STATOIL ASA 20-F 2011
Documents found in this filing:
Commission File No. 1-15200
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This section is a presentation of our performance in 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.
Statoil's Annual Report on Form 20-F for the year ended 31 December 2010 ("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
2010 was an important year strategically for Statoil. We demonstrated value creation by executing agreements for the partial sale of our operated assets in Brazil and Canada, sanctioned nine projects and executed a successful IPO of our retail activities.
Whilst production volumes were below our expectations in the second part of the year due to high maintenance, specific operational issues and reduced production permits, we continued 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 IFRS as adopted by the European Union (EU).
Production volumes fell below expectations in the second half of the year due to high maintenance, specific operational issues and reduced production permits. Nevertheless, Statoil continued to deliver strong financial results and cash flows in 2010.
Statoil was awarded shares in eight production licences on the Norwegian Continental Shelf (NCS), comprising six North Sea licences and two Norwegian Sea licences. We will be operator of six of the licences.
In the third licence round for offshore wind parks in the UK, the Forewind consortium, of which Statoil is a member, was awarded the rights to develop Dogger Bank, which was the largest zone in the round.
Lukoil and Statoil signed a contract relating to the West Qurna 2 field in Iraq. First oil is scheduled for the end of 2012 and full production is expected for a period of 13 years from 2017.
Our two Peregrino oil platforms were towed into position off the coast of Brazil. First oil is expected towards the end of the first quarter 2011.
We extended our portfolio in the US sector of the Gulf of Mexico. Statoil was the highest bidder on 21 licences.
We signed an investment contract worth USD 6 billion with ACG partners relating to the development of the Chirag oil project in the Azeri sector of the Caspian Sea.
Low-pressure production methods have increased oil recovery from the Oseberg field in the North Sea.
We increased our share in the St. Malo development in the Gulf of Mexico to 21.5% by exercising our first option in connection with the sale of Devon's share of the development.
We entered transport contracts with New Jersey and New York City for the transport and delivery of natural gas produced in the northern part of the Marcellus shale gas region in Pennsylvania (PA).
Statoil launched a new technology plan designed to reduce CO2 emissions from oil sand production, with the intention of achieving reductions of more than 40% by 2025.
Njord licence partners approved the development of the Njord North West flank, a development that will increase the total recoverable reserves and extend Njord's lifetime by up to two years.
We announced that we had found oil and gas at the Fossekall prospect north of the Norne field in the Norwegian Sea.
The Macondo accident in the Gulf of Mexico caused the loss of 11 lives and an extensive oil spill. US authorities imposed restrictions following the accident, leading to the temporary closure of two of our drilling operations in the area.
Statoil and EGL announced the transfer of a combined share of 15% in the Trans Adriatic Pipeline Project to E.ON Ruhrgas. The Trans Adriatic Pipeline will provide a link between the existing and planned pipeline systems for natural gas in South West Europe and the pipeline systems in West Europe.
We signed an agreement for the transport of gas through a pipeline from the northern part of the Marcellus shale gas region in Pennsylvania to Niagara on the US-Canadian border. The agreement secures us access to a central, inter-state pipeline system.
On 19 May a situation arose involving a change in pressure and the loss of drilling fluid in well C-06 on the Gullfaks C platform in the North Sea. We demobilised 89 employees to the Gullfaks A platform by helicopter. Our investigation and the report of the Petroleum Safety Authority Norway concluded that the planning of the drilling and completion operations in the well had been out with deficiencies in planning and risk assessment. Following this incident, we implemented a number of measures.
The first floating platform to be supplied with electricity from the mainland, Gjøa, was towed to its location on the west coast of Norway. The solution will reduce CO2 emissions by 210,000 tonnes of carbon dioxide per year.
The plan for the development and operation of the Gudrun field in the North Sea was approved by the Norwegian parliament in June. We expect that the traditional steel jacket will be completed and installed in the summer of 2011 before well drilling commences in October 2011. Production start-up is planned for the first quarter of 2014.
Work commenced on the Sheringham Shoal offshore wind farm in the UK, jointly owned by Statoil and Statkraft. The wind farm, scheduled to come on stream in 2011, will supply an estimated 200,000 UK households with electricity.
Statoil and Poweo of France signed a 20-year agreement relating to the supply of natural gas to Poweo's planned 400 MW combined cycle gas turbine (CCGT) power station in Toul, France. The plan is for deliveries to commence on 1 October 2012.
We announced the discovery of oil and gas east of the Gudrun field.
We announced a new organisational structure effective from 1 January 2011. The rationale behind the new organisation is to simplify our way of working by having fewer internal interfaces and better defined responsibilities, an increased global perspective and improved local presence close to important investments.
Oil production commenced from the subsea field Morvin, tied back to Åsgard, in the North Sea. The field has a strategic significance for the further development and operation of our North Sea activity.
The state-run Mexican oil company Petróleos Mexicanos (Pemex) and Statoil are collaborating to reduce gas flaring on the Tres Hermanos oil field in Mexico. It was announced in October that the project is registered under the UN's Clean Development Mechanism (CDM).
We carried out an extensive oil spill protection exercise on Sørøya in West Finnmark, in northern Norway, together with Eni and Lundin, NOFO (Norsk oljevernforening for operatørselskap) and a local task force. The exercise confirmed that the emergency response preparations function as planned.
We submitted our development plan for the Valemon field to the Ministry of Petroleum and Energy. The plan involves a new, unmanned platform in the North Sea planned to come on stream in 2014.
We approved development of the major Jack/St. Malo fields in the deepwater Gulf of Mexico together with operator Chevron and our other partners. Start-up is expected in 2014.
The seventh oil discovery in block 15/06 off the coast of Angola was announced, completing our minimum commitment to this area 18 months ahead of schedule. The well was tested for a rate of more than 6,000 barrels of light oil per day.
We announced that we were boosting our land-based projects in the USA by acquiring a 67,000 net acre share of the Eagle Ford shale gas formation. Statoil and Talisman have formed a 50/50 joint venture with the aim of developing the resources in Eagle Ford.
We submitted our application for new exploration licences in the Barents Sea and the Norwegian Sea in the 21st licensing round on the Norwegian continental shelf. It is expected that Norwegian authorities will allocate acreage here during the spring of 2011.
Production on the Gjøa oil and gas field came on stream on 7 November. This development opens up for more activity in the far north of the North Sea.
We announced that we would further concentrate our efforts to develop offshore wind turbines as part of our renewable energy strategy in the light of the rapid international developments within the offshore wind sector.
The Gas Advocacy Forum, a group of major gas players in Europe of which Statoil is a member, submitted a report to the EU Commission stating that Europe can achieve its target of an 80% reduction in carbon emissions by 2050 if natural gas is allowed to play a substantial role in the energy mix.
Production started up on the Vega gas and condensate field south west of the Sogne coast in Norway.
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 is present in 42 countries worldwide.
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 19.5% of our total production, which averaged 1,705 mmboe per day in 2010.
As of 31 December 2010, we had proved reserves of 2,124 mmbbl of oil and 509 bcm (equivalent to 18.0 tcf) of natural gas, corresponding to aggregate proved reserves of 5,325 mmboe.
We are present in 42 countries. As of 31 December 2010, there were approximately 30,400 employees in the Statoil group. Of this total, 10,400 were employees of the Statoil Fuel & Retail group, in which we held a 54% majority ownership interest as of 31 December 2010.
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 activities. We are contributing to the development of new energy resources, have ongoing activities in the fields of wind power and biofuels and are at the forefront in relation to the implementation of technologies for carbon capture and storage (CCS).
In further developing our international business, we intend to utilise our core expertise in areas such as deep water, heavy oil, harsh environments and gas value chains in order to exploit new opportunities and develop high quality projects.
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 geographical reach of Statoil's business.
See the section Business overview and strategy - New organisational structure as from January 2011, for the organisational structure of our business areas and staff functions up to and including 31 December 2010 and as from 1 January 2011.
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 a.s 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. The commencement of our operations focused primarily 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.
In the 1980s, we saw substantial growth through the development of major 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 we 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, for example through 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, partially divesting and reducing our interest in the business relating to service stations.
Although petroleum-related activities on the NCS and internationally have been the main part of our business, we increasingly participate in projects focusing on other forms of energy, such as wind power and CCS (carbon capture and storage), in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.
Information about Statoil's competitive position relies on a range of sources, including analysts' 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 analysts' reports, independent market studies and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.
We have endeavoured to present information based on other sources accurately, but we have not independently verified such information.
A new corporate structure was implemented with effect from 1 January 2011.
The figure below provides an overview of the organisational structure of our business areas and staff functions up to and including 31 December 2010.
A new corporate structure was implemented with effect from 1 January 2011 (see the figure and descriptions below). The changes were made in order to simplify the organisation and clarify internal accountability. The following Strategy section reflects the organisation as from 1 January 2011. However, the rest of the presentation in this annual report on Form 20-F 2010 is based on the organisation as of 31 December 2010.
Development and Production business areas
Our upstream activities were previously included in the Exploration & Production Norway and International Exploration & Production business areas. Over the past few years, we have made large investments in North America. Establishing DPNA as a separate business area reflects the importance of the region to our business.
Marketing, Processing and Renewable Energy
Technology, Projects and Drilling
Global Strategy and Business Development
Statoil's long-term strategy builds on the company's vision: "Crossing Energy Frontiers". It continues the current strategic direction of creating shareholder value as an upstream-oriented and technology-based energy company.
Our strategy of long-term value creation starts with our short-term deliveries in relation to operations and HSE. As we work towards our ambition of realising the full value potential of the Norwegian continental shelf (NCS), we are simultaneously developing international platforms for long-term growth and gradually building a position in renewable energy production.
We operate in an industry that is becoming more complex. Access to resources is also becoming more challenging. In future, the pace of change will increase and the importance of quality in execution will be even higher - making safe and efficient operations more important than ever.
The recovery of the world economy continued through 2010, mainly driven by strong growth in the emerging economies. This led to a robust recovery in energy demand in most regions.
Energy prices, which fell sharply during the second half of 2008, consolidated and partly recovered in 2009. With the exception of US natural gas prices, energy prices strengthened further in 2010.
Growing by more than 10% in the first part of the year, the Chinese economy provided an important stimulus to the recovery of other regions. India, other emerging economies and Latin America have also witnessed strong economic growth. The pace of growth abated somewhat, however, during the second half of 2010, in both some advanced and emerging economies.
In China a deliberate policy tightening to avoid overheating of the economy has ultimately led to somewhat lower growth, whereas private sector demand in several advanced countries only grew moderately. This reflects the process of deleveraging that both indebted household and the banking sectors in the USA and Europe are still undergoing. The sovereign debt crises in Europe and the volatility of the financial markets have added to the restrictions on bank lending, especially in Europe. After contracting by 1.9% in 2009, world GDP grew by about 3.6% in 2010.
The outlook for the world economy over the next few years will continue to be influenced by the adjustment processes within the various economies (internal rebalancing) and the re-adjustment of unbalanced trade and capital flows between debt-ridden advanced economies and fast-growing export-driven economies (external rebalancing). At the beginning of 2011, most advanced economies are still facing major internal adjustment challenges.
These economies need to strengthen households' balance sheets, stabilise public debt, and repair and reform their financial sectors. Governments' large budget deficits mean that fiscal policy will have to be significantly tightened over the medium-term, which will partially limit the pace of economic growth. By contrast, China and several other emerging economies face the challenge of restructuring their economies from being reliant on export-led growth to becoming more consumption-oriented.
However, China appears to be determined to move only cautiously in this direction, and the process of revaluation of the Chinese renminbi and other measures that could weaken its export machine will most likely be gradual. This cautiousness will slow the external rebalancing process and dampen the much needed stimulus to the advanced economies, and it could also spur rising protectionist sentiment in the USA and other regions.
Ultimately, the development of the world economy will be strongly dependent on the domestic policies of key countries and the degree of international policy cooperation. Consequently, the medium-term outlook is still characterised by moderate economic growth and major uncertainty, with considerable downside risk.
Energy markets and price developments
Crude oil prices, which plunged during the recession, started to recover in the spring of 2009 and ended the year in the USD 75-80/bbl price range. Given ample oil stocks and spare Opec production capacity of more than 5 mbd, the market was mainly driven by expectations of a sustained macroeconomic recovery and a gradual tightening of the oil market over the medium-term.
Costs of developing new oil production in high-cost areas were seen as a key benchmark in price determination. These underlying market dynamics prevailed throughout 2010. Crude oil prices fluctuated significantly during the year driven by changing perceptions about the sustainability of the world economic recovery. Prices strengthened considerably during the fourth quarter, partly supported by cold weather in the Northern hemisphere and ended the year in the USD 90-95/bbl range. US monetary policy, financial players' perceptions, portfolio optimisation and market positions continue to be important drivers for price determination. The average price of dated Brent in 2010 was USD 79.5/bbl, up from USD 61.6/bbl in 2009.
Global oil demand, which fell by 1.1 mbd in 2009, recovered sharply during 2010, with a gain of about 2.7 mbd relative to 2009 - the second strongest annual growth in demand in the last 30 years. China accounted for almost 0.9 mbd of the total, but other emerging economies also contributed to the growth in global oil demand. North American oil demand increased for the first time since 2005. At the same time, non-Opec production and Opec NGL/condensate production continued to expand strongly, by 1.1mbd and 0.5 mbd, respectively, while Opec crude oil production edged up modestly.
The Atlantic Basin product markets, which were severely hit by the economic recession, also partly recovered during 2010. Total products demand increased by 0.45 mbd in the USA, with the strongest growth in demand being for distillates/diesel and various products for broad industrial and household use. In the European markets, product demand, which fell by 0.9 mbd in 2009, consolidated in 2010, with transportation fuels seeing modest growth. However, these gains were offset by further contraction in demand for fuel oil.
Global distillate and naphtha demand, driven by the Asian markets, accounted for the largest proportion of the growth in total products demand. With product stocks in the Atlantic Basin markets still at comfortable levels and with a high level of spare refining capacity, product price differentials (margins) generally remained relatively low, especially gasoline margins. In the US market, a large part of the growth in demand was met by non-refinery liquids and ethanol. European distillate margins improved moderately during 2010 from depressed levels in 2009.
The 2008-2009 recession and the sharp increase in both US unconventional gas production and global LNG production all contributed to a significant over-supply of natural gas and sharply falling prices in all the main regional markets. However, prices consolidated around USD 5/MMBtu on the prospect of more balanced markets during autumn 2009. Despite a strong demand recovery, the Atlantic natural gas markets remained well supplied during 2010. In the first half of 2010, natural gas prices in Europe and North America fluctuated around the levels seen in 2009.
The two markets moved in different directions throughout the year, however, reflecting differences in their competitive nature and supply pressures. In North America, natural gas demand, driven by the recovery of the economy and a strong weather effect, increased by more than 3.0%. However, resilient domestic gas production kept the market over-supplied throughout the year, pushing stock levels to record highs and putting downward pressure on natural gas prices. During most of the year, prices have fluctuated in the USD 3.50-5.00/MMBtu range. The expansion of unconventional gas, especially shale gas, continued at a fast pace. The trends suggest that North America will remain self-sufficient and basically disconnected from the other regional gas markets.
In Europe, by contrast, the combination of strong but volatile demand growth and restrained gas supplies gradually restored the balance in the market and put spot prices on a rising trend during 2010. After fluctuating around USD 4.50/MMBtu during spring, spot prices rose through the rest of the year, reaching USD 9.00/MMBtu by the end of the year. Demand growth, which was very strong during the first half of the year, softened during the summer months, but, driven by extremely cold weather, recovered in the last quarter. Rising coal prices, mainly driven by strong demand from Asia and especially China, have sustained natural gas's competitiveness.
In the last part of the year, however, natural gas faced stronger competition from nuclear power and renewable energy in Germany and several other markets. Total European gas demand increased by about 6% from 2009. LNG imports from the Middle East and Africa continued to grow during 2010, but the moderation and flexibility of Russian exports served to balance the market and ensured a moderate tightening during the year. The strong demand from the Asian LNG markets has also played an important part in the rebalancing of the European gas market.
European electricity prices fluctuated around EUR 50-60/MWh during 2005-08, reached a peak of almost EUR 100/MWh immediately after the start of the economic crisis, but fell to a low of EUR 30-40/MWh in the middle of the recession. After falling by 6% in 2009, European power demand is estimated to have grown by about 4% in the first half of 2010. This drove electricity prices gradually upwards to around EUR 50/MWh.
Prices in the European carbon dioxide market, the EU Emissions Trading Scheme, are basically driven by the supply of allowances derived from the member countries' emission targets, and the demand for emission allowances, which is strongly influenced by activity levels in the industry and power sectors. Carbon prices tend to follow the same pattern as European energy prices. After recovering in the first half quarter of 2009, carbon prices fluctuated around EUR 13-15/tonne over the following 12 months. Since spring 2010, prices have fluctuated around the EUR 15/tonne level. The UN climate change negotiations had limited effect on the short to medium-term emissions trading market last year.
However, a challenging political environment and infrastructure bottlenecks in Iraq indicate that the build-up of new production capacity will proceed relatively slowly. Since oil price formation is also influenced by financial players, the uncertain outlook for financial markets, geopolitical developments and the US dollar will also play a role. The short-term outlook for the Atlantic Basin products markets is driven by modest demand growth and the potential for product imports from several export refineries in the Middle East and Far East. The outlook for sustained overcapacity in refining in the Atlantic Basin may well lead to capacity closures in the mature OECD markets over the next few years.
General market conditions for the oil and gas industry improved throughout 2010. However, the industry is still challenged by limited access to new resources and increased international competition.
In 2009, the oil and gas industry's margins were hit as a result of the financial turmoil. The lower oil and gas prices were accompanied by a moderate fall in supplier market costs. Companies reacted to the margin squeeze by adjusting capital expenditure plans, re-evaluating dividend policies and focusing strongly on cost control. This resulted in reduced demand in the supplier market and a further fall in supplier costs. Margins improved throughout 2010, as energy prices rebounded and the supplier markets in general experienced overcapacity and continued restrained prices (see chart). Several companies are following through with their announced portfolio restructuring programmes, however.
Looking at longer-term trends, certain strategic challenges have affected the direction of the industry. A large part of the world's remaining conventional resources are held by countries with limited access for international oil companies (IOCs), thus restricting IOCs access to new resources. In addition, the competition for international resources is intensifying, particularly with national oil companies becoming more active in the international hunt for resources. To replace produced reserves and grow, IOCs have therefore gradually been pushed into looking for hydrocarbon resources in more remote areas, in deeper waters and in more technologically challenging environments. As a result, unconventional and deepwater hydrocarbons play an increasingly important part in the global production mix. This trend is likely to continue.
Unconventional gas in general, and shale gas in particular, has attracted much interest from different players over the last few years. As US shale gas represents a relatively accessible resource with low break-even prices, it is an attractive proposition for the IOCs. All the major IOCs have therefore endeavoured to position themselves in this business area. These resources have become a game changer for the US hydrocarbon supply structure; due to the increase in unconventional gas production. The USA is currently almost self-sufficient as regards gas and the expected volume of natural gas imports has dropped significantly. This has contributed to the depressed US gas prices, particularly compared with oil, and there has recently been increased interest in the industry in more liquid rich shale plays.
In April 2010, the oil industry was impacted by one of the most serious accidents in its history, when the Deepwater Horizon rig exploded and caught fire in the US Gulf of Mexico, killing 11 people and causing a massive oil spill. The accident is expected to redefine important parts of the US offshore industry's technical requirements and industry practices, and similar repercussions are expected for global deepwater players. The US Department of the Interior's Bureau of Ocean Energy Management Regulation and Enforcement has already implemented significant new measures to address safety and operational issues, and companies and operators will face stricter operational requirements.
Refining margins have improved somewhat over the last year, but there is still some overcapacity in the refining market.
In October, Statoil formed a stand-alone company, Statoil Fuel & Retail ASA, comprising its energy and retail business, which successfully completed an initial public offering. This transaction is in line with the trend seen in recent years of large IOCs reducing their downstream positions.
Increased concern about energy security and climate change has continued to fortify policy and long-term market drivers for commercial growth in renewables. While most renewable energy sources are currently more costly than fossil fuels, the competitive landscape is expected to shift over time as production costs for renewable energy decline and the cost of carbon emissions is increasingly reflected in power and fuel prices. Significant amounts of public and private funding are currently going into research, development and expansion of new technologies in order to make renewables and carbon capture and storage (CCS) more competitive. Wind power is one of the largest areas in renewable energy, with prospects of increasing production over time. Offshore wind, where Statoil has taken on several projects, is expected to take a significant share of the total wind market if several large countries are to achieve their renewable energy goals.
Statoil's strategy is to profitably grow its long-term oil and gas production while gradually building a position in renewable energy production.
Overall strategic direction
Our growth strategy
The Global Strategy and Business Development (GSB) business area has been created to bring together corporate strategy, business development and merger and acquisition activities in order to actively drive Statoil's corporate development. GSB will set a strong strategic direction and identify, develop and deliver opportunities for global growth for Statoil. This will be achieved through close collaboration within the group across geographical regions and business areas. As noted at the February 2011 Capital Market Update, Statoil is currently undertaking a strategy review with the aim of securing continued growth and value creation.
Our growth strategy is based on exploration, focused business development, strategic acquisitions and divestments, and building long-term partnerships. Our aim is to increase the scale of our operations in terms of production, reserves and technological and geographical breadth, and to bring our resource base closer to production. We will continue to deliver profitable projects in a range of complex technical and stakeholder environments.
Our short-term priorities are to conduct safe operations and to deliver production growth in line with our guidelines.
Safe and efficient operations are essential to our business. In order to prevent harm to people and the environment, all activities in Statoil are carried out with a strong focus on HSE. We seek to achieve this through long-term and systematic application of best practices across our activities. We are improving efficiency, for example on the NCS through the "fast-track" and "integrated operations" (IO) initiatives, as we continue to maximise the full value potential of our positions.
By implementing the Statoil 2011 organisation, we aim to put ourselves in an even better position to become a global energy player. Combining company-wide activities in exploration (EXP), marketing, processing and renewables (MPR), technology, projects and drilling (TPD), and global strategy and business development (GSB) into individual business areas, and focusing development and production activity in three geographical business areas (DPN, DPNA, DPI), will allow us to systematically support the globalisation of Statoil, to better support business priorities, and to reinforce leadership and clarify accountability.
Utilising our capabilities
Responding to the climate challenge
Maximising value creation from upstream access opportunities
We will continue selective business development activities to optimise the portfolio.
Maximising long-term value creation on the NCS
Building and delivering profitable international growth
In the longer term, we anticipate that Statoil's future growth will mainly take place outside the NCS and that our international asset base will enable us to grow and become more diversified, both in geographical terms and in terms of types of production. Our short to medium-term focus is on delivering and maturing a high-quality project portfolio on time and within budget.
Developing profitable midstream and downstream positions
Creating a platform for renewable energy production and CCS
We are building a portfolio of wind farms, with the focus on offshore sites, and we are developing technology for large-scale deepwater offshore wind power generation. In this context, our participation in the Sheringham Shoal UK wind farm and the Forewind consortium on the Dogger Bank development are important projects for us. Off the south-west coast of Norway, we are piloting a prototype of the world's first full-scale floating wind turbine, Hywind, which is designed to be placed at water depths of between 120 and 700 metres.
In addition, we are reducing emissions of greenhouse gases from fossil energy production through CCS.
Using technological innovation and implementation as a key business enabler
Based on our history of technological achievements, we actively endeavour to master demanding and critical developments within our priority activity areas. We prioritise technology efforts that add value to resources and that enable us to develop smarter solutions for energy exploration and production that are cost-efficient and environmentally benign. We are refining and standardising our technical requirements and work processes.
Technology innovation and implementation is critical to success in many of our activities, such as enabling field development in frontier deepwater and Arctic areas, the production of heavy oil, exploration for hydrocarbons trapped below salt, and managing environmental and climate-related issues. In addition, in order to enable sustainable energy provision in the long term, we aim to remain competitive in a broad range of core and emerging technologies, such as floating offshore wind.
DPN's strategy is to realise the full potential of the Norwegian continental shelf (NCS).
Safe and efficient operations are essential to our business strategy
Maintaining a high production level
Access to new, high-quality exploration acreage is necessary in order to maintain a high production level in the longer term. Considering the long lead times for field developments, it is a prerequisite in the near term to open new acreage.
Energy efficiency and carbon emissions
Industry leader on the NCS
DPI's strategy is to build a large and profitable international E&P portfolio by delivering on existing projects and accessing new opportunities.
Development and Production International (DPI) is responsible for the safe and efficient development and production of oil and gas resources worldwide (apart from Norway and North America). DPI will focus on four strategic growth areas - deep water, gas value chains, harsh environments and heavy oil - and access projects where Statoil can apply its core technological and organisational expertise to create value. Going forward, particular attention will be devoted to:
In line with the corporate growth strategy, our growth strategy is based on exploration, focused business development, strategic acquisitions and divestments, and the building of long-term partnerships in order to increase the scale of our operations in terms of production, reserves and technological and geographical breadth and bring our resource base closer to production. DPI will continue to deliver profitable projects in a range of complex technical and stakeholder environments.
DPNA's strategy is to build a balanced portfolio of profitable assets by delivering existing projects and accessing new growth opportunities.
Development and Production North America (DPNA) is responsible for planning for the safe, efficient and profitable development and production of oil and gas resources in North America.
DPNA's growth ambition is focused on Statoil's four strategic growth areas: deep water, gas value chains, heavy oil and harsh environments.
Gas value chains
MPR's strategy is to maximise corporate value through safe, reliable and efficient operations, and through the development of profitable midstream, downstream and renewable energy business opportunities.
Marketing, Processing and Renewable Energy (MPR) is responsible for the transportation, processing, storage and marketing of all hydrocarbons in Statoil's upstream portfolio, including refined products. Following the initial public offering of Statoil's energy and retail business in October 2010, the remaining parts of Statoil's midstream and downstream oil and gas value chains now have a more industrial end-user focus.
Dynamic gas markets and the increasing complexity of Statoil's crude qualities call for close cooperation between Statoil's upstream business areas and MPR. An integrated value chain approach has already added significant value to key projects, such as Peregrino in Brazil (oil) and Marcellus in the USA (gas). For example, Statoil's upstream business areas and MPR had to work closely to find the most efficient solutions for the marketing of Peregrino crude oil.
We have a flexible gas transportation system, with six different landing points on the European Continent/UK and flexibility in terms of gas deliveries from large gas-producing fields such as Troll and Oseberg. We plan to leverage our competitive position as a low cost supplier with significant flexibility, proximity to attractive markets and our LNG capabilities to capture opportunities and maximise shareholder value.
MPR's ambition is to strengthen the interface between manufacturing and trading units and to add value through more pro-active integration of the operation of the Mongstad and Kalundborg refineries. The objective is to exploit synergies through crude feedstock optimisation, greater flexibility and exchange of products between the refineries. In the gas processing facilities, a high reliability and cost-efficient performance is fundamental for reliable and competitive deliveries of gas to Statoil's customers.
This strategy has been employed in the growing offshore wind industry, where the company is engaged in a development project in the UK (Sheringham Shoal) and also has been awarded an additional large offshore development acreage in the UK (as part of a consortium).
Statoil believes that technologies for CCS will provide attractive contributions in curbing greenhouse gas emissions to the atmosphere. MPR is engaged in ongoing efforts to develop a commercial CO2 storage concept, leveraging the unique and extensive experience Statoil has acquired from Sleipner and other fields that have been separating and injecting CO2 for years.
TPD's strategy is to create value by providing Statoil with safe and cost efficient drilling and project deliveries. Competitive solutions are key success factors in developing our global activities.
Statoil's upstream development portfolio is substantial. In addition our portfolio is technically as well as geographically diverse. We have demonstrated excellent project execution skills, for example within the Peregrino project off the coast of Brazil. Furthermore, we have gained valuable experience from oil sands in Canada, where the Leismer project started production late 2010. We have also expanded our portfolio of unconventional gas projects in the US.
Within renewable energy, a wind park with more than 80 windmills is being built off the east coast of England for the Sheringham Shoal project, thus gaining expertise in the execution of offshore wind projects.
TPD has made a significant effort associated with CO2 storage and carbon management to complete the construction of the Test Centre plant at Mongstad (TCM). Experience gained from TCM will be used to enhance new business opportunities with the potential of adding value to certain oil and gas activities across the company. (Future projects that will fall under strict CO2 regime or exposed for high CO2 costs will benefit from effective solutions for CO2 treatment and TCM experience will be valuable for project evaluation.)
On the NCS many of our projects are related to redeveloping and upgrading existing fields and installations to prolong lifetime and increase recovery rates. A number of small satellite fields are being tied into existing hubs as this will significantly shorten the time from discovery to production.
We are actively working to simplify development concepts and to standardise use of equipment and services. A key focus area is to enhance recovery from wells already drilled. Finally we are developing and implementing new technology with the aim of ensuring future growth both on the NCS and elsewhere.
Our corporate technology strategy is driven by business challenges and aims to further strengthen our industry position. The technology strategy addresses which technologies to develop and implement to support the corporate strategic ambitions. The technology strategy promotes technologies that will increase competitiveness and enable the company to grow and to deliver world class development projects.
We put emphasis on developing enabling- and new- technologies for frontier areas. An example of this is the choice of a subsea compression solution for the Åsgard field on the NCS. At the same time we put emphasis on standardising selected technologies, fast resource maturation and cost-efficient development solutions.
Much of our technology development and deployment is carried out in close cooperation with national and international universities, research institutes and suppliers. Our performance is strongly dependent on our supplier's performance. We work closely with our suppliers in order to optimise our joint performance.
Statoil is committed to delivering value through exploration in several of the most important oil and gas provinces in the world.
Exploration is an important growth tool for Statoil in order to secure long term growth of reserves, production and value. We are present in several of the most important oil and gas provinces in the world and will continue to optimise our portfolio, balancing infrastructure-led exploration, growth opportunities in mature areas and frontier exploration in new areas.
Our exploration strategy remains focused on accessing more new quality acreage, including unconventional hydrocarbons and technologically challenging exploration resources.
As of January 2011, Statoil merged all exploration activities into one business unit (EXP) in order to utilize competence, resources and technology more effectively across all exploration areas.
Statoil will focus on managing the risks associated with exploration activities. We will influence our partners and contractors over the implementation of safe practices in all phases of our activities and strive for a continuous improvement in our operational performance.
On the NCS further exploration is necessary for maximising the long term value of our portfolio beyond 2020, and we will collaborate across our producing areas to maximise value for the longer term by extending field lifetimes through near-field exploration. We participate in 213 licences in all licensed parts of the NCS and operate 157 of them.
Access to new, prospective acreage is necessary in order to maintain a high production level in the longer term.
Outside Norway we will expand our exploration portfolio managing risk and reward to deliver profitable growth.
We are the third largest licence holder in the deepwater regions of the US Gulf of Mexico. In addition we currently have exploration licences in Canada, USA (Alaska), Africa (Angola, Algeria, Egypt, Libya, Mozambique, Nigeria and Tanzania), Asia (India, Indonesia and Iran*), Europe and the Caspian region (Azerbaijan, the Faroes, Greenland, Ireland, Norway and the UK), South America (Brazil, Cuba and Venezuela).
*Statoil will not make any future investments in Iran under the present circumstances. For more information, see section Operational review - International E&P - International fields in development and production - The Middle East and Asia - Iran.
Statoil's operational review follows the organisation of its operations, although certain disclosures about oil and gas reserves are based on geographical areas, as required by the SEC.
Statoil prepared this operational review in accordance with the segment (business area) structure it used prior to 1 January 2011 (for more information, see section Business overview and strategy - New organisational structure as from January 2011). Each business area is presented individually, and underlying business clusters are included according to how the business area organises its operations.
For further information on extractive activities, see the sections E&P Norway and International E&P, respectively.
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 areas. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa and the Americas.
For further information on disclosures about oil and gas reserves and certain other supplementary disclosures based upon geographical areas as required by the SEC, see the sections Operational review - Production volumes and price information and Proved oil and gas reserves.
Exploration & Production Norway consists of our exploration, field development and operations activities on the Norwegian continental shelf (NCS).
Exploration & Production Norway (EPN) is the operator of 44 developed fields on the NCS. Statoil's equity and entitlement production on the NCS was 1,374 mmboe per day in 2010, which was about 73% of Statoil's total production. Acting as operator, EPN is responsible for approximately 75% of all oil and gas production on the NCS. In 2010, our average daily production of oil and natural gas liquids (NGL) on the NCS was 705 mboe, while our average daily gas production on the NCS was 106.4 mmcm (3.8 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 213 licences on the NCS and are operator for 157 of them.
As of 31 December 2010, EPN had proved reserves of 1,241 mmbbl of crude oil and 463 bcm (16.3 tcf) of natural gas, an aggregate total of 4,153 mmboe.
Activity levels in Exploration & Production Norway were high in 2010 with several new projects sanctioned including three fast track projects.
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 IOR projects. We also operate a significant number of exploration licences.
Statoil's NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.
We have organised our production operations into four business clusters - Operations West, Operations North Sea, Operations North and Partner Operated Fields. The Operations West and Operations North Sea clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea, while Partner Operated Fields cover the whole NCS.
The fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities where possible. 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 the 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.
In addition to the producing areas, we operate a significant number of exploration licences. The exploration acreage is located both in undeveloped frontier areas as well as close to infrastructure and producing fields.
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.
Statoil signed several sales and purchase agreements (SPA) in 2010. Two SPAs were signed with Marathon Petroleum AS. In the first SPA, Statoil acquired an 8.2% participation interest in PL025, which contains the Gudrun development, for a consideration of 10% of PL187 and 12.5% of PL048E. A new SPA was therefore signed in which Statoil acquired all of Marathon Petroleum AS's participation interests in PL025 and PL 187 (the Gudrun development and the Sigrun and Brynhild discoveries) and in PL048E (the Eirin discovery) for cash consideration.
An SPA was signed with PGNiG Norway AS in which it farms in 10% to PL326, the Gro discovery. We signed further SPAs with Concedo to acquire its 5% share of PL 348 containing the Gygrid discovery; with Petoro AS, a company owned by the Norwegian State that was formed to manage SDFI assets, to divest our 30% share in PL158 containing the Hasselmus discovery; and with TOTAL E&P Norge AS to divest our 21% share in PL043CS and PL043DS containing the Islay discovery. SPAs were also signed with TOTAL E&P Norge AS and ExxonMobil Exploration and Production Norway AS to carve out the Theta NE prospect from PL046, PL303 and PL078B, thus aligning the participation interests.
Several transactions have also been carried out that involve the farming-in and farming-out of exploration licences.
Statoil's 2010 exploration drilling activity on the NCS was reduced compared with the extensive exploration drilling campaigns carried out in 2008 and 2009.
17 exploration wells and four exploration extensions wells were completed in 2010 compared with the completion of 39 exploration wells in 2009 and also in 2008. In 2010, the focus has been on evaluating and maturing all the 2009 and 2008 well results.
12 of the 17 wells drilled for exploration purposes were wildcat wells drilled to test new prospects, and six of them were operated by Statoil. Five of the six Statoil-operated wildcat wells and three of the six partner-operated wildcat wells confirmed the presence of hydrocarbons.
A major oil discovery was made in the central part of the North Sea in the Avaldsnes prospect, which is located on the Utsira High, a structural element separating the two Statoil-operated fields, Sleipner and Grane. Lundin is operator for the Avaldsnes licence, and Statoil has a 40% ownership share. The prospect evaluation prior to the drilling was based on a new geological play model for the area. The positive result, which proves the validity of this model, has increased the probability of success for similar prospects in a neighbouring Statoil-operated licence scheduled for drilling in 2011.
Another discovery is Fossekall, located near the Norne field in the Norwegian Sea. Fossekall, which is operated by Statoil, will be developed as a tie-in to Norne together with Dompap, a discovery made in late 2008. Fossekall is now considered to be a fast track candidate with estimated production start-up in 2013. For further information about fast track projects, see section Operational review - Projects & Procurement - Project development.
The Snadd North discovery was made in 2010 in the BP-operated Skarv-Idun area, where Statoil is a major partner (36.165%). Test production of the low carbon dioxide gas will start during the third quarter 2011 and last for 12-18 months. Afterwards, the partnership will evaluate the further development of both Snadd North and South.
The drilling results from the two Shell-operated exploration wells in the Vøring basin are disappointing. The wildcat well located on the Dalsnuten prospect never penetrated any potential reservoir rock, and the appraisal well on the Gro structure proved the same marginal reservoir condition in this new segment as in the previous one. A re-evaluation of the prospects in this part of the Norwegian Sea is necessary before the next exploration well is drilled.
In the Barents Sea, ENI, as operator for the first of four scheduled drilling operations, started the joint 2010/2011 drilling campaign for the Arctic-equipped "Polar Pioneer" rig. Operatorship will be transferred from ENI to Statoil in early 2011, and the second well will be drilled in the southern part of the Hammerfest basin.
The Norwegian Minister of Petroleum and Energy has announced that there will be no drilling in any deepwater licenses granted from the NCS's 21st licensing round, scheduled to be completed in the first half of 2011, until the Norwegian Ministry of Petroleum and Energy has deeper knowledge about the accident that occurred on the BP-operated Macondo well in the deepwater Gulf of Mexico in April 2010, including possible implications for the Ministry's regulations. Although drilling on the NCS occurs mainly at a shallower depth and at lower pressure conditions than in the deepwater Gulf of Mexico, both Statoil and the Norwegian authorities are examining operations on the NCS in light of the accident in the Gulf of Mexico. The Norwegian Petroleum Safety Authority (PSA) is putting more focus on the ability of companies to effectively handle a potential blow-out event. This means, for example, that companies will have to demonstrate their ability to handle a potential blow-out and inform the PSA about how they plan to shut down a well in case of a blow-out before receiving permission to start drilling a new well. The PSA has also established a project team to systematise and assess experience gained and investigatory findings from the Macondo incident in order to secure lessons and improvements for the NCS.
The table below shows Statoil's exploratory and development wells drilled on the NCS over the last three years.
At the end of 2010, Statoil had a total of 1,241 mmbbl of proved oil reserves and 463 bcm (16.3 tcf) of proved natural gas reserves on the NCS.
Measured in barrels of oil equivalents (boe), our NCS proved reserves consist of 30% oil and 70% natural gas, based on total NCS proved reserves of 4,153 mmboe.
In 2010, final investment decisions were made for Valemon, Gudrun, Visund South and Marulk on the NCS, and contributed positively to the proved reserves balance. In addition, revision of proved reserves for several of our producing fields contributed positively.
Proved developed reserves at year end were 3,394 mmboe, which is 82% of the proved reserves. Of the 2010 proved developed reserves, 950 mmboe are oil and 389 bcm (13.7 tcf) are natural gas.
The following table shows our total NCS proved reserves as of 31 December for each of the last three years. Further information on reserves can be found in section Operational review - Proved oil and gas reserves and in note 35 - Supplementary oil and gas information - to our Consolidated Financial Statements.
In 2010, our total entitlement oil and NGL production in Norway was 257 mmbbl, and gas production was 38.8 bcm (1,372 bcf), which represents an aggregate of 1.374 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 2010, 2009 and 2008.
The NCS is the backbone of our operations and the centre of innovation. We continue to explore and develop the NCS as operator and partner using the best available technology and increasingly standardised development solutions.
The following fields are currently under development on the NCS.
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. (Gassco AS is a company owned by the Norwegian state that operates the Norwegian natural gas transportation system, Gassled. Statoil's ownership interest in Gassco was 32.1% by year end 2010, and 22.5% from 1 January 2011). The plan for development and operation (PDO) was submitted to the Norwegian authorities in February 2010, and approved by the Norwegian authorities in June 2010. Production is estimated to start in 2014. The total investments are estimated to be NOK 19.6 billion. Statoil holds a 46.8% interest in Gudrun.
Skarv is an oil and gas field located in the Norwegian Sea in which we have an interest of 36.165% and for which BP is the operator. The field is being developed with a floating production storage and offloading (FPSO) vessel and five subsea installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. Production is expected to start in August 2011. The total development cost is estimated by the operator, BP, to be NOK 36.8 billion.
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. The oil will be offloaded to shuttle tankers. Associated gas will initially be reinjected and later exported together with the gas cap. Statoil is the only partner in Goliat, with an interest of 35%. Eni is the operator. Production start-up is expected in late 2010. The operator has estimated the development costs for the field to be NOK 30.5 billion.
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 Huldrapipe to Heimdal for processing. Sales gas will be transported in Vesterled to St Fergus, or, alternatively, in Statpipe to Draupner. There will be a condensate tie-in to Kvitebjørn for stabilisation and further export in pipelines to Mongstad. Statoil holds an interest of 64.275% in the field. The PDO was submitted to the Norwegian authorities at the end of October 2010 and PDO approval is expected during the second quarter of 2011. The development cost of Valemon is currently estimated to be NOK 19.6 billion, and production start-up is estimated to take place during the fourth quarter 2014.
Marulk, in which Statoil holds an interest of 50%, is a gas and condensate field located in the Norwegian Sea 25 kilometres southwest of Norne. The field was discovered in 1992. The final investment decision was taken early 2010 and the PDO was approved by the Norwegian authorities 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 Åsgard Transport System for processing to sales gas at Kårstø. Condensate will be stored and off-loaded commingled with the Norne crude. Production is estimated to start in the second quarter 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 at 31 December 2010 for our major development projects.
The following projects are being developed on the NCS to extend the life of existing installations or to exploit new opportunities.
The Snorre redevelopment project, which is defined as an increased oil recovery (IOR) project, will contribute to achieving the overall oil recovery ambition for the Snorre Unit and Vigdis. The project includes a water injection pipeline from Statfjord C to the Vigdis field.
The Statfjord late life project converted Statfjord into a mainly gas-producing field by changing the drainage strategy. Gas exports to the UK through a new pipeline connected to the existing pipelines to Flags and St Fergus commenced in late 2007. Investments in the project are estimated to total NOK 21.5 billion.
Troll Field projects include the Troll B gas injection project and the Troll A P12 pipeline project. The main goals of these projects are IOR from Troll B and enabling the Troll field to maintain an average gas export capacity of 120 million standard cubic metres per day and a long-term gas export capacity of 30 billion standard cubic metres per year.
The Troll B Gas Injection project includes two gas injectors in the Troll West Gas Province south. Start-up is planned in 2011.
The Troll A P12 project includes a new 62.5-kilometre 36-inch pipeline between Troll A and Kollsnes, modifications on Troll A and an interface with the Kollsnes plant. Start-up of the pipeline is planned in late 2011.
The Troll C - O2 template, which will be located north-west of the Troll C platform, is defined as an IOR project. The O2 template will be tied back to the existing O1 template, which is tied back to Troll C. Drilling started in December 2009 and the first two wells started production in 2010.
The Norne M template will be located in the southern area of the Norne field. The template will have four production well slots and will be connected to the existing infrastructure at the K template. Drilling started in March 2010 and production start-up is scheduled for April 2011.
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 early 2014.
The main purpose of Kvitebjørn Precompression project is to increase and accelerate gas and condensate recovery by facilitating low pressure production. The project includes 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 is scheduled to start in May 2011 and production is planned to start in April 2012.
We continue to develop the NCS, delivering good results in a year that saw extensive turnarounds and several operational challenges.
Operations North Sea include a large part of Statoil's production activity on the NCS. Our focus is on increasing and prolonging production in the area, and we give priority to IOR and exploration and development of new fields.
The main producing fields in the Operations North Sea area are Troll, Sleipner, Kvitebjørn, Visund, Grane, Brage, Veslefrikk, Huldra, Glitne, Volve and Heimdal. In addition, our new Vega field started production in December 2010.
The area is dominated by natural gas production, with 57.5 of the equity production in 2010. The petroleum reserves are located below water depths of between 80 and 330 metres. In 2010, Statoil's share of the area's production was 240 mbbl of oil, condensate and NGL per day and 323 mboe of gas per day, or 563 mboe per day in total.
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 Statpipe.
Fram is connected to the Troll C platform for processing. Oil production started in 2003, while gas exports started in October 2007.
Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS 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 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
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 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 approval is expected during the first quarter of 2011. Then the lifetime of the processing facility at the Heimdal Gas Centre will be extended, thereby 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 Kvitebjørn field by approximately 35 million standard cubic metres (mscm) of oil equivalent and thus increase the recovery rate from 55% to 70%. Work on production of the compressor has already started. The offshore installation is expected to take place from 2012 until completion in early 2014.
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 re-injected 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. The PDO for Gudrun was approved by the Norwegian authorities in June 2010, and the hydrocarbons will be piped to the Sleipner field. On Sleipner, the oil and gas from Gudrun will be further processed before the oil is transported to Kårstø together with the Sleipner condensate.
The Troll Area comprises Troll, Fram and Vega. Troll is the largest gas field on the NCS and a major oilfield. The Troll Field Project submitted a new PDO in June 2008 for IOR in the area. The PDO was approved by Norwegian authorities in June 2009 and the project is well under way.
The Vega field came on stream in December 2010. It consists of two licences, Vega South and Vega Central; Statoil has substantial ownership interests in both licences. Vega is a new production area for Statoil. The Vega field has been developed with three seabed templates, and gas and condensate are sent to the new Gjøa platform. For further information about the Gjøa platform, see Operational review - E&P Norway - Fields in production on the NCS - Partner operated fields on the NCS.
Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. Huldra is located in the Viking Graben and developed by a (normally unmanned) platform remotely controlled from the Veslefrikk field. Oil from Veslefrikk is exported through the Oseberg Transportation System, while gas is exported to Kårstø. Veslefrikk also processes condensate from Huldra.
The first oil flowed from the Vilje field to the Alvheim 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.
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 used as a storage ship for crude oil before export. Gas is piped to the Sleipner A platform for final processing and export.
The Operations West area contains light oil petroleum resources in a compact geographic area in which Statoil is the sole operator. The main producing fields in the Operations West area are Statfjord, Gullfaks, Snorre, Oseberg, Tordis and Vigdis.
Statoil's share of the area's production in 2010 was 246 mbbl per day of oil, condensate and NGL, and 85 mboe per day of gas, or 331 mboe per day in total. Operations West is the leading oil-producing area on the NCS and, even after over 20 years of production, we believe 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 West area. These initiatives involve IOR, and they have resulted in a prolongation of planned production beyond the current licence periods for several of the fields.
In 2010, Operation West performed two turnarounds without serious HSE incidents.
Gullfaks has been developed with three large concrete production platforms. Oil is loaded directly into custom-built shuttle tankers on the field. Associated gas is piped to the Kårstø gas processing plant and then on to continental Europe. Five satellite fields, Gullfaks South, Rimfaks, Gullveig, Gulltopp and Skinfaks, have been developed with subsea wells remotely controlled from the Guilfaks A and C platforms.
On 19 May, a well control incident occurred at well C-06A on Gullfaks C. The direct cause of the incident was leakage in a well casing. A thorough procedure to reinstall the second well barrier kept the platform shut down for two months. Statoil's internal investigation into the incident found that there were deficiencies in risk management and compliance with internal requirements for drill operation, planning and execution. The most important remedial measures identified by the internal investigation relate to risk analyses and acceptance criteria when complexity increases; supporting documentation, quality assurance and formal procedures in planning and decisionmaking; and greater involvement of technical expertise. A copy of Statoil's internal investigation report can be found at http://www.statoil.com/enINewsAndMediaINews/2010/Downloads/5Nov_20 I 0_%20Rapport_broennhendelse_Gullfaks%20C .pdf.
The Norwegian PSA also audited the planning of the well, and issued a report that concluded that overall serious deficiencies were identified in Statoil's planning of the well. Following its investigation, the Norwegian PSA issued an order requiring Statoil to review and assess compliance with the work processes established to safeguard the well construction process on Gullfaks, conduct an independent assessment of why measures adopted after prior similar incidents did not have the desired effect on Gullfaks and implement measures throughout Statoil based on the Norwegian PSA ordered review and assessments. Statoil is complying in all respects with the Norwegian PSA's order. A copy of the Norwegian PSA's report and related documentation can be found at http://www.ptil.no/news/notification-of-order-to-statoil-gullfaks-c-article7409-79.html?lang=enUS.
Gullfaks C resumed drilling in July, but following our internal investigation, we shut down drilling operations for three wells in November to ensure that the drilling and well operations were being conducted in accordance with our procedures and the findings in our internal investigation.
In late 2010, Statoil decided to shut in the Gullfaks South Brent reservoir for six months in order to maintain drillability for future wells.
The Gimle field is a Gullfaks satellite field that is operated as a separate unit. Permanent production started in May 2006, converting the Gimle exploration well drilled from the Gullfaks C platform into a production well. By the end of 2010, Gimle consisted of two producers and one injector, all drilled as long-reach wells from the Gullfaks C platform.
The Oseberg area includes the main Oseberg field 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.
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 Snorre field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A). Oil and gas is exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A
Statfjord has been developed with three fully-integrated platforms supported by gravity base structures featuring concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Associated gas is piped through the Tampen link to the UK or, alternatively, to the Kårstø gas processing plant and then on to continental Europe. Three satellite fields (Statfjord 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.
According to plan, Statfjord A will be shut down for production in 2016.
Our producing fields in the Operations North area are Åsgard, Mikkel, Yttergryta, Heidrun, Kristin, Tyrihans, Norne, Urd, Alve, Njord and Snøhvit. The Morvin field started production on 1 August 2010.
Our share of the area's production in 2010 was 183 mbbl per day of oil, condensate and NGL, and 151 mboe per day of gas, or 334 mboe per day in total.
The region is characterised by petroleum reserves located at water depths between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult, 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 tankers to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden in Norway. Additional gas volumes are exported through the Åsgard Transport System (ÅTS) to gas markets in continental Europe.
Kristin is a gas and condensate field in the south-western section of the Operations North area. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and 170 degrees Celsius, respectively - are higher than 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 July 2009, and the field was producing from five wells by the end of 2010. In addition, gas is injected into two injection wells via Åsgard B. Tyrihans is expected to be completed in 2011 with another three 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. A second producing well is scheduled to start in 2011. The field is produced through subsea facilities, with the well stream tied back to the Norne FPSO.
Snøhvit is the first field 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 2010, Snøhvit was producing from nine wells. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore. Snøhvit re-injects 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 and the USA in tankers. The first shipment took place in late 2007. The LNG plant has suffered from operational challenges, particulary in relation to problems with the heat exchangers, which are located in the heart of the Snøhvit LNG Plant (Cold box). Their function is to bring the temperature down on the methane gas so that it liquidizes at -164 C. The heat exchangers use ethane and prophane as cooling medium as they condense at higher temperatures than methane. The cooling medium is sprayed over the spiral wounds which contains the methane gas.
Hammerfest LNG has improved regularity and capacity in 2010. There has been one planned inspection shutdown lasting ten days and two unplanned production stops due to unforeseen process challenges.
The Åsgard field contains 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 58 wells grouped in 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 at 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 planned production from four wells. The first three wells have been completed and were put into production by year end. The last well is expected to be completed during spring 2011. The well stream with oil and gas is tied back to Åsgard B for processing. Morvin is an important contributor to utilising the production capacity at Åsgard B.
Partner-operated fields account for a significant proportion of Statoil's oil and gas portfolio. With expected production start-up on Skarv in 2011, and on Marulk and Goliat in 2012, the importance of partner-operated fields in Statoil is increasing.
The portfolio ranges from development projects to mature fields, and their complexity requires detailed knowledge of the areas involved.
Ormen Lange, a deepwater gas field in the Norwegian Sea, is the second largest gas field on the NCS. Statoil has a 28.92% interest in the field. Statoil was operator for the development phase and Norske Shell became the operator for the production phase that began at the end of 2007. Statoil continues to execute 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 (Statoil's interest 7.604%), plus Tor (Statoil's interest 6.639%). Ekofisk has been upgraded with several new platforms over the years, the latest being the 2/4-M, which was installed in 2005. In early 2010 a final investment decision was made to construct a new Ekofisk accomodation and field centre platform. Several new projects are being studied: a new Ekofisk South drilling platform and redevelopments of Eldfisk and Tor. Final investment decisions were made in 2010 for Ekofisk South and Eldfisk. The new platforms are expected to extend the field life beyond the current licence period, which ends in 2028.
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 Statpipe. A final decision has been made to drill a fourth production well in late 2011, and a fifth production well is planned.
Statoil has a 10% interest in the Skirne gas and condensate field, which is operated by Total. The field has two subsea templates with one well each. The well stream is transported to Heimdal for processing. From there, gas is transported in Vesterled or Statpipe. The condensate is transported from Brae to St Fergus in the UK.
Statoil has an 11.78% interest in the Enoch field operated by Talisman. The field is a subsea development tied back to Brae A in the British sector. Production started in May 2007.
Gjøa is located in the North Sea and has been developed with a subsea production system and a semi-submersible production platform. Statoil was the operator in the development phase, while GDF SUEZ took over as operator from production start-up in November 2010. Statoil will provide support and services to GDF SUEZ through a post-transfer agreement, and we continue to execute the drilling and completion of the production wells. Gas is exported via the 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 holds a 20% interest in Gjøa.
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). During the last three years, however, no Statoil-operated fields have been decommissioned. On partner-operated fields, there has been removal activity on Frigg and Ekofisk.
For further information about decommissioning, see the note 25 to the Consolidated Financial Statements, Asset retirement obligations, other provisions and other liabilities.
Statoil is present in several of the most important oil and gas provinces in the world and International Exploration & Production will account for most of Statoil's future production growth.
International Exploration & Production (INT) is responsible for exploration, development and production of oil and gas outside the Norwegian continental shelf.
In 2010, the business area was engaged in production in 11 countries: Canada, the USA, Venezuela, Algeria, Angola, Libya, Nigeria, the UK, Azerbaijan, Russia and Iran. In 2010, INT produced 27 % of Statoil's total equity production of oil and gas, and INT's share is expected to increase significantly in the future.
We have exploration licences in North America (Canada and the USA), South America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria and Tanzania), the European and Caspian area (the Faroes, Greenland, Ireland, the UK and Azerbaijan), and the Middle East and Asia (India, Iran and Indonesia).
The main sanctioned development projects in which we are involved are in the USA and Angola. We believe we are well positioned for further growth through a substantial pre-sanctioned project portfolio, including a strengthened onshore USA position following the Eagle Ford acquisition.
The map shows our exploration and production areas.
International E&P's future growth ambitions have been further confirmed during 2010 through the sanctioning of a number of important projects.
To optimise our portfolio, we signed Joint Venture agreements with partners in Canada and in Peregrino off the coast of Brazil in 2010, while increasing our interest in several projects and broadening our US onshore gas portfolio with Eagle Ford.
Statoil brought a partner into the Peregrino development in Brazil by agreeing to sell a 40% share to the Sinochem Group from China. The transaction is subject to governmental approvals in Brazil. We also brought a partner into our Canadian oil sands project by selling 40% share to PTT Exploration & Production PCL (PTTEP) from Thailand. The transaction was closed on January 2011. Major additions to our international portfolio in recent years include entry into the Marcellus shale gas play in the USA in 2008 and entry into the West Qurna 2 field in Iraq in late 2009. Statoil's main merger and acquistion (M&A) activities in 2010 and early 2011 are presented below.
Acquisitions and licence rounds:
In January 2010, we entered a deal with ConocoPhillips whereby we acquired a 25% interest in 50 leases in the Chukchi Sea in Alaska. The addition of these leases to the 16 previously acquired in Chukchi means we now have a sizable acreage portfolio to explore in the coming years.
In January 2010, we increased our share in St. Malo in the US GoM from 6.25% to 21.5% by exercising our preemption rights.
Statoil was awarded 21 deepwater leases in Central Lease Sale 213 in the US GoM in March 2010.
Statoil increased its share in the Agbami field in Nigeria from 18.8%. to 20.2% with effect from 1 July 2010 as a result of an equity determination process.
In September 2010, Statoil acquired 20.67% of Nautical Petroleum's interest in UK offshore licence P335, which contains the Mariner field. Statoil's share in Mariner after the transaction is 65.1%. The increased ownership interest in Mariner strengthens Statoil's position in offshore heavy oil, a core area in Statoil's international growth strategy.
In October 2010, Statoil acquired 67,000 net acres in the Eagle Ford shale gas formation in Southwest Texas through agreements with Enduring Resources, LLC and Talisman Energy Inc.. This Eagle Ford position complements Statoil's existing US onshore portfolio, and entails supplying a different range of hydrocarbons to different markets. Statoil and Talisman have formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale. Talisman will operate the asset initially. Statoil will operate 50% of the acreage within three years of acquisition. The effective date of the transaction was 1 August 2010.
In November 2010, Statoil was awarded operatorship of three new exploration licences on the UK continental shelf. Statoil was awarded 44.4% interest in one licence close to the Statoil-operated Mariner heavy oil discovery and 50% interest in two licences near the Faroe border. The commitments for the licence close to Mariner are a seismic survey and evaluation, while, for the two other licences, the commitment consists of reprocessing existing seismic surveys.
In November 2010, Statoil was awarded interests in two large exploration blocks in the Baffin Bay bid round in Greenland, a 20.125% interest in block 5 and a 14.875% interest in block 8. Shell will be the operator for both blocks.These new frontier opportunities enhance our exploration portfolio. The commitment in the licences consists of acquiring seismic and carrying out a shallow core programme.
In December 2010, Statoil was awarded interests in four new offshore licences in Canada: a majority share and operatorship in three licenses in the Flemish Pass Basin, and a 50% share in one licence in the Jeanne d'Arc Basin. The new acreage underlines Statoil's ambitions in the area.
In January 2011 Sonangol announced that Statoil will be the operator of the Angolan pre-salt blocks 38 and 39 and be a participant in blocks 22, 25 and 40. Statoil will have 40% interest in blocks 38 and 39 and 20% interest in the other blocks. All blocks are in the Kwanza Basin offshore Angola. Formal granting of licences for all blocks is subject to the Angolan Ministry of Petroleum's decision of any appeal of the bid round jury's decision, and the successful negotiation of contractual terms including the terms of Production Sharing Agreements (PSAs).
Divestments and other reductions of Statoil's portfolio:
Libyan State Oil Company (NOC) in Libya has renegotiated the PSA for Mabruk, and in January 2010, our equity share of production in Mabruk was reduced from 25.0% to 5.0% effective as of 1 January 2008.
In May 2010, Statoil annouced entering a joint venture and the sale of 40% of the Peregrino field off the coast of Brazil to Sinochem Group. Statoil retains 60% ownership and operatorship of the field. Sinochem Group will pay a total of USD 3,070 million in cash. The divestment demonstrates substantial value creation on Statoil's part in the development phase and is a natural step in our continuous efforts to optimise our portfolio. Brazil will continue to be a key part of Statoil's international strategy. The transaction is subject to government approval in Brazil.
In November 2010, Statoil announced the sale of a 40% interest in its Kai Kos Dehseh oil sands project in Alberta, Canada to PTTEP of Thailand. Statoil will retain 60% ownership and operatorship of the project. PTTEP paid a total of USD 2,280 million for the 40% interest. This transaction underlines the quality of our Canadian resources and demonstrates our ability to create value as an oil sands operator. The effective date of the transaction was 1 January 2011, pending governmental approvals which resulted in a closing date of 21 January 2011.
Statoil's strategy is to continuously access new exploration acreage with high resource potential and to maximise the number of high impact wells.
We have exploration licences in North America (Canada and the USA), South America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria and Tanzania), Europe and the Caspian region (the Faroes, Greenland, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia).
We have completed 18 wells in 2010, and six were ongoing at year end. Of the 18 wells, seven were announced as discoveries and five are currently under evaluation. We plan to drill about 20 wells in 2011.
Areas with drilling or significant Statoil operated seismic activity in 2010
The areas where we entered or had significant activity in 2010 are presented below.
Statoil is operator and partner in licences off the coast of Newfoundland, and we hold 1,129 square kilometres (279,053 acres) of oil sands leases in Alberta.
In December 2010, Statoil was awarded interests in four new licences off the coast of Canada. The new acreage underlines the company's ambitions in the area. The licences include a significant discovery licence (SDL) and three exploration licences off the coast of Newfoundland. The licences were awarded through a land sale issue by the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB). These licences provide further growth opportunities near our Mizzen discovery in the Flemish Pass Basin and near existing infrastructure in the Jeanne d'Arc Basin, as well as more frontier opportunities. Statoil is operator and has a 65% interest in the SDL, which is an extension of Statoil's current Mizzen licence, and in the exploration licence located in the vicinity of the Mizzen SDL. Statoil is operator with a 75% interest in the exploration licence situated in the northern part of the Flemish Pass Basin and a partner with a 50% interest in the exploration licence located in the Jeanne d'Arc Basin.
In order to determine the extent of the exploitable oil sands deposits in Alberta, a total of more than 650 wells were drilled in the region from 2003 to 2010. Extensive seismic surveys were also carried out during the same period.
In the 2009-2010 winter drilling programme, wells were drilled that are required for delineation, observation and water source or disposal purposes for near-term development phases.
Additional drilling for delineation, observation, and water source or disposal purposes and further seismic surveys are under way at year end 2010 as part of the 2010-2011 winter drilling programme.
Our oil sand activities are described in more detail in section Operational review - International E&P fields in development and production-North America-Canada.
We have significant activities in the USA, with more than 400 leases in the Gulf of Mexico and 66 in Alaska. Drilling activity was reduced in 2010 as a result of the Gulf of Mexico drilling moratorium.
US Gulf of Mexico
As a result of the accident on the BP-operated Macondo well in the Gulf of Mexico in April 2010, a four-and-a-half-month moratorium on certain deepwater drilling in the Gulf of Mexico region was imposed, new regulatory initiatives were implemented and further changes and additions to laws and regulations are currently under review in the US. The future effects of this accident, including any new or additional regulations that may be adopted in response, are not fully known at this time.
Although the drilling moratorium was lifted on 12 October 2010, operators may not re-commence drilling activity until they certify compliance with all rules and requirements, including availability of adequate blow-out response resources. The US Bureau of Ocean Energy Management, Regulation & Enforcement has stated that Statoil is one of thirteen operators that may not need to submit revised exploration plans or development operations coordination documentation in order to re-commence its drilling activity. Statoil has worked in recent months to comply with all rules and requirements, and we are in the process of completing the work necessary so that our two rigs that were drilling in the Gulf of Mexico prior to the drilling moratorium can resume drilling. We expect the drilling for Statoil in the Gulf of Mexico to resume towards the end of the first half of 2011. The first new permit for the drilling of a deepwater well (apart from water injection and side track wells) was issued at the end of February 2011. There remains industry-wide uncertainty around the pace at which new drilling activity will be restored.
Statoil remains committed to deepwater exploration and development in the Gulf of Mexico and other deepwater basins around the world.
See the section Risk review - Risk factors - Risks related to increased regulation and regulatory compliance and section Operational review - Regulation - HSE regulation.
We were awarded 21 deepwater leases in Central Lease Sale 213 held in March 2010, including 14 with partner BHP Billiton.
We have interests in nine exploration licences in four different basins in waters off the coast of Brazil. We are the operator for four of the licences.
We have completed one well in BM-C-33 and one in BM-ES-29. This fulfilled our commitments in these licences. The second exploration period in BM-C-33 has begun, and drilling of the commitment well started in November. In addition, we have one commitment well in Statoil-operated BM-CAL-10 and BM-C-47 and one in the partner-operated BM-CAL-7. Rig capacity that will enable us to complete our commitment wells in BM-CAL-10 and BM-C-47, has been secured. Indra, in BM-ES-32, was announced as an oil discovery in December 2010.
Statoil will operate a total of three exploration wells in 2011. Two of them will be drilled in the Peregrino area. The objective of these wells is to prove some of the upsides we believe are present in the Peregrino area.
The interests in three blocks that we won in the eighth round in the Santos basin are pending award.
Statoil holds interests in blocks 4/05, 15, 15/06, 17, 31 and 34 in Angola.
We are engaged in extensive exploration activity in Angola. A number of wells were drilled in 2010, and more are expected to be drilled in 2011 and the coming years. We have interests varying from 5% to 50% in six blocks.
In January 2011, Sonangol announced that the Angolan jury of the bid rounds has elected Statoil for operatorship and participation in several pre-salt blocks offshore Angola. As the operating company, Statoil was elected by the jury of the bid rounds to participate in the following blocks:
As a non-operating partner, Statoil was elected by the jury of the bid rounds to participate in the following blocks:
Formal granting of licenses for all blocks is subject to the Angolan Ministry of Petroleum's decision of any appeal of the jury's decision, and the successful negotiation of contractual terms including Production Sharing Agreements (PSAs).
The exploration acreage in parts of Blocks 15, 17 and 31 has been relinquished. Areas with proved oil have been converted into development areas (DA) and provisional development areas (PDA).
In Block 4/05, operated by Sonangol and assisted by Statoil, we completed the remaining commitment exploration well in January 2011.
In Block 31, operated by BP, certain of the exploration acreage was relinquished in May 2010. A total of 31 exploration wells have been drilled in that block. We are working to mature existing discoveries into future developments on the remaining acreage.
In Block 15/06, which is operated by ENI, four discoveries were announced this year.
In Block 15, work is being initiated to mature existing discoveries as tie- ins to existing infrastructure. Thirty-eight exploration and appraisal wells have been drilled in block 15 so far.
In Block 17, appraisal drilling was carried out in 2010 and will continue into 2011. Thirty-five exploration and appraisal wells have been drilled in block 17.
Block 34, which is operated by Sonangol, is the only area with a remaining commitment well.
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, both with water depths in the 1,000 to 3,000 metres range.
Block 2 (11,099 square kilometres), Tanzania: We have fulfilled the seismic commitment in the current exploration phase in this block. In order to mature the block further, a 1,600 square kilometre 3D survey was carried out between December 2009 and March 2010. In March 2010, we farmed down 35% of our equity to ExxonMobil. We are the operator of the block and have a 65% interest. A well is planned to be drilled in late 2011 or early 2012.
Area 2&5 (8,041 square kilometres), Mozambique: Statoil is the operator with a 90% interest in the licence, which consists of two blocks under one licence agreement. The state oil company Empresa Nacional de Hidrocarbonetos (ENH) is the partner with a 10% interest. We are currently in the second exploration period and have fulfilled our 3D seismic commitment. A 1,300 square kilometer 3D survey was carried out between March and June 2010, and interpretation is ongoing. In accordance with the production sharing contract (PSC), we relinquished some of the area on 1 December, 2010. The decision to extend the licence and commit to drilling a well will be made by 1 June 2011.
We are the operator, with an 80% interest, in two offshore exploration licences located west of the Nile Delta in the Mediterranean, in water depths ranging from sea level to 3,000 metres.
The El Dabaa Offshore Licence (Block 9) covers an area of 8,368 square kilometers. We have fulfilled our seismic commitment. During the past year, we have been processing the 3D seismic survey and have also started reprocessing of our 2D seismic survey. During 2010, we have been planning the Kc37-1 (Kiwi-A1X) well. This well commenced drilling in October 2010 and operations continues into 2011. Completion of the well will fulfill our work commitment under the licence.
The Ras el Hekma Offshore Licence (Block 10) covers an area of 9,802 square kilometers. We have fulfilled our work commitment under this licence. We have been processing the 3D seismic survey and have also started reprocessing of our 2D seismic survey.
Statoil is operator of the Karama PSC with a 51% interest, and we also have a 40% interest in the Kuma PSC. Both licences are located off Indonesia in water depths ranging from 1,000 to 2,000 metres.
During 2010, detailed seismic mapping and special studies were carried out to define drillable prospects in both the Karama and Kuma PSCs. Drilling locations were defined for both PSCs and drilling programmes are currently being finalised. Several studies were carried out to support the definition of optimal drilling locations and in preparation for safe and efficient drilling operations. All drilling-related contracts have now been entered into and signed together with the other operators in the Makassar Strait Explorers Consortium (MSEC), which will use the drillship Global Santa Fe Explorer. The first MSEC well using the Global Santa Fe explorer was spudded in August. The Kuma well and at least two of the Karama wells are expected to be drilled during 2011.
At the end of 2010, the international business area had a total of 883 mmbbl of proved oil reserves and 45.9 bcm (1,621 bcf) of proved natural gas reserves.
Measured in barrels of oil equivalents (boe), our international proved reserves consist of 75% oil and 25% natural gas, based on total international proved reserves of 1,172 mmboe.
Several of our international fields contributed positively to the reserves balance in 2010:
Statoil announced during 2010 the establishment of joint ventures and the sale of a 40% interest in the Peregrino field in Brazil and sale of a 40% interest in the oil sand leases in Alberta, Canada. These sales were not finally approved by the relevant authorities by year end 2010, and are therefore not reflected in the 2010 proved reserves statement. The expected effect on 2011 proved reserves statement is approximately 66 million boe sales of reserves-in-place.
The increased oil price during 2010 has had a negative effect on our proved reserves' estimates for international projects with a Production Sharing Agreement or a Buy Back Agreement.
Proved developed reserves at year end were 581 mmboe, up 3% from 2010. Of the 2010 proved developed reserves, 407 mmboe are oil and 27.7 bcm (977 bcf) are natural gas.
The following table shows our total international proved reserves as of 31 December for each of the last three years. Further information on reserves can be found in section Operational review - Proved oil and gas reserves and in note 35 - Supplementary oil and gas information - to our Consolidated Financial Statements.
Statoil's petroleum production outside Norway in 2010 amounted to an average of 332 mboe per day of entitlement production and 514 mboe per day of equity production.
Our total annual entitlement production in 2010 was approximately 121 mmboe, compared with 130 mmboe in 2009.
The first table shows our average daily entitlement production of liquids and natural gas for the years ending 31 December 2010, 2009 and 2008.
The next table provides information about the fields which contributed to 2010 production.
The table below presents equity and entitlement production per country in 2010.
Major efforts are under way to make the transition from a mainly Norwegian offshore player to a world-class international operator.
We are working continuously to develop our inventory of projects into producing assets by looking at innovative technical and commercial solutions.
This section covers projects under development and fields in production. Significant pre-sanctioned projects, including some discoveries in the early evaluation phase, are also presented. This section often refers to a field's plateau production, which means the yearly average equity production at plateau for a field for a 100% ownership share. Capacities also refer to the total field or facility.
Exploration activities are described in the report section Operational review - International E&P - International exploration activity.
Statoil's development and production activities in North America comprise interests and operations in the US Gulf of Mexico, in the Appalachian region and in southwest Texas, off the eastern coast of Canada and in the oil sands of Alberta, Canada.
We also have a representative office in Mexico City.
Oil sands are an important long-term investment for the company, and our Leismer Demonstration Project is on schedule. Offshore, we have production from Hibernia and Terra Nova, and two development projects.
In 2007, we acquired 100% of the shares in North American Oil Sands Corporation (NAOSC) and operatorship of the Kai Kos Dehseh (KKD) leases in the Athabasca region of Alberta. In November 2010, we agreed to sell a 40% interest in the oil sands project to PTTEP of Thailand with a valuation date of 1 January 2011. The transaction was closed on 21 January 2011. We will act as Managing Partner and retain 60% ownership of the partnership holding the oil sands project, and will continue to be operator of the project. As of 31 December, we owned a 100% interest in 1,129 square kilometres (279,053 net acres) of oil sands leases located in the Athabasca region of Alberta. On closing, Statoil will hold a 60% interest, amounting to 167,432 net acres of oil sands leases.
Statoil Oil Sands project's first phase is the Leismer Demonstration Project, whose construction and commissioning is substantially complete, having achieved delivery of all key components on or ahead of schedule. In fact, the first steam milestone was completed a full month ahead of schedule. All of the production wells have been drilled and completed. Three of the four well pads were put on circulation, which resulted in early pre-commercial production of approximately 84,000 bbls of bitumen in 2010. Conversion to SAGD production mode will continue to progress at the remaining well pairs through the first quarter 2011. The Cheecham terminal is undergoing commissioning in accordance with plan. The Leismer Demonstration Project is connected to the existing pipeline infrastructure at Cheecham that runs to the Edmonton area. After producing pre-commercial production volumes in late 2010, we announced first commercial oil on 27 January 2011. The project was in full operation by the end of the first quarter of 2011.
Fields in production
Terra Nova produces from an FPSO and is operated by Suncor Energy. The Terra Nova field is also in decline, with 2010 gross production rates averaging 70,000 barrels of oil per day. Development drilling of the field is planned to continue in 2011.
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. The Hibernia South Extension Unit is located across three licence areas. Statoil holds working interests of 22.5% in PL1005, 4.5% in EL1093 and 4.5% of the unit portion of PL1001. Statoil's unitised interest is currently 10.5%. The development plan application (DPA) was approved in October 2010.
Tahiti and several other properties continued production in 2010. Statoil sanctioned the Tahiti Phase II, Jack, St. Malo and Big Foot projects. Onshore, Marcellus shale gas production is increasing, and we acquired acreage in the Eagle Ford play in Texas.
The Marcellus Shale Gas play is located in the Appalachian region in north-eastern 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. Statoil has continued to acquire acreage within the play, with a net acreage position of over 665,000 acres at the end of 2010. Marcellus provides Statoil with a long-life gas asset with considerable optionality in relation to the timing of drilling and producing from these leases. Marcellus production started in 2008, and Statoil's daily equity production was approximately 18,700 boe by year-end 2010. Statoil and Chesapeake will continue to acquire and high-grade acreage around the most prospective areas of the play and will build up production from both dry gas and natural gas liquid producing areas.
Water is used in our fracing operation in the Marcellus and our partners maintain the required permits to access necessary water supplies. Modern filtration methods and settling ponds are used to recycle produced frac fluid resulting in disposal of a minimal amount of waste water. Water processing facilities are under construction to process and re-use produced frac fluids, which will further reduce water consumption. We expect that additional water conservation improvements will further reduce usage and allow for efficient development of these unconventional resources.
Through agreements with Enduring Resources, LLC and Talisman Energy Inc. in 2010, Statoil acquired 67,000 net acres in the Eagle Ford shale formation in south-west Texas. Statoil and Talisman formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale formation. As part of the joint venture, Statoil and Talisman jointly acquired the Eagle Ford assets of Enduring, comprising 97,000 acres (48,500 net to Statoil), in a USD 1.325 billion transaction. The purchase price corresponds to about USD 10,900 per acre. Statoil also acquired 50% of Talisman's existing Eagle Ford acreage and production for USD 180 million (18,500 acres net to Statoil). As a result, Statoil and Talisman together hold 134,000 net Eagle Ford acres and associated assets and production in the joint venture. Statoil paid a total of USD 861 million (approximately NOK 5.2 billion), including closing adjustments, in the two transactions.
Offshore, Gulf of Mexico
Fields in production
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 barrels of oil per day, and gross average daily production in 2010 was approximately 32,000 boe.
Our three deepwater natural gas fields - Q, San Jacinto and Spiderman - are part of the Anadarko-operated Independence Hub. The Q field is Statoil-operated, while San Jacinto and Spiderman are partner-operated. The fields are subsea tie-backs to the Independence Hub platform, a floating production facility located in Mississippi Canyon Block 920. They are at varying stages of their life cycle. Spiderman continues to produce, while efforts are being made to extend the life of San Jacinto. Q was depleted in June 2010, and Statoil is planning for the abandonment of the well and related infrastructure. The Independence Hub is owned by third parties and has processing capacity of approximately one billion cubic feet of natural gas per day. We have contractual rights to 12.7% of the total capacity.
The Murphy-operated Front Runner oilfield is located in Green Canyon Blocks 338/339/382. We have 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.
We have a 30% interest in the Noble Energy-operated Lorien oilfield, located in Green Canyon 199. Lorien produces through a subsea tie-back to Shell's Bullwinkle platform.
Zia, an oilfield located in Mississippi Canyon Block 496, and Seventeen Hands, a gas field located in Mississippi Canyon Block 299, continue to produce small volumes. Both fields tie back to platforms owned by others.
Fields under development
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. In early 2010, we increased our interest in St. Malo from 6.25% to 21.5%. 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. The first oil is planned 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 is planned in late 2014.
Our current asset portfolio in Latin America comprises the Peregrino offshore heavy oil project in Brazil and the onshore extra heavy oil producing asset, Petrocedeño, in Venezuela.
In May 2010, Statoil agreed to sell 40% of the Peregrino Field to Sinochem Group. The transaction is subject to government approval in Brazil.
Statoil is operator for the Peregrino offshore oilfield in Brazil, and by 2012, we expect to become the largest foreign offshore operator in Brazil in terms of production.
The Peregrino field is a heavy oil field located in approximately 120 metres of water in the prolific Campos Basin, about 85 kilometres off the coast of Rio de Janeiro.
The field is being developed with a FPSO vessel and two wellhead platforms with drilling capability. First oil is expected towards the end of the first quarter 2011. We expect to reach plateau production in the first year of production. Design capacity is 100 mboe per day.
In May 2010 we agreed to sell 40% of the Peregrino Field to Sinochem Group. Statoil retains 60% ownership and operatorship of the field. The transaction is subject to government approval in Brazil.
Statoil has a 9.677% interest in Petrocedeño, one of the largest extra heavy crude 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 oil to be transported by pipeline to the coast, where it is upgraded to a light, low-sulphur syncrude destined for the international market. Petrocedeño, S.A., owned by the project partners - PDVSA, Total, and Statoil - operates the field and markets the products.
Petrocedeño experienced operational challenges also in 2010 and produced below design capacity. A recovery programme has been initiated to improve the situation.
We have been present in Venezuela since 1994, and our activities in the country are based on a long-term perspective.
Our development and production portfolio in sub-Saharan Africa comprises blocks 4/05, 15, 15/06, 17 and 31 off the coast of Angola, and the OML 127 and OML 128 production licences off the coast of Nigeria.
The Angolan continental shelf is the largest contributor to Statoil's production outside Norway. It yielded 173 mboe per day in equity production in 2010, 34 % of our total international oil and gas output.
Block 17 is operated by Total, and our interest is 23.33%. Production from the block currently comprises four development areas produced over two FPSOs. The Girassol, Jasmim and Rosa development areas are produced over the Girassol FPSO and the Dalia development area over the Dalia FPSO. The combined equity production from Block 17 in 2010 was 100 mboe per day.
The Pazflor project, which comprises the Perpetua, Acacia, Zinia and Hortensia discoveries, will be produced over a new FPSO, with expected production capacity of 220 mboe per day. Start-up is scheduled for the second half of 2011.
The CLOV project consists of the Cravo, Lirio, Orchidea and Violeta discoveries. The project was sanctioned in mid-2010 and major engineering, procurement and construction (EPC) contracts have been awarded. CLOV will be produced over a new FPSO, with expected production capacity of 160 mboe per day. The first oil is expected in 2014.
IOR projects to fill excess capacity on the Girassol FPSO and to increase oil recovery from Block 17 are under evaluation. 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 13.33%. Statoil's equity production from Block 15 in 2010 was 69 mboe per day. Production comes from the Kizomba A, Kizomba B, Kizomba C-Mondo, Kizomba C-Saxi Batuque, and Xikomba FPSOs. In addition, one satellite, Marimba, is producing through a tie-back to the Kizomba A FPSO.The Xikomba FPSO is expected to cease production in the first part of 2011.
Kizomba satellites phase 1, which consists of two discoveries, Clochas and Mavacola, was sanctioned by the partnership in 2009 and is currently under development. The first oil is scheduled for 2012.
Evaluation of a possible development of the Kizomba Satellites phase 2 is ongoing. The project includes the Bavuca, Kakocha and Mondo South discoveries.
Block 31 is an ultra-deepwater licence operated by BP. Our interest is 13.33%. 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 is now under execution. PSVM will be developed via a new FPSO with a production capacity of 150 mboe per day. According to the operator, production start-up is expected in late 2011.
Work is also ongoing to pursue a second development around the Palas, Astraea, Juno and Dione discoveries in the southern part of the block. Other discoveries will either be tied back to one of these developments or be developed through additional FPSOs.
Block 4/05 is operated by Sonangol P&P, and our interest is 20%. This block includes the Gimboa field. The equity production in 2010 was 3.2 mboe per day.
Block 15/06 is operated by Eni. Our 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 for the transfer of gas, and costs and investments related to the projects will be recovered through the PSA.
The first delivery of commissioning gas from block 15 to the Angola LNG Terminal is expected to start in the second quarter of 2011. Normal deliveries of gas are expected to start in the first quarter 2012.
Export of gas from Block 17 with injection into Block 2 started December 2010. Completion of a pipeline from Block 2 to the Angola LNG Terminal is scheduled for completion April 2011.
In Nigeria, we have an interest in the largest deepwater producing field, Agbami.
The Agbami field, located in deep waters off Nigeria, is produced from subsea wells connected to an FPSO. Production started in 2008. Agbami, which is operated by Chevron, is located in licences OML 127 and OML 128, approximately 110 kilometres off the Nigerian coast. Following a technical re-assessment of the resource inventory, our interest in the unitised field has been increased from 18.85% to 20.21% effective from 1 July 2010.
The Agbami field is currently producing at the nominal plateau rate of 250 mboe per day and is expected to continue to do so for several years to come.
The Nigerian government continues to work for the restructuring of the oil and gas sector through the passage of the Petroleum Industry Bill (PIB). The Bill is currently with the National Assembly and in its final stage. The law is likely to increase the government take.
The security and political situation is largely unchanged. The overall security situation is being monitored closely and appropriate security measures are being assessed for our personnel and assets.
Statoil has built a unique position as supplier to the European gas market. In addition to our heritage position on the Norwegian continental shelf, we have upstream assets that supply this market from Algeria and from Azerbaijan.
The Shtokman field is a long-term resource that can enhance our upstream gas position while making us a supplier from the north-east.
The Chirag Oil Project was sanctioned in March 2010 and is expected to start production in 2013. The project will comprise one new platform with capacity to produce 185,000 barrels of oil per day. This will further strengthen our position in Azerbaijan.
We have interests in production and development assets in Algeria, Libya, Ireland, the United Kingdom, Azerbaijan, Iraq and Russia, in addition to early-phase evaluation assets in the United Kingdom and Algeria.
We also have representative offices in Kazakhstan and Turkmenistan.
Our main assets, In Salah and In Amenas, are the third 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
A Contract of Association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. A joint marketing company sells the gas produced in the development. All gas that will be produced up until 2017 has been sold under long-term contracts.
In the In Salah Gas Compression Project, gas compression facilities were installed at the three existing northern fields in 2010. Compression has started at all three fields.
The In Amenas onshore development is the fourth largest gas development in Algeria, containing 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, and we have a 50% share of the development costs. Production has reached its 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.
The In Amenas Gas Compression Project, which is led by BP, was sanctioned in late 2010. The compressors are expected to come on stream in 2013. This will make it possible to reduce wellhead pressure and maintain the contractual production commitment.
Fields in development
The Hassi Mouina exploration phase has been extended until September 2011. Statoil is currently assessing the technical solutions for and commercial attractiveness of a potential development.
In 2010, we had two producing assets in Libya.
The Mabruk oilfield (operated by Repsol) is located in licence C-17 in the Sirte basin. Mabruk Oil Operations is the operating company for Mabruk C-17 license with Total as the lead partner for the International Oil Companies. The field has been producing since 1995. The Dahra south-east project was sanctioned in 2009.
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 Muzuq NC 186 license with Repsol as the lead partner for the International Oil Companies. The K field came on stream in 2010, and the average production was 218 mboe per day in 2010. The oil from the Murzuq fields was transported by pipeline to the Az Zawia terminal west of Tripoli for lifting by ship.
Due to the outbreak of political unrest in Libya, Statoil's Libyan operations were suspended in February 2011, 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 have been evacuated from Libya. The future impact of the ongoing unrest, potential political changes and international sanctions on Statoil's current Libyan operations is uncertain.
We have several oilfields under appraisal in the United Kingdom (UK) and hold interests in three producing fields.
Fields in production
The Schiehallion oilfield is located west of the Shetland Islands. BP is the operator, and we have a 5.88% interest. In April 2010, the Schiehallion partnership approved the concept selection for the acquisition of a new FPSO vessel.
Jupiter is a gas field located in the southern part of the UK North Sea. We have a 30% interest and the operator is ConocoPhillips.
All these fields are in the mature to late-life stage of production.
Discoveries under appraisal
Rosebank, a discovery made by Chevron in 2004, is located west of the Shetland Islands. We have a 30% interest in this field. The partnership is currently working on concept selection for field development.
We have a 36.5% interest in the Corrib gas field, which lies on the Atlantic Margin north-west of Ireland. The Shell-operated Corrib field development was sanctioned in 2001, and work towards the first gas is progressing.
Planning permission for the gas terminal was granted in 2004 but project execution was suspended in 2005 due to protests by local landowners. Alternative onshore pipeline routes were identified as part of a community consultation process and a modified application to tunnel under the estuary was submitted in May 2010. Approval for this was granted by the Irish planning authority, An Bord Pleanála (ABP), on 20 January 2011. Further approval was given by the Department of Communications, Energy and Natural Resources on 28 February 2011. Additional approvals are required from the Department of Environment, Heritage and Local Government and Mayo County Council before construction can begin.
Six subsea wells have been drilled and the pipeline from field-to-shore is in-place. However the control umbilical has yet to be installed. A link-line connecting the terminal to the Irish gas grid will be used to import gas to commission the terminal which will then be preserved in a state of readiness for first gas. The final schedule to first gas will be determined once all approvals are in-place.
We have been present in Azerbaijan since 1992 and are now the second largest foreign oil company in the country in terms of proven reserves and production.
At present, we hold interests in three production sharing agreements (PSAs) offshore in the Azeri sector of the Caspian Sea: the Azeri-Chirag-Gunashli (ACG) oilfield, the Shah Deniz gas and condensate field, and the Alov, Araz and Sharg prospects.
We have an 8.5633% interest in the BP-operated ACG PSA. Crude oil production from the field commenced in 1997. The field has subsequently been developed through ACG Phases one to three, and put on stream from 2005 through 2008. The Chirag Oil Project, which was sanctioned in March 2010, is expected to start production in late 2013. The project will comprise one new platform with capacity to produce 185,000 barrels of oil per day. Crude production from ACG currently exceeds 800,000 barrels of oil per day.
Statoil has a 25.5% interest in the Shah Deniz PSA, where BP is the field operator. The production of gas from stage one started in December 2006 and reached nearly seven billion cubic metres in 2010. We are the operator of the Azerbaijan Gas Supply Company (AGSC), which manages gas sales, contract administration and business development for Shah Deniz stage one gas. We are also the commercial operator of the South Caucasus Pipeline system (SCP) for gas transport from Shah Deniz to markets in Azerbaijan, Georgia and Turkey. See also section Risk review - Risk factors - Risks related to our business.
The crude oil from ACG is transported to the Mediterranean Sea through the 1,760-kilometre Baku-Tbilisi-Ceyhan (BTC) Pipeline, in which we participate with an 8.71% interest.
The Shah Deniz partnership has ambitions to start production of stage two. The project is in the concept selection phase, and commercial negotiations are ongoing to secure sales contracts and transportation rights to the markets.
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, and a 30% ownership interest in one producing field, the Kharyaga oilfield.
Field under planning
Field in production
During 2010, production has been maintained at plant capacity level. Phase three development is ongoing, and eight new wells have been drilled.
Statoil and Lukoil signed a development and production contract with the Iraqi authorities in January 2010 for the development of the West Qurna 2 field.
We have a representative office in China and the United Arab Emirates.
In January 2010, Statoil and Lukoil signed a development and production service contract with the Iraqi authorities for the development of the West Qurna 2 field.
The parties to the contract are the Iraqi state's South Oil Company and a consortium of contractors. South Oil Company is the contractual counterparty to the consortium of contractors, and it has signed the contract on behalf of the Republic of Iraq. Under the contract South Oil Company is also the highest authority with regard to both governance and procurement. The consortium consists of the Iraqi state's North Oil Company (25%), Lukoil (56.25%) 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 1,800,000 barrels per day.
With support from Statoil, Lukoil has built up the organisation required to develop the field. Statoil has taken positions in the operating organisation in administrative and technical roles. Statoil is also in the process of setting up a representative office in Baghdad.
Work on the field has started in the form of preparations for the start-up of development activities, which is expected in 2011. The first milestone under the service contract, the Preliminary Development Plan, was approved on 27 November 2010. Invitations to tender have been issued for the first contracts for the field development.
The security of personnel and implementation of necessary security measures are the main priorities. The security situation in Iraq is still demanding, but it has improved over the last two years.
By entering Iraq, Statoil has gained an important position in the Middle East, taking part in developing one of the world's largest oilfields.
Statoil was 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, after which the National Iranian Oil Company (NIOC) took over as formal operator.
Statoil is assisting the NIOC for a limited transitional period in accordance with the contractual framework for the development phase.
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.
The company will not make any future investments in Iran under the present circumstances, but it is committed to fulfilling its contract obligations in relation to South Pars.
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 section Risk review - Risk factors - Risks related to our business, for additional information about the risk of sanctions relating to activities in Iran.
The Natural Gas business area is responsible for Statoil's transportation, processing and marketing of natural gas worldwide, including the development of additional processing, transportation and storage capacity.
Natural Gas (NG) is also responsible for marketing gas supplies originating from the Norwegian state's direct financial interest (SDFI). In total, we account for approximately 80% of all Norwegian gas exports and are responsible for technical operation of the majority of the export pipelines and onshore plants in the processing and transportation system for Norwegian gas (Gassled*).
NG's business is conducted from three locations in Norway (Stavanger, Kårstø and Kollsnes) and from offices in Belgium, the UK, Germany, Turkey, Azerbaijan and the USA (Houston and Stamford).
In 2010, we sold 38.7 bcm (1.37 tcf) of natural gas from the Norwegian Continental Shelf (NCS) on our own behalf, in addition to approximately 35.3 bcm (1.25 tcf) of NCS gas on behalf of the Norwegian state. Statoil's total European gas sales, including third party gas, amounted to 85.9 bcm (3.04 tcf) in 2010. That makes us the second largest gas supplier to Europe.
In addition, we sold 5.5 bcm (0.19 tcf) of gas originating from our international positions, mainly in Azerbaijan and the USA, 3.0 bcm (0.11 tcf) of which was entitlement gas.
We have a significant interest in the NCS pipeline system owned by Gassled, which is the world's largest offshore gas pipeline transportation system, totalling approximately 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 United Kingdom. It thus gives us access to customers throughout Europe.
*This system is owned by Gassled in which Statoil has a 32.1% ownership interest at year end 2010. From 1 January 2011, Statoil's ownership is 28.5%.
In 2010, the gas market was characterised by gradually increasing gas prices and volatile customer off-take. Major maintenance projects at Kårstø and Kollsnes led to significantly reduced equity gas production in the third quarter.
In 2010, the European natural gas market was dominated by increasing supplies of LNG and only gradual recovery in demand.
We still expect short-term challenges resulting from increasing global supplies of LNG and slow recovery in European economies but expect growth in the gas markets in the long term. We expect demand for gas to continue to pick up along with a gradual industrial recovery and increased demand for gas in power generation. The new supply of LNG has also connected new emerging markets in Asia and Latin America to the global marketplace.
In the longer term, we believe natural gas will be an increasingly attractive commodity. According to the IEA World Energy Outlook 2010, estimated global gas consumption in 2030 will be 50% higher than the current level, reaching 4,500 bcm per year.
We market and sell our own gas as well as the Norwegian state's natural gas volumes, and we are the second largest gas supplier to Europe. We also market gas sourced from producing areas other than the NCS. Other major gas suppliers in Europe are Gazprom in Russia, Sonatrach in Algeria and GasTerra in the Netherlands. During 2010, Qatari LNG has also become a major European supplier. However, we believe that Norwegian natural gas exports will remain highly competitive due to reliability to Europe, 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 2010, 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.
The EU is set to import some 80% 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. Based on our infrastructure, we believe we are well positioned to supply part of this additional demand for imported natural gas.
Statoil participates in increasing gas production in Azerbaijan, and the Shah Deniz field in the Caspian Sea is a key asset. Gas is already exported from Azerbaijan to Georgia and Turkey via the South Caucasus Pipeline (SCP). We are working with our partners in Shah Deniz to commercialise the field's stage two development, including export solutions to Europe.
Statoil participates in the Trans Adriatic Pipeline (TAP), the aim of which is to connect the Italian market with gas flowing westwards from Turkey, through Greece and Albania. TAP is one of several pipeline projects competing for gas volumes from the Caspian region.
As the European energy markets are continuously facing changes in regulation and structures, we believe that natural gas will play an increasingly important role. This trend will be reinforced by further steps in Europe to curb climate gas emissions, in particular by the use of carbon pricing mechanisms such as the EU Emissions Trading Scheme. We expect continued growth in the use of natural gas as a source of electricity generation, as it is necessary to replace even more coal-based generation capacity with natural gas. 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 (a raft of 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.
For information about the EU Gas Directive, please see report section Operational review - Regulation - The EU Gas Directives.
Statoil is a long-term, reliable natural gas supplier with a strong position in some of the world's most attractive markets. We are the second largest gas supplier to Europe.
Statoil has end user sales business based in Belgium and the United Kingdom, serving major customers in Belgium, the UK, the Netherlands and France. 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 are also increasingly taking part in other liquid trading points, such as the TTF (Title Transfer Facility) in the Netherlands, the Zeebrugge Hub in Belgium and Gaspool /NCG in Germany.
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. On completion, the storage facility will comprise nine underground caverns. Statoil (UK) Limited owns one-third of the storage capacity being developed, of which the SDFI will have access to 48.3%. The facility has been developed and is operated by SSE Hornsea Limited. The limited commercial operation that started in 2009 continued in 2010. Full commercial operation of the nine-cavern facility is scheduled for 2012. The design capacity of the storage facility is expected to be 420 mmcm. Statoil's share of the total development cost is estimated to be NOK 0.7 billion.
In Germany, we hold a 30.8% stake in the Norddeutsche Erdgas-Transversale (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 will be handed over in 2011. All partners in Etzel Gas Storage are participating in this project.
The CPX capacity also includess 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 re-gasification 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. The agreement added a major building block to Statoil's gas value chain in the USA by providing access to large gas reserves geographically near the North East which, historically, is the highest paying gas market. This will thereby strengthen Statoil's USA gas position. Over time, Statoil expects this to result 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 billion cubic metres (bcm) per year/200,000 mcf/day directly from the Northern Marcellus production area to New York City and surrounding areas. In 2010, SNG concluded a transportation agreement with National Fuel Gas Supply Corporation for up to 3.2 billion cubic metres (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.
In December 2010, Statoil and Talisman formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale. As part of the joint venture, Statoil and Talisman have jointly acquired Enduring's Eagle Ford assets. At the same time, Statoil will buy into Talisman's existing Eagle Ford acreage and production. Together, in a 50/50 partnership Statoil and Talisman will hold 134,000 net Eagle Ford acres and associated assets and production in the joint venture. Initially, Talisman will take the lead as operator for the total acreage, with Statoil taking over the operatorship of 50% of the acreage within three years. Statoil expects that a significant proportion of the revenue from Statoil's Eagle Ford acreage will come from gas liquids and condensate. The Eagle Ford equity production will be a valuable addition to Statoil's oil and gas market portfolio in North America and it will contribute to bolstering value realisation.
The stage 2 development of Shah Deniz is currently in the concept selection phase of operator BP's capital value process. Field reserves support stage 2 production. In June 2010, the governments of Turkey and Azerbaijan signed a Memorandum of Understanding relating to the sale of gas to Turkey and transportation through Turkey to the European markets. Together with key partners in Shah Deniz, Statoil is currently negotiating sales contracts with several marketing companies in Europe and full sales and transit agreements with Botas in Turkey.
Over the last 30 years, the Norwegian gas pipeline system has been developed into an integrated system connecting gas-producing fields to 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 2010, the Gassled system transported 97.3 bcm (3.4 tcf) of gas to Europe.
In 2010, the Gassled system was again expanded through the merger with the Gjøa Gas Pipeline. 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.
The Gassled ownership interests were adjusted with effect from 1 January 2011. Petoro's interests increased by approximately 7% and all other parties reduced their interests proportionally. Statoil's direct ownership is 28.5% from 2011. Similar adjustments will be made to the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA. In addition, Statoil's future ownership interest in Gassled may change as a result of the inclusion of new infrastructure.
Statoil is 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.
Norways gas transport system tables
Norways gas transport system tables
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, or light oil, from the NCS received via the Statfjord pipeline, the Åsgard pipeline and the Sleipner condensate pipeline. The processing plant currently has a rich gas capacity of 88 mmcm per day. Products produced at Kårstø include ethane, propane, iso-butane, normal butane, naphtha and stabilised condensate. When all these elements have been separated from the gas, the remaining gas (dry gas) is sent to customers via the Statpipe, Europipe II and Rogass pipelines. The processing plant currently has a dry gas export capacity of 77 mmcm per day.
Over the last four years, the Kårstø processing plant has been undergoing comprehensive upgrading in order to meet safety and technical requirements and future needs. KEP is the project name for several projects aimed at making the Kårstø facilities more robust and ensuring safe and efficient operation. The investment is estimated to be around NOK 7.5 billion. The plan is that the remaining sub-projects will be completed between 2011 and 2012. In 2010, Kårstø produced 22.0 bcm of dry gas, 0.8 million tonnes of ethane, 3.6 million tonnes of LPG and 1.9 million tonnes of condensate/naphtha for export to customers worldwide. Capacity utilisation was 89.9% in 2010.
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 plant was initially built to receive gas from the Troll field in two 36-inch pipelines. In 2010, the Kollsnes projects (KOP) started with the aim of increasing the robustness of the plant and maintaining gas capacity, with a new 36-inch pipeline from the Troll Field to Kollsnes. In addition Kollsnes receives gas from the offshore fields Visund, Kvitebjørn and Fram. These volumes are processed through the NGL plant. The Kollsnes gas processing plant currently has a design capacity of 143 MSm3/day. The dry gas is sent to customers in France, Great Britain, Belgium, Netherlands, and Germany through the Zeepipe, Franpipe, Langeled and Norpipe pipelines.
Kollsnes is a swing producer based on customer off-take. During the year, monthly off-take generally varies between 25% and 100%. To maintain high availability as a swing producer, Kollsnes has invested NOK 500 million in 2009 and 2010 to upgrade the facilities through various robustness projects, such as electricity supply, turbo expanders and preventive maintenance of the compressors. In 2010, Kollsnes produced 36.4 bcm of dry gas and 1.9 MSm3 of condensate.
Statoil manages, transports and markets approximately 80% of all NCS gas.
Due to the relatively large size of the NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, a large proportion of Statoil's gas sales contracts are long-term contracts that typically run for 10 to 20 years or more. Under these contracts, the buyers agree to take a minimum daily volume and a minimum annual volume of gas. If this volume is not taken, the buyers are nevertheless obliged to pay for the contracted volume. The majority of Statoil's long-term sales contracts have reached plateau level.
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 gasoil. In our gas portfolio, we also have gas sales contracts in the UK that are priced with reference to a gas spot market index. There can be significant price fluctuations during the life of the contract. Under the traditional long-term contracts, prices are typically adjusted quarterly and are calculated on the basis of the prevailing prices for substitute fuels in the three to nine months prior to the adjustment date. However, the price formula, which allows such quarterly adjustment, does not pick up on all trends in the marketplace, such as changes in the taxation of gas and competing fuels imposed by national governments. That is why most of the 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 2010, Statoil was involved in such commercial discussions for significant volumes covered by long-term sales contracts. The outcome of these discussions has generally been the introduction of a smaller 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.
Manufacturing & Marketing adds value through the processing and sale of the group's and the Norwegian state's production of crude oil and natural gas liquids.
Manufacturing & Marketing (M&M) is responsible for the group's transportation, processing, marketing and trading of crude oil, natural gas liquids and refined products. We run two refineries, one methanol plant and three crude oil terminals. Our international trading activities make us one of the world's largest crude oil traders.
In 2010, we traded 694 million barrels of crude oil and condensate, approximately 18 million tonnes of refined oil products and 13 million tonnes of natural gas liquids (NGL). The refinery throughput was 14.7 million tonnes. Tjeldbergodden produced approximately 10% of the European market's demand for methanol.
Refining margins improved in 2010, but were still low compared with 2008. In addition, trading results were lower than in 2009. Statoil Fuel & Retail was listed on Oslo Stock Exchange.
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 SDFI's equity production of crude oil and NGL, in addition to third party volumes. In 2010, our total sales of crude and condensate were equivalent to 694 million bbls, including supplies to our own refineries. The main crude oil market for Statoil is north-western 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 694 million bbls sold in 2010, approximately 44% were Statoil's own equity volumes.
We operate the South Riding Point crude oil terminal in the Bahamas and are also responsible for optimising commercial utilisation of the crude terminal located at Mongstad. 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 utilisation of third party assets.
In 2010, Statoil and its subsidiary, SFR, entered into fuel product supply agreements under which SFR is supplied exclusively by Statoil with respect to certain oil products sold by SFR in Scandinavia and the Baltic states until 31 December 2015, unless the agreements are terminated pursuant to the early termination provisions or extended. SFR's aviation business is also mainly supplied by Statoil, under one of these supply agreements, and under agreements with SFR subsidiaries.
Statoil holds the lease for the South Riding Point crude oil terminal in the Bahamas until 2049. The lease includes oil storage as well as loading and unloading facilities.
The terminal, which is located on Grand Bahama Island, consists of two shipping berths and ten storage tanks with storage capacity for 6.75 million barrels of crude.
We have started a project to upgrade the terminal to enable the blending of crude oils, including heavy oils. Future blending operations will normally be carried out onshore, but facilities will also be installed that enable blending from ship to ship at the jetty.
This terminal will both support our global trading ambitions and improve our handling capacity for heavy oils. New blending facilities and full terminal capacity will strengthen both our marketing and trading positions in the North American market. The terminal will also be an important part of our plans to market our own volumes of heavy oil.
In addition to the existing lease period, we have an option to extend the agreement for an additional 30 years until 2079.
Statoil is majority owner and operator of the Mongstad refinery and Tjeldbergodden methanol plant in Norway and sole owner and operator of the Kalundborg refinery in Denmark. We also operate the Oseberg Transportation System.
We are majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil distillation capacity of 180 mbbl per day. We are sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbl per day. In addition, we have rights to 10% of production capacity at the Shell-operated refinery in Pernis, the Netherlands, which has a crude oil distillation capacity of 400 mbbl per day. Our methanol operations consist of an 81.7% stake in the gas-based methanol plant at Tjeldbergodden, Norway, which has a design capacity of 0.95 million tonnes per year.
We also operate the Oseberg Transportation System (36.2% stake) including the Sture crude oil terminal. The 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.
The following table shows operating characteristics for the plants at Mongstad, Kalundborg and Tjeldbergodden.
The improvement programme for cost savings and increased value added reached its targets for 2010. The programme will be continued in coming years with the aim of further improving Kalundborg's competitive position.
The Mongstad refinery is a medium-sized, modern refinery. It is linked to offshore fields, the Sture crude oil terminal and the Kollsnes gas processing plant, making it an attractive site for landing and processing hydrocarbons.
The Mongstad refinery, which was built in 1975, was significantly expanded and upgraded in the late 1980s. It has been subject to considerable investment over the last 15 years in order to meet new product specifications and improved energy efficiency. A medium-sized, modern refinery, it is directly linked to offshore fields through two crude oil pipelines, through a natural gas liquids (NGL)/condensate pipeline to the crude oil terminal at Sture and the gas processing plant at Kollsnes, and by a gas pipeline to Kollsnes. This makes Mongstad an attractive site for landing and processing hydrocarbons and for the further development of our oil and gas reserves.
In addition to the refinery, the main facilities at Mongstad consist of a crude oil terminal, an NGL process unit and terminal, and a combined heat and power plant (CHP). Statoil owns 65% of the crude terminal. A large proportion of its crude oil comes via two direct pipelines from the Troll field. The storage capacity is 9.4 million barrels of crude.
Vestprosess, which is owned 34% by Statoil, transports and processes NGL and condensate. The Vestprosess pipeline connects the Kollsnes and Sture plants to Mongstad. The NGL is fractionated in the Vestprosess NGL unit to produce naphtha, propane and butane.
The CHP plant, which is 100% owned by Dong Generation Norge AS, receives gas from Troll and the refinery for the production of electric power and heat.
The refinery is owned 79% by Statoil and 21% by Shell.
Approximately 45% of Mongstad's total production is delivered to Scandinavian markets, and 55% is exported to north-western Europe and the United States. The following table shows the approximate quantities of refined products (in thousand tonnes) produced at Mongstad for the periods indicated. In addition to crude, the Mongstad refinery upgrades large volumes of heavy fuel oil, NGL from Oseberg and Tune, and condensate from Troll, Kvitebjørn, Visund and Fram.
The Mongstad refinery can manufacture products to meet different specifications through in-line blending during ship loading.
The refinery's reliability (i.e. its on-stream factor) was high in 2010, while we experienced some operational problems during 2008 and 2009. There were also shutdowns due to the market situation in 2009. In 2008, the largest turnaround in Mongstad's history was executed on schedule, and we also carried out a major turnaround in 2010. Capacity utilisation (the share of available plant capacity actually used) was reduced in 2009. This was also due to the market situation.
The new CHP plant started commercial operation on 20 December 2010, and was part of a strategically important project for Manufacturing & Marketing. The plant improves the Mongstad refinery's energy efficiency and has a capacity of approximately 280 megawatts of electric power and 350 megawatts of process heat. The plant will have a gradual start-up phase as the refinery needs less steam due to a changed feedstock pattern, lower throughput and the postponement of projects. The plant is operated by Dong Energy, with Statoil paying an annual tariff for its use. There is an agreement with the Troll licensees to supply power to the Troll A gas platform and the associated Kollsnes onshore processing plant. In addition to the CHP plant, the CHP investment project included a new gas pipeline from Kollsnes and necessary modifications at the refinery.
Together with the Norwegian Government, Statoil is involved in several projects that aim to develop solutions for carbon capture and storage (CCS) at Mongstad. See section Operational review - Technology & New Energy - New energy for further information.
The Kalundborg refinery is a small but flexible oil refinery. This enables it to produce a variety of products, although its main products are low-sulphur petrol and diesel for markets in Denmark and Sweden.
The refinery is connected via two pipelines (one gasoline and one gasoil) to our terminal at Hedehusene near Copenhagen, and most of our products are therefore sold locally.
Kalundborg's refined products are also supplied to other markets in north-western Europe, mainly Sweden and England.
The following table shows the approximate quantities of refined products (in thousand tonnes) produced by Kalundborg in the periods indicated.
The refinery's reliability (i.e. its on-stream factor) was good in 2010 and on a par with the best years. The throughput in 2010 was lower than in 2009 due to a planned maintenance turnaround, while it was lower in 2009 than in 2008 due to the economic downturn. The product yield from the refinery is well positioned in relation to the expected future demand structure in the European market.
The methanol plant at Tjeldbergodden is the largest in Europe and one of the most energy efficient in the world. It is supplied with natural gas from the Heidrun field in the Norwegian Sea through Haltenpipe.
Statoil owns 81.7% of the plant, which has a maximum proven capacity of 0.92 million metric tonnes per year (mmtpa). The actual throughput in 2010 was reduced due to a planned maintenance turnaround. Methanol production in 2010 was 0.80 mmtpa.
We also own 50.9% of Tjeldbergodden Luftgassfabrikk DA, one of the largest air separation units (ASU) in Scandinavia.
The Sture terminal receives crude oil in two pipelines from the Oseberg area and the Grane field in the North Sea. The terminal is part of the Oseberg Transportation System in which Statoil has a 36.2% stake.
The terminal has storage capacity for 6.3 million barrels of crude.
The processing facilities at Sture stabilise Oseberg crude oil and recover LPG mix (propane and butane) and naphtha. Oseberg Blend and Grane crude qualities and LPG mix are exported. LPG and naphtha are also transported through the Vestprosess pipeline to Mongstad.
The LPG processing capacity is max. 68 tonnes/hr. The import capacity is approx. 96,000 cm/d of Oseberg blend, and approx. 40,000 cm/d of Grane oil.
Technology & New Energy is responsible for the development and implementation of technology and renewable energy, thereby contributing to solutions crossing energy frontiers.
Technology & New Energy (TNE) is responsible for ensuring capacity and expertise in the field of technology in addition to creating distinct technological solutions for global growth. This includes delivering innovative and competitive technological solutions for exploration, increased recovery, field development and safe, efficient and environmentally friendly operations. The research and development division, which has research centres in Trondheim, Bergen and Porsgrunn in Norway and in Calgary in Canada, is engaged in research and development as well as first use of new technology.
Climate change, supply security and growing demand for clean energy are opening up new business opportunities for Statoil, particularly in carbon capture and storage (CCS) and offshore wind power. Statoil is in a position to seize these opportunities by utilising core capabilities from the oil and gas industry. Statoil's New Energy business entity is responsible for the company's efforts in renewable energy. The activities are grouped under renewable energy production, new options and carbon management.
This is an overview of key events relating to TNE in 2010.
Our research and development (R&D) efforts focus on the technology areas identified as addressing our key business challenges. The aim is to secure future returns and strengthen our technology positions to give us a competitive advantage.
The R&D portfolio is organised in five programmes throughout the oil and gas value chain: Exploration, Increased Recovery, New development solutions, the Oil and gas value chain and New energy and HSE. R&D also addresses business challenges connected to the Gulf of Mexico and extra heavy oil in Canada. We also have an academia programme that addresses cooperation with universities and research institutes.
R&D expenditure has been stable for the last four years at approximately NOK 2.0 billion per year.
Cooperation with external partners such as academic institutions, R&D institutes and suppliers is crucial in relation to technology. Statoil aims for a 50/50 split between internal and external R&D spending.
Statoil has three research centres in Norway and a heavy oil technology centre in Canada. The R&D organisation is responsible for operating and further developing our world-class laboratories and experimental rigs.
New development solutions
Oil and gas value chain
New Energy and HSE
Extra heavy oil
Gulf of Mexico
By supporting collaboration between universities, research institutions and industry, we also contribute to building a strong Norwegian petroleum cluster. Through the R&D programmes and our international offices, we also cooperate with international universities and organisations in Canada, the USA, China and Brazil, among other countries.
Our renewable energy business focuses in particular on developing profitable business in areas where we may have a competitive edge as a result of our offshore expertise. Key areas are offshore wind and carbon capture and storage.
Offshore wind projects
When Sheringham gradually starts operating in 2011, it is expected to generate an estimated 1.1 TWh annually, equivalent to the annual energy consumption of 220,000 British homes. It will also save an estimated half a million tonnes of carbon dioxide emissions per year compared with energy produced using conventional methods in the UK.
Dogger Bank could be the world's largest wind power development, with a targeted capacity of 9GW, which is equivalent to nearly 10% of the total electricity needs in the UK. Due to the size of the area, the development will have to take place in phases. Dogger Bank covers nearly 9,000 square kilometres off the Yorkshire coastline, where depths range from 18 to 63 metres.
Carbon capture and storage (CCS)
Statoil is also engaged in the development of potential medium and long-term breakthrough technologies for carbon capture. Together with Gassnova (which represents the Norwegian government in matters relating to CCS), the South African integrated energy and chemical company Sasol, and Shell, we are building a centre for carbon capture technologies at Mongstad, known as the CO2 Technology Centre Mongstad (TCM).
The technology centre aims to help suppliers develop more cost-efficient, environmentally friendly and safe technologies for carbon capture to handle emissions from different flue gas sources, such as gas power, coal power and refineries. The centre is expected to have capacity to capture up to 100,000 tonnes of carbon dioxide annually. It represents an important step towards full, industrial-scale carbon capture. Construction work is progressing according to plan after starting in summer 2009, and start-up is scheduled for early 2012.
CCS business development
Potential storage sites are restricted to sedimentary basins that are spread around the world. These basins are found both onshore and offshore, mostly in the vicinity of land areas. Statoil has established a subsurface team dedicated to mapping and maturing future carbon storage. The ambition is to store our own carbon dioxide (for example from our own production of CO2-rich natural gas streams like Sleipner), and third party carbon dioxide (for example from captured CO2 from coal-fired power plants).
We are among the front runners in terms of applying technology in the oil and gas industry.
We achieve this by providing best practice support, devising world-class concepts for our development projects, and by heading up corporate initiatives designed to improve performance.
Our technological expertise enhances our performance in areas such as exploration, improved oil recovery (IOR) and integrated operations (IO). Technology development is used to promote and achieve corporate targets for production growth, increased regularity, reduced costs and improved drilling efficiency.
We also support innovators and entrepreneurs with technology developments and commercialisation activities, thus helping to create robust suppliers and new technology products that are vital to our oil, gas and new energy activities. Statoil has ownership interests and is involved in all major Science Parks and Incubators in Norway, and benefits from venture activities aimed at accessing new technologies. Through a special purpose company, Energy Capital Management AS, Statoil uses venture capital as a tool for accessing new technologies.
Selected advances made in 2010 are summarised below:
Extra heavy oil and the Leismer field
New system for open hole well-testing
Autonomous production valve
Projects & Procurement (PRO) is responsible for planning and executing all major development and modification projects, and for project and operational procurements, including securing rig capacity based on the corporate rig strategy.
PRO aims to be world-class in terms of project execution, to deliver on time and within budget and in accordance with high HSE standards and agreed quality standards. To become a truly global energy player, it is essential that Statoil is capable of executing projects at the very highest level, thereby strengthening the company's international competitiveness.
Key events in Projects & Procurement in 2010 include the start up of production on Gjøa and Leismer, and Peregrino reaching the final project phase.
Our project portfolio is diverse. It ranges from major new field developments to both small and large redevelopment projects on the Norwegian continental shelf (NCS) and internationally. We have also started on cessation projects on the NCS.
In 2010, we finalised 17 projects. Two mega-projects were ongoing in 2010: Gjøa and Peregrino. The Gjøa platform started production on 7 November. Peregrino is currently in the final development stage and production start-up is scheduled for the first quarter 2011.
Gudrun, an important Greenfield project on the NCS, was approved by the Norwegian authorities in 2010. The Gudrun field is scheduled to start production in the first quarter 2014.
The first four fast track subsea satellite tie-in projects are on schedule. All fast track developments consist of a single subsea template, a few wells and tie-back to existing systems. Statoil's portfolio is being expanded by a new wave of projects that are planned to be developed at reduced costs and on shorter schedules by industrialising execution and using standard equipment.
Executing projects internationally - an essential part of fulfilling the group's ambitions to become a truly global energy player - adds a further element of complexity to our business. Examples of our contributions in this respect are:
In building Statoil's international reputation as a world-class executor of projects, the way in which Statoil delivers results is of great importance. This means delivering on time and cost without compromising our high HSE and ethical standards.
On 17 March 2010, Statoil ASA's board of directors approved the creation of a stand-alone energy and retail business by means of an initial public offering (IPO) on the Oslo Stock Exchange.
In October 2010, Statoil's Energy & Retail business became a stand-alone entity, Statoil Fuel & Retail ASA, through an initial public offering and listing on the Oslo Stock Exchange. Statoil continues to own 54% of the shares in Statoil Fuel & Retail and consolidates the results of Statoil Fuel & Retail in its financial statements.
Statoil Fuel & Retail is a leading Scandinavian road transportation fuel retailer with over 100 years of operations in the region. Statoil Fuel & Retail also has established with a strong presence in Poland, Latvia, Lithuania and Estonia. In Russia, Statoil Fuel & Retail has a presence in the fuel retail market in the Murmansk, St. Petersburg/Leningrad and Pskov regions.
As at 31 December 2010, Statoil Fuel & Retail had a network of 2,283 fuel stations across its eight countries of operations, comprising a combination of full-service stations, which have integrated convenience stores, and automated fuel stations and truck stops. Of these, 1,765 fuel stations are located in Scandinavia, and 518 are located in Poland, Latvia, Lithuania, Estonia and Russia.
In addition, Statoil Fuel & Retail is involved in the sale of stationary energy (mainly heating oil, kerosene, LPG and heavy fuel for industrial purposes) and marine fuel (marine gasoil and heavy fuel) as well as aviation fuel, lubricants and chemicals.
Statoil's overall strategic objective is to build a globally competitive company and an exceptional place to perform and develop.
During the last few years, Statoil has expanded into new business activities, both geographically and into emerging technologies, such as deepwaters, heavy oil and shale gas. In order to succeed in these activities, we must have the right organisational and people capabilities, as well as the ability to attract new talents globally.
Through global people policies, Statoil aims to ensure consistent common standards across the organisation. Together with our values and ethics code of conduct, our people policies are the most important guidelines for the people processes. We endeavour to ensure a good match between the professional interests and goals of every employee and the needs of the business. Through our global development and deployment process, we endeavour to offer challenging and meaningful job opportunities. Statoil remains committed to providing financial and non-financial rewards that attract and motivate the right people, and it continues to focus on equal opportunities for all employees.
Through the Statoil 2011 reorganisation, effective from 1 January 2011, Statoil has accelerated the development of new leaders, and significantly expanded the proportion of female and international leaders.
The Statoil group employs approximately 30,300 permanent employees. Of these were 10,400 employees within the Statoil Fuel & Retail group, of which we held a 54% majority ownership interest as of 31 December 2010. Approximately 19,000 of Statoil group's employees are employed in Norway and approximately 11,300 outside Norway.
In 2010, the Statoil group recruited almost 3,400 new employees. The table below provides an overview of the number of permanent employees and percentage of women in the Statoil group from 2008 to 2010.
We believe Statoil's low turnover rates reflect a high level of satisfaction and engagement among its employees, which is also supported by the results of the annual organisational and working environment survey. In Statoil ASA, the total turnover rate for 2010 was 0.9%. The figure opposite provides an overview of the total turnover rate by gender and age in Statoil ASA.
We are committed to building a workplace that promotes diversity and inclusion through its people processes and practices.
At 31 December 2010, the overall percentage of women in the company was 37%, and 40% of the board of directors were women, and 20% of the corporate executive team were women. The focus on diversity issues is also reflected in the company's people strategy. One of the key priorities in 2010 has been to strengthen diversity in the leadership pipeline. At the end of December 2010, the total proportion of female managers in Statoil ASA was 25%, and, among managers under the age of 45, the proportion was 34%.
We also devote close attention to male-dominated positions and discipline areas. In 2010, 26 % of staff engineers were women, and among staff engineers with up to 20 years' experience, the proportion of women was 31 %. The proportion of female skilled workers in 2010 was 16 %.
The reward system in Statoil is non-discriminatory and supports equal opportunities, which means that, given the same position, experience and performance, men and women will be at the same salary level. However, due to differences between women and men in types of positions and number of years' experience, there are some differences in compensation when comparing the general pay levels of men and women.
We believe that being a global and sustainable company requires people with a global mindset. One way to build a global company is to ensure that recruitment processes both within and outside Norway contribute to a culturally diverse workforce. Outside Norway, we need to continue to focus on increasing the number of people and managers that are locally recruited, and to reduce long-term, extensive use of expats in our business operations.
Statoil's cooperation with employee representatives and trade unions is based on confidence, trust and continuous dialogue between management and the people in various cooperative bodies.
In Statoil, 68% of the employees in the parent company are members of a trade union. Work councils and working environment committees are established where required by law or agreement.
In 2010 the collaboration model for the Norwegian part of our business, agreed on by the unions and Statoil, played an important role in cooperation in the Statoil 2011 reorganisation. The collaboration model was established in 2009 with the finalisation of the merger between Statoil and Hydro's oil and gas division and is founded on the principles of simplification and decentralisation.
In 2010 the European Work Council (EWC) served as a central arena for dialogue between the Company management and the employees in the demerging of Statoil Fuel & Retail. The EWC is an arena where Statoil's employees in Europe receive relevant information on a regular basis, and engage in direct dialogue with management on matters concerning the group as a whole. Two conferences were held in 2010 where the main topic was the demerger.
in 2010 where the main topic was the demerger. In 2010, the ICEM agreement with the International Federation of Chemical, Energy, Mine and General Workers Union was renewed for another two-year period.
The following table shows significant subsidiaries owned directly by the parent company, as well as the parent company's equity interest and the subsidiaries' country of incorporation as at 31 December 2010.
Our voting interest is in each case equivalent to our equity interest.
Statoil's operational review accords with the organisation of its operations as at 31 December 2010, whereas certain disclosures about oil and gas reserves are based on geographical areas as required by the Securities and Exchange Commission (SEC).
Statoil prepared its operational review in accordance with its segment (business area) structure as at 31 December 2010. Each business area is presented individually, and includes underlying business clusters according to how the business area organises its operations. For information regarding Statoil's new segment structure, effective 1 January 2011, see section Business overview and strategy - New organisational structure as from January 2011.
For further information on extractive activities, refer to sections Operational review - E&P Norway and Operational review - International E&P, respectively.
Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures based upon geographical areas as required by the SEC. The geographical areas are defined by continent, and consist of Norway, Eurasia excluding Norway, Africa and the Americas.
For further information on disclosures for oil and gas reserves and certain other supplemental disclosures based upon geographical areas as required by the SEC, refer to the section Operational review - Proved oil and gas reserves.
This section describes our oil and gas production and sales volumes.
The following table shows our Norwegian and international entitlement production of crude oil and natural gas for the periods indicated. The stated production volumes are the volumes that Statoil is entitled to pursuant to conditions laid down in licence agreements and production sharing agreements. The production volumes are net of royalty oil paid in kind and of gas used for fuel and flaring. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian state's oil and natural gas. Production of an immaterial quantity of bitumen is included in crude oil production. Disclosures for the years end 31 December 2010 and 2009 are based on the SEC's revised requirements for geographical areas applicable starting in 2009 which were applied prospectively. The information for 2008 was not restated.
The following tables present the average unit of production cost based on entitlement volumes and realised sales prices. The information has been split by continent for 2010 and 2009, while this split was not required for 2008.
Proved oil and gas reserves were estimated to be 5,325 mmboe at year end 2010, compared with 5,408 mmboe at the end of 2009.
Statoil's proved reserves are estimated and presented in accordance with Securities and Exchange Commission (SEC) Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins, as issued by the SEC staff. In January 2009, the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis for the 2009 and 2010 estimations of proved reserves. For additional information, see "Critical accounting judgements and key sources of estimation uncertainty; Key sources of estimation uncertainty; Proved oil and gas reserves" in note 2 Significant accounting policies to the Consolidated Financial Statements. For prior period figures, see note 35 Supplementary oil and gas information to the Consolidated Financial Statements.
Summary of oil and gas reserves as of 31 December 2010 based on average fiscal year prices.
Statoil's proved reserves of bitumen in America is included as oil in the table above as they represent less than 3% of our proved reserves which is regarded as immaterial.
Basis for equivalents as given in section Terms and definitions.
Changes in proved reserves estimates are most commonly the result of revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or the inclusion of proved reserves in new discoveries through the sanctioning of development projects. These are sources of additions to proved reserves that are the result of continuous business processes and can be expected to continue to add reserves at some level in the future. Proved reserves can also be added or subtracted through the acquisition or disposal of assets.
Changes in proved reserves can also be due to factors outside management control, such as changes in oil and gas prices. Proved reserves as of 31 December 2010 and 2009 have been determined on the basis of a 12-month average price, whereas proved reserves for 2008 are based on year-end prices. While higher oil and gas prices normally allow more oil and gas to be recovered from the accumulations, Statoil will generally receive smaller quantities of oil and gas under production sharing agreements (PSAs) and similar contracts. These changes are included in the revisions category in the table below.
In Norway, reserves are recorded as proved when a development plan is submitted, since there is reasonable certainty that such a plan will be approved by the regulatory authorities. Outside Norway, reserves are booked as proved when regulatory approval is received, or when such approval is imminent. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years.
Additions that have contributed to our proved reserves in 2010 are:
New discoveries with reserves booked in 2010 all start production in the period from 2010 to 2014.
In 2010, Statoil announced the sale of a 40% interest in the Peregrino field in Brazil and the sale of a 40% interest in the oil sands leases in Alberta, Canada. As of 31 December 2010, these sales had not been approved by the relevant authorities and therefore the reduction in reserves is not reflected in the 2010 proved reserves statement. The sale of the interest in Canada, was approved by the relevant authorities on 21 January 2011. The expected effect on the 2011 proved reserves statement is approximately 66 million boe sales of reserves-in-place.
Sanction of development plans for several new fields and projects have contributed to more reserves in the extensions and discoveries category in 2010 compared to 2009. In 2009 approval of further development plans for several of our producing fields on the NCS contributed positively to revisions of proved reserves. The same number of development plans have not been approved in 2010 giving less contribution to the revisions and improved recovery category in 2010 compared to 2009. The table below shows the additions to reserves in each category relating to the reserve replacement ratio for the years 2010, 2009 and 2008. The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves, divided by produced volumes in any given period.
The reserves replacement ratio was 87% in 2010, compared with 73% in 2009. The increase in the reserves replacement ratio in 2010 compared with 2009 is mainly due to 2010 being a year with more additions to reserves from new fields, sanctioned future development plans for producing fields, revisions due to production experience and further drilling of wells and reduced production. The average replacement ratio for the last three years was 64%, including purchases, sales and the reduction of interest in Petrocedeño in 2008.
The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity related to the timing of project sanctions, and the time lag between exploration expenditure and the booking of reserves.
Preparation of reserves estimates
Although this team reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves, is collected from the assets and checked for consistency and conformity with applicable standards by CEPF. The final numbers for each asset are quality controlled and signed off by the responsible asset manager, before aggregation to the required reporting level by CEPF.
The aggregated results are submitted for approval to the relevant business area management teams and the corporate executive committee and finally presented to the board of directors.
The person with primary responsibility for overseeing the preparation of the reserves estimates is the chair of the CEPF team. The person who presently holds this position has a Bachelor's degree in Earth Sciences from the University of Gothenburg, and a Master's degree in Petroleum Exploration and Exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 25 years' experience of the oil and gas industry, 24 of which are with Statoil. She is a member of the Norwegian Petroleum Society and vice-chair of the UNECE Expert Group on Resource Classification (EGRC).
Development of reserves
Sanctioning of new projects, such as Gudrun, Marulk, Valemon and Visund South in Norway, Jack and St. Malo in the Gulf of Mexico, CLOV in Angola and West Qurna 2 in Iraq, added a total of 233 million boe of proved undeveloped reserves in 2010.
As of 31 December 2010, the total proved undeveloped oil and gas reserves amounted to 1,350 million boe, 56% of which is related to fields in Norway. The Peregrino field in Brazil represents the largest undeveloped asset and, together with other fields not in production, such as Skarv, Valemon, Gudrun and Goliat in Norway, CaesarTonga, Jack and St. Malo in GoM USA, Corrib in Ireland and the Kizomba satellites Pazflor and CLOV in Angola, these fields represent approximately 28% of the total proved undeveloped reserves at year end 2010. Significant undeveloped reserves are also related to large gas fields on the NCS with continuous development activities, such as Snøhvit and Troll, and the Petrocedeño field in Venezuela.
In 2010, Statoil incurred NOK 54 billion in development costs relating to assets carrying proved reserves, NOK 29 billion of which was related to moving proved undeveloped reserves to developed reserves.
Due to the nature of large fields with continuous development activity, such as Troll and Snøhvit in Norway, Azeri-Chirag-Gunashli in Azerbaijan and Petrocedeño in Venezuela, these fields contain reserves that are expected to remain undeveloped for five years or more. All these projects are large field developments, three of them offshore, with several billion dollar investments having been made in complex infrastructure. The development of these fields will require extensive, sustained drilling of wells for a long period of time. A large proportion of the central facilities are already in place, and a significant part of the total investments have been made. It is highly unlikely that either of these field development projects would be prematurely terminated, since this would result in a significant loss of capital.
Additional information about proved oil and gas reserves is provided in note 35 - Supplementary oil and gas information - to our consolidated financial statements.
As of 31 December 2010, the Statoil/SDFI arrangement amounted to a total of 26.3 tcf (745 bcm) in total gas commitments from the NCS. The principles for the booking of proved reserves are limited to contracted gas sales or gas with access to a robust gas market.
The majority of Statoil's gas volumes are sold under long-term contracts with take-or-pay clauses. For each individual year, Statoil and SDFI express their delivery commitments as the sum of the annual contract quantity (ACQ). In the contract years 2010 to 2013, the total ACQ for the respective years are: 2.48, 2.48, 2.41, and 2.41 tcf. The majority of the delivery commitments will be met by production from our existing proved reserves from fields where Statoil and/or SDFI participates, while any shortfalls will be covered by use of storage or sourcing in the market.
Operational statistics include information about acreage and the number of wells drilled.
Productive oil and gas wells and developed and undeveloped acreage
A gross value reflects wells or acreage in which Statoil has interests (presented as 100%). The net value corresponds to the sum of whole or fractional working interest for Statoil in gross wells or acreage.
The total gross number of productive wells as of end 2010 includes 370 oil wells and 16 gas wells with multiple completions or wells with more than one branch.
The largest concentrations of developed acreage in Norway are in Troll, Ormen Lange, Snøhvit and Oseberg. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of developed acreage (gross and net).
Undeveloped acreage concentration in Eurasia excluding Norway is in the Faroes with six exploration licences representing some 40% of the total net acreage in this geographical area. Our largest acreage concentration in Africa is the Hassi Mouina blocks in Algeria representing about one-third of the total net acreage in Africa. Most of the undeveloped acreage in America is located in the Gulf of Mexico. We also have large acreage concentrations in America in the Marcellus shale play located in the Appalachian region in north-eastern USA, in the Camamu-Almada Basin in off-shore Brazil, in oil sands located in the Athabasca region of Alberta, Canada, and off the coast of Newfoundland, Canada.
Net productive and dry oil and gas wells drilled
Related to our oil sand development in the Athabasca region of Alberta we also drilled 156 wells in 2010 to map and delineate the bitumen pay. All of these wells were logged and almost 100% were cored. We also drilled 11 wells in which we were searching for suitable water source or disposal water zones. Some of these were abandoned and some completed for water needs.
Exploratory and development drilling in process
Statoil's estimates of proved reserves are not materially different from those prepared by independent petroleum engineering consultants.
Petroleum engineering consultants DeGolyer and MacNaughton have carried out an independent evaluation of Statoil's proved reserves as of 31 December 2010. The evaluation accounts for 100% of Statoil's proved reserves. The aggregated net proved reserves estimates prepared by DeGolyer and MacNaughton do not differ materially from those prepared by Statoil when compared on the basis of net equivalent barrels.
A reserves audit report summarising this evaluation is included as Exhibit 15 (a)(iii).
The principal Norwegian legislation governing our petroleum activities in Norway comprises the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.
The principal Norwegian legislation governing our petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of 29 November 1996 (the "Petroleum Act"), and the regulations issued thereunder, and the Norwegian Petroleum Taxation Act of 13 June 1975 (the "Petroleum Taxation Act"). The Petroleum Act sets out the principle that the Norwegian state is the owner of all subsea petroleum on the NCS, that exclusive right to resource management is vested in the Norwegian state and that the Norwegian state alone is authorised to award licences for petroleum activities. We are dependent on the Norwegian state for approval of our NCS exploration and development projects and our applications for production rates for individual fields.
Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible for resource management and for administering petroleum activities on the NCS. The main task of the Ministry of Petroleum and Energy is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Norwegian parliament, the Storting, and relevant decisions of the Norwegian State. The Ministry of Petroleum and Energy primarily implements petroleum policy through its powers to administer the awarding of licences and to approve operators' field and pipeline development plans. Only those plans that conform to the policies and regulations adopted by the Storting are approved. As set out in the Petroleum Act, if a plan involves an important principle or will have a significant economic or social impact, it must also be submitted to the Storting for acceptance before being approved by the Ministry of Petroleum and Energy.
We are not required to submit any decisions relating to our operations to the Storting. However, the Storting's role in relation to major policy issues in the petroleum sector can affect us in two ways: firstly, when the Norwegian State acts in its capacity as majority owner of our shares and, secondly, when the Norwegian State acts in its capacity as regulator:
Although Norway is not a member of the European Union, or EU, it is a member of the European Free Trade Association (EFTA). The EU and its member states have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, with the members of EFTA (except Switzerland).
The EEA Agreement makes certain provisions of EU law binding between the states of the EU and the EFTA states, and also between the EFTA states themselves. An increasing volume of regulation affecting us is adopted within the EU and then applied to Norway under the EEA Agreement. As a Norwegian company operating both within EFTA and the EU, our business activities are regulated by both EEA law and EU law to the extent that EU law has been incorporated into EEA law under the EEA Agreement.
Production licences are the most important type of licence awarded under the Petroleum Act, and the Ministry of Petroleum and Energy holds executive discretionary power to and award a production licences and to decide the terms of that licence.
By the end of 2010, we participated in 213 licences on the NCS. As a participant in licences, we are subject to the regulations of the Norwegian licensing system.
Production licences are the most important type of licence awarded under the Petroleum Act, and the Ministry of Petroleum and Energy holds executive discretionary powers to award a production licence and to decide the terms of that licence. The Government is not entitled to award us a licence in an area until the Storting has decided to open the area in question for exploration. The terms of our production licences are decided by the Ministry of Petroleum and Energy.
A production licence grants the holder an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the licence. Notwithstanding the exclusive rights granted under a production licence, the Ministry of Petroleum and Energy has the power, in exceptional cases, to permit third parties to carry out exploration in the area covered by a production licence. For a list of our shares in production licences, see section Operational review - E&P Norway - Production on the NCS.
Production licences are normally awarded in licensing rounds. The first licensing round for NCS production licences was announced in 1965. The award of the first licences covered areas in the North Sea. Over the years, the awarding of licences has moved northward to cover areas in both the Norwegian Sea and the Barents Sea. In recent years, the principal licensing rounds have largely concerned licences in the Norwegian Sea.
The Norwegian State accepts licence applications from individual companies and group applications. This allows us to choose our exploration and development partners.
Production licences are awarded to joint ventures. As is the case for most fields on the NCS, our production activities are conducted through joint venture arrangements with other companies and, in some cases, with the Norwegian State through its wholly-owned company Petoro AS. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the licence. Once a production licence is awarded, the licensees are required to enter into a joint operating agreement and an accounting agreement that regulate the relationship between the partners. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.
The governing body of the joint venture is the management committee. In licences awarded since 1996 where the SDFI holds an interest, the Norwegian State, acting through Petoro AS, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the licence with respect to the Norwegian State's exploitation policies or financial interests. This veto power has never been used.
The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. By the end of 2010, we were the operator for 157 of our 213 licences on the NCS. The operator is in practice always a member of the joint venture holding the production licence, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement, under which the operator can normally terminate its engagement by giving six months' notice. However, with the consent of the Ministry of Petroleum and Energy, the management committee may instruct the operator to continue to perform its duties until a new operator has been appointed. The management committee can terminate the operator's engagement by giving six months' notice through an affirmative vote by all members of the management committee other than the operator. A change of operator requires the consent of the Ministry of Petroleum and Energy. In special cases, the Ministry of Petroleum and Energy can order a change of operator.
Licensees are required to submit a plan for development and operation, or PDO, to the Ministry of Petroleum and Energy for approval. In respect of fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Until the PDO has been approved by the Ministry of Petroleum and Energy, the licensees cannot undertake material contractual obligations or commence construction work without the prior consent of the Ministry of Petroleum and Energy.
Production licences are normally awarded for an initial exploration period, which is typically six years, but which can either be for a shorter period or for a maximum period of ten years. During this exploration period, the licensees must meet a specified work obligation set out in the licence. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfil the obligations set out in the production licence, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years. As a rule, the right to prolong a licence does not apply to the whole of the geographical area covered by the initial licence, but only to a percentage of the area, typically 50%. The size of the area that must be relinquished is determined at the time the licence is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production licence.
If natural resources other than petroleum are discovered in the area covered by a production licence, the Norwegian State may decide to delay petroleum production in the area. If such a delay is imposed, the licensees are, with certain exceptions, entitled to a corresponding extension of the licence period. To date, such a delay has never been imposed.
If important public interests are at stake, the Norwegian State may direct us and other licensees on the NCS to reduce the production of petroleum. The last time the Norwegian State directed a reduction in oil production was in 2002.
Licensees may buy or sell interests in production licences subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of interests in a licence, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. In most licences there are no pre-emption rights in favour of the other licensees. However, the SDFI, or the Norwegian State, as appropriate, still holds pre-emption rights in all licences. Not all of our licencing transactions entered into in 2010 on the NCS were approved by the Ministry of Petroleum and Energy and the Ministry of Finance. However, all approvals are expected during the first half of 2011.
A licence from the Ministry of Petroleum and Energy is also required in order to establish facilities for the transportation and utilisation of petroleum. When applying for such licences, the owners, who in practice are licensees under a production licence, must prepare a plan for installation and operation. Licences for the establishment of facilities for transportation and utilisation of petroleum will normally be awarded subject to certain conditions. Typically, these conditions require the facility owners to enter into a participants' agreement. The ownership of most facilities for transportation and utilisation of petroleum in Norway and on the NCS is organised as joint ventures of a group of licence holders. The participants' agreements are similar to the joint operating agreements entered into by the members of joint ventures holding production licences. The PDO for Valemon was submitted to the Norwegian authorities at the end of October 2010, and the approval from the Ministry of Petroleum and Energy and the Ministry of Finance is expected during the first half of 2011. The remaining licencing transactions we entered into in 2010 on the NCS were approved by the Ministry of Petroleum and Energy and the Ministry of Finance by year end 2010.
Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for the transportation and utilisation of petroleum expires or is relinquished or the use of a facility ceases. The decommissioning plan must be submitted to the Ministry of Petroleum and Energy no sooner than five and no later than two years prior to the expiry of the licence or cessation of the use of the facility, and it must include a proposal for the disposal of facilities on the field. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.
The Norwegian State is entitled to take over the fixed facilities of the licensees when a production licence expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with the expropriation of private property apply. None of our production licences on the NCS expired in 2010 and none is due to expire in 2011 and 2012.
Licences for the establishment of facilities for transportation and utilisation of petroleum typically include a clause whereby the Norwegian State can require that the facilities be transferred to it free of charge on expiry of the licence period.
We market gas from the NCS on our own and the Norwegian State's behalf. Gas is transported through the Gassled pipeline network to customers in Europe.
Gas sales contracts with buyers for the supply of Norwegian gas are concluded individually with each company.
The upstream gas transportation system consists of several pipelines owned by a joint venture called Gassled. At year end 2010, our direct ownership interest in Gassled was 32.1%. From 1 January 2011, our direct ownership interest in Gassled is 28.5%. Statoil is responsible for technical operation of the majority of the gas export pipelines and onshore plants in the Gassled processing and transportation system.
By Royal Decree of 20 December 2002, the Norwegian authorities issued regulations relating to access to and tariffs for capacity in the upstream gas transportation system. The regulations are based on three main considerations. Firstly, the regulations implement the Gas Directive of the European Union. Secondly, they establish a system for access to the upstream gas transportation system that is compatible with company-based gas sales from the NCS. Thirdly, they provide for new ownership structure in upstream gas transportation system (Gassled).
Parts of the regulations have general application and parts - including the tariffs - are only applicable to the upstream gas transportation system owned by the Gassled joint venture. The regulations establish the main principles for access to the upstream gas transportation system. The access regime consists of a regulated primary market where, pursuant to the regulations, the right to book spare capacity is allocated to users with a need to transport natural gas. Furthermore, the access regime consists of a secondary market where capacity can be transferred between users after allocation in the primary market if transportation needs change.
Capacity in the primary market is released and booked through Gassco AS on the internet. Spare capacity is released for pre-defined time periods at announced points in time and with specific time limits for reservations. If reservations exceed the spare capacity, the spare capacity will be allocated on the basis of an allocation formula. However, in the event of scarce capacity, consideration must first be given to the owners' duly substantiated needs for capacity, limited to twice the owner's equity interest in the upstream pipeline network.
Based on authorisation granted under the regulations, tariffs for the use of capacity in Gassled are decided by the Ministry of Petroleum and Energy. The ministry's policy for determining the tariffs is to avoid excessive returns on the capital invested in the transportation system, allowing the return on Norwegian petroleum activity to be taken out on the fields instead of in the transportation systems. The tariffs are paid for booked capacity and not on the basis of the volume actually transported.
For further information, see section Operational review-Natural Gas-Norway's gas transport system.
The EU Gas Directives, which have been included in the EEA Agreement and incorporated into Norwegian legislation, regulates the European gas market in conjunction with the Gas Transmission Access Regulation of 2005.
Most of our gas is sold under long-term gas contracts to customers in the EU. This gas market continues to be affected by changes in EU regulations and the implementation of such regulations in EU member states. Such regulation affects our ability to expand or even maintain our current market position, as quantities sold under our gas sales contracts may be influenced by the changed market conditions resulting from the EU Gas Directives.
The Directives requires that, with effect from July 2007, all consumers in Europe should be able to choose their energy supplier. Fundamental changes to this directive were adopted by the European Union in July 2009 to be implemented by the EU member states at the latest in March 2011 (as set out in EC Directive 2009/73), with specific focus on the separation of ownership of transmission assets from supply activities. The objective of these changes is to increase competition in national markets and integrate them into regional and, eventually, a single EU-wide market for natural gas. It is difficult to predict the effect liberalisation measures will have on the development of gas prices, but the main objective of the single gas market is to create greater choice and reduce prices for customers through increased competition.
Our petroleum operations are subject to extensive regulation with regard to health, safety and the environment, or HSE.
The Petroleum Safety Authority Norway (PSA) has regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. The PSA's area of responsibility includes supervision of safety, emergency preparedness and the working environment for both offshore and onshore petroleum facilities. Following the accident in the Gulf of Mexico, the PSA now requires companies to demonstrate their ability to handle a potential blow-out and to inform the PSA about how they plan to shut down a well in the event of a blow-out before receiving permission to start drilling a new well.
We are required at all times to have a plan to deal with emergency situations in our petroleum operations. During an emergency, the Ministry of Labour, the Ministry of Fisheries and Coastal Affairs/the Norwegian Coastal Administration may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, to deal with the emergency for the licensees' account.
In our capacity as holder of licences under the Petroleum Act, we are subject to strict statutory liability in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licences. This means that anyone who suffers damage or loss as a result of pollution caused by any of our NCS licence areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part. If the pollution is caused by a force majeure event, a Norwegian court may reduce the damages to a level it considers reasonable.
We anticipate that the health, safety and environmental laws and regulations to which we are subject, both in Norway and around the world, are likely to have an increasing impact on our operations. It is difficult, however, to predict accurately the effects of future developments in such laws and regulations on our future earnings and operations. Some risk of health, safety and environmental costs and liabilities is inherent in certain of our operations and products, as it is with other companies engaged in similar businesses. We cannot assure you that material costs and liablities will not be incurred; however, we do not currently expect any material adverse effect on our financial position or results of operations as a result of compliance with such laws and regulations.
We are subject to ordinary Norwegian corporate income tax and to a special petroleum tax relating to our offshore activities. We are also subject to a special carbon dioxide emissions tax and a nitrogen oxide tax.
Under our production licences, we are obliged to pay an area fee to the Norwegian State. Below is a summary of certain key aspects of the Norwegian tax rules that apply to our operations.
Corporate income tax
The maximum rate of depreciation of development costs related to offshore production installations and pipelines is 16.67% per year. Depreciation starts when the cost is incurred. Exploration costs may be deducted in the year in which they are incurred. Financial costs related to the offshore activity are calculated directly based on a formula set out in the Petroleum Tax Act. The financial costs deductible against the offshore tax regime are the total financial costs multiplied by 50% of tax values divided by the average interest-bearing debt. All other financial costs and income are allocated to the onshore tax regime.
Any tax losses can be carried forward indefinitely against subsequent income earned. Fifty per cent of losses relating to activity conducted onshore in Norway can be deducted from NCS income subject to the 28% tax rate. Losses on foreign activities may not be deducted against NCS income. Losses on offshore activities are fully deductible from onshore income.
By using group contributions between Norwegian companies in which we hold more than 90% of the shares and votes, tax losses and taxable income can be offset to a great extent. Group distributions are not deductible from our offshore income.
Dividends received are subject to tax in Norway. The basis for taxation is 3% of the dividend received, which is subject to the standard 28% income tax rate. Dividends from low-tax countries or portfolio investments outside the EEA will, under certain circumstances, be subject to the standard 28% income tax rate based on the full amounts received.
Capital gains from the realisation of shares are taxable. The basis for taxation is 3% of the gain, which is subject to the standard 28% income tax. Capital losses from the realisation of shares are not deductible. Exceptions apply to shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA, where, under certain circumstances, capital gains will be subject to the standard 28% income tax rate and capital losses will be deductible.
Special petroleum tax
Carbon dioxide emissions tax
Nitrogen oxide emissions tax
As an alternative to paying the nitrogen oxide tax, companies can voluntarily agree to contribute to an industry nitrogen oxide fund for the years 2008-2010. The contribution to the fund is NOK 11 per kilogram of nitrogen oxide emissions. We have entered into an agreement to contribute to the fund.
Taxation outside Norway
Generally, income from Statoil's upstream production outside Norway is subject to tax at the higher of the Norwegian onshore rate (28%) or the prevailing tax rate in the countries in which it operates. Statoil is subject to excess (or "windfall") profit tax in some of the countries where it produces crude oil.
Production sharing agreements
Income tax regimes
The Norwegian State's policy as a shareholder in Statoil has been and continues to be to ensure that petroleum activities create the highest possible value for the Norwegian State.
Initially, the Norwegian State's participation in petroleum operations was largely organised through Statoil. In 1985, the Norwegian State established the State's Direct Financial Interest, or SDFI, through which the Norwegian State has direct participating interests in licences and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licences and petroleum facilities in which we also hold interests. Petoro AS, a wholly-owned company by the Norwegian State, was formed in 2001 to manage the SDFI assets.
Historically, we marketed and sold the Norwegian State's oil and gas as part of our own production. The Norwegian State has chosen to continue this arrangement.
Accordingly, at an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article that requires us to continue to market and sell the Norwegian State's oil and gas together with our own oil and gas in accordance with an instruction established in shareholder resolutions in effect from time to time. At an extraordinary general meeting held on 25 May 2001, the Norwegian State, as sole shareholder, approved a resolution containing the instruction referred to in the new article. This resolution is referred to as the owner's instruction.
The Norwegian State has a coordinated ownership strategy aimed at maximising the aggregate value of its ownership interests in Statoil and the Norwegian State's oil and gas. This is reflected in the owner's instruction. It contains a general requirement that, in our activities on the NCS, we must take account of these ownership interests in decisions that could affect the execution of this marketing arrangement.
The owner's instruction sets forth specific terms for the marketing and sale of the Norwegian State's oil and gas. The principal provisions of the owner's instruction are set out below.
To ensure neutral weighting between the Norwegian State's and our own natural gas volumes, a list has been established for deciding the priority between each individual field. A mathematical optimisation model is used to decide the ranking. It describes existing and planned production facilities, infrastructure and processing terminals in which the Norwegian State and Statoil have ownership interests. The list yields a result giving the highest total net present value for the Norwegian State's and our oil and gas. In the evaluation, the following objective criteria apply:
The different fields are ranked in accordance with their assumed total value creation for the Norwegian State and Statoil, assuming that all of the fields meet our profitability requirements if we participate as a licensee, and the Norwegian State's profitability requirements if the State is a licensee. The list is updated annually, or more frequently if events occur that may significantly influence the ranking. Within each individual field in which both the Norwegian State and Statoil are licensees, the Norwegian State and Statoil will deliver volumes and share income in proportion to our respective participating interests.
The Norwegian State's oil and NGL is lifted together with our oil and NGL in accordance with applicable lifting procedures for each individual field and terminal.
Withdrawal or amendment
There is intense competition in the oil and gas industry for customers, production licences, operatorships, capital and experienced human resources.
In recent years, the oil and gas industry has experienced consolidation, as well as increased deregulation and integration in strategic markets.
Statoil competes with large integrated oil and gas companies, as well as with independent and government-owned companies for the acquisition of assets and licences for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas prices and demand, exploration and production costs, global production levels, alternative fuels and government (including environmental) regulations.
Statoil's ability to remain competitive will depend, among other things, on the management continuing to focus on reducing unit costs and improving efficiency, maintaining long-term growth in our reserves and production through continuing technological innovation. It will also depend on our ability to seize international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. We believe that we are in a position to compete effectively in each of our business segments.
We have interests in real property in many countries throughout the world, but no one individual property is significant to us as a whole.
Our head office, which is located at Forusbeen 50, NO-4035, Stavanger, Norway, comprises approximately 135,000 square metres of office space and is owned by Statoil.
A contract has been signed with IT Fornebu Holding AS in Oslo for the long-term lease of a new 60,000-square-metre office building to be built at Fornebu in Bærum municipality. The building, which will enable all of Statoil's activities in the Oslo region to be collocated, will be ready for occupation in autumn 2012. IT Fornebu Holding AS will be the owners and Statoil will be the tenant.
For a description of our significant reserves and sources of oil and natural gas, see note 35 - Supplementary oil and gas information in the Consolidated Financial Statements in this report.
We have the following transactions with related parties.
Transactions with the Norwegian State
Transactions with other entities in which the Norwegian State is a major shareholder
Other transactions with the Norwegian State
The significant amounts included in the line item Payables to equity accounted investments and other related parties in note 26 Trade and other payables to the Consolidated financial statement, are amount payables to the Norwegian State for these purchases. The prices paid by Statoil for the oil purchased from the Norwegian State are estimated at market prices. In addition, Statoil sells the Norwegian State's natural gas in its own name, but for the account and risk of the Norwegian State.
The Norwegian State compensates Statoil for its relative share of the costs related to certain Statoil natural gas storage and terminal investments and related activities. See report section Operational review-Regulation-Marketing and sale of the SDFI oil and gas for more details.
Although the Norwegian State is Statoil's majority owner, Statoil does not receive any preferential treatment with respect to licences granted by the Norwegian State or under any other regulatory rules enforced by the Norwegian State.
Members of the corporate executive committee and the board of directors may not take up loans under the current programme. None of the three employee-elected members of the board of directors and none of members of the corporate executive committee had any balances outstanding under this facility as of 12 March 2011.
Employees at certain employment levels are entitled to an interest-free car loan from the company. Members of the corporate executive committee and employee-elected members of the board are generally excluded from this arrangement, and none of them had any balances outstanding as of 12 March 2011.
Family members of certain corporate executive committee members or directors, who are also employees of Statoil, have participated in the employee loan and/or car loan programs prior to the appointment of such persons to the corporate executive committee or the board and may have balances outstanding.
Statoil's corporate assembly includes six employee representatives and three employee observers who, as part of their remuneration, may have balances outstanding under the Company's employee loan and/or car loan programs.
Other related party transactions
Statoil buys insurance policies for, amongst other things, physical loss of or damage to our oil and gas properties, liability to third parties, workers' compensation and employers liability, general liability, pollution and well control.
Our insurances are subject to:
i) Deductibles, excesses and Self Insured Retentions (SIR) that must be borne prior to recovery ii) Exclusions and limitations
Our Well Control policy, which covers costs relating to well control incidents (including pollution and clean-up costs), is subject to a gross limit per incident. The gross limits for our two most significant geographical areas, the NCS and the GoM are:
Norwegian Continent Shelf (NCS)
Gulf of Mexico (GOM)
The limits assumes 100% ownership interest in a given well and would be scaled to be equivalent to or percentage ownership interest in a given well.
Our SIR would vary between approximately NOK 16 and NOK 581 million per loss on the NCS depending on our ownership percentage interest in the well and certain other factors.
Our SIR in the GoM would be approximately NOK 150 million per incident assuming 100% ownership.
In excess of the well control insurance programs we have in place a third party liability insurance program with a gross limit of NOK 4,800 million per incident. The SIR is insignificant (maximum NOK 6 million).
We have a variety of other insurance policies related to other projects on a worldwide basis for which we have limited SIR.
There is no guarantee that our insurances will adequately protect us against liability for all potential consequences and damages.
Statoil delivered strong financial results and cash flows in 2010. Production volumes were below our expectations in the second part of the year, mainly due to maintenance, operational issues and production permit restrictions.
Total equity liquids and gas production were 1,888 mboe per day in 2010, which is somewhat below the previously guided range of 1,925 - 1,975 mboe per day. However, the company has had a strong cash flow and has a sound financial position.
Net operating income was up by 13% compared with 2009, largely because of higher prices for oil. This was partly offset by lower gas prices and reduced volumes sold. Net operating income amounted to NOK 137.2 billion in 2010.
Around 90% of the expected Hydro merger synergies have been achieved, and monitoring of the merger value capture is now closed.
In 2010, Statoil agreed to partially sell interests in our operated assets in Brazil and Canada. Final investment decisions were made for nine new projects (operated by Statoil), and we carried out an initial public offering (IPO) of our energy and retail business.
We acquired high potential exploration acreage in 2010 and the reserve replacement ratio grew to 87%, up from 73% in 2009. We believe we have the resource base required to improve this ratio going forward, and the high quality portfolio of yet-to-be-sanctioned projects is expected to add value to our business in the future.
The board of directors is proposing a dividend of NOK 6.25 per share for 2010.
Statoil delivered strong financial results and strong cash flows, despite reduced production. Exploration expenses and depreciation and impairment costs were down, largely as a result of reduced volumes and exploration activity.
In 2010, Statoil delivered total liquids and gas entitlement production of 1,705 mboe per day, down 6% from 1,806 mboe per day in 2009. Total equity production decreased by 4% from 2009, to 1,888 mboe per day in 2010. Higher maintenance activity, production permit restrictions, various operational issues and expected natural decline on mature fields caused the decrease. Limitations in the gas transportation systems from the Norwegian continental shelf (NCS) because of maintenance work also added to the decrease.
Despite reduced production and lower prices for gas, net operating income was up 13% at NOK 137.2 billion in 2010, compared with NOK 121.6 billion in 2009. The increase was mainly attributable to higher oil prices, decreased depreciation, amortisation and net impairment losses and decreased exploration expenses. It was partly offset by lower gas prices, reduced volumes of oil sold, losses on derivatives and a provision for an onerous contract relating to the US Cove Point Terminal.
Having realised approximately 90% of the expected synergies from the Hydro merger, Statoil has reduced overall expenses, reduced expenditures relating to logistics and procurement, improved operational efficiency, and increased value creation through commodities trading.
Statoil's exploration programme for 2010 totalled 35 exploration wells completed before 31 December 2010. Eighteen of them were drilled outside the Norwegian continental shelf (NCS). Eighteen wells were also announced as discoveries during the period. Six of them are located outside the NCS. In 2010, 526 mmboe of proved reserves were added through revisions, extensions and discoveries, compared with additions of 481 mmboe in 2009, also through revisions, extensions and discoveries.
In all, Statoil achieved a reserve replacement ratio of 87% in 2010. New resources were added to overall resources through exploration and business development, preparing the ground for growing proved reserves in the future.
Statoil progressed six new projects into production in 2010. The Gjøa, Vega, Vega South and Morvin fields on the NCS, the Eagle Ford field in the USA and the Leismer Demonstration project in Canada all came on stream in 2010.
Final investment decisions were made for nine new projects (operated by Statoil) in 2010, one of which is outside Norway.
In 2010, the group gained access to 12 new exploration licences in US Alaska, US GoM, Greenland, Newfoundland Canada and in the UK. On the NCS, we were awarded access to eight new licences, as operator for six and as partner in two. We were also awarded two licence extensions, both as operator. new exploration licences EPN
Sales volumes include our lifted entitlement volumes, the sale of SDFI volumes and our marketing of third-party volumes.
We take part in the production of oil and natural gas volumes, and incur capital expenditures and operating expenses on the basis of such equity volumes. Under certain production-sharing agreements (PSAs), a portion of the equity production is distributed to the relevant government before arriving at the volumes that we are ultimately entitled to sell (entitlement volumes). The timing of our lifting of our share of entitlement volumes may cause a difference at any given time between our share of entitlement volumes and the volumes lifted. This difference is called overlift if we have lifted more than our share of the entitlement production, and underlift if our cumulative lifting is less than our share of the entitlement volumes. The lifted volumes and volumes in inventory are the basis for what we can sell to third parties.
In addition to our own volumes of lifted entitlement production and production in storage, we market and sell oil and gas owned by the Norwegian state through the Norwegian state's share in production licences. This is known as the State's Direct Financial Interest, or SDFI. For additional information, see the section Operational review - Regulation - Marketing and sale of SDFI oil and gas. The following table shows SDFI and Statoil sales volume information for crude oil and natural gas, as applicable, for the periods indicated. The Statoil natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International Exploration & Production and ethane volumes.
For more information on the differences between equity and entitlement production, sales volumes and lifted volumes, see the section Financial analysis and review - Operating and financial review 2010 - Definitions of reported volumes.
Revenues and other income amounted to NOK 529.6 billion in 2010, which is NOK 64.1 billion higher than in 2009 and NOK 126.4 billion lower than in 2008. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by Statoil.
Revenues and other income amounted to NOK 529.6 billion in 2010, compared with NOK 465.4 billion in 2009 and NOK 656.0 billion in 2008. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by Statoil. In addition, we also market and sell the Norwegian State's share of liquids from the Norwegian continental shelf (NCS). All purchases and sales of the Norwegian State's production of liquids are recorded as purchases net of inventory variations and sales, respectively.
The NOK 64.1 billion increase in revenues from 2009 to 2010 was mainly attributable to higher prices for liquids and increased volumes of gas sold, partly offset by lower gas prices, reduced volumes of liquids sold and losses on derivatives.
Realised prices of liquids measured in NOK increased by 27% from 2009 to 2010, contributing NOK 34.6 billion to the increase in revenues, while increased volumes of gas sold contributed NOK 5.9 billion to the increase in revenues. The increase was partly offset by a 7% decrease in liftings of liquids with a total off-setting effect of NOK 10.1 billion, while gas prices were down by 10% in 2010, affecting revenues negatively by NOK 9.5 billion.
The NOK 190.6 billion decrease in revenues from 2008 to 2009 was mainly attributable to lower prices for both liquids and gas. Realised prices of liquids measured in NOK decreased by 29% from 2008 to 2009, contributing NOK 56.5 billion to the reduction in revenues. Gas prices were down 21% in 2009 compared with 2008 and contributed NOK 25.0 billion to the reduction in revenues. The decrease in revenues related to volumes purchased from the Norwegian State contributed NOK 124.3 billion.
Over time, the volumes lifted and sold will equal our production of entitlement volumes, but they may be higher or lower in any period due to differences between the capacity of the vessels lifting our volumes and the actual entitlement production in the period. Total liquids liftings were 969 mmboe per day in 2010, a decrease of 7% compared with the previous year. Total liquids liftings were 1.045 mmboe per day in 2009, an increase of 3% compared with 2008, when liftings were 1.019 mmboe per day.
The average daily overlift was 1 mboe per day in 2010. In 2009, there was an average underlift of 21 mboe per day, while there was an average underlift of 37 mboe per day in 2008.
Entitlement volumes lifted form the basis for revenue recognition, while equity production volumes affect operating costs more directly. See the report section Financial analysis and review - Operating and financial review 2010 - Sales volumes for more details on the production-sharing agreement (PSA) effects that cause differences between equity and entitlement volumes. See below for more details on the difference between lifted and produced volumes.
Net income from equity accounted investments was NOK 1.1 billion in 2010, NOK 1.8 billion in 2009 and NOK 1.3 billion in 2008.
Other income was NOK 1.8 billion in 2010, compared with NOK 1.4 billion in 2009 and NOK 2.8 billion in 2008. Other income in 2010 and 2009 was mainly related to a gain on the sale of assets and insurance proceeds relating to business interruptions. Other income in 2008 was mainly related to gain on the sale of assets.
Purchase, net of inventory variation includes the cost of the oil and NGL production purchased from the Norwegian State pursuant to the Owners Instruction. See section Operational review - Regulation - Marketing and sale of SDFI oil and gas for more details. The purchase, net of inventory variation amounted to NOK 257.4 billion in 2010, compared with NOK 205.9 billion in 2009 and NOK 329.2 billion in 2008.
The 37% decrease from 2008 to 2009 mainly stems from lower prices of liquids measured in NOK, while the 25% increase from 2009 to 2010 was mainly caused by higher prices of liquids measured in NOK.
Operating expenses include field production costs, including payroll expenses and employee benefits, and costs incurred for transport systems related to the company's share of oil and natural gas production. In 2010, operating expenses amounted to NOK 57.5 billion, an increase of NOK 0.6 billion since 2009 when operating expenses were NOK 56.9 billion. The increase was mainly attributable to higher operating costs related to preparation for start up on new fields, partly offset by lower transportation costs because of reduced production, and cost saving activities.
Operating expenses were NOK 56.9 billion in 2009, down 4% on 2008, when operating expenses were NOK 59.3 billion. The reduction was mainly attributable to reduced transportation costs and the reversal of a provision relating to a take or pay contract in previous periods.
Total entitlement liquids and gas production decreased from 1.806 mmboe per day in 2009 to 1.705 mmboe per day in 2010. In 2008, total liquids and gas production was 1.751 mmboe per day.
Total equity liquids and gas production decreased from 1.962 mmboe per day in 2009 to 1.888 mmboe per day in 2010. In 2008, equity production of liquids and gas was 1.925 mmboe per day.
The 4% decrease in total equity production in 2010 compared to 2009, was primarily caused by relatively higher maintenance activity in 2010 leading to production shutdowns, limitations in the gas transportation system from the NCS because of planned maintenance, production permit restrictions on the Ormen Lange field, various operational issues and an expected natural production decline on several mature fields. The decrease in equity production was partly compensated by production from the start-up of new fields and ramp-up on existing fields. Entitlement production decreased by 6%. It was impacted by the same factors as equity production and also by changes in profit tranches for some of our fields in Angola and higher prices leading to reduced entitlement shares on other fields.
The 2% increase in equity production from 2008 to 2009 was primarily due to increased production from the start-up of new fields, ramp-up on existing fields, partly offset by declining production from mature fields, various operational issues and maintenance activities. Entitlement production increased by 3% for the same reasons and also due to a less adverse effect of production sharing agreements (PSA-effects).
The production cost of entitlement volumes per boe was NOK 42.8 for the 12 months ending 31 December 2010, compared with NOK 38.4 for the 12 months ending 31 December 2009. In 2008, the production cost per boe was NOK 38.1. Equity volumes represent produced volumes under PSA contracts that correspond to Statoil's ownership percentage in a specific field, while entitlement volumes represent Statoil's share of the volumes distributed to the partners in the field, which are subject to deductions. Production costs are incurred on the basis of our equity production. The management therefore believes that unit of production cost based on equity production is a better measure of cost control than unit of production cost based on entitlement volumes.
Based on equity volumes, the production cost per boe for the 12 months ending 31 December 2010 and 2009 was NOK 38.6 and NOK 35.3, respectively. In 2008, the production cost per boe was NOK 34.6. Adjusted for restructuring costs, reversal of restructuring costs and other costs arising from the merger recorded in the fourth quarter 2007 and gas injection costs, the production cost per boe of equity production for the 12 months ending 31 December 2010 and 2009, was NOK 37.9 and NOK 35.3, respectively. The corresponding figure for 2008 was NOK 33.3.
Adjustments are made for certain costs relating to the purchase of gas used for injection into oil-producing reservoirs. The adjustment facilitates comparison of field production costs with other fields that do not pay for their own gas used for injection into oil-producing reservoirs.
Selling, general and administrative expenses include expenses relating to the sale and marketing of our products, such as business development costs, payroll expenses and employee benefits. These amount to NOK 11.1 billion in 2010, compared with NOK 10.3 billion in 2009 and NOK 11.0 billion in 2008. The NOK 0.8 billion increase from 2009 to 2010 mainly stems from a provision for an onerous contract in 2010. The increase was only partly offset by cost reductions from cost saving activities. The 6% decrease from 2008 to 2009 was due to numerous different factors, cost savings being one of them.
Depreciation, amortisation and net impairment losses include depreciation of production installations and transport systems, depletion of fields in production, amortisation of intangible assets and depreciation of capitalised exploration expenditure. It also includes impairment of long-lived assets and reversals of impairments. These expenses amounted to NOK 50.6 billion in 2010, compared with NOK 54.1 billion in 2009 and NOK 43.0 billion in 2008. The 6% decrease in depreciation, amortisation and net impairment losses in 2010 compared with 2009 was mainly due to lower impairment losses in 2010 and lower entitlement volumes. The 26% increase in depreciation, amortisation and impairment expenses in 2009 compared with 2008 was due to increased production on the NCS and impairment charges net of reversals of NOK 7.1 billion, mostly relating to assets in the Gulf of Mexico and refinery assets in Norway.
Exploration expenditures are capitalised to the extent that exploration efforts are considered successful, or pending such assessment. Otherwise, such expenditures are expensed.
The exploration expense consists of the expensed portion of our exploration expenditure in 2010 and impairment of exploration expenditure capitalised in previous years. In 2010, the exploration expenses were NOK 15.8 billion, a 5% decrease since 2009, when exploration expenses were NOK 16.7 billion. Exploration expenses were NOK 14.7 billion in 2008.
The 5% decrease in exploration expenses from 2009 to 2010 was mainly due to lower drilling activity and a smaller proportion of exploration expenditure capitalised in previous years being impaired. The decrease was partly offset by higher oil sands delineation drilling expenses, higher seismic expenditures and higher pre-sanctioning costs. The 14% increase in exploration expenses from 2008 to 2009 was mainly due a higher proportion of exploration expenditure capitalised in previous years being impaired.
In 2010, a total of 35 exploration and appraisal wells were completed, 17 on the NCS and 18 internationally. A total of 19 wells were announced as discoveries in the period, 12 on the NCS and seven internationally. In addition, four exploration extension wells were completed on the NCS in 2010, three of which were announced as discoveries.
In 2009, a total of 68 exploration and appraisal wells and two exploration extension wells were completed, 41 on the NCS and 29 internationally. Thirty-eight exploration and appraisal wells and two exploration extension wells have been declared as discoveries.
In 2008, a total of 79 exploration and appraisal wells and nine exploration extension wells were completed, 48 on the NCS and 40 internationally. Thirty-five exploration and appraisal wells and six exploration extension wells have been declared as discoveries.
Net operating income was NOK 137.2 billion in 2010, compared with NOK 121.6 billion in 2009 and NOK 198.8 billion in 2008. The 13% increase from 2009 to 2010 was primarily attributable to higher prices for liquids, partly offset by lower gas prices, reduced volumes of liquids sold, and losses on derivatives. The 39% decrease from 2008 to 2009 was primarily attributable to lower prices of liquids and gas, and increased depreciation, amortisation and impairment losses, partly offset by income from higher volumes sold.
In 2010, net operating income was negatively affected by impairment losses net of reversals (NOK 4.8 billion), lower fair value of derivatives (NOK 2.9 billion) and a provision for an onerous contract relating to the Cove Point terminal in the USA (NOK 0.8 billion), while overlift (NOK 1.4 billion) and gain on the sale of assets (NOK 1.3 billion) had a positive impact on net operating income.
In 2008, net operating income was negatively affected by impairment charges net of reversals (NOK 4.8 billion), underlift (NOK 2.4 billion) and other accruals (NOK 2.3 billion), while increased fair value of derivatives (NOK 1.8 billion), higher fair value of derivatives (NOK 0.8 billion), gains on the sale of assets (NOK 1.4 billion) and reversal of restructuring cost accrual (NOK 1.6 billion) had a positive effect on net operating income in 2008.
Net financial items amounted to a loss of NOK 0.4 billion in 2010, compared with a loss of NOK 6.7 billion in 2009 and a loss of NOK 18.4 billion in 2008. The positive change of NOK 6.3 billion from 2009 to 2010 was mostly attributable to fair value changes on interest rate swap positions, due to decreasing US dollar interest rates in 2010, compared with increasing US dollar interest rates in combination with a 17% weakening of the US dollar in relation to NOK in 2009.
Net foreign exchange losses in 2010 of NOK 1.8 billion and net foreign exchange gains in 2009 of NOK 2.0 billion are mainly related to currency derivatives used for currency and liquidity risk management. They are partly offset by currency effects on the working capital.
Interest income and other financial items amounted to NOK 3.2 billion for the year ending 31 December 2010, compared with NOK 3.7 billion for the year ending 31 December 2009. The NOK 0.5 billion decrease was mainly related to a NOK 0.4 billion decrease in interest income on current financial assets in combination with a NOK 0.2 billion decrease in interest income on net securities.
Interest expenses and other financial expenses amounted to a net expense of NOK 1.8 billion for the year ending 31 December 2010, compared with a net expense of NOK 12.5 billion for the year ending 2009. The decrease of NOK 10.7 billion was mostly due to fair value changes on interest rate swap positions relating to the interest rate management of external loans. For the year ending 31 December 2010, fair value gains amounted to NOK 2.4 billion. Correspondingly, fair value losses for the year ending 31 December 2009 amounted to NOK 6.8 billion.
In 2009, net financial items amounted to a loss of NOK 6.7 billion in 2009, compared with a loss of NOK 18.4 billion in 2008.
The positive change of NOK 11.7 billion from 2008 to 2009 was mostly attributable to NOK 2.0 billion net currency gains caused by a 17% weakening of the US dollar in relation to NOK for the year ending 31 December 2009, compared with net currency losses of NOK 32.6 billion caused by a 29% strengthening of the US dollar in relation to NOK for the year ending 31 December 2008.
Net foreign exchange gains in 2009 and net foreign exchange losses in 2008 were mainly related to currency derivatives used for currency and liquidity risk management. Effective 1 January 2009, the functional currency changed to USD for the parent company. As a result USD-denominated non-current financial liabilities that affected net foreign exchange gains (losses) in 2008, did not affect the income statement in 2009. The positive impact of net currency exchange gains was partly offset by a NOK 8.5 billion decrease in interest income and other financial items, and a NOK 14.5 billion increase in interest and other financial expenses.
Interest income and other financial items amounted to NOK 3.7 billion for the year ending 31 December in 2009, compared with NOK 12.2 billion for the year ending 31 December 2008. The NOK 8.5 billion decrease was mainly related to NOK 3.9 billion in lower income from securities and NOK 5.5 billion in decreased interest income on current financial assets.
Interest expenses and other financial expenses amounted to net expenses of NOK 12.5 billion for the year ending 31 December 2009, compared with a net gain of NOK 2.0 billion for the year ending 31 December 2008. The decrease of NOK 14.5 billion mostly relates to fair value losses on interest rate derivatives used to manage the interest rate risk of the loan portfolio, as a result of increasing US dollar interest rates in 2009. Correspondingly, decreasing US dollar interest rates in 2008 resulted in fair value gains on these swap positions.
Income taxes were NOK 99.2 billion in 2010, equivalent to an effective tax rate of 72.5%, compared with NOK 97.2 billion in 2009, equivalent to an effective tax rate of 84.6%, and NOK 137.2 billion in 2008, equivalent to an effective tax rate of 76.0%.
The decrease in the effective tax rate from 2009 to 2010 was mainly due to high taxes in 2009 caused by higher taxable income than accounting income in companies that are taxable in other currencies than the functional currency. The decrease in the effective tax rate was also caused by relatively lower income from the NCS in 2010 compared with 2009. This income is subject to a higher than average tax rate.
The increase in the tax rate from 2008 to 2009 was mainly due to significant taxable exchange gains, which do not have an impact on the accounting income in the financial statements of companies whose functional currency is USD. In 2009, the taxable income relating to these exchange gains was estimated to be NOK 25.0 billion higher than income before tax, which increased the effective tax rate. In addition, the effective tax rate was increased by relatively higher income from the NCS where higher than average tax rates apply, and impairment losses with lower than average tax rates.
The effective tax rate is calculated as income taxes divided by income before taxes. Fluctuations in the effective tax rates from year to year are principally the result of non-taxable items (permanent differences), and changes in the components of income between Norwegian oil and gas production, taxed at a marginal rate of 78%. Other Norwegian income, including the onshore portion of net financial items is taxed at 28%, and income in other countries is taxed at the applicable income tax rates in those countries.
In 2010, the non-controlling interest (minority interest) in net profit was NOK 0.4 billion, compared with NOK 0.6 billion in 2009 and NOK 0.005 billion in 2008. The non-controlling interest in 2010 is primarily related to Statoil's 54% ownership of Statoil Fuel & Retail, starting in October 2010, and 79% ownership of Mongstad crude oil refinery.
Net income was NOK 37.6 billion in 2010, compared with NOK 17.7 billion in 2009 and NOK 43.3 billion in 2008. The 112% increase from 2009 to 2010 was mainly due to increased net operating income as a result of higher revenues from liquids and a lower net financial loss, only partly offset by higher income taxes.
The 59% decrease from 2008 to 2009 was mainly due to reduced operating income caused by lower revenues from liquids and gas sales and a higher effective tax rate, only partly offset by reduced loss on net financial items.
The board of directors will propose for approval at the annual general meeting an ordinary dividend of NOK 6.25 per share for 2010, an aggregate total of NOK 19.9 billion. In 2009, the ordinary dividend was NOK 6.00 per share, an aggregate total of NOK 19.1 billion. The ordinary dividend for 2008 was NOK 4.40 per share, and a special dividend of NOK 2.85 per share was distributed, making an aggregate total of NOK 23.1 billion.
Planned turnarounds are expected to have a negative impact on the equity production of liquids of around 40 mboe per day for the full year 2011. The main impact is expected to be in the third quarter of 2011.
Organic capital expenditures for 2011 i.e. excluding acquisitions and capital leases, are estimated at around USD 16 billion.
The company will continue to mature its large portfolio of exploration assets. In 2011, we expect to drill around 20 exploration wells on the NCS and around 20 exploration and appraisal wells internationally. We expect total exploration expenditure in 2011 of around USD 3 billion.
We expect prices for crude oil, products and natural gas to continue to be volatile in the short to medium term. Refining margins have increased compared to 2009; however, they are still low from an historical perspective. We anticipate that the refining margins will remain low, at least in the near term. The refining industry is expected to still face major challenges in 2011. Even though global oil demand has recovered from 2009 levels, refinery overcapacity persists.
We believe that global oil demand will continue to increase in 2011. In line with the economic recovery, global oil demand is expected to normalize in the next few years. The shift of higher oil consumption in emerging markets, and lower oil consumption in mature regions, is expected to continue. Emerging markets, led by China, are expected to increase usage of oil for industrial production, construction and transportation. Western Europe and the US are expected to see a fall in oil demand primarily due to efficiency gains in the transportation sector and less intake from stationary facilities. Diesel demand in Europe will be robust, but a surplus of European gasoline supply will need to be sold to the traditional export market in US, but also to markets as West Africa.
Supply of natural gas liquids (NGL) is expected to increase significantly, especially as supply associated with new US shale gas production reaches the market. European NGL production is likely to remain high as volumes associated with oil fields are replaced by NGL from non-associated production. The increase in LPG availability is expected to find solid demand from the premium residential/heating segment, and as feedstock into the price-sensitive petrochemical industry. Naphtha finds a home in both the petrochemical and transportation sector.
We continue to take a positive long term view of gas as an energy source. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. In the USA, we believe that our position in the Marcellus and Eagle Ford shale gas acreage, in combination with Gulf of Mexico production, will provide a foundation for growth in our US market position in the years ahead.
Statoil's income could vary significantly with changes in commodity prices, even if volumes remain stable through the year. There is a small seasonal effect on volumes in the winter and summer seasons due to normally higher off-takes of natural gas during cold periods. There is normally an additional small seasonal effect on volumes as a result of the higher maintenance activity level on offshore production facilities during the second and third quarters each year, since generally better weather conditions allow for more maintenance work.
These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. See section Forward looking statements.
Oil and natural gas are subject to internal transactions between our business segments before being sold in the market. We have established a pricing policy for transfers based on the estimated market price.
The table below details certain financial information for our five business segments: Exploration & Production Norway (EPN), International Exploration & Production (INT), Natural Gas (NG), Manufacturing & Marketing (M&M), and Fuel & Retail (SFR). A new corporate structure was implemented from 1 January 2011, and the business segments will be changed accordingly going forward. See the section Business overview and strategy - New organisational structure as from January 2011.
The EPN and INT segments explore, develop and produce crude oil and natural gas, and extract natural gas liquids. The Natural Gas segment transports and markets natural gas and natural gas products. Manufacturing and Marketing is responsible for petroleum refining operations and the marketing of crude oil and refined petroleum products except for natural gas and natural gas products. Fuel & Retail markets fuel and related products, principally to retail consumers.
We eliminate intercompany sales when combining business segment results. These include transactions recorded in connection with our oil and natural gas production in the EPN or INT segments and also in connection with the sale, transportation or refining of our oil and natural gas production in the M&M, NG and SFR segments.
EPN produces oil, which it sells internally to Oil Sales, Trading & Supply (OTS) in the M&M segment. EPN also produces natural gas, which it sells internally to the NG segment, also for sale in the market. A large share of the oil and a small share of the natural gas produced by INT are also sold to the M&M segment or the NG segment, respectively. The remaining oil and gas from INT is sold directly in the market. Statoil has established an estimated market price-based transfer pricing policy whereby an internal price is set at which the EPN business area sells oil and natural gas to the M&M and NG segments.
In 2010, the average transfer price for natural gas per standard cubic metre was NOK 1.27 per scm. The average transfer price was NOK 1.38 per scm in 2009 and NOK 1.87 in 2008. For oil sold from EPN to M&M, the transfer price is the applicable market-reflective price minus a margin of NOK 0.70 per barrel.
For additional information please refer to the Consolidated Financial Statements - note 3 Segments.
The following table shows certain financial information for the five segments, including intercompany eliminations for each of the years in the three-year period ending 31 December 2010.
Following the change in segments in the fourth quarter of 2010 to report Statoil Fuel & Retail separately, prior periods have been restated to be comparable, see the Consolidated financial statement - note 3 Segments - for further information.
In 2010, Exploration & Production Norway delivered strong financial results and strong cash flows, despite reduced production. Exploration expenditure was down, largely due to lower exploration activity.
Statoil completed 17 exploration and appraisal wells on the NCS in 2010, 12 of which were discoveries. In addition, we completed four exploration extensions, three of which were discoveries. Based on the extensive exploration programme in 2008 and 2009, a number of discoveries were matured in the project phase and several prospects were identified. Total exploration expenditure was NOK 6.0 billion in 2010, compared with NOK 8.2 billion in 2009 and NOK 8.7 billion in 2008.
Gross investments amounted to NOK 31.9 billion in 2010, a decrease of NOK 3 billion from the NOK 34.9 billion invested in 2009. From 2008 to 2009, the investment amount remained at NOK 34.9 billion. Around half of our investments are related to new fields, while the other half are investments in existing fields.
In total, four new fields came on stream on the Norwegian continental shelf (NCS) in 2010: Morvin, Gjøa, Vega and Vega South.
Our production of oil and gas on the NCS averaged 1.374 mmboe per day in 2010, compared with 1.450 mmboe per day in 2009 and 1.461 mmboe per day in 2008.
Exploration & Production Norway generated total revenues of NOK 170.7 billion in 2010 and its net operating income was NOK 115.6 billion. The average daily entitlement production in 2010 was 704 mboe per day for liquids and 669 mboe per day for gas.
We generated total revenues and other income of NOK 170.7 billion in 2010, NOK 158.7 billion in 2009 and NOK 219.8 billion in 2008. An increase of 32% in the average price in USD of oil sold by E&P Norway to Manufacturing & Marketing accounted for NOK 29.3 billion of the increase in revenues and a minor increase in lifted volumes of natural gas, making a positive contribution of NOK 0.2 billion. This was partly offset by a decrease of 9% in lifted volumes of liquids, making a negative contribution of NOK 8.9 billion and a negative currency exchange rate deviation of NOK 4.7 billion due to a 4% increase in the USD/NOK exchange rate in 2010. Furthermore, an 8% decrease in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas accounted for NOK 4.1 billion of the decrease in revenues.
There was a decrease in total revenuesfromNOK 219.8 billion in 2008 to NOK 158.7 billion in 2009. A decrease of 37% in the average price in USD of oil sold by E&P Norway to Manufacturing & Marketing accounted for NOK 52.1 billion of the decrease in revenues, and a 26% decrease in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas accounted for NOK 18.9 billion of the decrease in revenues. This was partly offset by a positive currency exchange rate deviation of NOK 12.6 billion due to a 14% increase in the USD/NOK exchange rate. Furthermore, lifted volumes of liquids decreased by 4%, making a negative contribution of NOK 5.7 billion, which was partly offset by a 4% increase in lifted volumes of natural gas, making a positive contribution of NOK 2.9 billion in 2009 compared with 2008.
Operating expenses were NOK 23.5 billion in 2010, compared with NOK 23.4 billion in 2009 and NOK 23.5 billion in 2008. In 2010, increased operating plant costs and other expenses were partly offset by a decrease in transportation costs due to lower lifting of liquids. The decrease of NOK 0.1 billion in operating expenses from 2008 to 2009 was mainly due to lower operating plant costs, partly offset by increased processing/transportation costs.
The average daily lifting of liquids in 2010 was 711 mboe per day, compared with 778 mboe per day in 2009 and 808 mboe per day in 2008. Over time, the volumes lifted and sold will equal the volumes produced, but they may be higher or lower in any period due to differences between the capacity of the vessels lifting our volumes and the actual entitlement production in the period. The average daily overlift was 6 mboe per day in 2010 and 6 mboe underlift per day in 2009, compared with an average underlift of 16 mboe per day in 2008.
The average daily production of entitlement liquids in 2010 was 704 mboe per day, compared with 784 mboe per day in 2009 and 824 mboe per day in 2008. The decrease in production from 2009 to 2010 is mainly related to the C-06 situation, for more details, see section Operational review - E&P Norway - Fields in production on the NCS - Operations West, water injection issues and a decline in the main field on Gullfaks, reduced capacity at Kollsnes, a lower production permit than expected on Ormen Lange and operational challenges on Kristin and Oseberg. The negative effect on average daily production was approximately 70 mbbl in 2010. In addition, we had expected production profile reductions due to a natural decline on mature fields. The decrease was partly offset by increased production at Morvin and Tyrihans.
The decreased production from 2008 to 2009 was mainly related to expected production profile declines on several fields, various operational issues on the Kristin, Gullfaks South and Norne fields, a turnaround and less NGL due to less gas off-take on Oseberg and the closing down of the Tordis subsea separator from the end of May 2008 due to leakage from a well. The decrease was partly offset by a build-up of production on Ormen Lange and Snøhvit and new production at Alve, Tyrihans, Volve, Vilje and Yttergryta, and by Kvitebjørn returning to full production from July 2009 after it was shut down due to a damaged gas pipeline.
The average daily production of entitlement gas was 669 mboe per day in 2010 compared with 666 mboe in 2009 and 637 mboe in 2008.
The unit production cost was NOK 39.7 per boe in 2010, compared with NOK 36.9 per boe in 2009 and NOK 37.3 per boe in 2008. The total production cost was NOK 19.9 billion in 2010, compared with NOK 19.5 in 2009 and NOK 19.9 billion in 2008. The 8% increase in the unit production cost from 2009 to 2010 is due to a 5% decrease in production and a 2% increase in production costs. The increase in production cost is mainly related to new fields coming on stream and increased insurance. The 1% decrease in the unit production cost from 2008 to 2009, is mainly due to a 2% decrease in production costs, partly offset by a 1% decrease in production.
Depreciation, amortisation and net impairment losses were NOK 26.0 billion in 2010, compared with NOK 25.7 billion in 2009 and NOK 24.0 billion in 2008. The increase in 2010 compared with 2009 is mainly related to increased investments in mature fields, partly offset by change in the portfolio of producing fields and the impact on depreciation of reserve adjustments. The NOK 1.7 billion increase from 2008 to 2009 was mainly due to new fields in production in 2009.
Exploration expenditure (including capitalised exploration expenditure) in 2010 amounted to NOK 6.0 billion, compared with NOK 8.2 billion in 2009 and NOK 8.7 billion in 2008. The decrease from 2009 to 2010 was mainly due to fewer wells being drilled in 2010. The decrease from 2008 to 2009 was mainly due to fewer wells being drilled in 2009.
Exploration expenses in 2010 were NOK 5.5 billion, compared with NOK 5.2 billion in 2009 and NOK 5.5 billion in 2008.
In 2010, 17 exploration and appraisal wells and four exploration extensions were completed on the NCS, of which 12 exploration and appraisal wells and three of the exploration extension wells were announced as discoveries.
In 2009, 39 exploration and appraisal wells and two exploration extension wells were completed on the NCS, of which 31 exploration and appraisal wells and both exploration extension wells were announced as discoveries. In 2008, 39 exploration and appraisal wells and nine exploration extension wells were completed on the NCS, of which 27 exploration and appraisal wells and six exploration extension wells were discoveries.
The drilling of six exploration and appraisal wells was ongoing at the end of 2010. Six exploration and appraisal wells have been completed since 31 December 2010, three of which were discoveries.
The reconciliation of exploration expenditure with exploration expenses is shown in the table below.
Net operating income in 2010 was NOK 115.6 billion, compared with NOK 104.3 billion in 2009 and NOK 166.9 billion in 2008. The NOK 11.3 billion increase in 2010 was mainly due to increased liquid prices. The NOK 62.6 billion decrease in 2009 was mainly due to decreased prices for oil and gas.
Our strategy is to deliver international growth in the short and medium term from existing positions, while creating new opportunities for long-term value creation.
Our international entitlement production was 332 mboe per day in 2010, compared with 357 mboe per day in 2009. The average daily equity production of oil and gas was 514 mboe per day in 2010, compared with 512 mboe in 2009.
Equity volumes represent produced volumes under a production sharing agreement (PSA) that correspond to Statoil's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent Statoil's share of the volumes distributed to the partners in the field. They are subject to deductions for, among other things, royalties and the host government's share of profit oil. Entitlement volumes lifted are the basis for revenue recognition, while equity production volumes affect operating costs more directly. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.
Our international portfolio has been further strengthened in 2010 through agreements with Enduring Resources and Talisman in October for the acquisition of 67,000 net acres in the Eagle Ford shale area in southwest Texas. In January 2010, we increased our equity share in the St. Malo discovery in the US Gulf of Mexico from 6.25% to 21.5% by exercising our pre-emption rights. In September, Statoil announced that it will acquire 20.67% of Nautical Petroleum's interest in the Mariner field in UK. We have also entered into an agreement with the Chinese company Sinochem Group to sell 40% of our equity in the Peregrino field off the coast of Brazil and sold 40% of our equity in the Kai Kos Dehseh oil sands development in Northern Alberta in Canada to PTT Exploration and Production (PTTEP) of Thailand. An overview of portfolio transactions in 2010 is presented in section Operational review - International E&P - Our International E&P portfolio.
The total capital expenditure of NOK 44.9 billion in 2010 was higher than last year, mainly due to the acquisition of equity in Eagle Ford and St Malo in USA.
In total 18 exploration and appraisal wells were completed in 2010 and seven wells were announced as discoveries. At year end, five wells were pending final evaluation and the subsequent recertification process, which is still ongoing. Our international exploration activities in 2010 were affected by the drilling moratorium in the US Gulf of Mexico from 27 May to 12 October and subsequent re-certification process. The total exploration expenses were NOK 10.3 billion in 2010, compared with NOK 11.5 billion in 2009.
International Exploration & Production (INT) generated total revenues of NOK 51.0 billion in 2010 and net operating income of NOK 12.6 billion. The average daily entitlement production of liquids was 263 mboe and the average daily entitlement production of gas was 68 mboe.
INT generated total revenues and other income of NOK 51.0 billion in 2010 compared with NOK 41.8 billion in 2009 and NOK 46.1 billion in 2008. The increase from 2009 to 2010 was mainly related to a 25% increase in realised liquid and gas prices which made a positive contribution of NOK 9.4 billion and a 63% increase in other income which made a positive contribution of NOK 1.2 billion. The increase was partly offset by a 4% reduction in lifted volumes which contributed negatively in the amount of NOK 1.4 billion. The decrease from 2008 to 2009 was mainly related to a 34% decrease in realised liquid and gas prices that made a negative contribution of NOK 14.3 billion. This reduction was partly offset by a 26% increase in the lifted volumes, which contributed positively in the amount of NOK 11.2 billion.
The average daily lifting of liquids was 258 mboe in 2010 compared with 267 mboe in 2009 and 211 mboe in 2008. Over time, the volumes lifted and sold will equal our production of entitlement volumes, but they may be higher or lower in any period due to differences between the capacity and timing of the vessels lifting our volumes and the actual entitlement production during the period. The average daily over/underlift in 2010, 2009 and 2008 was 8 mboe in overlift, 2 mboe in underlift and 4 mboe in underlift respectively.
The average daily entitlement production of liquids was 263 mboe in 2010 compared with 283 mboe in 2009, and 232 mboe in 2008. The 7% decrease in average daily liquids entitlement production from 2009 to 2010 was mainly related to a higher PSA effect due to changes in profit tranches and higher prices leading to reduced entitlement shares, a decline in production profile and operational issues in several fields in Angola, and a reduced ownership share in the Mabruk field in Libya. The decrease was partly offset by an increased ownership share in the Agbami field in Nigeria. The 22% increase in average daily liquids entitlement production from 2008 to 2009 was mainly related to the ramp-up of the Agbami field in Nigeria and Saxi-Batuque in Angola, the start-up of Tahiti in the Gulf of Mexico and a higher entitlement factor on PSA fields due to lower prices.
The average daily entitlement production of gas was 68 mboe in 2010 (equivalent to 11 mmcm or 384 mmcf) compared with 74 mboe in 2009 (equivalent to 12 mmcm or 413 mmcf) and 59 mboe in 2008 (equivalent to 9 mmcm or 331 mmcf). The decrease in daily gas production from 2009 to 2010 was mainly related to decline in mature fields in the Independence Hub in the US Gulf of Mexico. The 25% increase in daily gas production from 2008 to 2009 was mainly related to higher off-take from the In Salah field in Algeria and increased production from Independence Hub due to extensive hurricane activity negatively affecting the production in 2008.
The average daily equity liquids and gas production was 514 mboe in 2010 compared with 512 mboe in 2009 and 465 mboe in 2008. The 10 % increase from 2008 to 2009 was mainly due to new fields coming into production.
The unit of production cost based on entitlement volumes was USD 8.6 per boe in 2010 compared with USD 7.2 per boe in 2009 and USD 7.6 per boe in 2008. Measured in NOK, it was 52.0 per boe in 2010, 45.2 per boe in 2009 and 42.2 in 2008. The 13% increase in unit of production cost measured in NOK from 2009 to 2010 is mainly due to increased preparations for production in Brazil for the Peregrino field and lower entitlement factor (from higher realised oil and gas prices in 2010). The increase in unit of production cost measured in NOK from 2008 to 2009 was mainly due to the strengthening of USD in relation to NOK and increased preparation for fields coming on stream.
Production costs are incurred based on our equity production. Management therefore considers that unit of production cost based on equity production is a better measure of cost control than unit of production cost based on entitlement volumes. The unit of production cost based on equity volumes was USD 5.4 per boe in 2010, compared with USD 4.9 per boe in 2009 and USD 4.6 per boe in 2008. Measured in NOK, it was 32.9 per boe in 2010, 30.8 per boe in 2009 and 25.9 per boe in 2008. The increase from 2009 to 2010 is mainly due to increased preparations for operating activity in Brazil for the Peregrino field.
Operating expenses and purchase [net of inventory variation] were NOK 8.5 billion in 2010, compared with NOK 7.8 billion in 2009 and NOK 7.3 billion in 2008. The 9% increase from 2009 to 2010 is mainly due to increased preparation for operation costs on the Peregrino field in Brazil. The 7% increase from 2008 to 2009 was mainly due to new fields coming on stream during 2008 and 2009 (Agbami, Tahiti and Thunder Hawk).
Selling, general and administrative expenses were NOK 2.9 billion in 2010, compared with NOK 2.8 billion in 2009 and NOK 3.2 billion in 2008. The 12% decrease from 2008 to 2009 was mainly due to cost saving initiatives and allocation of costs.
Depreciation, amortisation and net impairment losses were NOK 16.7 billion in 2010 compared with NOK 17.1 billion in 2009 and NOK 13.7 billion in 2008. The 3% decrease from 2009 to 2010 was mainly due to the impact on depreciation of increased proved reserves. The decrease was partly offset by an increase of 1.1 billion in net impairments which was mainly due to the impairment of the Corrib asset in Ireland. The 25% increase from 2008 to 2009 was due to an increase of NOK 4.6 billion in ordinary depreciation, which was mainly due to new assets coming on stream.
This increase was partly offset by a NOK 1.2 billion decrease in net impairments, which was mainly due to adverse effects of market conditions in 2008.
Exploration expenditure was NOK 10.8 billion in 2010 compared with NOK 8.7 billion in 2009 and NOK 9.1 billion in 2008. The increase from 2009 to 2010 was mainly due to increased exploration drilling costs and oil sands delineation drilling costs, increased seismic expenditures and higher pre-sanctioning costs. The average cost per well was significantly higher in 2010 compared to the previous year, mainly due to the situation in the US Gulf of Mexico, but also due to a few expensive wells with high equity share and technical challenges relating to some wells. The decrease from 2008 to 2009 was mainly due to a reduction in seismic spending, reduced drilling activity and lower field evaluation costs. The reduction was partly offset by the strengthening of the USD/NOK exchange rate from 2008 to 2009.
Exploration expenses were NOK 10.3 billion in 2010, compared with NOK 11.5 billion in 2009 and NOK 9.2 billion in 2008. The decrease was mainly due to reduction in net impairment effect of capitalised exploration assets of NOK 5.1 billion, partly offset by higher oil sands delineation drilling, higher seismic expenditures and higher pre-sanctioning costs. The increase from 2008 to 2009 is mainly due to the net impairment effect of capitalised exploration assets of NOK 2.9 billion, partly offset by decreases in drilling activity and seismic spending.
In total, 18 exploration and appraisal wells were completed in 2010 and seven wells were announced as discoveries. In 2009, 29 exploration and appraisal wells were completed and seven wells were announced as discoveries, six of which were completed in 2009 while one well was completed in 2008. At year end, nine wells were pending final evaluation. In 2008, 40 exploration and appraisal wells were completed, eight of which were announced as discoveries.
Net operating income in 2010 was NOK 12.6 billion, compared with NOK 2.6 billion in 2009, and NOK 12.8 billion in 2008. The increase from 2009 to 2010 was mainly related to increased prices, which contributed NOK 9.4 billion, increased other income which contributed NOK 1.2 billion, decreased exploration expenses contributing NOK 1.2 billion and decreased depreciations contributing NOK 0.5 billion.
This was partly offset by a reduction in lifted volumes which contributed NOK 1.4 billion and an increase in purchase, operating, selling, general and administrative expenses contributing NOK 0.8 billion.
The decrease from 2008 to 2009 was mainly related to reduced prices, which contributed negatively NOK 14.3 billion, an increase in depreciation, depletion and amortisation of NOK 3.4 billion, an increase in exploration expenses contributing NOK 2.3 billion, a decrease in other income of NOK 1.2 billion mainly related to the sale of assets, and a miscellaneous increase of NOK 0.2 billion. This was partly offset by increased lifted volumes, which positively affected the result by NOK 11.2 billion.
Gas sales in 2010 were characterised by recovering markets and increasing European gas prices. Trading and sourcing of third party volumes expanded further.
Gas prices developed positively in 2010 compared with price developments in the last quarter of 2009. However, average prices ended lower in 2010 compared to 2009 due to very high prices in the first quarter of 2009. Our volume-weighted average price was NOK 1.72 per scm in 2010 and 1.90 per scm in 2009, a decrease of approximately 9%.
The majority of our long-term gas supply contracts in Europe are indexed to oil products, which means that a change in oil prices will affect the gas markets after a certain time delay (6-9 months). Oil prices increased from the second quarter 2009, and had a positive effect on natural gas price development, particularly from the second half of 2010. In addition, European spot market contracts have seen a strong price recovery since the last quarter in 2009.
All of Statoil's gas produced on the Norwegian continental shelf (NCS) is sold by the Natural Gas business area and purchased from Exploration & Production Norway (EPN) at a market-based internal price. The gradually increasing natural gas sales prices in 2010 were largely offset by an increase in the internal purchase price. Our average internal purchase price was NOK 1.27 per scm in 2010, down from NOK 1.38 per scm in 2009, a decrease of 8%.
Natural gas sales volumes in 2010 were 52.8 bcm, compared to 49.8 bcm in 2009, an increase of 6%. Statoil sold 41.7 bcm of entitlement gas in 2010, a slight increase compared with 2009. In addition, we sold 35.3 bcm of NCS gas on behalf of the Norwegian State's direct financial interest (SDFI). Most of the gas was sold to European energy providers under long-term contracts. Our market share is approximately 20-25% in Germany and France and approximately 15% in the UK and the Netherlands.
Sales of third party volumes amounted to 11.1 bcm in 2010, compared with 8.4 bcm in 2009, an increase of 32%. The increase was mainly due to optimisation and balancing of our portfolio.
Revenues in Natural Gas largely come from gas sales under long-term gas sales contracts and tariff revenues from transportation and processing facilities. Natural Gas generated revenues of NOK 87.5 billion in 2010.