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STATOIL ASA 20-F 2010 Documents found in this filing:
Statoil ANNUAL REPORT ON FORM 20-F
Commission File No. 1-15200
*Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission Securities registered or to be registered pursuant to Section 12(g) of the Act: None Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the Ordinary shares of NOK 2.50 each 3,183,873,643 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities If this report in an annual or transition report, indicate by check mark if the registrant is not required to file reports Indicate by check mark whether the registrant: (1) has filed all reports to be filed by Section 13 or 15(d) of the Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a nonaccelerated Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements If “Other” has been checked in response to the previous question, indicate by check mark which financial If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule Annual report on Form 20-F 2009Table of content1 Introduction1.1 Cover page1.2 Key figuresKey figures is a presentation of our performance in important areas: income, return, cash flow, oil production and price, gas production and price, proved reserves, total recordable injuries, serious incidents, and carbon dioxide emissions. | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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For the year ended 31 December |
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(in NOK billion, unless stated otherwise) |
2009 |
2008 |
2007 |
2006 |
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Financial information |
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Total revenues |
465.4 |
656.0 |
522.8 |
521.5 |
Net operating income |
121.6 |
198.8 |
137.2 |
166.2 |
Net income |
17.7 |
43.3 |
44.6 |
51.8 |
Cash flow provided by operating activities |
73.0 |
102.5 |
93.9 |
88.6 |
Cash flow used in investing activities |
75.4 |
85.8 |
75.1 |
57.2 |
Interest-bearning debt |
104.1 |
75.3 |
50.5 |
54.8 |
Net interest-bearing debt |
75.3 |
46.0 |
25.5 |
43.8 |
Total assets |
562.8 |
579.2 |
483.1 |
458.8 |
Share Capital |
8.0 |
8.0 |
8.0 |
8.0 |
Minority Interest |
1.8 |
2.0 |
1.8 |
1.6 |
Net assets / Total equity |
200.1 |
216.1 |
179.1 |
169.4 |
Net debt to capital employed |
27.3 % |
17.5 % |
12.4 % |
20.5 % |
Return on average capital employed after tax |
10.4 % |
21.0 % |
17.7 % |
22.6 % |
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Operational information |
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Equity oil and gas production (mboe/day) |
1,962 |
1,925 |
1,839 |
1,780 |
Proved oil and gas reserves (mmboe) |
5,408 |
5,584 |
6,010 |
6,101 |
Reserve replacement ratio (three-year average) |
64% |
60% |
81% |
76% |
Production cost (NOK / boe equity volumes) |
35.3 |
34.6 |
41.4 |
27.3 |
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Share information |
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Ordinary and diluted earnings per share |
5.75 |
13.58 |
13.80 |
15.82 |
Share price at Oslo Stock Exchange on 31 December |
144.80 |
113.90 |
169.00 |
165.25 |
Dividend paid per share NOK (1) |
6.00 |
7.25 |
8.50 |
9.12 |
Dividend paid per share USD (2) |
1.04 |
1.26 |
1.47 |
1.58 |
Weighted average number of ordinary shares outstanding |
3,183,873,643 |
3,185,953,538 |
3,195,866,843 |
3,230,849,707 |
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(1) See Shareholder information section for a description of how dividends are determined and information on share repurchases. |
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(2) USD figure presented using the Central Bank of Norway 2009 year-end rate for Norwegian kroner, which was USD 1.00 = 5.7767 NOK. |
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Statoil publishes financial data in accordance with IFRS. Statoil did not publish financial data in accordance with IFRS in 2006 as we previously presented financial data in accordance with US GAAP. For this reason, we have not provided selected financial data for 2005 in this Annual Report. Selected financial data for that year presented in accordance with US GAAP is included in our 2006 Annual Report on Form 20-F.
1.5 A glance at 2009
2009 was a year of uncertainty, with the threat of the financial crisis, falling oil and gas prices and more unpredictable demand. Nevertheless, we delivered on our production targets and are well positioned for the future. This is a brief review of 2009.
The year at a glance
In January, we revealed our intent to merge land-based organisations and offshore installations in an over-arching production system designed to run the business more safely and predictably. The restructuring process proceeds as planned. The latest milestone is the opening of a new operations support centre at Sandsli.
Also in January, gas flowed from the Yttergryta subsea field on Åsgard in the Norwegian Sea. The field progressed from discovery to production in just 18 months. The average lead time for offshore oil and gas field developments in Norway is 15 years.
In March, we made a discovery at the Asterix gas prospect in the Norwegian Sea, which was deemed one of the larger finds offshore Norway in recent years.
In April, we joined forces with Norwegian power utility Statkraft to develop the 315 MW Sheringham Shoal Offshore Wind Farm off the coast of Norfolk, UK. The wind farm will have 88 turbines and is planned to start production in 2011. When fully operational, its annual electricity production will be about 1.1 TWh, enough to power some 220,000 UK homes.
Also in April, we announced the acquisition of a 40% stake in 50 blocks from BHP Billiton in the frontier DeSoto Canyon area of the US Gulf of Mexico. DeSoto Canyon is located east of Statoil's current production operation at Independence Hub. The area has water depths of about 1,000 metres, and is a mostly unexplored region in the eastern part of the Gulf of Mexico (GoM), offering advantageous early access to new plays.
In May, first oil was tapped on the Tahiti field in the Gulf of Mexico.
An offshore worker died on 7 May after an accidental fall on the North Sea Oseberg B platform operated by Statoil, in connection with the removal of scaffolding from the drilling area on the B platform. The victim was an employee of scaffolding contractor STS. In direct response to the accident, Statoil and contractors Aibel and STS took the initiative to introduce improvements throughout the entire scaffolding industry.
In June, production on the Lufeng 22-1 field in the South China Sea was shut down. We operated the field together with partner CNOOC from 1997. Under an agreement between CNOOC and Statoil, CNOOC has taken over full responsibility for the abandonment of phases two and three of the field. Our Shekou operations office was closed at the end of 2009, and our activities in China are currently centred around R&D cooperation and business development.
On June 1, we were devastated by the news that three colleagues from our Rio de Janeiro office were on Air France flight 447 that disappeared over the Atlantic. Geologist Marcela Pellizzon, 29, and lawyer Gustavo Peretti, 30, both Brazilian citizens, and Norwegian lawyer Kristian Berg Andersen, 37, perished in the accident. A memorial service was held in Rio in June.
In July, first oil was tapped on the Thunder Hawk field in the Gulf of Mexico.
Also in July, the Tyrihans field in the Norwegian Sea came on stream using the world's longest directly heated pipeline - some 43 kilometres long.
During the summer, some 30 vessels took part in marine operations on the Gjøa and Vega fields in the North Sea. Gjøa is our largest project under construction in the North Sea today and expected to start producing in 2010. The field's semi-sub platform is Statoil's first floating installation to source electricity from the mainland, reducing CO2 emissions by about 210,000 tonnes per year. The smaller Vega deposit will tie in to Gjøa and also start producing in 2010.
In August, we set a world record on the Ormen Lange field in the Norwegian Sea when the world's deepest remotely controlled "hot-tap" operation was completed at a sea depth of 860 metres.
In September, our Hywind pilot project - the world's first full-scale floating wind turbine - was officially inaugurated off the coast of western Norway for two years of testing. A still immature technology facing a long road to commercialisation and full-scale wind farm construction, Hywind can help floating wind turbines make a long-term contribution to meeting the world's soaring demand for energy.
Statoil CEO Helge Lund took part in a preliminary meeting at the UN headquarters in New York, in connection with preparations for the international climate summit in Copenhagen, after being appointed a member of the UN expert group for climate and energy. Statoil was the only oil company represented in the group, which consists of approximately 20 persons from different countries.
In October, we announced the nineteenth oil find on Angola's offshore Block 31. We hold a 13.3% stake in the acreage. Sonangol is concessionaire and BP operator. We are partner in nine producing Angolan fields, which contribute more than 200,000 barrels of equity production per day to our portfolio.
In November, we changed our name to Statoil and introduced our new brand identity. The Horton case - concerning Statoil's contract with Horton Investment Ltd, related to business development in Iran - was formally closed by the US authorities in November. Statoil fulfilled the conditions of agreements signed in 2006 with the US authorities to substantially strengthen our ethics and anti-corruption practices. Offshore installation of the first wellhead platform on the Statoil-operated Peregrino field in Brazil started.
In December, Statoil and Lukoil won the technical service contract from Iraq's Ministry of Oil to develop the sizeable West Qurna 2 field in the southern part of the country. West Qurna 2 is estimated to hold 12.9 billion barrels of recoverable reserves.
We signed memorandums of understanding (MoU's) with Gazprom to import LNG into the US and trade it there. The MoU's include Gazprom getting re-gasification capacity at the Cove Point, Maryland, LNG receiving terminal. Statoil will also sell natural gas to Gazprom at various US locations, while purchasing LNG from Gazprom at Cove Point.
Finally, it was announced on 18 December that Statoil and Chinese oil giant Sinopec will carry out joint geological studies on two deep-water blocks in the South China Sea. The agreement makes Statoil the first foreign company to work with Sinopec off the coast of China.
The year as a whole
Our total equity output both in and outside Norway increased to some 1,950,000 barrels of oil equivalents per day.
We carried out an extensive exploration drilling campaign on the NCS in 2009, completing 39 exploration wells, 30 wildcat wells to test new prospects and nine appraisal wells to establish the extent and size of previous discoveries. We proved 22 new discoveries, resulting in a discovery rate of more than 70%. Most of the finds are relatively small and close to producing fields in the North Sea and Norwegian Sea, making later tie-ins possible. The most important discoveries in 2009 were Asterix, Gro, Katla and Beta West; all except Gro being Statoil-operated.
Internationally, our average daily production surpassed 500,000 boe for the first time. Equity production increased by 10% from 2008, to 512 mboe/day, and production from three new fields started during the year. We had a high level of exploration activity: six of the 29 exploration wells drilled in 2009 have been announced as discoveries, with several interesting discoveries in the US Gulf of Mexico, Canada and Angola.
Looking ahead
The Leismer oil sands development project in Canada is well underway with production start up expected in autumn 2010. The Leismer Commercial Demonstration Plant is stage one of our total field development plan for several bitumen hubs upstream.
Our Peregrino project now towers over the surface of the sea in the Campos basin off Brazil. First oil is expected in early 2011 and production should reach its plateau of 100,000 barrels of oil equivalents per day within the first year.
The onshore Marcellus shale gas leases in the eastern US are in early stages of production and growing steadily.
2 Business overview
2.1 Our business
Statoil is an integrated energy company based in Norway. The company is present in approximately 40 other countries worldwide. We are the leading operator on the NCS and are also experiencing strong growth in our international production.
Statoil ASA is a public limited 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).
Entitlement oil and gas production outside Norway accounted for 20% of our total production, which averaged 1.806 mmboe per day in 2009.
As of 31 December 2009, we had proved reserves of 2 174 mmbbl of oil and 514 bcm (equivalent to 18.1 tcf) of natural gas, corresponding to aggregate proved reserves of 5 408 mmboe.
We are represented in approximately 40 countries and are engaged in exploration and production activities in 22 of them. As of 31 December 2009, we had approximately 29,000 employees.
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 have substantial processing and refining activities and approximately 2000 service stations in Scandinavia, Poland, the Baltic States and Russia.
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 of 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.
Business address
Our business address is Forusbeen 50, N-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Our largest locations in terms of the number of employees are in Stavanger, Bergen and Oslo, Norway.
The Statoil group and the main business and function areas are presented in the following sections of this report.
The figures below provide an overview of the geographical reach of Statoil's business and the organisational structure of our business areas and staff functions.
2.2 Our history
Statoil was formed in 1972 by a decision of the Norwegian Storting (parliament) and was listed on the Oslo and New York stock exchanges in 2001.
Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap a.s. Wholly-owned by the Norwegian State, the company's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway. In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and changed its name to Statoil ASA. On 1 October 2007, the oil and energy division of Hydro (formerly Norsk Hydro) was merged with Statoil, and the company was given the temporary name of StatoilHydro ASA. On 1 November 2009, the company changed its name back to Statoil ASA.
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 the exploration, production and development of oil and gas on the Norwegian continental shelf (NCS) as partner.
In the 1970s, we commenced our own operations, made important discoveries and entered into 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, resulting from intense technological development on the NCS. We laid the base 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 taken advantage of our competence to design and manage operations that function correctly in the environments they face, in order to grow our upstream activities by means of other than traditional offshore production, for example threough the development of heavy oil and shale gas projects.
Although petroleum related activities on the NCS and internationally have formed the main part of our business, we have increasingly participated in projects focusing on other forms of energy project, such as wind power and carbon capture and storage, in anticipation of the need to expand energy production, strengthen energy security and fight adverse climate change.
2.3 Statements on competitive position
Statements referring to Statoil's competitive position rely on a range of sources, including analysts' reports, independent market studies and our internal assessments of our market share.
Statements referring to Statoil's competitive position in the Business Overview and Operational Review sections are based on what we believe to be true and, in some cases, they rely on a range of sources, including investment analysts' reports, independent market studies and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.
2.4 Strategy
Statoil's long-term strategy builds on the company's vision: 'Crossing Energy Frontiers'. It continues the current strategic direction of creating shareholder value as an upstream-oriented, and technology-based energy company.
Our strategy of long-term value creation, starts with our short-term deliveries on 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.
2.4.1.Business environment
In 2009 the world economy experienced the most severe recession since the Great Depression of the 1930s. There is still significant uncertainty as to the health of the world economy.
The recession has led to a significant reduction in energy demand in most regions. Energy prices fell significantly in the first part of the 2009, and caused a large reduction in revenues for the players in the industry. The corresponding falls in suppliers' costs have been much smaller. Thus, the industry's profitability has weakened significantly. Most energy commodity prices have showed a partial rebound during the second half of 2009 contributing to a more positive outlook for 2010.
Macroeconomic outlook
After growing by more than 3% on an annual average basis during 2000-2008, the world economy in 2009 experienced the most severe recession since the Great Depression of the 1930s. Following the turbulence in the international financial system in the autumn of 2008, plunging business confidence and demand retrenchments led to a sharp contraction in global industrial production and international trade. In the first quarter of 2009 world economic activity fell by almost 4%. However, resolute and strong policy responses in all major economies stabilised the financial markets, restored general market confidence and from mid-2009 put the world economy on a moderate recovery path. China and other emerging economies in Asia provided an important stimulus to developed economies. For the year as a whole, there was a negative GDP growth of 3.4% and 1.9% for the OECD economies and the world economy, respectively.
At the beginning of 2010, the recovery of all major economies is still in progress. The rate of improvement does, however, vary across sectors and regions, as does the uncertainty of the outlook. Asia Pacific, less affected by the financial crisis and debt financed consumption, continues to grow relatively strongly, while the expansion in the United States and especially the European economies is more hesitant. This is mainly due to the household sectors' need for debt deleveraging, the high unemployment rate and the low rate of capacity utilisation in most industries. Furthermore, although the balance sheets of the financial institutions have improved during 2009, the planned banking reforms and the banks' own consolidation suggest that bank lending will continue to be restricted for some time. Overall, these forces indicate that the recovery of the world economy is expected to continue during 2010, but with a less vigorous upturn than was typical for previous business cycles.
The governments' economic rescue packages, which successfully contributed to the stabilisation and recovery in 2009, have led to severe deterioration of public finances in most OECD countries. The federal deficits of the main economies, excluding Germany, have increased from pre-crisis levels of about 1.0-2.0% of gross domestic products to an estimated 9-12% for 2010. Since these levels of public deficit are not sustainable, the outlook beyond 2010 implies a more contractive fiscal policy. This is likely to restrain the pace of economic growth beyond 2011-2012. The underlying structural global imbalances, which were among the underlying causes of the recession of 2008-2009, have been corrected only partly and temporarily. Overall, these imbalances suggest that the medium-term outlook for the world economy is still marked by uncertainty.
Energy markets and price developments
The sharp fall in world economic activity in 2008-2009 led to large reductions in energy demand in most regions of the world. Driven by a 2.1 mbd reduction in OECD oil demand, global oil demand fell by about 1.3 mbd (1.5%) from 2008 to 2009. The demand for natural gas also fell significantly in North America and Europe by 1.1 % and 6.3% (estimate), respectively. Helped by the relatively short-lived economic downturn, oil and gas demand held up reasonably well in China and non-OECD Asia. The weakness in energy demand has pushed energy prices down to levels not seen since the early 2000s.
After the historical high of USD 144 per barrel (dated Brent) in mid-2008, crude oil prices plunged by about USD 100 per barrel during the second half of 2008, before levelling out in the USD 40-45 per barrel range in the first quarter of 2009. The stabilisation was helped by large cuts in Opec production, which stabilised the physical markets and prevented oil stocks from building further. Despite the high oil stocks and comfortable spare Opec production capacity, crude oil prices started to recover in the second quarter, triggered by expectations of an emerging world economic recovery and the prospect of a weaker US dollar. The upward trend in oil prices lasted throughout the year, supported by constructive macroeconomic data and relatively strong demand growth in Asian markets. By the end of 2009, prices were around USD 75 per bbl. Financial players' perceptions, portfolio optimisation and market positions were important drivers behind the 2009 oil price recovery. The average price of dated Brent in 2009 was USD 61.6 per bbl, down from USD 97.3 per bbl in 2008.
The Atlantic products' markets have also been severely hit by the economic recession. Total demand for products in the US and OECD European markets both fell by close to 0.8 million barrels per day, or more than 4%, from 2008 to 2009. Reduction in the demand for distillates, including diesel oil, gas oil and jet/kerosene accounted for about half of the total, while gasoline demand kept up relatively well in both regional markets. Lower demand for oil products led to high products stocks and downward pressure on the price differentials between oil products and crude oil. However, the relative stability of the gasoline markets led to less depressed gasoline differentials (margins), while distillate margins were at their lowest since 2003-04. Thus, refineries with a high gasoline yield were somewhat sheltered from the recession, led market developments of 2008-09.
Natural gas prices (spot) in North America and Europe, which also peaked in mid-2008, fell continuously until September 2009 on the prospect of significant oversupply. This was driven by the outlook for recession-induced demand reductions, sustained US domestic production and prospects for a steep growth in the imports of LNG into the Atlantic Basic markets. Especially in the United States, market gas prices came under downward pressure due to a concern that the need for storage capacity could exceed the actual storage capacity. Prices reached a low of about USD 2.5-3.0 per million BTU in September 2009 - the lowest level since 2002-2004. Gradually, however, it became clear that as US domestic production began to slide, natural gas captured market shares from coal in power generation, the storage surplus was not growing and significant volumes of Middle East LNG supplies were directed to Asian and European markets. The reduced supply pressure put gas prices in both markets on a moderate recovery path, and by the end of the year US prices were back at about USD 5.70 per million BTU, close to the price levels at the beginning of the year. Although US conventional production slid further through 2009, the expansion of unconventional gas production, especially the production of shale gas, continued its sharply rising trend through the year. The European market has also been affected by lower gas demand and increased supply pressure, primarily from higher volumes of NGL and European spot prices (NBP) followed a similar pattern as US spot prices. The average NBP spot prices were reduced from USD 11.43 per million BTU in 2008 to USD 4.94 per million BTU in 2009.
European electricity prices fluctuated around a level of EUR 50-60 per MWh during 2005-08 and reached a peak of almost EUR 100 per MWh immediately after the break-out of the crisis in the financial markets in the autumn of 2008. Following the sharp decline in European economic activity during the winter of 2008-09, power demand contracted by more than 6 % (estimate) relative to the year before and pushed electricity prices to a low of EUR 30-40 per MWh. Power demand recovered during the second half of the year and pulled prices up into the EUR 40-50 per MWh range.
Prices in the European carbon dioxide market, the EU Emission Trading Scheme, tend to follow the same pattern as electricity prices as that market shares the same demand-side drivers. Carbon prices have, however, been relatively stable around EUR 13-15 per tonne during 2009. The lack of a clear direction following the Copenhagen meeting on future global and regional climate policies pushed carbon prices moderately downwards in December 2009.
The outlook for energy prices over the next few years is basically linked to the prospects for a moderate recovery of the world economy. The oil market is likely to resume the pre-crisis trends of moderate demand growth, modest to stagnant growth in non-Opec production and some expansion in Opec NGL/condensate production. This also suggests that Opec's spare production capacity will gradually be reduced. However, since oil price formation is strongly influenced by financial players, the uncertain outlook for financial markets, geopolitical developments and the US dollar will continue to be important additional drivers. The short-term outlook for the Atlantic Basin products markets is driven by a modest demand growth and the potential for products imports from several export refineries in the Middle East and Far East. The outlook for a sustained overcapacity in refining in the Atlantic Basin may at some point lead to capacity closures in Europe.
Prospects for a rebalancing of the European and North American gas markets are related to the strength of economic recovery. On the demand side, the price-driven competition with coal will continue to be important. The outlook for a further rise in US conventional gas production at relatively low costs has reduced the potential for imports to the North American markets. The prospects for increased LNG supplies into the Atlantic Basin are expected to cap significant natural gas price increases.
Industry context
Restricted upstream access, increasingly complex resources, the climate challenge and tougher financial terms have become more evident as strategic challenges for the oil and gas industry over the last 10 years. Access to resources restricts the growth potential of oil and gas companies, with a large share of the world's remaining conventional resources held by countries with limited access for international oil companies (IOCs). National oil companies have also entered the industry contest for international resources, resulting in an industry arena that is more competitive than ever. IOCs are therefore gradually being pushed to grow their asset base by accessing hydrocarbons in more remote areas, in deeper waters and in more technologically challenging environments. As a result, the contribution made by unconventional and deepwater hydrocarbons has increased by more than 10 percentage points during the last decade to make up nearly 30% of global production capacity in 2009. There are reasons to expect this trend to continue. Another key point is the global climate challenge. Climate regulation still remains uncertain post-Copenhagen, but a potential cost impact related to future policy adjustments remains a likely outcome. In addition to the access and climate challenge, industry profitability has tightened both through increasingly stringent government terms, but recently also through the margin squeeze following the financial turmoil.
The fall in oil and gas prices in the autumn of 2008 in the aftermath of the banking crisis took its toll on the industry in general. With average oil prices down by almost 40% in 2009 compared to 2008, revenues were severely hit. At the same time, suppliers' costs did not show a corresponding decrease. Data suggest that the cost level fell by 20-25% within capital intensive categories, while labour intensive supplies were reduced about 10%. Thus, overall industry profitability has significantly declined compared to 2008.
As a result of the margin squeeze, many companies have had to increase their borrowing, adjust their capital expenditure plans, re-evaluate their dividend policies, reduce their share buyback programmes and increase their focus on cost control and capital deployment efficiency through tighter prioritisation of exploration and development opportunities.
During the fourth quarter of 2008, most sources of funding dried up, and corporations with weak credit ratings had limited access to the bond market. However, the bond market recovered in 2009, especially for high-quality borrowers like the IOCs, which led to a large number of bond issues. Most of the money raised was used to finance existing operations and capital expenditure commitments rather than merger and aquisitions activities. Global E&P spending fell by some 15 - 20% in 2009. On the NCS on the other hand, the investment level grew by 14% mainly led by new field developments which are more challenging and require more resources due to their complexity and smaller size. With a more positive market sentiment and the jump in oil prices since the second quarter of last year, there is also an expectation of increased E&P spending for next year. Industry surveys indicate that global E&P expenditures will increase by approximately 10% this year. Statistics Norway suggests that the 2010 investment level on the NCS will be slightly lower than that of 2009. Consistent with the overall themes in the industry of cost control and capital discipline, disposals of non-core assets are back on the agenda. Several assets are currently being marketed among major oil and gas companies.
Following the financial turmoil, the drop in demand has led to refinery overcapacity and pressure on margins. This is exacerbated by the start up of several export refineries in the Far East and Mid-East. In the longer term, refining overcapacity in the Atlantic basin is expected to lead to capacity closures in Europe.
The increased concerns for energy security and climate change have continued to fortify policy and long-term market drivers for commercial growth in renewables. While most renewable energy forms are more costly than fossil fuels are today, the competitive landscape is expected to shift as production costs for renewable energy decline, while the cost of carbon emissions is reflected in power and fuel prices. Significant amounts of public and private funding are currently going into research, development and expansion of new technologies in order to make renewables and Carbon Capture and Storage (CCS) more competitive.
Wind power is the largest single market for new energy, with prospects of increasingly higher production growth over time. Offshore wind is expected to take a significant share of the total wind market if several of the major countries are to achieve their renewable energy goals.
2.4.2 A strategy for value creation and growth
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 overall long-term strategy builds on the following key components:
- Utilise our technology and management capabilities to capture the full potential of our positions on the Norwegian continental shelf (NCS).
- Deliver profitable international growth in the short and medium term from existing positions, whilst creating new opportunities for long-term value creation.
- Use exploration as a key growth tool to secure long-term production capacity.
- Develop profitable midstream and downstream positions in support of our upstream activities.
- Pursue selected business opportunities for renewable energy production and CCS.
- Apply technology and innovate in order to create value and accelerate asset developments.
- Minimise carbon emissions from, and the general environmental impact of, our upstream and midstream activities.
- Utilise organisational capabilities as a global energy company.
Short term priorities are to conduct safe and efficient operations and to deliver production growth in line with our guidance. We are transforming the way we work on the NCS in order to realise the full value potential of our positions there. We continue tight management of our cost base. Retaining financial flexibility remains important for us. In the longer term, our priorities are to optimise, mature and execute the current project portfolio, taking into account the dynamic economic environment, the globalisation of gas markets and the politically imposed framework and regulatory measures aimed at mitigating the risk of adjustment costs induced by climate change.
Utilising our capabilities
Gaining access to sufficient petroleum resources is increasingly challenging. We are seeking new opportunities in demanding areas requiring the full use of our legacy competence in technology and management. We also realise that mastering the most demanding areas qualifies us for succeeding in less demanding areas. There are four demanding areas in which Statoil has experience and competitive advantage:
- Deep water: we are active in six of the most interesting deepwater basins in the world - the Gulf of Mexico, Brazil, Angola, Nigeria, Norway and Indonesia.
- Harsh environments: we see the resource potential of the Arctic as particularly interesting, although it is a region that is not expected to deliver substantial results until the medium to longer term due to technical and environmental challenges .
- Heavy oil: we have positions in Norway, Canada, Venezuela, Brazil and the United Kingdom.
- Gas value chain: we are active in finding and delivering gas in many countries and have an extensive portfolio that includes Liquefied Natural Gas (LNG) and unconventional gas, e.g. US shale gas.
Responding to the climate challenge
Our ambition is to be an industry leader in carbon efficiency in terms of having a low climate impact in each of the activities in which we are engaged. We aim to create value by seeking low-carbon and energy-efficient competitive solutions in all areas of our business. Responding to the climate challenge in an effective manner will give our company a competitive advantage in the future.
Maximising value creation from upstream access opportunities
We will use exploration as a key growth tool to secure long term growth of reserves, production and value. This is consistent with maximising the long-term value of the NCS and with leveraging our core competencies to build, mature and deliver profitable growth outside Norway. We will continue to optimise our exploration portfolio, balancing frontier-, growth- and infrastructure led exploration.
We will continue selective business development activities to optimise the portfolio.
Maximising long-term value creation on the Norwegian continental shelf (NCS)
We maintain our position as the main industry player on the NCS.
We continuously work to improve our HSE performance and our cost and operational efficiency as well as implementing measures for improved hydrocarbon recovery (IHR). We see a structural shift in our non-sanctioned project portfolio from a few large, complex projects to a high number of mainly smaller projects or sub-sea tie-backs. This demands a high level of standardised technical concepts as well as simplified development processes.
Building and delivering profitable international growth
Our strategy is to deliver profitable international growth in the short and medium term from existing positions, while creating new opportunities for long-term value creation. We will utilise our core expertise in areas such as deep waters, harsh environments, heavy oil and the gas value chain to pursue attractive business opportunities around the world. Statoil's history as a state oil company gives us a competitive advantage in understanding host countries' needs and requirements and in working with them to develop the resource base to their benefit while creating value for our shareholders.
We anticipate that Statoil's future growth mainly will take place outside the NCS. Our short to medium-term focus is on delivering and maturing a high-quality project portfolio on time and within budget. In the longer term, our international asset base will allow us to grow and become more diversified, both in geographical terms and in types of production.
Developing profitable midstream and downstream positions
Statoil's strategy is to develop projects and to produce oil and gas where we see a potential for attractive returns and added value. We have a strong upstream focus in terms of our total value and asset base, complemented by a midstream and downstream portfolio related to marketing, trading, refining and storage of oil and gas products. We seek to capture synergies from our upstream positions and the market characteristics.
We anticipate further globalisation of the gas markets, and changes in the location of our oil and gas production. We also expect changes in consumption patterns in the aftermath of the financial crisis and as a result of the introduction of greenhouse gas mitigation measures by the authorities. We will monitor our midstream and downstream activities and adjust in a timely manner to meet the needs of markets and of our upstream positions to optimise our portfolio and maintain shareholder value.
Creating platform for renewable energy production and carbon capture and storage
Our strategy for renewable energy production and carbon management is to utilise existing core capabilities and current business positions to create profitable positions in renewable energy, prioritising offshore wind projects while keeping track of opportunities in other other areas through technology and selective investments.
We are building a portfolio of near-shore and off-shore wind farms and we are developing technology for large-scale deep water offshore wind power generation. In this context, our participation in Sheringham Shoal UK wind farm was an important milestone achieved in 2009 as was the preparation for the Forewind consortium on the Dogger Bank development to which we were awarded rights in 2010. Off the south-west coast of Norway we are piloting a prototype of the world's first full-scale floating wind turbine, Hywind, which is designed to be placed at water depths between 120 and 700 metres.
In addition, we reduce emissions of greenhouse gases from fossil energy production through carbon capture and storage (CCS).
Using technological innovation and implementation as a key business enabler
Technology is a key enabler in terms of Statoil realising its goals as an internationally competitive energy company. Our ambition is to attain distinctiveness and industrial leadership by aligning our technology and R&D efforts with our portfolio of activities and vice versa.
Based on our history of technological achievements, we actively seek to master demanding and critical developments within our priority activity areas. We prioritise technology efforts that add value to resources, and that allow us to develop smarter solutions for energy exploration and production, that are cost-effective and environmentally benign. We refine and standardise our technical requirements and work processes.
Technology innovation and implementation is critical to success in many of our activities, such as enabling field development in frontier deep waters and Arctic areas, the production of heavy oil, exploration for hydrocarbons trapped below salt, and managing environmental and climate-related issues. In addition, to enable sustainable energy provision in the long term, we aim to remain competitive in a broad range of core and emerging technologies, including offshore wind and sustainable biofuel.
2.5 E&P Norway
2.5.1 Introduction to E&P
Exploration & Production Norway consists of our exploration, field development and operations on the NCS.
Exploration & Production Norway (EPN) is the operator of 42 developed fields on the NCS. Statoil's equity and entitlement production on the NCS was 1,450 mmboe per day in 2009, which was about 75% of Statoil's total production. Acting as an operator, EPN is responsible for approximately 75% of all oil and gas production at the NCS. . In 2009, our average daily production of oil and natural gas liquids (NGL) was 784 mboe and our average daily gas production was 105.9 mmcm (3.7 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 219 licences on the NCS and are an operator for 162 of them.
As of 31 December 2009, EPN had proved reserves of 1,351 mmbbl of crude oil and 480 bcm (16,9 tcf) of natural gas, an aggregate of 4,369 mmboe.
2.5.2 E&P strategy
E&P Norway's strategy is to realise the full potential of the NCS through exploration, new developments, improved operational and drilling cost-efficiency, increased recovery from existing fields and the optimal use of existing infrastructure.
Safe and efficient operations are essential to our business
All activities in Statoil are conducted with a great focus on HSE in order to prevent harm to people and the environment. The implementation of Integrated Operations (IO) is expected to increase economic value through higher production, higher regularity and cost reductions. Upgrading and modification programmes for offshore installations are also planned with a view to maintaining safe and efficient operations.
Through our ongoing efforts to finalise the implementation of integrated operations and common work processes on all our installations on the NCS we aim to utilise best practices and optimise the use of our total resources to ensure safe and efficient operation.
Maintaining a high production level
Several fields on the NCS are maturing and production is declining. High priority will therefore be given to more efficient drilling operations, improved regularity and increased hydrocarbon recovery (IHR).
High regularity is expected to be achieved through efficient well work, better reservoir management, de-bottlenecking of export infrastructure and efficient turnarounds.
It is important to utilise unused capacity in existing infrastructure. Active near-field exploration is a key factor in extending fields' lifetime and initiating cost-effective tail-end production on fields that are in decline and/or have reached a critical point with respect to profitability.
Optimal development and exploitation of our existing portfolio is necessary in order to secure a solid foundation for future activities through continued active maturation of the project portfolio and high exploration level. New field developments are in general more challenging than before either in terms of complexity, smaller size or profitability. Hence these projects require more resources per barrel than before.
Access to new, prospective acreage is also necessary in order to maintain a high production level in the longer term. One of our ambitions is to become one of the leading players in the Arctic by 2020. Considering the long lead times for field developments, it is a pre-requisite in the near term to open new acreage. Succeeding in new field developments in the northern areas of the NCS is a priority for Statoil. Important efforts are currently under way to maintain stable operations in the Snøhvit LNG project, and to support timely and robust development of the Goliat oilfield. However, new high-quality exploration acreage remains a critical prerequisite for long-term success. To meet our ambitions in the far north, we have to address challenges in a range of areas - including geology and technology.
Gas position
The proportion of natural gas from our NCS portfolio is increasing. We have a flexible transportation system, with six different landing points on the European Continent/UK and flexibility in terms of gas deliveries from large gas-producing fields such as Troll and Oseberg.
Energy efficiency and carbon emissions
E&P Norway aims to maintain and strengthen the NCS's position as the most energy-efficient petroleum region in the world. We intend to push for energy efficiency in our day-to-day operations and evaluate new field developments in a long-term perspective with regard to energy and the environment. E&P Norway also plans to put more effort into developing a more energy-efficient supply chain with a life cycle perspective.
Industry leader on the NCS
We will maintain a stable relationship with suppliers, competitors, government and other stakeholders. The NCS is an arena for world-class innovation and technological development. Statoil is a leader in the deployment of new technology, including drilling and subsea technology, new solutions for reducing costs and the use of new technology for developing discoveries. As the largest operator on the NCS, we are leaders in the development of optimal area solutions and the overall development of the NCS.
2.5.3 E&P key events in 2009
In 2009, Exploration & Production Norway had a high level of exploration activity, and discoveries were made in 31 of 39 exploration wells.
- Total entitlement liquids and gas prodution in 2009 was 1,450 mboe per day.
- Started implementation of a new operating model for our offshore organisation in mid-2009.
- Several turnarounds completed in 2009.
- High exploration activity: 31 discoveries out of 39 exploration wells.
- New projects sanctioned:
- Goliat
- Ekofisk 2/4 V-A
- Vega South Oil
- Snorre Export
- Åsgard Gas Transfer
- Production from four new fields added total capacity of approximately 45 mboe per day:
- Yttergryta
- Alve
- Tyrihans
- Tune South
2.6 International E&P
2.6.1 Introduction to International E&P
Statoil is present in several of the most important oil and gas provinces in the world and International Exploration & Production will provide most of Statoil's future production growth.
International Exploration & Production (INT) is responsible for exploration, development and production of oil and gas outside the Norwegian continental shelf.
In 2009, the business area was engaged in production in 12 countries: Canada, the USA, Venezuela, Algeria, Angola, Libya, Nigeria, the UK, Azerbaijan, Russia, Iran and China. In 2009, INT produced 26% 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), Latin America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria and Tanzania), the European and Caspian area (the Faroes, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia).
The main sanctioned development projects in which we are involved are in Canada, USA, Brazil and Angola, and we believe we are well positioned for further growth through a substantial pre-sanctioned project portfolio including the latest addition, the West Qurna 2 in Iraq. In January 2010 Statoil and Lukoil signed the development and production contract for West Qurna 2 with Iraqi authorities.
The map shows our exploration and production areas.
2.6.2.International E&P strategy
Our long-term upstream growth ambition will mainly be achieved by developing our international portfolio of assets into profitable growth.
Our four focus areas are:
- Deep waters - We will further develop our position as a leading deepwater operator. New technology made it possible to develop the Ormen Lange field with subsea installations only. We will also build on the experience gained on the Tordis field, where subsea separation and water injection is used. This experience transfer is expected to significantly increase the final recovery factors in some of the most challenging reservoirs in deep waters that we are working on, for example in the Gulf of Mexico.
- Gas value chains - Statoil has long and valuable experience in gas value chains and has demonstrated its capabilities in the monetisation of significant, often remote, gas resources. This experience will be a valuable contribution to future projects, such as Shah Deniz II and the large Marcellus shale gas accumulation.
- Harsh environments - Statoil has the ability to deliver cutting edge field developments in harsh conditions under the strictest environmental regulations. With our long experience of development and operations off the coast of Norway, we have a competitive advantage to build on. The Sn øhvit field in the Barents Sea is a project that brings natural gas to land for liquefaction and export. The onshore plant is the first of its kind in Europe and the world's northernmost liquefied natural gas facility.
- Heavy oil - We are well positioned through operatorships and ownership interests in several key heavy oil projects. In the Peregrino field off the coast of Brazil and the Bressay and Mariner fields off the coast of the UK, we will utilise our experience from fields such as Grane in the North Sea. For our large, long-term resource base in Canadian oil sands, we will draw on experiences from our involvement in the subsurface aspects of the Venezuelan Petrocede ño project. The development will benefit from technological advances deriving from research and development work at the Statoil heavy oil technology centre in Canada. The research centre is among other tasks working on improving energy efficiency, reducing emissions, and thus also reducing operating costs related to the production of heavy oil.
These focus areas all draw on the strong technical and project execution skills we have acquired through our experience on the Norwegian continental shelf. We access resources by establishing new growth platforms with the potential of becoming new focus areas; through advanced exploration activities and high-grading of exploration prospects, focused business development and long-term partnerships with national energy companies.
Iraq is our latest new platform and we have succeeded in establishing a foothold in competition with other companies. It is one of the countries in the world with the highest remaining hydrocarbon production potential, and it has been closed for foreign investment for more than 30 years. Statoil has entered into a partnership with Lukoil, one of the largest onshore operators in the world.
Our international access strategy has increased the scale of our operations in terms of produced volumes, reserves and technological and geographical breadth. We aim to build a robust, diverse and long-life portfolio which can increase our opportunities in the future.
2.6.3 International E&P key events in 2009
International E&P's average daily production exceeded 500,000 boe in 2009.
- Equity production increased by 10% from 2008, to 512 mboe/day.
- Production from three new fields started during the year.
- High exploration activity: six of the 29 exploration wells drilled in 2009 have been announced as discoveries, with several interesting discoveries in the US Gulf of Mexico (GoM), Canada and Angola. Nine wells were under evaluation at year end 2009.
- On 12 December, Statoil and Lukoil entered a winning bid for the West Qurna 2 field in the second licensing round in Iraq. Statoil's equity share will be 18.75%.
- The Ceasar Tonga project in GoM was sanctioned by the partnership.
- Production from three new fields added a total capacity of approximately 50 mboe per day (Statoil equity):
- Tahiti in GoM
- Thunder Hawk in GoM
- Gimboa test production in Angola
- Offshore installation of the first wellhead platform on the Statoil-operated Peregrino field in Brazil started in late 2009.
2.7 Natural Gas
2.7.1 Introduction to Natural Gas
The Natural Gas business area is responsible for Statoil's transportation, processing and marketing of pipeline gas and LNG 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 the technical operations 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, Singapore, Azerbaijan and the USA (Houston and Stamford).
In 2009, 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 79.5 bcm (2.81 tcf) in 2009. That makes us the second largest gas supplier to Europe, with a market share of around 15% of the European gas market.
From our international positions, mainly Azerbaijan and the USA, we sold 5.3 bcm (0.19 tcf) of gas in 2009, 3.2 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 7800 kilometres. This network links gas fields on the NCS with processing plants on the Norwegian mainland, as well as terminals at six landing points located in France, Germany, Belgium and the United Kingdom, providing us with flexible access to customers throughout Europe.
*This system is owned by Gassled where Statoil has a 32.1% ownership.
2.7.2 Natural Gas strategy
NG's strategy is to maximise the value of our long-term sales business, increase value creation through portfolio optimisation and trading activities, and to establish new gas value chains.
NG's main task is to maximise value creation in markets that are constantly changing and deregulating, the European market in particular, by making active use of the new opportunities offered and managing risk within acceptable parameters.
We have a large European long-term gas sales contract portfolio and continuously evaluate midstream and downstream opportunities in order to take further advantage of our existing infrastructure, access to supplies, and natural gas marketing experience. Our downstream strategies may differ from region to region depending on our particular position in the area and the nature of the market in question.
In Europe, we are endeavouring to achieve greater efficiency in our existing supply portfolio, update and refine our commercial relations with key customers, and establish new positions that will improve delivery flexibility in our operations. Through balancing, optimisation from field to customer, trading activities, and sales directly to large industrial customers, we will continue to create additional value on top of our long-term sales business.
Natural gas is the focus of many exploration and business development activities carried out by both INT and EPN. A large proportion of the exploration activities on the NCS are focused on gas, and a number of INT projects focus on accessing international gas reserves.
We aim to further develop our position on the NCS and internationally through increased production and investment in existing and new fields and infrastructure aimed at serving the European and US gas markets. A necessary lever in support of this strategy is the continued development, maintenance and operation of the upstream and midstream (transport and processing) infrastructure required to safely and reliably deliver gas volumes where and when required. Efforts aimed at ensuring the safety, integrity and regularity of the infrastructure, while simultaneously upgrading and expanding the existing processing plants at Kårstø and Kollsnes, are of key importance in Norway.
The acquisition of a 32.5% interest in Chesapeake Energy's Marcellus shale gas acreage in the Appalachian basin in November 2008 will significantly strengthen our US natural gas business in terms of production, reserves and marketing (For more information, see Exploration & Production International). We will further develop our market position at the Cove Point LNG terminal on the East Coast of the USA. New midstream positions will be established in the USA in order to maximise value creation from this INT position in Marcellus. NG also plans to strengthen established market positions in Europe with gas from the NCS, the Caspian Sea and North Africa.
The main objective of NG's strategy is to utilise growth opportunities in all parts of the natural gas business and fully exploit the opportunities that changing market conditions provide. This means an increased focus on extracting value from the existing contracts and asset portfolio and on increasing the value added from trading and optimisation activities beyond the landing point. It also entails increased internationalisation of the gas business, including activities in North America, the Caspian region, LNG growth and the addition of new markets.
2.7.3 Natural Gas key events in 2009
Natural Gas delivered record operating income under challenging market conditions
- Strong Marketing & Trading results. NG delivered a record high trading result in 2009 due to our downstream positions and our ability to capitalise on price volatility. In addition we concluded approximately 8 bcm of new sales for the period 2009-2012.
- We maintained the value of our contract portfolio and were able to take advantage of volatile prices.
- Aldbrough gas storage in the UK. The facility began partial commercial operations in two caverns on 9 June 2009 .
- Naturkraft gas power plant at Kårstø. Naturkraft commenced commercial operation on 26 February 2009.
2.8 Manufacturing and Marketing
2.8.1 Introduction to Manufacturing & Marketing
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 combined operations in the transportation of oil, processing, sale of crude oil and refined products, retail activities and marketing of natural gas in Scandinavia. We operate in 13 countries, run two refineries, one methanol plant and three crude oil terminals. Our international trading activities make Statoil one of the world's largest crude oil traders. Over one million customers visit our 2000 service stations daily, and we operate an international lubricants and aviation fuel business.
Approximately 13,000 people from 30 nations work for M&M, around 10,000 outside Norway. In 2009, we traded 721 mmbbl of crude oil and condensate, approximately 25 million tonnes of refined oil products and 11.7 million tonnes of natural gas liquids (NGL). The refinery throughput was 15.0 million tonnes. Tjelbergodden produced approximately 10% of the European market's demand for methanol. In the energy and retail market, we sold approximately 12 billion litres in 2009, including 8 billion litres of petrol and diesel. Aviation fuelled over 70 airports worldwide and lubricant was distributed to 40 countries.
2.8.2 Manufacturing & Marketing strategy
M&M creates efficient, integrated oil value chains with competitive midstream and downstream positions.
M&M's main task is to maximise the value of Statoil's upstream production of crude oil and natural gas liquids (NGL) through professional refining and marketing. For this purpose, M&M has established efficient, integrated value chains with competitive midstream and downstream assets.
M&M's goal of safe, reliable and cost-efficient operations is the basis for further development of our market position. We will continue to pursue improvement opportunities and conduct necessary restructuring of our activities.
We will ensure high value creation based on Statoil's legacy assets on the Norwegian continental shelf, and a strong market position in North West Europe will continue to be a high priority.
Based on growing international upstream production, M&M will further develop regional trading hubs, with special emphasis on heavy oil activities. Statoil's heavy oil production in Canada and Brazil and our terminal asset on the Bahamas are important stepping stones.
M&M will continue to develop business-critical expertise and establish best practise in our work processes. We have developed a framework for deploying expertise throughout the organisation, with special emphasis on value chain expertise.
Oil sales, trading and supply (OTS)
OTS will continue to strengthen our global trading position, with an increased presence and activity in strategic regions such as the Americas and Asia, while maintaining our established market position in North West Europe. We will continue to develop business and infrastructure to secure market access and competitive pricing for our volumes worldwide. Trading infrastructure and sound logistical solutions give our business a competitive edge.
The acquisition of the South Riding Point Terminal in the Bahamas in 2009 will enable us to develop our trading around both equity and third party volumes sourced globally. OTS will continue to market Statoil's increasingly global upstream production both in conventional grades but even more importantly in extra heavy oils.
Manufacturing
Manufacturing's ambition is to contribute to maximising the value of Statoil's feedstocks from field to end user and to be an active downstream partner in the internationalisation of Statoil.
Manufacturing is preparing for the challenging market outlook that the European refining industry is facing. We are seeking to improve Mongstad and Kalundborg's competitive position by improving product yields, reliability and energy efficiency and by reducing costs while maintaining HSE performance.
Our ambition is to strengthen the value chain between our manufacturing and trading units and add value through more proactive integration of the operation of the Mongstad and Kalundborg refineries. This creates synergies through crude feedstock optimisation, greater flexibility and exchange of products between the refineries.
Energy and retail
Transportation fuel is the core of our energy and retail business (E&R), delivering 60% of gross income. Scandinavia and the Baltic region including Poland are the key geographical areas. In these markets, E&R is number one or two in terms of market share, with the exception of Poland where we are among the top five. In addition, we have a few stations in Murmansk and St Petersburg. Our engagement in the sale of heating oils and other stationary energy products is being reduced.
Our ambition is to improve profitability from our leading position in Scandinavia and to grow further on the eastern axis, building on our strong Baltic and Polish positions. We continually evaluate market opportunities based on the Scandinavian marketing concept. Acquisitions have recently been made in the automat sector and our ambition is to develop this market sector in parallel with our full-service offering. An important building block in realising this ambition is to be the environmental leader in our markets, with a first mover position in biofuels.
Statoil's Board of Directors has approved a proposal to create a stand-alone Energy & Retail business through an initial public offering (IPO) on the Oslo Stock Exchange. The IPO will take place at the earliest in the fourth quarter of 2010 or at a time when the capital market is deemed favourable for such an offering. Statoil intends to remain a majority shareholder of Energy & Retail at the time of the initial public offering and listing. The size and time horizon of Statoil's future ownership in Energy & Retail will be tailored to support and develop company value both for Energy & Retail and for the Statoil Group. The introduction of the new ownership structure is not expected to have a significant impact on the financial statements.
2.8.3 Manufacturing & Marketing key events 2009
Significantly lower margins in 2009 were challenging for the refining industry. The South Riding Point oil terminal lease boosted our international trading activities, while the JET business was successfully integrated into Scandinavian Energy and Retail.
- A challenging refining market, with a drop of from USD 8.3 to USD 4.3 per barrel in FCC refining margins.
- Impairment write-down of refineries reflecting the refining margin outlook.
- The combined heat and power (CHP) plant at Mongstad produced its first power for delivery to the grid in October 2009, with commissioning planned to continue into 2010.
- The sale or closure of all Hydro-branded stations in Sweden was completed in 2009. Closure of more than 400 stations.
- Restructuring and portfolio optimisation in stationary energy:
- Sold, or agreed to sell our downstream interests in gas companies located in Norway, Denmark and Sweden.
- The heating pellets, bottled gas and electricity businesses in Scandinavia sold.
- The international lubricants production will be centralised to Sweden, and the plant at Fagerstrand in Norway will be closed.
- Statoil's board of directors decided in March 2010 to change the ownership structure for the energy & retail business through a partial listing on the Oslo Stock Exchange.
- Acquisitions:
- The long-term lease of the South Riding Point oil terminal in the Bahamas acquired in October 2009.
- Our energy and retail business completed the integration of the JET stations in Scandinavia during 2009.
2.9 Technology and New Energy
2.9.1 Introduction to Technology & New Energy
Technology & New Energy is responsible for the development of technology and renewable energy, thereby contributing to solutions that cross 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 the piloting of new technology.
Climate change, supply security and a growing demand for clean energy are opening up new business opportunities for Statoil, particularly in Carbon Capture and Storage (CCS) and offshore wind. 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 business efforts in renewable energy. The activities are grouped under renewable energy production, new options and carbon dioxide management.
2.9.2 Technology & New Energy strategy
Statoil's technology strategy focuses on generating value by identifying, developing and applying technologies for securing maximum value from the Norwegian continental shelf (NCS), as well as establishing a position within renewables.
Technology strategy
Statoil's strategy is to maximise value as an international technology-based energy company. The objectives of the corporate technology strategy are to: (i) identify those technologies that will help the company to develop as a profitable, performance-driven, internationally competitive organisation; and (ii) guide the company's future growth in certain areas that can lead to substantial technology differentiation.
The strategy is focused on generating long-term business value through leading technology application. Its realisation will require the combined efforts of our technical staff to increase the value of existing business, secure and develop platforms for further growth and operate in new and more challenging environments. The strategy is upstream-motivated, although some weight is placed on energy diversification. Operational excellence and an HSE performance that is at the forefront in the industry underpin all our activities.
The corporate technology strategy is driven by the central business challenges and aims to build even stronger industry positions. Technology is a key enabler in relation to achieving this, and it will make significant contributions to field development in frontier deep waters (for example the Gulf of Mexico and Brazil), heavy oil production (for example Canadian oil sands, Venezuela and Peregrino in Brazil), and in arctic and sub-arctic regions with the focus on minimising risk to the environment and using our experience of operating in harsh weather conditions. Our ambition is to achieve distinctiveness and industry leadership in selected technologies and to stay competitive in a broad range of core and emerging technologies along the energy provision value chain, such as offshore wind and marine biofuel.
Efforts to standardise technology, secure fast track resource maturation and cost-efficient development solutions for mature resource areas contribute to the continued development of breakthrough and enabling technologies for frontier areas.
Furthermore, improved oil recovery (IOR) and improved drilling and well solutions are important in order to successfully grow our business. Statoil has achieved some of the petroleum industry's highest recovery factors on the NCS by combining scientific and engineering capabilities and introducing new technology. We intend to further advance the most important technologies to meet forthcoming IOR ambitions on the NCS and internationally. Drilling and well technology plays a key role in increasing production and ensuring regular delivery, and through its application we intend to achieve faster operations, reduced downtime and improved well flow, while improving safety during operations.
Technology development and deployment are carried out in close cooperation with national and international universities, research institutes, vendors and contractors. The split between external and internal research and development spending is around 50/50.
New Energy
Statoil's strategy for New Energy and carbon management is to utilise our core capabilities and current business positions to build a business with substantial value creation in the short and longer term. We will emphasise technologies where we can add value as a result of our offshore oil and gas expertise and experience. The main focus areas are offshore wind and carbon management. However, with the new energy industry still in an early phase of development, it is too early to "pick all the winners" of the future, so we are considering additional options in selected areas, such as second generation marine biofuels, geothermal, solar, hydrogen and other offshore renewables like wave and tidal energy. We also believe that our involvement has the potential to add value to certain oil and gas activities in the company, particularly in carbon management.
2.9.3 Technology & New Energy key events in 2009
This is an overview of key events related to TNE in 2009.
Technology
- The world's deepest hot tap operations on a pressurised pipeline were carried out on the Ormen Lange field in the Norwegian Sea during early August.
- New drilling and well technology developed by Statoil and FMC Technologies has been successfully tested on the Åsgard field in the Norwegian Sea. The new technology, called "Through tubing rotary drilling" (TTRD), enables old wells to be reused in a much simpler and more inexpensive way than previously.
- Statoil has introduced light well intervention (LWI) vessels on a large scale, with two such ships in operation all year round on the NCS. Compared with the use of traditional drilling rigs, these units cut the cost of well intervention work.
- Science education for the younger generation is part of Statoil's Academia programme. This June, a pilot - Newton energy room - financed by Statoil opened in Trondheim.
- Steerable line drilling pilot was a success. It will improve ability to drill in depleted reservoirs and unstable formations.
New Energy
- Statoil and Statkraft have decided to develop the 315MW Sheringham Shoal Offshore Wind Farm in the UK, providing energy to 220,000 British homes.
- Hywind, the world's first full-scale floating offshore wind turbine, started operation in autumn 2009 - enabling testing of the next generation of offshore wind technology.
- Construction of the European CO2 Technology Centre Mongstad (TCM) started in June 2009.
2.10 Projects & Procurement
2.10.1 Introduction to Projects & Procurement
Projects & Procurement is responsible for planning and executing all major development and modification projects, as well as for project and operational procurements within Statoil, including securing rig capacity based on the corporate rig strategy.
Our goal is to be world-class in terms of project execution and to deliver on time and within budget, in accordance with high HSE standards and agreed quality standards. To become a truly global energy player, it is essential that Statoil is able to execute projects at the very highest level, and thereby strengthen the company's international competitiveness.
Our current portfolio consists of more than 120 modification and development projects in the execution phase, with an expected total investment cost of more than NOK 200 billion. A large part of the portfolio consists of activities related to ongoing redevelopment efforts aimed at maximising production from the NCS.
2.10.2 Projects & Procurement strategy
Our strategy is to develop high-quality, efficient projects, as planned, and in a safe and reliable manner.
The ability to utilise the company's world-leading technology, execute projects in complex surroundings and demonstrate our core expertise in new markets is of vital importance in terms of opening up new business opportunities. The fight for global resources is fierce, but one Statoil is familiar with. The real challenge lies in local markets, local practices, new standards and new cultures. These unfamiliar settings affect price, availability, quality and lead times for deliveries.
We have great diversity in our project portfolio. On the NCS, many of our projects are related to redeveloping and upgrading existing fields and installations. These types of projects are often very complex, but the reward is a prolonged lifetime and increased recovery rates for our installations.
Moreover, a number of small satellite fields are being tied in to existing hubs. These projects are often part of the group's fast track programme, whose aim is to significantly shorten the time from discovery to production. Industrial standardisation is a key element in achieving this.
Internationally, our portfolio consists of fairly few, but large projects. Success relies on our ability to utilise our expertise and experience from the NCS. Our flagship is the Peregrino project off the coast of Brazil, Statoil's first operated mega project outside Norway. Furthermore, we are gaining valuable experience in Canada, where the Leismer demonstration project for heavy oil recovery is being developed.
Within renewable energy, the world first floating windmill was successfully completed in 2009 - the Hywind project. In addition to this, 88 windmills are being built off the east coast of England for the Sheringham Shoal project, thus gaining expertise in the execution of large projects in offshore wind.
A technology centre for carbon capture and storage is being built at Mongstad, the first step in developing a groundbreaking full-scale carbon capture plant.
We are dependent on the cooperation of a highly professional supply industry. We therefore seek to ensure a high degree of diversity among our suppliers, and are continuously on the lookout for innovative solutions and access to the best qualified expertise and external resources.
Securing sufficient flexibility in changing market conditions is a key focus area, and we expect our suppliers to adjust accordingly. Our activity level has remained high despite the world economic and financial situation having been very volatile in the past year. Although price reductions have been evident across most of our procurement segments, it is still a challenge to reduce market prices sufficiently to develop marginal fields. We therefore continue to seek cost optimisation, improvement in quality, productivity and efficiency in collaboration with our suppliers.
2.10.3 Projects key events in 2009
Key events in Projects & Procurement in 2009 include the successful start ups on Alve and Tyrihans, and completion of Hywind and the final platform at South Pars.
- The hull for the Gjøa semi platform has been transported from the Samsung yard in Korea to Stord. Mating of the hull and the platform topside was completed successfully on 27 December.
- Development of the Peregrino field off the coast of Brazil has proceeded according to plan. The substructure for the first drilling and wellhead platform was successfully installed on the seabed in November 2009, and the platform deck and modules were installed in January 2010.
- Production from the Yttergryta field on Haltenbanken started on 5 January 2009, only seven months after government approval of the PDO.
- Production from the Alve field started on 19 March.
- Production from the Tyrihans field started on 8 July.
- Production from the third and final platform on the South Pars phase 6-8 field started on 11 October.
- Major modifications of the Snøhvit LNG facilities were completed and production recommenced on 17 December.
- The world's first floating offshore windmill, Hywind, has been installed off the coast of Karmøy, Norway. Power production started on 21 September. Development of the Sheringham Shoal offshore wind park off the east coast of UK was sanctioned in March 2009. The wind farm, consisting of 88 windmills, is scheduled to start power production in 2011.
3 Operational review
Statoil's operational review is in accordance with the organisation of its operations, whereas certain disclosures about oil and gas reserves are based on geographical areas as required by the SEC.
Statoil prepares its operational review in accordance with its segment (business area) structure. Each business area is presented individually, and includes underlying business clusters according to how the business area organises its operations.
For further information on extractive activities, refer to sections 3.1 Operational review - E&P Norway and 3.2 Operational review - International E&P for descriptions of Exploration and Production Norway and International Exploration and Production, respectively.
Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures based upon geographical areas as required by the SEC. The geographical areas are defined by continent, and consist of Eurasia, Africa and the Americas. Relevant information is further split into Norway and Eurasia excluding Norway.
For further information on disclosures for oil and gas reserves and certain other supplemental disclosures based upon geographical areas as required by the SEC, refer to section 3.8 Operational review - Production volumes and price information and section 3.9 Operational review - Proved oil and gas reserves.
3.1 E&P Norway
3.1.1 The NCS portfolio
3.1.1.1 Core production areas
Statoil's NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.
We have organised our production operations into four business clusters - Operations West, Operations North Sea, Operations North and Partner Operated Fields. The Operations West and Operations North Sea clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea. Partner Operated Fields cover the whole NCS.
The fields in each area use common infrastructure, such as production installations and oil and gas transport facilities where possible. This reduces the investment required to develop new fields. Our efforts in these core areas will also focus on finding and developing smaller fields through the use of existing infrastructure and on increasing production by improving the recovery factor.
We are making active efforts to extend production from our existing fields through improved reservoir management and the application of new technology.
3.1.1.2 Potential producing areas
In addition to the producing areas, we operate a significant number of exploration licences. The exploration acreage is located both in undeveloped frontier areas and close to infrastructure and producing fields.
NCS
At the end of 2009, the total licensed acreage on the Norwegian continental shelf (NCS) covers an area of 130,142 square kilometres split between 413 licences - an increase of 27 licences from 2008. Statoil had interests in 219 licences covering an area of 59,107 square kilometres and was operator for 162 of the 219 licences. Compared with 2008, the total number of licences in which we have interests has increased by one.
North Sea
The total licensed acreage in the North Sea covers 63,591 square kilometres split between 240 licenses. We have interests in 22,507 square kilometres split between 113 licences, and we operate 86 of the 113 licences. Seven licences have been relinquished as a result of completion of committed work programmes for licences, prospectivity evaluation and portfolio high-grading. Furthermore, we have partly relinquished acreage in eight licences in order to minimise area fee costs. Three new licences were farmed into in 2009, and we were awarded three licences in the Awards in Predefined Areas 2008 (APA 2008). We became operator of one of them. In addition, we were awarded one licences extension as operator. One new licence and five licence extensions were awarded to us in the APA 2009. We became operator of the new licence and three of the licence extensions.
Norwegian Sea
The total licensed acreage in the Norwegian Sea covers 46,790 square kilometres split between 131 licences. We have interests in 23,794 square kilometres split between 79 licences, and we operate 54 of the 79 licences. In the deepwater region, we have interests in licences covering approximately 12,300 square kilometres. Three licences were relinquished in 2009 as a result of completion of committed work programmes, prospectivity evaluation and portfolio high-grading. Furthermore, we have partly relinquished acreage in four licences in order to minimise area fee costs. We were awarded one new licence in the APA 2008 where we became operator. In addition, we were awarded three licences extension and we are operator of two of these. We were awarded three licences in the 20th Round, and we became operator of two of them. One new licence and one licence extension were awarded to us in the APA 2009, and we became operator for both of those.
Barents Sea
The total licensed acreage in the Barents Sea covers 19,761 square kilometres split between 42 licences. We have interests in 12,806 square kilometres split between 27 licences, and we operate 22 of the 27 licences. Four licences were relinquished and eight licences partly relinquished in 2009 as a result of completion of committed work programmes, prospectivity evaluation and portfolio high-grading. We were awarded three licenses in the 20th Round, and we became operator of two of them. Statoil did not apply for acreage in the Barents Sea in the APA 2008 or the APA 2009 as we are well positioned in acreage in the Hammerfest Basin that we believe is more prospective than the acreage that was announced.
3.1.1.3 Portfolio management
The licence portfolio is continuously optimised, and our core areas and strategies will be strengthened and supported through active portfolio management.
A sales and purchase agreement was signed with Lundin Norway AS in 2009 for Statoil to farm in to three of its licences. Statoil acquired 30% of PL359 and 30% of PL410 in the Utsira High Area, as well as 10% of PL409 south of the Utsira High Area. Several interesting discoveries have recently been made in this area.
Furthermore, several transactions have been carried out involving the farming-in and farming-out of exploration licences.
3.1.2 Exploration on the NCS
Statoil has carried out an extensive exploration drilling campaign on the NCS in 2009 by completing 39 exploration wells; 30 wildcat wells to test new prospects and nine appraisal wells to establish the extent and size of previous discoveries.
By drilling the untested prospects we proved 22 new discoveries, resulting in a discovery rate of more than 70% for the 30 wildcat wells.
The presence of hydrocarbons was affirmed by all the nine appraisal wells, so the total result for exploration drilling in 2009 shows that 31 of the 39 exploration wells successfully proved or confirmed the presence of hydrocarbons. We operated 34 of the 39 exploration wells. In addition, we operated two exploration extensions that resulted in two new discoveries.
The most important discoveries in 2009 were Asterix, Gro, Katla and Beta West, all except Gro are Statoil-operated. In the Norwegian Sea, the Asterix (PL327) gas discovery, located approximately 80 kilometres west of Luva, is strategically important in relation to building the basis for a potential deepwater gas development in the Vøring Basin. The Gro (PL326) gas discovery located approximately 50 kilometres south-west of Asterix is promising, but needs further evaluation and appraising before concluding on the resource potential. In the North Seas, the Katla (PL104) oil/gas discovery opens the prolific Oseberg Area to the south, and, in the Sleipner Area, the Beta West (PL046) gas/condensate discovery broadens this area's exploration potential already proven by the Dagny/Ermitrude finds.
The table below shows our exploration and development wells drilled on the NCS during the last three years.
|
2009 |
2008 |
2007 |
North Sea |
|
|
|
Statoil operated exploratory |
23 |
13 |
11 |
Successful |
18 |
8 |
9 |
Dry |
5 |
5 |
2 |
Statoil operated development |
72 |
75 |
87 |
|
|
|
|
Partner operated exploratory |
1 |
4 |
0 |
Successful |
1 |
2 |
0 |
Dry |
0 |
2 |
0 |
Partner operated development |
17 |
13 |
16 |
|
|
|
|
Norwegian Sea |
|
|
|
Statoil operated exploratory |
10 |
14 |
6 |
Successful |
8 |
11 |
3 |
Dry |
2 |
3 |
3 |
Statoil operated development |
19 |
13 |
12 |
|
|
|
|
Partner operated exploratory |
4 |
1 |
3 |
Successful |
3 |
1 |
1 |
Dry |
1 |
0 |
2 |
Partner operated development |
1 |
3 |
2 |
|
|
|
|
Barents Sea |
|
|
|
Statoil operated exploratory |
1 |
7 |
3 |
Successful |
1 |
5 |
2 |
Dry |
0 |
2 |
1 |
Statoil operated development |
0 |
0 |
0 |
|
|
|
|
Partner operated exploratory |
0 |
0 |
1 |
Successful |
0 |
0 |
1 |
Dry |
0 |
0 |
0 |
Partner operated development |
0 |
0 |
0 |
Totals |
|
|
|
Exploratory |
39 |
39 |
24 |
Successful |
31 |
27 |
16 |
Dry |
8 |
12 |
8 |
Development |
109 |
104 |
117 |
|
|
|
|
3.1.3 Oil and gas reserves on the NCS
At the end of 2009, we had a total of 1,351 mmbbl of proved oil reserves and 480 bcm (16.9 tcf) of proved natural gas reserves on the NCS.
Measured in barrels of oil equivalents (boe), our NCS proved reserves consist of 31% oil and 69% natural gas, based on total NCS proved reserves of 4,369 mmboe.
One project on the NCS, the Goliat field in the Barents Sea, was sanctioned in 2009 and contributed positively to the reserves balance. In addition, approval of future development plans for several of our producing fields contributed positively. Future extension of the license period is now assumed reasonably certain on the NCS, increasing the proved reserves for certain fields.
The share of developed reserves at year end is 3,548 mmboe, which is 81% of the proved reserves. Of the 2009 proved developed reserves, 1,028 mmboe are oil and 401 bcm (14.1 tcf) are natural gas.
The following table shows our total NCS proved reserves as of 31 December for each of the last three years. Further information on reserves can be found in section 3.9 Operational review - Proved oil and gas reserves and in note 35 - Supplementary oil and gas information - to our Consolidated Financial Statements, which also explains revisions to the methodology for reserve etsimation for 2009 compared with earlier years.
|
Oil/NGL |
Natural gas |
Total |
||
Year |
|
mmbbls |
bcm |
bcf |
mmboe |
2009 |
Proved reserves end of year |
1,351 |
480 |
16,938 |
4,369 |
|
of which, proved developed reserves |
1,028 |
401 |
14,138 |
3,548 |
2008 |
Proved reserves end of year |
1,396 |
498 |
17,581 |
4,529 |
|
of which, proved developed reserves |
1,113 |
410 |
14,482 |
3,693 |
2007 |
Proved reserves end of year |
1,604 |
535 |
18,893 |
4,971 |
|
of which, proved developed reserves |
1,187 |
427 |
15,084 |
3,875 |
3.1.4 Production on the NCS
In 2009, our total entitlement oil and NGL production in Norway was 286 mmbbl, and gas production was 38.7 bcm (1,366 bcf), which represents an aggregate of 1.450 mmboe per day.
The following table shows the NCS production fields and field areas in which we are currently participating. Field areas are groups of fields operated as a single entity.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Producing wells |
|
|
Business cluster |
Georgraphical area |
Statoils equity interest in %(1) |
Operator |
On stream |
License expiry date |
|
Oil |
Gas |
Average daily production in 2009 mboe/day |
Operations North Sea |
|
|
|
|
|
|
|
|
|
Sleipner Øst |
The North Sea |
59.60 |
Statoil |
1993 |
2028 |
|
|
10 |
24.2 |
Sleipner Vest |
The North Sea |
58.35 |
Statoil |
1996 |
2028 |
|
|
18 |
95.2 |
Gungne |
The North Sea |
62.00 |
Statoil |
1996 |
2028 |
|
|
4 |
15.0 |
Troll Phase 1 (Gas) |
The North Sea |
30.58 |
Statoil |
1996 |
2030 |
|
|
39 |
131.2 |
Troll Phase 2 (Oil) |
The North Sea |
30.58 |
Statoil |
1995 |
2030 |
(2) |
113 |
|
41.8 |
Fram |
The North Sea |
45.00 |
Statoil |
2003 |
2024 |
|
9 |
|
30.2 |
Kvitebjørn |
The North Sea |
58.55 |
Statoil |
2004 |
2031 |
|
|
10 |
83.3 |
Visund |
The North Sea |
53.20 |
Statoil |
1999 |
2023 |
|
6 |
1 |
26.8 |
Grane |
The North Sea |
36.66 |
Statoil |
2003 |
2030 |
(3) |
25 |
0 |
62.2 |
Veslefrikk |
The North Sea |
18.00 |
Statoil |
1989 |
2015 |
|
18 |
0 |
2.2 |
Huldra |
The North Sea |
19.88 |
Statoil |
2001 |
2015 |
|
0 |
5 |
4.3 |
Glitne |
The North Sea |
58.90 |
Statoil |
2001 |
2013 |
|
6(4) |
0 |
3.8 |
Heimdal |
The North Sea |
29.87 |
Statoil |
1985 |
2021 |
(5) |
0 |
6 |
1.2 |
Brage |
The North Sea |
32.70 |
Statoil |
1993 |
2015 |
(6) |
22 |
0 |
10.9 |
Vale |
The North Sea |
28.85 |
Statoil |
2002 |
2021 |
|
|
1(7) |
1.8 |
Vilje |
The North Sea |
28.85 |
Statoil |
2008 |
2021 |
|
2 |
|
7.7 |
Volve |
The North Sea |
59.60 |
Statoil |
2008 |
2028 |
|
3 |
|
32.8 |
Total Operation North Sea |
|
|
|
|
|
|
204 |
94 |
574.4 |
|
|
|
|
|
|
|
|
|
|
Operations West |
|
|
|
|
|
|
|
|
|
Statfjord Unit |
The North Sea |
44.34 |
Statoil |
1979 |
2026 |
|
93(8) |
2 |
54.5 |
Statfjord Nord |
The North Sea |
21.88 |
Statoil |
1995 |
2026 |
|
7 |
|
1.1 |
Statfjord Øst |
The North Sea |
31.69 |
Statoil |
1994 |
2026 |
(9) |
7 |
|
3.4 |
Sygna |
The North Sea |
30.71 |
Statoil |
2000 |
2026 |
(10) |
3 |
|
0.7 |
Gullfaks |
The North Sea |
70.00 |
Statoil |
1986 |
2016 |
|
105 |
9 |
137.0 |
Snorre |
The North Sea |
33.32 |
Statoil |
1992 |
2015 |
(11) |
34 |
0 |
38.9 |
Tordis area |
The North Sea |
41.50 |
Statoil |
1994 |
2024 |
|
6 |
0 |
7.9 |
Vigdis area |
The North Sea |
41.50 |
Statoil |
1997 |
2024 |
|
10 |
0 |
21.1 |
Gimle |
The North Sea |
65.13 |
Statoil |
2006 |
|
|
2 |
|
3.9 |
Oseberg |
The North Sea |
49.30 |
Statoil |
1988 |
2031 |
|
59 |
|
105.8 |
Tune |
The North Sea |
50.00 |
Statoil |
2002 |
2032 |
|
|
4 |
10.5 |
Total Operations West |
|
|
|
|
|
|
326 |
15 |
384.8 |
|
|
|
|
|
|
|
|
|
|
Operations North |
|
|
|
|
|
|
|
|
|
Alve |
The Norwegian Sea |
85.00 |
Statoil |
2009 |
2029 |
|
1 |
|
21 |
Kristin |
The Norwegian Sea |
55.30 |
Statoil |
2005 |
2033 |
(12) |
12 |
0 |
64.9 |
Norne |
The Norwegian Sea |
39.10 |
Statoil |
1997 |
2026 |
|
12 |
0 |
16.6 |
Urd |
The Norwegian Sea |
63.95 |
Statoil |
2005 |
2026 |
|
5 |
0 |
4.1 |
Heidrun |
The Norwegian Sea |
12.41 |
Statoil |
1995 |
2024 |
|
34(13) |
0 |
11.8 |
Åsgard |
The Norwegian Sea |
34.57 |
Statoil |
1999 |
2027 |
|
0 |
39 |
128.9 |
Mikkel |
The Norwegian Sea |
43.97 |
Statoil |
2003 |
2022 |
(14) |
0 |
3 |
24.2 |
Njord |
The Norwegian Sea |
20.00 |
Statoil |
1997 |
2021 & 2023 |
(15) |
8(16) |
1 |
12.6 |
Tyrihans |
The Norwegian Sea |
58.84 |
Statoil |
2009 |
2029 |
|
3 |
0 |
20.4 |
Snøhvit |
The Barents Sea |
33.53 |
Statoil |
2007 |
2035 |
|
0 |
6 |
23.6 |
Yttergryta |
The Norwegian Sea |
45.75 |
Statoil |
2009 |
2027 |
|
0 |
1 |
4.5 |
Total Operations North |
|
|
|
|
|
|
75 |
50 |
332.5 |
|
|
|
|
|
|
|
|
|
|
Partner Operated Fields |
|
|
|
|
|
|
|
|
|
Ormen Lange |
The Norwegian Sea |
28.92 |
Shell |
2007 |
2041 |
|
|
10 |
112.0 |
Ekofisk area |
The North Sea |
7.60 |
ConocoPhillips |
1971 |
2028 |
|
150 |
0 |
24.2 |
Ringhorne Øst |
The North Sea |
14.82 |
ExxonMobil |
2006 |
2030 |
|
3 |
|
4.2 |
Sigyn |
The North Sea |
60.00 |
ExxonMobil |
2002 |
2018 |
|
1 |
2 |
14.2 |
Enoch |
The North Sea |
11.78 |
Talisman |
2007 |
2018 |
|
1 |
|
0.8 |
Skirne |
The North Sea |
10.00 |
Total |
2004 |
2025 |
|
|
2 |
2.6 |
Total Partner Operated Fields |
|
|
|
|
|
|
155 |
14 |
158.1 |
Total |
|
|
|
|
|
|
760.0 |
173.0 |
1,449.8 |
|
|
|
|
|
|
|
|
|
|
(1) Equity interest as of December 31, 2009. |
(8) 89 single completed wells, 4 multiple completed wells |
||||||||
(2) Troll Phase 2 (Oil) has 64 multi branched wells |
(9) PL037 expires in 2026 and PL089 expires in 2024 |
||||||||
(3) Grane has 9 multi branched wells |
(10) PL037 expires in 2026 and PL089 expires in 2024 |
||||||||
(4) Glitne 1 multi branched well |
(11) PL089 expires in 2024 and PL057 expires in 2015 |
||||||||
(5) PL036 expires in 2021 and PL102 expires in 2025. The owner |
(12) PL134B expires in 2027 and PL199 expires in 2033 |
||||||||
share of the topside facilities is 39,44%, however the owner share |
(13) 1 multi branched well |
||||||||
of the reservoir and production is 29,87%. |
(14) PL092 expires in 2020 and PL121 expires in 2022 |
||||||||
(6) PL185 expires in 2015 and PL053B and PL055 both expire in 2017 |
(15) PL107 expires in 2021 and PL132 expires in 2024 |
||||||||
(7) Vale 1 multi branched well |
(16) 1 multi branched well |
||||||||
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 2009, 2008 and 2007.
|
For the year ended December 31, |
||||||||
|
2009 |
2008 |
2007 |
||||||
|
Oil and NGL |
Natural gas |
|
Oil and NGL |
Natural gas |
|
Oil and NGL |
Natural gas |
|
Area production |
mbbl |
mmcm |
mboe |
mbbl |
mmcm |
mboe |
mbbl |
mmcm |
mboe |
Operations North |
175 |
25 |
332 |
175 |
22 |
314 |
181 |
19 |
303 |
Operations North Sea |
269 |
49 |
574 |
250 |
49 |
558 |
236 |
56 |
590 |
Operations West |
297 |
14 |
385 |
355 |
19 |
477 |
362 |
16 |
464 |
Partner Operated Fields |
43 |
18 |
158 |
43 |
11 |
112 |
39 |
3 |
60 |
Total |
784 |
106 |
1450 |
824 |
101 |
1461 |
818 |
95 |
1417 |
3.1.5 Development on the NCS
3.1.5.1 Fields under development on the NCS
The following fields are currently under development on the Norwegian continental shelf:
Gjøa is located in the North Sea and will be developed by installing a subsea production system and a semi-submersible production platform. Gas will be exported via the FLAGS pipeline to St Fergus and oil exported via the Troll 2 pipeline to the Statoil-operated Mongstad refinery near Bergen. The Gjøa platform will process and export volumes from both the Gjøa field and the neighbouring Vega fields. The platform will be supplied with land-based electricity from Mongstad. The investments are estimated to total NOK 33.3 billion. We hold a 20% interest in Gjøa. Production is scheduled to start in late 2010. GDF Suez will be the operator from production start.
The Gudrun Field is located in the North Sea. The field will be developed with a separate steel jacket based process platform for separation of oil and gas. Gas and partly stabilised oil will be transported in separate pipelines from Gudrun to Sleipner. Gas will be further transported through the Gassled system, while oil will be transported together with Sleipner condensate through pipeline to the Gassco operated Kårstø plant near Hugesund. The Plan for Development and operation was submitted to the Norwegian authorities in February 2010. Production is estimated to start in 1st quarter of 2014. The total investments are estimated to be NOK 20,3 billion. Statoil holds a 46,8% interest in Gudrun.
Morvin, in which we hold an interest of 64%, is an oil and gas field located in the Norwegian Sea, 15 kilometres north-west of Åsgard. The field was discovered in 2001, and the Plan for Development and Operation was submitted in February 2008 and approved by the Norwegian authorities in April 2008. The field will be a subsea development with two templates tied in to Åsgard B for processing through a 20-kilometre-long wellstream pipeline. The development of Morvin is currently estimated to require capital expenditure of NOK 8.4 billion, and production from the field is estimated to commence in late 2010.
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 an FPSO vessel and five subsea installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. Production is expected to start in August 2011, and the total development cost is estimated by the operator, BP, to be NOK 37.9 billion.
The PDO for Goliat was submitted in February 2009 and approved by the Norwegian parliament in June 2009. 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 the fourth quarter 2013. The operator's estimate of development costs for the field is NOK 28 billion.
The Vega/Vega South project comprises the development of three separate gas-condensate accumulations: Vega North and Vega Central in PL248 and Vega South in PL090C. Our ownership interests in the licences are 60% and 45%, respectively. The fields are located in the North Sea. Three four-slot templates will be installed, and production will be transported to the Gjøa installation in a common pipeline. The total investments for the project are estimated to be NOK 7.5 billion. Production is scheduled to start in late 2010.
The table below shows some key figures for our major development projects.
|
|
Estimates of |
|||
Project |
Statoil's share |
Statoil's investment (1) |
Production start |
Plateau production, Statoil's share (3) |
Lifetime in years |
Gjøa |
20.000 % |
6.7 |
2010 |
19,000 |
15 |
Goliat (2) |
35.000 % |
9.8 |
2013 |
30,000 |
18 |
Gudrun |
46.800 % |
9.5 |
2014 |
40,000 |
12 |
Morvin |
64.000 % |
5.4 |
2010 |
20,000 |
14 |
Skarv (2) |
36.165 % |
13.7 |
2011 |
53,000 |
12 |
Vega/Vega Sør |
60% / 45% |
4.1 |
2010 |
30,000 |
13 |
|
|
|
|
|
|
(1) Estimated in NOK billion |
|
|
|
|
|
(2) Partner operated project |
|
|
|
|
|
(3) Boe/day |
|
|
|
|
|
3.1.5.2 Redevelopments on the NCS
The following projects are being developed on the NCS to give existing installations an extended life or to exploit new opportunities.
Oseberg Low Pressure involves the installation of two new production manifolds for low-pressure wells with tie-in to second stage separators. Production started in February 2010.
The Snorre Redevelopment project, which is defined as an IOR project, will contribute to achieving the Snorre Unit and Vigdis overall oil recovery ambition. The project includes a water injection pipeline from Statfjord C to the Vigdis field.
The Statfjord Late Life project will convert Statfjord into a mainly gas-producing field by changing the drainage strategy. The export of gas to the UK through a new pipeline connected to the existing pipelines to Flags and St Fergus commenced in late 2007. Total investments in the project are estimated to amount to NOK 21.4 billion.
Troll Field projects include the Troll B Gas Injection Project and the Troll A P12 Pipeline Project. The main goals for these projects are IOR from Troll B and to enable 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. The pipeline is planned to start 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 production is planned to start in 2010.
A new low-pressure compressor module will be installed on Troll C to increase capacity, and thereby production and recovery from Troll West. Production is planned to start 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 and production is planned to start in 2010.
3.1.6 Fields in production on the NCS
3.1.6.1 Operations North Sea
Operations North Sea includes a large part of Statoil's production activity on the NCS. There is focus on increasing and prolonging production in the area, with priority given to Improved Oil Recovery and the exploration and the development of new fields.
Our producing fields in Operations North Sea are Troll, Fram, Sleipner, Kvitebjørn, Visund, Grane, Brage, Veslefrikk, Huldra, Glitne, Volve, Heimdal, Vilje and Vale. The area is dominated by the production of natural gas, as 53% of the equity production in 2009 was gas. The petroleum reserves are located below water depths of between 80 and 330 metres.
In 2009, Statoil's share of the area's production was 269 mbbl of oil, condensate and NGL per day and 18 mmcm (627 mmcf) of gas per day, or 575 mboe in total per day.
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, and gas exports started in October 2007.
Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS to use a stand-alone production system.
Grane is the first field on the NCS to produce heavy crude oil, and 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 will produce the injected gas. Due to a new drilling strategy, the field managed to increase daily production by approx. 15% in 2009.
Heimdal is a gas field located in the northern part of the North Sea. Heimdal mainly operates as a processing centre for other fields. Huldra, Skirne and Vale deliver gas to Heimdal, and gas from Oseberg is also transported via Heimdal.
Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. Condensate from the Sleipner field is transported to the gas processing plant at Kårstø. The gas from Sleipner has a high level of carbon dioxide, which is extracted on the field and re-injected into a sand layer beneath the seabed to reduce carbon dioxide emissions to the air. We are currently exploring several prospects and discoveries in the Sleipner area that can potentially be tied in to Sleipner.
The Troll Area comprises Troll and Fram, and the Vega and Gjøa development projects. Troll is the largest gas field on the NCS and a major oilfield. The Troll Field Project submitted a new Plan for development, operation and installation in June 2008 for IOR in the area. The project is well under way.
Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. Huldra is located in the Viking Graben and developed by a (normally unmanned) platform, remotely controlled from the Veslefrikk field. Oil from Veslefrikk is exported through the Oseberg Transportation System, while gas is exported to Kårstø. Veslefrikk also processes condensate from Huldra.
The first oil flowed from the Vilje field to the Alvheim floating production, storage and offloading vessel (FPSO) on 1 August 2008. The Vilje field, which is linked to the Alvheim field, is located in the northern part of the North Sea, north of the Heimdal field.
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 to hold crude oil before export. Gas is piped to the Sleipner A platform for final processing and export.
The Kvitebjørn field resumed production on 27 January 2009 after being shut down since August 2008 due to a gas leak resulting from damage caused to the Kvitebjørn gas pipeline.
3.1.6.2 Operations West
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 2009 was 256 mbbl per day of oil, 41 mbbl per day of NGL and 87 mboe per day of gas, or 385 mboe per day in total. Operations West is the leading oil producing area on the NCS and, even after 20 years of production, we believe there are still substantial opportunities for increased value creation.
Statoil has taken several initiatives to identify and implement measures to increase and prolong production from the Operations West area. These initiatives involve a combination of cost reductions and IOR, and they have resulted in the prolongation of planned production beyond the current licence period for several of the fields.
In 2009, Operations West performed six turnarounds within the scheduled time frame and 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 Gullfaks A and C platforms.
The Gimle field is a Gullfaks satellite field that is operated as a separate unit. At the end of 2009, Gimle consisted of two producers and one injector, all drilled as long-reach wells from the Gullfaks C platform.
The Oseberg area includes the main Oseberg field, which has been developed with field centre installations, and the Oseberg C production platform, and two satellite fields, Oseberg East and Oseberg South, developed with production platforms. In addition, the Tune field and Oseberg West Flank have been developed with subsea installations and tied back to the Oseberg Field Centre. Oil and gas from the satellites is piped to the Oseberg Field Centre for processing and transportation. Oil is exported to shore through the Oseberg transportation system to the Sture terminal, and gas is exported through the Oseberg gas transportation system to Heimdal and on to market.
There was a fatal accident on the Oseberg B installation on 7 May 2009. A person died after falling about 14 metres from scaffolding onto the deck. A major safety programme for scaffodling activities has been launched after the accident.
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 tied back to Gullfaks C, where the oil and gas is 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 IOR project involving Increased Water Injection from Statfjord C is delayed due to the need for riser replacement, which is estimated to take place in 2010.
The Snorre field has been developed with two platforms and one subsea production system. Oil and gas is exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A.
An inspection revealed internal damage to three risers on Snorre B in autumn 2008, resulting in the shutdown of risers and reduced production. Two of three risers were replaced during autumn 2009. The third riser will be replaced in 2010.
Statfjord has been developed with three fully-integrated platforms supported by gravity base structures featuring concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Associated gas is piped through the Tampen link to the UK or, alternatively, to the Kårstø gas processing plant and then on to continental Europe. Three satellite fields (Statfjord 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 Ministry of Petroleum and Energy for the late-life production period for Statfjord. The ministry granted a licence extension for the Statfjord area from 2009 to 2026.
3.1.6.3 Operations North
Our producing fields in the Operations North area are Åsgard, Mikkel, Heidrun, Kristin, Norne, Urd, Njord and Snøhvit. The Yttergryta field started production in January 2009, the Alve field in March 2009 and the Tyrihans field in July 2009.
Our share of the area's production in 2009 was 175 mbbl per day of oil, condensate and NGL, and 25 mmcm per day of gas, or 333 mboe in total per day.
This region is characterised by petroleum reserves located at water depths between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult and have challenged the participants to develop new types of platforms and new technology, such as floating processing systems with subsea production templates. We plan to increase efficiency by further coordinating our operations in the area and by stemming the decline in production from the mature fields through increased seismic activity and well maintenance. In addition, we intend to expand our activities by utilising our installed production and transportation capacity before building new infrastructure.
The Heidrun platform is the largest concrete tension leg platform ever built. Most of the oil from Heidrun is shipped by shuttle tankers to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden in Norway. Additional gas volumes are exported through the Åsgard Transport System (ÅTS) to gas markets in continental Europe.
Kristin is a gas and condensate field in the south-western section of the Operations North area. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and 170 degrees Celsius, respectively - are higher than any other developed field on the NCS. The stabilised condensate is exported to a joint Åsgard and Kristin storage vessel, and the rich gas is transported to shore via the ÅTS to the gas processing facility at Kårstø.
Tyrihans started producing oil and gas in July 2009 and by the end of the year was producing from 3 wells. In addition gas is injected into a fourth injection well via Åsgard B. Tyrihans will be completed in 2010/2011 with another 7 wells. All production is processed on the 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 exports started late 2007 via ÅTS and Kårstø.
The Norne field has been developed with a production and storage ship tied to subsea templates. This ship carries processing facilities on its deck and storage tanks for oil. Processed crude oil can be transferred over the stern to shuttle tankers. Norne is connected to gas markets in continental Europe through a link with ÅTS.
The Urd fields, Svale and Stær, are located ten kilometres and five kilometres north of the Norne field, respectively. The fields are produced through subsea facilities with the well stream tied back to the Norne FPSO.
The Alve field, which consists of one producing well, was started up in March 2009. The field is produced through subsea facilities with the well stream tied back to the Norne FPSO.
Snøhvit is the first gas field developed in the Barents Sea. Twenty wells will produce natural gas from three gas reservoirs: Snøhvit, Askeladd and Albatross. By the end of 2009 Snøhvit was producing from 6 wells. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore.
The natural gas, which is transported to shore through a 143-kilometre-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 and there are still some uncertainties related to the timing of regular and stable operations. Performance and regularity improved significantly in 2008 and 2009. One major maintenance shutdown in 2009 has been carried out to achieve a further improvement in regularity.
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 53 wells grouped in 18 seabed templates. Furthermore, 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 Åsgard Transport System (ÅTS) to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the 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 transport to the Åsgard B gas processing platform.
Yttergryta started production from a single well in January 2009. The well stream is tied back to Åsgard B for processing.
3.1.6.4 Partner-operated fields on the NCS
Partner-operated fields represent a significant proportion of Statoil's oil and gas portfolio. 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 in which Statoil has a 28.92% interest. Statoil was operator for the development phase and Norske Shell became the operator for the production phase that began at the end of 2007. Statoil continues to execute approved, but not yet completed, parts of the subsea development. The selected development is an extensive subsea development at depths ranging from 850 to 1100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. Gas is then transported through a dry gas pipeline, Langeled, via Sleipner to Easington in the UK.
Ekofisk is the first developed field complex that came into operation on the Norwegian continental shelf. The operator is ConocoPhillips. It consists of the fields Ekofisk, Eldfisk and Embla (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 was 2/4-M, which was installed in 2005. Several new projects are being studied: a new Ekofisk living accomodation and field centre, a new Ekofisk South drilling platform and redevelopments of Eldfisk and Tor. Final decisions are expected to be made during the next few years. These new platforms are expected to extend the field life beyond the current licence period, which ends in 2028.
Sigyn, operated by ExxonMobil, is a gas and condensate field located 12 kilometres south-east of the Sleipner A installation in which we have a 60% interest. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. The development consists of three production 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 field Ringhorne East. The unitised field started production in March 2006. Three production wells have been drilled from the Ringhorne facility. Oil is transported via Ringhorne to Balder for offshore loading. Gas is exported via Jotun into Statpipe. A fourth production well is planned.
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.
3.1.7 Decommissioning on the NCS
There has been no decommissioning of Statoil-operated fields during the last three years.
The Norwegian government has laid down strict procedures for the removal and disposal of offshore oil and gas installations under the Convention for the Protection of the Marine Environment of the Northeast Atlantic, known as the OSPAR Convention. During the last three years, however, there has been no decommissioning of Statoil-operated fields. On partner-operated fields, there has been removal activity on Frigg and Ekofisk.
3.2 International E&P
3.2.1 Our international E&P portfolio
Statoil has built up a large international resource base in recent years. We are continuously optimising our portfolio, and our focus areas and strategies will be strengthened and supported through active portfolio management. .
Major additions to our international portfolio include entry into the Marcellus shale gas acreage in north-eastern USA in 2008 and the purchase of the Kai Kos Dehseh oil sands in Canada in 2007. In 2008, we also took on the operatorship and acquired the remaining 50% equity share of Peregrino, a heavy oil project in Brazil. Statoil's main M&A activities in 2009 and early 2010 are presented below.
Acquisitions:
On 14 April 2009, Statoil acquired a 40% stake in 50 blocks from BHP Billiton in the DeSoto Canyon area of the US Gulf of Mexico. This positions us in a frontier play in the central GoM.
On 18 May 2009, we reached agreement with BPC Limited to become the operator of three offshore exploration licences in the Bahamas, identified as a frontier play. Approval and awarding of the licences by the Government of the Commonwealth of the Bahamas is still pending.
On 12 August 2009, we entered a deal where we farmed into a 30% share of the Repsol-operated BM-ES-29 licence in the Espirito Santo basin in Brazil, further positioning us in the pre-salt play. Repsol received equity shares in four of our GoM leases in exchange. The deal is currently pending government approval.
Iraq is the latest new growth platform where we have succeeded in establishing a foothold in competition with other companies. In Iraq's second licensing round on 12 December 2009, Statoil and Lukoil submitted the winning bid for developing the West Qurna 2 field. On 31 January 2010 Statoil and Lukoil signed the development and production contract for West Qurna 2 with Iraqi authorities. The consortium of contractors consists of the state Iraq's North Oil Company (25%), Lukoil (56.25%) and Statoil (18.75%). Lukoil will be the operator.
On 25 January 2010, we entered a deal with ConocoPhillips through which we gained 25% interest in 50 leases in the Chukchi Sea in Alaska. By adding on these leases to the 16 previously acquired in Chukchi, we now have a sizable acreage portfolio to explore in the coming years.
In January 2010, we increased our share in St.Malo in the US GoM from 6.25% to 21.5% by exercising our pre-emption rights. The transaction was completed on 9 March 2010.
On 17 March 2010, Statoil was the highest bidder on 21 leases in the Central lease sale 213 in the US GoM. Statoil's winning bids are subject to review and final approval by the Mineral Management Service (MMS).
Divestments and other reduction of Statoil's portfolio:
We completed the sale of our interests in licences off the coast of Denmark to Bayerngas Norge AS on 24 June 2009.
On 30 June 2009, we completed the sale of our interest in the UK Caledonia field (21.32%) to Premier Oil ONS Limited.
On 29 October 2009, we signed a well participation agreement with CNOOC under which we successfully farmed down Statoil's interest in several exploration prospects in the Gulf of Mexico.
With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20% interest, thus reducing Statoil's share from 40% to 30%.
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.
3.2.2 International exploration activity
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), Latin America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria and Tanzania), Europe and the Caspian region (the Faroes, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia). Our exploration strategy remains focused on accessing more new quality acreage, including unconventional hydrocarbons and exploration resources that are demanding in terms of technology.
In 2009, we reduced our exploration spending and activity level to reflect the new market situation with lower oil and gas prices. We have completed 29 wells in 2009, and seven were ongoing at year end. Of the 29 wells, six were announced as discoveries and nine are currently under evaluation. We plan to drill about 30 wells in 2010.
In 2009, we reached an agreement with BPC Limited to become the operator of three offshore exploration licences: Zapata, Islamorada and Falcones in the Cay Sal area of the south-western Bahamas. Approval and the awarding of the licences by the Government of the Commonwealth of the Bahamas is still pending.
In the Faroes, we have decided to enter into the third exploration period in Licence 008, and have committed to drilling one well during the period 2010-2014. We also received an extension for licences 006, 009 and 011 with one commitment well to drill.
We have entered the next exploration period in our 3/94 licence in Ireland with a commitment to drill one well.
In 2009, we relinquished our sole licence in Morocco.
The areas where we entered or had significant activity in 2009 are presented below.
3.2.2.1 North America
3.2.2.1.1 Canada
Statoil is operator and partner in licences off the coast of Newfoundland, and we hold 1129 square kilometres (279,053 acres) of oil sands leases in Alberta. The Statoil-operated Mizzen well resulted in a discovery in 2009.
Offshore
We completed drilling and testing operations for the exploration Mizzen well in licence 1049 in the frontier Flemish Pass basin in March 2009. The well proved a hydrocarbon accumulation, and a Significant Discovery Licence was awarded in February 2010.. Statoil is the operator and holds a 65% interest in the licence.
Ballicatters, an exploration well operated by Suncor with a Statoil interest of 50%, was drilled in the Jeanne d'Arc basin on licence 1113 and 1092 from July to October 2009. For technical reasons, the well has been suspended. A plan for re-entry is currently being developed.
Evaluation work based on 3D seismic data on the two operated licences in the southern part of the Jeanne d'Arc basin has continued during the year in order to define drillable prospects. This work will continue in 2010, and plans for the drilling of identified prospects will be developed.
Oil sands
We currently have an interest in 1129 square kilometres (279,053 net acres) of oil sands' leases located in the Athabasca region of Alberta.
In order to determine the extent of the exploitable oil sands deposits in Alberta, a total of more then five hundred wells were drilled in the region from 2003 to 2009. In addition, extensive seismic surveys were acquired during that period.
In the 2008-2009 winter drilling programme, only wells required for delineation, observation and water source or disposal for near-term development phases were drilled.
Our oil sand activities are described in more detail in section 3.2.5.1.1 Operational review - International E&P - International fields in development and production - North America - Canada.
3.2.2.1.2 The USA
We have significant activities in the USA, with more than 400 leases in the Gulf of Mexico and 66 in Alaska. With two new rigs in the Gulf of Mexico, we embarked on an extensive drilling programme and were drilling two operated wells at the end of 2009.
US Gulf of Mexico
During 2009, we participated in ten exploration and appraisal wells, five of which were completed by year end. Heidelberg 1 and Vito 1 wells were announced as Miocene oil discoveries in 2009. A Vito appraisal well (sidetrack to Vito 1) was announced as a Miocene oil discovery in March 2010, and a second sidetrack appraisal well is planned for 2010 to further delineate the discovery.
In 2009, Statoil became the operator for an extensive drilling programme with two new rigs arriving in the Gulf of Mexico during the second half of the year. At year end, the Maersk Developer was drilling an appraisal well on the Tucker discovery in Walker Ridge and the Discoverer Americas was drilling an exploration well on the Krakatoa prospect in Mississippi Canyon. These two operations will continue in 2010, and we plan to drill additional deepwater wells during 2010.
In 2009, we acquired a 40% stake in 50 leases from BHP Billiton in the frontier DeSoto Canyon area of the US Gulf of Mexico. DeSoto Canyon is located east of Statoil's current production operation at Independence Hub. The area has water depths of about 1000 metres. We were awarded 23 leases in the Central Lease Sale 208, including 14 in the eastern GoM with partner BHP Billiton. Following a thorough technical evaluation, it was decided not to submit any bids for the Western Lease Sale 209.
Statoil was the highest bidder on 21 leases in the Central lease sale 213 in March 2010. Statoil's winning bids are subject to review and final approval by the Mineral Management Service (MMS).
To date, three multi-well participation agreements have been entered into with Ecopetrol (agreement concluded in 2008), Repsol and CNOOC, reducing our interests in a total of eight deepwater prospects .
Alaska
We entered an agreement with ConocoPhillips under which we acquired a 25% equity in 50 leases covering the Devil's Paw prospect in the Chukchi Sea.
With the selection of the seismic contractor in 2009, we have taken the first step towards 3D Seismic acquisition for Statoil's Chukchi Sea acreage, which is planned for 2010. Preparation of environmental and other permit applications is progressing and stakeholder engagement with North Slope communities has also commenced. In addition, Statoil has participated in the collection of environmental baseline data in the Chukchi Sea.
Gas shales
Exploration activity related to gas shale in onshore USA is presented in article 3.2.5 Operational review-International E&P-Fields in development and production.
3.2.2.2 Latin America
3.2.2.2.1 Brazil
We have interests in nine exploration licences in four different basins in waters off the coast of Brazil. We are the operator of four of the licences. During 2009, we acquired a 30% interest in the pre-salt licence BM-ES-29.
In 2009, we farmed into a 30% share of the Repsol-operated BM-ES-29 licence in the Espirito Santo basin with one commitment well to drill. The interests in three blocks that we won in the 8th round in the Santos basin are pending award.
We have completed two wells in BM-J-3 and one well in BM-C-33, which fulfilled our commitments for these licences. We have one commitment well in BM-CAL-10, one in BM-CAL-7 and one in BM-C-47.
3.2.2.3 Africa
3.2.2.3.1 Angola
Statoil holds interests in blocks 4/05, 15, 15/06, 17, 31 and 34 in Angola. Fourteen wells were completed in 2009, with three announced as discoveries.
We have extensive exploration activity in Angola, with a number of wells drilled in 2009 and expected to be drilled in 2010 and the coming years. We have interests varying from 5% to 50% in six blocks .
The Block 15 exploration licence, with ExxonMobil as operator, has expired. Areas with proven oil have been converted to Development Area (DA) and Provisional Development Areas (PDA). A total of 38 exploration and appraisal wells have been drilled on the original Block 15 and offspring DAs and PDAs.
In Block 17, which is operated by Total, a total of 34 exploration and appraisal wells have been drilled, with the last two completed in 2009.
In Block 31 operated by BP, six exploration wells were completed in 2009 with two discoveries announced. To date, a total of 31 exploration wells have been drilled in the block. Three wells have been completed in Block 15/06, with one discovery announced and one well ongoing at year end.
We have fulfilled our commitments in blocks 15 and 17 and have remaining commitments to fulfil in other blocks: one well in Block 4/05, two wells in Block 15/06, one well in Block 31 and one well in Block 34.
3.2.2.3.2 East Africa
Statoil is the operator of 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 1000 to 3000 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 1600-square-kilometre 3D survey has been acquired 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.
Area 2&5 (13,402 square kilometres), Mozambique: We are the operator, with a 90% interest in the licence, which consists of two blocks under one licence agreement, with the state oil company Empresa Nacional de Hidrocarbonetos (ENH) as partner. We are currently in the second exploration period during which there is a commitment to shoot 3D seismic. A 1300-square-kilometre 3D survey is currently being acquired.
3.2.2.3.3 Egypt
We are the operator, with an 80% interest, in two offshore exploration licences located in the Mediterranean, west of the Nile Delta, in water depths ranging from sea level to 3000 metres.
El Dabaa Offshore (Block 9) covers an area of 8368 square kilometres. We have fulfilled the 2D and 3D seismic commitments. We have a commitment to drill one well in this licence and planning related to the drilling of this well will be in focus during 2010.
Ras El Hekma Offshore (Block 10) covers an area of 9802 square kilometres. We have fulfilled our work commitment in this licence, which includes the acquisition of 2D and 3D seismic surveys. Initial processing was completed early in 2009, and further processing is ongoing.
3.2.2.4 Middle East and Asia
3.2.2.4.1 Indonesia
Statoil is operator of the Karama production sharing contract (PSC) with a 51% interest, and it has a 40% interest in the Kuma PSC. Both licences are located off Indonesia, in water depths ranging from 1000 to 2000 metres.
In 2009, all the acquired seismic data have been processed, and seismic interpretation and mapping of potential drilling locations have been initiated for both the Karama PSC and the Kuma PSC. We have entered into several shared drilling-related contracts together with the other five consortium companies that will use the contracted drillship, Global Santa Fe Explorer. We have three commitment wells in the Karama PSC, and one commitment well in the Kuma PSC. Drilling is planned to start in 2010/2011. Several studies have been initiated to support the definition of optimal drilling locations and in preparation for safe and efficient drilling operations.
3.2.3 International oil and gas reserves
At the end of 2009, the international business area had a total of 824 mmbbl of proved oil reserves and 34.3 bcm (1 210 bcf) of proved natural gas reserves.
Measured in barrels of oil equivalents (boe), our international proved reserves consist of 79 % oil and 21 % natural gas, based on total international proved reserves of 1 039 mmboe.
Several of our international fields contribute positively to the reserves balance in 2009:
- Kizomba satellites phase 1 in Angola and the Caesar Tonga Unit in Gulf of Mexico, USA, were sanctioned in 2009.
- The Gimboa field in Angola commenced test production in April 2009.
- The PSVM development in Angola was approved by the concessionaire in 2008 and as a result recorded proved reserves for the first time in 2009.
- The Marcellus Shale Gas play in USA, part of our gas value chain strategy, recorded proved reserves in 2009 for the first time.
- The Leismer Demonstration Project in the Kai Kos Dehseh leases in Canada, with initial production scheduled for late 2010, contributes to the reserves balance in 2009 with reference to several analogous SAGD projects in operation in the Athabascan area.
Effective from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20 % interest, thus reducing Statoil's share from 40 % to 30 % and having a negative effect on our reserves' balance.
The increase in the oil price during 2009 has had a negative effect on our proved reserves' estimates for international projects with a Production Sharing Agreement or a Buy Back Agreement.
The share of developed reserves at year end is 565 mmboe, up 5 % from 2008. Of the 2009 proved developed reserves, 413 mmboe are oil and 24.1 bcm (852 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 3.9 Operational review - Proved oil and gas reserves and in note 35 - Supplementary oil and gas information to our consolidated financial statements, which also explains revisions to the methodology for reserve estimation for 2009 compared with earlier years.
|
|
Oil/NGL |
Natural gas |
Total |
|
Year |
|
mmbbls |
bcm |
bcf |
mmboe |
2009 |
Proved reserves end of year |
824 |
34.3 |
1,210 |
1,039 |
|
of which, proved developed reserves |
413 |
24.1 |
852 |
565 |
2008 |
Proved reserves end of year |
805 |
39.7 |
1,403 |
1,055 |
|
of which, proved developed reserves |
406 |
20.6 |
727 |
536 |
2007 |
Proved reserves end of year |
785 |
40.4 |
1,426 |
1,039 |
|
of which, proved developed reserves |
323 |
21.2 |
748 |
456 |
3.2.4 International production
Statoil's petroleum production outside Norway in 2009 amounted to an average of 357 mboe per day of entitlement production and 512 mboe per day of equity production.
Our total annual entitlement production in 2009 was approximately 130 mmboe, compared with 106 mmboe in 2008. The first table shows our average daily entitlement production of liquids and natural gas for the years ending 31 December 2009, 2008 and 2007. In 2009 the fields Tahiti and Thunder Hawk in the USA came on stream and the Gimboa field in Angola started test production.
|
For the year ended 31 December |
||
Entitlement production |
2009 |
2008 |
2007 |
|
|
|
|
Oil and NGL (mboe per day) |
283 |
232 |
252 |
Natural gas (mmcm per day) |
12 |
9 |
9 |
Total (mboe per day) |
357 |
290 |
307 |
The next table provides information about the fields which contributed to 2009 production.
Field |
Statoil's equity interest in percent |
Operator |
On stream |
License expiry |
Productive wells as of year end |
North America |
|
|
|
|
|
Canada: Hibernia |
5.00% |
HMDC |
1997 |
2027 |
33 |
Canada: Terra Nova |
15.00% |
Suncor |
2002 |
2022 |
15 |
USA: Lorien |
30.00% |
Noble |
2006 |
HBP (1) |
2 |
USA: Front Runner |
25.00% |
Murphy Oil |
2004 |
HBP |
8 |
USA: Spiderman Gas |
18.33% |
Anadarko |
2007 |
HBP |
3 |
USA: Q Gas |
50.00% |
Statoil |
2007 |
HBP |
1 |
USA: San Jacinto Gas |
26.67% |
ENI |
2007 |
HBP |
2 |
USA: Zia |
35.00% |
Devon |
2003 |
HBP |
1 |
USA: Seventeen Hands |
25.00% |
ENI |
2006 |
HBP |
1 |
USA: Marcellus shale gas |
Varies |
Varies |
2008 |
HBP |
51 |
USA: Tahiti |
25.00% |
Chevron |
2009 |
HBP |
6 |
USA: Thunder Hawk |
25.00% |
Murphy Oil |
2009 |
HBP |
3 |
|
|
|
|
|
|
Latin America |
|
|
|
|
|
Venezuela: PetroCedeño (2) |
9.68% |
PetroCedeño |
2008 |
2032 |
404 |
|
|
|
|
|
|
Sub Saharan Africa |
|
|
|
|
|
Angola: Kizomba A |
13.33% |
ExxonMobil |
2004 |
2026 |
27 |
Angola: Kizomba B |
13.33% |
ExxonMobil |
2005 |
2027 |
24 |
Angola: Xikomba |
13.33% |
ExxonMobil |
2003 |
2027 |
5 |
Angola: Marimba North |
13.33% |
ExxonMobil |
2007 |
2027 |
3 |
Angola: Mondo |
13.33% |
ExxonMobil |
2008 |
2029 |
9 |
Angola: Saxi-Batuque |
13.33% |
ExxonMobil |
2008 |
2029 |
7 |
Angola: Girassol/Jasmim |
23.33% |
Total |
2001 |
2022 |
25 |
Angola: Dalia |
23.33% |
Total |
2006 |
2024 |
26 |
Angola: Rosa |
23.33% |
Total |
2007 |
2022 |
12 |
Angola: Block 4/05 (3) |
20.00% |
Sonangol |
2009 |
2026 |
3 |
Nigeria: Agbami |
18.85% |
Chevron |
2008 |
2024 |
12 |
|
|
|
|
|
|
North Africa, Europe, Caspian and Russia |
|
|
|
|
|
Algeria: In Salah |
31.85% |
Sonatrach/BP/Statoil |
2004 |
2027 |
32 |
Algeria: In Amenas |
50.00% |
Sonatrach/BP/Statoil |
2006 |
2022 |
17 |
Libya: Mabruk (4) |
5.00% |
Total |
1995 |
2028 |
59 |
Libya: Murzuq |
2.40% |
Repsol |
2003 |
2032 |
93 |
Azerbaijan: ACG |
8.56% |
BP |
1997 |
2024 |
59 |
Azerbaijan: Shah Deniz |
25.50% |
BP |
2006 |
2031 |
4 |
UK: Alba |
17.00% |
Chevron |
1994 |
2018 |
38 |
UK: Caledonia (5) |
21.32% |
Chevron |
2003 |
2018 |
1 |
UK: Jupiter |
30.00% |
ConocoPhillips |
1995 |
2010 |
16 |
UK: Schiehallion |
5.88% |
BP |
1998 |
2017 |
21 |
Russia: Kharyaga (6) |
30.00% |
Total |
1999 |
2032 |
20 |
|
|
|
|
|
|
Middle East and Asia |
|
|
|
|
|
China: Lufeng (7) |
75.00% |
Statoil |
1997 |
2011 |
0 |
Iran: South Pars |
37.00% |
POGC |
2008 |
2012 |
30 |
|
|
|
|
|
|
Total International E&P |
|
|
|
|
1073 |
|
|
|
|
|
|
(1) Held by production; A company’s right to own and operate an oil and gas lease is perpetuated beyond its original primary term, as long thereafter as oil and gas is produced in paying quantities |
|||||
(2) Petrocedeño is a non-consolidated company |
|||||
(3) Producing wells are related to test production |
|||||
(4) Renegotiation of the PSA by the Libyan State oil Company (NOC) for the Mabruk field was completed in January 2010. Statoil's equity share in Mabruk was reduced from 25.0% to 5.0% effective as of 1 January 2008 |
|||||
(5) Caledonia field was sold to Premier Oil in June 2009 |
|
|
|
|
|
(6) With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20% interest, thus reducing Statoil's share from 40% to 30% |
|||||
(7) Lufeng field was shut down in June 2009 |
|||||
The table below presents equity and entitlement production per country in 2009.
Country |
Average daily equity production (1) mboe/day |
Average daily entitlement production (2) mboe/day |
North America |
|
|
Canada |
18.2 |
18.2 |
USA |
46.3 |
46.3 |
|
|
|
Sub Saharan Africa |
|
|
Angola |
191.3 |
118.6 |
Nigeria |
38.5 |
35.7 |
|
|
|
North Africa, Europe, Caspian and Russia |
|
|
Algeria |
66.7 |
42.0 |
Libya (3) |
7.0 |
4.5 |
Azerbaijan |
106.3 |
54.6 |
Russia |
8.9 |
8.0 |
UK |
7.7 |
7.7 |
|
|
|
The Middle East and Asia |
|
|
China |
1.5 |
1.4 |
Iran |
6.2 |
6.2 |
|
|
|
Subtotal International E&P production |
499 |
343 |
|
|
|
Equity accounted production |
|
|
Venezuela: PetroCedeño (4) |
13.6 |
13.6 |
|
|
|
Total International E&P including share of equity accounted production |
512 |
357 |
|
|
|
(1) In PSA countries our share of capital expenditures and operational expenses are computed on the basis of equity production |
||
(2) Production figures are after deductions for royalties, production sharing and profit sharing |
||
(3) Renegotiation of PSA by the Libyan State oil Company (NOC) for the Mabruk field was completed in January 2010. 2009 volumes are based on old PSA terms. |
||
(4) Petrocedeño is accounted for pursuant to the equity accounting method. |
||
3.2.5 International fields in development and production
Major efforts are being made to make the transition from a mainly North Sea player to a world-class international operator.
We are working continuously to develop our inventory of projects into producing assets by looking at innovative technical and commercial solutions.
This section covers projects under development and fields in production. Pre-sanctioned projects, including some discoveries in the early evaluation phase, are also presented. This section often refers to a field's plateau production, which means yearly average equity production at plateau for a field where we have a 100% ownership share. Capacities also refer to the total field or facility.
Exploration activities are described in report section 3.2.2 Operational review - International E&P - International exploration activity.
Sanctioned projects coming on stream 2010-2012 * |
Statoil's share |
Operator |
Time of sanctioning |
Production start |
|
|
|
|
|
Canada: Leismer Demonstration Plant (Oil Sands phase 1) |
100.0 % |
Statoil |
2007 |
2010 |
Brazil: Peregrino |
100.0 % |
Statoil |
2007 |
2011 |
Angola: Pazflor |
23.33% |
Total |
2007 |
2011 |
Angola: PSVM |
13.33% |
BP |
2008 |
2011 |
The USA: Ceasar Tonga phase 1 |
23.55% |
Anadarko |
2009 |
2011 |
Angola: Kizomba satellites phase 1 |
13.33% |
Exxon |
2009 |
2012 |
* Not exhaustive |
|
|
|
|
3.2.5.1 North America
Statoil's E&P activities in North America comprise interests in the US Gulf of Mexico, shale gas in the Appalachian region of north-eastern USA, off the eastern coast of Canada and oil sands in the Alberta province in onshore Canada.
We also have a representative office in Mexico City.
3.2.5.1.1 Canada
Oil sands represent a 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.
Oil sands
In 2007, we acquired 100% of the shares in North American Oil Sands Corporation (NAOSC) and operatorship of the Kai Kos Dehseh (KKD) leases. We currently own interests in 1129 square kilometres (279,053 net acres) of oil sands' leases located in the Athabasca region of Alberta. In its raw state, bitumen is a heavy viscous oil that we will produce using the steam-assisted gravity drainage method (SAGD) from a depth of approximately 430 metres, with an average producing zone thickness ranging from 15 to 30 metres.
Oil sands represent a long-term investment, and Statoil has the flexibility required to develop it in stages. The first phase is the Leismer Demonstration Project, which will have a capacity of approximately 20,000 barrels of oil per day with initial production scheduled for late 2010.
Construction and commissioning of the Leismer Demonstration Project is on schedule, with approximately 75% completion progress at the end of December 2009. All the production wells have been drilled and completion of the wells is ongoing. The installation of the bitumen and diluent pipelines from the Leismer Demonstration Project to Cheecham is on schedule. Work on the Cheecham terminal is also proceeding according to plan. On completion, the Leismer Demonstration Project will be connected to the existing pipeline infrastructure at Cheecham that runs to the Edmonton area.
Statoil will use the Leismer Demonstration Project as a learning platform, where we will test a number of technologies or processes aimed at improving efficiency and extraction and improving our environmental footprint. The Statoil Heavy Oil Research Centre in Calgary is an integral part of this effort.
Offshore
Statoil has interests in two crude oil producing fields: Hibernia (Statoil share 5%) and Terra Nova (15%), and in the two development projects; Hebron (9.7%) and Hibernia Southern Extension Unit (10.5%)
Fields in production
Hibernia, which was developed with a gravity base structure (GBS), is operated by Hibernia Management and Development Company Ltd (HMDC). The Hibernia field is in the initial stages of decline, with 2009 production rates averaging 125,000 barrels of oil per day.
Terra Nova produces from a floating production, storage and offloading vessel (FPSO) and is operated by Suncor. The Terra Nova field is also in decline, with 2009 production rates averaging 80,000 barrels of oil per day.
Development projects
The Hebron field, operated by ExxonMobil, will be developed with a gravity based structure (GBS). To date, the pre-engineering project studies have been completed.
The Hibernia Southern Extension Unit, 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 license areas, where Statoil holds working interests of 22.5% in PL1005, 4.5% in EL1093 and 4.5% of the unit portion of PL1001. Statoil's unitised interest is currently 10.5%.
3.2.5.1.2 USA
With the projects Tahiti and Thunder Hawk on stream, and CaesarTonga sanctioned, we have taken our assets in the Gulf of Mexico to a new level. Onshore we continue to ramp up production from our Marcellus shale gas asset.
Onshore
The Marcellus Shale Gas play is located in the Appalachian region of 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 the Marcellus. The Marcellus provides Statoil with a long-life gas asset with considerable optionality. The asset is part of our gas value chain strategy, whereby we are building a North American gas marketing hub integrated with our Cove Point LNG import terminal and our offshore gas production in the Gulf of Mexico. Marcellus production started in 2008 and Statoil's daily equity production reached around 3,000 boe per day at year end 2009. Statoil and Chesapeake will continue to acquire and high-grade acreage around the most prospective areas of the play and will gradually build up production.
Offshore, Gulf of Mexico
Fields in production
Production started in May 2009 from the Chevron-operated Tahiti oilfield in which we have a 25% interest. The field is located in Green Canyon Block 640 and consists of six wells in two subsea drill centres connected to a Spar floating facility with a production capacity of 125,000 bbl per day. The second phase of the Tahiti development is in the appraisal and project initiation phase. Tahiti 2 will add as many as six producing and four water injection wells to the existing architecture, and the Spar facility is being upgraded to handle 155,000 bbl per day.
In July 2009, production started from the Thunder Hawk oilfield located in Mississippi Canyon Block 734. We have a 25% interest in the Murphy Oil-operated development consisting of a semi-submersible floating production facility located in Mississippi Canyon Block 736. The processing capacity is approximately 45,000 bbl oil per day.
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 produce via subsea tie-backs to the Independence Hub platform, a floating production facility located in Mississippi Canyon Block 920. The Independence Hub is owned by third parties and has processing capacity of one billion cubic feet of natural gas per day (178 000 boe per day) . We have contractual rights to 12.7% of that capacity.
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.
The Murphy-operated Front Runner oilfield is located in Green Canyon 338/339/382. We have a 25% interest in Front Runner, which started production in 2004.
We also had production from Zia in 2009. It is a small oil field located in Mississippi Canyon Block 496 and Seventeen Hands, a small gas field located in Mississippi Canyon Block 299. Both fields tie back to platforms owned by others.
Fields under development
Statoil has a 23.55% working interest in the Anadarko Petroleum-operated Caesar Tonga Unit in Green Canyon Block 683. Development of the four block unit was sanctioned in 2009 as a four-well subsea tie-back to the Anadarko's Constitution platform. The field is expected to start oil production in 2011.
Discoveries under appraisal
The Jack oilfield, which is located in Walker Ridge Block 758/759 and in which we have a 25% interest, was discovered in 2004.
St. Malo is an oilfield located in Walker Ridge Block 678. In January 2010, we increased our interest in St. Malo from 6.25% to 21.5% by exercising our pre-emption rights. St. Malo and Jack are in approximately 2000 metres of water, approximately 40 kilometres apart. Both fields are operated by Chevron and are currently planned to be developed jointly. In 2009, the concept for the development was selected and front-end engineering and design started. The development concept consists of separate subsea wells tied to a shared centrally located surface facility. The Jack and St Malo development is expected to be sanctioned in late 2010.
We have a 27.5% interest in Big Foot, a Chevron-operated oil discovery located in Walker Ridge Block 29. In 2009, a dry tree tension leg platform with a drilling rig was selected as the development concept. Project sanctioning is expected in 2010.
3.2.5.2 Latin America
Our current asset portfolio in Latin America comprises our interest in the Peregrino offshore heavy oil development project in Brazil and the onshore extra heavy oil producing asset, Petrocedeño, in Venezuela.
3.2.5.2.1 Brazil
Statoil is operator for, and owns 100% of the Peregrino oil field off the coast of Brazil. By 2012, we are expected to become the largest international offshore operator in Brazil in terms of production.
The Peregrino field is a heavy oil field located in approximately 120 metres of water in the prolific Campos Basin off the coast of Brazil, about 85 kilometres off the coast of Rio de Janeiro.
The field is being developed with a Floating Production Storage and Offloading Vessel (FPSO) and two wellhead platforms with drilling capability. The first oil production is planned to come on stream in early 2011 and we expect to reach plateau production within the first year of production. Design capacity is 100,000 boe per day. All development contracts have been signed, and the execution phase of the project and installation of field facilities are now in progress.
3.2.5.2.2 Venezuela
Statoil has a 9.677% interest in Petrocedeño, one of the largest extra heavy crude projects in Venezuela.
The Petrocedeño project involves the exploitation of extra heavy crude oil from the reservoirs in the Orinoco Belt. A diluting component is added in order 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, operates the field and markets the products.
Petrocedeño experienced operational problems throughout 2009,and was not able to produce up to design capacity. A preventive maintenance shutdown took place at the end of the year and activities were initiated to restore the plant to normal operation.
We have been present in Venezuela since 1994, and we have a long-term perspective on our activities in the country.
3.2.5.3 Sub Saharan Africa
Our development and production portfolio in sub-Saharan Africa comprises blocks 4/05, 15, 17 and 31 off the coast of Angola, and the OML 127 and OML 128 production licences off the coast of Nigeria.
3.2.5.3.1 Angola
The Angolan continental shelf is the largest contributor to Statoil's production outside Norway. It yielded 191 mboe per day in equity production at the end of 2009, 37% of our total international oil and gas output.
Angola is a key building block in our international strategy and our ambition is to become an operator in the country.
Block 17 is operated by Total, and our interest is 23.33%. Production from the block currently comprises four development areas produced over two FPSOs. The Girassol, Jasmim and Rosa development areas are produced over the Girassol FPSO and the Dalia development area over the Dalia FPSO.
Girassol and Jasmim went off plateau production in October 2008. The combined production from Girassol, Jasmim and Rosa was in the order of 215 mboe per day in 2009. Dalia FPSO produced at a peak level of 240 mboe per day in 2009.
The Pazflor project, which comprises the discoveries Perpetua, Acacia, Zinia and Hortensia, will be produced over a new FPSO with expected production capacity of 200 mboe per day and start-up scheduled for the end of 2011. Once Pazflor starts production, Block 17 is expected to reach a production level of around 650 mboe per day.
The CLOV project, the fourth FPSO development in Block 17, consists of the discoveries Cravo, Lirio, Orchidea and Violeta. Basic engineering started in 2008. Engineering, procurement and construction contracts are under evaluation, and sanction of the project is anticipated in 2010.
Increased Oil Recovery (IOR) projects to fill ullage capacity on the Girassol FPSO and to increase oil recovery from Block 17 are under evaluation. The IOR projects include subsea tie-backs, development of infill wells and the use of new technology.
Pursuant to the Production Sharing Agreement (PSA), all surplus gas from from Block 17 is to be delivered to Sonangol, which owns the gas. Block 17 is progressing on a Gas Export Project that is split into two phases. Phase I, sanctioned in 2007, is an export line from Block 17 to Block 2, where the gas can be injected through a wellhead platform if Angola LNG Terminal (AnLNG) is unavailable. Phase II, sanctioned in 2008, includes a 24-inch diameter pipeline from Block 2 to AnLNG. Costs related to the Gas Export Project will be recovered through the PSA.
Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil. Our interest is 13.33%. Total production from Block 15 exceeded 600 mboe per day in 2009. Production from the block currently comes from five FPSOs; Kizomba A, Kizomba B, Xikomba, Kizomba C-Mondo and Kizomba C-Saxi Batuque. In addition, one satellite, Marimba, is producing through a tie-back to the Kizomba A FPSO. Xikomba, which is a small, isolated field, is expected to be shut down in October 2010.
Kizomba satellites phase 1, consisting of two medium-sized discoveries - Clochas and Mavacola - was sanctioned by the partnership in 2009. Sonangol has approved all major contracts, and detailed engineering is ongoing. It is scheduled to come on stream in 2012.
The Mondo 4 appraisal well drilled in 2009 proved a separate structure of limited size in the Mondo development area. Feasibility studies are ongoing, both for the Mondo 4 discovery and for the other remaining, undeveloped discoveries in the block.
Pursuant to the PSA, all surplus gas from the offshore blocks is to be delivered to Sonangol, which owns the gas. The Gas Gathering Project for Block 15 is under development. It will collect gas from Kizomba A, B and C and the satellites. A dedicated trunk line will deliver the gas to AnLNG.
Block 31, an ultra-deepwater licence, is operated by BP, and our interest is 13.33%. The common development of the first four discoveries in the northern part of the block - Plutao, Saturno, Venus and Marte (PSVM) - was approved by the concessionaire in July 2008. PSVM will be developed via a new FPSO with a production capacity of 150,000 boe per day. Production start-up is expected in late 2011.
Work is also ongoing to pursue the development of SE-PAJD (Hub 2), comprising the Palas, Astraea, Juno and Dione discoveries.
One to two additional production hubs are expected to be launched in this block.
Block 4/05 is operated by Sonangol P&P, and our interest is 20%. This block includes the Gimboa field, which was sanctioned in 2006. The average production has been 21 mboe per day since the FPSO commenced test production in April 2009. Work is also ongoing to pursue the development of Gimboa Phase 2, with two small-sized discoveries, UMC-6 and UMC-7.
Block 15/06 is operated by Eni. Our interest is 5%. Several discoveries have been made. Work is ongoing to assess a development solution for the discoveries located in the northwestern part of the block.
3.2.5.3.2 Nigeria
In Nigeria, we have an interest in the largest deepwater producing field, Agbami.
The Agbami field in deep waters off Nigeria has been developed with subsea wells connected to an FPSO. Production started in 2008. Agbami, which is operated by Chevron, is located in licences OML 127 and OML 128, approximately 110 kilometres off the Nigerian coast. Our interest in the unitised field is 18.85%. The Agbami field reached a plateau production rate of 250 mboe per day in August 2009, four months ahead of schedule.
There is renewed vigour on the part of the Nigerian government to restructure the oil and gas sector by introducing an omnibus bill called the Petroleum Industry Bill (PIB) to replace 16 petroleum related laws that will be repealed. So far, it is not possible to determine the impact of potential restructuring and changes in the regulatory and fiscal framework.
The security and political situation is largely unchanged, with various groups causing continued uncertainty. The overall situation is monitored continuously and appropriate security measures are being assessed for our personnel and assets.
3.2.5.4 North Africa, Europe, Russia and Caspian
Statoil has built a unique position as supplier to the European gas market. In addition to our heritage position on the Norwegian continental shelf, we have upstream assets supplying the market from both the south (Algeria), and south-east (Azerbaijan).
The Shtokman field is a long-term resource that can enhance our upstream gas position while making us a supplier from the north-east.
We have interests in production and development assets in Algeria, Libya, Ireland, the United Kingdom, Azerbaijan and Russia, in addition to early-phase evaluation assets in the United Kingdom and Algeria.
We also have representative offices in Kazakhstan and Turkmenistan.
3.2.5.4.1 Algeria
Our main assets, In Salah and In Amenas, are the third and fourth largest gas developments in Algeria.
Fields in production
The In Salah onshore gas development, in which we have a 31.85% interest, is Algeria's third largest gas development. The field is currently producing at plateau level of around 130 mboe per day.Carbon capture is an important environmental commitment. The carbon capture and reinjection at In Salah is verified through a separate Joint Industry Project (between Statoil, BP and Sonatrach). The project aims to reaffirm the sustainability and reliability of carbon dioxide reinjection as a preferred solution for the reduction of carbon emissions. So far, more than three million tonnes of carbon dioxide have been captured and stored.
A Contract of Association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil. A joint marketing company sells the gas produced in the development, and all gas that will be produced up until 2017 has been sold under long-term contracts.
The In Amenas onshore development is the fourth largest gas development in Algeria, containing significant liquid volumes. Production efficiency is high, but export capacity through the Sonatrach pipelines is limited.
The facilities are built and are operated through a joint operatorship between Sonatrach, BP and Statoil, and we have a 50% share of the development costs. Production from this project has currently 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 only. A continuous production drilling campaign is ongoing.
The security situation in the northern part of Algeria is still regarded as unstable and being monitored continuously. Appropriate measures are assessed on the basis of the perceived risk level.
Fields in development
The In Salah Gas Compression Project: start-up of two of the three gas compression plants is expected during 2010. The third plant is expected to start up in early 2011. Work is ongoing on the In Salah Southern Field Development Project to mature the remaining four discoveries into production.
The In Amenas Gas Compression Project is led by BP and expected to be sanctioned in late 2010. The compressors are expected to come on stream in 2013. This will make it possible to reduce wellhead pressure and thus increase production.
In March 2009, the last of the 10 Hassi Mouina exploration/appraisal wells was completed and the drilling rig demobilised. A total of 2500 km of 2D seismic has been collected. At present, Statoil is working on assessing the technical solutions for and commercial attractiveness of a potential development.
3.2.5.4.2 Libya
We are well positioned for growth in Libya, with two producing assets and a focus on technology-based IOR projects.
Fields in production
The Mabruk oilfield is located in licence C-17, north-west in the Sirte basin. The Dahra south-east project was sanctioned in early 2009, and drilling and construction are progressing according to plan.
The NC 186 licence in the Murzuk area consists of seven fields. We are currently producing from six fields (A, B, D, H, I and J) through one common processing facility. The oil from the Murzuk fields is transported by pipeline to the Az Zawia terminal west of Tripoli for lifting by ship. The remaining field with an approved field development plan is K field, which is expected to start production in 2010. The gas utilisation project aimed at stopping continuous flaring is expected to start up in 2010.
3.2.5.4.3 United Kingdom
We have several oilfields under appraisal in the United Kingdom (UK) and hold interests in three producing fields.
Fields in production
The Alba oilfield, located in the central part of the UK North Sea, is operated by Chevron. We have a 17% interest in this field.
Schiehallion oilfield is located west of the Shetland Islands. The operator is BP and we have a 5.88% interest.
Jupiter is a gas field located in the southern part of the UK North Sea. We have a 30% interest and the operator is ConocoPhillips.
All these fields are in the mature to late-life stage of production.
Discoveries under appraisal
We are operator for Bressay (in which we have a 81.63% interest), Mariner (in which we have a 44.44% interest) and Mariner East (in which we have a 62% interest). They are all heavy oil discoveries for which studies and appraisal will continue.
Rosebank, a discovery made by Chevron in 2004, is located west of the Shetland Islands. We have a 30% interest in this field. The operator has recently completed appraisal drilling and is moving towards concept selection.
3.2.5.4.4 Ireland
We have a 36.5% interest in the Corrib gas field, which lies on the Atlantic Margin north-west of Ireland. The Shell-operated Corrib field development was sanctioned in 2001, and work towards first gas is progressing.
The development will comprise seven subsea wells, and the gas will be transported through a pipeline to an onshore gas processing terminal. The gas will be exported from the terminal via the Bord Gais Eireann link line to the existing Irish gas grid.
The Irish planning authorities granted planning permission for the gas terminal in 2004. Project execution was suspended in 2005 due to protests by local landowners. Work on the project recommenced in 2006 following a comprehensive safety review on the onshore pipeline by the Irish authorities. Alternative pipeline routes were identified as part of a community consultation process and a revised route was submitted to the Irish planning authority (ABP) during first quarter 2009. ABP responded to the application in November 2009 with a number of questions and a proposed alternative route which is predominantly located within the Sruwaddacon estuary rather than on land. The project is in the process of reviewing the proposal and will respond to ABP within May 2010. Six of the seven offshore wells have been drilled. Construction of the onshore gas terminal is expected to be completed during 2010. First gas for the project will be dependent upon construction methodology adopted for the revised onshore pipeline route and receipt of the necessary approvals from the Irish Authorities..
3.2.5.4.5 Azerbaijan
We have been present in Azerbaijan since 1992, and we are now the second largest foreign oil company in the country in terms of proved reserves and production.
At present, we hold interests in three PSAs offshore in the Azeri sector of the Caspian Sea: the Azeri-Chirag-Gunashli (ACG) 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 the ACG Phase I-III developments finalised in 2008. 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. Today, crude production from ACG exceeds 800,000 barrels of oil per day.
The crude oil from ACG is transported to the Mediterranean Sea through the 1760-kilometre Baku-Tbilisi-Ceyhan (BTC) Pipeline, in which we participate with an 8.71% interest.
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 at the beginning of 2007 and exceeded six billion cubic metres in 2009. We are the operator of the AGSC company that 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.
The partnership is working with the ambition to start production of Shah Deniz Stage two in 2016, with a capacity of around 16 billion cubic metres of natural gas per year. The project is in the concept selection phase, and commercial negotiations are ongoing to secure sales contracts and transportation rights to the markets.
The Caspian region has long been viewed as an area with a risk of increased economic, social and political instability. Although the general situation has improved, there are still political disputes that remain unsolved in both Azerbaijan and Georgia.
3.2.5.4.6 Russia
Statoil has been present in Russia since the late 1980s. We have a 24% ownership interest in Shtokman Development AG, which is responsible for the Shtokman development phase one, and a 30% ownership interest in one producing field, the Kharyaga oilfield.
Field under planning
The Shtokman gas and condensate field is located in the Russian Barents Sea, and the agreement with Gazprom gives Statoil a 24% equity interest in Shtokman Development AG in which Gazprom (51%) and Total (25%) are the other two partners. The owners have seconded personnel to Shtokman Development AG (SDAG), which is responsible for planning, financing, constructing and operating the infrastructure that is necessary for the first phase of the development. SDAG will own and operate the infrastructure for 25 years from the start of commercial production. SDAG is currently maturing the technical concept for the first phase of the Shtokman development in accordance with the framework agreements signed in 2007. Implementation of the project is subject to a final investment decision pursuant to SDAG's plans.
Field in production
The Kharyaga field is located onshore in the Timan Pechora basin in north-west Russia. The field is being developed under a production sharing agreement (PSA). Total is the operator. With effect from 1 January 2010, the Russian state oil company Zarubezhneft became a partner in the Kharyaga PSA with a 20% interest, thus reducing Statoil's share from 40% to 30%.
Pursuant to the terms of the PSA, the Kharyaga field is being developed in stages. Production from phase three started in 2009, and the production has been increased to design capacity of 30,000 bbl per day. At year end 2009, 13 wells had been drilled out of a total of 23 planned wells. Phase three also involves the installation of gas treatment facilities that will stop gas flaring in the future.
3.2.5.5 The Middle East and Asia
In January 2010, Statoil and Lukoil signed a development and production contract with Iraqi authorities for the development of the West Qurna 2 field.
We have representative offices in Indonesia, Singapore, Dubai and the United Arab Emirates.
3.2.5.5.1 Iran
Statoil was the offshore operator for the development of phases 6, 7 and 8 of the South Pars gas and condensate field in the Iranian sector of the Persian Gulf. The development is now complete and the last platform began production in 2009.
The Iranian oil company NIOC has taken over as operator for the field. Statoil will be assisting NIOC for a limited transitional period in accordance with the contractual framework.
Statoil has previously taken part in exploration and drilling activities in the country on the Anaran field. Work on this project has been stopped.
Statoil also holds a licence for exploration of the Khorramabad field. No activity is planned for this licence.
See section Risk review - Risk factors- Risks related to our business, for additional information about the risk of US sanctions relating to activities in Iran.
The company will not make any future investments in Iran under the present circumstances, but it is committed to fulfilling its contract obligations in respect of South Pars.
3.2.5.5.2 China
Statoil operated the Lufeng 22-1 oilfield in the South China Sea together with partner CNOOC from 1997 until mid-2009.
Production on Lufeng 22-1 was shut down on 15 June 2009. Abandonment of phase one and demobilisation of the Floating Production, Storage and Offloading (FPSO) vessel was finalised on 14 July 2009. Under an agreement between CNOOC and Statoil, CNOOC has taken over full responsibility for the abandonment of phases two and three of the field. The Shekou operations office was closed at the end of 2009.
Statoil's activities in China are currently centred around R&D cooperation and business development.
3.2.5.5.3 Iraq
On 31 January 2010, Statoil and Lukoil signed a development and production contract with the Iraqi authorities for the development of the West Qurna 2 field.
The consortium of contractors consists of the state of Iraq's North Oil Company (25%), Lukoil (56.25%) and Statoil (18.75%). Lukoil will be the operator. The development and production contract for the West Qurna 2 field was offered as a standard service contract under which the contractors receive cost recovery plus a remuneration fee. Lukoil and Statoil's bid for West Qurna 2 included a production plateau level of 1,800,000 barrels per day.
Lukoil and Statoil are working to set up the organisation required to develop the field. A substantial proportion of the work will be done by an Iraqi workforce or by Lukoil, but Statoil will also contribute to the joint organisation. Statoil will also set up a small representative office in Baghdad.
The security of personnel and implementation of necessary security measures are the main priorities. The security situation in Iraq is still demanding, but it has improved over the last two years. There are variations in different parts of the country, and West Qurna 2 is not considered to be in the most challenging area.
Statoil has been working with the Iraqi authorities for more than five years, conducting joint field studies and training Iraqi personnel. The entry into Iraq gives Statoil an important position in the Middle East, developing one of the world's largest oil fields for the benefit of both the Iraqi people and the participating companies.
3.3 Natural Gas
3.3.1European gas market
In natural gas, we see short term challenges and long term upsides. We expect demand for gas to pick up along with an industrial recovery, and despite weak markets, Statoil's gas business has delivered good results.
In the longer term, we believe natural gas will be an increasingly attractive commodity. According to the IEA World Energy Outlook 2009, estimated annual growth in global gas consumption in the period 2007 to 2030 will be 1.5%, slightly less than last year's estimate.
Growth in gas demand in OECD Europe in the same period is expected to be 0.8% per annum. This translates into a demand for gas in OECD Europe in 2030 of approximately 650 bcm - up from the current level of around 550 bcm. Gas's share of total primary energy consumption is approaching 25% in the OECD countries in Europe, and it is expected to reach 28% in 2030. A large part of the growth in gas consumption in the period - more than 60 per cent - is expected to come from the electricity sector.
We market and sell our own gas and the Norwegian State's natural gas volumes. We are the second largest gas supplier to Europe and the sixth largest supplier in the world. Furthermore, we market gas sourced from producing areas other than the NCS. Other major gas suppliers in Europe are Gazprom in Russia, Sonatrach in Algeria and GasTerra in the Netherlands. We believe that Norwegian natural gas exports will remain highly competitive due to reliability, access to a flexible and integrated transportation infrastructure and proximity to key European markets such as the UK, Germany and France. In addition, natural gas is an attractive source of energy from an environmental perspective since it emits far less CO2 than coal and oil.
The UK was for a long time the second largest producer of natural gas in Europe after Russia. However, it is expected that the UK could be dependent on imports for approximately 80% of its gas requirements already in 2016. Based on our growing infrastructure, we believe we are well positioned to supply part of the UK's additional demand for imported natural gas and continue to be a key player in the UK market - Europe's largest and most liberalised natural gas market.
The Langeled gas export pipeline was put into operation in 2007, connecting the NCS to Easington in the UK. Another infrastructure project called the Tampen Link, a pipeline from the Statfjord field on the NCS to the existing Flags pipeline on the UK continental shelf, was also completed in 2007. By 2010, the ongoing Gjøa/Vega field developments will be completed and tied into the Flags system - further increasing NCS export capacity to the UK market.
Disputes between Russia and Ukraine about gas transit highlight the importance of Russian gas supplies to European markets. In the years ahead, Russian supplies are expected to grow further, and, in the longer term, the EU is set to import some 80% of its natural gas due to declining domestic gas production. In order to diversify supplies, European countries and companies are actively seeking to establish alternative supply solutions, mainly through LNG, but also by establishing new pipeline infrastructure from the Caspian region and from North Africa.
Europe will need additional sources of natural gas, both because of growth in demand and because of declining domestic production. Statoil participates in increasing gas production in Azerbaijan, with the Shah Deniz field in the Caspian Sea as a key asset. Gas is already exported from Azerbaijan to Georgia and Turkey via the South Caucasus Pipeline (SCP). In order to bring gas even further west, we participate in the Trans Adriatic Pipeline (TAP) that aims to connect the Italian market with gas flowing westwards from Turkey, through Greece and Albania.
As the European energy market undergoes deregulation and structural changes, we believe that natural gas will play an increasingly important role. This trend will be reinforced by 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 the use of natural gas as a source of electricity generation to continue to grow, as it is necessary to replace even more coal-based generation capacity with natural gas. Deregulation creates new opportunities and business models in the gas sector, both with regard to added values through efficiency gains and to building a more substantial portfolio of sales directly aimed at large industrial customers and local distribution companies. The integration of the gas and power markets also presents us with new business opportunities in trading and as a means of increasing the value of gas by upgrading through generation and improving our flexibility in market operations. We therefore aim to manage and further develop marketed volumes, and to increase the scale and scope of our trading and optimisation, including both midstream and downstream activities.
For information about the EU Gas Directive, please see report section 3.10.3 Operational review - Regulation - The EU gas directive.
3.3.2 Gas sales and marketing
Statoil is a long-term, reliable natural gas supplier that has a strong position in some of the world's most attractive markets. We are the second biggest gas supplier to Europe and the sixth largest in the world.
Europe
The major export markets for NCS gas are Germany, France, the United Kingdom, Belgium, Italy, the Netherlands and Spain. Our main customers are large national or regional gas companies such as E.ON Ruhrgas, GdF Suez, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), Distrigaz and GasTerra. In addition, we sell to large end users, mostly through long-term take-or-pay contracts.
In the United Kingdom, we market our gas to large industrial customers, power generators and wholesalers, in addition to participating in the UK spot market. NG also has an end user sales business based in Belgium, serving major customers in Belgium, the Netherlands and France. Our group-wide gas trading activity is mainly focused on the UK gas market, which is a significant market in terms of size and the most liberalised market in Europe. We are also increasingly taking part in other liquid trading points such as the TTF (Title Transfer Facility) in the Netherlands, the Zeebrugge Hub in Belgium and Gaspool 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, close to the Easington terminal. On completion, the storage facility will comprise nine underground caverns. Statoil (UK) Limited owns one third of the storage capacity being developed, of which the SDFI will have access to 48.3%. The facility has been developed and is operated by SSE Hornsea Limited. The storage facility started limited commercial operation during the second quarter 2009, with full commercial operation of the nine-cavern facility scheduled for 2011. 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, or 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. The rest will be completed in 2010 and early 2011. All partners in Etzel Gas Storage are participating in this project.
USA
The USA is the world's largest and most liquid gas market. Statoil Natural Gas LLC (SNG) has a gas marketing and trading organisation in Stamford, Connecticut that markets natural gas to local distribution companies, industrial customers and power generators. SNG has two long-term capacity contracts with Dominion Resources Inc., which owns the Cove Point LNG re-gasification terminal in Maryland. The first is for a one-third share of Cove Point capacity (LTD1), which equates to approximately 3.2bcm per year, and the second is for 100% of the Cove Point Expansion (CPX) capacity of approximately 7.7 bcm per year. This equates to a total re-gasification capacity of 10.9 bcm per year. This expansion reflects Statoil's focus on the growing natural gas market in the USA and provides more flexibility in sourcing third party LNG to the terminal. The CPX capacity also includes downstream pipeline capacities from the Cove Point terminal to Leidy in Pennsylvania, and gas storage capacity at Leidy. The Cove Point Expansion capacity commenced services on 26 March 2009. A pier expansion project at Cove Point was approved by the Federal Energy Regulatory Commission (FERC) in July 2009 and construction has now started, with completion of the project expected in the latter part of 2011. This will enable the Cove Point terminal to accommodate larger LNG vessels than is currently the case and provide Statoil with increased supply opportunities for third party LNG cargoes into Cove Point.
Through Statoil, SDFI pays for a share of the capacity at the Cove Point 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 addition to sourcing some pipeline gas domestically for profit optimisation purposes.
In 2008, Statoil entered into a strategic agreement with Chesapeake Energy Corporation (as described in 3.2.5.1.2 The USA). The agreement adds a major building block to Statoil's gas value chain in the USA. It also provides access to large gas reserves located geographically near the North East which, historically, is the highest paying gas market. This will thereby strengthen Statoil's USA gas position. Over time, this will result in a significant increase in the volume of gas marketed and traded by Statoil in the USA.
SNG has also concluded transportation agreements with Tennessee Gas Pipeline (a subsidiary of El Paso Corp), and Texas Eastern Transmission (a subsidiary of Spectra Energy Corp), ensuring Statoil the right to transport up to 2 billion cubic metres (bcm) per year/200 000 mcf/day directly from the Northern Marcellus production area to New York City and the surrounding areas. These agreements secure access to some of the main pipeline systems for gas in the New York City area and thereby help maximize the value of our gas produced in the Marcellus shale. We expect that this will create attractive sales opportunities in New York City, New Jersey and surrounding areas in what is regarded the most attractive gas market in the US
Azerbaijan
Statoil has a 25.5% share in the Shah Deniz gas/condensate field in Azerbaijan and is the commercial operator for gas transportation and sales activities for Shah Deniz stage 1 gas volumes. In addition, Statoil chairs the partners' gas sales committee for the planned Shah Deniz stage 2 full field development. Azerbaijan, Georgia and Turkey are part of the gas sales portfolio for stage 1 in which Turkey is the main market. Gas is purchased and sold through the Statoil-operated Azerbaijan Gas Supply Company (AGSC), and the gas is shipped to customers through the South Caucasus Pipeline (SCP), which runs from the Sangachal terminal in Azerbaijan via Georgia to the Georgian/Turkish border. Shah Deniz stage 1 gas transportation and sales reached 6.2 bcm in 2009.
The stage 2 development of Shah Deniz is currently in the Concept Selection phase of operator BP's Capital Value Process. Field reserves support a significant stage 2 production and will be larger than in stage 1. Key activities for NG in this context are related to the commercialisation of stage 2 through the organisation, planning and conducting of gas market/transport evaluations and negotiations with counterparties in the Caspian region, Turkey, the European Union and Russia. Progress of the marketing activities has been hampered by the lack of an intergovernmental agreement between Turkey and Azerbaijan on volumes for transit and sales to the Turkish market.
In February 2008, Statoil signed an agreement with the Swiss EGL Group to establish a joint venture to develop, build and operate the Trans Adriatic Pipeline (TAP) from Greece via Albania to Italy. We joined the TAP project as part of our efforts to provide attractive export options and ensure competition for the Shah Deniz gas in the European market. TAP will thus be competing with other pipelines to attract potential customers for gas from Shah Deniz. A final investment decision is linked to the Shah Deniz stage 2 development.
Algeria
Statoil has a 31.9% share in Algeria's third largest gas development, the In Salah field and In Amenas. The gas is sold through a joint marketing company that sells the gas produced from development on behalf of the operators Sonatrach, BP and Statoil. All gas that will be produced up until 2017 has been sold under long-term contracts.
LNG
Statoil's LNG trading and commercial operations are based in the company's offices in Stavanger, Norway. From here, daily contact is maintained between the production plant at Melkøya, vessels at sea and the contractual receivers of the LNG. Production from the plant at Melkøya, the first LNG production facility in Europe, proved to be unstable throughout 2009. In addition to scheduled maintenance during the months of August to October, several unexpected interruptions to production were experienced during the year. Despite the operational issues at Melkøya, we met our contractual obligations through mitigation activities, such as purchasing replacement LNG and piped gas to supplement available Snøhvit LNG. Global LNG prices have been under pressure from lower demand and increased global production. The largest drop in LNG imports was seen into the US market. Of the Snøhvit production, a total of six cargoes were diverted away from the US market into higher priced markets in Europe. Statoil will continue to pursue its ambition to grow a global LNG portfolio.
3.3.3 Norway's gas transport system
The Norwegian gas pipeline system has been developed over the last 30 years to become an integrated system connecting gas producing fields to receiving terminals in Europe via processing plants on the Norwegian mainland.
Norway's gas pipelines currently total 7800 kilometres. Since 2003, all gas pipelines with third party customers have been unitised into a single joint venture, Gassled, with regulated third party access. The Gassled system is operated by the independent system operator, Gassco AS, a company wholly owned by the Norwegian State. In 2009, the Gassled system transported 96.6 bcm (3.4 tcf) of gas to Europe.
In 2009, the Gassled system was again expanded through the merger of the Kvitebjørn gas pipeline, Norne Gas Transportation System and Etanor ethane fractionation system at Kårstø. When new gas infrastructure facilities are merged into Gassled, the ownership shares are adjusted in relation to the relative value of the assets and each owner's relative interest.
From 1 January 2011, the Gassled ownership interests will be adjusted. Petoro's interests will increase by approximately 8% and all other parties will reduce their interests proportionally. 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 pipeline infrastructure system.
As an integrated pipeline network with high flexibility and regularity, we believe that the Norwegian gas pipeline system is an essential facility that ensures reliable supplies of natural gas to Europe.
The tables below present facts about the NCS gas pipelines, including transportation routes and daily capacities, and our ownership in Gassled and other terminals.
Gas pipelines included in Gassled |
Start up date |
Product |
Start point |
End point |
Transport capacity(1) mmcm/day |
Statoil share in % |
|
|
|
|
|
|
|
|
|
Zeepipe |
|
|
|
|
|
|
|
|
Zeepipe 1 |
1993 |
Dry gas |
Sleipner riser platform |
Zeebrugge |
40.9 |
See Ownership structure Gassled |
|
Zeepipe 2A |
1996 |
Dry gas |
Kollsnes |
Sleipner riser platform |
72.0 |
|
|
Zeepipe 2B |
1997 |
Dry gas |
Kollsnes |
Draupner E |
71.0 |
|
Europipe 1 |
1995 |
Dry gas |
Draupner E |
Dornum/Emden |
44.5 |
|
|
Franpipe |
1998 |
Dry gas |
Draupner E |
Dunkerque |
52.4 |
|
|
Europipe II |
1999 |
Dry gas |
Kårstø |
Dornum |
64.6 |
|
|
Norpipe AS |
1977 |
Dry gas |
Norpipe Y (Ekofisk Area) |
Emden |
43.1 |
|
|
Åsgard Transport |
2000 |
Rich gas |
Åsgard |
Kårstø |
70.4 |
|
|
Statpipe |
|
|
|
|
|
|
|
|
Zone 1 |
1985 |
Rich gas |
Statfjord |
Kårstø |
26.8 |
|
|
Zone 4A |
1985 |
Dry gas |
Heimdal |
Draupner S |
33.3 |
|
|
|
|
|
Kårstø |
Draupner S |
20.1 |
|
|
Zone 4B |
1985 |
Dry gas |
Draupner S |
Norpipe Y (Ekofisk Area) |
30.0 |
|
Oseberg Gas Transport |
2000 |
Dry gas |
Oseberg |
Heimdal |
39.9 |
|
|
Vesterled (Frigg transport) |
2001 |
Dry gas |
Heimdal |
St. Fergus |
36.0 |
|
|
Langeled North |
2007 |
Dry gas |
Nyhamna |
Sleipner Riser |
Approx. 70.0 |
|
|
Langeled South |
2006 |
Dry gas |
Sleipner |
Easington |
68.0 |
|
|
Tampen Link |
2007 |
Rich gas |
Statfjord |
FLAGS |
26.5 (2) |
|
|
Norne Gas Transportation System |
2001 |
Rich gas |
Norne field |
Åsgard Transport |
11.0 |
|
|
Kvitebjørn gas pipeline |
2004 |
Rich gas |
Kvitebjørn |
Kollsnes |
25.4 |
|
|
Gjøa Gas Pipe (3) |
2010 |
Rich gas |
Gjøa Field |
FLAGS |
17.0 |
|
|
|
|
|
|
|
|
|
|
(1) We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries. |
|||||||
(2) 26.5 mmcm/d is the maximal committable capacity |
|
|
|
|
|||
(3) To be included in Gassled from 1st June 2010 |
|
|
|
|
|
||
Gas pipelines not included in Gassled |
Start-up date |
Product |
Start point |
End point |
Transport capacity mmcm/day |
Statoil share in % |
|
|
|
|
|
|
|
Haltenpipe |
1996 |
Rich gas |
Heidrun |
Tjeldbergodden/ Åsgard Transport |
7.1 |
19.06 |
Heidrun gas export |
2001 |
Rich gas |
Heidrun |
Åsgard Transport |
10.9 |
12.41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminal facilities included in Gassled |
Startup date |
Product |
Location |
|
|
|
|
|
|
|
|
|
|
Zeepipe JV |
|
|
|
|
|
|
Europipe receiving facilities |
1995 |
Dry gas |
Dornum, Germany |
|
|
|
Europipe metering station |
1995 |
Dry gas |
Emden, Germany |
|
|
|
Norsea Gas AS |
1977 |
Dry gas |
Gas Terminal, Emden, Germany |
|
|
|
Statpipe JV (Kårstø gas treatment plant) |
1985 |
Dry gas/NGL |
Kårstø, Norway |
|
|
|
Easington Receiving Facilities |
2006 |
Dry gas |
Easington, UK |
|
|
|
Vesterled JV (Frigg terminal) |
1978 |
Dry gas |
St. Fergus, Scotland |
|
|
|
Kollsnes Gas Plant |
1996 |
Dry gas/NGL |
Kollsnes, Øygarden Norway |
|
|
|
Etanor DA |
2000 |
Ethane |
Kårstø, Norway |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Terminals not included in Gassled |
Startup date |
Product |
Location |
|
|
|
|
|
|
|
|
|
|
Zeepipe terminal JV (1) |
1993 |
Dry gas |
Zeebrugge, Belgium |
|
|
|
Dunkerque terminal DA (2) |
1998 |
Dry gas |
Dunkerque, France |
|
|
|
|
|
|
|
|
|
|
(1) Gassled owners hold 49 per cent interest in the terminal. |
|
|
|
|
||
(2) Gassled owners hold 65 per cent interest in the terminal. |
|
|
|
|
||
Ownership structure Gassled |
Period 2009-2010 |
Period 2011-2028 |
Petoro AS(1) |
38.46% |
46.51% |
Statoil ASA |
32.10% |
28.32% |
ExxonMobil |
9.43% |
8.03% |
Total |
7.78% |
6.04% |
Shell |
5.32% |
4.92% |
Norsea Gas AS |
2.73% |
2.25% |
ConocoPhillips |
2.00% |
1.67% |
Eni |
1.53% |
1.27% |
Dong |
0.66% |
1.00% |
Statoil interest including 28.58% of Norsea Gas AS |
32.88% |
28.96% |
|
|
|
(1) Petoro holds the participating interest on behalf of the SDFI. |
|
|
Gas pipelines included in Gassled |
Start up date |
|
|
|
|
Zeepipe |
1993/1996/1997 |
|
Europipe 1 |
1995 |
|
Franpipe |
1998 |
|
Europipe II |
1999 |
|
Norpipe AS |
1977 |
|
Åsgard Transport |
2000 |
|
Statpipe |
1985 |
|
Oseberg Gas Transport |
2000 |
|
Vesterled (Frigg transport) |
2001 |
|
Langeled North |
2007 |
|
Langeled South |
2006 |
|
Tampen Link |
2007 |
|
Norne Gas Transportation System |
2001 |
|
Kvitebjørn Gas Pipeline |
2004 |
|
Gjøa Gas Pipe 3) |
2010 |
|
|
|
|
Terminal facilities included in Gassled |
Startup date |
Location |
|
|
|
Zeepipe JV |
|
|
Europipe receiving facilities |
1995 |
Dornum, Germany |
Europipe metering station |
1995 |
Emden, Germany |
Norsea Gas AS |
1977 |
Emden, Germany |
Statpipe JV (Kårstø gas treatment plant) |
1985 |
Kårstø, Norway |
Easington Receiving Facilities |
2006 |
Easington, UK |
Vesterled JV (Frigg terminal) |
1978 |
St. Fergus, Scotland |
Kollsnes Gas Plant |
1996 |
Kollsnes, Norway |
|
|
|
(1) We use committable capacity as a measurement for transport capacity. Committable capacity is defined as the capacity available for stable deliveries. |
||
(2) 26.5 mmcm/d is the maximal committable capacity |
|
|
(3) To be included in Gassled from 1 July 2010. |
|
|
3.3.4 Kårstø gas processing plant
As technical service provider (TSP), Statoil is responsible for the operation, maintenance and further development of the Kårstø gas processing plant on behalf of the operator Gassco.
Kårstø processes rich gas and condensate, 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.
The Kårstø processing plant is undergoing comprehensive upgrading over the next few years in order to meet safety and technical requirements and future needs. KEP is the project name for several projects intended to make the Kårstø facilities more robust and ensure safe and efficient operation. This investment is estimated at around NOK 7 billion. The first sub-project was completed successfully in 2008. Plans entail the completion of the remaining sub-projects between 2010 and 2012. The peak manning for KEP on site will be around 700. In 2009, Kårstø produced 24.1 bcm of dry gas, 0.9 million tonnes of ethane, 4.2 million tonnes of LPG and 2.2 million tonnes of condensate/naphtha for export to customers worldwide.
3.3.5 Kollsnes gas processing plant
As technical service provider (TSP), 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 landed from the Troll field in two 36-inch pipelines. The plant currently has a design capacity of 144 mmcm per day. In 2008, an upgrade was completed of the flash gas compressor and the condensate system, increasing the robustness of the plant. In 2009, Kollsnes produced 31.0 bcm of dry gas and 2.0 mmcm of condensate.
3.3.6 Gas sales agreements
Statoil manages, transports and markets approximately 80% of all NCS gas.
Due to the relatively large size of the NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, most of Statoil's gas sales contracts are long-term contracts that typically run for 10 to 20 years or more. Under these contracts, the purchasers agree to take daily and annual quantities of gas and, if the gas is not taken, they are obliged to pay for the contracted quantity. The majority of Statoil's long-term sales contracts have reached plateau level.
Prices under traditional long-term contracts are generally tied to a formula based on the prevailing prices for substitute fuels for natural gas, typically heavy fuel oil and gasoil. By contrast, the most recent long-term gas sales contracts in the UK are priced with reference to a daily UK market gas price index. There can be significant price fluctuations during the life of the contract. Under the traditional long-term contracts, prices are typically adjusted quarterly and are calculated on the basis of the prevailing prices in the three to nine months before the date of adjustment as published in reference indices. However, the price formula, which allows for monthly or quarterly adjustment, does not pick up on all trends in the marketplace, e.g. changes in the taxation of gas and competing fuels imposed by national governments. Therefore, most of our long-term gas contracts contain contractual price adjustment mechanisms that can be triggered at regular intervals, either by the buyer or the seller. Under our long-term sales contracts either party is entitled to initiate a price review process under certain circumstances.
In 2009, Statoil was involved in commercial discussions (in lieu of a price review) or in formal price review processes for approximately 75% of the volumes covered by our long-term sales contracts.
3.4 Manufacturing & Marketing
3.4.1 Oil Sales, Trading and Supply
Statoil is one of the major net sellers of crude oil in the world, operating from sales offices in Stavanger, Oslo, London, Singapore and Stamford, and selling and trading crude oil, condensate, NGL and refined products.
We market Statoil's own volumes and SDFI's equity production of crude oil and NGL, in addition to third party volumes. In 2009, our total sales of crude and condensate were equivalent to 721 million barrels, including supplies to our own refineries. The main crude oil market for Statoil is in 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 721 mill bbls sold in 2009, approximately 47% were Statoil's own equity volumes.
We also operate the South Riding Point crude oil terminal in the Bahamas in addition to being responsible for optimising the commercial utilisation of the crude terminals located at Mongstad and Sture in Norway.
3.4.1.1 South Riding Point
On 22 October 2009 Statoil completed the acquisition of SRP Holding Limited, which holds the lease for the South Riding Point crude oil terminal in the Bahamas until 2049. The lease includes oil storage as well as loading and unloading facilities.
The terminal, which is located on Grand Bahama Island, consists of two shipping berths and ten storage tanks with storage capacity for 6.75 million barrels of crude.
We plan to upgrade the terminal to allow for the blending of crude oils, including heavy oils. Future blending operations will normally be carried out onshore, but facilities will also be installed that allow for blending from ship to ship at the jetty.
The acquisition is a strategic measure that will both support our global trading ambitions and improve our handling capacity for heavy oils. We have rented capacity at the terminal since 1993. New blending facilities and full terminal capacity will strengthen both our marketing and trading positions in the North American market. The terminal will also be an important part of our plans to market our own volumes of heavy oil.
In addition to the existing lease period, we have an option to extend the agreement for an additional 30 years until 2079.
3.4.2 Manufacturing
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, and sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbl per day. In addition, we have 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 a 81.7% stake in the gas-based methanol plant at Tjeldbergodden, Norway, which has a design capacity of 0.95 million tonnes per year.
We also operate the Oseberg Transportation System (36.2% stake) including the Sture crude oil terminal. The plant was built to receive crude from the Oseberg field through a pipeline, and 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.
All data for year ended December 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Throughput (1) |
|
Distillation capacity (2) |
|
On stream factor % (3) |
|
Utilization rate % (4) |
||||||||
Refinery |
2009 |
2008 |
2007 |
|
2009 |
2008 |
2007 |
|
2009 |
2008 |
2007 |
|
2009 |
2008 |
2007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Mongstad |
10.0 |
10.0 |
10.9 |
|
8.7 |
8.7 |
8.7 |
|
92.3 |
92.2 |
97.8 |
|
86.8 |
88.2 |
93.2 |
Kalundborg |
5.0 |
5.2 |
4.7 |
|
5.5 |
5.5 |
5.5 |
|
95.3 |
88.3 |
96.4 |
|
88.2 |
90.3 |
91.7 |
Tjeldbergodden |
0.71 |
0.91 |
0.70 |
|
0.95 |
0.95 |
0.95 |
|
82.6 |
98.9 |
81.7 |
|
90.2 |
96.5 |
97.7 |
(1) Actual throughput of crude oils, condensates, NGL, feed and blendstock, measured in million tonnes. |
|||||||||||||||
(2) Nominal crude oil and condensate distillation capacity, and methanol production capacity, measured in million tonnes. |
|
|
|
|
|
|
|||||||||
(3) Composite reliability factor for all processing units, excluding turnarounds. |
|
|
|
|
|
|
|
|
|
|
|||||
(4) Composite utilization rate for all processing units, stream day utilization. |
|
|
|
|
|
|
|
|
|
|
|||||
3.4.2.1 Mongstad
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 was built in 1975. It was significantly expanded and upgraded in the late 1980s, and it has been subject to considerable investment over the last 15 years in order to meet new product specifications. It is a medium-sized, modern refinery. It is directly linked to offshore fields through two crude oil pipelines and linked through an NGL/condensate pipeline to the crude oil terminal at Sture and the gas processing plant at 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 and a Natural Gas Liquids (NGL) process unit and terminal. The crude terminal is owned 65% by Statoil. A large proportion of its crude oil comes through two direct pipelines from the Troll field. The storage capacity is 9.4 million barrels of crude.
Vestprosess, which is owned 34% by Statoil, transports and 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 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-west Europe and the United States. The following table shows the approximate quantities of refined products (in thousand tonnes) produced at Mongstad for the periods indicated. 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 its in-line blending during ship loading.
|
For the year ended 31 December |
|||||
Mongstad product yields and feedstock |
2009 |
2008 |
2007 |
|||
|
|
|
|
|
|
|
LPG |
372 |
4% |
311 |
3% |
373 |
4% |
Gasoline / naphtha |
4,401 |
44% |
3,902 |
39% |
4,721 |
43% |
Jet / kerosene |
717 |
7% |
820 |
8% |
755 |
7% |
Gasoil |
3,473 |
34% |
3,680 |
37% |
3,865 |
35% |
Fuel oil |
374 |
4% |
485 |
5% |
311 |
3% |
Coke / sulphur |
164 |
2% |
190 |
2% |
222 |
2% |
Fuel, flare & loss |
532 |
5% |
575 |
6% |
692 |
6% |
Total throughput |
10,033 |
100% |
9,963 |
100% |
10,939 |
100% |
|
|
|
|
|
|
|
Troll, Heidrun (FOB crude oils) |
4,062 |
40% |
4,676 |
47% |
4,751 |
43% |
Other North Sea crude oils (CIF crude oil) |
3,679 |
37% |
3,072 |
31% |
3,780 |
35% |
Residue |
1,316 |
13% |
1,132 |
11% |
1,265 |
12% |
Other fuel and blendstock |
976 |
10% |
1,083 |
11% |
1,143 |
10% |
Total feedstock |
10,033 |
100% |
9,963 |
100% |
10,939 |
100% |
|
|
|
|
|
|
|
Note: Changes in throughput and yields are partly due to maintenance shutdowns (e.g. major turnaround in 2008). |
||||||
The refinery reliability (i.e. on-stream factor) was high in 2007, but the site experienced some operational problems during 2008 and 2009. In addition, there were also shutdowns due to the market situation in 2009. In 2008 the largest turnaround in Mongstad's history was executed on schedule. There were no turnarounds in 2007 or 2009. Capacity utilisation (the share of available plant capacity actually used) was reduced in 2009, also due to the market situation.
We are building a combined heat and power plant (CHP plant) at Mongstad. The CHP plant is part of a strategically important project for Manufacturing & Marketing. The CHP plant will improve the Mongstad refinery's energy efficiency. The CHP plant 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 under commissioning and testing, and will be operated by Dong Energy, with Statoil paying an annual tariff for its use. There is an agreement with the Troll licensees that this facility will 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 includes 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. These projects are further described in section 3.5.2 Operational review - Technology & New Energy - New energy.
3.4.2.2 Kalundborg
The Kalundborg refinery is a small and 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.
Kalundborg's refined products are also supplied to other markets in north-western Europe, mainly Germany and France. Fuel oil is exported to Italy and the USA.
The following table shows the approximate quantities of refined products (in thousand tonnes) produced by Kalundborg in the periods indicated.
|
For the year ended 31 December |
|||||
Kalundborg product yields and feedstock |
2009 |
2008 |
2007 |
|||
LPG |
71 |
1% |
54 |
1% |
78 |
2% |
Gasoline / naphtha |
1,620 |
32% |
1,598 |
31% |
1497 |
32% |
Jet / kerosene |
130 |
2% |
251 |
5% |
209 |
4% |
Gasoil |
2,140 |
43% |
2,105 |
40% |
1997 |
42% |
Fuel oil (2) |
886 |
18% |
1,023 |
20% |
746 |
16% |
Coke / sulphur |
0 |
0% |
6 |
0% |
5 |
0% |
Fuel, flare & loss |
189 |
4% |
183 |
3% |
186 |
4% |
Total throughput(1) |
5,036 |
100% |
5,220 |
100% |
4,718 |
100% |
|
|
|
|
|
|
|
Condensates: Ormen Lange, Snöhvit, Sleipner |
998 |
20% |
659 |
12% |
170 |
4% |
Other North Sea crude oils |
3,713 |
74% |
4,314 |
83% |
4395 |
93% |
Other fuel and blendstocks |
202 |
4% |
247 |
5% |
153 |
3% |
Other crudes |
123 |
2% |
|
|
|
|
Total feedstocks |
5,036 |
100% |
5,220 |
100% |
4,718 |
100% |
|
|
|
|
|
|
|
1) Total throughput has decreased from 2008, due to the economic downturn. The refinery operates in a market, |
|
|
|
|
|
|
that is oversupplied with products, so the production during 2009 was not maximized. |
|
|
|
|
|
|
2)The Fuel Reduction plant has been in operation throughout 2009, except for a planned shutdown in September, |
|
|
|
|
|
|
and an incident in October, hence the reduction in 2009. |
|
|
|
|
|
|
The refinery reliability (i.e. on-stream factor) was relatively high in 2007 and 2009, but 2008 was more challenging; partly related to startup after a major modification project. There was a turnaround in 2007. Capacity utilisation (the share of available plant capacity actually used) was reduced in 2009 due to the market situation.
Kalundborg has improved its performance significantly in recent years through several small investment projects aimed at increasing flexibility and improving yield/product quality. It produces high-quality products, including low-sulphur gasoline and diesel, in accordance with EU specifications.
The Fuel Reduction Project was completed in 2008, and it is now producing according to the design specifications.
3.4.2.3 Tjeldbergodden
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). Actual throughput in 2009 was reduced due to depressed methanol market prices and necessary maintenance. Methanol production in 2009 was 0.71 mmtpa
We also own 50.9% of Tjeldbergodden Luftgassfabrikk DA, one of the largest air separation units (ASU) in Scandinavia.
3.4.2.4 Sture
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.
3.4.3 Energy and Retail
Energy and retail employs close to 10,500 employees who run 2000 service stations and 300 automated truck stops in eight countries. We also market refined products directly to consumer and industrial markets.
The majority of Energy and Retail's sales are generated in Scandinavia. In Norway we have a transport fuel market share of approximately 35%. In Sweden, our transport fuel market share is approximately 32%, and in Denmark it is approximately 27%, based on sales from Statoil and JET-branded stations together with truck-stop sales. Other service stations are located in Poland, Russia and the Baltic states: Estonia, Lithuania and Latvia. We are the market leader in Estonia and Latvia measured in terms of fuel volumes sold, with approximately 23% and 36% respectively of the local transport fuel market in 2009.
The full-service stations in the retail segment sell transportation fuels, car accessories and basic vehicle service products. Most stations also offer consumer goods (including fast food), convenience products and basic groceries. In 2009, together with automated stations, these stations sold approximately 6.9 billion litres of petrol and diesel. Sales from truck stops accounted for additional sales of 1.0 billion litres.
The following table lists retail outlets by region or country as of 31 December 2009 and our volume of automotive fuel sales for the year ended 31 December 2009.
Retail outlets/country |
|
|
|
|
|
|
|
|
|
|
|
Service Stations |
Scandinavia |
Poland |
Baltics |
Russia |
Total |
Statoil owned and operated |
276 |
186 |
167 |
19 |
648 |
Statoil owned and dealer operated |
464 |
|
|
|
464 |
Dealer owned and operated |
178 |
57 |
6 |
|
241 |
Automated stations |
588 |
47 |
17 |
|
652 |
Total |
1506 |
290 |
190 |
19 |
2005 |
|
|
|
|
|
|
Truck Stops |
292 |
0 |
0 |
0 |
292 |
|
|
|
|
|
|
Automotive fuel volumes (millions of litres) |
|
|
|
|
|
|
|
|
|
|
|
Petrol |
2,449 |
375 |
439 |
61 |
3324 |
Diesel |
3,391 |
568 |
469 |
19 |
4447 |
LPG/Ethanol |
67 |
137 |
24 |
0 |
228 |
Total |
5,907 |
1,080 |
932 |
80 |
7,999 |
In addition to retail operations, Energy and Retail also supplies aviation and marine fuels, as well as a large number of Statoil-brand refined products. Such products include heating oil and lubricants that are supplied to both retail and industrial customers.
JET integration
A total of 123 JET stations in Sweden and 70 JET stations in Denmark have been successfully integrated into Statoil. A major IT integration has taken place in order to move the stations from the old ConocoPhillips systems over to the Statoil IT platform. The integration of these 193 sites boosts Energy and Retail's position as the leading fuel company in Scandinavia, with a balance between full-service and automated outlets.
Developing our business
Statoil's Board of Directors has approved a proposal to create a stand-alone Energy & Retail business through an initial public offering (IPO) on the Oslo Stock Exchange. The IPO will take place at the earliest in the fourth quarter of 2010 or at a time when the capital market is deemed favourable for such an offering. Statoil intends to remain a majority shareholder of Energy & Retail at the time of the initial public offering and listing. The size and time horizon of Statoil's future ownership in Energy & Retail will be tailored to support and develop company value both for Energy & Retail and for the Statoil Group. The introduction of the new ownership structure is not expected to have a significant impact on the financial statements.
3.5 Technology & New Energy
3.5.1 Research and development initiatives
Our research and development (R&D) efforts focus on the technology areas identified as addressing our key business challenges.
The R&D portfolio is organised in five programmes: Exploration; Increased Oil Recovery and Reservoir Drilling & Well; New Development Solutions; Oil and Gas Value Chain; New Energy and New Ideas. In addition, there is an Academia programme that addresses cooperation with universities and research institutes.
Research and development expenditure has been stable for the last three years at approximately NOK 2.1 billion per year.
Cooperation with external partners such as academic institutions, R&D institutes and suppliers is crucial in relation to technology provision. The aim is a 50/50 split between internal and external R&D spending.
In the exploration technology context, we are developing new basin and prospect concepts that enable better global screening, exploration drilling and quantitative prediction of basin prospectivity. In addition, we are working on the identification, characterisation and prediction of deepwater plays for exploration in complex geological settings. The incorporation of integrated geophysical and geological methodologies into next generation workflows results in continued improvement of subsurface imaging and interpretation. The goal is to considerably reduce the risk of drilling dry holes and to enable us to determine the presence of commercially viable reservoirs prior to drilling.
For proven reservoirs, the aim is to optimise hydrocarbon recovery by improving ways of identifying remaining resources and draining our reservoirs as efficiently and effectively as possible. Important success factors here are data integration and faster model updates for integrated operations across disciplines, organisational entities and geographical areas. We are developing fit-for-purpose modelling techniques for better and more efficient modelling of reservoir drainage, more efficient drilling and intervention solutions and more cost effective well construction methods.
Innovative offshore field development solutions are resulting in a transition from topside facilities to intelligent, remotely-operated, autonomous seabed facilities, coupled with ultra-long, subsea tie-backs and wellstream compression devices. However, we also see that compact processing technology developed for subsea application has a substantial potential to improve production efficiency on existing platforms. The aim is to improve the regularity and performance of both new and producing fields. Furthermore, it is necessary to increase our knowledge about design and operations in ice-bound areas and in ultra-deepwater conditions. Environmental activities relating to our licence-to-operate in the far north and time-critical research relating to exploration drilling in the far north are being addressed. We are also developing technology for the processing and transportation of offshore heavy oil.
The opportunities in gas value chain technology may lie in gaining greater access to, and cost-effectively developing, difficult unconventional gas resources. We are developing technology for the processing and transportation of challenging gas as well as pipeline solutions for deep and ultra-deep assets, and refining technology for handling challenging and unconventional crude oil, such as for the Peregrino field in Brazil.
The Calgary Heavy Oil Technology Centre was established in 2008 to strengthen our efforts in heavy oil technologies. The focus is on developing onshore extra-heavy oil value chains.
Our commitment to environmental stewardship is twofold: meeting our objective of zero harm to the environment by expanding our toolkit of environmental monitoring and integrated risk-modelling systems, and, secondly, creating business in new energy sources. In addition to our present activities in offshore wind and marine biofuels we are assessing opportunities in renewable energy sources and carriers. Cost and energy-efficient carbon capture and storage (CCS) that does not harm the environment is an important element being addressed by Statoil. We believe technological innovation is the key to a profitable, sustainable, low-carbon energy future. Integrating trend-breaking technologies such as biotechnology and other new ideas into the value chains is also part of our research and development efforts.
As part of the research effort, we are pursuing an extensive collaboration programme with academic institutions in which we gain access to world-class research within strategic areas for Statoil. By stimulating the development of leading expertise in the energy segment, we also secure long-term recruitment to science and technology.
By supporting collaboration between universities, research institutions and industry, we also contribute to building a strong Norwegian petroleum cluster.
3.5.2 New energy
New Energy focuses particularly 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.
Renewable power production
Our main focus in renewable power production is on making offshore wind power a profitable business, but we are also engaged in activities in onshore wind, wave, tidal, solar and geothermal energy. In October 2002, Havøygavlen Wind Park came on line with a capacity of 40 MW. It generates enough power for approximately 5000 Norwegian homes. Havøygavlen is the world's northernmost wind farm, located close to North Cape. Havøygavlen is a wholly owned subsidiary of Statoil. We also have two windmills that power a pioneering project on the island of Utsira. In addition, Statoil has several other onshore wind projects under evaluation in Norway.
Sheringham Shoal
In 2009, Statoil joined forces with the Norwegian utilities company Statkraft to develop the Sheringham Shoal offshore wind farm in the UK. Located off the coast of northern Norfolk, the 315 MW Sheringham Shoal wind farm is expected to provide enough energy to power almost 220,000 British homes. Sheringham Shoal, which received consent in August 2008, will be a major contributor of clean power to the UK market. The generated electricity and renewable energy certificates will be sold in the UK market. Construction work started in 2009. The 88 wind turbine generators will be set into production one by one as they are commissioned and tested in the period up until the end of 2011.
To fulfil its EU 2020 renewable energy target, the UK Government has estimated that more than 30% of its electricity production will have to come from renewable electricity by 2020. Offshore wind will play a major part in achieving this target. In January 2010 The Crown Estate announced the third round of offshore leasing, awarding areas which could develop in total 32 GW of offshore wind capacity. This comes in addition to the potential capacity of 8 GW from previous rounds. Statoil was as part of the Forewind consortium awarded the Dogger Bank zone. This is the largest area in the licensing round with an expected capacity of 9-13 GW. Forewind is a consortium of four equal partners. In addition to Statoil, it consists of RWE npower renewables, Scottish and Southern Energy and Statkraft. This is currently an investment opportunity, and Statoil has as of yet not committed to any investments in the project.
Hywind - the world's first full-scale floating wind turbine
In 2009, Statoil crossed a new energy frontier when the company developed the world's first full-scale floating wind turbine - Hywind. The 2.3 MW turbine, a pilot of a concept developed by Statoil, is located 10 km off the island of Karmøy north of Stavanger in Norway. The test period started in autumn 2009 and will last for two years. The Hywind pilot is based on known technology from both the wind power industry and oil and gas industry, which has been combined in a completely new way. Work on this project rests on the fundamental philosophy that existing turbine solutions can function using floating structures and mooring systems developed for the offshore sector.
Having demonstrated technological feasibility through the Hywind pilot, the next phase will focus on demonstrating commercial feasibility. Statoil is therefore considering locations for further demonstration.
Sustainable fuels
Biofuel is considered to be the most effective measure for reducing carbon dioxide emissions from the transport sector. We wish to position ourselves for longer-term growth in low-cost second-generation marine biofuel technology by building technological expertise and securing access to winning technologies through demo projects, and by engaging in technology development and active technology monitoring.
Carbon capture and storage
Carbon capture and storage (CCS) is seen as one of the main methods of combating climate change. Statoil has long been a pioneer of CCS in oil and gas production, and we currently operate some of the world's largest projects in this area. Statoil is engaged in the development of potential medium and long-term breakthrough technologies for carbon dioxide capture. They include both improvements of existing concepts and radically novel concepts. The aim is to significantly improve energy efficiency and reduce costs.
Together with Gassnova (which represents the Norwegian government in matters relating to CCS), the South African integrated energy and chemical company Sasol, and Shell, we are building a centre for carbon dioxide capture technologies at Mongstad, known as the European carbon dioxide Technology Centre Mongstad (TCM). Sasol has signed a Memorandum of Understanding (MoU) to explore the possibility of becoming a participant in the TCM.
The technology centre demonstration plant aims to help suppliers develop more cost-efficient, environmentally friendly and safe technologies for carbon dioxide capture to handle emissions from different flue gases, such as gas power, coal power and refineries. The plants will have the capacity to capture up to 100,000 tonnes of carbon dioxide annually, and this therefore represent an important step towards full, industrial scale carbon dioxide capture. Construction activities are progressing according to plan after starting in summer 2009, and start up is scheduled for the end of 2011/early 2012.
CCS business development
Based on our experience from Sleipner, In Salah and Snøhvit and our experience of handling geological risk and developing large projects, Statoil is seeking CCS-related business opportunities. Provided that satisfactory commercial and legal conditions are in place, Statoil's ambition is to develop, own and operate profitable CCS projects, focusing on storage. However, to become an important tool in the fight against emissions of greenhouse gases and combating climate change, CCS must become commercially viable.
Potential storage sites are restricted to sedimentary basins that are distributed 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 dioxide storage. The ambition is to store our own carbon dioxide (for example from our own production of carbon dioxide-rich natural gas streams like Sleipner), and third party carbon dioxide (for example from captured carbon dioxide from coal-fired power plants).
Our business activities in carbon dioxide also include the development of projects under the United Nations' Clean Development Mechanism (CDM). This activity builds on our experience of carbon dioxide reduction from the oil and gas sector. Country selection is based on CDM market conditions, Statoil's presence in the country and other criteria, such as emission data and sector attractiveness. Our main activities so far have been in Mexico and China.
3.5.3 Technology development
We are among the front runners in applying technology within the oil and gas industry.
We achieve this by providing best practice support, devising world-class concepts for our development projects, and by leading established corporate initiatives to improve performance.
Our 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. In 2009, we established a special purpose company, Energy Capital Management AS, to manage corporate venture activities. This move focuses on venture capital as a tool for accessing new technologies, and it will underpin Statoil's technology strategy and help to capitalise on today's ownership positions in the venture business. In addition, through the LOOP programme, Statoil helps suppliers to develop new, innovative products and services for our business.
Selected advances made in 2009 are summarised below:
Advanced seismic imaging for exploration
Major technological advances have been made for seismic imaging in complex geology. New state-of-the-art migration algorithms required to image sub-salt structures in the Gulf of Mexico and other salt provinces have been developed and qualified for use by the internal imaging teams in Norway and Houston. This new internal imaging capability will improve our capability in terms of defining sub-salt plays and prospects and maturing drillable prospects. This advance is a key short-term element in the exploration seismic imaging and interpretation initiative.
Through-tubing rotary drilling
New drilling and well technology developed by Statoil and FMC Technologies will improve oil recovery from subsea fields. The technology has now been successfully tested on the Åsgard field in the Norwegian Sea. This technology enables the reuse of old subsea wells in a simpler and more inexpensive way than before, by drilling a new well directly through the production tubing in an existing well. The technology is estimated to have a great potential to increase oil production from subsea fields.
Steerable liner drilling 9-5/8"
The steerable drilling liner concept had its first successful pilot on the Brage field in 2009. This technology improves the ability to drill in depleted reservoirs and unstable formations, and it is an important tool for drilling infill wells in mature fields.
Compact inline technology
A compact cyclonic oil/water and gas/liquid separation unit has been developed. Full-scale pilot testing was carried out on Gullfaks this year. This type of inline technology has multiple areas of application. It is an important tool in relation to succeeding with subsea processing in deep waters such as the Gulf of Mexico. It is excellent for de-bottlenecking and tie-ins to existing platforms, and it presents future opportunities for unmanned platforms. It is Statoil-owned technology, licensed to FMC.
Experience from mono ethylene glycol (MEG) regeneration systems
Results from the start-up and operation of the MEG system on Snøhvit and Ormen Lange have been summarised. The experience from these two MEG systems gives Statoil unique knowledge and understanding of the complex MEG chemistry and process, and it generates new ideas for how such systems can be improved to increase operational regularity.
Laboratory experiments for thermal extra-heavy oil recovery
An experimental rig has been constructed in Alberta, Canada to provide data for optimising the solvent co-injection process in order to reduce energy consumption (steam-oil ratio) and improve bitumen recovery efficiency compared with steam-assisted gravity drainage (SAGD). Two SAGD experiments have been successfully performed as part of providing the basis for studying solvent co-injection and developing expertise in this experimental technique. The solvent co-injection experiment has been completed, and the preliminary results are promising when compared with the two previous SAGD experiments. It is expected that solvent co-injection will reduce both CO2 emissions and water consumption. This has implications for both investments and operating costs.
Hot tapping
The world's deepest hot tap operation on a pressurised pipeline was performed on the Ormen Lange field in the Norwegian Sea in early August. Hot tapping operations involve carrying out repairs, replacements or tie-ins on pipelines that remain pressurised. That makes it possible to avoid expensive shutdowns and simplifies the tie-in of new pipeline systems to existing infrastructure.
Lander technology
Lander technology is an important contributor to the paradigm shift that is taking place in environmental monitoring. Depending on the communication systems (physical downloading of data, cable, communication buoys) and how the lander systems are powered (batteries or from our installations/from land), the multi-sensor platform can measure and send data in real-time. Since the landers serve as a platform, different sensors will be deployed depending on the nature of the actual activity of interest. So far, a lander has been deployed in Nordland VII for measurement of background information on physical and chemical condition in addition to measurement of biological fluxes.
3.6 Projects
3.6.1 Project development
Our projects portfolio is very diverse, ranging from new projects and improvements to existing assets to generating production growth on the NCS and supporting the company's ambitions to become a global energy player.
Completion of our two mega projects, Gjøa and Peregrino, will be our biggest milestones in 2010 and 2011. Moreover, several modification projects such as Statfjord Late Life involve optimising production from exisisting fields.
Project completions 2010 - 2011 |
Type |
NCS |
Gjøa |
Heidrun PPL upgrade |
|
Morvin |
|
Ormen Lange Southern Fields |
|
Oseberg C mud module |
|
Oseberg D Gas Treatment |
|
Oseberg D HRSG |
|
Oseberg F Low Pressure Production |
|
Sleipner A 10 bar inlet pressure |
|
Snorre A produced water upgrade |
|
Snorre A Re-development, |
|
Snorre B produced water upgrade |
|
Statfjord Late Life |
|
Tordis/Vigdis Control systems |
|
Troll A Living Quarter Extension |
|
Troll B gas injection |
|
Troll C Low Pressure Production |
|
Troll O2 Template, |
|
Troll P12 Pipeline |
|
Vega |
|
Visund Nord |
|
Åsgard Gas Transfer |
|
Onshore |
Energiverk Mongstad |
Statoil Mongstad Miljøinvestering (SMIL) |
|
Kårstø Double Inlet X-over (DIXO) |
|
Kårstø NGL Metering station |
|
Kollsnes projects |
|
International |
In Salah Gas Compression |
Leismer Demo |
|
Peregrino |
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 PRO's contributions in this respect are the Leismer Demonstration project and the In Salah Gas Compression.
If we are to build an international reputation as a world-class implementer of projects, the way in which we deliver results is as important as the results themselves. That means delivering on time and cost, and without compromising high HSE and ethical standards.
3.7 People and the group
Statoil's overall strategic objective is to build a globally competitive company and an exceptional place to perform and develop.
The financial and economic turmoil that characterised the global economy in 2009 has affected the entire industry, leading to a stronger focus on efficiency improvements and on the optimal use of existing resources. At the same time, the increase in business activities internationally requires Statoil to develop new capabilities to succeed globally and to attract talents in new countries.
We have recently reviewed our global people policies to ensure consistent common standards across groups. Together with our values and ethical code of conduct, our people policies are the most important guidelines for furthering the people processes.
3.7.1 Employees in Statoil
The Statoil group employs approximately 29,000 permanent employees in 40 countries, and more than 18,000 of them are employed in Norway, and approximately 11,000 were employed outside Norway. Of these, 9,399 were employed in the retail business.
In 2009, the Statoil group recruited almost 3,700 new employees, 50% were recruited to the retail organisation.
By the end of 2009, 35% were under the age of 35, 57% were between 35 and 55 years old, and 8% were 55 years or older. The table below provides an overview of the number of permanent employees and percentage of women in the Statoil group from 2007 to 2009.
|
Number of employees |
Women |
||||
Geographical Region |
2009 |
2008 |
2007 |
2009 |
2008 |
2007 |
|
|
|
|
|
|
|
Norway |
18,100 |
17,891 |
17,959 |
31% |
30% |
29% |
Rest of Europe |
9,593 |
10,475 |
10,151 |
50% |
47% |
46% |
Africa |
165 |
144 |
117 |
28% |
32% |
34% |
Asia |
150 |
169 |
144 |
55% |
54% |
52% |
North America |
584 |
448 |
315 |
34% |
39% |
33% |
South America |
147 |
102 |
72 |
48% |
53% |
53% |
|
|
|
|
|
|
|
TOTAL |
28,739 |
29,229 |
28,758 |
37% |
35% |
37% |
|
|
|
|
|
|
|
Non - OECD |
2,703 |
3,009 |
2,904 |
64% |
65% |
66% |
* Service station personnel are included
Geographical Region |
Permanent employees 2009 |
Consultants |
Total Workforce* |
Consultants** |
% of part time |
New hires |
|
|
|
|
|
|
|
Norway |
18100 |
5309 |
23409 |
23% |
4.5 |
1310 |
Rest of Europe |
9593 |
4556 |
14149 |
32% |
7.2 |
2113 |
Africa |
165 |
41 |
206 |
20% |
N/A |
29 |
Asia |
150 |
36 |
186 |
19% |
N/A |
13 |
North America |
584 |
281 |
865 |
32% |
N/A |
172 |
South America |
147 |
104 |
251 |
41% |
N/A |
62 |
|
|
|
|
|
|
|
TOTAL |
28739 |
10327 |
39066 |
26% |
N/A |
3699*** |
|
|
|
|
|
|
|
Non - OECD |
2703 |
314 |
3017 |
10% |
N/A |
288 |
|
|
|
|
|
|
|
*Total workforce consists of number of permanent employees and consultants |
|
|
|
|||
** Consultants do not include enterprise personnel |
|
|
|
|
|
|
*** 1843 of these were recruited to the retail business |
|
|
|
|
||
Statoil's low turnover rates reflect a high level of satisfaction and engagement among its employees, which is also supported by the results of the annual organisational and working environment survey. In Statoil ASA, the total turnover rate for 2009 was 0.73%. The figure below provides an overview of the total turnover rate by gender and age in Statoil ASA
3.7.2 Equal opportunities
We are committed to building a workplace that promotes diversity and inclusion through its people processes and practices.
In December 2009, the overall percentage of women in the company was 37%, and 40% of the board of directors were women, as were 22% of the corporate executive team. The focus on diversity issues is also reflected in the company's people strategy. One of the key priorities in 2009 has been to strengthen diversity in the leadership pipeline. The total proportion of female managers in Statoil ASA is 25%, and, among managers under the age of 45, the proportion is 34%.
Through our development programmes, we aim to increase the number of female managers, and we endeavour to give equal representation to men and women in leadership development programmes. In 2009, we worked systematically on the development, deployment and succession planning of business-critical leadership positions. Of leaders promoted to the top 170 roles in 2009, 47% were female. Of the 84 senior vice presidents in Statoil, 24% are female, while 35% of our successor pool for these roles are female.
We also devote close attention to male-dominated positions and discipline areas. In 2009, 26% of staff engineers were women, and among staff engineers with up to 20 years' experience, the proportion of women is 31%. The proportion of female skilled workers in 2009 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.
Cultural diversity
We believe that being a global and sustainable company requires people with a global mindset. One way to build a global company is to ensure that recruitment processes both within and outside Norway contribute to a culturally diverse workforce. In December 2009, 4% of the managers and 7% of the rest of our employees based in our Statoil offices in Norway are of non-Norwegian origin. 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.
3.7.3 Unions and representatives
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, 69% 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 2009, one of Statoil's cooperation priorities has been to improve relations with European employee representatives. The European Work Council (EWC) consists of employee representatives from nine European countries, mostly from the retail side of the business. 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 for this purpose in 2009.
Statoil is also currently party to an international agreement with the International Federation of Chemical, Energy, Mine and General Workers Union (ICEM). This agreement supports and facilitates Statoil's ambition to further promote and develop good employee and industrial relations on a broad global basis and its content reflects our policies and values on areas such as industrial relations, human rights and labour standards and HSE.
Since 2007, Statoil has undergone major organisational changes as a result of the merger between Statoil and Hydro's oil and gas division. In 2009, Statoil finalised the merger by implementing its new operating model on the Norwegian continental shelf, which affected 5000 offshore employees. The unions and the company agreed on the principles for the new collaboration model, which involve simplifying and decentralising the model.
3.7.4 Organisational structure
The following table shows significant subsidiaries owned directly by the parent company, as well as the parent company's equity interest and the subsidiaries' country of incorporation.
Our voting interest is in each case equivalent to our equity interest.
Ownership in certain subsidiaries (in %) |
|
|
|
|
|
Name |
% |
Country of |
Name |
% |
Country of |
SIA Statoil Latvija |
100 |
Latvia |
Statoil Norge AS |
100 |
Norway |
Statholding AS |
100 |
Norway |
Statoil Norsk LNG AS |
100 |
Norway |
Statoil AB |
100 |
Sweden |
Statoil North Africa Gas AS |
100 |
Norway |
Statoil Angola Block 15 AS |
100 |
Norway |
Statoil North Africa Oil AS |
100 |
Norway |
Statoil Angola Block 15/06 Award AS |
100 |
Norway |
Statoil North America Inc. |
100 |
United States |
Statoil Angola Block 17 AS |
100 |
Norway |
Statoil Orient AG |
100 |
Switzerland |
Statoil Angola Block 31 AS |
100 |
Norway |
Statoil Petroleum AS |
100 |
Norway |
Statoil Apsheron AS |
100 |
Norway |
Statoil Polen Invest AS |
100 |
Norway |
Statoil Azerbaijan AS |
100 |
Norway |
Statoil Sincor AS |
100 |
Norway |
Statoil BTC Finance AS |
100 |
Norway |
Statoil SP Gas AS |
100 |
Norway |
Statoil Coordination Centre NV |
100 |
Belgium |
Statoil UK Ltd |
100 |
United Kingdom |
Statoil Danmark AS |
100 |
Denmark |
Statoil Venezuela AS |
100 |
Norway |
Statoil Deutschland GmbH |
100 |
Germany |
Statoil Venture AS |
100 |
Norway |
Statoil Exploration Ireland Ltd. |
100 |
Ireland |
Statpet Invest AS |
100 |
Norway |
Statoil Forsikring AS |
100 |
Norway |
UAB Lietuva Statoil |
100 |
Lithuania |
Statoil Hassi Mouina AS |
100 |
Norway |
|
|
|
Statoil New Energy AS |
100 |
Norway |
Statoil Methanol ANS |
82 |
Norway |
Statoil Nigeria AS |
100 |
Norway |
Mongstad Refining DA |
79 |
Norway |
Statoil Nigeria Deep Water AS |
100 |
Norway |
Mongstad Terminal DA |
65 |
Norway |
Statoil Nigeria Outer Shelf AS |
100 |
Norway |
Tjeldbergodden Luftgassfabrikk DA |
51 |
Norway |
|
|
|
|
|
|
3.8 Production volumes and price information
Statoil's operational review is in accordance with the organisation of its operations, whereas certain disclosures about oil and gas reserves are based on geographical areas as required by the SEC.
Statoil prepares its operational review in accordance with its segment (business area) structure. Each business area is presented individually, and includes underlying business clusters according to how the business area organises its operations.
For further information on extractive activities, refer to sections 3.1 Operational review - E&P Norway and 3.2 Operational review - International E&P for descriptions of Exploration and Production Norway and International Exploration and Production, respectively.
Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures based upon geographical areas as required by the SEC. The geographical areas are defined by continent, and consist of Eurasia, Africa and the Americas. Relevant information is further split into Norway and Eurasia excluding Norway.
For further information on disclosures for oil and gas reserves and certain other supplemental disclosures based upon geographical areas as required by the SEC, refer to this section 3.8 Operational review - Production volumes and price information and 3.9 Operational review - Proved oil and gas reserves.
3.8.1 Entitlement production
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, or PSAs. 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 extra heavy oil from the field Petrocedeño in Venezuela is included as crude oil.
|
For the year ended 31 December |
||
Entitlement production |
2009 |
2008 |
2007 |
|
|
|
|
Norway |
|
|
|
Crude oil (mmbbls)1 |
279 |
302 |
299 |
Natural gas (bcf) |
1367 |
1348 |
1238 |
Natural gas (bcm) |
38.7 |
38.2 |
35.1 |
Combined oil and gas (mmboe) |
523 |
542 |
519 |
|
|
|
|
Eurasia excluding Norway |
|
|
|
Crude oil (mmbbls)1 |
19 |
n/a |
n/a |
Natural gas (bcf) |
49 |
n/a |
n/a |
Natural gas (bcm) |
1.4 |
n/a |
n/a |
Combined oil and gas (mmboe) |
28 |
n/a |
n/a |
|
|
|
|
Africa |
|
|
|
Crude oil (mmbbls)1 |
63 |
n/a |
n/a |
Natural gas (bcf) |
54 |
n/a |
n/a |
Natural gas (bcm) |
1.5 |
n/a |
n/a |
Combined oil and gas (mmboe) |
73 |
n/a |
n/a |
|
|
|
|
America |
|
|
|
Crude oil (mmbbls)1 |
20 |
n/a |
n/a |
Natural gas (bcf) |
48 |
n/a |
n/a |
Natural gas (bcm) |
1.4 |
n/a |
n/a |
Combined oil and gas (mmboe) |
29 |
n/a |
n/a |
|
|
|
|
Outside Norway |
|
|
|
Crude oil (mmbbls)1 |
n/a |
85 |
92 |
Natural gas (bcf) |
n/a |
121 |
114 |
Natural gas (bcm) |
n/a |
3.4 |
3.2 |
Combined oil and gas (mmboe) |
n/a |
106 |
112 |
|
|
|
|
Total |
|
|
|
Crude oil (mmbbls)1 |
381 |
386 |
391 |
Natural gas (bcf) |
1519 |
1469 |
1352 |
Natural gas (bcm) |
43.0 |
41.6 |
38.3 |
Combined oil and gas (mmboe) |
652 |
648 |
632 |
|
|
|
|
|
|
|
|
1) Crude oil includes natural gas liquids (NGL) and condensate. NGL includes both LPG and naphta. |
|
||
3.8.2 Average production cost and sales prices
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 2009, while this split is not available for prior periods.
|
Norway |
Outside Norway |
|
|
|
Year ended 31 December 2008 |
|
|
Average sales price liquids in USD per bbl |
91.5 |
88.7 |
Average sales price natural gas in NOK per Sm3 |
2.4 |
1.3 |
Average production cost in NOK per boe |
37.3 |
42.2 |
|
|
|
Year ended 31 December 2007 |
|
|
Average sales price liquids in USD per bbl |
70.9 |
69.1 |
Average sales price natural gas in NOK per Sm3 |
1.69 |
1.17 |
Average production cost in NOK per boe |
46.3 |
34.4 |
|
Norway |
Eurasia excluding Norway |
Africa |
America |
|
|
|
|
|
Year ended 31 December 2009 |
|
|
|
|
Average sales price liquids in USD per bbl |
57.8 |
58.2 |
57.8 |
61.7 |
Average sales price natural gas in NOK per Sm3 |
1.9 |
0.6 |
1.4 |
0.9 |
Average production cost in NOK per boe |
36.9 |
55.2 |
40.9 |
45.3 |
3.9 Proved oil and gas reserves
Proved oil and gas reserves were estimated to be 5408 mmboe at the end of 2009, compared with 5584 mmboe at the end of 2008.
Proved reserves and changes in proved reserves are estimated in accordance with SEC definitions. As of 31 December 2009 Statoil's estimates reflect the revisions to Rule 4-10 of SEC Regulation S-X on the definitions of reserves. For additional information see "Critical accounting judgements and key sources of estimation uncertainty; Proved oil and gas reserves" in note 2 Significant accounting policies to the consolidated financial statements. For prior period figures, see note 35 Supplementary oil and gas information to the consolidated financial statements. The reserves replacement ratio is defined as the sum of additions and revisions of proved reserves, divided by produced volumes in any given period.
Summary of oil and gas reserves as of 31 December 2009 based on average fiscal-year prices.
|
Proved reserves |
||
|
Oil and NGL |
Natural Gas |
Total oil and gas |
Reserves category |
(mmbbls) |
(bcf) |
(mmboe) |
|
|
|
|
Developed |
|
|
|
Norway |
1,028 |
14,138 |
3,548 |
Eurasia excluding Norway |
94 |
523 |
187 |
Eurasia |
1,122 |
14,661 |
3,735 |
Africa |
208 |
256 |
254 |
America |
111 |
73 |
124 |
|
|
|
|
Undeveloped |
|
|
|
Norway |
322 |
2,800 |
821 |
Eurasia excluding Norway |
44 |
224 |
84 |
Eurasia |
366 |
3,024 |
905 |
Africa |
102 |
83 |
116 |
America |
265 |
51 |
274 |
|
|
|
|
Total proved reserves |
2,174 |
18,148 |
5,408 |
Changes in proved reserves estimates most commonly originate from revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or the inclusion of proved reserves in new discoveries through the sanctioning of development projects. These are sources of additions to proved reserves that result from continuous business processes and could be expected to continue to add reserves at some level in the future. Proved reserves can also be added or subtracted through acquisitions or disposals 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 2009 have been determined based on a 12 month average price, whereas proved reserves for previous years 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's proved oil and gas reserves under PSAs and similar contracts will generally decrease as a result. Statoil will receive smaller quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of increased oil and gas prices. These changes are included in the revisions category in the table below.
In Norway, reserves are booked as proved when a development plan is submitted, since there is reasonable certainty that such a plan will be approved by the regulating authorities. Outside of Norway, reserves are booked as proved when regulatory approval is received, or when such approval is imminent. New discoveries with reserves booked in 2009 all start production in the period from 2009 to 2013. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years.
Additions that have contributed to our proved reserves in 2009 are:
Extension and discoveries that have increased our proved reserves in 2009 are:
- The Goliat field in the Bartents Sea in Norway, Kizomba satellites phase 1 in Angola and the Caesar Tonga Unit in Gulf of Mexico, USA, were sanctioned in 2009.
- The Beta Vest structure, an extension to the Sleipner Vest field, proved hydrocarbons by drilling in 2009.
- The Gimboa field in Angola commenced test production in April 2009.
- The PSVM development in Angola was approved by the concessionaire in 2008 and is carrying proved reserves in 2009.
- The Marcellus Shale Gas play in the USA, part of our gas value chain strategy, carries proved reserves in 2009.
Approval of future development plans for several of our producing fields on the NCS has contributed positively to revision of proved reserves:
- On the Oseberg field, a decision to upgrade existing drilling facilities allows for more wells to be drilled, resulting in increased reserves.
- On the Rimfaks field, a decision of pressure depleting the Brent reservoir has increased the reserves.
- On the Kvitebjørn field, a project has been approved that will allow for production at lower reservoir pressure through installation of a compressor module, thereby increasing the reserves.
In December 2008, the SEC issued new rules for reporting of oil and gas reserves by revising the definition of proved reserves. The technical aspects of the new rules have affected our proved reserves from certain fields:
- At the Kai Kos Dehseh leases in the Athabascan area in Canada, the Leismer Demonstration Project is able to book proved reserves for the first time, referring to several analogous reservoirs in the Athabascan area where reserves are currently produced using the SAGD technology. The project was sanctioned in 2008 and is scheduled to start production in 2010.
- Future extension of the licence period is now assumed reasonably certain on the NCS, increasing the proved reserves for certain fields.
- Some fields, previously limited by lowest known hydrocarbons, have been included in the proved reserves based on a lower contact established with reasonable certainty based on reliable technology.
The effect of the new rules on our total proved reserves is however immaterial and is estimated to be less than 2%. This estimate includes the effect of the change in product price to be used, from year end price to a 12 month average price.
Below is a table showing the reserves additions in each change category relating to the reserve replacement ratio for the years 2009, 2008 and 2007.
|
For the year ended 31 December |
||
(million boe) |
2009 |
2008 |
2007 |
Revisions and improved recovery |
326 |
213 |
325 |
Extensions and discoveries |
155 |
17 |
215 |
Purchase of petroleum-in-place |
0 |
69 |
0 |
Sales of petroleum-in-place |
(4) |
(10) |
0 |
Change in interest * |
0 |
(68) |
0 |
Total reserve additions |
476 |
222 |
541 |
Production |
(652) |
(648) |
(632) |
Net change in proved reserves |
(176) |
(426) |
(91) |
|
|
|
|
* Reduction of interest in Petrocedeño |
|
|
|
The reserves replacement ratio was 73% in 2009, compared with 34% in 2008. The increase in the reserves replacement ratio in 2009 compared with 2008 is mainly due to 2009 being a year with more reserves additions from new fields and sanctioned future development plans for producing fields. The average replacement rate for the last three years was 64%, including purchases, sales and reduction of the shareholding in Petrocedeño in 2008.
|
For the year ended 31 December |
||
Reserves replacement ratio (three-year average) |
2009 |
2008 |
2007 |
Corporate |
0.64 |
0.60 |
0.81 |
The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity related to the timing of project sanctions, and the time lag between exploration expenditure and booking of reserves.
Preparation of reserves estimates
Statoil's annual proved reserves reporting process is coordinated by a central group of experts. This group is called Corporate Exploration and Production Forecasting (CEPF) and consists of experts within geosciences, reservoir and production technology and financial evaluation with on average more than 20 years of experience from the oil and gas industry. The CEPF group reports to the Vice President of Finance and Control in the Technology and New Energy business area and is thus independent of both E&P Norway and the International E&P business areas.
Although this group reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. 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 required reporting level by CEPF.
The aggregated results are brought forward for approval to relevant Business Area management teams and the corporate executive committee and finally presented to the board of directors.
The technical person primarily responsible for overseeing the preparation of the reserves estimates is the manager of the CEPF group. The person who presently holds this position has a Bachelor's Degree in Earth sciences from the University of Gothenburg, and a Master's degree in Petroleum Exploration and Exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 24 years of experience in the oil and gas industry of which 23 are within Statoil. She is a member of the Norwegian Petroleum Society and a vice chairperson of the UNECE Expert Group on Resource Classification (EGRC).
Development of reserves
Total quantity of proved undeveloped oil and gas reserves as of 31 December 2009 was 1 295 mmboe of which 63% is related to fields in Norway. Significant undeveloped reserves are related to large gas fields on the NCS with continuous development activity, such as Troll, Snøhvit, Tyrihans, Visund and Ormen Lange.
Due to the nature of large fields with continuous development activity such as Troll and Snøhvit in Norway, Azeri-Chirag-Gunashli in Azerbaijan and Petrocedeño in Venezuela, these fields contain reserves that remain undeveloped for five years or more. The Troll phase 3 development activity includes start-up of production from additional wells in 2024 while the Snøhvit development activity includes start-up of production from additional wells in the Askeladden structure in 2017, both to maintain the plateau production. The development activity for Azeri-Chirag-Gunashli and Petrocedeño include continuous drilling beyond 2015.
Fields under development but not yet in production, such as Skarv, Gjøa and Goliat in Norway, CaesarTonga in GoM USA, Corrib in Ireland, Leismer Demonstration Project in Canada, Peregrino in Brazil and Kizomba satellites in Angola represent approximately 30% of the total proved undeveloped reserves at year end 2009.
The sanctioning of new projects such as CaesarTonga in the GoM and Marcellus in the USA, Goliat in Norway, the Leismer Demonstration Project in Canada and the Kizomba satellites and PSVM in Angola added a total of 128 mmboe of proved undeveloped reserves in 2009. Start of production and further development of producing fields contributed to converting reserves from undeveloped to developed. The net change in proved undeveloped reserves during 2009 represents a reduction of 60 mmboe.
Start of production from the fields Alve, Yttergryta and Tyrihans in Norway, Tahiti and Thunder Hawk in GoM USA, Marcellus in USA and Gimboa in Angola increased our developed reserves by 224 mmboe in 2009. Most of this increase came from converting undeveloped reserved into developed reserves.
In 2009 Statoil incurred NOK 56.9 billion in development costs related to assets carrying proved reserves, of which NOK 29.9 billion were related to moving proved undeveloped reserves to developed.
Additional information about proved oil and gas reserves is provided in note 35 - Supplementary oil and gas information - to our Consolidated Financial Statements.
Delivery commitments
From the Norwegian Continental Shelf (NCS) Statoil is required, on behalf of the Norwegian State's direct financial interest (SDFI), to manage, transport and sell the Norwegian State's oil and gas. These reserves are sold in conjunction with our own reserves. As part of this arrangement, Statoil will deliver gas to customers in accordance with various types of sales contracts. In order to fulfil the commitments, Statoil will utilise a field supply schedule which provides the highest possible total value for the joint portfolio of oil and gas between Statoil and SDFI.
As at 31 December 2009, the Statoil/SDFI arrangement amounted to a total of 29.5 tcf (835 bcm) in total expected gas commitments on the NCS. The principles for booking of proved reserves are limited to contracted gas sales or gas with access to a robust gas market.
The majority of Statoil's gas volumes are sold under long term contracts with Take or Pay clauses. For each individual year, Statoil and SDFI express their delivery commitments as the sum of the Annual Contract Quantity (ACQ). In the contract years 2009 to 2012, the joint ACQ for the respective years are; 2.50, 2.43, 2.39, and 2.40 tcf. The majority of delivery commitments will be fulfilled by production from our existing proved reserves from fields where Statoil and/or SDFI participates, while any shortfalls would be covered by sourcing existing gas markets.
3.9.1 Operational statistics
Operational statistics include information about acreage and the number of wells drilled.
Productive oil and gas wells and developed and undeveloped acreage
The following tables show the number of gross and net productive oil and gas wells and total gross and net developed and undeveloped oil and gas acreage in which Statoil had interests at 31 December 2009.
A "gross" value reflects wells or acreage in which Statoil has interests (presented as 100%). The net value corresponds to the sum of whole or fractional working interest for Statoil in gross wells or acreage.
At 31 December 2009 |
|
Norway |
Eurasia excluding Norway |
Africa |
America |
Total |
Number of productive oil and gas wells |
|
|
|
|
|
|
Oil wells |
— gross |
813 |
140 |
305 |
472 |
1,730 |
|
— net |
294.0 |
19.3 |
32.7 |
48.2 |
394.2 |
Gas wells |
— gross |
159 |
49 |
49 |
58 |
315 |
|
— net |
68.5 |
16.6 |
18.0 |
17.5 |
120.6 |
The total gross number of productive wells as of end 2009 includes 340 oil wells and 16 gas wells with multiple completions or wells with more than one branch.
At 31 December 2009 (in thousands of acres) |
Norway |
Eurasia excluding Norway |
Africa |
America |
Total |
|
Developed and undeveloped oil and gas acreage |
|
|
|
|
|
|
Acreage developed |
— gross |
763 |
198 |
815 |
146 |
1,922 |
|
— net |
277 |
52 |
258 |
17 |
604 |
Acreage undeveloped |
— gross |
13,843 |
12,012 |
30,921 |
10,439 |
67,215 |
|
— net |
6,181 |
6,266 |
20,398 |
4,723 |
37,568 |
Net productive and dry oil and gas wells drilled
The following tables show the net productive and dry exploratory and development oil and gas wells completed or abandoned by Statoil in the past three years. The 2009 information is split by continent, whereas this split is not available for prior years. Productive wells include wells in which hydrocarbons were found, and the drilling or completion of which, in the case of exploratory wells, has been suspended pending further drilling or evaluation. A dry well is one found to be incapable of producing sufficient quantities to justify completion as an oil or gas well.
Year 2009 |
Norway |
Eurasia excluding Norway |
Africa |
America |
Total |
Net productive and dry exploratory wells drilled |
21.3 |
0.9 |
4.4 |
2.8 |
29.3 |
— Net dry exploratory wells drilled |
9.6 |
0.3 |
2.1 |
1.0 |
13.0 |
— Net productive exploratory wells drilled |
11.7 |
0.6 |
2.2 |
1.8 |
16.3 |
|
|
|
|
|
|
Net productive and dry development wells drilled |
25.7 |
4.6 |
8.1 |
13.9 |
52.3 |
— Net dry development wells drilled |
1.2 |
0.4 |
0.7 |
0.0 |
2.3 |
— Net productive development wells drilled |
24.5 |
4.2 |
7.3 |
13.9 |
50.0 |
|
|
Norway |
Outside Norway |
Total |
|
|
|
|
|
Year 2008 |
|
|
|
|
Net productive and dry exploratory wells drilled |
|
26.1 |
12.1 |
38.2 |
— Net dry exploratory wells drilled |
|
7.2 |
5.8 |
13.0 |
— Net productive exploratory wells drilled |
|
18.9 |
6.3 |
25.2 |
|
|
|
|
|
Net productive and dry development wells drilled |
|
27.9 |
23.7 |
51.6 |
— Net dry development wells drilled |
|
0.5 |
0.0 |
0.5 |
— Net productive development wells drilled |
|
27.4 |
23.7 |
51.1 |
|
|
|
|
|
Year 2007 |
|
|
|
|
Net productive and dry exploratory wells drilled |
|
13.2 |
14.0 |
27.1 |
— Net dry exploratory wells drilled |
|
4.5 |
5.9 |
10.4 |
— Net productive exploratory wells drilled |
|
8.7 |
8.0 |
16.7 |
|
|
|
|
|
Net productive and dry development wells drilled |
|
34.7 |
19.7 |
54.4 |
— Net dry development wells drilled |
|
0.7 |
1.0 |
1.7 |
— Net productive development wells drilled |
|
34.0 |
18.7 |
52.7 |
Related to our oil sand development in the Athabasca region of Alberta we also drilled 48 wells in 2009 to delineate the bitumen pay. All of these wells were drilled, logged, cored and abandoned. We also drilled 15 water wells in which we were searching for suitable source or disposal water zones. Some of these were abandoned and some completed for water needs.
Exploratory and development drilling in process
The following table shows the number of exploratory and development oil and gas wells in the process of being drilled by Statoil at 31 December 2009.
At 31 December 2009 |
|
Norway |
Eurasia excluding Norway |
Africa |
America |
Total |
Number of wells in progress |
|
|
|
|
|
|
Developement Wells |
— gross |
35 |
7 |
11 |
111 |
164 |
|
— net |
15.3 |
1.0 |
2.6 |
58.6 |
77.5 |
Exploratory Wells |
— gross |
4 |
- |
1 |
6 |
11 |
|
— net |
1.8 |
- |
0.1 |
2.1 |
4.0 |
3.9.2 Report of DeGolyer and MacNaughton
Statiol's estimates of proved reserves are not materially different from those prepared by independent petroleum engineering consultants.
DeGolyer and MacNaughton, petroleum engineering consultants, have performed an independent evaluation of Statoil's proved reserves as of 31 December 2009. The evaluation accounts for 100 % of Statoil's proved reserves. The aggregated net proved reserves estimates prepared by DeGolyer and MacNaugthon do not differ materially from those prepared by Statoil when compared on the basis of net equivalent barrels.
Net proved reserves at 31 December 2009 |
Oil, Condensate and LPG |
Sales Gas |
Oil Equivalent |
Estimated by Statoil |
2,174 |
18,148 |
5,408 |
Estimated by DeGolyer and MacNaughton |
2,284 |
18,274 |
5,540 |
A reserves report summarising this evaluation is included as Exhibit 15(a)(iii).
3.10 Regulation
The principal Norwegian legislation governing our petroleum activities in Norway consists of 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, as well as the Norwegian Petroleum Taxation Act of 13 June 1975 (the "Petroleum Taxation Act"). The Petroleum Act states 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 power to administer the award of licences and approve operators' field and pipeline development plans, as well as petroleum transport and gas sales contracts. Only those plans that conform to the policies and regulations 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 with respect to major policy issues in the petroleum sector may 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:
- The Norwegian State held 67% of our ordinary shares as of 12 March 2010. The Norwegian State's shareholding in Statoil is managed by the Ministry of Petroleum and Energy. The Ministry of Petroleum and Energy will normally decide how the Norwegian State will vote on proposals submitted to general meetings of the shareholders. However, in certain exceptional cases, it may be necessary for the Norwegian State to seek approval from the Storting before voting on a certain proposal. This will normally be the case if we issue additional shares and such issuance would significantly dilute the Norwegian State's holding, or if such issuance would require a capital contribution from the Norwegian State in excess of government mandates. It is not possible to predict what stance the Norwegian Storting will take on a proposal for issuance of additional shares that would either significantly dilute its holding of Statoil shares or require a capital contribution from it in excess of governmental mandates. A decision by the Norwegian State against our proposal to issue additional shares would prevent us from raising additional capital in this manner and could adversely affect our ability to pursue business opportunities and to further develop the company.
- The Norwegian State exercises important regulatory powers over us, as well as over other companies and corporations. As part of our business, we, or the partnerships to which we are a party, frequently need to apply for licences and other approval of various kinds from the Norwegian State. In respect of certain important applications, such as the approval of major plans for operation and development of fields, the Ministry of Petroleum and Energy must obtain the consent of the Storting before it can approve our or the relevant partnership's application. This may take additional time and affect the content of the decision. Although Statoil is majority-owned by the Norwegian State, it does not receive preferential treatment with respect to licences granted by or under any other regulatory rules enforced by the Norwegian State.
Although Norway is not a member of the European Union, or EU, it is a member of the European Free Trade Association (EFTA). The EU and its member states have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, with the members of EFTA (except Switzerland).
The EEA Agreement makes certain provisions of EU law binding 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.
3.10.1 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 power to award a production licence and to decide the terms of that licence.
In 2009, we participated in 222 production 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 power 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 report section 3.1.4 Operational review - E&P Norway - Production on the NCS.
Production licences are normally awarded through licensing rounds. The first licensing round for NCS production licences was announced in 1965. The award of the first licences covered areas in the North Sea. Over the years, the awarding of licences has moved northward and covers areas in both the Norwegian Sea and the Barents Sea. In recent years, the principal licensing rounds have mainly included licences in the Norwegian Sea. Beginning in 2003, the Norwegian government changed its policy on mature areas and introduced a scheme for awarding production licences called "Award in Predefined Areas" (APA) in mature parts of the Norwegian continental shelf. The awarding of licences in the predefined areas has taken place every year since 2003. In a report to the Storting, the Ministry of Petroleum and Energy has announced that this policy will continue.
The Norwegian State accepts licence applications from individual companies and group applications. This allows us to choose our exploration and development partners.
Production licences are awarded to joint ventures. As is the case for most fields on the NCS, our production activities are conducted through joint venture arrangements with other companies and in some cases with the Norwegian State through its wholly-owned company Petoro. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the 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. Each member is entitled to one seat on the management committee. The management committee's tasks are set out in the joint operating agreement and include setting guidelines for the operator of the field, exercising control over the activities of the operator, and making decisions on the activities of the joint venture. Votes in the management committee are counted by a combination of the number of members in the joint venture and their ownership interests. The number of votes required to make a decision varies from licence to licence, but a decision is normally reached when a certain number of the members and a percentage of the ownership interests, specified individually in each licence, have voted in favour of a proposal. The voting rules are structured so that a licensee holding more than 50% of a licence normally cannot vote through a proposal on its own, but will need the support of one or more of the other licensees. In licences awarded since 1996 where the SDFI holds an interest, the Norwegian State, acting through the SDFI management company, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the licence with respect to the Norwegian State's exploitation policies or financial interests. This veto power has never been used.
Under the joint operating agreements covering licences awarded prior to 1996, the management company that supervises the Norwegian State's SDFI interest, Petoro AS, has the power, with certain exceptions, to make decisions unilaterally in matters that are assumed to be of a political nature or matters of principle, or which may have significant social or socio-economic consequences, if Petoro AS is acting under the direction of its shareholder. Prior to the establishment of the SDFI management company, Statoil held this right, which was exercised three times, most recently in 1988. In autumn 2002, the Storting began to allow individual licence groups to substitute this special voting rule for the SDFI with a veto rule similar to the veto rules that have applied to licences awarded since 1996. Such substitution is subject to the approval of the Ministry of Petroleum and Energy.
The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. In 2009, we were the operator for 42 of our 48 production licences. The operator is in practice always a member of the joint venture holding the production licence, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement. Under the joint operating agreement, an operator can normally terminate its engagement at 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 at six months' notice on an affirmative vote by all members of the management committee other than the operator. A change of operator requires the consent of the Ministry of Petroleum and Energy. In special cases, the Ministry of Petroleum and Energy can order a change of operator.
Licensees are required to submit a plan for development and operation, or PDO, to the Ministry of Petroleum and Energy for approval. In respect of fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Until the PDO has been approved by the Ministry of Petroleum and Energy, the licensees cannot, without the prior consent of the Ministry of Petroleum and Energy, undertake material contractual obligations or commence construction work.
Production licences are normally awarded for an initial exploration period, which is typically six years, but 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 the licence does not apply to the whole of the geographical area covered by the initial licence, but only to a percentage, 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. From 15 July 1987 until the end of 1989, licensees were directed to curtail oil production by 7.5%. Between 1 January 1990 and 30 June 1990, licensees were directed to curtail oil production by 5%. In 1998, the Norwegian State resolved to reduce Norwegian oil production by about 3%, or 100 mbbl per day. In March 1999, the Norwegian State decided to further increase the reduction to 200 mbbl per day. In the second quarter of 2000, the reduction was again set to 100 mbbl per day. On 1 July 2000, this restriction was removed. By a Royal Decree of 19 December 2001, the Norwegian government decided that Norwegian oil production would be reduced by 150 mbbl per day from 1 January 2002 until 30 June 2002. This amounted to a reduction in output of approximately 5%.
Licensees may buy or sell interests in production licences subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of 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. Except from one minor transaction which is still pending approval, all of our licencing transactions entered into in 2009 were approved by the Ministry of Petroleum and Energy and Ministry of Finance.
A licence from the Ministry of Petroleum and Energy is also required in order to establish facilities for the transport and utilisation of petroleum. When applying for such licences, the owners, which are in practice licensees under a production licence, must prepare a plan for installation and operation. Licences for the establishment of facilities for transport 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 transport and utilisation of petroleum in Norway and on the NCS are organised as joint ventures of a group of licence holders, and the participants' agreements are similar to the joint operating agreements entered into by the members of joint ventures holding production licences. All of our applications for facility licences submitted in 2009 have been granted by the Ministry of Petroleum and Energy.
Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for the transportation and 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 the cessation of the use of the facility, and it must include a proposal for the disposal of facilities on the field. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.
The Norwegian State is entitled to take over the fixed facilities of the licensees when a production licence expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with the expropriation of private property apply. None of our production licences expired in 2009 and none are due to expire in 2010.
Licences for the establishment of facilities for transport 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.
3.10.2 Gas sales and transportation
We market gas from the Norwegian continental shelf on our own and the Norwegian state's behalf. Gas is transported through the Gassled pipeline network to customers in Europe.
Gas sales contracts with buyers for the supply of Norwegian gas are concluded individually with each company.
The upstream gas transportation system consists of several pipelines owned by a joint venture called Gassled. We have a 32.102% direct ownership interest in Gassled (32.881% including our indirect interest through our 28.58% holding in Norsea Gas AS) and are responsible for technical operation of the majority of the gas export pipelines and onshore plants in the Gassled processing and transportation system. See section 3.3.3 Operational review-Natural Gas-Norway's gas transport 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. There are three main considerations behind the regulations. Firstly, together with the Act adopted by the Storting in June 2002, the regulations implement the Gas Directive of the European Union. Secondly, they established a system for access to the upstream gas transportation system that is compatible with company-based gas sales from the NCS. Thirdly, they provided for the new ownership structure of the upstream gas transportation system (Gassled).
Parts of the regulations have 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 needs for the transport of natural gas. Furthermore, the access regime consists of a secondary market where capacity can be transferred between users after the 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 the 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 actually transported volume.
3.10.3 The EU Gas Directive
The EU Gas Directive, which has been included in the EEA Agreement and incorporated into Norwegian legislation, regulates the European gas market in conjunction with the Gas Transmission Access Regulation of 2005.
Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that 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 subject to a material change in gas prices as a result of the regulations under the EU Gas Directive.
The Directive requires that, with effect from July 2007, all consumers in Europe should be able to choose their energy supplier. Fundamental changes to this directive were adopted by the European Union in July 2009 and will enter into force in EU in March 2011 (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.
3.10.4 HSE regulation
Our petroleum operations in Norway are subject to extensive regulation with regard to health, safety and the environment, or HSE.
Under the Petroleum Act, which is administered by the Ministry of Petroleum and Energy, our petroleum operations must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of employees, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained and developed in accordance with technological developments. Statoil established a system for monitoring the technical safety of its facilities and plants in 2001, and, as part of this system, it collects and interprets information from its operating activities and incorporates risk management into its operating activities.
We are required at all times to maintain a plan to deal with emergency situations in our petroleum operations. During an emergency, the Ministry of Labour, the Ministry of Fisheries and 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 account of the licensees.
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 facilities.
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 level of damages to a level it considers reasonable.
3.10.5 Taxation of Statoil
We are subject to ordinary Norwegian corporate income tax as well as to a special petroleum tax relating to our offshore activities. We are also subject to a special carbon dioxide emissions tax and a nitrogen oxide fee.
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
Our profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. The corporate income tax rate is currently 28%. Our profits are computed in accordance with ordinary Norwegian corporate income tax rules, subject to certain modifications that apply to companies engaged in petroleum operations. Gross revenue from oil production and the value of lifted stocks of oil are determined on the basis of norm prices. Norm prices are decided on a monthly basis by the Petroleum Price Board, a body whose members are appointed by the Ministry of Petroleum and Energy, and published quarterly. The Petroleum Taxation Act states that the norm prices shall correspond to the prices that could have been obtained in a sale of petroleum between independent parties in a free market. When adopting norm prices, the Petroleum Price Board takes a number of factors into consideration, including spot market prices and contract prices in the industry.
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 average interest-bearing debt. All other financial costs and income are allocated to the onshore tax regime.
Any tax losses may be carried forward indefinitely against subsequent income earned. Fifty percent of losses relating to activity conducted onshore in Norway may be deducted from NCS income subject to the 28% tax rate. Losses 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 the 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 amounts 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. Exemptions 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
A special petroleum tax is levied on profits from petroleum production and pipeline transportation on the NCS. The special petroleum tax is currently levied at a rate of 50%. The special tax is applied to relevant income in addition to standard 28% income tax, resulting in a 78% marginal tax rate on income subject to petroleum tax. The basis for computing the special petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible from the special petroleum tax, and a tax-free allowance, or uplift, is granted at a rate of 7.5% per year. The uplift is computed on the basis of the original capitalised cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditure is incurred. Unused uplift may be carried forward indefinitely.
Abandonment costs
Abandonment costs incurred can be deducted as operating expenses. Provisions for future abandonment costs are not tax deductible.
Carbon dioxide emissions tax
A special carbon dioxide emissions tax applies to petroleum activities on the NCS. The tax is NOK 0.46 for 2009 and NOK 0.47 for 2010 per standard cubic metre of gas burned or directly released and per litre of oil burned. In addition, companies operating on the NCS have to buy allowances to cover the carbon dioxide emissions from the petroleum activities.
Nitrogen oxide emissions tax
With effect from 1 January 2007, the Norwegian government introduced a nitrogen oxide tax applicable to emissions of nitrogen oxide on the NCS. The fee is NOK 15.85 per kilogram of nitrogen oxide for 2009 and NOK 16.14 for 2010.
As an alternative to paying the nitrogen oxygen fee, companies can voluntarily agree to contribute to an industry nitrogen oxygen fund for the years 2008-2010. The contribution to the fund is NOK 11 per kilogram of nitrogen oxide emissions. We have entered into an agreement to contribute to the fund.
Area fee
After the expiry of the initial exploration period, the holders of production licences are required to pay an area fee. The amount of the area fee is set out in regulations issued under the Petroleum Act. In respect of most of the production licences, the initial annual area fee is currently NOK 30,000 per square kilometre. For the subsequent year the fee is increased to NOK 60,000 per square kilometre and thereafter the yearly fee is increased to NOK 120,000 per square kilometre. Production licences for which a plan for development and operation (PDO) has been submitted are, from the time of submission of the PDO and for as long as extraction from the deposit takes place, exempt from the obligation to pay the area fee for the area defining the deposits included in the PDO.
Taxation outside Norway
Statoil's international petroleum activities are subject to tax pursuant to local tax legislation. Fiscal regulation of our upstream operations is generally based on corporate income tax regimes and/or production sharing agreement (PSA) regimes. Royalties may be applicable in each regime.
Generally, income from 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
Under a PSA, the host government typically retains the right to the hydrocarbons in place. Under a PSA, the contractor normally receives a share of the oil produced to recover its costs, and is also entitled to an agreed share of the oil as profit. The allocation of profit oil between the state and the contractors is typically increasingly based on a success factor, such as surpassing certain specified internal rates of return, production rates or accumulated production. Normally, the contractors carry the exploration costs and risk prior to a commercial discovery and are then entitled to recover those costs during the producing phase. Fiscal provisions in a PSA contract are to a large extent negotiable and are unique to each PSA. Parties to a PSA are generally insulated from legislative changes in a country's general tax laws.
Income tax regimes
Under an income tax/royalty regime, companies are granted licences by the government to extract petroleum, and the state may be entitled to royalties in addition to tax based on the company's net taxable income from production. In general, the fiscal terms surrounding these licences are not negotiable and the company is subject to legislative changes to the tax laws.
3.10.6 The Norwegian state's participation
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 us. 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.
As a result of changes in global markets and competitive conditions in the petroleum industry, the Norwegian State carried out a strategic review of its oil and gas policy in 2000. Based on the results of this strategic review, the Norwegian State prepared a plan to restructure its petroleum holdings on the NCS that was approved by the Storting on 26 April 2001. The key elements of the restructuring plan led to:
- the partial privatisation of Statoil
- restructuring of the Norwegian State's SDFI assets, including the sale of SDFI assets to us and to other oil and gas companies, and an exchange of interests in certain oil and gas infrastructure between the SDFI and us
- the establishment of procedures to ensure that, as long as the Norwegian State instructs us to do so, we will continue to market and sell the State's oil and gas, together with our oil and gas
- the transfer of responsibility for and management of the SDFI's assets from us to a new company called Petoro AS, which is wholly owned by the Norwegian State; and
- the transfer of operational responsibility for certain pipelines on the NCS from us to Gassco AS, which is wholly owned by the Norwegian State.
3.10.7 Marketing and sale of SDFI oil and gas
Historically, we have marketed and sold the Norwegian State's oil and gas as part of our own production, and the Norwegian State has elected to continue this arrangement.
Accordingly, at an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article 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 instructions referred to in the new article. This resolution is referred to as the owner's instruction.
The Norwegian State has a coordinated ownership strategy 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, which contains a general requirement that, in our activities on the NCS, we are required to take account of these ownership interests in decisions that may affect the execution of this marketing arrangement.
The owner's instruction sets forth specific terms for the marketing and sale of the Norwegian State's oil and gas. The principal provisions of the owner's instruction are set out below.
Objectives
The overall objective of the marketing arrangement is to obtain the highest possible total value for our oil and gas and the Norwegian State's oil and gas and to ensure an equitable distribution of the total value creation between the Norwegian State and us. In addition, the following considerations are important:
- to create the basis for long-term and predictable decisions concerning the marketing and sale of the Norwegian State's oil and gas;
- to ensure that results, including costs and revenues related to our oil and gas and the Norwegian State's oil and gas, are transparent and possible to measure; and
- to ensure efficient and simple administration and execution.
Our tasks
Our tasks under the owner's instruction are to market and sell the Norwegian State's oil and gas and to carry out all necessary tasks, other than those carried out jointly with other licensees under the production licence, relating to the marketing and sale of the Norwegian State's oil and gas, including, but not limited to, responsibility for processing, transport and marketing. In the event that the owner's instruction is terminated, in whole or in part, by the Norwegian State, the owner's instruction provides for a mechanism under which contracts for the marketing and sale of the Norwegian State's oil and gas to which we are a party may be assigned to the Norwegian State or its nominee. Alternatively, the Norwegian State may require that the contracts be continued in our name, but that, in the underlying relationship between the Norwegian State and us, the Norwegian State has all rights and obligations related to the Norwegian State's oil and gas.
Costs
The Norwegian State does not pay us a specific consideration for executing these tasks, but the Norwegian State reimburses us for its proportionate share of certain costs, which, under the owner's instruction, may be our actual costs or an amount specifically agreed.
Price mechanisms
For sales of the Norwegian State's natural gas, both to us and to third parties, the payment to the Norwegian State is based on either achieved prices, a net back formula or market value. We now purchase all of the Norwegian State's oil and NGL. Pricing of the crude oil is based on market reflective prices. NGL prices are based on either achieved prices, market value or market reflective prices.
Lifting mechanism
As part of the coordinated ownership strategy, a lifting mechanism for the Norwegian State's and our oil and gas is established in accordance with rules set out in the owner's instruction.
To ensure neutral weighting between the Norwegian State's and our own natural gas volumes, a list has been established for deciding the priority between each individual field. To decide the ranking, a mathematical optimisation model is used that describes existing and planned production facilities, infrastructure and processing terminals in which the Norwegian State and we have ownership interests. The list yields a result giving the highest total net present value for the Norwegian State's and our oil and gas. In the evaluation, the following objective criteria shall apply:
- the effect of the draw on the depletion rate
- identification of time-critical fields
- influence on oil/liquid fields with associated gas requiring gas disposal; and
- spare capacity and flexibility in transportation systems and onshore facilities.
The various fields are ranked in accordance with the assumed total value creation for the Norwegian State and us, assuming all of the fields meet our profitability requirements if we participate as a licensee, and the Norwegian State's profitability requirements if the State is a licensee. The list is updated annually or more frequently if events occur that may significantly influence the ranking. Within each individual field in which both the Norwegian State and we are licensees, the Norwegian State and we will deliver volumes and share income in accordance with our respective participating interests.
The Norwegian State's oil and NGL are lifted together with our oil and NGL in accordance with applicable lifting procedures for each individual field and terminal.
Withdrawal or amendment
The Norwegian State may at any time utilise its position as majority shareholder of Statoil to withdraw or amend the instruction requiring us to market and sell the SDFI oil and natural gas together with our own.
3.10.8 Petoro AS
In 1985, the Norwegian State began taking a direct financial interest in production licences through the establishment of the SDFI, and, in 2001, a new state-owned company, Petoro, was formed to manage SDFI assets.
From the establishment of Statoil in 1972 and until 1 January 1985, the participation of the Norwegian State in production licences and facilities for the transport and utilisation of petroleum took place entirely through Statoil. With effect from January 1985, the Norwegian State's participation was reorganised through the establishment of the SDFI. Through this reorganisation, the Norwegian State began taking a direct financial interest in production licences. The establishment of the SDFI entailed the transfer of a substantial part of our participation in most of our then licences to the SDFI, although, formally, such licences continued to be held wholly in our name. Since its establishment in 1985, the SDFI has taken shares in most licences awarded. The SDFI also holds shares in a number of oil and gas pipelines and land-based terminal facilities.
In connection with the restructuring, the Norwegian State formed a new state-owned company, Petoro AS, in May 2001, which took over responsibility for, and the management of, the SDFI assets as licensee, in accordance with a new chapter of the Petroleum Act. The Norwegian State continues to be the beneficial owner of these assets. We continue to market and sell the Norwegian State's oil and gas together with our own oil and gas in accordance with the owner's instruction described in report section 3.10.7 Operational review-Regulation-Marketing and sale of the SDFI oil and gas. One of the tasks of Petoro AS is to supervise our compliance with the owner's instruction.
Petoro AS does not own any of the oil and gas produced under the licence interests it holds, it does not receive any revenues from sales of the Norwegian State's oil and gas, and it is not permitted to have an operator role. However, Petoro AS may become a participant in new licences awarded by the Norwegian State.
3.10.9 Gassco AS
In connection with the restructuring of the Norwegian State's oil and gas interests in May 2001, the Norwegian State formed a separate company, Gassco AS.
Gassco took over as operator of the natural gas transportation system previously operated by us on 1 January 2002. Gassco AS is wholly owned by the Norwegian State. The owners of the infrastructure systems appointed Gassco AS as the new operator.
The transfer of the operatorship to Gassco AS was made without consideration of, and does not affect existing arrangements, with respect to ownership or access to the natural gas transportation system or transport tariffs. However, in accordance with the joint venture agreements for each of the gas transportation assets, the operator is entitled to be reimbursed for its costs as operator. Accordingly, since Gassco AS was appointed as operator, we no longer receive such reimbursement, and we will, as will other users of the infrastructure, be required to pay our share of Gassco AS's expenses relating to the operation of the natural gas pipelines in which we hold interests.
Gassco AS has entered into contracts with us for each infrastructure joint venture, pursuant to which we will carry out technical operating activities on behalf of Gassco AS, such as system maintenance, for which we will receive reimbursement of costs. Either Gassco AS or we may terminate each of these contracts without cause, except for the contract for the Statpipe joint venture, after five years. Either Gassco AS or we may also terminate the part of the Statpipe contract that concerns the offshore pipelines, after five years. Currently, Gassco AS may terminate the part of the Statpipe contract that concerns the Kårstø plant at any time, provided that two-thirds of the owners, representing more than two-thirds of the ownership interests, have supported such termination.
The natural gas transportation system was transferred to a new joint venture called Gassled as of 1 January 2003. Gassco AS is the operator of the Gassled joint venture. Our direct ownership interest in Gassled is currently 32.102% (32.881% including our indirect interest through our 28.58% holding in Norsea Gas AS), 15.73% in Zeepipe Terminal JV and 20.87% in Dunkerque Terminal DA. From 1 January 2011, our direct ownership interest in Gassled will be reduced to 28.217% due to an increased ownership interest for Petoro. In addition, our ownership interest in Gassled may also change as a result of the inclusion of existing or new infrastructure or if Gassled undertakes further investments without participation from its owners in the same ratio as their ownership interests in Gassled. For more information on the Gassled joint venture, see report section 3.3.3 Operational review - Natural Gas - Norway's gas transportation system.
3.11 Competition
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 major integrated oil and gas companies, as well as with independent and government-owned companies for the acquisition of assets and licences for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas prices and demand, the cost of exploration and production, global production levels, alternative fuels and governmental and environmental regulations.
Statoil's ability to remain competitive will depend, among other things, on management's continued focus on reducing unit costs and improving efficiency, maintaining long-term growth in our reserves and production through continued technological innovation and our ability to seize international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. The company believes that it is in a position to compete effectively in each of its business segments.
3.12 Property, plant and equipment
We have interests in real estate in numerous countries throughout the world, but no one individual property is significant to us as a whole.
Our principal offices located at Forusbeen 50, N-4035, Stavanger, Norway, comprise approximately 135,000 square metres of office space, and are 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 consolidated, will be ready for occupation in autumn 2012. IT Fornebu Holding AS will be the owner 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.
3.13 Related party transactions
We have the following transactions with related parties, including state-owned entities and the DnBNOR bank:
Transactions with the Norwegian state
For a description of shares held by the Norwegian state, see report section 6.4 Shareholder information-Major shareholders. See also report section 4.2.7 Financial analysis and review -Liquidity and capital resources - Material contracts.
Transactions with other entities in which the Norwegian State is a major shareholder
Because the Norwegian State controls a substantial proportion of industry in Norway, there are many state-controlled entities with whom we do business. The financial value of most such transactions is relatively small, and the ownership interest of the Norwegian State in such counterparties has not had any effect on the arm's-length nature of the transactions. In respect of the goods and services that we purchase in particular, we purchase telephone services from Telenor ASA, a telecommunications company in which the Norwegian State holds a 53.97% interest. Such purchases are made pursuant to standard tariff rates applicable to public and private companies in Norway.
Other transactions with the Norwegian State
Total purchases of liquids and natural gas from the Norwegian State amounted to NOK 74,338 million (204 mmboe) in 2009. In 2008 and 2007, the total purchases amounted to NOK 112,682 million (223 mmboe) and NOK 98,498 million (237 mmboe) respectively. Purchases of natural gas from the Norwegian State (excluding purchases from licences and sales on behalf of the Norwegian State) amounted to NOK 265 million in 2009. In 2008 and 2007, the purchases of natural gas amounted to NOK 375 million and NOK 287 million, respectively. The significant amounts included in the line item Payables to associated companies and other related parties in note 25 Trade and other payables to the Consolidated financial statement, are amount payables to the Norwegian State for these purchases. The prices paid by 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 3.10.7 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.
Employee loans
We have a general arrangement with DnBNOR whereby DnBNOR makes available to each of our employees personal consumer loans of up to NOK 300,000. The employees pay the "norm interest rate", which is variable and set by the Norwegian State, and we pay the difference between the norm interest rate and the then-current market interest rate. We also guarantee these loans up to an aggregate maximum amount of NOK 10 million. The repayment period is up to eight years. Our obligations resulting from paying the interest rate difference will be dependent on the loan volume, but, based on current interest rates, it would not exceed NOK 5 million per year.
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 15 March 2010.
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 15 March 2010.
4 Financial analysis and review
Statoil delivered a strong operational performance in 2009 and the company is in good financial shape and well positioned to continue to deliver growth and shareholder value towards 2012 and beyond.
The company met its guided production level by increasing equity production by 2%, to 1.962 mboe per day. It also delivered a successful exploration programme while maintaining cost control and capital discipline. However, net operating income was down by 39%, mainly because of lower prices for both oil and gas. Net operating income amounted to NOK 121.6 billion.
Around 80% of the Hydro merger synergies have been achieved, and the remainder are expected to be realised during 2010. Significant cost reductions have secured Statoil's highly competitive operating unit cost position.
The company has had a strong cash flow throughout the financial turmoil and has a sound financial position. Statoil is thus positioned to continue its production growth towards 2012 despite the current weakness in the gas markets, and it has projects and resource potential to underpin profitable growth beyond 2012. The board of directors is proposing an attractive dividend of NOK 6.00 per share for 2009.
4.1 Continued deliveries in turbulent markets
Statoil delivers sound financial and operational results in a demanding market. The activity level is high, and our production is growing according to plan.
In 2009, Statoil delivered total liquids and gas entitlement production of 1.806 mboe per day, up 3% from 1.751 mboe per day in 2008. The contribution from international operations reached the highest level yet, accounting for approximately 20% of the entitlement production. Total equity production increased by 2% from 2008, to 1.962 mboe per day in 2009.
Despite strong production and increased contribution from higher volumes, net operating income was down 39% at NOK 121.6 billion in 2009, compared with NOK 198.8 billion in 2008. The decrease was mainly attributable to lower prices for oil and gas and increased depreciation, amortisation and impairment losses. Having realised approximately 80% of the expected synergies from the merger, Statoil has reduced overall expenses, reduced expenditures related to logistics and procurement, improved operational efficiencies, and increased value creation through commodities trading.
Statoil delivered an extensive exploration programme in 2009. Of a total of 70 exploration wells completed before 31 December 2009, 29 were drilled outside the NCS. Forty wells were announced as discoveries, seven of which are located outside the NCS. In 2009, 481 mmboe were added through revisions, extensions and discoveries, compared with additions of 230 mmboe in 2008, also through revisions, extensions and discoveries.
In all, Statoil achieved a reserve replacement ratio of 73% in 2009.
Statoil maintained a high level of activity in progressing projects into production in 2009. Four projects on the NCS and two international projects came on stream in 2009. Eight new projects have been sanctioned for development in 2009, three of which are outside Norway.
In 2009, the group gained access to 13 new exploration licences in India, Canada, GoM, Libya, Brasil and the Faroe Islands. On the NCS, we were awarded access to 13 new licences, as operator for six and as partner in seven. We were also awarded five licence extensions, as operator for four and partner in one. In addition, the group signed a contract with Lukoil and the Iraqi government concerning an 18.75% interest in the West Ourna 2 field in Iraq.
4.1.1 Sales volumes
Sales volumes include our lifted entitlement volumes, the sale of SDFI volumes as well as our marketing of third party volumes
We take part in the production of oil and natural gas volumes, and incur capital expenditures and operating expenses on the basis of such equity volumes. Under certain profit sharing agreements (PSAs), a portion of the equity production is distributed to the relevant government before arriving at the volumes that we are ultimetely entitled to sell (entitlement volumes). The timing of when we lift our share of entitlement volumes may cause us to at any point in time have a difference between our share of entitlement volumes and the volumes lifted. This difference is called overlift if we have lifted more than our share of the entitlement production, and underlift if our cumulative lifting is less than our share of the entitlement volumes. The lifted volumes and volumes in inventory are the basis for what we can sell to third parties.
In addition to our own volumes of lifted entitlement production and in storage, we market and sell oil and gas owned by the Norwegian state through the Norwegian state's share in production licences, known as the State's Direct Financial Interest, or SDFI. For additional information, see section 3.13 Operational review-Related party transactions. The following table shows SDFI and Statoil sales volume information for crude oil and natural gas, as applicable, for the periods indicated. The Statoil natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International E&P and ethane volumes.
For more information on the differences between equity and entitlement production, sales volumes and lifted volumes, see section 4.1.10 Financial analysis and review - Continued deliveries in turbulent markets - Definitions of reported volumes.
Sales Volumes |
|
Year ended December 31, |
|
2009 |
2008 |
2007 |
|
Statoil: (1) |
|
|
|
Crude oil (mmbbls) (2) |
381 |
372 |
395 |
Natural gas (bcf) |
1462 |
1387 |
1257 |
Natural gas (bcm) (3) |
41.4 |
39.3 |
35.6 |
Combined oil and gas (mmboe) |
642 |
619 |
619 |
|
|
|
|
Third party volumes: (4) |
|
|
|
Crude oil (mmbbls)(2) |
257 |
242 |
240 |
Natural gas (bcf) |
192 |
127 |
177 |
Natural gas (bcm) (3) |
5.4 |
3.6 |
5.0 |
Combined oil and gas (mmboe) |
291 |
265 |
271 |
|
|
|
|
SDFI assets owned by the Norwegian State: |
|
|
|
Crude oil (mmbbls) (2) |
200 |
213 |
235 |
Natural gas (bcf) |
1,431 |
1,440 |
1,327 |
Natural gas (bcm) (3) |
40.5 |
40.8 |
37.6 |
Combined oil and gas (mmboe) |
455 |
470 |
472 |
|
|
|
|
Total |
|
|
|
Crude oil (mmbbls) (2) |
838 |
827 |
869 |
Natural gas (bcf) |
3,085 |
2,955 |
2,760 |
Natural gas (bcm) (3) |
87.4 |
83.7 |
78.2 |
Combined oil and gas (mmboe) |
1388 |
1353 |
1361 |
|
|
|
|
(1) The Statoil volumes included in the table above are based on the premise that volumes sold were equal to lifted volumes in the relevant year. Changes in inventory may cause these volumes to differ from the sales volumes reported elsewhere in this report by the Oil Trading and Supplies (OTS) organisation in the Manufacturing and Marketing segment in that such volumes include volumes still in inventory or transit held by other reporting entities within the group. Excluded from such volumes are volumes lifted by the International E&P but not sold by OTS, and volumes lifted by E&P Norway or International and still in inventory or in transit. |
|||
(2) Sales volumes of crude oil include NGL and condensate. All sales volumes reported in the table above include internal deliveries to our manufacturing facilities. |
|||
(3) At a gross calorific value (GCV) of 40 MJ/scm. |
|||
(4) Third party volumes of crude oil include both volumes purchased from partners in our upstream operations and other cargos purchased in the market. The third party volumes are purchased either for sale to third parties or for our own use. Third party volumes of natural gas include third party LNG volumes related to our activities at the Cove Point regasification terminal in the U.S. |
|||
4.1.2 Group profit and loss analysis
Revenues and other income were NOK 465.4 billion in 2009, which is NOK 190.6 billion lower than in 2008 and NOK 57.4 billion lower than in 2007. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by Statoil.
Consolidated statement of income |
Year ended 31 December |
||||
(in NOK billion) |
2009 |
2008 |
2007 |
09-08 change |
08 -07 change |
|
|
|
|
|
|
Revenues and other income |
|
|
|
|
|
Revenues |
462.3 |
652.0 |
521.7 |
(29%) |
25% |
Net income from associated companies |
1.8 |
1.3 |
0.6 |
39% |
111% |
Other income |
1.4 |
2.8 |
0.5 |
(51%) |
428% |
|
|
|
|
|
|
Total revenues and other income |
465.4 |
656.0 |
522.8 |
(29%) |
25% |
|
|
|
|
|
|
Operating expenses |
|
|
|
|
|
Purchase, net of inventory variation |
205.9 |
329.2 |
260.4 |
(37%) |
26% |
Operating expenses |
56.9 |
59.3 |
60.3 |
(4%) |
(2%) |
Selling, general and administrative expenses |
10.3 |
11.0 |
14.2 |
(6%) |
(23%) |
Depreciation, amortisation and net impairment losses |
54.1 |
43.0 |
39.4 |
26% |
9% |
Exploration expenses |
16.7 |
14.7 |
11.3 |
14% |
30% |
|
|
|
|
|
|
Total operating expenses |
343.8 |
457.2 |
385.6 |
(25%) |
19% |
|
|
|
|
|
|
Net operating income |
121.6 |
198.8 |
137.2 |
(39%) |
45% |
|
|
|
|
|
|
Net financial items |
(6.7) |
(18.4) |
9.6 |
(64%) |
(291%) |
|
|
|
|
|
|
Income tax |
(97.2) |
(137.2) |
(102.2) |
(29%) |
(34%) |
|
|
|
|
|
|
Net income |
17.7 |
43.3 |
44.6 |
(59%) |
(3%) |
Earnings per share for income attributable to equity holders of company basic and diluted |
|
|
|
|
|
5.7 |
13.6 |
13.8 |
(58 %) |
(100 %) |
|
Operational data |
Year ended 31 December |
||||
|
2009 |
2008 |
2007 |
09-08 change |
08-07 change |
|
|
|
|
|
|
Average liquids price (USD/bbl) |
58.0 |
91.0 |
70.5 |
(36 %) |
29 % |
USDNOK average daily exchange rate |
6.30 |
5.63 |
5.86 |
12 % |
(4 %) |
Average liquids price (NOK/bbl) |
364 |
513 |
413 |
(29 %) |
24 % |
Gas prices (NOK/scm) |
1.90 |
2.40 |
1.66 |
(21 %) |
45 % |
Refining margin, FCC (USD/boe) |
4.3 |
8.2 |
7.5 |
(48 %) |
9 % |
Total entitlement liquids production (mboe per day) |
1066 |
1055 |
1070 |
1 % |
(1 %) |
Total entitlement gas production (mboe per day) |
740 |
696 |
654 |
6 % |
6 % |
Total entitlement liquids and gas production (mboe per day) |
1806 |
1751 |
1724 |
3 % |
2 % |
Total equity liquids production (mboe per day) |
1202 |
1200 |
1165 |
0 % |
3 % |
Total equity gas prodcution (mboe per day) |
760 |
725 |
674 |
5 % |
8 % |
Total equity liquids and gas production (mboe per day) |
1962 |
1925 |
1839 |
2 % |
5 % |
Total liquids liftings (mboe per day) |
1045 |
1019 |
1081 |
3 % |
(6 %) |
Total gas liftings (mboe per day) |
740 |
696 |
654 |
6 % |
6 % |
Total liquids and gas liftings (mboe per day) |
1785 |
1714 |
1735 |
4 % |
(1 %) |
Production cost entitlement volumes |
38.4 |
38.1 |
44.1 |
1 % |
(14 %) |
Equity production cost excluding restructuring and gas injection cost (NOK/boe, last 12 months) |
35.3 |
33.3 |
31.2 |
6 % |
7 % |
Revenues and other income was NOK 465.5 billion in 2009, compared to NOK 656,0 billion in 2008 and NOK 521.7 billion in 2007. 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 NCS. All purchases and sales of the Norwegian State's production of liquids are recorded as purchases net of inventory variations and sales, respectively.
The NOK 190.6 billion decrease in revenues from 2008 to 2009 was mainly attributable to lower prices of both liquids and gas. Realised prices of liquids measured in NOK decreased by 29% from 2008 to 2009, contributing NOK 56.5 billion to the reduction in revenues. Gas prices were down 21% in 2009 compared to last year, and contributed NOK 25.0 billion to the reduction in revenues. The reduction in revenues was partly compensated by a 4% increase in liftings of both liquids and gas, with a total off-setting effect of NOK 15.2 billion. The decrease in revenues related to volumes purchased from The Norwegian State contributed NOK 124.3 billion.
Realised prices of liquids measured in NOK increased by 29% from 2007 to 2008, contributing NOK 37.0 billion to the revenues, whereas the overall gas sales volumes contributed NOK 6.1 billion and the increase in prices of natural gas contributed NOK 29.2 billion to the change. This was partly off-set by a decrease in liftings of liquids of NOK 9.0 billion. The increase in revenues related to volumes purchased from The Norwegian State contributed NOK 71.0 billion.
The volumes lifted and sold will over time equal our production of entitlement volumes, but 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 was 1.045 mmboe per day in 2009, an increase of 3% compared to last year. In 2008, total liquids liftings decreased from 1.081 mmboe per day in 2007 to 1.019 mmboe per day in 2008. The average daily underlift was 21 mboe per day in 2009 and 37 mboe per day in 2008, while there was an average overlift of 11 mboe per day and 2007.
Entitlement volumes lifted is the basis for the revenue recognition, while equity production volumes affect operating costs more directly. See report section Financial analysis and review - Continued deliveries in turbulent markets - Sales volumes for more details on the PSA effects that causes differences between equity and entitlement volumes. See below for more details on the difference between lifted and produced volumes.
Net income from associated companies was NOK 1.8 billion in 2009, NOK 1.3 billion in 2008 and NOK 0.6 billion in 2007.
Other income was NOK 1.4 billion in 2009, compared with NOK 2.8 billion in 2008 and NOK 0.5 billion in 2007. The income in 2009 stem mainly from insurance proceeds relating to business interruptions. The income in 2008 and 2007 was mainly related to gain from sale of assets.
Purchase, net of inventory variation includes the cost of the oil and NGL production purchased from the Norwegian state pursuant to the Owners Instruction. The purchase, net of inventory variation amounted to NOK 205.9 billion in 2009, compared to NOK 329.2 billion in 2008 and NOK 260.4 billion in 2007. The increase from 2007 through 2008 was mainly caused by higher prices of liquids measured in NOK, while the 37% decrease from 2008 to 2009 mainly stem from lower prices of liquids measured in NOK.
Operating expenses include field production costs and transport systems related to the company's share of oil and natural gas production. Operating expenses were NOK 56.9 billion in 2009, reduced by 4% since 2008 when operating expenses were NOK 59.3 billion. The reduction was mainly attributable to reduced transportation costs and the reversal of a provision related to a take or pay contract in previous periods. In 2007, operating expenses were NOK 60.3 billion, and the 2% decrease from 2007 to 2008 was primarily due to restructuring costs related to the merger in 2007 and was only partly offset by increased costs related to start-up of new fields, higher activity and industry cost inflation in 2008.
Total liquids and gas entitlement production increased from 1.751 mmboe per day in 2008 to 1.806 mmboe per day in 2009. In 2007, total liquids and gas production was 1.724 mmboe per day. activities. Equity production of oil and gas increased from 1.925 mmboe per day in 2008 to 1.962 mmboe per day in 2009. In 2007, equity production of liquids and gas was 1.839 mmboe per day.
The 2% increase in equity production from 2008 to 2009 was primarily due to increased production from start-up of new fields, ramp-up on existing fields, partly offset by declining production from mature fields, various operational issues and maintenance activities. Entitlement production increased by 3% due to the same reasons and also due to a less adverse effect of product sharing agreements (PSA-effects).
The 5% increase in equity production from 2007 to 2008 was primarily due to new fields coming on stream and a higher gas off-take, partly offset by declining production from maturing fields. The 2% increase in entitlement production was due to the same reasons, but was partly offset by higher adverse PSA-effects.
The production cost per boe based on entitlement volumes was NOK 38.4 for the 12 months ended 31 December 2009, compared with NOK 38.1 for the 12 months ending 31 December 2008. In 2007, the production cost per boe was NOK 44.1. Production costs are incurred based on our equity production. Management therefore thinks that unit of production cost based on equity production is a better measure of cost control than unit of production cost based on entitlement volumes. Based on equity volumes, the production cost per boe for the two periods was NOK 35.3 and NOK 34.6, respectively.
Adjusted for restructuring costs and other costs arising from the merger recorded in the fourth quarter of 2007 and gas injection costs, the production cost per boe of equity production for the 12 months ending 31 December 2009 and 2008, was NOK 35.3 and NOK 33.3 respectively.
Adjustments are made for certain costs related to the purchase of gas used for injection into oil-producing reservoirs. The adjustment facilitates comparison of field production costs with other fields which do not pay for their own gas used for injection into oil producing reservoirs.
Selling, general and administrative expenses include expenses related to the sale and marketing of our products, such as business development costs, payroll and employee benefits. These amount to NOK 10.3 billion in 2009, compared to NOK 11.0 billion in 2008 and NOK 14.2 billion in 2007. The 6% decrease from 2008 to 2009 consists of numerous different factors, cost savings being one of them. The 23% decrease from 2007 to 2008 was mainly due to restructuring costs related to the merger in 2007 and was only partly offset by increased costs related to higher activity and industry cost inflation in 2008.
Depreciation, amortisation and impairment includes depreciation of production installations and transport systems, depletion of fields in production, amortisation of intangible assets and depreciation of capitalised exploration expenditure. It also includes write-downs of impaired long-lived assets and reversals of impairments. These expenses amounted to NOK 54.1 billion in 2009, compared to NOK 43.0 billion in 2008 and NOK 39.4 billion in 2007.
The 26% increase in depreciation, amortisation and impairment expenses in 2009 compared to 2008 was due to increased production on the NCS and impairment charges net of reversals of NOK 7.1 billion, mostly related to assets in the Gulf of Mexico and refinery assets in Norway.
Depreciation, amortisation and impairment expenses in 2008 showed a increase of 9% compared to 2007. The increase was due to impairment charges net of reversals of NOK 2.3 billion, mostly related to the Gulf of Mexico, and an increase in production.
|
Year ended 31 December |
||||
Depreciation, amortisation and net impairment losses (in NOK billion) |
2009 |
2008 |
2007 |
09-08 change |
08-07 change |
Ordinary depreciation |
(46.5) |
(40.4) |
(37.0) |
15 % |
9 % |
Amortisation of intangible assets |
(0.1) |
(0.1) |
(0.2) |
5 % |
(31 %) |
Impairments, net of reversals |
(6.4) |
(2.4) |
(2.2) |
166 % |
11 % |
Impairment of intangible assets |
(1.0) |
0.0 |
0.0 |
n/a |
n/a |
Depreciation, amortisation and net impairment losses |
(54.1) |
(43.0) |
(39.4) |
26 % |
9 % |
Exploration expenditures are capitalised to the extent that exploration efforts are considered successful, or pending such assessment. Otherwise, such expenditures are expensed. The exploration expense consists of the expensed portion of our exploration expenditure in 2009 and write-offs of exploration expenditure capitalised in previous years. In 2009, the exploration expenses were NOK 16.7 billion, a 14% increase since 2008 when exploration expenses were NOK 14.7 billion. In 2007, exploration expenses were NOK 11.3 billion.
|
For the year ended 31 December |
||||
Exploration (in NOK billion) |
2009 |
2008 |
2007 |
09-08 change |
08-07 change |
|
|
|
|
|
|
Exploration expenditure (activity) |
16.9 |
17.8 |
14.2 |
-5% |
25% |
Expensed, previously capitalised exploration expenditure |
7.0 |
3.7 |
1.7 |
89% |
118% |
Capitalised share of current periods exploration activity |
(7.2) |
(6.8) |
(4.6) |
6% |
48% |
|
|
|
|
|
|
Exploration expense |
16.7 |
14.7 |
11.3 |
14% |
30% |
The 14% increase in exploration expenses from 2008 to 2009 was mainly due to a higher number of wells drilled and a higher portion of exploration expenditure capitalised in previous years being impaired. The 30% increase in exploration expenses from 2007 to 2008 was mainly due to a higher number of wells drilled, generally more expensive wells, higher field evaluation costs and delineation of the oil sands project in Canada.
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.
In 2007, a total of 71 exploration and appraisal wells were completed, 24 on the NCS and 47 internationally. In addition, two exploration extension wells were completed in the same period. Thirty-four of the exploration and appraisal wells were confirmed discoveries, 16 on the NCS and 18 internationally. Both exploration extension wells were discoveries.
Net operating income was NOK 121.6 billion in 2009, compared to NOK 198.8 billion in 2008 and NOK 137.2 billion in 2007. 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. The 45% increase from 2007 to 2008 was mainly due to higher realised prices for both liquids and natural gas, measured in NOK, and it was only partly offset by increased operating expenses caused by a higher activity level and new, more expensive fields coming on stream.
Net operating income in 2007 was also influenced by increased operating, selling and administrative expenses stemming in part from restructuring and other costs arising from the merger, a negative change in derivatives, new fields coming on stream and increased activity levels. The restructuring costs and other costs arising from the merger were recorded primarily under operating and general and administrative expenses, and they were allocated to the business areas where possible. Restructuring costs and other costs arising from the merger were primarily related to pensions and early retirement costs and impairment of assets in Sweden.
In 2009, net operating income was affected by the following items: impairment losses net of reversals (NOK 12.2 billion) and underlift (NOK 1.2 billion) negatively affected net operating income, while higher fair value of derivatives (NOK 2.2 billion), higher values of products in operational storage (NOK 2.1 billion), other accruals (NOK 1.3 billion), gain on sale of assets (NOK 0.5 billion) and reversals of restructuring costs (NOK 0.3 billion) all positively affected net operating income in 2009.
In 2008, net operating income was affected by the following items: impairment charges net of reversals (NOK 4.8 billion), lower values of products in operational storage (NOK 2.8 billion), underlift (NOK 2.4 billion) and other accruals (NOK 2.3 billion) all affected net operating income in 2008 negatively, while increased fair value of derivatives (NOK 1.8 billion), gains on derivatives to hedge the value of inventories (NOK 0.8 billion), gains on sales of assets (NOK 1.4 billion) and reversal of restructuring cost accrual (NOK 1.6 billion) positively affected net operating income in 2008.
In 2007, net operating income was impacted of the following items: impairment charges net of reversals (NOK 2.8 billion), loss on derivatives to hedge the value of inventories (NOK 1.1 billion), other accruals (NOK 1.2 billion), restructuring cost accrual (NOK 6.7 billion) and other costs related to the merger (NOK 3.2 billion) all impacted net operating income in 2007 negatively, while increased fair value of derivatives (NOK 0.5 billion), overlift (NOK 1.6 billion), higher values of products in operational storage (NOK 1.5 billion) positively impacted net operating income in 2008.
Net financial items amounted to a loss of 6.7 billion in 2009, compared to a loss of NOK 18.4 billion in 2008.
The NOK 11.7 billion positive change from 2008 to 2009 was mostly attributable to NOK 2.0 billion net currency gains caused by a 17% weakening of US dollar versus the NOK for the year ended 31 December 2009, compared to NOK 32.6 net currency losses caused by a 29% strengthening of the US dollar versus the NOK for the year ended 31 December 2008.
Net foreign exchange losses in 2009 and net foreign exchange losses in 2008 are mainly related to currency derivatives used for currency and liquidity risk management. Effective 1 January 2009 the functional currency changed to US dollar for the parent company. As a result US dollar denominated non-current financial liabilities that impacted Net foreign exchange gains (losses) in 2008, do not impact the income statement in 2009. The positive impact of net currency exchange gains was partly offset by a NOK 8.5 billion decrease in interest income and other financial items and a NOK 14.5 billion increase in interest and other finance expenses.
Interest income and other financial items amounted to NOK 3.7 billion for the year ended 31 December in 2009, compared to NOK 12.2 billion for the year ended 31 December 2008. The NOK 8.5 billion decrease was mainly related to NOK 3.9 billion in lower income from securities and NOK 5.5 billion in decreased interest income on current financial assets.
Interest expense and other finance expenses amounted to a net expenses of NOK 12.5 billion for the year ended 31 December 2009, compared to a net gain of NOK 2.0 billion for the year ended 31 December 2008. The decrease of NOK 14.5 billion mostly relate to fair value losses on interest rate derivatives used to manage the interest rate risk of the loan portfolio, due to increasing US dollar rates for 2009. Correspondingly, decreasing US dollar rates in 2008 resulted in fair value gains on these swap positions.
In 2008, Net financial items amounted to a loss of NOK 18.4 billion, compared with a gain of NOK 9.6 billion in 2007.
The NOK 28.0 billion negative change from 2007 to 2008 was mostly attributable to NOK 32.6 billion net currency losses caused by a 29% strengthening of US dollar versus the NOK for the year ended 31 December 2008, compared to NOK 10.0 billion net currency gains from a 14% weakening of the US dollar versus the NOK for the year ended 31 December 2007.
Net foreign exchange losses in 2008 and net foreign exchange gains in 2007 are mainly related to currency derivatives used for currency and liquidity risk management, in combination with net impact on the US dollar denominated loan portfolio.The negative impact of currency exchange losses was partly offset by a NOK 9.9 billion increase in interest income and other financial items and a NOK 4.7 billion decrease in interest and other finance expenses.
Interest income and other financial items amounted to NOK 12.2 billion for the year ended 31 December 2008, compared to NOK 2.3 billion for the year ended 31 December 2007. The increase of NOK 9.9 billion mainly related to an increase in interest income of NOK 4.4 billion and an increase in income from securities of NOK 5.5 billion, mainly related to currency gains on USD denominated investments.
Interest expense and other finance expenses amounted to a net gain of NOK 2.0 billion for the year ended 31 December 2008, compared to a net loss of NOK 2.7 billion for the year ended 31 December 2007.
Management of the portfolio of security investments, mainly related to equity securities, is held by our insurance captive, Statoil Forsikring AS, commercial papers is held by Statholding AS and liquidity funds is held by Statoil ASA.
The Norwegian central bank's closing rate for USDNOK was 5.78 on 31 December 2009, 7.00 on 31 December 2008 and 5.41 on 31 December 2007. These exchange rates have been applied in Statoil's financial statements.
Income taxes were NOK 97.2 billion in 2009, equivalent to a tax rate of 84.6%, compared to NOK 137.2 billion in 2008, equivalent to a tax rate of 76.0% and NOK 102.2 billion in 2007, equivalent to a tax rate of 69.6%.
The increase in the tax rate from 2008 to 2009 was mainly due to significant taxable exchange gains, which do not have an impact on the statement of income for companies whose functional currency is USD. In 2009 the taxable income related to these exchange gains is estimated to be NOK 25.0 billion higher than income before tax, which increases the tax rate. In addition, the tax rate was increased by relatively higher income from the NCS with higher than average tax rates, and impairment losses with lower than average tax rates.
The increase in the tax rate from 2007 to 2008 was mainly related to the net loss on financial items which is tax deductible at a lower tax rate than the average rate. In addition, the tax rate was increased by the deferred tax expense caused by currency effects in certain group companies which are taxable in a different currency than the functional currency. This was partly offset by the tax effect of a proportionally higher operating income being subject to a lower than average tax rate.
The effective tax rate is calculated as income taxes divided by income before taxes. Fluctuations in the effective tax rates from year to year are principally the result of non-taxable items (permanent differences), changes in the components of income between Norwegian oil and gas production, taxed at a marginal rate of 78%. Other Norwegian income, including the onshore portion of net financial items are taxed at 28%, and income in other countries taxed at the applicable income tax rates.
In 2009, the non-controlling interest (minority interest) in net profit was negative NOK 0.6 billion, compared to an income of NOK 0.005 billion in 2008 and NOK 0.5 billion in 2007. The non-controlling interest is primarily related to the Mongstad crude oil refinery.
Net income was NOK 17.7 billion in 2009, compared to NOK 43.3 billion in 2008 and NOK 44.6 billion in 2007. The 59% decrease from 2008 to 2009 is mainly due to reduced operating income caused by lower revenues from liquids and gas sales and a higher effective tax rate, only partly offset by reduced loss on net financial items.
The 3% decrease from 2007 to 2008 was mainly caused by a loss on financial items, high income taxes and increased operating expenses, and was only partly offset by higher prices on both liquids and natural gas, measured in NOK.
The Board of Directors proposes to the Annual General Meeting a dividend of NOK 6.00 per share for 2009, making an aggregate total of NOK 19.1 billion. In 2008, ordinary dividend was NOK 4.40 per share, as well as NOK 2.85 per share in special dividend, making an aggregate total of NOK 23.1 billion. Ordinary dividend for 2007 was NOK 4.20 per share, as well as NOK 4.30 per share in special dividend, making an aggregate total of NOK 27.1 billion for 2007.
4.1.3 Group outlook
Statoil's guidance for equity production is in the range of 1,925 to 1,975 mboe per day in 2010.
The expected volumes are exclusive of any Opec cuts. Commercial considerations related to gas sales activities, operational regularity, the timing of new capacity coming on stream and gas offtake represent the most significant risks related to the production guidance.
Planned turnarounds in 2010 are estimated to have a negative impact on the equity production of around 50 mboe per day in 2010.
Capital expenditure in 2010, excluding acquisitions and capital leases, is estimated to be around USD 13 billion.
The unit production cost for equity volumes is estimated to be NOK 35-36 per boe, which is on a par with 2009.
The company will continue to mature its large portfolio of exploration assets and expects an exploration activity level in 2010 of around USD 2.3 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 been declining for more than a year, and we anticipate that they will remain low, at least in the near term.
In the long term, we continue to take a positive view of gas as an energy source. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. In the USA, we believe that our position in the Marcellus shale gas acreage, in combination with Gulf of Mexico production and our LNG regasification capacity position at Cove Point, will provide a foundation for growth in our US market position in the years ahead.
Statoil's income could vary significantly with changes in commodity prices, while volumes are fairly stable through the year. There is a small seasonal effect on volumes 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 "Forward looking statements" section 10.
4.1.4 Segment performance and analysis
Oil and natural gas are subject to internal transactions between our business segments before being sold in the market. We have established a pricing policy for transfers based on the market price.
The table details certain financial information for our four business segments: Exploration & Production Norway (EPN), International Exploration & Production (INT), Natural Gas (NG) and Manufacturing & Marketing (M&M). 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 or NG segments.
EPN produces oil, which it sells internally to Oil Sales, Trading and Supply (OTS) in the M&M segment, which then sells the oil in the market. EPN also produces natural gas, which it sells internally to 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 is also sold in the same way as the oil and natural gas produced by EPN. The remaining oil and gas from INT is sold directly in the market. Statoil has established a 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.
The transfer price formula for natural gas produced by EPN and marketed and sold by NG was changed with effect from 1 January 2008 in order to better reflect fundamental changes in the markets for competing energies, for instance crude oil, for developments in natural gas markets and for changes in the natural gas sales contracts portfolio. The internal price is linked to the gas market prices, and it better reflects the distribution of value creation between NG and EPN. The change was effective as of 1 January 2008 and it is reflected in our financial reporting, without prior periods being restated.
In 2009, the average transfer price for natural gas per standard cubic metre was NOK 1.38 per scm. The average transfer price was NOK 1.87 in 2008 and NOK 1.39 in 2007. 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 note 5 Segments in the Consolidated Financial Statements.
The following table shows certain financial information for the four segments, including intercompany eliminations for each of the years in the three-year period ending 31 December 2009.
|
For the year ended 31 December |
||
(in NOK billion) |
2009 |
2008 |
2007 |
|
|
|
|
Exploration & Production Norway |
|
|
|
Total revenues |
158.7 |
219.8 |
179.2 |
Net operating income |
104.3 |
166.9 |
123.2 |
Non-current assets |
176.0 |
165.5 |
153.1 |
|
|
|
|
International Exploration & Production |
|
|
|
Total revenues |
41.8 |
46.1 |
41.6 |
Net operating income |
2.6 |
12.8 |
12.2 |
Non-current assets |
152.7 |
160.6 |
107.3 |
|
|
|
|
Natural Gas |
|
|
|
Total revenues |
98.6 |
110.8 |
73.4 |
Net operating income |
18.5 |
12.5 |
1.6 |
Non-current assets |
34.8 |
35.7 |
35.6 |
|
|
|
|
Manufacturing & Marketing |
|
|
|
Total revenues |
351.2 |
531.3 |
428.0 |
Net operating income |
(0.5) |
4.5 |
3.8 |
Non-current assets |
28.6 |
34.4 |
27.6 |
|
|
|
|
Other and elimination |
|
|
|
Total revenues |
(184.9) |
(252.1) |
(199.5) |
Net operating income |
(3.3) |
2.1 |
(3.4) |
Non-current assets |
3.0 |
3.9 |
2.9 |
|
|
|
|
Statoil group |
|
|
|
Total revenues |
465.4 |
656.0 |
522.8 |
Net operating income |
121.6 |
198.8 |
137.2 |
Non-current assets |
395.1 |
400.1 |
326.5 |
Non-current assets, not allocated to segments |
51.4 |
33.5 |
26.9 |
(in NOK million) |
Crude oil |
Gas |
NGL |
Refined products |
Other |
Total sale |
|
|
|
|
|
|
|
Year ended 31 December 2009 |
|
|
|
|
|
|
Norway |
182,353 |
80,018 |
34,655 |
45,927 |
18,137 |
361,090 |
USA |
19,836 |
5,555 |
117 |
14,017 |
672 |
40,197 |
Sweden |
0 |
0 |
0 |
16,556 |
3,795 |
20,351 |
Denmark |
0 |
0 |
0 |
15,105 |
1,957 |
17,062 |
Other |
9,978 |
2,959 |
154 |
10,762 |
1,102 |
24,955 |
|
|
|
|
|
|
|
Total revenues (excluding net income from associated companies) |
212,167 |
88,532 |
34,926 |
102,367 |
25,663 |
463,655 |
(in NOK million) |
Crude oil |
Gas |
NGL |
Refined products |
Other |
Total sale |
|
|
|
|
|
|
|
Year ended 31 december 2008 |
|
|
|
|
|
|
Norway |
260,171 |
79,813 |
44,536 |
79,659 |
31,105 |
495,284 |
United States |
24,712 |
8,795 |
1,660 |
20,182 |
2,545 |
57,894 |
Sweden |
0 |
0 |
0 |
23,428 |
2,618 |
26,046 |
Denmark |
0 |
0 |
0 |
16,858 |
2,558 |
19,416 |
Singapore |
11,203 |
1,906 |
0 |
0 |
0 |
13,109 |
UK |
1,982 |
10,878 |
2 |
0 |
2,800 |
15,662 |
Other |
7,305 |
930 |
198 |
16,885 |
2,008 |
27,326 |
|
|
|
|
|
|
|
Total revenues (excluding net income from associated companies) |
305,373 |
102,322 |
46,396 |
157,012 |
43,634 |
654,737 |
(in NOK million) |
Crude oil |
Gas |
NGL |
Refined products |
Other |
Total sale |
|
|
|
|
|
|
|
Year ended 31 December 2007 |
|
|
|
|
|
|
Norway |
209,764 |
62,911 |
47,119 |
52,537 |
14,342 |
386,673 |
United States |
24,142 |
5,269 |
1,766 |
22,823 |
(864) |
53,136 |
Sweden |
0 |
0 |
0 |
15,217 |
7,892 |
23,109 |
Denmark |
0 |
0 |
0 |
13,161 |
1,759 |
14,920 |
Singapore |
13,861 |
0 |
0 |
367 |
0 |
14,228 |
Other |
13,290 |
2,485 |
139 |
11,517 |
2,691 |
30,122 |
|
|
|
|
|
|
|
Total revenues (excluding net income from associated companies) |
261,057 |
70,665 |
49,024 |
115,622 |
25,820 |
522,188 |
4.1.5 Exploration & Production Norway
Our overall strategy on the NCS is to conduct safe, efficient and reliable operations and capture the full potential of the NCS by developing profitable oil and gas resources.
Statoil delivered an extensive exploration programme on the NCS in 2009. We participated in 39 exploration and appraisal wells, 31 of which resulted in discoveries. In addition, we completed two exploration extensions, both announced as discoveries. Total exploration expenditure was NOK 8.2 billion in 2009, compared with NOK 8.7 billion in 2008 and NOK 5.7 billion in 2007.
Gross investments amounted to NOK 34.9 billion in 2009, which is unchanged from 2008 and slightly higher than NOK 31.1 billion in 2007. 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 NCS in 2009: Yttergryta, Alve, Tyrihans and Tune South.
Our production of oil and gas on the NCS averaged 1.450 mmboe per day in 2009, compared with 1.461 mmboe per day in 2008 and 1.417 in 2007.
4.1.5.1 Profit and loss analysis
Exploration & Production Norway generated total revenues of NOK 158.7 billion in 2009 and its net operating income was NOK 104.3 billion. The average daily entitlement production in 2009 was 784 mboe per day for liquids and 666 mboe per day for gas.
|
For the year ended 31 December |
||||
Income statement (in NOK billion) |
2009 |
2008 |
2007 |
09-08 change |
08-07 change |
|
|
|
|
|
|
Total revenues and other income |
158.7 |
219.8 |
179.2 |
(28 %) |
23 % |
|
|
|
|
|
|
Operating expenses |
23.4 |
23.5 |
29.1 |
(0 %) |
(19 %) |
Selling, general and administrative expenses |
0.1 |
(0.1) |
0.3 |
(153 %) |
(135 %) |
Depreciation, amortisation and impairment |
25.7 |
24.0 |
23.0 |
7 % |
4% |
Exploration expenses |
5.2 |
5.5 |
3.6 |
(6 %) |
52% |
Total expenses |
54.4 |
52.9 |
56.1 |
3 % |
(6 %) |
Net operating income |
104.3 |
166.9 |
123.1 |
(38 %) |
36% |
|
|
|
|
|
|
Operational data: |
|
|
|
|
|
Liquids price (USD/bbl) |
57.8 |
91.5 |
70.9 |
(37 %) |
29% |
Liquids price (NOK/bbl) |
363 |
515 |
415 |
(30 %) |
24% |
Transfer price natural gas (NOK/scm) |
1.38 |
1.87 |
1.39 |
(26 %) |
34% |
|
|
|
|
|
|
Liftings: |
|
|
|
|
|
Liquids (mboe per day) |
778 |
808 |
831 |
(4 %) |
(3 %) |
Natural gas (mboe per day) |
666 |
637 |
599 |
5 % |
6% |
Total liquids and gas liftings (mboe per day) |
1444 |
1445 |
1430 |
(0 %) |
1% |
|
|
|
|
|
|
Production: |
|
|
|
|
|
Entitlement liquids (mboe per day) |
784 |
824 |
818 |
(5 %) |
1% |
Entitlement natural gas (mboe per day) |
666 |
637 |
599 |
5 % |
6% |
Total entitlement liquids and gas production (mboe per day) |
1450 |
1461 |
1417 |
(1 %) |
3% |
We generated total revenues of NOK 158.7 billion in 2009, NOK 219.8 billion in 2008 and NOK 179.2 billion in 2007. A decrease of 37% in the average price in USD of oil sold by E&P Norway to Manufacturing and Marketing accounted for NOK 52.1 billion of the decrease in revenues, and a 26% decrease in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas accounted for NOK 18.9 billion of the decrease in revenues. This was partly offset by a positive currency exchange rate deviation of NOK 12.6 billion due to a 14.0% increase in the USD/NOK exchange rate. Furthermore, lifted volumes of liquids decreased by 4.0%, making a negative contribution of NOK 5.7 billion, which was partly offset by a 4.3% increase in lifted volumes of natural gas, making a positive contribution of NOK 2.9 billion.
The average daily lifting of liquids in 2009 was 778 mboe per day, compared with 808 mboe per day in 2008 and 831 mboe per day in 2007. Over time, the volumes lifted and sold will equal the volumes produced, but they may be higher or lower in any period due to differences between the capacity of the vessels lifting our volumes and the actual entitlement production in the period. The average daily underlift was 6 mboe per day in 2009 and 16 mboe per day in 2008, compared with an average overlift of 13 mboe per day in 2007.
There was an increase in total revenues from NOK 179.2 billion in 2007 to NOK 219.8 billion in 2008. An increase of 31% in the average price in USD of oil sold by E&P Norway to Manufacturing and Marketing contributed NOK 54.6 billion, and a 35% increase in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas, contributed NOK 17.9 billion. Lifted volumes of natural gas increased by 6.7%, resulting in a positive contribution of NOK 3.2 billion. This was offset by a negative currency exchange rate deviation of NOK 11.1 billion due to a 7.2% decrease in the USD/NOK exchange rate. In addition, other income increased by NOK 3.1 billion, mainly as a result of a change in the fair value of derivatives. Lifted volumes of crude oil decreased by 2.5%, making a negative contribution of NOK 3.1 billion.
Operating, general and administrative expenses were NOK 23.5 billion in 2009, compared with NOK 23.4 billion in 2008 and NOK 29.4 billion in 2007. Increased processing/transportation cost were partly offset by lower operating plant cost.
The decrease of NOK 6.0 billion in operating, general and administrative expenses from 2007 to 2008 was mainly due to a decrease in other expenses of NOK 6.8 billion, which was largely due to restructuring costs as a result of the merger in 2007 and a decrease of NOK 1.3 billion in transportation costs in 2008, due in part to reduced booking of transportation capacity. In addition, selling, general and administrative expenses decreased by NOK 0.4 billion while processing costs decreased by NOK 0.3 billion, from 2007 to 2008. This was partially countered by an increase of NOK 2.7 billion in operating plant costs, which was largely due to the start up of new fields of NOK 1.1 billion, increased costs of NOK 0.5 billion of gas purchased for injection at Grane and increased operating activity.
The average daily production of entitlement liquids in 2009 was 784 mboe per day, compared with 824 mboe per day in 2008 and 818 mboe per day in 2007. The decrease in production from 2008 to 2009 was mainly related to expected declines on several fields, various operational issues on the Kristin, Gullfaks South and Norne fields, turnaround and less NGL due to less gas offtake on Oseberg and close-down of the Tordis subsea separator from the end of May 2008 due to leakage from a well. The decrease was partly offset by build up of production at Ormen Lange and Snøhvit and new production from Alve, Tyrihans, Volve, Vilje and Yttergryta, and Kvitebjørn returning to full production from July 2009 after it was shut down due to a damaged gas pipeline.
The increased production from 2007 to 2008 was mainly related to the start-up of the Volve field in February 2008, higher production on Kvitebjørn than in 2007until the shutdown from August 2008, when Kvitebjørn was shut down to allow safe drilling operations most of the year, new wells on Fram and a building up of production on Ormen Lange. The increase was partly offset by declining production from wells in the Grane, Norne, Troll Olje, Tordis, Visund and Sleipner fields.
The average daily production of entitlement gas was 666 mboe per day in 2009 (equal to 105.9 mmcm or 3.74 mmcf), compared with 637 mboe in 2008 (equal to 101.3 mmcm or 3.58 mmcf) and 599 mboe in 2007 (equal to 95.2 mmcm or 3.36 mmcf).
The unit production cost was NOK 36.93 per boe in 2009, compared with NOK 37.31 per boe in 2008 and NOK 46.26 per boe in 2007. The total production cost was NOK 19.5 in 2009, compared with NOK 19.9 billion in 2008, and NOK 23.9 billion in 2007.
The 19% decrease from 2007 to 2008 is due to a 17% decrease in costs and a 3% increase in production. Indirect operating costs decreased by NOK 7.2 billion, mainly due to restructuring costs as a result of the merger in 2007 and the refund in 2008 of the licence partners' proportional share of the restructuring costs. Operating plant costs increased by NOK 2.7 billion, due to both higher activity and increased pressure on costs in the industry. NOK 1.1 billion is attributed to the start-up of new fields. Other variable costs increased by NOK 0.8 billion due to losses on sales of assets.
Depreciation, depletion and impairment expenses were NOK 25.7 billion in 2009, compared with NOK 24.0 billion in 2008 and NOK 23.0 billion in 2007. The increase is mainly due to new fields in production in 2009.
The NOK 1.0 billion increase from 2007 to 2008 was mainly due to higher depreciation costs as a result of higher depreciation offshore resulting from increased production and changes in the portfolio of producing fields.
Exploration expenditure (including capitalised exploration expenditure) in 2009 amounted to NOK 8.2 billion, compared with NOK 8.7 billion in 2008 and NOK 5.7 billion in 2007. The decrease from 2008 to 2009 was mainly due to fewer wells being drilled in 2009.
The increase from 2007 to 2008 primarily stemmed from a higher number of wells being drilled.
Exploration expenses in 2009 were NOK 5.2 billion, compared with NOK 5.5 billion in 2008 and NOK 3.6 billion in 2007.
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.
In 2007, 24 exploration and appraisal wells and two exploration extension wells were completed. Of these, 16 exploration and appraisal wells and both exploration extension wells resulted in discoveries.
The drilling of two exploration and appraisal wells was ongoing at the end of the fourth quarter 2009. Three exploration and appraisal wells have been completed since 31 December 2009. All of the wells, Omega North, Lower Lunde and Hild appraisal, were discoveries.
The reconciliation of exploration expenditure with exploration expenses is shown in the table below.
|
For the year ended 31 December |
||||
Exploration (in NOK billion) |
2009 |
2008 |
2007 |
09-08 change |
08-07 change |
Exploration expenditure (activity) |
8.2 |
8.7 |
5.8 |
(6 %) |
51% |
Expensed, previously capitalized exploration expenditure |
1.2 |
0.7 |
0.1 |
57% |
1398% |
Capitalized share of current period's exploration activity |
(4.2) |
(3.9) |
(2.2) |
(7 %) |
(80 %) |
Exploration expenses |
5.2 |
5.5 |
3.6 |
(6 %) |
|