closely link corporate strategy, business development and M&A activities to actively drive Statoil's corporate development.

Reporting segments
After implementing the new corporate structure 1 January 2011, Statoil has reported its business in five reporting segments: Development and Production Norway (DPN); Development and Production International (DPI), which combines the DPI and DPNA business areas; Marketing, Processing and Renewable Energy (MPR); Fuel & Retail (SFR); and Other. See note 4 Segments, to the consolidated financial statements for additional information.

Activities relating to the Exploration business area are allocated to and presented in the respective development and production segments.

The Other reporting segment includes activities in TPD, GSB, Corporate Staffs and Services, and activities related to the CFO.

After the successful listing on the Oslo Stock Exchange in October 2010, Statoil's remaining ownership share in the listed company Statoil Fuel & Retail ASA, is 54%. SFR is fully consolidated in Statoil's financial statements, and is reported as seperate reporting segment followed up by the CFO area. SFR is a leading road transportation fuel retailer that is present in eight countries in Scandinavia, and Central and Eastern Europe. SFR is also involved in the sale of stationary energy, marine fuel, aviation fuel, lubricants and chemicals. As of December 2011, SFR had a network of 2,305 service stations in its eight countries of operations. Statoil Fuel & Retail ASA also markets refined products directly to consumer and industrial markets.

2.5 Strategy

Statoil's vision is "Crossing Energy Frontiers". It guides our long-term strategy as an upstream-oriented and technology-based energy company.

At the heart of our strategy is a strong focus on operations and HSE. We operate in an industry that is becoming increasingly complex. Access to and competition for resources is becoming more challenging. The pace of change will continue to increase in the future and the importance of quality in execution will be even higher - making safe and efficient operations more important than ever.

2.5.1 Our business environment

While the current global economic situation is fragile, non-OECD economies are still growing at an impressive rate. This factor should play a large role in keeping global energy demand high in the future.

Since the 2008 financial crisis, OECD countries have struggled to stage a stable and sustained recovery. Key economies are hampered by high sovereign debt and large deficits. Households and businesses remain very cautious, and a rebalancing of public and private balance sheets in the OECD will take time. Non-OECD economies, on the other hand, have remained relatively robust, growing at about three times the pace of the OECD average.

Global oil demand climbed slightly in 2011 as growth in non-OECD markets offset the decline in the OECD markets. In spite of muted demand, prices hovered around USD 110/bbl for much of 2011, in contrast to the period 2008-2009, when demand contraction led prices to fall to below USD 40/bbl. The ramp-up in prices as demand rebounded in 2010 reflected growing concern about future capacity additions, which, along with actual supply-side shocks, continued to play a role in maintaining high prices in 2011.

In gas markets, 2011 was marked by a 9% increase in LNG imports to Asia in the wake of the Fukushima tragedy. This increase contrasted with stagnant North American and declining European demand. The recovery in gas demand following the 2008-2009 recession heralded a new paradigm in pricing as continued aggressive development of unconventional gas in North America broke the link between Henry Hub and UK National Balancing Point (NBP) and Asian LNG prices. Henry Hub was below USD 4/MMBtu for much of 2011, whereas the UK NBP price was closer to USD 10/MMBtu, and Asian LNG prices were even higher, reflecting the willingness of buyers there to pay an energy security premium.

Given OECD weakness and non-OECD robustness, Statoil expects the world economy to grow by 3.1% annually over the coming 10 years, with an OECD annual average of 2.1% and a non-OECD annual average of 5.4%. This anticipated economic development pattern means increasing economic gravitation towards the East, at the expense of the West.

Solid non-OECD growth is expected to support energy demand over the next 10 years. In the period from 2011 to 2020, internal Statoil research suggests that growth in oil demand will average 1.0% (~0.8 mbpd) annually and will - along with continued concern about upstream capacity - support oil prices close to the levels seen recently. Statoil expects non-OPEC capacity to rise by only 0.3-0.4 mbpd per year on average going forward, which means increased demand for OPEC liquids and reduced OPEC spare capacity.

Statoil's internal research suggests that gas demand in Europe and North America will increase by 1-2% per year in the period up to 2020, while Asian demand will grow at around 5% per year in the same period. Both Europe and Asia will rely more on imported LNG to meet demand, which will probably result in upward pressure on prices. This contrasts with the situation in North America, where continued development of shale gas is expected to maintain downward pressure on prices in the short to medium term.

The current global economic situation is fragile, and the actual development path could be either more subdued or more buoyant than currently anticipated. As a result, energy prices could vary considerably in the short to medium term.

Production to reserve growth remains a key challenge for international oil companies, as it has been over the last five to ten years. We believe Statoil's compound average growth rate in the last decade (2.7%) is highly competitive. Access to new resources has been made more difficult as a result of increasing competition and tighter fiscal conditions in many resource-holding countries. Corporate responses to this situation have been varying mixes of moves into unconventional assets such as shale gas, increased focus on exploration, and the rationalisation of asset portfolios to strengthen balance sheets and reposition for growth.

Going forward, the decline of legacy fields and the increasingly technically challenging nature of new field developments are expected to put upward pressure on capital and operational expenditures. Together with depressed equity markets and tightening credit, this will put a strain on the liquidity of many industry players in the years ahead and may trigger industry restructuring.

2.5.2 Our corporate strategy

Statoil aims to grow and enhance value through its technology-focused upstream strategy, supplemented by selective positions in the midstream and in low-carbon technologies.

Statoil made sound strategic progress in 2011. First, a major reorganisation was implemented at the beginning of the year, then an updated strategy was presented to investors in June.

Statoil's immediate priorities remain to conduct safe, reliable operations with zero harm to people and the environment, and to deliver production growth.

To succeed going forward we are focusing strategically on the following:

• Revitalising Statoil's legacy position on the NCS
• Building offshore clusters
• Developing into a leading exploration company
• Stepping up our activity in unconventional resources
• Creating value from a superior gas position
• Continuing portfolio management to enhance value creation
• Utilising oil and gas expertise and technology to open new renewable energy opportunities.

Revitalising Statoil's legacy position on the NCS
The NCS remains a prolific and productive oil and gas province where only half of the resources have been produced. The Skrugard discovery in the spring of 2011 and Havis discovery in early 2012 have increased expectations of the exploration potential of the Barents Sea. Furthermore, the Aldous/Avaldsnes discoveries have stimulated efforts to make additional new large discoveries in the more mature North Sea. Between now and 2020, Statoil aims to bring on stream new production from a combination of developments of smaller discoveries, increased oil recovery (IOR) projects and the development of larger discoveries.

Current plans put the number of IOR projects at approximately 100. Future oil price expectations will extend the economic lifetime of most of the major fields, and thereby reduce the time criticality of many of the IOR projects. This will allow for greater flexibility in determining the optimal timing of these projects.

A number of larger field developments are currently in the project pipeline. They include the Luva, Dagny, Skrugard and Aldous/Avaldsnes fields, which are expected to contribute considerably to Statoil's total production over the period 2016-2020.

Of the approximately 40 smaller field development projects identified on the NCS, Statoil currently has nine projects in its fast-track development portfolio. Plans for development and operation have already been submitted for five of them (Skuld, Hyme, Stjerne, Vigdis North-East and Visund South) and two more (Visund North and Vilje South) have received licence approval. Fast-track developments are expected to contribute approximately 100,000 barrels of oil equivalent per day (boepd) by 2014.

Building offshore clusters
Statoil's international oil and gas production has increased from 100,000 to 500,000 boepd over the last decade. The company has established a presence in 41 countries and built a strong international portfolio of assets.

These countries include some of the most attractive basins in the industry - such as the USA (Gulf of Mexico [GoM] and onshore), Brazil, Angola and Azerbaijan (Caspian). Based on its efforts over the last 15-20 years, Statoil is now in a position to build at least three to five offshore clusters in select areas over the next eight to ten years.

Offshore clusters are areas that make a material contribution to total production, where Statoil is the operator and has a mix of assets in different stages of development, and where we possess considerable expertise, both below and above ground. Through the cluster focus, our goal is to achieve greater economies of scale, capture synergies and thereby increase profitability.

The first oil from the Peregrino field in Brazil was produced in 2011. We continue to work on ramping up Peregrino production, and, in the time ahead, we will focus on further developing the Peregrino area and maturing the existing exploration portfolio.

In Angola, we are working to optimise the non-operated portfolio, and to explore the significant pre-salt acreage we were awarded in 2011 (18,400 square kilometres). This is an exciting new play with parallels to the Brazilian pre-salt acreage.

In the GoM, Statoil was one of the first oil companies to be issued a permit to resume drilling after the Macondo incident. Here, besides managing our non-operated production, we are stepping up our efforts to mature, high grade and drill the best prospects in our drilling programme, and we continue to focus on developing improved subsurface capabilities in order to increase recovery rates.

Developing into a leading exploration company
2011 has been a good year for exploration for Statoil. In fact, the company made the single biggest oil discovery worldwide in 2011 (Johan Sverdrup in the North Sea).

To replicate this success we aim to balance the strengthening of our exploration portfolio in offshore clusters (North Sea, Angola, Brazil, the Caspian and the GoM) with frontier exploration and more high-impact wells to unlock new plays (e.g. the Norwegian Sea, Barents Sea and other Arctic areas, Tanzania and Indonesia).

More specifically, we will focus on:

• A select set of basins - including frontier regions
• Drilling more significant wells
• Securing access to exploration acreage early and at scale and low cost through innovation and new ways of cooperation
• Reducing drilling costs

Stepping up our activity in unconventional resources
The Brigham acquisition in the fourth quarter of 2011 is the most recent example of our ambition to step up our position in North American unconventional resources. Building on our Alberta, Canada Kai Kos Deh Seh oil sands project - where we announced the first oil production at the Leismer Demonstration Project in January 2011 and reached one million barrels of accumulated oil production in June 2011 - our unconventional resources portfolio is now diverse, and it also includes leases in the shale gas and oil basins of Marcellus, Eagle Ford and Bakken across the USA.

Our priorities in unconventional resources include:

• Delivering on production plans
• Developing and executing a technology roadmap for unconventional resources
• Filling in our current upstream positions
• Further building for the long term through early access to land.

By 2020, we anticipate that North American production of unconventional resources will contribute in excess of 12% of Statoil's total oil and gas production.

Creating value from a superior gas position
Compared to our peers, the proximity of our reserves, the flexibility of our production and transportation systems and our commercial experience in gas sales and trading puts us in a unique position in relation to the European gas market. In the short term, we are making considerable efforts to maximise the value of our gas in this market.

In the medium to long term, our strategic thinking is directed towards the continued promotion of gas as an important part of meeting European objectives for energy security and emission reductions. Statoil has a pan-European perspective that includes North Africa (Algeria), the Caspian and LNG options, in addition to gas from the NCS. We strongly believe that natural gas is the most cost-effective bridge to a low-carbon economy.

Beyond Europe, Statoil's planned midstream gas and liquids activities in North America are progressing in step with the building of our upstream unconventional resources business. These activities encompass a mix of capacity commitments, ownership and/or operation of gathering, transportation and storage facilities, marketing alliances and trading operations. They are considered important in terms of both flow assurance and margin capture.

Continuing portfolio management to enhance value creation
By being proactive, we intend to further enhance our portfolio in the years ahead so that it will ultimately be more valuable, more robust and more sustainable beyond 2020. The strategic focus in these endeavours will be to access exploration acreage and unconventional reserves, secure operatorships, build cluster positions, manage asset maturity, de-risk positions and demonstrate the intrinsic value of the portfolio.

The transactions signed and/or closed in 2011 (the Gassled farm-down, Brigham acquisition, Snøhvit farm-up, Valemon/Hild swap, the acquisition of Marcellus and Eagle Ford in-fill acreage and the NCS asset package sale to Centrica) further underpin our ability to redeploy capital and create value.

Utilising oil and gas expertise and technology to open new renewable energy opportunities
Climate change and growing demand for clean energy are creating new renewable and low-carbon technology business opportunities. Our core capabilities and expertise put us in a position to seize these opportunities in two specific areas: offshore wind, and carbon capture and storage (CCS).

Our first priority in offshore wind will be to complete the Sheringham Shoal development in the UK. Beyond Sheringham Shoal, our aim is to utilise the experience gained to develop new projects. In addition, work also continues on developing the proprietary Hywind floating offshore wind concept. Whether at Sheringham Shoal or through Hywind, our overall ambition is to play an active role in reducing costs in order to make offshore wind profitable on a stand-alone basis.

CCS represents a key technology for reducing carbon emissions. We have become a world leader in the development and application of CCS, and we intend to build on our carbon storage experience (Sleipner, In Salah and Snøhvit projects) to position ourselves for a future commercial CCS business. We are maturing two carbon capture projects at present - the large-scale Technology Centre Mongstad testing facility and the full-scale Carbon Capture Mongstad plant.

2.5.3 Our technology

We continually develop and deploy innovative technologies to achieve safe and efficient operations, and deliver on our strategic objectives. We have also defined four business-critical aspirations that we will strive to achieve over the next decade.

We believe that technology is a critical success factor in the business environment within which we operate. This environment is characterised by an increasingly broad and complex opportunity set, stricter demands on our licence to operate and tougher competition. In this context, technology is increasingly important for resource access, value creation and growth.

Our track record has demonstrated our ability to overcome significant technical challenges through the development and deployment of innovative technologies. At present, we are an industry leader in subsurface production and multiphase pipeline transportation.

Statoil's technology strategy is based on three main principles:

• Prioritising business-critical technologies
• Strengthening our licence to operate
• Expanding our capabilities

Prioritising business-critical technologies
Four business-critical technology aspirations need to be met in order to deliver on our strategic objectives for 2020:

• We need to be an industry leader in seismic imaging and interpretation based on proprietary technology in order to increase our discovery rates.
• We need to achieve breakthrough performance on reservoir characterisation and recovery to maximise value.
• We need a step change in well construction efficiency to drill more cost-effective wells.
• We need to develop and operate "longer, deeper and colder" subsea technologies in order to increase production and recovery. Large-scale subsea compression and complete subsea production factories are the goal by 2015 and 2020, respectively.

Strengthening our licence to operate
To secure our licence to operate, we must continuously focus on technologies for safe, reliable and efficient operations, as well as supporting integrity management. We are committed to developing and implementing energy-efficient and environmentally sustainable solutions.

Expanding our capabilities
Succeeding in a highly competitive environment will require more than just a strong focus and heavy investments. It will require the ability to build on competitive advantages, stimulate innovation and take a long-term view on selected potentially high-impact technology ventures. To do this, we will:

• Specify asset-specific requirement and execution plans to introduce new solutions
• Provide incentives for and reward those ventures that solve complex technical problems through innovative solutions, particularly when combined with prudent risk management
• Continuously adapt our collaborative way of working with partners and suppliers on a global basis.

3 Operational review

Statoil's operational review follows the segments resulting from the new corporate structure implemented on 1 January 2011. However, certain disclosures about oil and gas reserves are based on geographical areas, as required by the SEC.

The new corporate structure is presented in the section Organisational structure.

In this chapter, the operations of each reporting segment are presented. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. However, the Exploration operating segment's activities, which include group discoveries and the appraisal of new exploration resources, are presented as part of the various development and production reporting segments (Development and Production Norway and Development and Production International).

The operating segments TPD and GSB are included in the reporting segment Other.

As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based upon geographical area. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa and the Americas.

For further information about disclosures concerning oil and gas reserves and certain other supplementary disclosures based upon geographical area as required by the SEC, see the sections Operational review - Production volumes and price information and Operational review - Proved oil and gas reserves.

3.1 Development and Production Norway (DPN)

3.1.1 Introduction to DPN

Development and Production Norway (DPN) consists of our field development and operational activities on the Norwegian continental shelf (NCS).

Development and Production Norway is the operator of 44 developed fields on the NCS. Statoil's equity and entitlement production on the NCS was 1.316 mmboe per day in 2011, which was about 71% of Statoil's total production. Acting as operator, DPN is responsible for approximately 72% of all oil and gas production on the NCS. In 2011, our average daily production of oil and natural gas liquids (NGL) on the NCS was 693 mboe, while our average daily gas production on the NCS was 99.1 mmcm (3.5 bcf).

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 227 licences on the NCS and are operator for 171 of them.

As of 31 December 2011, Statoil had a total of 1,369 mmbbl of proved oil reserves and 444 bcm (15.7 tcf) of proved natural gas reserves on the NCS.

3.1.2 DPN key events in 2011

Activity levels in Development and Production Norway were high in 2011 with several new projects sanctioned - including eight fast-track projects.

• Total entitlement liquids and gas production in 2011 amounted to 1,316 mmboe per day
• An extensive turnaround programme was completed in 2011

Final investment decisions were made for the following projects:

• Ormen Lange northern field development*
• Stjerne
• Vigdis North-East
• Hyme
• Åsgard subsea compression
• Njord low pressure production
• Snorre A drilling upgrade
• Veslefrikk rig upgrade
• Troll 3rd & 4th compressor
• Skuld
• Vilje South
• Sleipner TKK
• Visund Nord
• Svalin M
• Hild*

* Partner-operated assets

3.1.3 The NCS portfolio

Our NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.

We are extending production from existing fields through improved reservoir management and increased oil recovery (IOR) projects. We also operate a significant number of exploration licences.

3.1.3.1 Core production areas

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 South, Operations North Sea West, Operations North Sea East and Operations North. The Operations South and Operations North Sea West and East clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea, while partner-operated fields cover the entire NCS and are included internally in the Operations South business cluster.

When possible, the fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities. This reduces the investments 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.

3.1.3.2 Portfolio management

Statoil takes an active approach to portfolio management on the NCS. By continuously managing our portfolio, we create value by optimising our positions in core areas and new growth areas in accordance with our strategies and targets

The highlights from 2011 are as follows:

• Statoil has further optimised its portfolio on the Norwegian continental shelf (NCS) by strengthening its position in growth areas through acquiring an additional interest in Snøhvit. In parallel, the company has high-graded parts of its portfolio by divesting interests and exiting certain less strategic fields.
• Statoil farmed down in three fields (Kvitebjørn, Heimdal, Valemon) and exited five (Skirne-Byggve, Fulla, Frigg-Gamma-Delta, Vale and Rind). These divestments are principally carried out through a transaction with Centrica that is expected to be closed in the second quarter 2012.

For further details regarding the above-mentioned transactions see the section - Global Strategy and Business Developement (GSB) - GSB key events in 2011- below.

3.1.4 Exploration on the NCS

2011 was one of the best exploration years ever for Statoil on the NCS.

We made two Statoil-operated important oil discoveries during the year - the Aldous discovery (PL265) in the North Sea and the Skrugard discovery (PL532) in the Barents Sea. The number of exploration wells increased from 17 exploration wells and four exploration extensions completed in 2010 to 25 exploration wells and four exploration extensions of production wells completed in 2011. This increase is mainly due to the maturation of targets based on new knowledge gained from the extensive 2008 and 2009 drilling campaigns and new acreage awarded in the Norwegian government's 20th concession round.

The 2011 portfolio has been well-balanced and split between infrastructure-led exploration (ILX) and growth/frontier wells (higher volume potential). Eighteen of the 25 wells were wildcats drilled to test new prospects, and 15 of the wildcats were operated by us. Eleven of the 15 Statoil-operated wildcat wells were discoveries, while the three partner-operated wildcat wells were dry.

The Aldous Major South discovery in PL265 on the Utsira Height in the Sleipner area is situated 140 kilometres west of Stavanger and 35 kilometres south of the Grane field. The discovery was made in sandstone from the Jurassic age in a reservoir of very high quality. The licence was awarded to Statoil as operator in 2001. The partners are Petoro, Det norske and Lundin. Five wells have been drilled in the licence, four of which have encountered hydrocarbons. All the wells have contributed valuable information and understanding of the geological history of the area. The PL265 partnership will consider further exploration drilling to clarify the potential and optimal development solution.

The Avaldsnes discovery was made in PL501 in 2010, with Lundin as operator and Statoil and Mærsk as partners. Avaldsnes and Aldous are connected, and it is important going forward to gain a good understanding of the reservoir distribution between the two licences.
The new name for the Aldous/ Avaldsnes development is Johan Sverdrup, and Statoil is aiming for a rapid development with the ambition of starting production in 2017.

The Skrugard discovery is located about 250 kilometres off the coast from the Melkøya LNG plant in Hammerfest. The well proved to have excellent reservoir parameters, and the volume discovered is large enough for a new stand-alone development in the Barents Sea. One new wildcat well in this licence was spudded in late 2011 on the Havis prospect, with a discovery in early 2012. Following that, an appraisal well on the Skrugard discovery is being drilled after the Havis well in Q1 2012.

In addition to the Johan Sverdrup and Skrugard discoveries, we have made several commercial discoveries in the North Sea, such as Krafla, Krafla West, Opal and Rutil. These wells were drilled to add resources to our existing production installations. The Opal and Rutil discoveries are labelled fast-track candidates, which means that their development phases and production start-ups can be expedited.

We did not drill any wells in the Norwegian Sea deepwater region in 2011. The focus has been on interpreting and gaining an understanding of the 2010 well results in order to choose the right target for the next exploration well.

We were awarded 11 licences in the 21st concession round on the NCS - eight as operator and three as a partner. Four of our operatorships were awarded in the Barents Sea and four in the Norwegian Sea. All of the new licences in the Norwegian Sea are concentrated in the Luva area and fit well with the strategy for the area. In the Barents Sea, there is a strong focus on the licences surrounding the Skrugard discovery and the Hoop area, which is classified as a high-potential frontier area.

We have also been awarded interests in 11 production licences in the 2011 Awards for Pre-defined Areas (APA) on the NCS, eight of which are operatorships. In the North Sea, we will be operator in eight of the nine licences awarded, and we will participate as partner in one or two licences in the Norwegian Sea.

In June, the maritime border delimitation agreement was ratified by the Norwegian and Russian foreign ministers. The area is still immature. The Norwegian Ministry of Petroleum and Energy and the Norwegian Petroleum Directorate have completed the first phase of seismic acquisition in the Barents Sea East and have announced that they will complete phase two for the resolved area in 2012.

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

Potential producing areas
In addition to producing areas, Statoil operates a significant number of exploration licences. The exploration acreage is located both in undeveloped frontier areas and near infrastructure and producing fields.

North Sea
In addition to the Johan Sverdrup development on the Utsira High, there are firm plans to explore other significant prospects and growth opportunities in the North Sea. Future discoveries will most likely be tied in to existing infrastructure; however, stand-alone developments will also be considered if the volumes are sufficient. The total area in which we participate has been reduced by about 4,000 square kilometres during 2011 as a result of relinquishments

Norwegian Sea
In the Norwegian Sea, the Luva discovery in the Vøring area has passed the concept selection phase, and the project is targeted for a final investment decision and submission of a plan for development and operation within the year. The establishment of new infrastructure in this area will create a need for additional tie-in volumes, and there are plans to drill more deepwater wells in the coming years.

Barents Sea
Statoil participated in three wildcat wells and was operator for two of them. The Skrugard discovery proved to have excellent reservoir parameters and the proved reserves are sufficient to build new infrastructure in the Barents Sea and open up a new production area. There are several other promising prospects in the area, and there are firm plans to further explore this area. The newly awarded licences in the Hoop area 200 kilometres north-east of the Skrugard discovery could have the potential to create new producing areas in future.

3.1.5 Development on the NCS

The NCS is the backbone of our operations. We continue to explore and develop the NCS as an operator and partner using the best available technology and increasingly standardised development solutions.

3.1.5.1 NCS fields under development

The following fields are currently under development on the NCS, and they include both traditional and fast-track processes.

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 the 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 by pipeline to the Gassco-operated Kårstø plant near Haugesund. The plan for development and operation (PDO) was approved by the Norwegian authorities in June 2010. Production is estimated to start in 2014. The total investments are estimated to amount to NOK 18.5 billion. On 15 December 2010, Statoil signed an agreement with Marathon Petroleum Norge to buy their 20% share of the production licences covering the Gudrun field. As a consequence of this, Statoil's share in the development is now 75%, effective from 1 April 2011.

The jacket for the processing platform has been constructed by Aker Verdal. It was successfully installed in its field location in the last week of July 2011. Conductor driving was subsequently performed, and drilling of the first production well started on 6 September, four weeks ahead of schedule. A total of seven production wells will be drilled and completed prior to production start-up.

Valemon, which is located in the North Sea, will be developed with a steel jacket platform with gas, condensate and water separation. Drilling will be performed using a jack-up rig. Rich gas will be transported via the Huldra pipeline to Heimdal for processing. Sales gas will be transported in Vesterled to St Fergus, or, alternatively, in the Statpipe pipeline to Draupner. There will be a condensate tie-in to Kvitebjørn for stabilisation and further export in pipelines to Mongstad. The PDO for the Valemon field development, submitted to the Norwegian Ministry of Petroleum and Energy (MPE) in October 2010 was approved by the Norwegian parliament on 10 June 2011. The development cost of Valemon is currently estimated to be NOK 19.8 billion, and production start-up is estimated to take place during the fourth quarter of 2014. Statoil's ownership interest in Valemon is per 31.12.2011 64.275%. In October 2011, a sales agreement was made with Centrica Resources (Norge) AS for a 13% share of Valemon, reducing Statoil's ownership interest to 53.775%. This transaction is expected to be closed in the second quarter of 2012.

Contracts for the construction of the steel jacket (Heerema Vlissingen), for transportation and installation of the jacket (Heerema Marine Contractors) and a contract for the tie-in modifications on Kvitebjørn (Bergen Group Rosenberg) have all been awarded. In addition, the contract for drilling production wells has been awarded to Seadrill Offshore AS. The drilling rig West Elara is to be used for this operation.

Visund South is located in the Tampen area of the North Sea. The field was discovered in early 2009. Statoil is the operator, with an ownership interest of 53.2%. The PDO was formally submitted to the MPE on 21 January 2011, and it was approved by the Norwegian parliament on 10 June 2011. The development cost is currently estimated to be NOK 5.6 billion. The field will be developed with a subsea template tied back to the Gullfaks C platform. The template has been constructed by FMC Technologies. It was installed on the field in June 2011. Production drilling commenced on 11 September. Production is scheduled to start in the fourth quarter of 2012.

Hyme is an oil discovery in the Halten area of the Norwegian Sea, about 15 kilometres east of the Njord field. Statoil is operator and holds a 35% ownership interest in the discovery. The PDO for the field, which was submitted to the MPE on 12 May 2011, was approved by the MPE on 28 June. The development cost is currently estimated to be NOK 4,8 billion. The selected development concept includes a subsea template that will be tied back to the Njord A platform, one multilateral production well and one water injection well. Production start-up is scheduled for the first quarter of 2013.

Stjerne is an oil discovery in the Oseberg area, located 13 kilometres south west of the Oseberg South platform. Statoil is the operator and holds a 49.3% ownership interest. The discovery was made in March 2009 and it is being developed as a one-template subsea tie-in to the Oseberg South platform, with two oil production wells and two water injection wells for pressure support. The PDO for the field was submitted to the MPE on 2 May 2011 and approved by the MPE on 16 September 2011. The development cost is currently estimated to be NOK 5.5 billion. Production start-up is scheduled for the first quarter of 2013.

Vigdis North-East is an oil discovery made in 2009 approximately seven kilometres south west of the Snorre A platform in the Tampen area of the North Sea. Statoil is the operator and holds a 41.5% ownership interest. Vigdis North-East will be developed with a subsea template tied in to the Vigdis B subsea template. The oil will be processed on the Snorre A platform. The field will be developed with three oil production wells and one well for water injection. The PDO was submitted to the MPE on 12 April 2011 and approved by the MPE on 16 September 2011. The development cost is currently estimated to be NOK 4.5 billion. Production start-up is scheduled for December 2012.

Skuld is a development project covering the Dompap and Fossekall oil discoveries north east of the Norne field in the Norwegian Sea. Dompap was discovered in 2009 and Fossekall in April 2010. Statoil is operator and holds a 63.955% ownership interest in the development. The Skuld development concept contains of one subsea template at Dompap and two subsea templates on Fossekall, and a total of six oil production wells and three water injection wells. The subsea installations will be tied back to the Norne floating production storage and offloading vessel (FPSO) through a production flowline. The PDO for the development was submitted to the MPE 26 September 2011, and sanctioned 20 January 2012. The development cost is currently estimated to be NOK 10.6 billion. Production start-up is scheduled for early 2013.

Vilje South is a southern extension of the Vilje field, located north of Heimdal in the North Sea. Vilje South is described as a possible upside in the Vilje PDO (named Mygg). The development cost is currently estimated to be NOK 1.1 billion. Statoil is the operator and holds a 28.853% ownership interest. Vilje South will be developed as a single stand-alone subsea satellite well tied back to the existing subsea facility on Vilje, with production start-up scheduled for the third quarter 2013.

Skarv is an oil and gas field located in the Norwegian Sea in which Statoil has an interest of 36.165%, with BP as operator and E.ON Ruhrgas & PGNiG as the other partners. The field is being developed with an FPSO vessel and five subsea multi-well installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. The operator currently expects production to start in the second quarter of 2012. The total development cost at the investment decision was estimated to be NOK 32 billion by the operator BP.

The PDO for Goliat was submitted in February 2009 and approved by the Norwegian authorities in June the same year. Goliat is the first oilfield to be developed in the Barents Sea. The field is being developed with subsea wells tied back to a circular FPSO vessel. The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni, which has an interest of 65%. Statoil is the only partner, with an interest of 35%. The operator expects production start-up to occur in late 2013. The operator has estimated the development costs for the field to be NOK 31 billion.

Marulk, in which Statoil holds an interest of 50%, is a gas and condensate field located in the Norwegian Sea 25 kilometres south west of Norne. The field was discovered in 1992. The final investment decision was taken in early 2010 and proved reserves were booked in 2010. The PDO was approved by the MPE in July 2011.The field is a subsea development with two wells tied back to Norne. Rich gas will be transported through the Norne pipeline and the Åsgard Transport System for processing to sales gas at Kårstø. Condensate will be stored and offloaded commingled with the Norne crude. Production is estimated to start in the second quarter of 2012. The operator estimates the total investments to be NOK 4 billion. The operator is Eni, but Statoil is carrying out the project work.

The table below shows some key figures as of 31 December 2011 for our major development projects.

3.1.5.2 Redevelopments on the NCS

The following projects are being developed on the NCS to extend the life of existing installations, increase oil recovery and exploit new profitable opportunities.

The Gullfaks B water injection upgrade project includes replacement of the pipeline from Gullfaks A to Gullfaks B, upgrading of the existing water injection system and increased water injection capacity on Gullfaks B. The project is expected to be completed in the first half of 2013.

The main purpose of the Kvitebjørn pre-compression project is to increase and accelerate gas and condensate recovery by facilitating low-pressure production. The project includes the installation of a turbine-driven compressor in a new module on the platform. Start-up is scheduled for December 2013.

The Njord North-West Flank project will enable Njord A to drill and produce from the NWF reservoir. Drilling started in October 2011 and production is scheduled to start in November 2012.

The Troll A 3rd and 4th pre-compressor project is described in the original PDO for the Troll field. The purpose of the project is to increase gas production by installing two extra pre-compressors on the Troll A platform. This will enable low-pressure production from the Troll East and West gas provinces. The project was sanctioned by the licence partners in the fourth quarter 2011. The investment costs are estimated to be NOK 11 billion. The expected completion date is the fourth quarter 2015. Statoil's ownership interest in the project is 30.584%. The Troll field is located in the northern part of the North Sea.

The Åsgard subsea compression project will install compact subsea compressors in the Midgard part of the Åsgard fields. The purpose of the project is to increase the recoverable reserves by introducing subsea compression of the wellstream. The Åsgard subsea compression project will implement a significant amount of new subsea technology, and will be the first implementation of subsea gas compression. The PDO was submitted to the Norwegian Ministry of Petroleum and Energy (MPE) in August 2011, and approval by the authorities is expected in early 2012. The investment cost for the project is estimated to be NOK 14 billion. The expected completion date is early 2015. Statoil holds a 34.57% ownership interest in the project.

3.1.6 Fields in production on the NCS

We continued developing the NCS in 2011, and delivered strong results in a year marked with extensive turnarounds and operational challenges.

3.1.6.1 Production on the NCS

In 2011, our total entitlement oil and NGL production in Norway was 252 mmbbl, and gas production was 36.2 bcm (1,287 bcf), which represents an aggregate of 1.316 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.

The following table shows our average daily entitlement production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2011, 2010 and 2009.

3.1.6.2 Operations South

Operations South includes a large part of Statoil's production activity on the NCS. The main producing fields in the Operations South area are Statfjord, Snorre, Tordis, Vigdis, Sleipner and partner-operated fields.

Statoil's share of the area's production in 2011 was 155 mbbl per day of oil, condensate and NGL, and 220 mboe per day of gas, or 375 mboe per day in total. Of this, partner-operated assets (see the section Partner-operated fields) accounted for 43 mbbl per day of oil, condensate and NGL, and 122 mboe per day of gas, or 165 mboe per day in total. Even after over 30 years of production from this area, we believe that there are still substantial opportunities for increased value creation.

Statoil has taken several initiatives to identify and implement measures to increase and prolong production from the Operations South area. These initiatives involve IOR, and they have resulted in a prolongation of planned production beyond the current licence period for several of the fields.

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

The PL 089 licence includes the Vigdis, Borg and Tordis fields. The Tordis field and the southern part of the Borg field have been developed with seven subsea satellites and two templates that are tied back to Gullfaks C, where the oil and gas are processed and stored for offshore loading and export.

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 PDO for the Vigdis North-East Fast Track Project was approved by the MPE in September 2011, and production start-up is planned for the fourth quarter of 2012.

Statfjord has been developed with three fully integrated platforms supported by gravity base structures with 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 North, Statfjord East and Sygna) have been developed, each of them tied back to the Statfjord C platform. In 2005, an amended PDO was approved by the Norwegian authorities for the late-life production period for Statfjord. The Norwegian authorities granted a licence extension for the Statfjord area from 2009 to 2026. The plan is that Statfjord A production will be shut down in 2016.

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. It is extracted on the field and reinjected into a sand layer beneath the seabed to reduce 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. Production from the Beta West structure in Sleipner West, which was discovered in 2009, was approved by the Norwegian Petroleum Directorate (NPD) in April 2011. The hydrocarbons from Gudrun will be piped to the Sleipner field. Oil and gas will be processed at Sleipner. The oil will be transported to Kårstø together with the Sleipner condensate, and the gas will be exported together with the Sleipner gas directly into the Gassled transportation system.

3.1.6.3 Operations North Sea West

Operations North Sea West includes a large part of Statoil's mature production activity on the NCS. Our main focus is on increasing and prolonging production in the area, giving priority to increased oil recovery, exploration and new field development.

The main producing fields in the Operations North Sea West area are Gullfaks, Kvitebjørn, Visund, Grane, Brage, Gimle, Veslefrikk, Huldra, Glitne, Volve and Heimdal.

The petroleum reserves are located below water depths of between 80 and 335 metres. In 2011, Statoil's share of the area's production was 177 mbbl of oil, condensate and NGL per day and 96 mboe of gas per day, or 273 mboe per day in total.

The Gimle field is a Gullfaks satellite field that is operated as a separate unit. Permanent production started in May 2006, with the Gimle exploration well drilled from the Gullfaks C platform being converted into a production well. By the end of 2010, Gimle consisted of two producers and one injector, all drilled as long-reach wells from the Gullfaks C platform.

Brage is an oilfield east of Oseberg in the northern part of the North Sea. The oil is piped to Oseberg and then through the pipeline in the Oseberg Transport System to the Sture terminal. A gas pipeline is tied back to the Statpipe pipeline.

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

Grane is the first field on the NCS to produce heavy crude oil. It is Statoil's largest producing 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 by pipeline from the Heimdal facility. As a result, after around 25 years of oil production, Grane is producing injected gas as well.

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

Oil production from Gullfaks is gradually increasing after a well control incident at well C-06 A on Gullfaks C in May 2010. Oil production is currently significantly higher than was expected in January 2011. This is the result of active reservoir management and partially restored water injection, which is now optimised according to strict operational criteria. Production drilling operations have also been initiated on Gullfaks satellites, and two drilling rigs are now in operation. The repair of integrity-weakened wells is ongoing according to plan.

Statoil received the Petroleum Safety Authority Norway's investigation report on the gas leak that occured on Gullfaks B December 2010. Statoil published its own investigation of the incident in February 2011.The gas leak occurred in connection with the resetting of piping after maintenance of a choke valve in the wellhead area on the North Sea platform.

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. The plan for development and operation (PDO) for Valemon was submitted in October 2010. Gas from this field will be carried via the existing pipeline from Huldra to Heimdal. The PDO was approved on 9 June 2011. The lifetime of the processing facility at the Heimdal Gas Centre will thereby be extended, enabling us to maintain important processing capacity in the area.

Pre-compression plans for the Kvitebjørn field are expected to increase the production of gas and condensate from the field by approximately 35 million standard cubic metres (mscm) of oil equivalent, thereby increasing the recovery rate from 55% to 70%. Work on production of the compressor has already started. Offshore installation is expected to take place from 2012 until completion in early 2014.

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 that is 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 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.

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. In April 2011, we had an incident with the Coflon risers that resulted in the risers having to be replaced and production being reduced. Three new risers were installed by November, making it possible to actively prioritise between wells in order to resume full production.

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

3.1.6.4 Operations North Sea East

Operations North Sea East is a major gas area that also contains significant quantities of oil. The area includes the Troll, Fram, Vega, Oseberg and Tune fields.

Statoil is committed to the development of the area, and important investments have been approved in 2011. They include the investment decision to install two new compressors in Troll A for NOK 11 billion and the fast-track development of Stjerne on Oseberg for NOK 5.4 billion. Both the Oseberg and Troll areas have significant prospective potential and new IOR projects are under evaluation.In 2011, Statoil's share of the area's production was 147 mbbl of oil, condensate and NGL per day and 159 mboe of gas per day, or 306 mboe per day in total.

The Troll area comprises Troll, Fram and Vega. Troll is the largest gas field on the NCS and a major oilfield.

The Troll field is split into three hydrocarbon-bearing regions: the Troll West Oil Province (TWOP), Troll West Gas Province (TWGP) and Troll East (TE). Oil-producing wells on TWOP and TWGP-South are tied into the Troll B platform, while oil wells on TWGP-North are tied into the Troll C platform. Most of Troll A's gas exports are produced on the giant condeep Troll A platform, which is located in the western part of the Troll East structure at a water depth of approximately 300 metres. Some gas is exported from Troll West as well. There is some limited communication between Troll East and Troll West.

Fram consists of Fram West and Fram East, both of which were awarded under the PLO90 production licence permit. Fram West is an oilfield with two subsea templates connected to Troll C. On Troll C, the gas is separated and exported via Troll A, while the rest is reinjected into the reservoir. Fram East produces from the F-East Sognefjord, C-West Sognefjord and C-West Etive reservoirs. The drainage strategy for the Sognefjord reservoirs is pressure maintenance through water injection.

The Vega field came on stream in December 2010. It consists of three provinces called Vega North, Vega Central and Vega South, which were previously organised under two licences and are now unitised into the Vega Unit. The production from Vega is sent to Gjøa and processed there. The Vega gas is sent to a processing facility at St Fergus (Scotland). NGL/oil production from Vega is exported through a pipeline from Gjøa that is connected to Troll oilpipe II, which transports oil and condensate to the Mongstad refinery.

The Oseberg area includes the main Oseberg field, which has been developed with field 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 are piped to the Oseberg field centre for processing and transportation. Oil is exported to shore through the Oseberg transportation system, and gas is exported through the Oseberg gas transportation system to Heimdal and on to market.

3.1.6.5 Operations North

Our producing fields in the Operations North area are Åsgard, Mikkel, Yttergryta, Heidrun, Kristin, Tyrihans, Norne, Urd, Alve, Njord, Snøhvit and Morvin.

Our share of the area's production in 2011 was 214 mbbl per day of oil, condensate and NGL, and 149 mboe per day of gas, or 363 mboe per day in total.

The region is characterised by petroleum reserves located at water depths of 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, challenging 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. Heidrun was the first production platform in Operations North, with production start-up in 1995. Most of the oil from Heidrun is shipped by shuttle tanker 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 west 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 on 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 2009, and the field was producing from seven wells by the end of 2011. In addition, gas is injected into two injection wells via Åsgard B. The Tyrihans development project is expected to be completed in 2012 with another two wells. All production volumes are processed on the Kristin 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 export started in late 2007 via ÅTS and Kårstø.

The Norne field has been developed with a production and storage ship tied to subsea templates. This ship has processing facilities on 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 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 Alve field, which consists of one producing well and a subsea template, 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 field to be developed in the Barents Sea. Twenty wells are expected to produce natural gas from three gas reservoirs: Snøhvit, Askeladd and Albatross. By the end of 2011, Snøhvit was producing from nine wells, filling the plant capacity. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore. Snøhvit reinjects carbon dioxide from the liquefied natural gas (LNG) plant into a separate well/reservoir.

The natural gas, which is transported to shore through a 143-kilometre-long pipeline, is landed on Melkøya, where it is processed at our LNG plant. This plant is Europe's largest export factory for LNG, which is shipped to customers in Europe, the USA and Asia in tankers. The first shipment took place in late 2007. The LNG plant has also suffered from operational challenges in 2011, particularly in relation to problems with the heat exchangers, which are located in the heart of the LNG Plant (cold box). Their function is to bring down the temperature of the methane gas so that it liquidises at -164 degrees Celsius (see section Gas Sales and Marketing - LNG - for more information). Snøhvit carried out a major turnaround in 2011 after which regularity has been high. A new 24-hour production record for Snøhvit was set on 6 August 2011, corresponding to 109% of the original design capacity of the plant.

The Åsgard field comprises three fields: Smørbukk, Smørbukk South and Midgard. The field was developed with the Åsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the Åsgard C storage vessel. The subsea production installations are among the most extensive in the world, with a total of 17 seabed templates. The Åsgard B platform is the largest floating gas processing centre in the world, and Åsgard 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 ÅTS to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the Åsgard A vessel and condensate from the Åsgard C storage vessel 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 on Midgard for onward transportation to the Åsgard B gas processing platform.

Yttergryta produces from a single well, and the well stream is tied back to Åsgard B for processing.

Morvin started production on 1 August 2010. The field consists of two seabed templates with production from four wells. The last well was completed in spring 2011. The well stream with oil and gas is tied back to Åsgard B for processing. Morvin makes an important contribution to utilising the production capacity on Åsgard B.

3.1.6.6 Partner-operated fields

Our partner-operated fields account for a significant proportion of our oil and gas portfolio. They range from development projects to mature fields. Production is expected to start up on Skarv and Marulk in 2012.

Ormen Lange, a deepwater gas field in the Norwegian Sea, is the second-largest gas field on the NCS. Statoil has a 28.916% interest in the field. Statoil was operator for the development phase, while Norske Shell became the operator for the production phase that began at the end of 2007. Statoil continues to execute the approved, but not yet completed subsea compression pilot. The selected development is an extensive subsea development at depths ranging from 850 to 1,100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. The gas is then transported through a dry gas pipeline, Langeled, via Sleipner to Easington in the UK.

Ekofisk was the first developed field complex to come into operation on the NCS. ConocoPhillips is the operator. It consists of the Ekofisk, Eldfisk and Embla fields (in which Statoil has an interest of 7.604%), plus Tor (in which Statoil has an interest of 6.639%). Ekofisk has been upgraded with several new platforms over the years, the latest being the 2/4-M drilling platform, which was installed in 2005. In early 2010, a final investment decision was made to build a new Ekofisk accommodation and field centre platform. With 550 beds, it will be the largest in the world. Investment decisions were made in 2010 for a new Ekofisk South project consisting of a new drilling platform with subsea water injection facilities and the redevelopment of Eldfisk, which consists of a new drilling and process platform. The new facilities are expected to extend the field life considerably beyond the current licence period, which ends in 2028. Redevelopment of Tor is under evaluation.

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

Statoil has a 14.82% interest in the ExxonMobil-operated Ringhorne East field. 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 the Statpipe pipeline. A fourth and fifth production well are planned to be drilled in 2012.

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

Gjøa, which is located in the North Sea, has been developed with a subsea production system and a semi-submersible production platform. Statoil was the operator during the development phase, while GDF SUEZ took over as operator from production start-up in November 2010. Statoil continues to execute the drilling and completion of the production wells into 2012. Gas is exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus, and oil is exported via the Troll 2 pipeline to the Statoil-operated Mongstad refinery near Bergen. The Gjøa platform processes and exports volumes from both the Gjøa field and the neighbouring Vega fields. The platform is supplied with land-based electricity from Mongstad. Statoil has a 20% interest in Gjøa.

3.1.7 Decommissioning on the NCS

No Statoil-operated fields have been decommissioned 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 (the OSPAR Convention). No Statoil-operated fields have been decommissioned during the last three years, however. On partner-operated fields, there has been removal activity on Frigg and Ekofisk.

In 2011, Statoil commenced execution of the Troll-Oseberg Gas injection (TOGI) decommissioning project.

For further information about decommissioning, see note 24 to the consolidated financial statements, Asset retirement obligations, other provisions and other liabilities.

3.2 Development and Production International (DPI)

3.2.1 Introduction to DPI

Statoil is present in several of the most important oil and gas provinces in the world, and Development and Production International (DPI) is expected to account for most of the company's future production growth.

Development and Production International is responsible for the development and production of oil and gas outside the Norwegian continental shelf (NCS).

In 2011, the reporting segment was engaged in production in 12 countries: Canada, the USA, Brazil, Venezuela, Angola, Nigeria, Iran, Algeria, Libya, Azerbaijan, Russia and the UK. In 2011, DPI produced 28.9% of Statoil's total equity production of oil and gas.

Statoil has exploration licences in North America (Gulf of Mexico, Canada and Alaska), South America and sub-Saharan Africa (Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania), Middle East and North Africa (Libya and Iran) and Europe and Asia (the Faeroes, Greenland, the UK, Azerbaijan and Indonesia).

The main sanctioned development projects in which DPI is involved are in the USA, Angola and Canada. We are well positioned for further growth through a substantial pre-sanctioned project portfolio, including a strengthened onshore US position through the acquisition of Brigham Exploration Company which was closed in December 2011.

The map shows Statoil's international exploration and production areas.

3.2.2 DPI key events in 2011

International development and production continued to grow in 2011 through the start-up of several important projects.

• Equity production increased by 3.9% from 2010, to 534 mboe per day:
  • On 27 January, Statoil announced the first oil from the Leismer Demonstration Project in Canada.
  • On 9 April, the Statoil-operated Peregrino offshore field in Brazil started production.
  • On 25 June, the Hibernia Southern Extension, located off the coast of Canada, delivered its first oil.
  • On 24 August, the start-up of the Pazflor development in Angola was announced.
• Strong ramp-up from US onshore was driven by a large number of new wells and better than expected well performance in Marcellus.
• The final investment decision was made for In Salah Southern Fields in Algeria and the Schiehallion Redevelopment in the UK.
• The acquisition of Brigham Exploration Company, which was finalised in December 2011, gives Statoil strategic exposure to US unconventional plays, which are believed to contain a substantial resource base and represent an increasingly important part of future energy supplies.
• The Peregrino South well in Brazil added significant volumes to the overall Peregrino field resource base.
• Drilling in the US Gulf of Mexico recommenced after the moratorium. Statoil is the operator there that was awarded most permits for new exploration wells by year-end (four), and it was the first operator to start a new exploration well.
• New licences in the Kwanza Basin in Angola established Statoil as a leading player in the pre-salt trend, with potential for significant new resources.
• New acreage was accessed in Canada, Indonesia and Suriname.

3.2.3 The DPI portfolio

To enhance our US growth and commitment to shale plays in 2011, we acquired Brigham Exploration Company and increased our acreage in Marcellus and Eagle Ford.

Acquisitions
In December 2011, we acquired 100% of the outstanding shares of Brigham Exploration Company. The acquisition adds production of approximately 21 mboe per day (as of December) to Statoil's production and gives us access to 1,500 square kilometres (375,000 acres) in the Bakken and Three Forks formations in the Williston Basin.

In addition to the Bakken acquisition, we continue to deepen our existing positions. In the liquids-rich Eagle Ford, we have increased our acreage from 67,000 to 87,974 net acres. Similarly, we have deepened our position in Marcellus, with continued acreage acquisitions in the northern dry gas core and south-west liquids-rich area. The total Marcellus acreage has increased from 665,000 net acres to 689,000 net acres.

Divestments and other reductions of Statoil's international portfolio
On 14 April 2011, Statoil's formation of a joint venture and sale of 40% of the Peregrino field off the coast of Brazil to the Sinochem Group was formally closed. The deal, which was first announced on 21 May 2010, has obtained all required government approvals from the Brazilian and Chinese authorities. Statoil retains 60% ownership and operatorship of the field.

With effect from January 2011, Statoil formed a joint venture with PTTEP of Thailand in its oil sands business and, as part of that transaction, sold PTTEP a 40% interest in the leases in Alberta, Canada. Statoil retains 60% ownership and operatorship of the oil sands project.

3.2.4 International exploration

Statoil supports its international growth ambitions by accessing material acreage positions early in the exploration phase. Further focus is placed on drilling an increasing number of wells with significant discovery potential.

We have exploration licences in North America (Gulf of Mexico, Canada and Alaska), South America and sub-Saharan Africa (Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania), Middle East and North Africa (Libya and Iran), and Europe and Asia (the Faroes, Greenland, the UK, Azerbaijan and Indonesia).

We completed 16 wells in 2011. Five were announced as discoveries: the Mukuvo and Lira discoveries in Angola, the Gavea and Peregrino South discovery in Brazil and the Logan discovery in GoM.There were five dry wells, while six wellsare currently under evaluation. We plan to drill around 20 wells in 2012.

In Angola, Statoil was awarded operatorship in two new blocks and partnership in three new blocks in 2011. These blocks are all in the Angola pre-salt play.

Statoil acquired interests in six new licences in Indonesia in 2011.

Together with Chevron and Repsol, we were named successful bidders in Canada for exploration rights on two land parcels in the Flemish Pass Basin, off the coast of Newfoundland and Labrador. Statoil will be the operator of both licences, with a 50% interest.

During the second half of 2011, our exploration activities in the Gulf of Mexico returned to levels similar to before the Macondo incident, which Statoil was not involved in, and two Statoil-operated wells have been completed.

We entered Suriname in 2011 through a farm-in agreement with Tullow. We have acquired a 30% working interest in block 47, with a commitment to participate in a seismic survey.

Our two licences in Egypt - El Dabaa and Ras el-Hekma - expired in 2011, after we had completed the work programme to which we were committed. We drilled one well in the El Dabaa licence, which was dry. Final closure is ongoing.

We reduced our share in three of our licences in the Faroes during 2011, selling 49% in License 006, and 50% in License 009 and License 011 to ExxonMobil. We retain a 50% interest and operatorship in each of these licenses.

Areas with drilling or significant Statoil-operated seismic activity in 2011

The areas where we had significant activity in 2011 are presented below:

Exploratory wells in Eurasia (excl. Norway), Americas and Africa

3.2.4.1 North America

Statoil has significant activities in the USA, with approximately 300 exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska. We are also an operator and partner in exploration licences off the coast of Newfoundland in Canada.

3.2.4.1.1 Canada

Statoil is operator and partner in exploration licences off the coast of Newfoundland (11,138 square kilometres).

In 2011, Statoil operated a well on the Fiddlehead prospect in the Jeanne d'Arc Basin and an appraisal well on the Mizzen discovery in the Flemish Pass Basin. The drilling operations were completed successfully and safely. Statoil successfully completed a 1,600 square-kilometre seismic 3D programme on the EL1123 licence, Cupids. We also participated in the Suncor Energy-operated Ballicatters discovery in the Jeanne d'Arc Basin.

We have strengthened our offshore position in Canada and our Arctic portfolio through agreements with Chevron Canada and Repsol E&P Canada. The agreements involve three major basins off the coast of Canada: the Flemish Pass and Orphan basins off the coast of Newfoundland, and the Beaufort Sea located in Canada's high north. These new joint ventures over large land blocks in deep water represent important strategic steps for Statoil in the offshore sector in Canada, providing us with access to large potential resources and increasing the optionality of our exploration portfolio.

Statoil Canada, Chevron Canada and Repsol E&P Canada were named successful bidders for exploration rights on two land parcels in the Flemish Pass Basin, off the coasts of Newfoundland and Labrador. Statoil will be the operator of both licences with a 50% interest. Chevron Canada will have a 40% interest and Repsol E&P Canada 10%. This offers promising growth opportunities near the Statoil-operated Mizzen discovery.

Statoil intends to continue exploration activities in 2012, with one Statoil-operated well and one partner-operated well.

3.2.4.1.2 USA

Statoil has significant activities in the USA, with approximately 300 exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska. Drilling activity has returned to a level similar to that before the Macondo incident.

US Gulf of Mexico
Statoil's exploration activities in the GoM have returned to levels similar to before the Macondo incident. Statoil operated the Cobra Paleogene well in the Alaminos Canyon and the Logan Paleogene well in Walker Ridge. The Logan well discovered hydrocarbons, and evaluations are ongoing to assess volumes and commerciality.

Statoil participated in the Deep Blue appraisal well (Noble is the operator) and is currently participating in the Kakuna exploration well (Nexen is the operator) and the Heidelberg appraisal well (Anadarko is the operator). Upon completion of the Heidelberg well in early 2012, Statoil intends to commence drilling of the Bioko Paleogene prospect, which has already been awarded a permit.

Exploration activity in the Gulf of Mexico in 2012 is expected to include three Statoil-operated exploration wells and participation in approximately four partner-operated wells.

In 2011, Statoil secured a cross assignment in the Bioko prospect with ConocoPhillips, and, together we farmed down a participation interest in the Bioko well to Shell. Statoil also succeeded in swapping interests in the Kilchurn/Innsbruck prospects with Marathon.

Alaska
Statoil opened an office in Anchorage, Alaska to support operations and activities off the Alaskan coast. Statoil carried out a successful geotechnical programme of high-resolution seismic and soil borings on our operated leases for well location planning and permitting activities. There was extensive stakeholder engagement with local communities and there were no safety or environmental incidents. Statoil continued to participate in gathering extensive baseline science data in the Chukchi Sea and signed an agreement with the National Oceanic and Atmospheric Administration (NOAA) for environmental cooperation in the Arctic.

Shale
Activity related to US onshore shale is presented below in the International fields - North America section.

3.2.4.2 South America and sub-Saharan Africa

We have exploration licences in Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania.

3.2.4.2.1 Brazil

Statoil has interests in seven exploration licences in four different basins off the coast of Brazil, and it is the operator for four of the licences.

In 2011, we completed two Statoil-operated wells in the Campos Basin, plus three sidetracks in BM-C-47. The second well and third sidetrack were drilled in BM-C-7. All wells and sidetracks proved oil and added significant reserves to the greater Peregrino area.

We participated in the Gavea and Pão de Açucar exploration wells in BM-C-33, which were both discoveries. Pão de Açucar was announced in February 2012 as a significant discovery, and its development potential together with Gavea is under evaluation by the partnership. BM-C-33 is located in the Campos Basin.

In the Camamu-Almada basin, located outside Salvador, we farmed down 10% of the Petrobras-operated licence BM-CAL-7 and 15% of the Statoil-operated BM-CAL-10 to Gran Tierra. During 2011, we drilled one well in BM-CAL-10, which was dry.

Statoil also participated in one licence in the Espirito Santo basin, BM-ES-32, where the Indra discovery is located. BM-ES-29 was relinquished in 2011 after we had completed the committed work programme. The interests in three blocks that we won in the eighth round in the Santos Basin are pending award.

In 2012, Statoil expects to operate one appraisal well and take part in at least two non-operated exploration wells.

3.2.4.2.2 Angola

Statoil holds interests in blocks 4/05, 15, 15/06, 17, 22, 25, 31, 38, 39 and 40 in Angola.

In December 2011, Statoil was awarded licences for the operatorship of and participation in several pre-salt blocks off the coast of Angola. Statoil was awarded the following blocks as operator:

• Block 38, 6,298 square kilometres, with a 55% share (partners are Sonangol P&P and China Sonangol)
• Block 39, 7,800 square kilometres, with a 55% share (partners are Sonangol P&P and Total)

Statoil was awarded the following blocks as partner:

• Block 22, 5,180 square kilometres, with a 20% share (Repsol is operator, Sonangol P&P is partner)
• Block 25, 4,825 square kilometres, with a 20% share (Total is operator, Sonangol P&P and BP is partner)
• Block 40, 7,588 square kilometres, with a 20% share (Total is operator, Sonangol P&P is partner)

We are engaged in extensive exploration activity in Angola. A number of wells were drilled in 2011, and more are expected to be drilled in and after 2012. We have interests varying from 5% to 50% in four blocks.

In Block 4/05, which is operated by Sonangol and assisted by Statoil, we completed the remaining commitment exploration well in January 2011.

In Block 31, which is operated by BP, a total of 31 exploration wells have been drilled. We are working to mature existing discoveries into future developments on the remaining acreage.

In Block 15/06, which is operated by ENI, several exploration and appraisal wells have been drilled this year.

In Block 15, work is being initiated to mature existing discoveries as tie-ins to existing infrastructure.

In Block 17, appraisal drilling was carried out in 2011 and is expected to continue into 2012.

Block 34 was relinquished in 2011 after completion of the committed work programme.

3.2.4.2.3 East Africa

Statoil is the operator for two large frontier offshore blocks in the East Africa region - block 2 in Tanzania and area 2&5 in Mozambique. The blocks have water depths of between 1,000 and 3,000 metres.

Tanzania
Block 2 Tanzania (5,500 square kilometres): Statoil is the operator with a 65% share, while ExxonMobil is a partner and has a 35% share. Statoil announced in February 2012 that it had made a significant gas discovery in the Zafarani exploration well. This well fulfills our commitment in the current exploration phase. Following the completion of this well, we intend to drill an exploration well on the Lavani prospect. Tanzania Petroleum Development Corporation (TPDC) has the right to a 10% working interest in case of a development phase.

Mozambique
Area 2&5 Mozambique (7,800 square kilometres): Statoil is the operator with a 90% interest. The area consists of two blocks under one licence agreement. The state oil company Empresa Nacional de Hidrocarbonetos (ENH) has a 10% interest. We entered the third exploration phase on 1 June 2011 with one well commitment. A 3D survey was started in mid-November 2011. It was completed in early January 2012.

3.2.4.3 Middle East and North Africa

We have exploration licences in Libya and Iran.

However, the company will not make any future investments in Iran under the present circumstances (see the section International Fields - Middle East and North Africa - Iran). Our two licences in Egypt, El Dabaa and Ras el-Hekma, expired in 2011, after completion of the committed work programme. We drilled one well in the El Dabaa licence, which was dry. Final closing is ongoing.

3.2.4.4 Europe and Asia

We have exploration licences in the Faroes, Greenland, the UK, Azerbaijan and Indonesia.

3.2.4.4.1 Indonesia

Statoil has interests in eight production-sharing contract (PSC) licences in Indonesia. We operate Karama and Halmahera II, and are partners in Kuma, North Ganal, North Makassar, West Papua IV, Obi and Halmahera Kofiau.

We acquired interests in six licences during 2011. The North Ganal and North Makassar PSCs are located in the North Makassar Strait. The West Papua IV, Obi, Halmahera Kofiau and Halmahera II PSCs are located in the eastern part of Indonesia.

We are the operator of Halmahera II PSC. Eni is the operator of North Ganal PSC, while Niko Resources is the operator of the remaining licences. We have a commitment to drill one well in the North Makassar PSC and one in the North Ganal PSC. We only have commitments to conduct seismic surveys in the other PSC.

One well in the Kuma PSC was drilled in 2011 and the result is still under evaluation. A seismic acquisition programme was started in 2011 and is expected to continue into 2012. Three wells in the Karama PSC and one well in the North Makassar PSC are planned to be drilled during 2012.

3.2.5 International production

In 2011, Statoil's petroleum production outside Norway amounted to an average of 334 mboe per day of entitlement production and 534 mboe per day of equity production.

Our total annual entitlement production in 2011 was approximately 334 mboe per day, compared with approximately 332 mboe per day in 2010.

The first table below shows DPI's average daily entitlement production of liquids and natural gas for the years ending 31 December 2011, 2010 and 2009.

The table below provides information about the fields that contributed to production in 2011.

The table below shows equity and entitlement production per country in 2011.

3.2.6 International fields

Major efforts are under way to make the transition from a mainly Norwegian offshore player to a world-class international operator.

DPI is working continuously to develop the inventory of projects into producing assets by looking at innovative technical and commercial solutions.

This section covers projects under development and fields in production. Significant pre-sanctioned projects, including some discoveries in the early evaluation phase, are also presented. A field's plateau production is often referred to in this section. It means the yearly average equity production at plateau for a field for a 100% ownership share. Capacities also refer to the whole field or facility.

Exploration activities are described in the report section Operational review - Development and Production International (DPI) - International exploration.

3.2.6.1 North America

Statoil's development and production activities in North America comprise interests and operations in several areas and basins.

Statoil has activities in the US Gulf of Mexico, the Appalachian region, south-west Texas, the Williston Basin, off the East Coast of Canada and in the oil sands of Alberta, Canada. We also have a representative office in Mexico City.

3.2.6.1.1 Canada

The oil sands business remains an important long-term investment, and the Leismer Demonstration Project has been operational since early 2011. Offshore, we have production interests in Hibernia and Terra Nova, and interests in two development projects.

Oil sands
In 2007, we acquired 100% of the shares in North American Oil Sands Corporation and operatorship of 1,129 square kilometres (279,053 net acres) of oil sands leases in the Athabasca region of Alberta. In January 2011, we formed a joint venture with PTTEP of Thailand and, as part of that transaction, sold them a 40% interest in the leases. We continue to be managing partner, operator and 60% owner of the oil sands project.

The Leismer Demonstration Project started its first commercial production on 11 January 2011, and it produced approximately 3.7 mmbbls of bitumen in 2011. All of the project's production wells have been drilled and completed, with all four well pads in steam-assisted gravity drainage (SAGD) production mode. The Leismer Demonstration Project is connected to the existing pipeline infrastructure at our Cheecham terminal, which connects to a third-party pipeline that runs to the Edmonton area. In 2011, production ramp-up and operational performance exceeded our prior expectations.

Our second oil sands development, Corner, is currently in an early stage of development.

To determine the extent of the exploitable oil sands deposits in Alberta, more than 872 wells were drilled in the region from 2003 to 2011. Extensive seismic surveys were also carried out during the same period.

During the 2010-2011 winter drilling programme, 126 wells were drilled for the purpose of further delineation of the oil sands reservoirs, for the observation and monitoring of production operations, and for water source/ water disposal for both near and longer-term development projects. A total of 182.7 square kilometres of 3D seismic was also shot during the winter of 2010-2011. Drilling activities will continue during the 2011-2012 winter evaluation programme, along with 3D and 4D seismic coverage.

Offshore fields in production
Hibernia produces from a gravity-based structure (GBS). It is operated by Hibernia Management and Development Company Ltd (HMDC). The Hibernia field is in the initial stages of decline, with gross production rates averaging 154,000 barrels of oil per day (Statoil 5%) in 2011.

Terra Nova produces from an FPSO and is operated by Suncor Energy. The Terra Nova field is also in decline, with gross production rates averaging 43,000 barrels of oil per day (Statoil 15%) in 2011. One development well was delivered in 2011, with positive results. Development drilling of the field is planned to continue in 2012. Terra Nova production was limited in 2011 due to the occurrence of hydrogen sulphide (H2S) in the producing reservoir. The partnership plans to execute a major off-station capital programme in 2012 to remediate the H2S issue.

Offshore development projects
The Hebron field, which is operated by ExxonMobil, will be developed using a GBS. The project has entered the front-end engineering design (FEED) phase. Statoil holds a 9.7% interest in the development project.

The Hibernia Southern Extension Unit, which is operated by ExxonMobil, comprises the development of resources in several fault blocks to the south of the existing Hibernia field. The field is planned for development as a satellite to the Hibernia field. Statoil's unitised interest is currently 10.5%. The project achieved early delivery of two producing wells in 2011. The development part of the project, which consists of the installation of a subsea template for water injection, has been sanctioned by the partnership and is expected to be on stream in 2014. Production from the producing wells will be limited until the development is completed.

3.2.6.1.2 USA

The onshore Marcellus and Eagle Ford shale gas investments became key contributors to our North American production. Offshore, the USA continues to deliver production expectations and to progress a strong pipeline of Gulf of Mexico development projects.

Onshore
The Marcellus shale gas play is located in the Appalachian region in north-east USA. In November 2008, we entered into a strategic alliance with Chesapeake Energy, acquiring 32.5% of Chesapeake's 1.8 million acres in Marcellus. We have continued to acquire acreage within the play, with a net acreage position of over 689,000 acres at the end of 2011. Marcellus provides Statoil with a long-life gas asset with considerable optionality in relation to the timing of drilling and production from these leases. Statoil's daily equity production was 28,700 boe from 300 wells by year-end 2011.

Our joint venture acreage is concentrated around the developing core regions, most notably north-east Pennsylvania (PA), south-west Pennsylvania and north-west West Virginia (WV). We have engaged in a number of trades and purchases to consolidate our position in these areas. We see encouraging signs concerning estimated ultimate recovery rates (EUR), very strong initial production rates from north-east PA, and above pro-forma production rates in south-west PA and WV, with an upside on liquids. Statoil and Chesapeake will continue to acquire high-grade acreage around the most prospective areas of the play and will build up production from the areas. The operator was running 23 rigs in the play at the end of 2011.

Through agreements with Enduring Resources, LLC and Talisman Energy Inc., Statoil acquired 67,000 net acres in the Eagle Ford shale formation in south west Texas in 2010. Statoil and Talisman formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale formation. Together, Statoil and Talisman initially held 134,000 net Eagle Ford acres and associated assets and production in the joint venture. The venture has continued to acquire acreage within the play, with a net acreage position of over 87,974 acres at the end of 2011. Statoil's daily equity production was 5,200 boe by the end of 2011 from 100 wells. The operator was running ten rigs in the play at the end of 2011.

The acquisition of Brigham Exploration Company, which was finalised in December 2011, gives Statoil strategic exposure to US unconventional plays, which are believed to contain a substantial resource base and represent an increasingly important part of future energy supplies. Statoil's daily equity production was 26,200 boe for December. For more information on the acquisition, please refer to the section Global Strategy and Business Development (GSB) Key events in 2011.

Offshore Gulf of Mexico
Statoil's production from the Gulf of Mexico is anticipated to increase in the next few years as a result of incremental production from development fields, despite the decline experienced in the producing fields.

Fields in production
Production started in May 2009 from the Chevron-operated Tahiti oilfield in which we have a 25% interest. The field is located in Green Canyon blocks 640/596. It consists of seven wells in three locations connected to a floating facility with a processing capacity of approximately 155,000 barrels of oil per day. Gross average daily production was 110,000 boe in 2011. The second phase of the Tahiti development, which will mitigate the decline from the initial phase, was sanctioned in 2010 and is now in the execution phase.

Production started in July 2009 from the Thunder Hawk oilfield located in Mississippi Canyon block 734. We have a 25% interest in this Murphy Oil-operated development, which consists of a semi-submersible floating production facility located in Mississippi Canyon block 736. The processing capacity is approximately 45,000 boe/d. The gross average daily production is declining and was 12,900 boe in 2011. A fourth well has been approved by the partners. It is expected to be in production by the middle of 2012.

Spiderman, a deepwater gas field, is part of the Anadarko-operated Independence Hub, which is a floating production facility located in Mississippi Canyon block 920. Statoil has an 18.3% interest in the field. The gross average daily production in 2011 was approximately 22,000 boe/d. The Independence Hub is owned by third parties. It has a processing capacity of approximately one billion cubic feet of natural gas per day. Statoil has contractual rights to 12.7% of the total capacity through May 2012 and 6.4% for five years thereafter.

The Murphy-operated Front Runner oilfield is located in Green Canyon blocks 338/339/382. Statoil has a 25% interest in Front Runner, which started production in 2004. The field produces while carrying out simultaneous drilling activities from a rig situated on a spar floating production facility. Gross average daily production was 7,000 boe/d in 2011.

In addition Statoil has a 30% interest in the Noble Energy-operated Lorien oilfield located in Green Canyon block 199, and 35% in Zia, located in Mississippi Canyon block 299.

Fields under development
Statoil has a 23.6% 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 Anadarko's Constitution platform. First production at the Caesar Tonga development in the Green Canyon area of the deep-water Gulf of Mexico was on 7 March 2012. Current Production is approximately 40,000 barrels of oil equivalent (BOE) per day from the first three subsea wells in about 5,000 feet of water. A fourth development well is expected to be drilled and completed later this year as part of the planned phase one development.

Tahiti Phase 2 will add two producing and three water-injection wells to the existing architecture. Injection from the first two water-injection wells is expected to start in the first quarter 2012, while first oil from additional producers is expected in the first quarter 2013.

Statoil has a 25% working interest in the Jack oilfield, located in Walker Ridge blocks 758/759, and a 21.5% working interest in St. Malo, located in Walker Ridge block 678. St. Malo and Jack are located at a water depth of approximately 2,000 metres and are approximately 40 kilometres apart. The two fields are operated by Chevron and will be developed jointly with subsea wells connected to a centrally-located production platform. The Jack and St. Malo projects were sanctioned in September 2010 and the first oil is expected in late 2014.

Statoil has a 27.5% interest in Big Foot, located in Walker Ridge block 29. Big Foot is operated by Chevron and will be developed with a dry tree tension leg platform with a drilling rig. The Big Foot project was sanctioned in December 2010. The first oil from Big Foot is scheduled in late 2014.

Discovered in 2007, Julia (ExxonMobil 50% and Statoil 50%) is one of the major discoveries in Paleogene, with a significant in-place volume. In October 2008, ExxonMobil (operator) filed for Suspension of Production (SOP) based on a subsea tie-back concept or, alternatively, a stand-alone facility; which was denied by Minerals Management Service (now Bureau of Ocean Energy Management - BOEM). In May 2011 the Director of Hearing and Appeals ("OHA") issued a decision upholding BOEM's SOP denial and overruling the prior Interior Board of Land Appeals ("IBLA") decision (2009), which was in favour of the Julia partners. In August 2011, Statoil and ExxonMobil filed separate appeals in the federal court system challenging the OHA Director's decision. In parallel, Julia owners were engaged in settlement negotiations with the Department of Interior (DOI) and Department of Justice (DOJ) to resolve the SOP issues. At the same time, the Julia partners negotiated with the Jack and St Malo partners to secure an amendment to the production handling agreement (PHA) for Julia's re-entry into the Jack and St Malo host. A settlement agreement was signed with DOI and DOJ at the end of December 2011. On 18 January, the US District Court signed and filed its Order approving the Julia settlement and dismissed the case. The settlement is final. In early January 2012, the PHA amendment was also signed by the Jack and St Malo host owners and Julia partners. ExxonMobil, operator for Julia, is gearing up and plans to restart the project in the second quarter of 2012. The first oil is expected by mid-2016.

3.2.6.2 South America and sub-Saharan Africa

Our development and production activities in South America and sub-Saharan Africa comprise the Peregrino operatorship in Brazil, the Petrocedenõ project in Venezuela, the Agbami offshore field in Nigeria and four Angolan offshore blocks.

3.2.6.2.1 Brazil

Statoil is the operator of the Peregrino offshore field, which started production in April 2011. We are among the largest foreign offshore operators 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, about 85 kilometres off the coast of Rio de Janeiro.

The field came on stream on 9 April 2011. It is producing the oil from two well head platforms with drilling capability to an FPSO for final processing. Our share of the production was 15.7 mboe per day in 2011. Design capacity is 100,000 barrels of oil per day.

In May 2010, Statoil agreed to form a joint venture and sell 40% of the Peregrino field to Sinochem Group. Statoil retained 60% ownership, and operatorship of the field. The transaction was formally signed on 14 April 2011 after being approved by the Brazilian government.

Work is also ongoing to develop the Peregrino South and South West discoveries.

3.2.6.2.2 Venezuela

Statoil has a 9.7% interest in Petrocedeño, one of the largest extra-heavy crude oil projects in Venezuela.

The Petrocedeño project involves the extraction of extra-heavy crude oil from reservoirs in the Orinoco Belt. A diluting component is added in order to enable the extra-heavy crude 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, which is owned by project partners PDVSA, Total and Statoil, operates the field and markets the products.

Statoil's share of Petrocedeño production in 2011 was 13.6 mboe per day, which is below design capacity. A recovery programme is ongoing to improve the situation.

We have been present in Venezuela since 1994 and have a long-term commitment to the country based on the participation in Petrocedeño and Venezuela's large oil reserves.

3.2.6.2.3 Angola

The Angolan continental shelf is the largest contributor to Statoil's production outside Norway. It yielded 176 mboe per day in equity production in 2011, 33.0% of Statoil's total international oil and gas output.

Block 17 is operated by Total. Our interest is 23.3%. Production from the block currently comprises five development areas produced over three FPSOs. The Girassol, Jasmim and Rosa development areas are produced over the Girassol FPSO and the Dalia development area over the Dalia FPSO. This year, the Pazflor development came on stream, producing to the Pazflor FPSO. The combined equity production from block 17 was 113.9 mboe per day in 2011.

The Pazflor project, which comprises the Perpetua, Acacia, Zinia and Hortensia discoveries, came on stream on 24 August 2011. The expected production capacity of the FPSO is 220 mboe per day.

The CLOV project consists of the Cravo, Lirio, Orchidea and Violeta discoveries. The project was sanctioned in mid-2010 and it is currently under development. CLOV will be produced over a new FPSO, with an expected production capacity of 160 mboe per day. The first oil is expected in 2014.

An IOR initiative to fill excess capacity on the Girassol FPSO was implemented in 2011. Additional projects are under development on block 17. The IOR projects include subsea tie-backs, infill wells, and the use of multi-phase pumps.

Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil. Our interest is 13.3%. Statoil's equity production from block 15 was 58.8 mboe per day in 2011. Production here stems from the Kizomba A, Kizomba B, Kizomba C-Mondo and Kizomba C-Saxi Batuque FPSOs. In addition, one satellite, Marimba, is producing through a subsea tie-back to the Kizomba A FPSO. The Xikomba FPSO ceased production in March 2011. It is now being decommissioned.

Kizomba Satellites phase 1, consisting of two discoveries, Clochas and Mavacola, was sanctioned by the partnership in 2009. It is currently under development. The first oil is scheduled for 2012.

Possible development of the Kizomba Satellites phase 2 is being evaluated. The project includes the Bavuca, Kakocha and Mondo South discoveries.

Block 31 is an ultra-deepwater licence operated by BP. Our interest is 13.3%. The 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, and it is now under execution. PSVM will be developed via a new FPSO with a production capacity of 150 mboe per day. The first oil is scheduled for 2012. Work is also ongoing to pursue a second development in the southern part of block 31.

Block 4/05 is operated by Sonangol P&P, and Statoil's interest is 20%. This block includes the Gimboa field. The equity production was 3.4 mboe per day in 2011.

Block 15/06 is operated by Eni, and Statoil's interest is 5%. Work is currently being done to progress a development solution for the discoveries on the block. .

Gas Gathering Projects: Pursuant to the production sharing agreement (PSA), all surplus gas from the fields in Angola is to be delivered to Sonangol, which owns the gas. No income will be generated from the transfer of gas, and costs and investments related to the projects will be recovered through the PSA.

The delivery of commissioning gas from block 15 to the Angola LNG Terminal started in the second quarter of 2011. The export of gas from block 17 with injection into block 2 started in December 2010. The pipeline from block 2 to the Angola LNG Terminal was completed in 2011. It is ready to start deliveries to the terminal.

3.2.6.2.4 Nigeria

In Nigeria, we have a 20.2% interest in the largest deep water producing field, Agbami.

The Agbami field is produced from subsea wells connected to an FPSO. It is located about 110 kilometres off the coast of Nigeria and is operated by Chevron. The field is producing close to the nominal plateau rate of 250 mboe per day.

The National Assembly is still debating the Petroleum Industry Bill (PIB), which will most likely increase the government take if passed.

Together with our partner Chevron we are currently in arbitration with the national oil company NNPC over the interpretation of certain clauses in the production sharing contract (PSC) that governs our share of Agbami.

The security situation in Lagos and the rest of south west Nigeria is normally medium to high depending on the time of day. While the kidnapping of middle- to high-income Nigerians does take place, it is relatively rare. Robberies and car snatching are more common place. There is, however, an increase in piracy and other waterborne crime. There has been no impact on large crude oil tankers in 2011. Convoy and security vessels are used to protect supply ships and other smaller vessels. Kidnappings are on the rise in the Delta area in the south. The security situation is similarly serious in the north east.

3.2.6.3 Middle East and North Africa

Statoil's development and production in the Middle East and North Africa in 2011 primarily encompassed Algeria, Libya, Egypt, Iran and Iraq.

In this region, Statoil is active as a joint operator in the producing fields In Salah and In Amenas in Algeria. The upstream assets in Algeria supplement Statoil's strong position as a supplier to the European gas market. In 2011, Statoil has been an active partner in licences in Libya and Iraq and it was also the operator for two exploration licences in Egypt in 2011.

Due to the political situation in Libya, Statoil's Libyan operations and production were stopped in February 2011. The Murzuq field resumed production on 13 November 2011 and the Mabruk field resumed production on 12 January 2012.

Statoil also has offices in Abu Dhabi and Iran.

3.2.6.3.1 Algeria

Our main assets, In Salah and In Amenas, are the third-largest and fourth-largest gas developments in Algeria. The developments of the In Salah Southern Fields and In Amenas Gas Compression Project were sanctioned in 2010.

Fields in production
The In Salah onshore gas development, in which Statoil has a 31.9% interest, is Algeria's third-largest gas development. The field is currently producing at plateau level of around 130 mboe per day.

A contract of association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil.

In the In Salah Gas Compression Project, gas compression facilities were installed on the three existing northern fields in 2010, and compression has started on all three fields.

The In Amenas onshore development is the fourth-largest gas development in Algeria. It contains significant liquid volumes. Production efficiency is high, although occasional capacity restrictions due to priorities in the export pipeline system remain an issue.

The facilities are operated through a joint operatorship between Sonatrach, BP and Statoil where Statoil's share of the investments (working interest) is 45.9%. Production has reached plateau level. The rights and obligations are governed by a production sharing contract that gives BP and Statoil access to a share of the liquid volumes. A continuous production drilling campaign is ongoing.

Fields in development
The In Salah Southern Field Development Project was sanctioned in late 2010. This project will mature the remaining four discoveries into production. It is planned to come on stream in the first half of 2014. The southern fields will tie in to existing facilities in the northern fields.

The In Amenas Gas Compression Project, which is led by BP, was sanctioned in late 2010. The compressors are expected to come on stream early in 2013. This will make it possible to reduce well head pressure and maintain the contractual production commitment.

The Hassi Mouina exploration phase has been extended until September 2012 . Statoil is currently assessing the technical solutions for and the commercial attractiveness of a potential development.

3.2.6.3.2 Iran

Statoil was the offshore operator for the development of phases 6, 7 and 8 of the South Pars gas and condensate field in the Persian Gulf until its completion in 2009. Statoil will not make any future investments in Iran under the present circumstances.

The National Iranian Oil Company (NIOC) took over as the formal operator of South Pars after its completion. Statoil assisted the NIOC for a limited transitional period in accordance with the contractual framework for the development phase. The technical service agreement (TSA) concluded at the end of March 2011, in accordance with the contract.

Statoil has previously taken part in exploration and drilling activities in the country on the Anaran block. Work on this project has been stopped. Statoil also holds a licence for exploration of the Khorramabad block. No activity is planned for this licence.

A small staff is working to secure the outstanding contractual cost recovery and remuneration for Statoil for the development and exploration contracts. Considerable progress has been made during 2011.

In a letter from the US Department of State dated 1 November 2010, Statoil was informed that the company is no longer considered to be a company of concern with regard to its previous Iran-related activities, since the Secretary of State chose to apply the "Special Rule" in the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010.

See the section Risk review - Risk factors - Risks related to our business for additional information about the risk of sanctions relating to activities in Iran.

3.2.6.3.3 Libya

Due to political unrest in February 2011, Statoil's operations were suspended in Libya. Work is now ongoing to restore production in full on the Murzuq and Mabruk oil fields.

Due to the outbreak of political unrest in Libya, Statoil's Libyan operations were suspended in February 2011 and the fields stopped production on 21 February (Murzuq) and 26 February (Mabruk). Statoil's office in Libya was closed on 20 February 2011. All Statoil expatriate staff and their families were safely evacuated from the country. The local staff were paid wages during the unrest and, as order was restored, they were involved in the reestablishment of the office in the capital, Tripoli. The office was opened 20 March 2012.

The Murzuq field resumed production on 13 November 2011. The NC 186 licence in the Murzuq area consists of seven fields (A, B, D, H, I/R, J and K). Akakus Oil Operations is the operating company for the Murzuq NC 186 license, with Repsol as the lead partner for the international oil companies. . Statoil's share of investments (working interest) in the NC 186 license in the Murzuq field is 10%. The oil from the Murzuq fields is transported by pipeline to the Az Zawia terminal west of Tripoli for lifting by ship.

The Mabruk oilfield resumed production in January 2012. The field is located in licence C-17 in the Sirte basin. Mabruk Oil Operations is the operating company for the Mabruk C-17 license, with Total as the lead partner for the international oil companies. Statoil's share of investments (working interest) in the c-17 license in the Mabruk field is 12.5%. The field has been producing since 1995. The Dahra south-east project was sanctioned in 2009.

Work to fully restore production is ongoing in both areas.

3.2.6.3.4 Iraq

In 2010, Statoil and Lukoil entered into an agreement with the Iraqi authorities for the development of the West Qurna 2 field. However, Statoil has now started the process of transferring its 18.75% share to Lukoil.

The parties to the contract were the Iraqi state's South Oil Company and a consortium of contractors consisting of the Iraqi state's North Oil Company (25% and state partner), Lukoil, (56.25% and operator) and Statoil (18.75%). The development and production service contract for the West Qurna 2 field was offered as a 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 mboe per day.

However, Statoil has agreed with Lukoil and the Iraqi authorities to start the process of transferring its 18.75% share in the West Qurna 2 development project to the operator Lukoil. The booked reserves have been adjusted accordingly.

3.2.6.4 Europe and Asia

Development and Production in Europe and Asia primarily comprises Azerbaijan, Russia, United Kingdom and Ireland.

Statoil is active in several partner-operated licences in this region, including the major producing fields Shah Deniz and Azeri-Chirag-Guneshli in Azerbaijan. The upstream assets in Azerbaijan are a significant supplement to Statoil's strong position as a supplier to the European gas market. Statoil is also a partner in the Shtokman gas field in Russia, together with Gazprom and Total. Shtokman is a long-term resource that can enhance our upstream gas position while making Statoil a supplier from the north east. In the United Kingdom, Statoil has several oilfields under appraisal and it holds interests in three producing fields.

3.2.6.4.1 Azerbaijan

Statoil has been present in Azerbaijan since 1992, and has invested more than USD 5 billion. The two fields Azeri-Chirag-Gunashli and Shah Deniz contribute around 100 mboe per day of equity production to Statoil.

Statoil has a 8.6% stake in the Azeri-Chirag-Gunashli (ACG) field and an 8.7% stake in the 1,760-km Baku-Tbilisi-Ceyhan (BTC) pipeline that is used to transport most of ACG oil to the southern Turkish port of Ceyhan, enabling Azeri crude to be shipped to the world markets. The ACG field is operated by BP and is governed by a production sharing agreement (PSA) signed in 1994 with a duration of 30 years. In 2011, the field produced an average of 718 mboe per day.

The Chirag Oil Project sanctioned by the ACG partnership in 2010 is progressing according to plan. The first production from this project is scheduled for late 2013, and it is planned to add some 185 mboe per day in new production to ACG.

In addition to the share in ACG, Statoil has a 25.5% share in the Shah Deniz gas and condensate field, and a 25.5% share in the South Caucasus Pipeline, which transports the Shah Deniz gas from Azerbaijan through Georgia to the eastern Turkish border. The condensate from Shah Deniz is transported through the BTC pipeline to Ceyhan in Turkey. The Shah Deniz field is operated by BP and Naftiran Intertrade Company (NICO) has a 10% interest in this field. Statoil runs the Azerbaijan Gas Sales Company, which has been established to manage gas allocation and sales to customers in Azerbaijan, Georgia and Turkey. Statoil is also the commercial operator of the South Caucasus Pipeline Company, which is responsible for the commercial operations around the South Caucasus Pipeline. Shah Deniz Phase 1 has been in production since 2006. Shah Deniz produced 115 mboe per day of gas and 38 mboe per day of condensate in 2011. The PSA expires in 2031.

In 2007, the Shah Deniz partners decided to start maturing the second phase of the Shah Deniz field development. The concept for the Shah Deniz Phase 2 field development was agreed by the partners in late 2010. Project development operator BP estimates annual production from Shah Deniz Phase 2 to be 16 bcma of gas per year and about 100 mboe per day of condensate. The current plan is to make a final investment decision around the middle of 2013. That would mean first gas from the Shah Deniz Phase 2 development in late 2017.

The licences in Alov, Araz and Sharg expired in 2011 and were handed back to the State Oil Company of Azerbaijan (SOCAR). Operator BP has not been able to do any field work on these licences, as they are located in the disputed zone between Azerbaijan and Iran.

3.2.6.4.2 Russia

Statoil has been present in Russia since the late 1980s. We have a 24% ownership interest in Shtokman Development AG, which is responsible for the Shtokman development phase one. We also have a 30% ownership interest in the Kharyaga oilfield.

Field in production
The Kharyaga field is located onshore in the Timan Pechora basin in north-west Russia. The field is being developed under a production sharing agreement (PSA). Statoil has a 30% equity interest in Kharyaga. Kharyaga produced 8.9 mboe per day of oil in 2011.

During 2011, production has been maintained at plant capacity level. Phase 3 and the Phase 3 Extension development are ongoing, and 24 wells have been drilled.

Field under planning
The Shtokman gas and condensate field is located in the Russian Barents Sea. The agreement with Gazprom gives Statoil a 24% equity interest in Shtokman Development AG (SDAG), in which Gazprom (51%) and Total (25%) are the other two partners. The owners have seconded personnel to SDAG, which is responsible for the planning, financing, constructing and operation of the infrastructure that is necessary for the first phase of the development. SDAG will own and operate the infrastructure for 25 years from the start of commercial production. SDAG is currently finalising the technical concept and is preparing for the execution of 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 (FID) pursuant to SDAG's plans. In December 2011, the FID was postponed until 31 March 2012.

3.2.6.4.3 United Kingdom

Statoil has several oilfields under appraisal in the United Kingdom (UK) and it holds interests in three producing fields.

Fields in production
The Alba oilfield, located in the central part of the UK North Sea, is operated by Chevron. Statoil has a 17% interest in this mature field. Alba produced 4.3 mboe of oil per day in 2011.

The Schiehallion oilfield is located west of the Shetland Islands. BP is the operator and Statoil has a 5.9% interest. In July 2011, the Schiehallion partnership sanctioned the redevelopment of the field and the acquisition of a new FPSO vessel. This is expected to extend production until at least 2035. Schiehallion produced 0.8 mboe of oil and gas per day in 2011.

Jupiter is a gas field located in the southern part of the UK North Sea. ConocoPhilips is the operator of the field, and Statoil has a 30% interest. Jupiter production is currently very low (~ 5 million standard cubic feet per day). The joint venture is discussing abandonment plans. Jupiter produced 0.4 mboe of gas per day in 2011.

Discoveries under appraisal
Statoil is the operator for and holds a 81.6% interest in Bressay. Statoil is also operator for Mariner (65.1% interest) and Mariner East (62.0% interest). Mariner East is a potential subsea tieback to the main Mariner platform. All three fields are heavy oil.

Rosebank, a discovery made by Chevron in 2004, is located west of the Shetland Islands. Statoil has a 30% interest in this field. The partnership is currently working towards concept selection for the field development.

3.2.6.4.4 Ireland

Statoil has 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 was sanctioned in 2001, and work towards the first gas is ongoing.

The project has been delayed for some years mainly due to lengthy consideration of planning applications both for the terminal and the onshore section of pipeline and a controversial challenge that Shell experienced in 2005 when a small number of local landowners refused to allow Shell E&P access to their land to proceed with construction work relating to the onshore section of pipeline.

Now the construction of the gas terminal is 95% complete and preservation work is ongoing to maintain the condition of the equipment pending commissioning. Planning permission and other governmental consents for the tunnel required to lay the onshore pipeline under the estuary were obtained during the first quarter of 2011. Work started on the tunnel launch compound in July once all preconditions had been met. Groundwork is ongoing and the civil engineering contractor has been mobilised to site.

Six subsea wells have been drilled and the pipeline from field to shore is in place. The link line connecting the terminal to the Irish gas grid is in place. Production start-up is now anticipated to take place in 2014 at the earliest.

3.3 Marketing, Processing and Renewable Energy (MPR)

3.3.1 Introduction to MPR

Marketing, Processing and Renewable Energy (MPR) is responsible for the transportation, processing, manufacturing, marketing and trading of crude oil, natural gas, liquids and refined products, and for developing business opportunities in renewables.

We run two refineries, two gas processing plants, one methanol plant and three crude oil terminals. We are also responsible for developing a profitable renewable energy position.

MPR is also responsible for marketing gas supplies originating from the Norwegian state's direct financial interest (SDFI). In total, we are responsible for marketing approximately 80% of all Norwegian gas exports.

In 2011, we sold 36.1 bcm (1.3 tcf) of natural gas from the Norwegian continental shelf (NCS) on our own behalf, in addition to approximately 33.5 bcm (1.2 tcf) of NCS gas on behalf of the Norwegian state. Statoil's total European gas sales, including third-party gas, amounted to 79.8 bcm (2.9 tcf) in 2011, of which 39.5 bcm (1.4 tcf) was gas sold on behalf of the Norwegian state. That makes us the second-largest gas supplier to Europe.

In 2011, we also sold 671 million barrels of crude oil and condensate, approximately 15 million tonnes of refined oil products from our own refineries, and 14 million tonnes of natural gas liquids (NGL). Tjeldbergodden produced approximately 865,000 tonnes of methanol. Our international trading activities make us one of the world's largest net crude oil sellers.

The MPR business activities are organised in the following business clusters:
-Natural Gas
-Crude oil, liquids and products
-Processing and manufacturing
-Renewable energy

3.3.2 MPR key events 2011

In 2011, the gas market was characterised by volatility in both market prices and customer off-take. Refinery margins and trading margins were weaker than in 2010. The operation of facilities has been stable, and HSE results have improved since 2010.

• Sales of entitlement gas totalled 39.0 billion cubic metres (bcm), a decrease of 2.7 bcm compared with 2010.
• The on-stream factor (excluding Kårstø and Kollsnes) was 95.6% in 2011, compared with 91.1% in 2010. The available yearly capacity for Kårstø and Kollsnes was 93.3% in 2011, compared with 90.4% in 2010.
• Turnarounds were carried out at Tjeldbergodden, Kalundborg, Sture and Kollsnes in 2011, mainly according to plan and with good HSE performance.
• In June 2011, Statoil entered into an agreement for partial divestment of its ownership interest in Gassled, from 29.1% to 5.0%. The divested interest of 24.1% was purchased by the financial investment company Solveig Gas Norway AS. The transaction was approved by the government authorities in December 2011.
• Statoil and Centrica signed a long-term gas sales agreement for the delivery of 5 bcm gas per year to the UK market from 2015 to 2025. This new long-term gas sales agreement follows an existing agreement between Statoil and Centrica that expires in 2015.
• The first volumes were lifted from the Peregrino field in Brazil on 17 June.
• Electricity production from the Sheringham Shoal wind farm commenced in August.
• Large parts of Statoil's onshore wind power activities in Norway were sold. The transactions were closed in September.

3.3.3 Natural Gas

3.3.3.1 Natural Gas

The Natural Gas business cluster is responsible for Statoil's marketing and trading of natural gas worldwide, for power and emissions trading and for overall gas supply planning and optimisation.

Natural Gas (NG) is also responsible for marketing gas originating from the SDFI. NG also manages Statoil's asset ownership in gas infrastructure, such as the processing and transportation system for Norwegian gas (Gassled).

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

In 2011, we sold 36.1 bcm (1.3 tcf) of natural gas from the NCS on our own behalf, in addition to approximately 33.5 bcm (1.2 tcf) of NCS gas on behalf of the Norwegian state. Statoil's total European gas sales, including third-party gas, amounted to 79.8 bcm (2.9 tcf) in 2011 of which 39.5 bcm (1.4 tcf) was gas sold on behalf of the Norwegian state.

In addition, we sold 5.5 bcm (0.2 tcf) of gas originating from our international positions, mainly in Azerbaijan and the USA, of which 2.7 bcm (0.1 tcf) was entitlement gas.

We are a significant shipper in the NCS pipeline system owned by Gassled*, which is the world's largest offshore gas pipeline transportation system, totalling approximately 8,100 kilometres. This network links gas fields on the NCS with processing plants on the Norwegian mainland and with terminals at six landing points located in France, Germany, Belgium and the UK. It thereby gives us access to customers throughout Europe.

*Statoil had a 5% ownership interest in the system at the end of 2011.

3.3.3.2 The gas market

In 2011, the nuclear accident in Japan led to greater gas power generation and higher LNG imports from European sources, while the US gas market became self-sufficient with a relatively low cost shale gas supply.

In the longer term, we believe that natural gas will be an increasingly attractive commodity. According to the IEA World Energy Outlook 2011, estimated global gas consumption in 2035 will be 55% higher than 2009 levels, reaching 4,750 bcm per year.

Europe
We market and sell our own gas as well as the Norwegian state's gas volumes. We also market gas sourced from producing areas other than the NCS. Other major gas suppliers to Europe are Gazprom in Russia, Sonatrach in Algeria, GasTerra in the Netherlands and, since 2010, Qatari LNG. We believe that Norwegian natural gas exports will remain highly competitive due to their reliability, access to a 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 carbon dioxide than coal and oil. During 2011, we increased our efforts to develop new marketing channels, targeting both end-user segments and power producers, resulting in new short-term and longer-term contracts.

European natural gas prices were driven by a number of factors. Strong European storage injection levels coupled with the pull of LNG volumes towards Asia following the events in Japan supported prices through the summer, but a warm start to the winter of 2011-2012 contributed to low demand, relatively low winter prices and low storage withdrawals.

The interplay between coal and gas-fired power plant dispatch, which forms the basis for the coal switching price, was a key determinant of European gas prices throughout 2011. Coal prices remained relatively stable during the first three quarters of 2011 but fell by nearly USD 15/tonne in the fourth quarter of 2011 due to lack of support from Asian coal demand and concerns about economic growth weighing on commodity markets. Gas prices, in turn, remained above the coal switching price for most of the year due to the global tightness in LNG availability. The decline in coal prices, combined with a slide in carbon emissions prices, effectively meant that coal strengthened its position as the preferred fuel for power generation and reduced demand for gas. As a result, gas-to-power demand in 2011 was on average 22% lower than 2010 levels.

We anticipate continued high demand for LNG over the next five years and expect that the pending nuclear policy decisions in Japan and other countries with nuclear power will create uncertainty with regard to the market direction. As we believe global demand for natural gas will continue to grow, predominantly in Asia, we expect that any global LNG oversupply will diminish towards the middle of the decade as demand growth outpaces supply, despite new production capacity coming on stream. We expect European demand to grow due to increased demand for gas for power generation.

Liberalisation creates new opportunities and new business models in the gas sector, both with regard to added value as a result of efficiency gains and with regard to building a more substantial portfolio of sales directly aimed at large industrial customers and local distribution companies. Access to downstream markets has traditionally presented challenges, since capacity has been booked by incumbent companies. The Third Package (draft legislation from the EU) will introduce measures that should address capacity congestion and result in gradual improvements in market access and liquidity as the legislation is implemented across Europe. The integration of the gas and electricity markets also presents us with new business opportunities.

The EU is set to import some 75% of its natural gas by 2020 due to declining domestic gas production. In order to diversify supplies, European countries and companies are actively seeking alternative supply solutions. Moreover, Europe will need additional new sources of natural gas, since the global LNG market is expected to divert more gas to the growing Asian economies. We believe we are well positioned to supply part of this additional natural gas demand.

The gas market in OECD Europe is expected to grow from the current level of 550 bcm to approximately 630 bcm by 2030. The competitiveness of gas is expected to drive its share of total energy consumption from 25% today to 29% in 2030. Most of this growth is expected from increasing installation of gas power generation capacity.

Since the European energy markets are continuously facing changes in regulation and structures, we believe that natural gas will play an increasingly important role. We expect this trend to be reinforced as Europe pursues its long-term target of moving to a low-carbon economy, as reflected in the European Commission's "Energy Roadmap 2050".

North America
In North America, natural gas markets continued to be dominated by increasing domestic production from unconventional resources. Though demand was up again in 2011, by over 3% compared with the same period in 2010, this was almost entirely weather driven, with some increase from price-sensitive substitution of gas for coal in the power-generation sector. Even with this support, prices only traded in the USD 4-5 per million BTU range for the first three quarters of 2011, and, with the warmer weather at the end of the year, traded in the USD 3-4 range. Despite these prices, production continued to rise, increasing by 7%. Rig counts, a primary leading measure, stayed high as joint ventures and natural gas liquids yields have supported gas-directed drilling. With the relatively warm start to the winter of 2011-12 and record high storage levels, it appears that prices will continue to be under pressure throughout 2012.

The natural gas system in North America still shows few concrete signs of the structural changes in demand required to fully realise the benefits of the unconventional revolution in the USA, but there are more positive indications. The low-price environment and large global fuel spreads are incentivising new outlets for domestic gas resources. Most notable is Cheniere Energy's proposed LNG export facility, which has received an export licence, signed both off-take and construction agreements, and appears to be on track to commence operations in the 2015-16 timeframe. This would eventually make it the first such facility in the continental USA. Further plants look to have a more difficult time, due to the commercial arrangements that most proposed builders are asking off-take customers to accept, and potential export licensing headwinds. These new markets for US natural gas are needed to firm up prices, which would positively impact producers.

3.3.3.3 Gas sales and marketing

Statoil is a long-term, reliable natural gas supplier with a strong position in some of the world's most attractive markets.

Europe
The major export markets for gas from the NCS are Germany, France, the UK, Belgium, Italy, the Netherlands and Spain. The gas is mostly sold through long-term take-or-pay contracts. Our main customers are large national or regional gas companies such as E.ON Ruhrgas, GdF Suez, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), Distrigaz and GasTerra. We also market our gas to large industrial customers, power producers and wholesalers, in addition to participating in the spot market.

Our group-wide gas trading activity is mainly focused on the UK gas market (National Balancing Point), which is a significant market in terms of size and the most liberalised market in Europe. We also take part in other liquid trading points, such as the PegN (Peg Nord) in France, TTF (Title Transfer Facility) in the Netherlands, the Zeebrugge Hub in Belgium and Gaspool/NCG in Germany.

Statoil has end-user sales business based in Belgium and the UK, serving major customers in Belgium, the UK, the Netherlands and France.

In 2004, Statoil (UK) Limited and SSE Hornsea Limited (subsidiaries of Statoil 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, near the Easington terminal. The storage facility was officially opened on 27 June 2011. It comprises nine underground caverns that have been formed by using seawater to leach out salt water deposits around two kilometres underground. Statoil (UK) Limited owns one-third of the storage capacity being developed, of which the Norwegian State's direct financial interest (SDFI) will have access to 48.3%. The facility has been developed and is operated by SSE Hornsea Limited. Six of the nine caverns at Aldbrough are already storing gas. Full commercial operation of the nine-cavern facility is scheduled for 2012. When fully commissioned, Aldbrough will have the capacity to store around 330 million cubic metres of gas.

In Germany, we hold a 30.8% stake in the Norddeutsche Erdgas-Transversale (Netra) overland gas transmission pipeline, and a 23.7% stake in Etzel Gas Storage through our subsidiary Statoil Deutschland. Etzel Gas Storage is currently increasing its working gas capacity by 10 additional caverns, one of which was completed in 2009. Eight caverns were handed over to commercial operation in 2010, and the last one was handed over in 2011. All partners in Etzel Gas Storage are participating in this project.

USA
The USA is the 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 producers. SNG has two long-term capacity contracts with Dominion Resources Inc., which owns the Cove Point LNG regasification terminal in Maryland. The first is for a one-third share of Cove Point capacity (LTD1), which is equivalent to approximately 3.2 bcm per year. As of 31 December 2011, the second is for 100% of the Cove Point Expansion (CPX) capacity of approximately 7.7 bcm per year. This is equivalent to a total regasification capacity of 10.9 bcm per year. This long-term capacity agreement was renegotiated in December 2010 and approved by the boards of Statoil ASA and Dominion Resources Inc. in January 2011. The agreement was approved by the US government in April 2011. As a consequence, Statoil's commitments relating to the regasification capacity at CPX have been significantly reduced.

The CPX capacity also includes downstream pipeline capacity from the Cove Point terminal to Leidy in Pennsylvania and gas storage capacity at Leidy.

Through Statoil, SDFI pays for a share of the capacity at the Cove Point regasification terminal, downstream pipeline capacity and storage capacity. LNG is sourced from the Snøhvit LNG facility in Norway and from third-party suppliers.

SNG also markets the equity production from Statoil's assets in the US Gulf of Mexico.

In 2008, Statoil entered into a strategic agreement with Chesapeake Energy Corporation relating to Marcellus shale gas. This strengthens Statoil's natural gas position in the USA by providing access to large gas reserves geographically near the north east, which, historically, is the highest-paying gas market. This also results in a significant increase in the volume of gas marketed and traded by Statoil in the USA.

In 2009, SNG 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 two bcm per year/200,000 mcf/day directly from the Northern Marcellus production area to New York City and surrounding areas. The expected in-service date is late 2013 or early 2014.

In 2010, SNG concluded a transportation agreement with National Fuel Gas Supply Corporation for up to 3.2 bcm per year (320,000 mcf/day). This agreement will enable Statoil to transport gas on a direct path from the Northern Marcellus production area to the US/Canadian border at Niagara Falls, thereby providing access to the attractive urban areas of eastern Canada. The expected in-service date is November 2012.

In December 2010, Statoil and Talisman formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale. NG will market Statoil's share of the gas production. The Eagle Ford equity production is a valuable addition to Statoil's oil and gas market portfolio in North America.

In 2011, Statoil Natural Gas LLC has entered into two long-term gas sales agreements with a major Canadian gas distributor. Under both agreements, Statoil will deliver gas to our counterparty at Niagara Falls on the US-Canadian border. Our counterparty has contracted for transportation capacity on the Trans Canada Pipeline (TCPL) from Niagara Falls to the Enbridge Central Delivery Area (ECDA), which covers the greater Toronto market area. The start of delivery for both deals is November 2012, which aligns with the in-service date for Statoil's Northern Access transportation capacity.

Azerbaijan
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 Shah Deniz stage 1 gas volumes. In addition, Statoil participates in the gas export negotiation committee for the Shah Deniz 2 project, which is led by the Azerbaijani state oil company SOCAR. Azerbaijan, Georgia and Turkey are part of the gas sales portfolio for stage 1 in which Turkey is the main market. Gas is purchased and sold through the Statoil-operated Azerbaijan Gas Supply Company (AGSC), and the gas is shipped to customers through the South Caucasus Pipeline (SCP), which runs from the Sangachal terminal in Azerbaijan via Georgia to the Georgian/Turkish border. Shah Deniz stage 1 gas transportation and sales reached 6.3 bcm in 2011, 3.7 bcm of which reached Turkey.

The stage 2 development of Shah Deniz is currently in the late stages of the concept selection phase of operator BP's capital value process. Field reserves support stage 2 production. In October 2011, the governments of Turkey and Azerbaijan signed an intergovernmental agreement relating to the sale of gas to Turkey and transportation through Turkey to the European markets. On the same date, the Shah Deniz Consortium entered into a gas sales agreement for 6 bcm per year and a transit agreement for 10 bcm per year with Botas in Turkey. Together with key partners in Shah Deniz, Statoil is currently negotiating sales contracts with several marketing companies in Europe and assessing alternative routes for bringing the gas into Europe.

Algeria
Statoil has a 31.85% share in In Salah and a 50% share in In Amenas, Algeria's third-largest and fourth-largest gas developments, respectively. All of the gas produced from In Salah is sold under long-term contracts.

LNG
The LNG production plant at Melkøya, the first and only large-scale LNG production facility in Europe, underwent technical maintenance from the end of April to the middle of July in 2011. The main scope was the replacement of a sea water cooler and the replacement of two electrical motors in the main compressors. LNG production has been more regular since the maintenance, and the facility's production is currently stable at design capacity. Market demand for LNG has been robust in 2011. Due to continued low prices in the USA, only a minimum number of cargoes, based on operational necessity, have been delivered to the USA. The remaining LNG portfolio has been diverted away from the US market into higher-priced markets in Europe and Asia. Statoil will continue to pursue its ambition to grow a global LNG portfolio, including non-equity LNG supply and commitments.

3.3.3.4 Norway's gas transport system

Over the last 30 years, the Norwegian gas pipeline system has been developed into an integrated system connecting gas-producing fields with receiving terminals in Europe via processing plants on the Norwegian mainland.

The total length of Norway's gas pipelines is currently 8,100 kilometres. All gas pipelines on the NCS with third-party customers are owned by 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 2011, the Gassled system transported 94.2 bcm (3.3 tcf) of gas to Europe.

Statoil's ownership interests in Gassled have been adjusted twice in 2011. With effect from 1 January 2011, Petoro's interests increased by approximately 7% and all other parties reduced their interests proportionally. Statoil's ownership was reduced to 29.1% from 1 January 2011. Similar adjustments were made to the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA.

In June 2011, Statoil entered into an agreement for partial divestment of its ownership interest in Gassled from 29.1% to 5.0%. The divested interest of 24.1% has been purchased by the financial investment company Solveig Gas Norway AS. The transaction was approved by the government authorities in December 2011, and the divestment date was 30 December 2011. The divestment does not affect Statoil's position as the largest shipper in Gassled.

When new gas infrastructure facilities are merged into Gassled, the ownership interests are adjusted in relation to the relative value of the assets and each owner's relative interest. Hence, Statoil's future ownership interest in Gassled may change as a result of the inclusion of new infrastructure.

Statoil is the technical service provider (TSP) for Gassco with respect to the Kårstø and Kollsnes processing terminals, as well as for most of the gas pipeline and platform infrastructure system.

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

The tables below present facts about the NCS gas pipelines, including transportation routes and daily capacities, and about our ownership in Gassled and receiving terminals.

3.3.3.5 Kårstø gas processing plant

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

Kårstø processes rich gas and condensate (light oil) from the NCS received via the Statpipe pipeline, the Åsgard Transport pipeline and the Sleipner condensate pipeline. The processing plant currently has a rich gas capacity of 88 MSm3/d. Products produced at Kårstø include ethane, propane, isobutane, normal butane, naphtha and stabilised condensate. When all of these products have been separated from the rich gas, the remaining gas (dry gas) is sent to customers via the Statpipe, Europipe II and Rogass pipelines. The processing plant currently has a dry gas export capacity of 77 MSm3/d.

Since 2008, the Kårstø processing plant has been undergoing comprehensive upgrading in order to meet safety and technical requirements, and future needs. The Kårstø Expansion Project (KEP) is the project name for several projects aimed at making the Kårstø facilities more robust and ensuring safe and efficient operation. The project investment is estimated to be around NOK 6 billion. The plan is to complete the remaining sub-projects in 2012.

3.3.3.6 Kollsnes gas processing plant

As technical service provider, Statoil is responsible for the operation, maintenance and further development of the Kollsnes gas processing plant on behalf of the operator Gassco.

The Kollsnes plant was initially built in 1996 to receive gas from the Troll field in two 36-inch pipelines. The treatment process at Kollsnes involves separating out the NGL, and compressing the dry gas for export via Statpipe, Zeepipe, Europipe I and Franpipe. The processing capacity at Kollsnes has increased several times since the facility became operational. In 2010, the Kollsnes projects (KOP) started with the aim of maintaining the high regularity of the plant. In addition, a third 36-inch pipeline from the Troll field to Kollsnes was installed. Kollsnes also receives gas from the Visund, Kvitebjørn and Fram fields. These volumes are processed through the NGL plant. The Kollsnes gas processing plant currently has a design capacity of 143 MSm3/day.

The Troll field is a swing producer based on customer off-take. During the year, monthly off-take generally varies between 25% and 100%.

3.3.3.7 Gas sales agreements

Statoil manages, transports and markets approximately 80% of all NCS gas and has a growing US gas position. In Europe, the gas is sold through long-term contracts with major European utilities, and a growing proportion is direct sales.

These direct sales are carried out with large industrial users, power producers and local distribution companies, and through short-term contracts and trading on European liquid marketplaces (hubs) in the UK and on the Continent. In the USA, gas is sold through a mix of contracts and trading on liquid marketplaces.

Due to the relatively large size of the NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, a large proportion of Statoil's gas sales contracts are long-term contracts that typically run for 10 to 20 years or more.

The long-term contracts contain flexibility arrangements guaranteeing a minimum annual off-take - the so-called take-or-pay quantity - and they provide daily flexibility for the customer. Prices in traditional long-term contracts are generally tied to a formula based on the prices for substitute fuels for natural gas, typically heavy fuel oil and gas oil. In our gas portfolio, we also have gas sales contracts that are priced with reference to a gas spot market index. There can be significant price fluctuations during the life of the contract. Most of the traditional long-term gas contracts contain contractual price adjustment mechanisms that can be triggered by the buyer or seller at regular intervals, or under certain given circumstances. In the last two years, the outcome of such discussions for values covered by long-term sales contracts has generally been the introduction of a small proportion of spot price indexation and/or limited reduction in the volume obligation for the buyer, and increased access to the continental spot markets for Statoil.

Statoil expects to continue to optimise the market value of the gas delivered to Europe through a mix of long-term contracts and short-term marketing and trading opportunities. This is done both as a response to customer needs and in order to capture new business opportunities as the markets become more liberalised.

3.3.4 Crude oil, liquids and products

3.3.4.1 Crude oil, liquids and products

Crude oil, liquids and products (CLP) adds value through the processing and sale of the group's and the Norwegian State's direct financial interest (SDFI) production of crude oil and natural gas liquids.

CLP is responsible for the group's transportation, marketing and trading of crude oil, natural gas liquids and refined products, including methanol. We are responsible for the commercial operation of two refineries (Mongstad, Norway and Kalundborg, Denmark) and the commercial operation of two crude oil terminals (Mongstad, Norway and South Riding Point, Bahamas). Our international trading activities make us one of the world's largest net crude oil sellers.

In 2011, MPR sold 671 million barrels of crude oil and condensate, approximately 15 million tonnes of refined oil products from our own refineries and 14 million tonnes of natural gas liquids (NGL).

3.3.4.2 The oil market

The year 2011 had strong prices for Brent crude and significant volatility. The supply disruptions caused by the political turmoil in North Africa and the Middle East were important factors. The market for physical crude was tight and in backwardation.

The 2011 price for Brent crude averaged USD 111 per barrel, more than USD 30 higher than in 2010, and also significantly higher than the USD 97 per barrel from the previous record year of 2008. After starting 2011 at around USD 95 per barrel, Brent reached highs above USD 125 per barrel in April, and thereafter oscillated between USD 100 and USD 120 per barrel.

There are two main reasons why prices were strong in 2011. In 2010, oil demand growth came in at a record-high level of 2.9 mboe per day, as world demand rebounded quickly from the 2008-2009 recession, led by strong growth in non-OECD countries. This tightened global oil inventories sharply during the fourth quarter of 2010 and the first quarter of 2011, and we entered 2011 without much of the excess capacity that had formed in the oil market during the financial crisis of 2008-2009.

The "Arab spring" raised the general level of uncertainty attached to oil supplies from this region, and the outbreak of the Libyan civil war in February took 1.5 mboe per day of light sweet crude off the market. In addition, a string of production disruptions in some key producing countries wiped out much of the anticipated oil supply growth. Saudi Arabia and other key Persian Gulf member states responded by raising oil production, but not by enough to cover the entire loss of Libyan volumes. As a consequence, global oil inventories were reduced further. By late summer, they were near five-year lows, but increased slightly during the fourth quarter of 2011 compared to five-year lows.

As crude supply has lagged behind demand throughout 2011, the market for physical crude has been very tight. The market has been in backwardation throughout the year. The loss of Libyan crude exports as well as the many minor disruptions in North Sea production also led to strong premiums for North Sea light sweet crudes, and for Brent versus other global markers. In the USA, a lack of infrastructure to bring the rapidly increasing volumes of shale oil produced in the Midwest region to market led to sharp discounts for the inland WTI crude marker, which at some points traded as much as USD 25 per barrel below Brent crude. This dislocation has eased after the announcement that a key pipeline will be reversed to enable crude flows south to the US Gulf Coast. However, rapid changes in US inland oil balances will continue to cause turbulence on the North American crude market.

Increasing worries about the state of the global economy and about the sovereign debt situation in Europe and the USA capped the rally in crude prices and have led to significant volatility over the course of the year. However, due to the tight fundamentals in the oil market, crude has remained strong despite the increasing economic and financial headwinds. The nuclear disaster in Fukushima in Japan in March had a mixed effect on markets and added to volatility, but, over time, it has led to additional oil demand for power generation after most nuclear plants were taken off the grid for security checks.

3.3.4.3 Marketing and trading

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

We market Statoil's own volumes and the SDFI's equity production of crude oil and NGL, in addition to third-party volumes. In 2011, our total sales of crude and condensate were equivalent to 671 million barrels, including supplies to our own refineries. The main crude oil market for Statoil is north-west Europe. In addition, we sell volumes to North America and Asia. Most of the crude oil volumes are sold in the spot market based on publicly quoted market prices. Of the total 671 million barrels sold in 2011, approximately 41% were Statoil's own equity volumes.

The Product and Refinery Optimisation (PRO) unit is responsible for optimising and marketing Statoil's total production of 15 million tonnes of refined products from the refineries at Mongstad (Norway) and Kalundborg (Denmark). We also market the 865,000 tonnes of methanol from the Tjeldbergodden plant (Norway). In addition to equity volumes, we sell approximately 14 million tonnes of products in north-west Europe, the USA, and in the trans-Atlantic basin.

We are responsible for optimising commercial utilisation of the crude terminal located at Mongstad and the South Riding Point crude oil terminal in the Bahamas. We are also responsible for Statoil's crude and LPG liftings at the Sture terminal.

Marketing activities are also optimised through lease contracts and long-term agreements for the utilisation of third-party assets.

3.3.4.4 Terminals

Statoil holds the lease for the South Riding Point crude oil terminal in the Bahamas until 2049, which includes oil storage as well as loading and unloading facilities. We also operate the Mongstad terminal and have shared ownership with Petoro.

South Riding Point
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. The overall occupancy was 10% in 2011 as the terminal was closed for upgrading in the first quarter and had limited operations during the second and third quarters. The total throughput in 2011 was approximately 25 million barrels.

In 2011, we upgraded the terminal to enable the blending of crude oils, including heavy oils. The blending is carried out onshore, and from ship to ship at the jetty.

This terminal is intended to both support our global trading ambitions and improve our handling capacity for heavy oils. We expect the new blending facilities and full terminal capacity to strengthen both our marketing and trading positions in the North American market. The terminal is also 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.

Mongstad terminal
Statoil operates the Mongstad terminal, which has storage capacity of 9.4 million barrels of crude. Statoil owns 65% of the terminal and Petoro the other 35%.

Crude oil is landed at Mongstad via two pipelines from Troll, by dedicated vessels from Heidrun and by crude vessels from the market.

The terminal supports Statoil's global trading, blending and transhipment of crudes and is an important tool in the marketing of North Sea crudes.

3.3.5 Processing and manufacturing

3.3.5.1 Processing and manufacturing

Processing and manufacturing is responsible for the safe, reliable and efficient operation of Statoil's onshore facilities.

This includes the refineries at Mongstad and Kalundborg, the methanol production plant at Tjeldbergodden and the gas processing plants at Kårstø and Kollsnes. It does not include the LNG plant at Melkøya, however. That plant is operated by DPN.

Processing and manufacturing is also responsible for the operation of the Oseberg Transportation System and the oil terminal at South Riding Point in the Bahamas.

We are the majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil and condensate distillation capacity of 220,000 barrels per day. We are the sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118,000 barrels per day. In addition, we have rights to 10% of production capacity at the Shell-operated refinery in Pernis in the Netherlands, which has a crude oil distillation capacity of 400,000 barrels per day. Our methanol operations consist of an 81.7% interest 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% interest), including the Sture crude oil terminal. The terminal was built to receive crude from the Oseberg field by pipeline. Since 2003, it has also received crude from the Grane field pipeline. Oseberg blend (after stabilisation), Grane blend and some LPG are exported, while some LPG and naphtha is piped to Mongstad combined with condensate from the Kollsnes gas processing plant.

Processing and manufacturing performs the role of technical service provider (TSP) for the Kårstø and Kollsnes gas processing plants, in accordance with the technical service agreement between Statoil and the operator Gassco. Processing and manufacturing also performs the TSP role for Transport Net (Norway's gas transport system) and the oil terminal at South Riding Point, Bahamas. For further information on Kårstø, Kollsnes, Transport Net and South Riding Point, see Natural Gas and Crude oil, liquids and products, respectively above.

The following table shows operating statistics for the plants at Mongstad, Kalundborg and Tjeldbergodden.