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STATOIL ASA 20-F 2008 Documents found in this filing:
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 20-F
Commission File No. 1-15200 StatoilHydro ASA Norway Forusbeen 50, N-4035 Stavanger, Norway Eldar Sætre Securities registered or to be registered pursuant to Section 12(b) of the Act:
Securities registered or to be registered pursuant to Section 12(g) of the Act: None Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the Annual Report:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act Yes_X_ No__ If this report in an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes__ No_X_ Indicate by check mark whether the registrant: (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes_X_ No__ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: U.S. GAAP __ Annual report on Form 20-F 2007
Table of content
1 Introduction
1.1 Key figures
1.2 Financial highlights
StatoilHydro is publishing financial data in accordance with IFRS for the first time in this Annual Report and Form 20-F 2007. StatoilHydro did not publish financial data in accordance with IFRS in prior years, as we previously presented financial data in accordance with US GAAP. For this reason, we have not provided selected financial data for 2005, 2004 and 2003 in this Annual Report and Form 20-F 2007. Selected financial data for those years presented in accordance with US GAAP is included in our 2006 Annual Report on Form 20-F. 1.3 Events and highlights
1.4 StatoilHydro's annual report
StatoilHydro’s Annual Report on Form 20-F for the year ended December 31, 2007 (“Annual Report on Form 20-F”) is available online at www.statoilhydro.com. StatoilHydro is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, StatoilHydro files its Annual Report on Form 20-F 2007 and other related documents with the SEC. It is also possible to read and copy documents referred to in the Annual Report on Form 20-F 2007 that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC on 1-800-SEC-0330 for further information about the public reference rooms and their copy charges. The report can also be downloaded from the SEC website at www.sec.gov. 2 Business overview
2.1 Our business
StatoilHydro ASA is a technology-based oil and gas company based in several locations in Norway and internationally. We are the leading operator on the Norwegian continental shelf (NCS) and we are also experiencing strong growth in our international production.
StatoilHydro ASA is a public limited company organised under the laws of Norway and is subject to the provisions of the Norwegian act relating to public limited liability companies (the Norwegian Public Limited Companies Act). Our head office is at Forusbeen 50, NO-4035 Stavanger, Norway. Our telephone number is +47 51 99 00 00. Stavanger, Bergen and Oslo are our largest locations. Entitlement oil and gas production outside Norway represented 18% of our total output, which averaged 1.724 mmboe per day in 2007.
As of 31 December 2007, we had proved reserves of 2,389 mmbbls of oil and 576 bcm (equivalent to 20.3 tcf) of natural gas, corresponding to aggregate proved reserves of 6,010 mmboe. We are represented in 40 different countries and are engaged in exploration and production activities in 24 of them. At 31 December 2007, we had approximately 29,500 employees. We rank 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 2,300 service stations in Scandinavia, Poland, the Baltic States and Russia. We contribute to developing new energy resources, have ongoing activities in the fields of wind power and biofuels and are at the forefront with respect to technologies for carbon capture and storage. In further developing our international business, we intend to utilise our core expertise in areas such as deepwater, heavy oil, harsh-environment and gas value chains in order to exploit new opportunities and execute high quality projects. The StatoilHydro group and the main business and functional areas are presented in the following sections.
2.2 Our history
On 1 October 2007, the oil and gas assets of Norsk Hydro ASA (Hydro Petroleum) were merged with Statoil ASA, and the company changed its name to StatoilHydro ASA. Through this merger, our ability to fully realise the potential of the NCS was strengthened and our chances of succeeding as an international player improved. As a result of the merger, we are the largest international oil and gas company operating in water deeper than 100 metres. The financial and other information in this report reflect the developments of former Statoil ASA and Hydro Petroleum on a combined basis for all periods presented. Statoil was founded by a decision of the Norwegian Storting (parliament) in 1972 and incorporated as a limited 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 it changed its name to Statoil ASA. Norsk Hydro's involvement in the oil and gas industry started in 1965, when it was awarded licences by the Norwegian State to explore for petroleum on the NCS. Hydro participated in the discovery of the Ekofisk field in 1969 and the Frigg field in 1971. The development of these discoveries brought it into the petroleum refining and marketing business. In 1975, it began oil refining operations at Mongstad in Norway. In 1974, Mobil discovered the Statfjord field in the North Sea, which was to have enormous significance for further developments. During the development of Statfjord, one of the world's largest offshore oilfields, we encountered great challenges. Statfjord came on stream in 1979 and Statoil took over as operator eight years later. StatoilHydro has a 44% interest in the field. The 1980s saw us become a major player in the European gas market through large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, we were heavily involved in manufacturing and marketing in Scandinavia and we established a comprehensive network of service stations. We acquired Esso's service stations, refineries and petrochemical facilities in Denmark and Sweden. The 1990s were characterised by intense technological development on the NCS. StatoilHydro became a leading company in the fields of floating production facilities and subsea developments. We grew strongly, expanded in product markets and increased our commitment to international exploration and production in alliance with BP. In recent years, our business has grown as a result of substantial investments, including several acquisitions. This include among other the acquisition of Saga Petroleum AS in 1999, several major acquisitions in the Gulf of Mexico, acquisitions of oil sand leases in Canada in 2007, the 24% equity interest in the Shtokman Development Company and most recently the acquisition of the remaining share in the Peregrino field in Brazil (the transaction is subject to government approval), in which we also become the operator. For more information of this aquisition, see report section Operational review-International E&P. 2.3 Statements regarding competitive position
Statements referring to StatoilHydro's competitive position in the Business Overview and Operational Overview 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
2.4.1 Business environment
Macroeconomic outlook Strong global growth, and in particular China's entry into the global economy, has led to high commodity prices. Contrary to previous periods with high oil prices, this time the global economy has managed to maintain robust growth. The outlook for the global economy is still positive, and Global Insight expects global growth to be around 3.5% over the next four years, before declining somewhat to a long-term growth trend of around 3%. Coupled with the effects of the weak US economy and potential spill-over effects, the recent turmoil in the financial markets has increased the downside risk in the short term. On the other hand, the positive growth signals from Asian markets are expected to counterbalance the downside risk.
Crude oil price developments Brent Dated gradually increased by USD 37 per barrel during 2007 to average USD 72.4 per barrel. The WTI (West Texas Intermediate) grade saw similar price growth and it also averaged USD 72.4 per barrel in 2007. At the start of 2007, oil prices were relatively soft due to high oil stocks and a mild winter. However, Opec production cuts in late 2006 and spring 2007 led to an increasingly tight balance between global supply and demand for oil. Major OECD oil stocks were trimmed significantly during the year. Non-Opec output rose slightly as oil production from the former Soviet Union and increased biofuel production more than compensated for lower North Sea and Mexican production. Oil demand remained relatively supportive, with growth of one million barrels per day, mainly due to continued growth in Asia and the Middle East. Increased national control of resources In the short term, the upstream exploration and production industry in particular is expected to experience strong margins based on past investment, while at the same time facing increasing challenges in gaining access to new attractive investment opportunities. This is due to the changing conditions and the increase in goverment take resulting from higher oil prices, the increase in the amount of capital chasing limited exploration and production opportunities, a more cost sensitive environment and lack of qualified experts in a high activity environment. High oil prices, resource nationalism and the focus on energy independence, climate change and local employment, have fuelled a strong increase in interest in alternatives to conventional upstream oil and gas, such as unconventional oil and gas, new energy, natural gas value chains and energy efficiency. The International Energy Agency's World Economic Outlook 2007 estimates that cumulative investments in energy value chains globally will be approximately USD 22 trillion in 2006 dollars during the period 2006-2030, which will mean large future investment opportunities for energy companies. 2.4.2 A strategy for growth
StatoilHydro's strategy is to maximise value and potential on the NCS while growing our international production. We are an upstream focused and technology driven energy company with strong gas and downstream positions. With continued focus on HSE as a competitive advantage and a basis of our operations, we concentrate our efforts on four areas:
In the short term, we plan to focus on predictable and efficient operation by realising the potential value resulting from the merger of Statoil ASA with the oil and gas assets of Norsk Hydro ASA. In the longer term, our focus will be on developing prospects and projects that will enable us to excel and profitably grow. We endeavour to act in a responsible and sustainable manner by continuously improving energy and environmental efficiency in our production processes. Maximising long-term value creation from the NCS As a consequence of the merger of Statoil ASA with Norsk Hydro ASA's oil and gas assets, we are in a unique position on the NCS. Our combined asset base, experience and technical know-how will enable us to fully utilise these resources. The NCS portfolio is expected to continue to be the company's core activity area, income generator and technology base for many years to come. We believe the potential for further exploration on the NCS is significant, and we aim to be the industrial architect and driving force in utilising this potential to the maximum. We will strive to improve HSE performance, regularity and drilling efficiency, we will use Increased Oil Recovery (IOR) measures where appropriate and maximise the potential of the merged company. Our focus will be on delivering results and optimising our portfolio in order to maximise value creation. Building profitable international growth The company's growth beyond 2012 is mainly expected to take place in the international arena. Our short to medium-term focus is on delivering our current projects on time, at agreed cost and quality. We plan to make the most of our NCS resources, capabilities and technical experience to develop new business opportunities internationally. In the longer term, we believe that growth in our international assets will transform the structure and profile of the company. We expect to become more diversified, not only in geographical terms, but also in terms of production methods. This was demonstrated through the acquisition of the Canadian company North American Oil Sands Corporation (NAOSC) and the development of the Peregrino field (heavy oil) off the coast of Brazil, both of which present new challenges and opportunities in terms of applying our technology and experience to a different type of oil production than in the North Sea. In connection with the company's international growth our main focus will be on utilising our core expertise in areas such as deepwater, harsh environment, heavy oil and gas value chains to exploit new opportunities around the world. We believe that our skills, experience and technological ability will give us a competitive advantage in these areas. We intend to achieve this growth through an ambitious exploration programme, developing and delivering from our current international assets, and, as appropriate, acquiring new assets which complement our portfolio. Developing profitable midstream and downstream positions Compared with many of our peers, we have a strong upstream focus in terms of our total value and asset base. However, we also have a sizeable midstream and downstream portfolio in retailing, marketing, trading, refining and storage of oil and gas products. We are one of the largest seller of crude oil in the world, and our refineries, gas processing plants and service stations support our upstream positions. Our ambition is to maximise value for the company by making the most of the opportunities which these value chains represent. Creating a platform for new energy We are a leading industry player in the field of carbon capture and storage. Our ambition is to further develop our technology and capabilities in this area to create a profitable business and to reduce emissions. We are also looking into the opportunities for commercially sound investments in renewable energy chains. We have initiated projects in the areas of wind power and biofuels, setting the stage for further expansion in this area, such as offshore wind farms. 2.5 E&P Norway
2.5.1 Introduction
Exploration & Production Norway (EPN) consists of our exploration, field development and production operations on the NCS. EPN is the operator of 37 developed fields that collectively produced more than three mmboe per day in 2007, which represented about 80% of the total production from the NCS. In 2007, our average daily oil and NGL production was 817.9 mboe and our daily gas production was 95.2 mmcm (3.4 bcf), totalling 1.417 mmboe per day. We are well positioned in terms of exploration acreage throughout the licensed parts of the NCS, both within and outside our core production areas. We participate in 225 licences on the NCS and are operator for 175 of them. As of 31 December 2007, EPN had proved reserves of 1,604 mmbbls of crude oil and 535 bcm (18.9 tcf) of natural gas, which represents an aggregate of 4,971 mmboe.
2.5.2 Strategy
There are several factors that are expected to contribute to the achievement of our production goals on the NCS. They include increased production efficiency, increased drilling efficiency, cost-effective operations, improved recovery from existing fields, development of new discoveries, the proving of new reserves through intensive exploration activity, increased access to new licences, focus on health, safety and the environment (HSE) and optimal use of existing infrastructure. Stable production As fields on the NCS mature and production declines, high priority will be given to implementing measures to increase production from existing fields. The main measures in this context are more efficient drilling and increased production time on our platforms. Higher regularity is expected to be achieved through improved well work, better reservoir management, de-bottlenecking of export infrastructure, better planning of turnarounds and fewer topside plant failures.
Additional production is expected to be achieved by means of new capacity, including ramp-ups on Ormen Lange and Snøhvit, new field developments and implementation of improved oil recovery measures. Tie-ins to existing infrastructure on fields that are in decline and/or have reached a critical point in their technical life will also have high priority. A well balanced asset portfolio on the NCS with respect to regions and maturity is necessary in order to secure high production.
Gas position The proportion of natural gas from our NCS portfolio is increasing. We have a flexible transportation system, with six different landing points and flexibility in terms of gas deliveries from gas producers such as Troll and Oseberg. Finding and developing new resources We intend to achieve optimal development and exploitation of our existing portfolio in order to secure a solid foundation for future growth through continued high exploration activity. Of the 35 wells that are planned to be drilled in 2008, 30 are located in areas with existing infrastructure, and five will be drilled in frontier areas. Access to new prospective acreage is necessary in order to maintain a high production level. Active infrastructure-led exploration is also a key factor in extending the life of the infrastructure in the tail-end production phase. Safe and efficient operations are essential to our business All activities in StatoilHydro will be conducted with high focus on HSE in order to achieve our goal of avoiding harm to people and the environment. The implementation of Integrated Operations (IO) is expected to improve cooperation across activities and organisations, both offshore and onshore. Implementing IO also has the potential to increase value through higher production, higher regularity and cost reductions offshore. Upgrading and modification programmes for offshore installations are also planned with a view to maintaining safe and efficient operations. Industrial architect for NCS Due to our central position on the NCS, we have a responsibility to maintain a stable relationship with suppliers, competitors, government and other stakeholders. The NCS is a world-class arena for innovation and technological development. StatoilHydro is also a leader in the use of new technology on the NCS, including drilling and subsea technology, new solutions to reduce costs and the use of new technology to develop discoveries. As the largest operator on the NCS, we have a responsibility to take the lead in the development of optimal area solutions and overall development of the NCS. 2.5.3 Key events
2.6 International E&P
2.6.1 Introduction
International Exploration & Production (INT) is responsible for exploration, development and production of oil and gas outside the NCS. The figure above shows our exploration and production areas. In 2007, the business area had production from Canada, the US Gulf of Mexico, Venezuela, Algeria, Libya, Angola, Azerbaijan, the UK, China and Russia. In 2007, INT produced approximately 20% of StatoilHydro's total equity production of oil and gas, and our share is expected to increase significantly in the future. We have exploration activities in North America (Canada and the US), Latin America (Brazil, Cuba and Venezuela.), North Africa (Algeria, Egypt, Libya and Morocco), Sub-Saharan Africa (Angola, Mozambique, Nigeria and Tanzania), the Caspian region (Azerbaijan), Western Europe (Denmark, the Faeroe Islands, Ireland and the UK), the Middle East (Iran) and Indonesia. The main development projects that we are involved in are in Canada, the US GoM, Brazil, Angola, Nigeria, Azerbaijan and Ireland, and we believe we are well positioned for further growth through a substantial non-sanctioned project portfolio.
2.6.2 Strategy
INT is responsible for exploration, development and production of oil and gas resources outside the NCS. This includes:
INT is driving the company's future upstream growth ambition. The strategy is to access new resources through high quality exploration activities and focused business development by utilising our technological experience and project execution skills. Resources are moved effectively into production through our demonstrated project execution and operational experience from the NCS. Over the last decade, we have concentrated our efforts to access new resources around four focus areas; deepwater; harsh environment; gas value chains and heavy oil, all of which draw on our experience from the NCS. The international access strategy has proven successful, and our resource base has increased in terms of both produced volumes and technological and geographical breadth. INT's near-term focus is on strengthening our presence in existing producing regions in order to achieve stronger positioning. Gaining operatorships and building regional organisational hubs is a part of this strategy. As new fields come on stream, they will complement our existing international activities, with production ranging from Azeri gas and condensate to Brazilian heavy oil and deepwater fields in the US Gulf of Mexico (GoM). We expect to further develop our position in the gas value chain/harsh environment though our participation in Shtokman development phase 1 and in extra heavy oil through the staged development of Canadian oil sands. We will also continue to move forward our deepwater portfolio in Angola. We also have world-class technological and project management expertise in areas such as subsea wells, drilling and completion of high-pressure, high-temperature wells, Increased Oil Recovery, gas chain management, heavy oil, gas to liquids and carbon capture and storage (CCS). Our exploration strategy is based on gaining access to high-potential basins globally and targeting multiple blocks in high-focus areas. Our long-term ambition is to access at least one new basin for the company per year in order to support long-term growth. After securing access, the subsurface work has concentrated on preparing the acreage for drilling with a moderate risk profile at the portfolio level. We have strong strategic focus on increasing our share of operatorships with a view to shaping the future direction of our business. Our business development activities are highly complementary to our international exploration work, working hand-in-hand to create portfolios of projects and opportunities. Our Gulf of Mexico entry strategy is a clear example of how acquisitions and exploration can build a focused portfolio with a strong inventory of projects. By making the most of our competitive advantages, we have gained access to new projects in existing and new core areas. Business development will continue to be an important tool in accessing new resources and competences. Our strategy will support further growth through commercialising our existing technological strengths, developing new expertise and providing innovative solutions and new partnership models. 2.6.3 Key events
2.7 Natural Gas
2.7.1 Introduction
The Natural Gas (NG) business area is responsible for StatoilHydro's transportation, processing and marketing of pipeline gas and LNG worldwide, including the development of sufficient processing, transportation and storage capacity. NG is also responsible for marketing gas supplies originating from the Norwegian State's direct financial interest (SDFI). In total, we account for approximately 80% of all Norwegian gas exports and are responsible for technical operation of the majority of export pipelines and onshore plants in the processing and transportation systems 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, China and the US.
In 2007, we sold 34.8 bcm (1.2 tcf) of natural gas from the NCS on our own behalf, in addition to approximately 31.2 bcm (1.1 tcf) NCS gas on behalf of the Norwegian State. StatoilHydro's total European gas sales, including third party gas, were 74.0 bcm (2.6 tcf) in 2007. That makes us the second largest gas supplier in Europe with a market share of around 15% in the European gas market. From our international positions (mainly Azerbaijan and the US), we sold 2.2 bcm (0.08 tcf) of gas in 2007, of which 0.8 bcm was entitlement gas (0.03 tcf). We have a significant interest in the world's largest offshore gas pipeline transportation system, which is approximately 7,800 kilometres long. This network links gas fields on the NCS with gas processing plants on the Norwegian mainland and terminals at six landing points located in France, Germany, Belgium and the United Kingdom, providing us with flexible access to customers throughout Europe.
2.7.2 Strategy
NG's strategy is to maximise the value of our long-term sales business, improve our portfolio optimisation activities and establish new gas value chains. We have a large long-term gas sales contract portfolio and are continuously evaluating midstream and downstream opportunities in order to take further advantage of our existing infrastructure, access to supplies and experience in marketing of natural gas. 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 from our existing supply portfolio, to deliver larger volumes and to enter into a wider range of sales arrangements in order to reach a broader customer base. Through balancing, optimisation and trading activities, we will continue to create additional value on top of our long-term sales business. We aim to further develop our position on the NCS and internationally through increased production and investments in new fields and infrastructure aimed at serving the European and US gas markets. NG plans to strengthen established market positions in Europe with gas from the NCS, the Caspian Sea and North Africa. The market position at the Cove Point terminal on the East Coast of the US will be further developed with equity gas supplied from the Snøhvit field and with third-party gas. In addition, natural gas is the focal point of many of the exploration and business development activities carried out by both INT and EPN. In general, 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. The main objective of NG's strategy is to improve our growth opportunities in all parts of the natural gas business and to fully exploit the opportunities that changing market conditions provide us with. This means 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, LNG growth and the addition of new markets. The main task for NG is to maximise value creation in markets that are constantly changing, making active use of the new opportunities offered and managing risks within acceptable parameters. A necessary lever to support this strategy is to continue to develop, maintain and operate 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 processing plants at Kårstø and Kollsnes, will be of key importance. 2.7.3 Key events
2.8 Manufacturing and Marketing
2.8.1 Introduction
Manufacturing & Marketing (M&M) adds value through the processing and sale of the group's and the Norwegian State's production of crude oil and natural gas liquids (NGL). M&M is responsible for the group's combined operations in the transportation of oil, processing, the sale of crude oil and refined products, retail activities and marketing of natural gas in Scandinavia. We operate in 12 countries, have two refineries, one methanol plant and two crude oil terminals and have international trading activities and an extensive distribution network for businesses and private customers. Over one million customers visit our approximately 2,300 service stations daily. More than 13,000 people representing over 30 nationalities are employed by M&M. Approximately 10,500 of them work outside Norway. In 2007, we had trading activity of 781 mmbbls of crude oil and condensate, approximately 30 million tonnes of refined oil products and 11.2 million tonnes of NGL. The refinery throughput was 15.6 million tonnes. In the energy and retail market, we sold approximately 13 billion litres in 2007, including eight billion litres of petrol and diesel.
2.8.2 Strategy
Our strategy is to contribute to the integrated oil value chain by selectively building competitive midstream and downstream positions. This strategy aims to maximise value of our crude oil production and to strengthen and support the value of the group's upstream portfolio. Continued focus on safe, reliable and efficient operations is the basis for future growth in this segment. M&M will focus on further developing our position in North America to maximise the value creation from the group's crude production in Canada, the US GoM, and StatoilHydro production imported to North America from other regions. Oil Sales, trading and supply It is vital to continue to build a strong commercial organisation that is supported by flexible systems in order to succeed with increased trading activity. Manufacturing We will also endeavour to implement cost efficient and flexible liquid transportation solutions. We will seek to add value by implementing logistics solutions such as combining cargoes and crude qualities, reducing feedstock costs and providing the flexibility required to handle high acid and heavy crude oil.
Energy and retail Our ambition is to further develop and strengthen our downstream positions in Scandinavia and to establish StatoilHydro as a leading supplier of biofuels in key markets. In Eastern Europe, we plan to build on our strong Baltic and Polish position, and continue to evaluate market opportunities based on the Scandinavian concept. There will also be increased focus on expanding the downstream business in Russia, mainly based on developing a competitive retail position in the St. Petersburg area. 2.8.3 Key events
2.9 Technology and New Energy
2.9.1 Introduction
Technology & New Energy (TNE) aims to be a centre of excellence for technology and new energy contributing to global business success. This means that TNE is responsible for ensuring we have capacity and competence 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 solutions, concept development and safe and efficient operations. The research and development department, which has research centres in Trondheim, Bergen and Porsgrunn in Norway and in Calgary in Canada, is engaged in research into and the development, piloting, implementation and commercialisation of new technology. The new energy department is responsible for developing a sustainable business for new energy, comprising development projects and technology development such as wind power, biofuels, hydrogen and carbon capture and storage.
2.9.2 Strategy
TNE is an important partner for the business areas and is responsible for research and development and new energy. Technology strategy The technology strategy continues to be upstream-focused, although considerable attention is also paid to integrating technology into value chains, the exploitation of oil sands, carbon management and renewable energy sources. In addition to advancing a range of technologies, we aim to develop and/or sustain distinctive technology positions in selected areas in order to optimise ongoing operations, achieve competitive advantages and build new platforms for growth. To replace resources, we plan to develop technologies that are specifically designed to rapidly identify and acquire prime exploration acreage and production assets and improve recovery factors, especially from complex reservoirs. We also plan to develop technology aimed at successfully exploiting our widening portfolio of international ventures, which now includes tight reservoirs and heavy oil. For example, through the acquisition of NAOSC in 2007, we have become heavily involved in the Canadian oil sands business in which the main challenges are to improve recovery and meet demanding environmental standards throughout the value chain. Customised technologies and capabilities are also required to address frontier area challenges, which in some cases differ radically from those encountered on the NCS. Today, they are largely related to deepwater and harsh environments. Furthermore, our gradual transition from topside to seabed facilities, when coupled with long-distance multiphase transport and pressure boosting, will facilitate ultra-deepwater field developments and pave the way for Arctic operations. Supplier cooperation and venture activities are expected to remain important. We are also reviewing our intellectual property rights policy and clarifying our policy on technology acquisition in terms of proprietary development and cooperation as opposed to off-the-shelf purchasing.
New Energy Our New Energy business aims to achieve profitable growth in the sale of wind power and biofuels. For wind power, there are short-term opportunities in land-based and near-shore developments. In the longer term, the development of technology for offshore wind power may pave the way for the supply of renewable power on a large scale. In biofuels, the main focus is on traditional (first generation) biodiesel and bio-ethanol, with the emphasis on documented sustainable production. In the longer term, synthetic (second/third generation) products and processes are being investigated. Furthermore, we intend to sustain our position as a leading industry player in carbon capture and storage. Building on the Kyoto mechanisms (e.g. the Clean Development Mechanism), we intend to reap the benefits of our carbon dioxide expertise. We are also exploring the potential of hydrogen and other renewable energy technologies as additional areas for long-term, profitable growth. 2.9.3 Key events
Technology
New Energy
2.10 Projects
2.10.1 Introduction
Projects (PRO) is responsible for planning and executing all development and modification projects costing more than NOK 50 million, as well as for contributing to safe and efficient operations in connection with those projects. Projects is also responsible for procurement, including securing rig capacity based on a corporate rig strategy. In order to become a truly global energy player, it is essential that we are able to execute projects and thereby strengthen the company's international competitiveness. Our goal is to be world-class in terms of project execution and to deliver on time and budget, in accordance with high HSE standards and agreed quality standards. Our current portfolio consists of more than 80 modification and development projects in the execution phase, with a total expected investment cost of more than NOK 150 billion. A major part of the portfolio consists of activities related to ongoing redevelopment efforts, aimed at maximising production from the NCS. 2.10.2 Strategy
Our strategy is to develop projects on time, at cost and in a safe and reliable manner. Our ability to utilise the company's world-leading technology and execute projects in complex surroundings will be of vital importance in terms of opening up new business opportunities, as will our ability to demonstrate our core expertise in new markets. We have a growing portfolio of international projects, such as the In Salah gas compression project in Algeria, the development of the Iranian gas field South Pars phases 6, 7 and 8 and the Leismer demonstration project for heavy oil recovery in Canada. We are constantly encountering new and complex markets, and are facing increased global demand for resources due to an extremely high activity level in the oil and gas industry. This is a challenge for international project execution due to the impact it has on price levels, availability, quality and lead times for deliveries. On the NCS, there is a growing need for the redevelopment of existing fields and installations. As fields mature, production equipment needs upgrading. In the years ahead, a number of fields will need upgrading or renewal of drilling units, control systems, hydrocarbon processing systems, cranes and other major redevelopment efforts. In order to handle this in the most efficient way, we intend to use inter-field project organisations to standardise tasks and continuously search for synergies between projects and contracts. We are dependent on the cooperation of a highly professional supply industry. We aim for diversity among our suppliers, and are continuously on the lookout for innovative solutions and for suppliers that can offer us the best product, the best technology and the best quality. Our procurement function works to ensure that we have the rig capacity required to drill both new prospects and production wells. 2.10.3 Key events
3 Operational review
3.1 E&P Norway
3.1.1 Industry overview
Total production from the NCS is at a historically high level. In 2007, the total production from the NCS was 4.1 mmboe per day. However, production of oil on the NCS has decreased since peaking in 2001 and it is now at the lowest level since 1993/94. While oil production on the NCS shows a falling trend, natural gas production is increasing and we expect production of natural gas will constitute a larger share of total production in the future. This will affect both the level of activity and profitability on the NCS. Increased oil recovery from the existing fields is an important factor in maintaining the current production level. Most of the IOR measures are related to the drilling of new wells. Securing rig capacity is vital in terms of increasing the recovery factor. This has been a major challenge for the industry and, combined with a tight supply market, it has led to an upward pressure on rig rental expenses.
Another challenge facing the companies on the NCS is that future production will come from smaller and more complicated fields. The new development projects have more complex reservoirs and are technically more challenging. They will therefore demand more resources per barrel than the older and larger fields. We believe there is still large undiscovered resource potential on the NCS, both in mature and frontier areas. According to estimates published by the Norwegian Petroleum Directorate, approximately one-third of the resources on the NCS are undiscovered.
Access to attractive acreage is an important factor in realising the potential of the NCS. In January 2008, 37 companies were awarded 52 new licenses in the North Sea, the Norwegian Sea and the Barents Sea relating to APA 2007 (Awards in Predefined Areas). The annual APA concession system offers relinquished acreage and un-awarded blocks offered in previous licensing rounds located in specific mature parts of the NCS. The APA system ensures that large areas close to existing and planned infrastructures are available for the industry. The APA area will be expanded as new exploration areas are matured. The Norwegian authorities decided to postpone the 20th Licensing Round until 2009 in order to ensure cost-efficient exploration of frontier areas on the NCS according to a press release from the Norwegian Petroleum Directorate. Ensuring safe and stable operations with no harm to people or the environment is an essential aspect of operating on the NCS, and there has been increased focus on these issues in recent years. 3.1.2 The NCS portfolio
3.1.2.1 Core production areas
Our 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 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. 3.1.2.2 Potential producing areas
In addition to the producing areas, we operate a considerable number of exploration licences. The exploration acreage is located in both undeveloped frontier areas and close to infrastructure and producing fields. North Sea Total licensed acreage in the North Sea covers 66,548 square kilometres. We participate in 33,241 square kilometres and operate 20,086 square kilometres. Following execution of the work programme and prospectivity evaluation, a decision was made to relinquish five licenses and farm-out two licenses in 2007. Four licenses were awarded to us in the awards in predefined areas (APA) 2007 and we became operator of three of these.
Norwegian Sea. Total licensed acreage in the Norwegian Sea covers 41,815 square kilometres. We participate in 27,139 square kilometres and operate 18,736 square kilometres. In the deepwater region we have interests in licenses covering approximately 16,000 square kilometres. Following execution of work programme and prospectivity evaluation, five licenses were relinquished in the Norwegian Sea in 2007, two in the deep water region and three in the shallow water region. Four licenses were awarded to us in the APA 2007, and we became operator of all of these. The Nordland VI & VII and Troms II area outside Lofoten and Vesterålen is temporarily closed for petroleum activity due to environmental concerns. The Norwegian parliament will evaluate opening of this area in 2010. Barents Sea. Total licensed acreage in the Barents Sea covers 13,421 square kilometres. We participate in 11,460 square kilometres and operate 10,052 square kilometres. Following execution of the work programme and prospectivity evaluation, two licenses were relinquished in 2007. In addition, we have relinquished 5,300 square kilometres of the 13,500 square kilometres of seismic option areas. Four licenses were awarded to us in the APA 2007, and we became operator of two of these. We also became operator of one additional award from the APA 2006. 3.1.2.3 Portfolio management
We use portfolio management as an active tool to optimise our license portfolio, strengthen our core areas and achieve our long term production targets. Statoil's share in Murchison (11.52% in the Unit) was sold in June, and Trym( 30%)was sold in July 2007. Other transactions were related to exploration licences. 3.1.3 Exploration
In 2007, we participated in 24 exploration wells, 16 of which resulted in discoveries. We operated 19 of the 24 exploration wells, including 14 of the 16 discoveries. In addition, we operated two exploration extensions, both of which resulted in discoveries. In 2007, the most important discoveries in the North Sea were Ermintrude and Ragnarrock, both close to the Sleipner field. In the Oseberg area, production tests carried out on the Shetland Chalk oil discovery confirmed recoverable resources in chalk reservoirs. In the shallow water of the Norwegian Sea, the Onyx South West gas discovery increased the probability of a new gas province development. In the Barents Sea, the Goliat West well proved additional resources in deeper segments, and the Nucula discovery confirmed the oil potential in this part of the Barents Sea. The table below shows our exploration and development wells drilled on the NCS during the last two years.
3.1.4 Oil and gas reserves
As of the end of 2007, we had a total of 1,604 mmbbls of proved oil reserves and 535 bcm (18.9 tcf) of proved natural gas reserves on the NCS. Measured in barrels of oil equivalent (boe), our proved reserves consist of 32% oil and 68% natural gas, based on total proved reserves on the NCS of 4,971 mmboe.
The following table shows our proved reserves of NCS crude oil and natural gas as of the end of the periods indicated. The data is net of royalties in kind, but includes reserves attributable to our account based on our proportionate participation in fields with multiple participants. No major discoveries or other favourable or adverse events have occurred since 31 December 2007 that would mean a significant change in the estimated proved reserves as of that date. Further information on reserves can be found in note 32 - Supplementary oil and gas information - to our Consolidated Financial Statements.
3.1.5 Production
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.
In 2007, our total equity oil production in Norway was 298.5 mmbbls, and gas production was 34.7 bcm (1,227 mmcf), which represents an aggregate of 1.417 mmboe per day. Our producing fields are currently organised into four business clusters: Operations West, Operations North Sea, Operation North and Partner Operated Fields. The following table shows our average daily equity production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2007 and 2006
3.1.6 Development
3.1.6.1 Fields under development
The Alve field, in which we hold an 85% interest, is located in PL159B in the Norwegian Sea, 14 kilometres south west of the Norne field. The PDO was submitted to the Norwegian authorities in January 2007 and approved in March 2007. The field will be developed through the installation of a four-slot subsea wellhead template that will be tied back to the Norne Floating Production Storage Offloading (FPSO). Production is scheduled to start in early 2009. As of 31 December 2007, NOK 0.8 billion had been invested. The total investment for the project is estimated to be NOK 2.5 billion.
Oseberg Delta is a subsea gas and oil development of the resources in the Delta structure in block 30/9 that makes use of Oseberg Field Centre facilities for processing and export. We have a 49.3% ownership interest in the project. Investments in the project are estimated to amount to NOK 2.3 billion. NOK 1.5 billion had been invested as of 31 December 2007. Production is scheduled to start in early 2008. Gjøa will be developed by installing a subsea production system and a semi-submersible production platform. Gas will be exported via FLAGS pipeline to St. Fergus and oil export through the Troll 2 pipeline to the StatoilHydro-operated Mongstad refinery near Bergen. The Gjøa platform will process and export volumes from both the Gjøa field and the neighbouring Vega fields. The platform will be supplied with land-based electricity from Mongstad. The total investments are estimated to be NOK 29.7 billion and, as of 31 December 2007 NOK 4.2 billion had been invested. We hold a 20% interest in Gjøa. Production is scheduled to start in late 2010. The Vega/Vega Sør project comprises the development of three separate gas-condensate accumulations: Vega Nord and Vega Sentral in PL248 and Vega Sør in PL090C. Our ownership interests in the licences are 60% and 45%, respectively. 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 7.9 billion. As of 31 December 2007, NOK 0.7 billion had been invested. Production is scheduled to start in late 2010. The Vilje project comprises the development of two oil wells in the Vilje reservoir (PL036). Two satellite wells have been installed, and production from the field will be transported to the Alvheim FPSO (Marathon operated) in a 19 km pipeline. A parallel gas pipeline feeds Vilje with downhole lift gas from Alvheim. As of 31 December 2007, NOK 2.4 billion had been invested. The total investments for the project are estimated to be NOK 2.5 billion, including investments of NOK 0.8 billion on Alvheim. The date for production start-up will depend on the schedule for the FPSO, and it is estimated to be mid-2008. Tyrihans, in which we hold an interest of 58.5%, is located in the Norwegian Sea and consists of two hydrocarbon accumulations: the Tyrihans South (an oilfield with associated gas) and Tyrihans North (a gas field with a thin oil zone). The fields will be developed with subsea wells drilled and completed from five subsea templates. The well stream will be transported in one pipeline to the Kristin platform for processing. Gas injection for reservoir pressure support is provided from Åsgard B through a gas injection pipeline to Tyrihans. Both the production pipeline between Tyrihans and Kristin and the gas injection pipeline between Åsgard B and Tyrihans, as well as the subsea well templates, were installed in 2007 . Production is scheduled to start in mid-2009. The total development costs are estimated to be NOK 14.5 billion, with NOK 5.1 billion having been invested as of 31 December 2007. 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. The field will be a subsea development with two templates tied in to Åsgard B for processing through a 20 km long wellstream pipeline. The development of Morvin is currently estimated to require capital expenditure of NOK 8.7 billion, and production from the field is estimated to commence in late 2010. As of 31 December 2007, NOK 0.5 billion had been invested. The Yttergryta subsea gas and condensate field development, with an investment value of approximately NOK 1.2 billion, is an excellent example of a relatively small but unique project in our portfolio. The discovery was made in the summer of 2007 and the PDO was submitted in January 2008. Production start-up is expected to take place in early 2009. As of 31 December 2007, NOK 0.2 billion had been invested. We hold a 45.75% interest in the project. The world's largest drilling rig for Arctic areas, Aker Spitsbergen, is expected to commence production drilling on Yttergryta during the summer of 2008, and the wellstream will be tied back to the Åsgard B platform for processing and further export. Gulltopp. A long-reach well is being drilled from the Gullfaks A-platform to develop the Gulltopp field. Gulltopp, which was discovered in 2002, is a small oilfield. Due to several operational problems, the well was temporarily plugged in the third quarter of 2006. Drilling resumed in October 2007, and the estimated start-up of production is mid-2008. The PDO for Skarv was submitted in June 2007 and approved by the Norwegian Parliament in December 2007. Skarv is an oil and gas field. It is located in the Norwegian Sea. We have an interest of 36.165%. BP is the operator. Skarv extends across three production licences (PL212/262 Skarv and PL 159 Idun). The field is being developed by 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. At the time the PDO was submitted, the total development cost was estimated by the operator to be NOK 32 billion. The table below shows some key figures for our major development projects.
3.1.6.2 Redevelopments
The Statfjord Late Life (SFLL) 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. The total investments in the project are estimated to be NOK 18.9 billion, including the pipeline investment of NOK 1.8 billion. As of 31 December 2007, NOK 8.6 billion had been invested. Oseberg Low Pressure involves the installation of two new production manifolds for low-pressure wells with tie-in to second stage separators. Production is planned to start in late 2009. 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 is expected to start in late 2009 and production is planned to start in 2010. A new low-pressure compressor module on Troll C will be installed to increase capacity, and thereby production and recovery from Troll Vest. A major modification is currently being carried out on the Sleipner B wellhead platform, where pre-compression facilities will be installed in order to boost gas production through reduced wellhead pressure. Start-up is planned in late 2008. Tune Sør is a single satellite well tied back via the Tune Main template to the Oseberg Field Centre. Tie-in and production start up are planned for mid-2009. 3.1.7 Fields in production
3.1.7.1 Operations North Sea
Operations North Sea covers most of StatoilHydro's production activity in the North Sea. Our producing fields in Operations North Sea are Troll, Fram, Sleipner, Kvitebjørn, Visund, Grane, Brage, Veslefrikk, Huldra, Glitne, Volve, Heimdal and Vale. The area is dominated by the production of natural gas, as 60% of the equity production 2007 was gas. The petroleum reserves are located under water depths of between 80 and 330 metres. There is high focus on increasing and prolonging production in the area. Increased oil recovery and the exploration and development of new fields have priority. In late 2007, our application for an extension of the licence period in the Sleipner area until 2028 was approved, which is expected to have a positive impact on the economic life of the infrastructure in the area.
In 2007, StatoilHydro's share of the area's production was 236 mbbl of oil, condensate and NGL per day and 56 mmcm (1,984 mmcf) of gas per day, or 590 mboe in total per day. In October 2007, the 1,200 kilometre long Langeled pipeline, the world's longest subsea gas pipeline, began carrying gas from the processing plant at Nyhamna, via Sleipner to Easington in England. 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 Future Development Project involving a planned capacity increase on Troll A and Kollsnes was discontinued due to the decision by the Norwegian Ministry of Petroleum and Energy not to increase the production permit beyond the current level. . The building blocks that were not affected by the government decision are continued through the Troll Project, for which a PDO is expected to be submitted in 2008. Fram is connected to the Troll C platform for processing. Oil production started in 2003, and gas exports started in October 2007. 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 underneath the seabed to reduce the carbon dioxide emissions into the air. In 2007, the Sleipner field, including Volve, was granted an extension of its permit by the Ministry of Petroleum and Energy, which will enable the field to operate until 2028. We are currently exploring several prospects and discoveries in the Sleipner area that can potentially be tied in to Sleipner. Consequently, the start-up of production on Kvitebjørn was postponed. Kvitebjørn resumed production in January 2008 after examinations showed that the pipeline could be used temporarily for export. The pipeline repairs are weather dependent and are therefore scheduled for the summer season 2008. Gas and condensate exports from Kvitebjørn will be halted during the repair period.
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. Grane is an oilfield located to the east of the Balder field in the northern part of the North Sea. Oil from Grane is piped to the Sture terminal, where it is stored and shipped. Injection gas is imported to Grane in a pipeline from the Heimdal facility. In 2007, three new wells were completed using new technology, which was tested on Grane.
Brage is an oilfield east of Oseberg in the northern part of the North Sea. The oil is sent piped to Oseberg and on through the pipeline in the Oseberg Transport System (OTS) to the Sture terminal. A gas pipeline is tied back to Statpipe. Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. 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. Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS using a stand-alone production system.
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. Volve started producing in February 2008. Heimdal is a gas field located in the northern part of the North Sea. Heimdal mainly operates as a processing centre for other fields. Huldra, Skirne and Vale deliver gas to Heimdal, and gas from Oseberg is also transported via Heimdal. Heimdal had reduced regularity in 2007, which contributed to reduced production on Heimdal Vale and Huldra. 3.1.7.2 Operations West
The Operations West area contains light oil petroleum resources in a compact geographic area in which StatoilHydro is the sole operator. The main producing fields in the Operations West area are Statfjord, Gullfaks, Snorre, Oseberg, Tordis and Vigdis. Our share of the area's production in 2007 was 362 mbbl per day of oil, condensate and NGL, and 16 mmcm per day (575 mmcf per day) of gas, or 464 mboe per day in total. Operations West is the leading oil producing area on the NCS and, even after twenty years of production, we believe there are still substantial opportunities for increased value creation.
We have 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 increased oil recovery, and they have resulted in a prolongation of planned production beyond the current licence period for several of the fields. 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. In 2009, the three Statfjord platforms are scheduled for conversion to produce oil and gas with a lower reservoir pressure. During oil offloading from the Statfjord A platform on 12 December 2007, about 4,400 standard cubic metres of crude oil were spilled into the sea. Statfjord B celebrated 25 years of production in November 2007. 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. Three satellite fields, Gullfaks South, Rimfaks and Gullveig, have been developed with subsea wells remotely controlled from the Gullfaks A and C platforms. The Gimle field is a Gullfaks satellite field. Permanent production started in May 2006, converting the Gimle exploration well drilled from the Gullfaks C platform into a production well. By the end of 2007, Gimle consisted of one producer and one injector, and drilling of a new producer will start early 2008. The Oseberg area includes the main Oseberg field developed with Field Centre installations and the Oseberg C production platform, and two satellite fields, Oseberg East and Oseberg South, developed with production platforms. In addition, the Tune field and Oseberg West Flank have been developed with subsea installations and tied back to the Oseberg Field Centre. Oil and gas from the satellites is piped to the Oseberg Field Centre for processing and transportation. Oil is exported to shore through the Oseberg Transportation System, and gas is exported through the Oseberg Gas Transportation system to Heimdal and on to market. The Snorre field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A). Oil and gas is exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A. The Snorre field celebrated 15 years of production in 2007. The PL 089 asset includes the Vigdis field and the fields in the Tordis Area. The Tordis area has been developed with seven subsea satellites and two templates tied back to Gullfaks C, where the oil and gas is processed and stored for offshore loading and export. A subsea separator was installed on Tordis in 2007. The Vigdis reservoir 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 Vigdis Extension Phase 2 project will be completed by early 2008. 3.1.7.3 Operations North
Our producing fields in the Operations North area are Åsgard, Mikkel, Heidrun, Kristin, Norne, Urd, Njord and Snøhvit. Our share of the area's production in 2007 was 181 mbbls per day of oil, condensate and NGL, and 19 mmcm per day (686 mmcf per day) of gas, or 303 mboe in total per day.
This region is characterised by petroleum reserves located at water depths between 250 and 500 meters. 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 Åsgard field contains three fields: Smørbukk, Smørbukk South and Midgard. The field complex 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 in the field complex are 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. 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 pipeline to gas markets in continental Europe. 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 the ÅTS. The Urd fields, Svale and Stær, are located 10 km and 5 km north of the Norne field, respectively. The fields are produced through subsea facilities with the well stream tied back to the Norne FPSO. Production from the first two Urd wells started in the fourth quarter of 2005. 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. Njord consists of two installations. Njord A is a platform with drilling facilities and a production plant for oil and gas. Njord B is a storage vessel for oil. The Njord field has produced oil since 1997 and gas exports started in late 2007 through the ÅTS and Kårstø. Kristin is a gas 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 bars 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. In 2007, the last of twelve wells was completed and entered into production. Snøhvit is the first developed gas field in the Barents Sea. Twenty wells will produce natural gas from three gas reservoirs: Snøhvit, Askeladd and Albatross. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities on the surface. The natural gas is transported to shore through a 143 kilometre long pipeline and it is landed at Melkøya, where it is processed. Snøhvit is Europe's largest export factory for LNG. LNG 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 uncertainties related to the timing of regular and stable operations. See also Risk review-Risk factors-Risks related to our business about uncertainties with and operating risks related to development projects. 3.1.7.4 Partner operated fields
Ormen Lange, a deepwater gas field in the Norwegian Sea, is the second largest gas field on the NCS. StatoilHydro has an interest of 28.92%. StatoilHydro was the operator for the development phase and Norske Shell became the operator for the production phase that began on 1 December 2007. StatoilHydro will continue to execute approved, but not yet completed, parts of the subsea development. Ormen Lange extends across three production licences. The selected development is an extensive seabed development at depths ranging from 850 to 1,100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. Sales gas is transported through a dry gas pipeline, Langeled, via Sleipner to Easington in the UK. Production started in September 2007. StatoilHydro 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. Ekofisk is the oldest operating field complex in our portfolio. It is operated by ConocoPhillips. The ownership interest is 7.60%. The Ekofisk Area Growth project is ongoing, including several sub-projects, such as Eldfisk II, Ekofisk South and a new accommodation platform for the Ekofisk Centre. Alternatives are being evaluated for improving resource management on the Ekofisk, Eldfisk and Tor fields. StatoilHydro has a 14.82% interest in the ExxonMobil-operated field Ringhorne East. It is located within PL 027 and PL 169 in the North Sea. The unitised field started production in March 2006. Three production wells have been drilled from the Ringhorne facility. Oil is transported via Ringhorne to Balder for offshore loading. Gas is exported via Jotun into Statpipe. A fourth production well is planned. Sigyn, operated by ExxonMobil, is a gas and condensate field located 12 kilometres southeast of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. Our interest is 60%. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform. StatoilHydro has a 10% interest in the Skirne gas and condensate field, which is operated by Total. The field has two subsea templates. The well stream is transported to Heimdal for processing. From there gas is transported in Vesterled or Statpipe. The condensate is transported to Brae/Forties in the UK sector. 3.1.8 Decommissioning
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. There has been no decommissioning of StatoilHydro-operated fields during the last three years. On partner-operated fields there has been removal activity on Frigg and Ekofisk. 3.2 International E&P
3.2.1 Industry overview
A number of fundamental changes have taken place in the international oil and gas industry over the past few years. These are likely to result in continued strong competition for upstream opportunities. The strong rise in commodity prices has led to increased activity in the industry. This, combined with supplier bottlenecks, has contributed to increased costs. These changes have taken place at a time when the industry has been attracting a much higher level of competition, both in terms of the number and type of participants and the complexity of projects. Politics and new policies continue to influence the environment in resource-rich countries across the world. In general, the more resources a country has in the ground, the stricter the fiscal terms for participants. Conventional OECD resources represent a relatively minor part of discovered global oil and gas resources. The increased complexity of new projects is resulting in higher risk and capital expenditure. Moreover, unconventional reserves will also require further downstream capital expenditure (e.g. upgraders) than conventional additions to reserves have historically required. 3.2.2 Portfolio management
In November 2006, StatoilHydro and Anadarko Petroleum Corporation signed an agreement under which StatoilHydro agreed to acquire two of Anadarko's US Gulf of Mexico discoveries and one prospect for USD 901 million. The transaction was completed in the first quarter of 2007. In June 2007, we agreed with the Venezuelan government on the main terms and conditions for our participation in the new incorporated joint venture to be created for the Sincor project. The new mixed company, PetroCedeño S.A., started on 9 February 2008. At year end 2007, StatoilHydro held a 15% share in the Sincor project, while our new share in PetroCedeño S.A. is 9.677% In June 2007, we acquired 100% of the shares in NAOSC for approximately USD 2.0 billion. Through the acquisition, we gained access to 275,213 net acres of oil sands leases located in the Athabasca region of Alberta, Canada. In August 2007, we acquired the discoveries Mariner (44.44%), Mariner East (62.0%) and an additional 65.63% equity in Bressay (our interest is 81.63%) on the UK continental shelf (UKCS) from Chevron. In the same UK area we also acquired a 30% interest in the discovery Broch from the Canadian companies Silverstone and Wilderness. These are all heavy oil discoveries and StatoilHydro is the operator of all these licences. In October 2007, we signed a framework agreement with Gazprom to become a partner in the Shtokman development, phase 1. The agreement gives us a 24% equity interest in Shtokman Development Company, in which Gazprom and Total are the two other partners. The project planning phase aims to establish an acceptable technical and commercial basis for the final investment decision, which is expected to be made in the second half of 2009. Until the final investment decision is made, our exposure is limited to the company's share of the costs of planning and studies. In December 2007, we entered into an agreement to sell all the former Spinnaker assets in the shallow water of the US Gulf of Mexico to Mariner Energy, Inc. for a cash consideration of USD 243 million. The transaction was accomplished through the sale of our wholly owned subsidiary Hydro Gulf of Mexico, LLC. The sale was effective 1 January 2008. In December 2007, we signed a sales and purchase agreement with Fairfield & Mitsubishi to divest our interests in both the Dunlin (28.76% interest) and Merlin (2.35% interest) fields on the UKCS. The sale was effective from 1 January 2008 and is expected to be completed in April 2008. In March 2008, we signed an agreement with Anadarko to take over the remaining 50% in the Brazilian Peregrino project. This will give us a 100% working interest and operatorship of the development. In addition, we are acquiring Anadarko's 25% interest in the Kaskida discovery in the deepwater US Gulf of Mexico. The transaction is subject to government approval and the acquisition of the Kaskida discovery is also subject to other parties not exercising preferential rights to purchase. As of 4 April, the company has been formally notified that two of such parties intend to exercise their preferential rights to purchase which, if exercised, will result in the company not acquiring an interest in the Kaskida discovery, but will not affect the company's interest in Peregrino. 3.2.3 Exploration activity
The exploration strategy for StatoilHydro was revised in 2002, to date has been very positive. We have added significant resources and targeted new high-potential basins globally. As we have matured existing and acquired blocks, we have seen a considerable step-up in both number of wells drilled and resources discovered. We completed 47 wells in 2007 and 11 were ongoing as per year end. Of 47 wells, 18 were announced as discoveries and 14 were under evaluation at year end. All of the 11 ongoing wells have been completed in the first quarter 2008, and two of these have been announced as discovery. We are further high-grading prospects for our short-term drilling, which imply prioritisation and sequencing of the most prospective drilling targets, more optimal allocation of rig fleet and a dedicated exploration organisation to exploit the overall competence pool of StatoilHydro internationally. We plan to drill about 35 wells in 2008. The areas where we entered or had significant activity in 2007 are covered below. In addition, we have licences in Cuba, Morocco, Mozambique, the Faeroe Isles, Ireland, Denmark and Iran. 3.2.3.1 North America
3.2.3.1.1 Canada
Through a land sale in 2006, StatoilHydro was awarded operatorship for a 50% interest in two licences, EL 1100 and EL1101, in the southern part of the Jeanne d'Arc Basin near the Terra Nova Field. In 2008, we have planned the acquisition of 3D seismic data for EL 1100 and EL1101. Evaluations of existing licences will aim to identify new drillable prospects. One exploration well was completed in early 2007 to test the hydrocarbon potential of a structure southeast of the Terra Nova Field. The well, operated by Petro Canada, encountered oil and has been suspended without being production tested. A 3D seismic survey of 520 square kilometres was acquired in 2007 on EL1092 near the Hibernia field in the Jeanne d'Arc Basin. We have a 50% interest in this Petro Canada-operated licence. 3.2.3.1.2 The USA
US Gulf of Mexico Since 2003, we have established a significant deepwater portfolio and we are one of the largest deepwater acreage holders in the US Gulf of Mexico. Our current deepwater GoM portfolio consists of more than four hundred leases. acquired through the 2005 acquisitions of the EnCana and Spinnaker Gulf of Mexico portfolios, combined with a number of exploration led farm-in agreements (e.g. Chevron in Alaminos Canyon and ExxonMobil in Walker Ridge) and lease sale awards.
In 2006, we acquired Plains Exploration & Production's working interest in two US GoM deepwater discoveries (Caesar and Big Foot) and one prospect (Big Foot North), as well as Anadarko's interest in two discoveries (Knotty Head and Big Foot) and the prospect Big Foot North. During 2007, we completed four exploration wells, four appraisal wells and one sidetrack in deep waters. Two exploration wells, one appraisal well and one appraisal sidetrack were still operating at year end. The Julia and Tonga West wells were announced as deepwater discoveries in 2007. Appraisal well Big Foot 3, sidetrack number two, has confirmed the same pay intervals of the previously announced discovery and sidetrack well. In addition, during 2007, we participated in five exploration wells and one appraisal well on the shelf, two of which resulted in discoveries. We participated in both the Western and the Central lease sales held in 2007. Following the Western sale we were awarded 42 deepwater leases covering five prospects in our Paleogene focus area. We were awarded 21 deepwater blocks in the Central lease sale 205 in the first quarter of 2008. In addition we were the highest bidder on 16 leases in the Central area lease sale 206 announced on 19 March 2008. The winning bids are subject to review and final approval by the Minerals Management Service (MMS), which can take up to 90 days. There are no work commitments associated with Gulf of Mexico leases. In 2007, we sold 18 deepwater blocks to Cobalt International Energy. We also farmed out our 35% equity share in Green Bay to Anadarko in return for the rig which Anadarko brought in to drill the first Green Bay well. The completion of the North Bront exploration well resulted in StatoilHydro earning 50% of ExxonMobil's equity in their Alaminos Canyon leases. All our assets on the Shelf were sold to Mariner Energy effective 1 January 2008. In March 2008, we entered an agreement with Anadarko to acquire a 25% interest in the Kaskida discovery. (The transaction is subject to government approval and the acquisition of the Kaskida discovery is also subject to other parties not exercising preferential rights to purchase. As of 4 April, the company has been formally notified that two of such parties intend to exercise their preferential rights.) Alaska StatoilHydro was the high bidder on 16 leases, of which 14 were joint bids with ENI Petroleum, in Chukchi Sea Lease Sale 193 in Alaska, announced on 6 February 2008. StatoilHydro will be the operator of all leases. The Chukchi Sea is located offshore Alaska northwest of Prudhoe Bay, in water depths from 20 to 80 metres. The area is considered a frontier area with no production or infrastructure as of today. Our winning bids are subject to review and final approval by the MMS. 3.2.3.2 Latin America
3.2.3.2.1 Venezuela
We completed the third and last well of the minimum exploration programme in block 4, Plataforma Deltana, Eastern Venezuela in October 2007. The campaign, which was initiated in December 2004, found gas-bearing sands in the Cocuina area. The Orca and Ballena wells did not encounter commercial gas volumes. We are the operator of Plataforma Deltana Block 4 and have informed Venezuela's Ministry of Energy and Petroleum that we intend to retain the acreage around Cocuina in order to assess its commerciality and to return the rest of the acreage in the block. 3.2.3.2.2 Brazil
We have interests in seven exploration licences in four different basins in offshore waters in Brazil. We are operator for two of them. In addition, in 2008 we signed an agreement with Anadarko to acquire the remaining share and to become the operator with a 100% interest in the large Peregrino field in licence BM-C-7 in the Campos Basin. (The transaction is subject to government approval.) One appraisal well was drilled in block BM-C-7 in 2007 and resulted in a discovery. License BM-J-3, operated by Petrobras, entered into the second exploration phase in 2005. The second exploration phase (three years), has a two-well work commitment and triggered relinquishment of 50% of the original area. We also have one commitment well in BM-CAL-10, one in BM-CAL-7 and two commitment wells in BM-C-33.
In the 8th Bid Round in 2006, together with Petrobras and Repsol, we had the highest bids for three blocks in the deepwater Santos Basin. In 2007, we participated in the 9th Brazilian Bid Round and, together with Anadarko Petroleum, we successfully bid for two blocks in the Campos Basin. They were awarded in March 2008, giving us a 50% interest in blocks C-M-529 and C-M-530. The blocks won in the 8th Bid Round have not yet been awarded by the government. Pending the award by the government, we successfully bid for a 30% interest in blocks S-M-1105 and 1109 and the operatorship and a 40% interest in block S-M-1233. 3.2.3.3 North Africa
3.2.3.3.1 Algeria
The Hassi Mouina licence was officially awarded in July 2004, and we have a 75% equity share in the licence. We are the operator in the exploration phase. The Hassi Mouina block extends over 23,000 square kilometres and is situated in the western/central part of Sahara in an under-explored area. The three-year exploration period expired on 14 March 2008. A second exploration period with a one well commitment was approved by Sonatrach. A 30% relinquishment of our interest in the block is part of the contractual terms under the exploration PSA on transition from the first to the second exploration period. During 2007, we completed the seismic work programme (started in 2005), one appraisal well and two exploration wells. All three wells resulted in gas discoveries. The work programme commitments for the initial exploration period were fulfilled by the end of 2007. A fourth well (exploration well TMS-1) has been completed and announced as a discovery in the first quarter of 2008. 3.2.3.3.2 Libya
In the exploration production sharing agreement (Epsa) IV bidding round in October 2005, three licences were awarded to StatoilHydro. The licences, all operated by StatoilHydro, were ratified in December 2005, initiating a five-year exploration period. Area 94 (100% interest) covers an area of 9,849 square kilometres on the south-eastern Cyrenaica Platform with a commitment of one exploration well and 2D seismic. Area 146 (100% interest) covers an area of 2,492 square kilometres in the Murzuk basin with a work commitment of 2D seismic and two exploration wells. Area 171 (50% interest) covers an area of 11,305 square kilometres in the Kufra basin with a work commitment of two exploration wells and 2D seismic. The seismic commitments were fulfilled in 2007 for all three licences. In addition, we have a 20% interest in Areas 186/7 operated by Repsol. During 2007, 13 wells were drilled, two of which were discoveries. Drilling is expected to continue until the end of the current licence period in May 2008. 3.2.3.3.3 Egypt
StatoilHydro is operator with an 80% interest in two offshore exploration licences located in the Mediterranean, west of the Nile Delta at water depths ranging from sea level to 3,000 metres. Production Sharing Agreements for both blocks were signed in July 2007. El Dabaa Offshore (Block 9) The block covers an area of 8,368 square kilometres. We are committed to drilling one exploration well and conducting 2D and 3D seismic surveys over a four-year period. Nine hundred kilometres of 2D seismic was acquired in 2007. Ras El Hekma Offshore (Block 10) The block covers an area of 9,802 square kilometres. The related work commitment includes 2D and 3D seismic surveys over a four-year period. Seventeen hundred kilometres of 2D seismic was acquired in 2007. 3.2.3.4 Sub Saharan Africa
3.2.3.4.1 Angola
StatoilHydro holds interests in blocks 4/05, 15, 15/06, 17, 31 and 34 in Angola. Seven wells were completed in 2007, with four announced as discoveries. Block 4/05 (20% interest) is operated by Sonangol. The commitment of one exploration well was fulfilled in 2007. Block 15 (13.33% interest)is operated by ExxonMobil. A total of 34 exploration and appraisal wells have been drilled to date with 20 discoveries announced. All exploration commitments have been met and expired exploration acreage has been handed back to the authorities. Block 15/06 (5% interest) Eni is the operator of the block we acquired in 2006. The work commitment for block 15/06 is extensive, covering 3D seismic surveys and including the drilling of eight wells, to be carried out during the first five years of the exploration phase. Block 17 (23.33% interest) is operated by Total. To date, a total of 30 exploration and appraisal wells have been drilled with 16 discoveries announced, and, as a result, all exploration commitments have been met. Expired exploration acreage has been handed back to the authorities. Block 31 (13.33% interest) is operated by BP. In 2007, four wells were completed with three discoveries, and to date a total of 21 exploration wells have been drilled in the block. The exploration period ends on 1 June 2008 and all commitments have been met. Block 34 (50% interest) We are the technical assistant to the operator, the Angolan national oil company Sonangol P&P. In 2005, Sonangol P&P signed an agreement with the concessionaire to enter into the second exploration phase for Block 34. One exploration well remains to be drilled in block 34 and alternative exploration models will be evaluated for the well. 3.2.3.4.2 Nigeria
StatoilHydro is operator for two deepwater exploration licences, OML 128 and OML 129. In addition, we have shares in four exploration licences: OPL 324 and 315, operated by Petrobras, OPL 242 and OPL 256, which we acquired through the acquisition of Spinnaker and which are operated by Ocean Energy (Devon).
OML 128. (53.85% interest). In addition to the Agbami field, which is expected to come on stream in mid-2008, two leads have been identified in the block. A new 3D survey is planned for 2008.
OML 129. (53.85% interest). There are two discoveries in the block, Bilah and Nnwa. Only one well has been drilled in the Bilah condensate discovery so far. The Nnwa discovery extends into the Shell-operated Block OML 135 (known as the Doro structure). In 2007, StatoilHydro and Shell (SNEPCO) initiated a joint subsurface project with the aim of developing a common reserve base and appraisal strategy for the combined NnwaDoro structure. This project will continue in 2008. OPL 315. In 2005, we were awarded a 45% share in block OPL 315 with Petrobras as operator. The licence is committed to carrying out a work programme by February 2011 consisting of one well and a seismic survey. OPL 324 (25% interest) The second commitment well, Kiniun-1, was drilled in 2006. All commitments have been fulfilled and the block will be relinquished in 2008 OPL 242 (15% interest) One commitment well was drilled in 2007, Opukiri-1. All exploration obligations have been fulfilled. OPL 256 (12.5% interest) The third commitment well in this block, Ofuruma-1, was drilled in 2007. Obligations have been fulfilled and an application for relinquishment of the entire block is pending approval. 3.2.3.4.3 Tanzania
StatoilHydro gained access to during a licence round in 2005. A PSA was signed in April 2007 with the Tanzanian Government and the Tanzanian Petroleum Development Cooperation (TPDC). We are the operator, with a 100% interest. The exploration period is divided into three stages:
We established a local office in Dar es Salaam in late 2007. The 2D seismic acquisition is planned for 2008. 3.2.3.5 Caspian
3.2.3.5.1 Azerbaijan
We have a 25.5% interest in the Shah Deniz licence operated by BP. All exploration commitments have been fulfilled. There was a major gas-condensate discovery in 2007 confirming sufficient gas at Shah Deniz for a second stage development. We signed an exploration, development and production sharing agreement (PSA) in 1998, with BP as operator, covering the Alov, Araz and Sharg structures. We have a 15% interest in this PSA, which is located roughly 150 kilometres south-east of the Azeri capital of Baku. The contract area covers about 1,400 square kilometres and is located at water depths of 450 to 800 metres. The structures are located in the area of the Caspian Sea that is the subject of a dispute between Azerbaijan and Iran, and, since the contract was signed, Iran has claimed that parts of the area are in Iranian waters. The first well of three commitment wells in the area is planned to be drilled within 12 to 18 months after settlement of the border issue, and a drilling location for this first well has been identified. Negotiations with SOCAR, the State Oil Company of Azerbaijan, have resulted in a freezing of the licence fee until the border issue is resolved, as well as in an extension of the exploration period until six months after the completion of the third well. It is not expected that the border issue will be resolved by 2008. 3.2.3.6 Western Europe
3.2.3.6.1 The United Kingdom
StatoilHydro is a 30% partner in a group of Chevron-operated exploration licences west of Shetland. In 2005, a discovery was made in the original license on the Rosebank/Lochnagar prospect. A three-well drilling programme to appraise this discovery commenced late in 2006. Three appraisal wells and a sidetrack were completed in 2007, with one announced discovery. Chevron plans to return to exploration/appraisal drilling in the area in late 2008 or early 2009. In 2007, we completed the acquisition of the discoveries Mariner (our interest is 44.44%), Mariner East (62.0%) and an additional 65.63% equity in Bressay (81.63%) on the UKCS from Chevron. StatoilHydro is the operator of these discoveries. In addition, a separate agreement was entered into with the Canadian companies Silverstone and Wilderness for the right to participate in the Broch discovery in block 9/16. Equity (30%) and operatorship of the Broch licence was transferred to us in March 2008. These are all heavy oil discoveries which are currently under appraisal. 3.2.3.7 Other areas
3.2.3.7.1 Indonesia
We were awarded one offshore exploration share in the deepwater Kuma block in January 2007. The Kuma block lies directly off the west coast of Sulawesi and covers an area of over 5,000 square kilometres. Water depths are between 1,000 and 2,000 metres. Our share in the Kuma block is 40% and ConocoPhilips is the operator. The work commitment consists of 2D seismic and one exploration well. In March 2007, StatoilHydro, together with PT Pertamina (Persero), was awarded the Karama offshore exploration block located adjacent to the Kuma block. We are the operator, with a 51% share. The three-year work commitment consists of 3D seismic and three exploration wells. 3.2.4 Oil and gas reserves
The proven reserves of the international business area increased by 0.7% in 2007, from 1,032 mmboe to 1,039 mmboe.
New projects sanctioned in 2007 were the most important driver behind the increase in reserves. The Peregrino project in offshore waters of Brazil was sanctioned in March 2007, and the Pazflor project on block 17 in Angola was sanctioned in December 2007. Revisions of existing estimates had a net positive impact on the 2007 accounts. The expected future oil price used as the basis for entitlement calculations has risen substantially in 2007 compared with 2006. This has contributed negatively to our proved reserves of international fields which are regulated by PSAs. Acquisitions and divestments during 2007 had no effect on the international proved reserve balance. North American Oil Sands Corporation was officially taken over by StatoilHydro in the middle of 2007, but the current maturity level of the asset does not justify recognition of proved reserves. The share of developed reserves at year end 2007 was 456 mmboe, which is up 18.5% from 2006. Of the 2007 reserves, 785 mmboe are oil/NGL and 40.4 bcm (1,426 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 note 32 - Supplementary oil and gas information - to our Consolidated Financial Statements.
3.2.5 Production
StatoilHydro's petroleum production outside Norway amounted to an average of 307 mboe per day entitlement production and 422 mboe per day equity production in 2007. The total annual entitlement production in 2007 was approximately 112 mmboe compared with 85 mmboe in 2006.
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 2007 and 2006. The new fields that came on stream in 2007 were Spiderman, Q and San Jacinto in the US Gulf of Mexico and Rosa and Marimba North in Angola.
3.2.6 Fields under development and in production
This section covers projects under development and fields in production. Pre sanctioned projects including some discoveries in early phase evaluation are also presented. Exploration activities are described in the previous section Exploration Activity. This section often refers to a field's plateau production. This refers to yearly average equity production at plateau for a field, 100% (not our share). Capacities also refer to the total field or facility, 100% share. The number of development wells as of 31 December 2007 for producing fields is provided under Production above. The total number of development wells in fields under development, that were already drilled or undergoing drilling as of year end 2007 was 75. 3.2.6.1 North America
StatoilHydro's E&P activities in North America comprise interests in the US Gulf of Mexico, off the eastern coast of Canada, and oil sands activities in the Alberta province in onshore Canada. 3.2.6.1.1 Canada
Oil Sands In June 2007, we acquired 100% of the shares in NAOSC for approximately USD 2.0 billion. At the time of acquisition, NAOSC owned interests in 275,213 net acres of oil sands leases located in the Athabasca region of Alberta. In order to determine the extent of the exploitable bitumen pools, a total of 286 exploration and delineation wells were drilled by NAOSC in the region from 2003 to 2007. In its raw state, bitumen is a heavy viscous, tar-like form of oil that we plan to produce using the steam assisted gravity drainage method (SAGD) from a depth of approximately 1,400 feet with an average producing zone thickness ranging from 50 to 100 feet. The project life is expected to exceed 20 years and it will be developed in phases. The Leismer SAGD Demonstration Project was sanctioned by the board of directors in December 2007 with a capacity of 20,000 boe per day, and we anticipate the sanctioning of further project phases after 2009. Initial production is scheduled for mid-2010. Also, in August 2007, we submitted an application to the Alberta regulatory authorities for the full 220,000 boe per day commercial SAGD project. In December 2007, we submitted an application to the Alberta regulatory authorities for the construction of an upgrader to process the bitumen into lighter synthetic crude oil. East Coast Offshore East coast offshore consists of non-operated, mature oil production from the Hibernia and Terra Nova fields and two discoveries under appraisal - Hebron and Hibernia Southern Extension. Operational challenges include harsh weather conditions and ice management.
Discoveries under appraisal The Hebron oilfield was discovered in 1981. The field is operated by Chevron and our interest is 10.2%. The Hebron partners signed a Unitisation and Joint Operating Agreement in 2005. Negotiations with the Provincial Government resumed in 2007 and resulted in the signing of a Memorandum of Understanding. Development will probably comprise a gravity-based structure platform (GBS) supporting all modules (production, development and quarters) and developing several reservoirs. The Hibernia Southern Extension project operated by ExxonMobil comprises the development of resources in several fault blocks to the far south of the existing Hibernia Main Field. The submission of a Development Plan Application is planned for 2008 pending commercial agreement within the partnership and the signing of a Memorandum of Understanding with the Provincial Government. Fields in production The Hibernia field is developed with an iceberg-resistant GBS type platform which supports all topside facilities, twin-drilling derricks and living quarters. Crude is stored in caissons in the GBS and offloaded to tankers. The field is producing from 51 wells, including several world-class extended reach drilling wells. Terra Nova. Subsea wells are centred in four iceberg scour resistant excavations on the seabed. Wells are connected to a double-hulled, ice-reinforced FPSO via production and injection risers. Terra Nova's production efficiency is low due to a number of technical issues on the FPSO. Several initiatives are underway to improve reliability of the production system. 3.2.6.1.2 U.S. Gulf of Mexico
We have step by step built a high quality asset portfolio in US Gulf of Mexico through a clear strategy combining acquisitions and exploration. Discoveries under appraisal The Jack oil field is located at Walker Ridge 758/759, approximately 250 miles south-west of New Orleans, Louisiana. Jack, which was discovered in 2004, was part of the acquisition of Encana's US GoM deepwater properties in 2005. Chevron is the operator, and we have a 25% interest. We are planning further appraisal activities in 2008. An integrated project team has been formed and it is evaluating various development concepts. St. Malo, located at Walker Ridge 678, is operated by Chevron and it was also part of the Encana acquisition in 2005. St. Malo and Jack are in approximately 7,000 feet of water and separated by approximately 25 miles. We have a 6.25% interest in St. Malo. Currently, an integrated project team is exploring various development solutions at St. Malo, and we are planning further appraisal activities in 2008. Fields under development The Tahiti field located at Green Canyon 640 was the core field acquired in our 2005 acquisition of Encana's deepwater Gulf of Mexico properties. We have a 25% interest in the Chevron-operated field. The Tahiti development will consist of a Spar production platform connected to two subsea drill centres with production capacity of 125,000 bbl per day. Originally, first production was planned for mid-2008. However, in June 2007 we were notified of a problem with the mooring shackles, which is expected to delay the hull installation by 10 to 12 months. First production on Tahiti is now estimated to occur in the second half of 2009. We acquired our 25% interest in the Murphy-operated oil field Thunder Hawk as part of the Spinnaker acquisition in 2005. The field is located at Mississippi Canyon 734. The field will be developed with a floating semi-submersible tied in to a third party processing facility in Mississippi Canyon 736. The processing capacity is expected to be 45,000 bbl of oil per day. Fields in production As of 31 December 2007, we produced oil and gas from several deepwater fields as well as many shelf fields in the GoM. Our Eastern Gulf fields were part of the Spinnaker acquisition in 2005. Our deepwater natural gas fields comprising Spiderman, San Jacinto and Q made us as a key player in the development of the Eastern GoM. The fields in the Eastern Gulf were developed via subsea tie-back to the Independence Hub, a floating production facility installed in 2007 on Mississippi Canyon Block 920. The Independence Hub was constructed and is owned by third parties and is capable of processing one billion cubic feet of natural gas per day. We own 12.7% of the capacity of the hub. Spiderman, San Jacinto and Q commenced production as the Independence hub came on stream in fourth quarter 2007. Lorien, located at Green Canyon 199, is producing through a two well subsea tie-back to Shell's Bullwinkle platform. In June 2007, Lorien experienced an unexpected one-month shut-in. Subsequent to the shut-in, production has not been restored to its previous rates. The operator, Noble Energy, is currently evaluating scenarios to fully deplete the reservoir. We acquired our 25% interest in the Murphy-operated Front Runner field as part of the Spinnaker acquisition in 2005. Due to production shortfalls, we announced an extensive review of the field in October 2006 to determine whether the recoverable resources estimated at the time of the acquisition could be produced from the field's reservoirs. Our review concluded that the geology of Front Runner is more complex and the reservoir communication weaker than expected at the time of acquisition. As a result, the expected recoverable reserves from Front Runner were reduced by 56% due to lower expected volumes of oil in place and reduced expected recovery rates. The Spinnaker acquisition also gave us , which are two smaller deepwater fields located at Mississippi Canyon 496 and 299, respectively. Shelf. At year end 2007 we produced oil and gas from 32 blocks on the shelf. All our former Spinnaker assets on the shelf were sold to Mariner Energy effective 1 January 2008. 3.2.6.2 Latin America
Our current asset portfolio in Latin America comprises our interest in the onshore extra heavy oil producing asset named the Petrocedeño Mixed Company (the former Sincor project), and the heavy oil Peregrino development project in Brazil. We are also pursuing positions in Mexico and have a representation office in Mexico City. 3.2.6.2.1 Venezuela
The Petrocedeño project (former Sincor project) involves the exploitation of extra heavy crude oil from the reservoirs in the Orinoco Belt. A diluent is added in order for the 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. Sincor C.A., owned by the project partners, operates the field and is responsible for the development, operation, upgrading and marketing of its products. At year-end 2007, we held a 15% share in the Sincor project. A major maintenance turnaround is scheduled for 2008 to perform activities to grant operational reliability of the Upgrader according to the maintenance plan. During this period light oil upgrading will be affected and it is expected that heavy oil will be produced and marketed as diluted crude oil. In 2007, Decree-Law 5.200 for Migration mandates the transformation of Sincor and other oil projects into incorporated joint ventures with minimum majority participation by the state of 60%. As a result, our participation in Sincor will be reduced to 9.677% after the migration to an incorporated entity is completed as mandated by law. The new mixed company, known as Petrocedeño, S.A., was incorporated in late 2007. Petrocedeño, S.A. became effective from 9 February 2008. The transfer of control of operations of the Sincor project on 1 May 2007 and the signing of the Memorandum of Understanding on 26 June 2007 relating to the migration into a mixed company necessitate changes to the Sincor financing agreements. Petrocedeño, S.A., is financed with a mix of shareholders equity and debt. The lenders to the former Sincor project have come to agreement on all terms and conditions related to the financing of Petrocedeño, S.A. The financing agreements have been signed and took effect as of the date of closing. 3.2.6.2.2 Brazil
In March 2008 StatoilHydro and Anadarko signed an agreement whereby StatoilHydro will take over the remaining 50% in the Brazilian Peregrino project, offshore off Brazil. This will give StatoilHydro a 100% working interest and operatorship of the development. The transaction is pending governmental approval. The development was sanctioned by the partners in March 2007 and approved by the Petroleum National Agency in May 2007. The field will be developed with an FPSO and two drilling/wellhead platforms. The first oil is planned to come on stream within 2010 and peak production of 100 mboe per day is expected to be reached within the first year of production. 3.2.6.3 North Africa
StatoilHydro has interests in onshore producing assets in the North African countries Algeria and Libya. 3.2.6.3.1 Algeria
We have a position as a significant gas seller in Europe. Our strategy is to serve this market from multiple sources. Due to its close vicinity to Europe, Algeria is an attractive country that can contribute to realise this strategy. The decision to enter into Algeria was made in 2003 and our engagements in all assets have a long-term perspective. The overall security and political situation is monitored continuously. We recognise the need for a greater level of protection for personnel and property compared with Europe. Appropriate measures are continuously being assessed based on the perceived risk level. In our evaluation the current risk level will continue throughout 2008. 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. A Contract of Association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and StatoilHydro. A joint marketing company sells the gas produced in the development, and all gas produced until 2017 has been sold under long-term contracts. The In Amenasonshore development is the fourth largest gas development in Algeria containing significant liquid volumes. The development was built and is operated through a joint operatorship between Sonatrach, BP and StatoilHydro, and we have a 50% share of the development costs. The rights and obligations are governed by a production sharing contract, giving BP and StatoilHydro access to a share of the liquid volumes only. The production of gas started up in mid-2006 and the production of the liquids commenced in December 2006. Following initial start-up challenges the production is now at stable levels. 3.2.6.3.2 Libya
Fields in production The Mabruk West onshore oil field is situated in the north of Libya. The Libyan authorities approved a field development plan (FDP), for Mabruk Phase IV in Mabruk Central and East in July 2004. The development includes the construction of new facilities and the drilling of additional development wells in East and West Mabruk. The new gas oil separation plant came on stream in June 2007. The FDP for Mabruk Phase V covering the Dahra and Gharian areas has not yet been formally approved by the Libyan authorities. Murzuk consists of several fields within the Murzuk basin. Production from the NC 186 A-field started in 2003, the NC 186 D-field commenced in 2004, and the NC 186 B and H fields came on stream in 2006. The 186 A, B, D and H fields are being developed with one common processing facility. Oil from these fields is transported from the NC 186 gas oil separation plant and blended with oil from NC 115 and then transported by pipeline to the Az Zawia terminal west of Tripoli. The FDP for the NC 186/115 I/R field was approved by Libya's National Oil Company (NOC) in September 2007. The master development plan for the Murzuq gas utilisation project Phases I and II was finalised in June 2007, and the project is expected to be completed in late 2009. NOC has initiated renegotiation of the existing production and sharing agreements with independent oil companies operating in Libya in order to increase the Libyan share of production. NOC's aim is to have all production and sharing agreements in Libya updated to the latest standard, the Exploration Production Sharing Agreement - concession round IV format. NOC is currently reviewing the contracts for licence 186 in Murzuq and C-17 in Mabruk, where StatoilHydro is a partner. 3.2.6.4 Sub Saharan Africa
StatoilHydro's current development and production portfolio in Sub Saharan Africa comprises blocks 4/05, 15, 17 and 31 offshore Angola, and the production licenses OML 127 and OML 128 offshore Nigeria. 3.2.6.4.1 Angola
The Angolan continental shelf is the largest contributor to StatoilHydro's present production outside Norway. It yielded more than 100 mboe per day in entitlement production at the end of 2007, representing approximately 35% of the group's total international oil and gas output. FPSO vessels with subsea wellheads are the preferred oil-field development concept in deepwater Angola due to the great water depths, high production volumes and lack of infrastructure. Current production from Angola comes from the Kizomba A, Kizomba B, Xikomba, Marimba North and Mondo fields in block 15, and Girassol, Jasmim, Rosa and Dalia fields in block 17. Marimba North and Rosa came on stream in 2007 and Mondo came on stream 1 January 2008. Gimboa in block 4 and Saxi Batuque in block 15 are both expected to commence production in 2008.
In December 2007 the operator Total announced that the Pazflor field in block 17, is ready for development. A new development project, PSVM in block 31, is expected to be approved in 2008. Work is also ongoing to pursue the CLOV development in block 17, additional development hubs in block 31 and satellites like Clochas and Mavacola in block 15. Block 17 is operated by Total and our interest is 23.33%. Production from the block currently comprises the Girassol, Jasmin, Dalia and Rosa development areas. The Girassol and Jasmim development areas both produce over the Girassol FPSO. The plateau production level, reached in 2005, was 250 mboe per day. The second FPSO, Dalia, commenced production in December 2006, and is expected to reach peak production level of 240 mboe per day in 2009. The first oil from Rosa a tie-back to the Girassol FPSO, was produced in June 2007 and the peak production level of 150 mboe per day is expected to be reached in 2008. The combined production on the Girassol FPSO has a capacity limit of 250 mboe per day. The Pazflor project comprises the discoveries Perpetua, Acacia, Zinia and Hortensia. Pazflor was sanctioned in 2007 by StatoilHydro and Sonagol approved the main contracts by the end of 2007. The FPSO is expected to have a peak production of 200 mboe per day, with start-up scheduled in 2011. After the planned commencement of production in the Pazflor development project, the installed production capacity on block 17 will be approximately 700 mboe per day. Work is ongoing to pursue the common development of four additional discoveries, Cravo, Lirio, Orchidea and Violeta which will comprise another potential development called CLOV. We have a 13.33% interest in block 15, which is operated by ExxonMobil. Three FPSOs were in production at 31 December 2007: Kizomba A, Kizomba B and Xikomba. On 1 January 2008, the Kizomba C-Mondo FPSO started production. One more FPSO, Kizomba C-Saxi/Batuque, is expected to come on stream in 2008.
Kizomba A, which encompasses the Hungo and Chocalho discoveries, commenced production in August 2004, and peak production of 250 mboe per day was reached in 2006. Marimba North commenced production as a tie-back to the Kizomba A FPSO in September 2007. The peak production limit on the FPSO was then increased to 270 mboe per day, of which Marimba North produces 35 mboe per day. Kizomba A is expected to fall off plateau in the second quarter of 2008. Kizomba B, which encompasses the Kissanje and Dikanza discoveries, commenced production in July 2005. Xikomba is a small, isolated discovery producing from a leased FPSO. The Kizomba C-Mondo and Kizomba C-Saxi/Batuque projects were sanctioned in 2005. The Kizomba C-Mondo FPSO started up on 1 January 2008. The Kizomba C-Saxi/Batuque FPSO is expected to start up in mid-2008. The combined Kizomba C production is expected to reach plateau levels of 200 mboe per day in 2009. Work is also ongoing to pursue the development of two medium-sized discoveries: Clochas and Mavacola. This ultra deepwater licence on block 31 is operated by BP, and we have a 13.33% interest. The common development of the first four discoveries in the northern part of the block, Plutao, Saturno, Venus and Marte (PSVM) is expected to be approved in 2008. Two to four additional production hubs are expected to be launched. The Gimboa field, which is located in block 4/05, was sanctioned in April 2006. The operator for the block is Sonangol P&P and we have a 20% interest in the block. Peak production from the field is expected to be 35 mboe per day and the FPSO is expected to start production in the second half of 2008. In 2007, an investment decision on a gas export project was sanctioned for block 15. For block 17, Phase 1 of the project, comprising gas storage in block 2, was sanctioned in 2007. Angola LNG will use the gas. We are not a partner in Angola LNG, but all costs will be recovered under the terms of the PSAs and providing a gas export solution makes it possible to avoid loss of oil recovery on the fields. Planning is ongoing for Phase 2 of the project for block 17, comprising the transportation system to Angola LNG . 3.2.6.4.2 Nigeria
Even with a newly elected government in place, the political situation remains unstable, particularly in the strategically important oil region in the Niger Delta. Consequently, the overall security and political situation is monitored continuously. We have developed rigorous security measures to protect our personnel and other assets. Appropriate measures are continuously being assessed based on the perceived risk level. The Agbami field in deep waters off Nigeria is developed with an FPSO and first oil is expected in 2008. Agbami, operated by Chevron, is located in licences OML 127 and OML 128, and our interest in the unitised field is 18.85%. The Agbami field is expected to reach a plateau production of 230 mboe per day from mid-2009. The Nigerian Department of Petroleum Resources has initiated a process to review the terms of the 1993 production sharing contract terms. The affected deepwater operators in Nigeria (seven companies) have been asked to form a joint operator group for this purpose. 3.2.6.5 Caspian
StatoilHydro's current interests in the Caspian area comprise projects in Azerbaijan and a representative office in Kazakhstan. 3.2.6.5.1 Azerbaijan
In 1992, we established a presence as one of the first international oil companies in the Caspian Sea. Since then, we have entered into three PSAs in Azerbaijan, and we are among the largest foreign oil companies in the country in terms of proved reserves and production. At present, we hold interests in three PSAs offshore in the Azeri sector of the Caspian Sea: the Azeri-Chirag-Gunashli (ACG) oil field, the Shah Deniz gas and condensate field further described in this report section and the Alov, Araz and Sharg prospects described under report section Operational review-International E&P-Exploration activity. The Caspian region has long been viewed as an area with a substantial risk of increased economic, social and political instability. Although the general situation has improved, there are still political disputes that remain unsolved in both Azerbaijan and Georgia, and the existing risks should not be underestimated. Ongoing negotiations concerning the Caspian Sea. A binding legal regime governing the division of the Caspian Sea between the five border states of Azerbaijan, Iran, Kazakhstan, Turkmenistan and Russia is yet to be agreed. This has on occasion led to disputes over rights to hydrocarbon resources between Azerbaijan and Iran and between Turkmenistan and Azerbaijan. There are currently bilateral agreements in place between Russia, Kazakhstan and Azerbaijan. StatoilHydro is a partner with an 8.56% interest in the BP-operated PSA. The ACG field development is being developed in three phases in addition to the Early Oil Production phase (EOP). We expect overall daily production from ACG to reach the plateau level of around one million bbls per day by 2010. The Chirag platform has been producing as a part of EOP since November 1997 and it is currently producing at stable levels. ACG Phase I has been completed with the exception of water injection, which commenced during 2007 and will be completed in 2008. Central Azeri started oil production in early 2005 and gas injection started in 2006. All construction activities have been completed on ACG Phase II. West Azeri commenced oil production in 2005 and East Azeri commenced oil production in late 2006. The pre-drilling programme for ACG Phase III(Deep Water Gunashli development) commenced during 2005 and continued successfully in 2006. Overall Phase III construction activities are progressing on schedule. Two offshore platform jackets with topsides were installed during 2007. It is anticipated that the first oil from Phase III will be delivered during the second quarter of 2008. Total ACG production is expected to reach 900 mbbls of oil per day by the end of 2008. The Deep Water Gunashli subsea water injection facilities were sanctioned during 2006 and are planned to be operational in 2009. Export of hydrocarbons. The Caspian Sea is landlocked, without direct access to open sea. The export of oil is therefore dependent on onshore pipelines. Currently, crude oil from ACG is transported to the Mediterranean Sea through the 1,760 kilometre Baku-Tbilisi-Ceyhan (BTC) Pipeline, in which we participate with an 8.71% interest. The commissioning of the BTC Pipeline ensured export flexibility through multiple pipelines and thereby spread the risk involved in commercialising the land-locked upstream resources. The BTC Pipeline was sanctioned in 2002 and completed in May 2006. In the fourth quarter of 2007, the BTC Pipeline had an export capacity of more than 900 mbbls of oil per day. The Shah Deniz area covers 860 square kilometres and lies at a water depth of between 50 and 500 metres. The partners have completed a four-year exploration phase involving a three-dimensional seismic survey and the drilling of three wells. The partnership submitted a notification of a commercial discovery in 2001 and entered into a 30-year development and production period. StatoilHydro is the commercial operator covering gas sales, contract administration and business development for the Shah Deniz stage I. This appointment also covers the South Caucasus Pipeline system (SCP) for gas transport to markets in Azerbaijan, Georgia and Turkey. BP is field operator and we have a 25.5% interest. Shah Deniz Stage I development on the eastern flank of the reservoir and a 680 kilometre long, 42-inch pipeline, from the landing terminal through Azerbaijan and Georgia to the Turkish border (SCP), was sanctioned by the partnership in 2003. The SCP system has been prepared for expanded capacity to facilitate future development stages. Shah Deniz Stage I commenced production on December 2006, but the field had to be shut down due to well problems, in 2007all four pre-drilled wells were tied back and production resumed in February 2007. The plateau production from stage I is expected to be approximately 8.6 bcm (300 bcf) per year and to be reached after two to three years of production. 3.2.6.6 Western Europe
We have interests in producing and development assets in the UKCS and Ireland and an early phase evaluation asset in Denmark. Our ambition is to continue to build on our portfolio, whilst pursuing opportunities to improve on the production and cost performance of our current producing assets and bring through to development the existing discoveries. In 2007 we acquired several heavy oil discoveries on the UKCS, Bressay, Mariner/Mariner East and Broch. These are presented under section Exploration Activity. 3.2.6.6.1 United Kingdom
In 1983, the UK office was established as a trading office. Exploration and production activities, which started in 1987, were strengthened by the acquisition of Aran Energy PLC in 1995. We continue to participate as both partner and operator in UK licences Fields in production The UK portfolio comprises the fields Schiehallion, Alba, Caledonia, Dunlin, Merlin and Jupiter. Most of our UK fields are currently in tail-end production. In March 2008 we signed an agreement to divest our interest in the Dunlin and Merlin fields, effective 1 January 2008. 3.2.6.6.2 Ireland
The Corrib gas field, in which we have a 36.5% interest, lies on the Atlantic Margin north-west of Ireland. The Corrib field development, operated by Shell, was sanctioned in 2001 and the production licence was granted in late 2001 with a duration of 30 years. 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 linkline to the existing Irish gas grid. The Irish planning authorities granted planning permission for the gas terminal in October 2004. Project execution was suspended in July 2005 due to protests by some local landowners. Following a comprehensive safety review by the Irish authorities, work on the project recommenced in May 2006. Currently, six of the seven offshore wells have been drilled and civil work continues on the onshore terminal site. Construction of the gas terminal commenced in July 2007 and is ongoing. As part of a community consultation process, alternative pipeline routes have been identified, and the final planning application for the pipeline will be made by mid-2008. 3.2.6.6.3 Denmark
Discoveries under appraisal We have a 25% interest in the Hejre field, operated by Dong, in licence 5/98. This is an undeveloped oilfield located at a water depth of 70 metres in the Danish sector of the North Sea. Field challenges include high pressure and high temperature reservoir. The partnership is in the concept evaluation phase. 3.2.6.7 Middle East
StatoilHydro is pursuing business development opportunities in the Middle East region and has representative offices in Riyadh (Saudi Arabia), Abu Dhabi and Dubai (United Arab Emirates), Doha (Qatar) and Amman (Jordan, covering Iraq). 3.2.6.7.1 Iran
In December 2002, we became operator for the development of the offshore part of the South project under a buy-back contract with a 37% share during the development phase. The South Pars phases 6/7/8 offshore project comprises three wellhead platforms with three pipelines for gas to shore, a condensate loading line and associated single point mooring (SPM) for condensate exports, the drilling of 27 production wells, the hook-up of three pre-drilled wells and the required reservoir management. All three jackets were installed during the first part of 2004 at a water depth of 65 meters in the Persian Gulf. Drilling and completion of the 30 production wells was finalised in January 2006. Two of the 32 inch pipelines to shore have been installed, tested and are ready for commissioning. The SPM buoy has been completed. Together with the SPD (South Pars Development) 7 tripods and flare tower, the SPD 9 platform topside was installed offshore during the spring of 2007. We are presently completing the SPD 9 platform for production start up in 2008 and are preparing SPD 7 and SPD 8 for onshore mechanical completion followed by offshore installation and production start up during 2008 and 2009. Planning for installation of the third pipeline is progressing. StatoilHydro entered into a contract with the National Iranian Oil Company (NIOC) for exploration of the Anaran block close to the Iraqi border in April 2000. In 2003, our interest was reduced to 75% through a farm out to Lukoil. A discovery on the Azar structure was made in 2005 and a discovery on the Changuleh structure was made in September 2006. A commerciality report for Azar was submitted to NIOC in December 2005, and Azar was declared commercial by NIOC in the middle of 2006. A Master Development Plan for the combined development of Azar and Changuleh was submitted to NIOC in December 2007. Further review of the project is currently ongoing. StatoilHydro signed an exploration and development service contract with NIOC for the Khorram-Abad block in Lurestan province in south-western Iran in September 2006. The block covers 7,400 square kilometres, and the work programme includes acquisition of 600 kilometres of 2D seismic and the drilling of three exploration wells. The seismic shooting started in August 2007 and is still ongoing. See report section Risk review - Risk factors for additional information concerning the risk of US sanctions related to activities in Iran. See report section Risk review - Legal proceedings for additional information concerning the Horton Case. 3.2.6.7.2 Iraq
In 2005, the Norwegian Ministry of Petroleum and Energy signed a Memorandum of Understanding (MOU) with its Iraqi counterpart. We are participating in an institutional and technical assistance programme under this MOU. In addition, we have entered into our own Memorandum of Cooperation (MOC) with the Iraqi Ministry of Oil. Under this agreement, we have carried out joint exploration and field development studies, as well as provided technological assistance and transfer. This MOC was renewed in December 2007. 3.2.6.8 Other areas
3.2.6.8.1 China
We opened our first office in China in 1982. Today, our business involves operating the Lufeng field, oil trading, LPG trading and business development. Our partner on the Lufeng field is the China National Offshore Oil Company. The field, which already is well beyond original expected life, is still producing, and the current lease of the FPSO has now been extended through 2008. In February 2007, we entered into a strategic partnership with China National Petroleum Corporation through the signing of a Memorandum of Understanding relating to domestic and international exploration and production cooperation, LNG projects and research and development. 3.2.6.8.2 Russia
We have been present in Russia since the early 1990s with a representative office in Moscow. We have one producing field, the Kharyaga oil field. In October 2007, StatoilHydro signed a framework agreement with Gazprom to become a partner with 24% ownership in the Shtokman development company responsible for planning, financing and constructing the infrastructure necessary for the first phase of the Shtokman development, which will own the infrastructure for 25 years from start of commercial production. The implementation of the project is subject to a final investment decision which is planned to take place in the second half of 2009. Field in production The Kharyaga field is located onshore in the Timan Pechora basin in North West Russia. The Kharyaga PSA was signed between Total and the Russian Authorities in 1995 and became effective in 1999. We have 40% interest and Total is the operator. The Kharyaga field will be developed in stages according to the terms of the PSA. Oil production commenced in October 1999. Phase 1 with production of 10,000 boe per day utilising three existing wells. has now been initiated with the objective to increase production from 20,000 to 30,000 bopd. This phase involves the drilling of more production and injection wells, process upgrade and the installation of gas treatment facilities for the sale of associated gas. 3.3 Natural Gas
3.3.1 Industry overview
According to the International Energy Agency's (IEA) World Energy Outlook for 2007, fossil fuels will continue to be the prime source of incremental energy supply in the decades ahead. However, on a regional level the growth in demand for specific fuels will vary. In the developing countries, coal is expected to see the fastest growth in demand, whereas natural gas is expected to continue to be the fastest growing fuel in OECD markets and transition economies. Natural gas can substitute for other fuels in almost any application. In many global scenarios for the mitigation of climate change, there is an implicit assumption that gas use will increase. Hence, the future demand for natural gas looks robust and sustainable, assuming that the necessary regulatory and competitive frameworks are established. On the supply side, there is major concern over possible energy deficits (or "gaps") in the main gas-producing countries. In consequence, international natural gas markets will be influenced by policy decisions in key producing countries such as Russia, Algeria and Qatar.
From around 2010, it is expected that Europe will need additional supplies of piped gas and/or LNG in order to cover demand. High regularity and the geographical location makes NCS gas attractive in the European market. We therefore expect that demand for gas from Norway will continue to increase in our primary gas markets. The international gas industry is driven by several trends that have implications for our business:
These trends and developments indicate new opportunities for our gas business. While robust demand will continue to underpin the longer term supply business, increased transparency, connectivity and liquidity in the market place will open up new areas for value creation through optimisation and trading. Hence, our gas strategy aims to continue to strengthen the long-term supply business while at the same time grasping new business opportunities as market developments allow. 3.3.2 European gas market
According to the IEA, the estimated annual growth in global gas consumption in the period 2005-2030 will be 2.1%. Growth in OECD Europe in the same period is expected to be 1.4%. This translates into a European demand for gas in 2030 of approximately 770 bcm - approximately six times Norway's current export capacity. The share of gas in total primary energy consumption is approaching 25% in the OECD countries in Europe. Approximately 59% of the growth in gas consumption in the period is expected to come from the electricity sector. The IEA expects growth in demand for all sub-sectors of the European natural gas market. We market and sell our gas together with the Norwegian State's natural gas. We are the second largest gas supplier in Europe and the sixth largest supplier in the world. In addition, we market gas sourced from producing areas other than the NCS. Other major gas suppliers in Europe are Gazprom from Russia, Sonatrach from Algeria and Gasunie from the Netherlands. We believe that Norwegian natural gas exports will remain highly competitive because of reliability, access to the transportation infrastructure and proximity to the European market. In addition, natural gas is an attractive source of energy from the perspective of climate change since it emits far less greenhouse gasses than coal and oil.
For a long time, the UK was the second largest producer of natural gas in Europe after Russia. However, by 2016 it is expected that the UK may be dependent on imports for approximately 80% of its gas requirements. Based on our growing infrastructure, we believe we are well positioned to supply a portion of the UK's additional demand for imported natural gas and to engage further in Europe's largest and most liberalised natural gas market. A new export pipeline, Langeled, from the NCS to Easington in the UK is now in operation. Another new infrastructure project is the Tampen Link, a pipeline from the Statfjord field on the NCS to the existing Flags pipeline on the UK continental shelf, which was completed in 2007. 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 additional steps in Europe to curb carbon dioxide emissions, in particular by the use of carbon pricing mechanisms such as the EU Emission Trading Scheme. We expect the use of natural gas as a source of electricity generation to continue to grow, as there is a need to replace even more coal-based generation capacity with natural gas. Deregulation opens up new opportunities and business models in the gas sector, both with regard to added values through efficiency gains and to building a more substantial end user sales portfolio. 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, optimisation and midstream and downstream activities. At the same time, we are facing a more competitive downstream natural gas market in Continental Europe. However, we believe that our long-term relations with large customers, experience in the marketing of natural gas and established points of entry will put us in a strong competitive position. For more information about the EU Gas Directive, please see report section Regulation - Gas directive of the European Union. 3.3.3 Gas sales and marketing
The major export markets for NCS gas are Germany, France, the United Kingdom, Belgium, Italy, the Netherlands and Spain. Our main customers are large national or regional gas companies such as E.On Ruhrgas, Gaz de France, ENI Gas & Power, British Gas Trading (a subsidiary of Centrica), Distrigaz and Gasunie. In addition, we sell to large end users, mostly through long-term take-or-pay contracts. In November 2007, the Norwegian state announced that it would not support plans to increase gas production from the Troll field, due to the possible negative impact on future liquids production. In consequence, plans for an additional gas export pipeline from Norway were cancelled. We had previously expected that gas production from the Troll field could be used to provide significant gas volumes to the European market in the future. We are now working on a number of projects to realise the full potential of the NCS that will contribute to strengthening our position as an important and reliable long-term supplier of natural gas in Europe. 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 large customers in Belgium, the Netherlands and France. Our group-wide gas trading activity is mainly focused on the UK gas market, which is a significant market in terms of size and the most liberalised market in Europe. We are also increasingly taking part in other liquid trading points such as the TTF (Title Transfer Facility) in the Netherlands and at Zeebrugge Hub in Belgium. In 2004, Statoil (UK) Limited and SSE Hornsea Limited (subsidiaries of StatoilHydro and Scottish and Southern Energy Plc) entered into a joint venture for the development, operation and maintenance of a salt cavern gas storage facility near Aldbrough, on the east coast of Yorkshire and close to the Easington terminal. On completion, the storage facility will comprise nine underground caverns. Statoil (UK) Limited owns one third of the storage capacity being developed, of which the SDFI has a 48.3% share. The facility has been developed and will be operated by SSE Hornsea Limited. The storage facility is expected to begin commercial operation by the fourth quarter of 2008 with full commercial operation of the nine cavern facility achieved in 2011. The design capacity for the storage facility is expected to be 420 mcm. StatoilHydro's share of the total development cost is estimated to NOK 0.7 billion.
In Germany, we hold a total 31.4% stake in the Norddeutsche Erdgas-Transversale, or Netra, overland gas transmission pipeline, and a 23.7% stake in Etzel Gas Storage through our subsidiaries Statoil Deutschland and Hydro Energie Deutschland. StatoilHydro has a 25.5% share in the Shah Deniz field in Azerbaijan and is commercial operator with responsibility for gas transportation and all gas sales activities. Turkey is the main market for gas from Stage 1 of the Shah Deniz development, and in addition Georgia and Azerbaijan are part of the gas sales portfolio. The gas is transported to customers through the South Caucasus Pipeline (SCP) running from Azerbaijan via Georgia to the Georgian/Turkish border. Shah Deniz Stage 1 production and the related gas transport in SCP were ramped up throughout 2007.
Shah Deniz transportation solutions. Possible transportation solutions for the Shah Deniz stage 2 gas to the European market. The Stage 2 development of Shah Deniz is currently being progressed toward a planned start-up in the end of 2013. Field reserves support a significant Stage 2 development and is likely to be on a similar or larger scale as Stage 1 (with plateau production of approximately 8.6 bcm). Key activities for NG in this respect are related to the commercialisation of Stage 2 through organisation, planning and conduct of gas market/transport evaluations and negotiations with counterparties in the Caspian region, Turkey and the European Union. In February 2008, StatoilHydro signed an agreement with EGL to establish a joint venture to develop, build and operate the Trans Adriatic Pipeline (TAP) from Greece, through Albania to Italy. A final investment decision is to be made in the second half of 2009. This potential pipeline, expected to be operational at the earliest from 2011, will open a new corridor and market outlet for natural gas from the Caspian Sea into Europe. We have chosen to join the TAP project as part of our effort to offer an attractive export route for the Shah Deniz gas to the European market.
In the US, Statoil Natural Gas LLC (SNG) markets gas to local distribution companies, industrial customers and power generators. LNG will be sourced from our Snøhvit LNG facilities in Norway. Currently, the LNG is imported from Trinidad, Algeria and Egypt and regasified through the Cove Point terminal in Maryland, US. We have a long-term contract with the operator of Cove Point, Dominion Resources Inc., securing us capacity rights of 2.4 bcm per year at the Cove Point terminal and pipeline. The terminal and pipeline interconnect with three interstate pipelines, allowing gas to be directed to the Mid-Atlantic and North-East markets. The SDFI participates with a 56.5% share of our capacity in the terminal and pipeline. SNG also markets the equity production from our assets in the US Gulf of Mexico in addition to sourcing some pipeline gas domestically, mainly for optimisation purposes. In 2005, StatoilHydro entered into contractual commitments with Dominion for 100% of the expansion of the Cove Point terminal with a capacity of approximate 7.7 bcm annually of gas for a 20-year period, with planned start-up in late 2008 or early 2009. The expansion reflects our focus on the growing liquefied natural gas market in the US, at the same time as market access through Cove Point is strategically important to a potential Snøhvit phase 2 and other LNG projects under consideration by StatoilHydro. In addition it gives us more flexibility in sourcing third party LNG to the terminal. The respective future shares of StatoilHydro and the SDFI on the Cove Point terminal, the additional capacity and related commitments are subject to further consideration, and the outcome may therefore have an impact on the extent of future commitments assumed and reported by StatoilHydro. On 20 October 2007, the first vessel with a cargo of liquefied natural gas from the Snøhvit field left port at Melkøya. For the first time StatoilHydro is supplying gas from the Norwegian continental shelf in a cooled state by ship. LNG gives us increased flexibility in terms of marketing gas globally. The plant at Melkøya is the first LNG production facility in Europe and it will be a key component in StatoilHydro's focus on LNG, which is the fastest growing gas market in the world. The LNG plant has suffered from operational challenges and there are still uncertainties related to the timing of regular and stable operations. Our commitments to our customers Iberdrola and SNG commenced on 1 October 2006. To meet our obligations, we have put into effect mitigation activities such as purchasing of replacement LNG and piped gas. 3.3.4 Norwegian gas transportation system and other facilities
To transport Norwegian natural gas to European customers, Norwegian gas producers have built an extensive gas pipeline system, connecting gas fields to gas processing plants on the Norwegian mainland and receiving terminals in Europe.
In 2003, all gas pipelines with third party access were unitised into a single joint venture, Gassled. The Gassled system is operated by Gassco AS, which is wholly owned by the Norwegian State. Gassco has no ownership interest in Gassled or in gas production. In 2007, the Gassled system transported 86.3 bcm (3.0 tcf) of Norwegian gas and it has additional capacity to transport 35 bcm to 40 bcm (1.2 tcf to 1.4 tcf) per year. Our ownership in Gassled and other pipelines and terminals is listed in the tables below. The Kårstø Expansion Project and Langeled were included in Gassled with effect from 1 October 2005 and 1 September 2006, respectively. Tampen Link was included in Gassled from 1 September 2007 with subsequent adjustments in Gassled ownership interests. From 1 January 2011, our ownership interest in Gassled will be reduced due to an increased ownership interest for the SDFI. Similar adjustments of the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA will also be made. In addition, our ownership interest in Gassled may change as a result of including existing or new infrastructure or if Gassled undertakes further investments without participation from its owners in proportion with their ownership interests in Gassled. Gassled has a licence period that extends to 2028. From 1 July 2007, Gassco also took over direct operation of the receiving terminals and the metering stations in Emden and Dornum in Germany, as well as the Zeepipe Terminal and the Dunkerque Terminal. Prior to 1 July 2007, the facilities in Emden and Dornum were operated by a joint operating company established by StatoilHydro and ConocoPhillips. At the time Gassco took over operations of these facilities, roughly 100 employees at these facilities were transferred from StatoilHydro and ConocoPhillips to Gassco. It was resolved in 2006 that Gassco, as operator of the Norwegian gas pipeline network, should take over the daily technical operations of the continental terminals. The Ormen Lange field was officially opened in October 2007. Gas from the Ormen Lange field is transported in the Langeled pipeline from Nyhamna, via Sleipner to Easington in the UK. At plateau levels, the Ormen Lange field is expected to provide StatoilHydro with more than 6 billion standard cubic meters of gas per year. It is anticipated that Ormen Lange as a field will account for approximately 20% of Norwegian gas export in 2010. The Langeled pipeline is merged with the Gassled system. StatoilHydro was development operator for the Ormen Lange field while Shell took over as field operator 1 December 2007, in accordance with the decision made by the Norwegian Ministry of Petroleum and Energy in December 1999.
In October 2007, the strategically important Tampen Link pipeline was opened. The Tampen Link opens a new corridor to the UK gas market. The Tampen Link pipeline ties Statfjord into Britain's existing Far North Liquids and Associated Gas System (Flags), which runs to St. Fergus in Scotland. The pipeline increases our ability to export gas from the NCS, with a maximum committable capacity of 26.5 million standard cubic metres per day. On completion, the ownership of Tampen Link was merged with Gassled. Our ability to transport own supply of natural gas from various field interests enables us to make regular and reliable gas deliveries to our customers. The pipelines intersect at platforms, tie-in locations and processing plants, providing a flexible network for the transportation of natural gas from various fields and gas processing plants to our entry points into the European market, depending on our customers' contracted daily and annual natural gas sales requirements. Each field operates with an accounting system, permitting fields to borrow and repay gas volumes as needed to meet their supply needs. The major costs associated with running a pipeline system are maintenance and compression costs that result from operating compression facilities to support gas throughput. Most transport agreements are based on a tariff per unit transported which covers the operating cost of the transport system and provides a return on the capital invested. The Ministry of Petroleum and Energy sets such tariffs. The pipelines are maintained under an annual maintenance plan approved by the Norwegian Petroleum Directorate. The following table shows the major NCS gas transportation systems in which we have an interest, and the transportation routes and capacities. All of the pipelines and terminals are operated by Gassco AS.
3.3.5 Kårstø gas treatment plant
As technical service provider (TSP), StatoilHydro is responsible for the operation, maintenance and further development of the Kårstø gas treatment plant on behalf of the operator Gassco. Kårstø processes rich gas and condensate, or light oil, from the NCS received via the Statfjord-Kårstø pipeline, the Åsgard-Kårstø pipeline and the Sleipner condensate pipeline. Products produced at Kårstø include ethane, propane, iso-butane, normal butane and naphtha and stabilised condensate. The treatment plant currently has a design capacity of 78 mmcm per day. In order to meet technical requirements and future needs, the Kårstø processing plant will undergo comprehensive upgrading over the next few years. KEP2010 is a common term for several projects intended to make Kårstø facilities more robust for safe and efficient operations. The project's framework investment is estimated at around NOK 6.5 billion. Plans call for the completion of KEP2010 projects between 2010 and 2012, with upgrading work beginning in 2008. The KEP2010 workforce working on site will comprise around 500 personnel at any given time. In 2007, Kårstø produced 0.9 million tonnes of ethane, 4.6 million tonnes of LPG and 2.8 million tonnes of condensate/naphtha exported to customers worldwide. 3.3.6 Kollsnes gas treatment plant
As TSP, StatoilHydro is responsible for the operation, maintenance and further development of the Kollsnes gas treatment plant on behalf of the operator Gassco. The plant was built to receive gas landed from the Troll field through two 36-inch pipelines. Kollsnes was upgraded in 2005 to receive gas from Visund and Kvitebjørn. In 2006, a sixth export compressor was put into production, increasing the export capacity by approximately 25 mmcm per day. The plant currently has a design capacity of 146.5 mmcm per day. In 2007, Kollsnes produced 38.5 bcm of dry gas and 1.6 mcm of condensate. 3.3.7 Gas sales agreements
StatoilHydro is required by the Norwegian State to manage, transport and sell the gas on behalf of the SDFI. StatoilHydro manages, transports and markets approximately 80% of all NCS gas. Due to the relatively large size of NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, most of StatoilHydro's gas sales contracts are long-term contracts in which 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. Our long-term contracts generally run for 10 to 20 years or more. A significant portion of our current long-term sales contracts will reach plateau level between 2005 and 2008. Prices in these contracts are generally tied to a formula based on the prevailing prices for a customer's principal alternative fuels to natural gas, mainly heavy fuel oil and gas oil. Consequently, there can be significant price fluctuations during the life of the contract. Prices in these contracts are generally adjusted quarterly and are calculated on the basis of prices prevailing in the three to nine months before the date of adjustment as published in reference indices. By contrast, recent long-term gas sales contracts in the UK are priced with reference to a daily UK market gas price index. However, the price formula, which allows for monthly or quarterly adjustment, does not pick up on all trends in the marketplace, i.e. 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 by either the buyer or the seller. Under our long-term sales contracts either party is entitled to initiate a price review process under certain circumstances as set forth in these contracts. In 2007, StatoilHydro was involved in commercial discussions (in lieu of price review) or in formal price review processes for approximately 43% of the volumes covered by our long-term sales contracts. 3.4 Manufacturing and Marketing
3.4.1 Industry overview
We expect oil and gas consumption to continue to grow and thereby play a central role in the global demand for energy for at least the next 20 to 30 years. We expect growth in demand in OECD markets to be moderate, while demand from emerging economies will be stronger. We further envisage some challenges globally in bringing upstream capacity on stream on time to meet increased demand. In addition, we expect a decline in production on the NCS, and the expectation is that the global supply situation will remain tight. We believe that future hydrocarbon exploitation will be increasingly complex and costly. The quality of oil produced will vary more as the methods of developing available resources will increasingly become unconventional. At the same time, the quality requirements for end user products will become more stringent. The conversion process is therefore expected to become more challenging. Selective midstream and downstream involvement and presence will thus be important to ensure robust value chains for upstream projects with extra heavy crude oil qualities.
We expect the current focus on the environmental footprint of energy use to continue. As such, there will be focus on non-hydrocarbon transportation fuels. We believe that energy companies that provide solutions to these environmental challenges will improve their competitive position. Future oil demand will increasingly be focused on the transportation sector, and new energy carriers are expected to emerge in the stationary energy sector. We anticipate that the oil value chain therefore will be increasingly directed towards the transportation fuel segment. Europe has been moving towards an increase in diesel vehicles since the European Commission encouraged lower taxes on diesel fuel. We believe this trend will continue. The availability of the necessary human resources and competence will also remain a key challenge for the industry in general and even more so for the midstream sector. 3.4.2 Oil Sales, Trading and Supply
We are one of the largest net sellers of crude oil in the world, operating from sales offices in Stavanger, London, Singapore and Stamford, selling and trading crude oil, NGL and refined products. We market and sell own volumes of crude and NGLs together with the Norwegian State's volumes and third party volumes. In 2007, we sold 783 mmbbls of crude oil and condensate. This includes sales to our own refineries and other internal divisions. The main crude oil market for StatoilHydro is in north-western Europe. However, we also sell volumes to North America and Asia. Most of the crude oil volumes are sold in the crude spot market based on publicly quoted market prices. Of the total volumes sold in 2007, approximately 47% were StatoilHydro volumes. Total sales of LPG amounted to 8.2 million metric tonnes and total sales of naphtha were 4.4 million metric tonnes in 2007. Most of the LPG and naphtha was sold to customers in north-western Europe.
The main markets for our refined products, NGL and condensate, are in north-western Europe and the Baltic Sea area. We are supplying condensate in Europe, including to our own refineries at Mongstad and Kalundborg, as well as to other refiners and the petrochemical industry. In addition, condensate cargoes are sold in the US market. In 2007, we sold approximately 30 million tonnes of refined oil products, the majority of which were refined at our refineries at Mongstad and Kalundborg. From the fourth quarter of 2007, new condensate grades were available from the Ormen Lange and Snøhvit fields, which gives us more qualities, flexibility and increased trading volumes from the NCS. 3.4.3 Manufacturing
We are majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil distillation capacity of 179 mbbls per day, and sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbls per day. In addition, we have the right to 10% of the production capacity at the Shell operated refinery in Pernis, The Netherlands, which has a crude oil distillation capacity of 400 mbbls per day. Our methanol operations consist of our 81.7% stake in the gas-based methanol plant at Tjeldbergodden, Norway, which has a design capacity of 0.95 million tonnes per year.
We also operate the Oseberg Transportation System (36.2% stake), including the Sture crude oil terminal. The plant was built to receive crude from the Oseberg field through a 28-inch pipeline, and since 2003 has also been receiving crude from the Grane field through a 29-inch pipeline. Oseberg blend (after stabilisation), Grane blend and LPG are exported, and condensate is piped to Mongstad. The following table gives operating characteristics of the plants at Mongstad, Kalundborg and Tjeldbergodden.
3.4.3.1 Mongstad
The Mongstad refinery, built in 1975, significantly expanded and upgraded in the late 1980s and subject to considerable investments over the last 10 years to meet new product specifications, is a medium-sized, modern and sophisticated refinery. The refinery is directly linked to offshore fields through two crude oil pipelines and indirectly linked through an NGL/condensate pipeline to the crude oil terminal at Sture and the gas terminal at Kollsnes, making Mongstad an attractive site for landing and processing hydrocarbons and for further development of our oil and gas reserves. The main facilities at Mongstad, in addition to the refinery, are a crude oil terminal, owned 65% by StatoilHydro, and an NGL terminal, owned by Vestprosess, in which StatoilHydro has an ownership interest of 34%.
The refinery is owned 79% by StatoilHydro and 21% by Shell. We have a service agreement with Shell Global Solutions, Shell subsidiary, which provides technical operational support, project development support and general technical advice to Mongstad. Approximately 45% of Mongstad's total production is delivered to the Scandinavian markets and 55% is exported to north-western Europe and the United States. The following table shows the approximate quantities of refined products (in thousand tonnes) produced at Mongstad for the periods indicated. As shown below, in addition to crude, the Mongstad refinery upgrades large volumes of fuel feedstock (up to one million tonnes per year), NGL from Oseberg and Tune, and condensate from Troll, Kvitebjørn and Visund.
The Mongstad refinery is able to manufacture products to meet different specifications through its in-line blending during ship loading. Considerable investments have been made in the last 10 years to meet new product specifications. The refinery reliability (i.e. on stream factor) was high in 2005, 2006 and 2007. There were no planned turnarounds in 2005, 2006 or 2007. We are planning a major turnaround in 2008. In 2006, we received the final permit to build a combined heat and power plant (CHP plant) at Mongstad. The CHP plant is a strategically important project for Manufacturing & Marketing. The use of heat from the CHP plant will result in significant improvements in the Mongstad refinery's energy efficiency. The CHP plant is expected to provide approximately 280 megawatts of electric power and 350 megawatts of process heat when it comes online in 2010. The plant will be built and operated by Dong Energy, and StatoilHydro will pay an annual fee for use. By year end 2007, the progress of the CHP investment project was 31%, as planned. Under an agreement with the Troll licensees, this facility will also supply power to the Troll A gas platform and the associated Kollsnes processing plant onshore. In addition to the CHP plant, the project includes a new gas pipeline from Kollsnes and necessary modifications at the refinery. StatoilHydro and the Ministry of Petroleum and Energy have agreed to form a technology company that will facilitate the building of a carbon dioxide capture plant at Mongstad. We will own 20% of the company. The plant will have a capacity to capture 100,000 tonnes of carbon dioxide annually. The goal is to test, qualify and develop carbon capture technology in order to reduce costs and risk. Due to the test nature of the facility and the current lack of infrastructure for transportation and storage, the carbon dioxide will not be stored until later. Based on the lessons learned, a final investment decision is planned in 2012 to build a full-scale capture plant at the refinery. The Norwegian State has full responsibility for the investment in and operation of this full-scale carbon capture plant. 3.4.3.2 Kalundborg
Kalundborg produces products such as gasoline, jet fuel, diesel oil, propane and fuel oil, supplying markets in Denmark and Sweden. The refinery is connected through two pipelines (gasoline/gas oil) to our terminal at Hedehusene, near Copenhagen. Kalundborg's refined products are also supplied to markets in north-western European, mainly Germany and France. Fuel oil is exported to Italy and the US. The following table shows the approximate quantities of refined products (in thousand tonnes) produced by Kalundborg for the periods indicated.
There were turnarounds in both 2005 and 2007. Kalundborg is a plant with high energy efficiency, high utilisation and relatively low operating costs. The refinery has improved its performance substantially 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 petrol, in accordance with EU specifications. The main project at Kalundborg in 2007 has been the Fuel Reduction Project. This project is expected to be on stream March 2008, and will reduce production of heavy fuel oil and increase sulphur free auto diesel. 3.4.3.3 Tjeldbergodden
Our methanol operations at Tjeldbergodden in Norway, which we own 81.7%, have a maximum proven capacity of 0.92 mmtpa and the actual throughput in 2007 was 0.70 mmtpa. We also own 50.9% of Tjeldbergodden Luftgassfabrikk DA, one of the largest air separation units (ASU) in Scandinavia, which also owns the first Norwegian natural gas liquefaction plant, located at Tjeldbergodden with an annual gas (methane) capacity of 36 mmcm (1.3 bcf). Our partners are AGA (37.8%) and ConocoPhillips (11.3%). The ASU supplies oxygen to the methanol plant and AGA markets and sells industrial gases produced. 3.4.4 Energy and Retail
Energy and Retail has approximately 9,600 employees, and consists of approx 2,300 service stations and 185 truck stops in 8 countries. In addition, we are marketing refined products to consumer and industrial markets.
The Energy segment supplies aviation and marine fuels, as well as a large number of Statoil-brand refined products. These include oil-based heating fuels and lubricants which are supplied to both retail and industrial customers. We have operations for lubricants and LPG in Poland and the Baltic countries, supplementing our strong market position in Scandinavia, which is based on approximately 350,000 customers and annual sales of approximately 4.7 billion litres. In the LPG market, we have a market share of approximately 40% of the Scandinavian market. Our portfolio also includes ownership interests in gas distribution companies. The full-service stations in the Retail segment provide automotive fuels, car accessories and simple vehicle service products. In addition, most stations offer consumer goods, including fast food, convenience products and basic groceries. In 2007, these stations, together with automated stations, sold approximately 5.3 billion litres of petrol and diesel. Bulk fuel sales and sales from truck stops accounted for additional sales of three billion litres. The following table lists these retail outlets by region or country as of 31 December 2007 and our volume of automotive fuel sales for the year ended 31 December 2007:
Scandinavia is our home retail market. We have a petrol market share of approximately 30% in Norway and 17% in Denmark. In Sweden our Statoil and Hydro branded stations have a petrol market share of approximately 32%. Other service stations are located in Poland, Russia and the Baltic countries; Estonia, Lithuania and Latvia. We rank as a market leader, measured in terms of fuel volumes sold, in Estonia and Latvia with approximately 40% and 32%, respectively, of the local retail petrol market in 2007. During 2007, the retail network and energy business in the Faeroe Islands was sold resulting in a capital gain of approximately NOK 0.1 billion after tax. 3.5 Technology and New Energy
3.5.1 Industry overview
The success of our business is closely related to our access to and application of advanced technological expertise, which has largely been developed through exploration and production activities on the NCS. Many major challenges have been addressed, including operating under the harsh weather and environmentally sensitive conditions in the Norwegian Sea, transporting oil and gas across the deep Norwegian trench, and draining complex petroleum reservoirs characterized by high pressures and high temperatures. Much of this experience is increasingly being applied to StatoilHydro's international operations. In the wake of higher energy prices, technology development has intensified in both the oil and gas industry and in the field of renewables. The renewable energy industry is growing rapidly, driven by ambitions to increase the contribution of sustainable energy to the total energy supply. Although energy production from renewables is still modest in most countries, wind power, solar energy and biofuels are developing into significant industries. Global investment in sustainable energy has seen double digit growth rates in recent years. 3.5.2 Technology development
StatoilHydro is the world's largest operator of offshore fields in water depths below 100 metres, and we have considerable experience of overcoming the challenges presented by harsh environments. Nevertheless, there is a need to rapidly utilise new technology to increase the resource base and maximise production. Technology & New Energy (TNE) is a centre of force for the development and implementation of new technology in the company. This is achieved by providing best practice support and expertise for our operations, developing world-class technical concepts for our development projects, and heading up established corporate initiatives in order to improve performance in exploration, increased oil recovery and integrated operations. In this manner, TNE will support the other business areas in achieving corporate targets for production growth, increased regularity, reduced costs and improved drilling efficiency. Selected advances made during the last few years are summarised below. Exploration Much progress has been made in the geological understanding and geophysical imaging of Atlantic margin deepwater plays and prospects, including those occurring beneath thick layers of salt. Advances are also being made in extending electromagnetic seabed logging from 2D to 3D and combining seabed logging with seabed seismic surveys. Both techniques are designed to lower the risk of dry holes by differentiating between petroleum and water-bearing prospects prior to drilling. Another innovation is the development of a disposable rig-less exploration tool, which burrows its way down to a prospect. This development may assist in obtaining low-cost, real-time geological information in advance of drilling.
Other advances have been made in increasing the speed with which high-quality subsurface seismic images can be produced and improving our fundamental understanding of geological processes to rapidly screen prospective basins. The accurate assessment of the maturation, migration and entrapment of hydrocarbons around the world is of paramount importance in identifying prospective areas. Increased Oil Recovery (IOR) Other IOR advances are being made in drilling and well technology. For example, "through-tubing drilling and completion" technology permits offshoot wells (sidetracks) to be drilled laterally from their parents in order to access isolated pockets of untapped oil and gas in mature fields. Optimal directional well positioning permits the penetration of more distant parts of a reservoir and the drilling of production wells that do not follow simple paths. Moreover, the completion and remote control of smart wells (including multi-laterals) helps to increase ultimate recovery factors.
Subsea field development and long-distance transport In 2007, we reached three subsea development milestones: the start of production on the Ormen Lange and Snøhvit fields and the installation of the first full-scale subsea separation facility at Tordis, making it the world's first commercial field with seabed processing. Removing produced sand and water from the Tordis wellstream and re-injecting it into the subsurface is expected to improve the recovery factor from 49% to 55%. The Ormen Lange and Snøhvit developments have also broken records in terms of long-distance transport. Unprocessed wellstream is carried 160 kilometres from the furthest Snøhvit well to the LNG plant near Hammerfest, while the world's longest subsea pipeline, Langeled, carries Ormen Lange gas from central Norway to the UK over a distance of 1,200 kilometres. We were responsible for the design and installation of Langeled, which was laid on time and at cost. While the offshore part of the Snøhvit project has been a success, the onshore part of this LNG project has experienced some operational challenges and there are still uncertainties related to the timing of regular and stable operations. Gas solutions StatoilHydro, in association with its partners PetroSA and Lurgi, has developed its own GTL process technology, which is currently being demonstrated in a semi-commercial plant at Mossel bay in South Africa. Carbon capture at Mongstad The establishment of the European carbon dioxide test centre at Mongstad has the following objectives:
New Energy Complementary offshore wind technologies are available through our equity positions in the Norwegian companies Sway AS and ChapDrive AS. We have an interest in developing operational wind power through our holding in Arctic Wind, which operates the Havøygavlen wind farm in Northern Norway, which produced 76.5 GWh in 2007. Looking ahead to possible future processes for synthetic ("second generation") biofuels, StatoilHydro has completed a technology assessment of forest biomass-to-liquids (BTL) processes. The study, carried out in collaboration with Norske Skog ASA, has been completed and will form the basis for further evaluations of BTL technologies. In 2007, StatoilHydro acquired a 42.5% holding in the Mestilla biodiesel production plant in Lithuania, with a sales and distribution agreement for the entire biodiesel production capacity of 100,000 tonnes per year. Production started towards the end of 2007. Testing of hydrogen as a future transportation fuel was taken a step further by the opening of our second hydrogen refuelling station in Porsgrunn in Norway. Hydrogen, itself a long-term option, is also the basis for ongoing sales of water electrolysis technology, in which StatoilHydro holds a strong market position. Product development based on our electrolyser technology continues, aiming at emerging markets for on-site hydrogen generation based on renewable energy. Through New Energy's investment and venture activities, we have gained insight into technologies at the forefront of wave power, tidal power and fuel cell development.
StatoilHydro's 2008 R&D portfolio
3.5.3 Research and development
New technology developed and implemented in 2007 contributed in different ways to the group's financial performance. Performance efficiency increased for seismic processing through improved computer tools. Remaining oil identified in the Statfjord formation on the Snorre field using advanced fluvial modelling tools developed by StatoilHydro. Hydrocarbon production from a number of NCS fields (including Gullfaks) increased using conventional time-lapse 4D seismic - a technology in which we are among industry leaders. We also made good progress in developing a 4D seabed seismic monitoring system based on fibre-optic technology. Research and Development expenditures were NOK1,969 and NOK 1,616 million in 2007 and 2006, respectively. R&D expenditures are partly financed by joint venture partners of StatoilHydro operated activities. Our share of the expenditures have been recognized as expenses. 3.5.3.1 R&D initiatives
As conventional fossil fuels become ever harder to find, companies are increasingly setting their sights on remote geographical areas and developing unconventional hydrocarbon sources such as oil sands and building growth platforms in carbon-free energy sources (renewables).
In exploration technology, we plan to develop new (and in some cases unconventional) basin and prospect concepts, and to continue improving subsurface imaging and interpretation by integrating geophysical and geological methodologies and incorporating them into next generation workflows. The goal is to considerably reduce the risk of drilling dry holes and 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 reserves and draining our reservoirs as efficiently and effectively as possible. An important success factor here is integrated operations, which we define as new work processes that use real-time data to enable closer cooperation between disciplines, organisational entities and geographical areas. The objective is to achieve more reliable, better and swifter decisions. Innovative offshore field development solutions are largely expected to focus on the exploitation of hydrocarbons in deepwater and Arctic areas, as well as areas containing heavy oil. We foresee an increasing transition from topside to intelligent, remotely-operated, autonomous seabed facilities, coupled with ultra-long, subsea tie-backs and wellstream compression devices. Furthermore, we believe it will be necessary to develop new drilling concepts, especially in ice-infested areas, and to develop pipelines capable of withstanding ultra-cold and ultra-deepwater conditions. We plan to focus on developing onshore extra heavy oil value chains and on improving recovery methods, water management and carbon capture. The opportunities in gas chain technology may lie in gaining greater access to, and cost-effectively developing, difficult unconventional gas resources and acquiring leading-edge capabilities in selected technologies (such as membrane-based separation). The realisation of floating LNG (and possibly floating GTL) facilities for gas fields that cannot otherwise be easily or economically exploited is another opportunity we plan to pursue. We also plan to develop sustainable CCS value chains. Our commitment to environmental stewardship is twofold: meeting our zero harm to the environment objective by expanding our toolkit of environmental monitoring and integrated risk-modelling systems and creating business in new energy sources. In addition to consolidating our present activities in offshore wind and biofuels, we plan to further investigate opportunities in geothermal and solar power and the use of hydrogen as an energy carrier. We believe technological innovation is the key to meeting a profitable, sustainable, low-carbon energy future. 3.6 Projects
3.6.1 Industry overview
On the NCS, the trend is moving from a portfolio of mainly green-field and tie-in projects towards complex, brown-field redevelopment projects on old installations, where vital work must be timed to coincide with major planned turnarounds. Because of the growing portfolio and the fact that the market situation requires more internal resources to ensure deliveries of acceptable quality at the right time, the shortage of engineering competence is as critical as in previous years, with respect to both the number of available engineering personnel and the competence and quality of work delivered. In addition, increased international activity is expected to make strong demands on our ability to utilise our resources to develop international activities. In consequence, there is a risk that engineering may be negatively affected, which, in turn, may influence construction and completion progress. To develop a global mindset in our organisation, we must create and mobilise the right teams in regions and areas where we have little or limited experience. A high activity level on the NCS will make strong demands on our ability to execute projects as sanctioned and in accordance with our 'zero harm' HSE vision. To succeed, we must challenge established models, ensure continuous improvement and establish best practice on the basis of experience. As regards physical deliveries of goods and services, there have been significant cost increases and this remains a concern. The tight market can also contribute negatively to the quality of work and deliveries as well as to increased lead times for deliveries. 3.6.2 Projects development
A number of new projects will require our attention in the coming years. The Gjøa/ Vega development, Tyrihans, Morvin, Alve and Yttergryta are all examples of new projects on the NCS that are expected to contribute to continued growth on the NCS, whereas Ormen Lange Offshore and Statfjord Late Life are two projects that are expected to contribute to optimising production from existing assets.
Internationally, we see a number of projects that supports our global ambitions. However, to become a truly global energy player we must also perform the role of operator. Our contribution in this respect will be to execute projects such as South Pars, In Salah and Leismer in a predictable manner. By reaching the major milestones in these projects on schedule and while maintaining high HSE standards, our reputation as a world-class implementer of projects will be strengthened. 3.6.2.1 Norwegian Continental Shelf
After the completion of both Snøhvit and the Ormen Lange/Langeled developments, the combined Gjøa/Vega development is the largest ongoing project on the NCS. Over a period of four years, NOK 37 billion is expected to be invested in these projects, located in the Sogn-area off the west coast of Norway. The Gjøa producing facility is designed in a way that makes it possible to process oil and gas from other small discoveries in the area in the future.
The Gjøa-platform will be provided with land-based electricity from Mongstad that is estimate to reduce emissions by 240,000 tonnes of carbon dioxide per year, equivalent to the annual emissions from 100,000 cars. Tyrihans is a NOK 14.5 billion stand-alone subsea field development tied back to the Kristin platform. The field will be developed with four production/gas injection templates and one water injection template, with a total of 12 wells (eight oil producers, two gas injectors, one gas producer and one water injector). The Tyrihans field was discovered in 1982/1983 and the PDO was approved by the Norwegian authorities in February 2006. All major contracts (pipeline, subsea production system, drilling rig, drilling services and well completion equipment) are awarded, and as of November 2007, the project is progressing in accordance with plans. During the 2008 and 2009 seasons, marine operations will be conducted, including installation, tie-in and RFO. The remaining work prior to the estimated start-up in July 2009 consists of topside modifications on Kristin and Åsgard B and delivery of the subsea production system and seawater injection system. The Alve discovery is developed with one subsea template as a satellite tieback to the Norne FPSO, optimising the capacity at Norne. The investment related to developing Alve is NOK 2.5 billion, and production is estimated to start up during the first quarter of 2009. The concept includes a four-slot HOST template at Alve with an umbilical and a 12,6" ID insulated production pipeline with direct electric heating (DEH) for hydrate control to Norne. The gas will be processed at Norne. Some modifications topside are necessary to include well stream from Alve. The Alve development solution includes some flexibility for future additional tie-backs.
The Yttergryta subsea gas and condensate field development with an expected capital expenditure value of approximately NOK 1.2 billion is an excellent example of a relatively small but unique project in our portfolio. The discovery was made in the summer of 2007, and production start-up is expected to take place in 2009. The wellstream will be tied back to the Åsgard B platform for processing and further export. Ormen Lange Offshore is the second phase of the gigantic Ormen Lange gas field development. The purpose is to ensure optimal depletion from the field when the pressure in the reservoir drops. Groundbreaking work is now being done to qualify technology for subsea compression on Ormen Lange, and, if successful, the new technology could contribute to considerable cost savings, not only for the Ormen Lange partners, but for the entire oil and gas industry. The development of the Ormen Lange field in the Norwegian Sea is one of the largest and most demanding industrial projects ever carried out in Norway. StatoilHydro has been operator during the development phase of Ormen Lange, and the operatorship was handed over to Shell in December 2007 after production start-up in October 2007. The field has been developed with seabed installations at depths down to 1,100 metres, combined with an onshore plant at Nyhamna in Aukra municipality in Norway for processing and exporting the gas. The gas is exported through the world's longest subsea pipeline, Langeled, 1,200 kilometres to Easington on the east coast of Britain. The gas can also be transported via the riser platform on the Sleipner field in the North Sea to customers on the European continent. The development of Ormen Lange has been challenging. Pipelines and installations had to be placed on the extremely steep and uneven area of the sea floor where the Storegga Slide took place 8,000 years ago. The subsea installations have to be able to withstand the exceptional currents that are characteristic of this part of the Norwegian Sea, as well as sub-zero temperatures on the sea floor, and extreme wind and wave conditions. Following a gradual increase in production over the first two to three years, the field is expected to produce 70 million standard cubic meters of gas per 24-hour period. 3.6.2.2 Onshore facilities
A large redevelopment programme is currently underway at the Kårstø, Mongstad and Kollsnes production sites. A total of almost NOK 12 billion is currently being invested to ensure the regularity of gas production and to prepare for future volumes from sanctioned projects offshore. At Mongstad, the project for the construction of a CHP plant is well underway. When in operation in 2010, the CHP is expected to increase the energy efficiency at Mongstad to close to 80% and make the Mongstad processing facility self-sufficient in power, in addition to supplying power to Troll A, Gjøa and Kollsnes. The capacity will be about 280 megawatts of electricity and roughly 350 megawatts in the form of heat from this combined heat and power plant at Mongstad. At Kårstø, several smaller projects have been gathered together in the Kårstø Expansion Project 2010 (KEP 2010). The first part is a compressor upgrade that will make it possible to increase the pressure, and thus enable more stability in the gas flow through the export pipelines leaving Kårstø. The second part of the project is a complete modernisation and upgrading of security and control systems at the site, to prepare the plant for several more years of production and to meet stricter future HSE standards. The Kollsnes Flash Gas and Condensate project is an upgrade of the existing system due to capacity and regularity limitations. The installation of a new flash gas compressor train and a new condensate treatment train will contribute to increasing production and operating regularity at the Kollsnes processing plant. In addition, capacity for future production of 40 million standard cubic metres per day will be built into the systems. 3.6.2.3 International
On 12 December 2002, we became operator for the development of the offshore part of the South Pars phases 6-7-8 project . The South Pars phases 6-7-8 offshore project consists of three wellhead platforms with three pipelines for gas to shore, a condensate loading line and associated single point mooring (SPM) for condensate exports, the drilling of 27 production wells, the hook-up of three pre-drilled wells and required reservoir management.
Together with the SPD 7 tripods and flare tower, the SPD 9 platform topside was installed offshore during the spring of 2007. We are presently completing the SPD 9 platform for production start-up in 2008 and are preparing SPD 7 and SPD 8 for onshore mechanical completion followed by offshore installation and production start-up during 2008 and 2009. Planning for the installation of the third pipeline is progressing. Project completion is estimated for 2009. In Algeria, we are involved in onshore gas production and exploration activities. The In Salah Gas Compression project is part of the original development plan for In Salah, and it consists of turbine and electricity-driven gas compressor facilities to be installed at Reg, Teg and Kretchba, respectively. The purpose of the new compressor facilities is to counteract the declining production rates from the three fields. Executing projects in completely new surroundings like Algeria presents us with a lot of new challenges. Standards with respect to safety and security are different from what we are used to, and working in a joint venture reveals distinct cultural and company differences with regard to project development. The project is still in the initial phase and detailed engineering has started. Through the acquisition of the North American Oil Sands Corporation, StatoilHydro gained access to 1,110 square kilometres of oil sand leases situated in the Athabasca region of the Alberta province in Canada, approximately 500 kilometres north-east of Edmonton. The current development plan is to develop the area through a staged process where the Leismer Demonstration Plant for integrated steam-assisted gravity drainage will be the first stage of a total field development that will have a capacity of 20,000 boe/day. 3.6.2.4 Redevelopments
A major part of our project portfolio consists of activities relating to ongoing redevelopment efforts, aimed at maximising production from the NCS. As fields mature, production equipment needs upgrading. In the years ahead, a number of fields will need upgrading or renewal of drilling units, control systems, cranes and other major redevelopment efforts. We endeavour to organise these tasks as field projects in accordance with coordinated master plans for the different fields, such as the various redevelopment projects taking place at Statfjord, Troll and Oseberg. On 12 October, gas export started from the Statfjord Field to UK customers through the Tampen Link pipeline. The gas processing facilities that have been installed on the three Statfjord pipelines will enable us to increase the gas recovery rate from 58% to 74%.
In the coming years the Statfjord Late Life project will redevelop all three Statfjord installations from oil processing to gas processing facilities, thereby extending the lifetime of the field by several years. In the Troll area, a number of redevelopment projects are scheduled for the years to come, both with a view to carrying out required refurbishments and to ensure maximum recovery from the reservoirs (IOR) and increase production efficiency. The compressor upgrade and extension of the living quarters on Troll A, the low-pressure production on Troll C and the Troll B gas injection are all vital projects in this respect. The total investment involved amounts to more than NOK 5 billion. The various redevelopment projects related to the Oseberg field represent a substantial investment aimed at ensuring the vitality of the field in the coming years. The major redevelopment projects on Oseberg amount to a total investment of almost NOK 3.5 billion during the period 2008-2010. Vital projects include low-pressure production on Oseberg F, a heat recovery steam generator on Oseberg F and upgrading of the drilling unit at Oseberg B. 3.7 People and organisation
In StatoilHydro, the way in which our results are achieved is as important as the results themselves. We will create value for our owners based on a clear performance framework defined by our values and principles for HSE, ethics and leadership. Our ambition is to be a globally competitive company. We create a stimulating working environment and provide our people with good opportunities for professional and personal development. We seek to achieve this through developing a strong, value-based performance culture, clear principles for leadership and an effective management and control system. Corporate governance, our values, leadership model, operating model and corporate policies are described in the StatoilHydro Book, which has been made available for all employees in Norwegian and English. The Merger The merger between Statoil and Hydro's oil and gas activities gave the new company access to highly qualified personnel. In order to achieve our goals and attain the planned growth, the company must be capable of attracting and retaining talented personnel with the right expertise and strong values in a competitive market. Surveys show that Statoil and Hydro, both individually and after the merger, were among the most preferred employers in Norway in 2007. Emphasis has been placed on building on the best from both companies and on ensuring equal opportunities for all employees. The development of a common corporate culture has been given high priority. Furthermore, policies with respect to compensation and working conditions in the merged businesses have been harmonised in cooperation with employee representatives.
3.7.1 Employees in StatoilHydro
At the end of 2007, StatoilHydro had 29,500 employees, of which 11,000 work outside Norway. The merger resulted in almost 5,000 employees being transferred from Hydro to StatoilHydro. Between February and September 2007, an extensive staffing process was carried out. This gave the company the option of selecting the best for the job and the individual employees a good opportunity to influence their choice of a new job in the merged company. StatoilHydro is an expertise-based company in which 55% of employees in the parent company have college or university education, and 21% have craft certificates. StatoilHydro ASA is Norway's biggest company for apprentices and our training of skilled workers maintains a stable and high level. Since the merger, the number of apprentices has increased to 316, spread over the different discipline areas. 3.7.2 Gender equality and diversity
Forty percent of the members of StatoilHydro ASA's new board are women. Gender equality is an important part of our personnel policy. After the merger, the proportion of female employees in the group is 35%. The proportion of female managers is 26%. Among managers under the age of 45, the proportion of women is 34%. Women are relatively well represented in the technical disciplines. In 2007, 22% of our staff engineers were women. Among staff engineers with up to 20 years' experience, the proportion of women was 33%. Wage levels are roughly the same for women and men with similar experience and corresponding positions. The proportion of our skilled workers who are women is 18%. On average, female skilled workers have slightly lower basic salaries than male skilled workers. This is due to differences in jobs and in number of years' experience. In the group as a whole, women earn 91% of men's earnings. This is due to differences in experience and in the proportion of women and men at different levels in the organisation. One of the measures introduced to meet our long-term recruitment needs and ensure access to personnel with different experience and backgrounds is the group trainee programme. We received a total of 2,000 applications for the programme from 91 different countries in 2007. The selection of candidates was completed in February 2008.
Share of women in different groups in StatoilHydro in 2007:
3.7.3 Flexible work arrangements
We have arrangements such as flexible working hours and remote work if the nature of the work is such that this is possible without it having particularly detrimental effects for the company. Such arrangements have become more widespread after the merger as a result of the decision to largely maintain geographical locations from both companies. As a result of the merger, approximately 300 employees signed commuting agreements with the company and a corresponding number moved to new office locations. 3.7.4 Cooperation with unions
In StatoilHydro ASA, 69% of the employees are covered by collective agreements. During the merger process, union members from Statoil and Hydro were represented on the Integration Planning Team which, among other things, was responsible for developing the new organisation and designing the staffing process. The climate of cooperation has been good and the process enjoyed broad support among employees. The company finds it essential to have a good and confidence-based relationship to its employees and their representatives. 3.7.5 Development and rewards
In 2008, all StatoilHydro employees will be included in the annual individual development process, People@StatoilHydro. The process is intended to ensure alignment between the company's business goals and the goals of individual employees. In addition, it is also intended to support the development of our employees and provide a clear picture of their performance and potential. Employees in StatoilHydro ASA are rewarded in relation to their position, expertise, performance and behaviour. In management development, the focus has been on the start-up of the new management teams. A shared understanding of the business challenges, the company's values and the leadership principles has been an important theme. At year end 2007, more than 100 management teams had completed a structured process. The goal for 2008 is to complete this process throughout the organisation. Work has started on further developing the management development programme. A separate programme has been established for the training of project managers in cooperation with the University of California, Berkeley. A broad spectrum of learning programmes is offered through the StatoilHydro School of Business and Technology. Most of them are open to all employees in the company. In 2007, 6,225 courses were completed with a total of 53,067 participants. The total number of hours of tuition was 107,276. As part of the merger process, a number of courses were held in the fourth quarter 2007 in connection with the new company's joint systems and IT solutions. 3.7.6 Health and working environment
StatoilHydro works systematically to ensure a working environment that promotes job satisfaction and good health. There are risk factors in our business that can entail a health and safety risk, and we must have good systems for managing this risk. This is done through defining requirements when we design workplaces. We closely monitor physical, chemical and organisational factors in the working environment, and we have a system for following up groups that are exposed to risk. Special attention is devoted to chemical health hazards, and, in 2007, action plans were drawn up for the individual business areas. The psychosocial working environment is important. A good balance must be achieved between work requirements, the opportunity the individual employee has for control and participation and support from colleagues and managers. We are focusing strongly on health and job satisfaction in the integration process. Prior to the merger, emphasis was placed on preparing managers to look after the interests of employees and on improving their insight into human reactions to change. This will be closely followed up in the time ahead. The company's health service is adapted to suit its activities and to meet requirements in the different countries in which it operates. Medical emergency response capability is established where necessary. StatoilHydro is an inclusive workplace enterprise. We actively monitor the working environment and make adaptations to prevent sickness absence. In connection with sickness absence, employees are followed up with a view to help them return to work as soon as possible. We are concerned with ensuring that employees have a stimulating working environment and are subject to a good personnel policy in all phases of their professional careers. Sickness absence in StatoilHydro in 2007 was 3.5%. It has remained stable and low at 3.5% for the last three years. The average sickness absence in Norway in the third quarter of 2007 was 6.0%. 3.7.7 Safety
Safe and efficient operations is our first priority. Our technical safety condition monitoring and the safety behaviour programme have been widely recognized. Accidents and particular major accidents pose a great threat to our business. Basic understanding of risks and the risk influencing factors are vital for performing safe operations. The total numbers of serious HSE incidents in our operations were held stable in 2007. The numbers of serious gas leakages on our installations and plants have declined slightly in 2007. StatoilHydro had three fatal accidents in 2007. In connection with mooring of the LPG vessel "Goodwood" at Mongstad harbour, two members of the crew were hit by a towing line and seriously injured. One of them died in the hospital the same day. A member of the winch crew on the crane barge "Saipem 7000" was hit by a hydraulic hose, fell overboard and drowned at the Tordis Field. A truck driver died after a traffic accident in Sweden. We firmly believe that all accidents can be prevented and our goal remains zero harm. We place a high focus on continually striving for better safety results in all our business. In striving for improving our results we are proud to say that our safe behaviour programme now includes 35,000 persons. The fundamental aspects of this programme are the five human safety barriers: correct priorities, compliance with requirements, open dialogue, continuous risk assessment and caring about each other. In our work to reduce the risk, we use a system for monitoring technical safety conditions. Together with daily focus on safe performance of work operations, this make us able to systematically work day-by-day to reduce the risk for major accidents. Although we did not achieve our 2007 HSE target we feel that we are on the correct track and will seek improvements in the years to come. 3.7.8 Organisational structure
The following table shows significant subsidiaries owned directly by the parent company in alphabetical order, as well as the parent company's equity interest and each subsidiary's country of incorporation. In each case our voting interest is equivalent to our equity interest.
3.8 Oil and gas production and sales volumes
The following table sets forth our Norwegian and international production of crude oil and natural gas for the periods indicated. The stated production volumes are the volumes that StatoilHydro is entitled to in accordance with conditions laid down in concession agreements and production sharing agreements, or PSAs. The production volumes are net of royalty oil paid in kind and of gas used for fuel and flare. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian State's oil and natural gas.
Sales Volume Information In addition to our own volumes, we market and sell oil and gas owned by the Norwegian State through the Norwegian State's share in production licenses, known as the State's direct financial interest, or SDFI, together with our own production. For additional information see section Operational review-Related party transactions. The following table sets forth SDFI and StatoilHydro sales volume information for crude oil and natural gas, as applicable, for the periods indicated. The SDFI volumes shown below include royalty oil we sell on behalf of the Norwegian State. The payment of royalty obligations on the NCS was abolished on 31 December 2005. The StatoilHydro natural gas sales volumes include equity volumes sold by Natural Gas, natural gas volumes sold by International E&P and ethane volumes.
3.9 Reserves replacement
Proved oil and gas reserves were estimated to be 6,010 million boe at the end of 2007, compared to 6,101 million boe at the end of 2006.
Proved reserves and changes to proved reserves are estimated in accordance with SEC definitions. The reserves replacement ratio is defined as the sum of proved reserves additions and revisions, divided by produced volumes in any given period. Changes in proved reserves estimates most commonly originate from revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or inclusion of proved reserves in new discoveries through sanctioning of development projects. These are sources of proved reserves additions that result from continuous business processes, and could be expected to continue to add reserves at some level in the future. Proved reserves may also be added or subtracted through acquisitions or disposals of assets. Changes in proved reserves may also originate from factors outside of management control, such as changes in oil and gas prices. While higher oil and gas prices normally allow more oil and gas to be recovered from the accumulations, StatoilHydro's proved oil and gas reserves under PSAs and similar contracts will generally decrease as a result. This reflects the fact that we will receive smaller quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of the increased oil and gas prices. These changes are included in the revisions category in the table below.
Reserves in new discoveries are normally booked only when regulatory approval has been received, or when such approval is imminent. Reserve additions from new discoveries booked in 2007 are expected to be produced in the period from year 2008 to 2026. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years. Below is a table showing the reserves additions in each change category relating to the reserve replacement ratio for the years 2007, 2006 and 2005.
A total of 541 million boe proved reserves were added during 2007, of which 261 million boe were proved developed reserves. The remaining 280 mmboe were proved undeveloped reserves. The reserves replacement ratio was 86% in 2007, compared to 61% in 2006. The increase in the reserve replacement ratio in 2007 compared to 2006 is mainly due to 2006 being a year with relatively small reserve additions from sanctions of new development projects. The average replacement rate for the last three years was 81%, including purchases and sales.
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 relating to the timing of project sanctions, and the time lag between exploration expenditure and booking of reserves.
We review our petroleum reserves in the course of business from time to time as new information becomes available. This information can relate to remaining reserves, existing production performance, decisions related to development, production, acquisition and divestment of reserves and changes in economic conditions. In addition, information on proved oil and gas reserves, standardised measure of discounted net cash flows relating to proved oil and gas reserves, and other information related to proved oil and gas reserves reported in note 32 - Supplementary oil and gas information - to our Consolidated Financial Statements, is collected and checked for consistency and conformity with applicable standards by a central group that is independent of the exploration and production business units. Although this group reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Before presenting the aggregated results to the responsible management of the relevant business units and the Chief Executive Officer for approval, this central group asks DeGolyer and MacNaughton, independent petroleum engineering consultants, to perform an independent evaluation of proved reserves, which was last performed as of 31 December 2007 for our assets. The results obtained by DeGolyer and MacNaughton do not differ materially from those reported by us when compared on the basis of net equivalent barrels of oil. DeGolyer and MacNaughton has delivered to us its summary letter report describing its procedures and conclusions, a copy of which appears in the following report section. Reserve engineering is a process of forecasting the recovery and sale of oil and gas from a reservoir and is in part subjective. It is clearly associated with considerable uncertainty, often positive, but also negative. The accuracy of any reserve information is a function of the quality of available data and of engineering and requires interpretation and judgment. The requirements of SEC with respect to the calculation of proved reserves set a standard for estimating reserves, which results in amounts that are reasonably certain technically, and consistent with the economic, regulatory and operating conditions at the time the estimates are made. See note 32 - Supplementary oil and gas information - to our Consolidated Financial Statements, for further details of our proved reserves. The transformation process of the Sincor joint venture into the new mixed company Petrocedeño was not finalised by the end of 2007. StatoilHydro therefore held proved reserves at year end 2007 in the Sincor joint venture structure with a share of 15%. StatoilHydro's shareholding interest in Petrocedeño will be 9.677%. The change in StatoilHydro's share will result in a reduction of proved reserves corresponding to 68 million barrels following completion of the transformation process. 3.9.1 Report of DeGolyer and MacNaughton
DeGolyer and MacNaughton, independent petroleum engineering consultants, performs an independent evaluation of proved reserves, which was performed as of 31 December 2007 for our properties. DeGolyer and MacNaughton has delivered to us its summary letter report describing its procedures and conclusions, a copy of which follows below. DEGOLYER AND MACNAUGHTON February 18, 2008 StatoilHydro ASA
Gentlemen:
Pursuant to your request, we have prepared estimates of the proved oil, condensate, liquefied petroleum gas (LPG), and sales gas reserves, as of December 31, 2007, of certain properties in Algeria, Angola, Azerbaijan, Brazil, Canada, China, Iran, Ireland, Libya, Nigeria, Norway, Russia, the United Kingdom, the United States, and Venezuela owned by StatoilHydro ASA (StatoilHydro). The estimates are discussed in our “Report as of December 31, 2007 on Proved Reserves of Certain Properties owned by StatoilHydro ASA” (the Report). We also have reviewed StatoilHydro’s estimates of reserves, as of December 31, 2007, of the same properties included in the Report.
In our opinion, the information relating to proved reserves estimated by us and referred to herein has been prepared in accordance with Paragraphs 10– 13, 15, and 30(a)– (b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the Financial Accounting Standards Board and Rules 4– 10(a) (1)– (13) of Regulation S–X of the United States Securities and Exchange Commission (SEC).
StatoilHydro represents that its estimates of the proved reserves, as of December 31, 2007, attributable to StatoilHydro’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalents (MMboe):
Note: Gas is converted to oil equivalent using a factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent.
StatoilHydro has advised us that its estimates of proved oil, condensate, LPG, and natural gas reserves are in accordance with the rules and regulations of the SEC. It is our opinion that the guidelines and procedures that StatoilHydro has adopted to prepare its estimates are in accordance with generally accepted petroleum reserves evaluation practices and are in accordance with the requirements of the SEC.
Our estimates of the proved reserves, as of December 31, 2007, attributable to StatoilHydro’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalents (MMboe):
Note: Gas is converted to oil equivalent using a factor of 5,612 cubic feet of gas per 1 barrel of oil equivalent.
In comparing the detailed reserves estimates prepared by us and those prepared by StatoilHydro for the properties involved, we have found differences, both positive and negative, in reserves estimates for individual properties. These differences appear to be compensating to a great extent when considering the reserves of StatoilHydro in the properties included in the Report, resulting in overall differences not being substantial. It is our opinion that the reserves estimates prepared by StatoilHydro on the properties reviewed by us and referred to above, when compared on the basis of net equivalent million barrels of oil, in aggregate, do not differ materially from those prepared by us.
Submitted,
DeGOLYER and MacNAUGHTON
/s/ Lloyd W. Cade
___________________________
Lloyd W. Cade, P.E.
3.10 Regulation
The principal Norwegian legislation applying to petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of November 29, 1996 (the "Petroleum Act"), and a number of regulations promulgated thereunder, as well as the Norwegian Petroleum Taxation Act of June 13, 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 the exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is authorized to award licenses concerning the petroleum activities. Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible for resource management and for administering petroleum activities on the NCS. The main task of the Ministry of Petroleum and Energy is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Storting, and relevant decisions of the Norwegian State. The Ministry of Petroleum and Energy primarily implements petroleum policy through its power to administer the award of licenses and approve operators' field and pipeline development plans, as well as petroleum transport and gas sales contracts. Only those plans that conform to the policies and regulations set by the Storting are approved. As set forth in the Petroleum Act, if a plan involves an important principle or will have a significant economic or social impact, it must also be submitted to the Storting for acceptance before being approved by the Ministry of Petroleum and Energy. We are not required to submit any decisions relating to our operations to the Storting. However, the Storting's role with respect to major policy issues in the petroleum sector may affect us in two ways: first, when the Norwegian State acts in the capacity as the majority owner of our shares and, second, when the Norwegian State acts in its capacity as regulator:
Although Norway is not a member of the European Union, or EU, it is a member of the European Free Trade Association (EFTA). The EU and its member states have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, with the members of EFTA (except Switzerland). The EEA Agreement makes certain provisions of EU law binding as between the states of the EU and the EFTA states, and also as between the EFTA states themselves. An increasing volume of regulation affecting us is adopted within the EU and is then applied to Norway under the EEA Agreement. As a Norwegian company operating both within EFTA and the EU, our business activities are regulated by both EEA law and EU law to the extent that EU law has been accepted into EEA law under the EEA Agreement. 3.10.1 The Norwegian licensing system
The most important type of license awarded under the Petroleum Act is the production license. The Ministry of Petroleum and Energy holds executive discretionary power to award a production license and to determine the terms of that license. The Government is not entitled to award a license in an area until the Storting has decided to open the area in question for exploration. A production license grants the holders an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the license. Notwithstanding the exclusive rights granted under a production license, the Ministry of Petroleum and Energy has the power to, in exceptional cases, permit third parties to carry out exploration in the area covered by a production license. For a list of our shares in production licenses, see report section Production - E&P Norway - Operational review. Production licenses are normally awarded through licensing rounds. The first licensing round for NCS production licenses was announced in 1965. The award of the first licenses covered areas in the North Sea. Over the years the award of licenses has moved northward and covers areas both in the Norwegian Sea and in the Barents Sea. In recent years, the principal licensing rounds have mainly included licenses in the Norwegian Sea. Beginning in 2003, the Norwegian government changed its policy on mature areas and introduced a scheme for award of production licenses named "Award in Predefined Areas" (APA) in mature parts of the Norwegian Continental Shelf. The award of licenses in the predefined areas has taken place every year since 2003. The Ministry of Petroleum and Energy has, in a report to the Storting, announced that this policy will continue. The Norwegian State accepts license applications from individual companies and group applications, enabling us to choose our exploration and development partners. Production licenses are awarded to joint ventures consisting of several companies. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the license. Once a production license is awarded, the licensees are required to enter into a joint operating agreement and an accounting agreement which regulate the relationship between the partners. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.
The governing body of the joint venture is the management committee. Each member is entitled to one seat on the management committee. The management committee's tasks are set out in the joint operating agreement and include setting guidelines for the operator of the field, exercising control over the activities of the operator, and making decisions on the activities of the joint venture. Votes in the management committee are counted by a combination of the number of members in the joint venture and their ownership interest. The number of votes required to make a decision varies from license to license, but a decision is normally reached when a certain number of the members and a percentage of the ownership interests, specified individually in each license, have voted in favour of a proposal. The voting rules are structured so that a licensee holding more than 50% of a license normally cannot vote through a proposal on its own, but will need the support of one or more of the other licensees. In licenses awarded since 1996 where the SDFI holds an interest, the Norwegian State, acting through the SDFI management company, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the license as to the Norwegian State's exploitation policies or financial interests. This veto right has never been used. Under the joint operating agreements covering licenses awarded prior to 1996, the management company that supervises the Norwegian State's SDFI interest, Petoro AS, has the power, with certain exceptions, to make decisions unilaterally in matters which are assumed to be of political or principal importance, or which may have significant social or socio-economic consequences, if Petoro AS is acting under the direction of its shareholder. Prior to the establishment of the SDFI management company, StatoilHydro held this right, which was exercised three times, most recently in 1988. In autumn 2002, the Storting began to allow individual license groups to substitute this special voting rule for the SDFI with a veto rule similar to the veto rules which have applied to licenses awarded since 1996. Such a substitution is subject to approval from the Ministry of Petroleum and Energy. The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. The operator is in practice always a member of the joint venture holding the production license, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement. Under the joint operating agreement, an operator may normally terminate its engagement upon six months' notice. The management committee may, however, with the consent of the Ministry of Petroleum and Energy, instruct the operator to continue performing its duties until a new operator has been appointed. The management committee can terminate the operator's engagement upon six months' notice on an affirmative vote by all members of the management committee other than the operator. A change of operator requires the consent of the Ministry of Petroleum and Energy. In special cases the Ministry of Petroleum and Energy can order a change of operator. Licensees are required to submit a plan for development and operation, or PDO, to the Ministry of Petroleum and Energy for approval. In respect of fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Until the PDO has been approved by the Ministry of Petroleum and Energy, the licensees cannot, without the prior consent of the Ministry of Petroleum and Energy, undertake material contractual obligations or commence construction work. Production licenses are normally awarded for an initial exploration period which is typically six years, but which can be either for a shorter period or for a maximum period of ten years. During this exploration period the licensees must meet a specified work obligation set out in the license. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfil the obligations set out in the production license, they are entitled to require that the license be prolonged for a period specified at the time when the license is awarded, typically 30 years. The right to prolong the license does not apply as a main rule to the whole of the geographical area covered by the initial license, but only to a percentage, typically 50%. The size of the area which must be relinquished is determined at the time the license is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production license. If natural resources other than petroleum are discovered in the area covered by a production license, the Norwegian State may decide to delay petroleum production in the area. If such a delay is imposed, the licensees are, with certain exceptions, entitled to a corresponding extension of the period of the license. To date, such a delay has never been imposed. The Norwegian State may, if important public interests are at stake, direct us and other licensees on the NCS to reduce production of petroleum. From 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 mbbls per day. In March 1999, the Norwegian State decided to increase the reduction to 200 mbbls per day. In the second quarter of 2000, the reduction was brought back to 100 mbbls per day. On 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 mbbls per day from 1 January 2002 until 30 June 2002. This amounted to roughly a 5% reduction in output. Licensees may buy or sell interests in production licenses subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of interest in a license, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. There are in most licenses no pre-emption rights in favour of the other licensees. The SDFI, or the Norwegian State, as appropriate, however, still holds pre-emption rights in all licenses. A license from the Ministry of Petroleum and Energy is also required in order to establish facilities for transport and utilization of petroleum. When applying for such licenses, the owners, which are in practice licensees under a production license, must prepare a plan for installation and operation. Licenses to establish facilities for transport and utilization of petroleum will normally be awarded subject to certain conditions. Typically, these conditions require the facility owners to enter into a participants' agreement. The ownership of most facilities for transport and utilization of petroleum in Norway and on the NCS are organized as a joint venture of a group of license holders, and the participants' agreements are similar to the joint operating agreements entered into among the members of joint ventures holding production licenses. Licensees are required to prepare a decommissioning plan before a production license or a license to establish and use facilities for transportation and utilization of petroleum expires or is relinquished, or the use of a facility ceases. The decommissioning plan must be submitted to the Ministry of Petroleum and Energy no sooner than five and no later than two years prior to the expiry of the license or the cessation of the use of the facility, and must include a proposal for the disposal of facilities on the field. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities. The Norwegian State is entitled to take over the fixed facilities of the licensees when a production license expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with expropriation of private property apply. Licenses for the establishment of facilities for transport and utilization of petroleum typically include a clause whereby the Norwegian State can require that the facilities be transferred to it free of charge at the expiration of the license period. 3.10.2 Gas sales and gas transportation
In contrast to the organization of gas sales prior to 1 June 2001, gas sales contracts with buyers for the supply of Norwegian gas are now concluded individually by each company. The upstream gas transportation system consists of several pipelines owned by a joint venture called Gassled, see report section Norwegian gas transportation system. The Norwegian authorities have by a royal decree of 20 December 2002 issued regulations for access to and tariffs for capacity in the upstream gas transportation system. There are three main considerations behind the regulations. Firstly the regulations, together with the law adopted by the Storting in June 2002, implement the Gas Directive of the European Union. Further, they established a system for access to the upstream gas transportation system that is compatible with company-based gas sales from the NCS. Thirdly, they provided for the new ownership structure of the upstream gas transportation system (Gassled). Parts of the regulations have a general application and parts - including the tariffs - are applicable only to the upstream gas transportation system owned by the Gassled joint venture. The regulations establish the main principles for access to the upstream gas transportation system. The access regime consists of a regulated primary market where the right to book free capacity, in accordance with regulations, is allocated to users with a duly substantiated reasonable need for transportation of natural gas. Further, the access regime consists of a secondary market where the capacity can be transferred between the users after the allocation in the primary market if the need for transportation changes.
The capacity in the primary market is released and booked through Gassco AS on the internet. Spare capacity is released for pre-defined time periods at announced points in time and with specific time limits for reservations. If the reservations exceed the spare capacity, the spare capacity will be allocated based on a distribution formula. However, consideration shall in case of spare capacity first be given to the owners' duly substantiated needs for capacity, which is limited to twice the owner's equity interest in the upstream pipeline network in question. Based on authorization given under the regulations, tariffs for use of capacity in Gassled are determined by the Ministry of Petroleum and Energy. The Ministry's policy for determining the tariffs is to avoid excessive returns being created on the capital invested in the transportation system, allowing the return on the Norwegian petroleum activity to be taken out on the fields instead of in the transportation systems. The tariffs are to be paid for booked capacity and not in respect of the actually transported volume. 3.10.3 Gas directive of the European Union
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. The Directive requires that all consumers in Europe should be able to choose their energy supplier beginning in July 2007. Fundamental changes to this directive and regulation were proposed by the European Commission in September 2007 with a specific focus on the separation of ownership of transmission assets from supply activities. The objective of these proposals is to increase competition in national markets and integrate them into regional and eventually a single EU-wide market for natural gas. The final form of these proposals are as yet unknown and are expected to be developed further throughout 2008. It is difficult to predict the effect liberalisation measures will have on the evolution of gas prices, but the main objective of the single gas market is to bring greater choice and reduced prices for customers through increased competition. 3.10.4 HSE regulation
Petroleum operations in Norway are subject to extensive regulation with regard to health, safety and the environment, or HSE. Under the Petroleum Act, which is in this respect administered by the Ministry of Labour and Government Administration, all petroleum operations must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of employees, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained and developed in accordance with technological developments. Licensees and other persons engaged in petroleum operations are required to maintain at all times a plan to deal with emergency situations. During an emergency, the Ministry of Labour and Government Administration may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, to deal with the emergency for the account of the licensees. The Petroleum Safety Authority Norway (PSA) has the regulatory responsibility for safety, emergency preparedness and the working environment for all petroleum-related activities. The PSA's sphere of responsibility also includes supervision of safety, emergency preparedness and the working environment at the petroleum facilities and connected pipeline systems on land. In our capacity as a holder of licenses under the Petroleum Act, we are subject to strict statutory liability in respect of losses or damages suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licenses. This means that anyone who suffers losses or damages as a result of pollution caused by any of our NCS license areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part. If the pollution is caused by a force majeure event, a Norwegian court may reduce the level of damages to the extent it considers reasonable. 3.10.5 Taxation of StatoilHydro
We are subject to ordinary Norwegian corporate income tax as well as to a special petroleum tax relating to our offshore activities. We are also subject to a special carbon dioxide emissions tax and, from 2007, a nitrogen oxide fee. Under our production licenses we are obligated to pay an area fee to the Norwegian State. Set forth below is a summary of certain key aspects of the Norwegian tax rules that apply to our operations. Corporate income tax. Our profits, both from offshore oil and natural gas activities and from onshore activities, are subject to Norwegian corporate income tax. The corporate income tax rate is currently 28%. 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 provides that the norm prices shall correspond to the prices that could have been obtained in case of a sale of petroleum between independent parties in a free market. When adopting norm prices, the Petroleum Price Board takes into consideration a number of factors, including spot market prices and contract prices within the industry. The maximum rate for depreciation of development costs related to offshore production installations and pipelines is 16 2/3% per year. The depreciation starts when the cost is incurred. Exploration costs may be deducted in the year in which they are incurred. Beginning in 2007, financial costs related to the offshore activity are calculated directly based on a formula set 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 per cent of losses relating to activity conducted onshore in Norway may be deducted from NCS income subject to the 28% tax rate. Losses from foreign activities may not be deducted against NCS income. Losses from offshore activities are fully deductible against onshore income. By use of group contributions between Norwegian companies in which we hold more than 90% of the shares and the votes, tax losses and taxable income can, to a great extent, be offset. Group distributions are not deductible in our offshore income. From 1 January 2004, dividends received have not been subject to tax in Norway. Exemptions exist for dividends from low-tax countries or portfolio investments outside the EEA. From 26 March 2004, capital gains on realization of shares are not taxable and losses are not deductible. Exemptions exist for shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA. Special petroleum tax. A special petroleum tax is levied on profits derived from petroleum production and pipeline transportation on the NCS. The special petroleum tax is currently levied at a rate of 50%. The special tax is applied to relevant income in addition to the standard 28% income tax, resulting in a 78% marginal tax rate on income subject to petroleum tax. The basis for computing the special petroleum tax is the same as for income subject to ordinary corporate income tax, except that onshore losses are not deductible against the special petroleum tax, and a tax-free allowance, or uplift, is granted at a rate of 7.5% per year. The uplift is computed on the basis of the original capitalized cost of offshore production installations. The uplift may be deducted from taxable income for a period of four years, starting in the year in which the capital expenditures are incurred. Unused uplift may be carried forward indefinitely. Abandonment costs. Abandonment costs incurred can be deducted as operating expenditures. 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 0.80 for 2007 and NOK 0.45 for 2008 per standard cubic meter of gas burned or directly released and per litre of oil burned. For 2008, companies operating on the NCS will have to buy quotas to cover the carbon dioxide emissions from the petroleum activities. Nitrogen oxide fee. Beginning on 1 January 2007, the Norwegian government introduced a nitrogen oxide fee applicable to emissions of nitrogen oxide on the NCS. The fee is NOK 15.40 per kilogram of nitrogen oxide (NOK 15.39 for 2008). Area fee. After the expiration of the initial exploration period, the holders of production licenses are required to pay an area fee. The amount of the area fee is set out in regulations promulgated under the Petroleum Act. In respect of most of the production licenses, the initial annual area fee is currently NOK 7,000 per square kilometre. The annual area fee is increased yearly by NOK 7,000 until it reaches NOK 70,000 per square kilometer. Royalty. The obligation to pay royalty on the NCS was abolished at the end of 2005. 3.10.6 The Norwegian state as a regulatory authority
As a corporation based in Norway, we are subject to the laws and regulations of the Kingdom of Norway. Changes to relevant laws and regulations could have a significant impact on our operations. Various agencies and departments of the Kingdom of Norway exercise regulatory functions over our activities. The Ministry of Petroleum and Energy also exercises important regulatory powers over all petroleum operations of the companies of the NCS, including those of Statoil. For additional information about the Ministry of Petroleum and Energy's role, see previous report sections under Regulation for further details. A number of other agencies and departments, such as the Norwegian Petroleum Directorate, the Ministry of Finance, the Ministry of Labour and Government Administration, the Ministry of the Environment and the Norwegian Pollution Control Authority, exercise regulatory powers which affect important parts of our operations.
A significant part of the taxes we pay are paid to the Norwegian State, see previous report sections under Regulation for further details. 3.10.7 The Norwegian state's direct participation in petroleum operations on the NCS
The Norwegian State's policy as an owner has been, and continues to be, to ensure that petroleum activities create the highest possible value for the Norwegian State. Initially, the Norwegian State's participation in petroleum operations was organized mainly through us. In 1985, the Norwegian State established the State's direct financial interest, or SDFI, through which the Norwegian State has taken direct participating interests in licenses and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licenses and petroleum facilities in which we also hold interests. As a result of changes in global markets and competitive conditions in the petroleum industry, the Norwegian State implemented a strategic review of its oil and gas policy in 2000. Based on the results of this strategic review, the Norwegian State prepared a plan to restructure its petroleum holdings on the NCS that was approved by the Storting on 26 April 2001. The key elements of the restructuring plan include:
3.10.8 Marketing and sale of the SDFI's oil and gas
Introduction. We have historically marketed and sold the Norwegian State's oil and gas as a part of our own production. The Norwegian State has elected to continue this arrangement. Accordingly, at an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article which requires us to continue to market and sell the Norwegian State's oil and gas together with our own oil and gas in accordance with an instruction established in shareholder resolutions in effect from time to time. At an extraordinary general meeting held on 25 May 2001, the Norwegian State, as sole shareholder, approved a resolution containing the instructions referred to in the new article. This resolution is referred to as the owner's instruction. The Norwegian State has a coordinated ownership strategy to maximise the aggregate value of its ownership interests in StatoilHydro and the Norwegian State's oil and gas. This is reflected in the owner's instruction, which contains a general requirement that, in our activities on the NCS, we are required to take account of these ownership interests in decisions that may affect the execution of this marketing arrangement. The owner's instruction sets forth specific terms for the marketing and sale of the Norwegian State's oil and gas. The principal provisions of the owner's instruction are as set forth below. Objectives. The overall objective of the marketing arrangement is to obtain the highest possible total value for our oil and gas and the Norwegian State's oil and gas and ensure an equitable distribution of the total value creation between the Norwegian State and us. In addition, the following considerations are important:
Our tasks. Our tasks under the owner's instruction are to market and sell the Norwegian State's oil and gas and to carry out all necessary tasks, other than those carried out jointly with other licensees under the production license, in relation to the marketing and sale of the Norwegian State's oil and gas, including, but not limited to, the responsibility for processing, transport and marketing. In the event that the owner's instruction is terminated, in whole or in part, by the Norwegian State, the owner's instruction provides a mechanism under which contracts for the marketing and sale of the Norwegian State's oil and gas to which we are a party may be assigned to the Norwegian State or its nominee. Alternatively, the Norwegian State may require that the contracts be continued in our name, but to the effect that in the underlying relationship between the Norwegian State and us, the Norwegian State receives all rights and obligations related to the Norwegian State's oil and gas. Costs. The Norwegian State does not pay us specific consideration for executing these tasks, but the Norwegian State reimburses us for its proportionate share of certain costs, which under the owner's instruction may be our actual costs or an amount specifically agreed. Price mechanisms. For sales of the Norwegian State's natural gas, both to us and to third parties, the payment to the Norwegian State is based on either achieved prices, a net back formula or market value. We now purchase all of the Norwegian State's oil and NGL. Pricing of the crude oil is based on market reflective prices. NGL prices are based on either achieved prices, market value or market reflective prices. Lifting mechanism. As part of the coordinated ownership strategy, a lifting mechanism for the Norwegian State's and our oil and gas is established in accordance with rules set out in the owner's instruction. To ensure a neutral weighting between the Norwegian State's and our natural gas volumes, a list has been established for deciding the priority between each individual field. To decide the ranking, a mathematical optimisation model is used which describes existing and planned production facilities, infrastructure and processing terminals where the Norwegian State and we have ownership interests. The list yields a result giving the highest total net present value for the Norwegian State's and our oil and gas. In the evaluation, the following objective criteria shall, among other things, apply:
The different fields are ranked in accordance with the assumed total value creation for the Norwegian State and us, assuming all of the fields meet our profitability requirements if we participate as a licensee, and the Norwegian State's profitability requirements if the State is a licensee. The list is updated annually or more frequently if incidents occur that may significantly influence the ranking. Within each individual field where both the Norwegian State and we are licensees, the Norwegian State and we will deliver volumes and share income in accordance with our respective participating interests. The Norwegian State's oil and NGL are lifted together with our oil and NGL in accordance with applicable lifting procedures for each individual field and terminal. Withdrawal or Amendment. The Norwegian State may utilise its position as majority shareholder of StatoilHydro at any time to withdraw or amend the instruction requiring us to market and sell the SDFI oil and natural gas together with our own. 3.10.9 Petoro AS - The SDFI management company
From the establishment of StatoilHydro in 1972 until 1 January 1985, the participation of the Norwegian State in production licences and facilities for transport and utilisation of petroleum took place entirely through us. As of 1 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 a transfer of a substantial part of our participation in most of our then-existing 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. We were, until 17 June 2001, registered as licensee for all SDFI shares in licenses. In accordance with a decision made in an extraordinary general meeting on 10 May 2001, we were until this time also the manager of the SDFI shares in these licences on behalf of the Norwegian State. Where both the SDFI and we had an interest in the same licence, the department managing our interest also managed the SDFI interest. In fields with SDFI interests only, the interests were managed by a separate unit that we established for this purpose. Our tasks as the manager of the SDFI's interests have included attending management committee meetings for both the SDFI's and our own share in licences, and votes cast by us in management committee meetings have represented both the SDFI's and our own interests in the licences. We have also been responsible for marketing the petroleum of which the Norwegian State becomes the owner through the SDFI shares in production licences. In connection with the restructuring, the Norwegian State on 9 May 2001 established a new State-owned company, Petoro AS, which took over responsibility for and the management of the SDFI assets as licencee, in accordance with a new chapter of the Petroleum Act. The Norwegian State continues to be the beneficial owner of these assets. We continue to market and sell the Norwegian State's oil and gas together with our own oil and gas, pursuant to the owner's instruction described under report section Marketing and sale of the SDFI's 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, does not receive any revenues from sales of the Norwegian State's oil and gas, and is not permitted to obtain an operator role. However, Petoro AS may become a participant in new licences awarded by the Norwegian State. 3.10.10 Gassco AS - The gas transportation operating company
In connection with the restructuring of the Norwegian State's oil and gas interests, on 14 May 2001 the Norwegian State established a separate company, Gassco AS, which on 1 January 2002 took over as operator of the natural gas transportation system previously operated by us. Gassco AS is wholly owned by the Norwegian State. The owners of the infrastructure systems appointed Gassco AS as the new operator. The transfer of the operatorship to Gassco AS was made without consideration and does not affect existing arrangements with respect to ownership or access to the natural gas transportation system or tariffs for transport. However, in accordance with the joint venture agreements relating to each of the gas transportation assets, the operator is entitled to be reimbursed for its costs as operator. Accordingly, since Gassco AS was appointed as operator, we no longer receive such reimbursement, and we will, as will other users of the infrastructure, be required to pay our portion of Gassco AS's expenses associated with the operation of the natural gas pipelines in which we hold interests. Gassco AS has entered into contracts with us for each infrastructure joint venture, pursuant to which we will carry out technical operating activities on behalf of Gassco AS, such as system maintenance, for which we will receive reimbursement of costs. Either Gassco AS or we may terminate without cause each of these contracts, except the contract for the Statpipe joint venture, after five years. Either Gassco AS or we may also terminate the part of the Statpipe contract, which refers to the offshore pipelines, after five years. Currently, Gassco AS may terminate the part of the Statpipe contract that refers to the Kårstø plant, at any time, provided that 2/3 of the owners, representing more than 2/3 of the ownership interests, have supported such termination. The natural gas transportation system was transferred to a new joint venture called Gassled as of 1 January 2003. Gassco AS is the operator of the Gassled joint venture. Our initial direct ownership interest in Gassled is currently 32.06% (32.86% including our indirect interest through our 28.58% holding in Norsea Gas AS), 15.71% in Zeepipe Terminal JV and 20.84% in Dunkerque Terminal DA. From 1 January 2011, our direct ownership interest in Gassled will be reduced to 28.05% due to an increased ownership interest for SDFI. In addition, our ownership interest in Gassled may also change as a result of inclusion of existing or new infrastructure or if Gassled undertakes further investments without participation from its owners in the same ratio as their ownership interests in Gassled. For more information on the Gassled joint venture, see report section Norwegian gas transportation system and other facilities. 3.11 Competition
In the oil and gas industry there is intense competition for customers, production licenses, operatorships, capital and experienced human resources. In recent years the oil and gas industry has experienced consolidation, as well as increased deregulation and integration in strategic markets. StatoilHydro competes with major integrated oil and gas companies, as well as independent and government-owned companies for the acquisition of assets and licences for the exploration, development and production of oil and gas, and for the refining, marketing and trading of crude oil, natural gas and related products. Key factors affecting competition in the oil and gas industry are oil and gas prices and demand, the cost of exploration and production, global production levels, alternative fuels and governmental and environmental regulations. StatoilHydro's ability to remain competitive will require, among other things, management's continued focus on reducing unit costs and improving efficiency, maintaining long-term growth in our reserves and production through continued technological innovation and our ability to capture international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. The company believes that it is in a position to compete effectively in each of its business segments. 3.12 Property, plant and equipment
Our principal offices located at Forusbeen 50, N-4035, Stavanger, Norway, comprise approximately 103,000 square meters of office space, and are owned by StatoilHydro. We have interests in real estate in numerous countries throughout the world, but no one individual property is significant to us as a whole. We have no significant ongoing construction projects or plans to add new office space. See Supplementary information on Oil and Gas producing activities in the F-pages for a description of our significant reserves and sources of oil and natural gas. 3.13 Related party transactions
Transactions with the Norwegian State For a description of shares held by the Norwegian State, see report section Shareholder information-Major Shareholders, section 6.4. See also report section Financial performance-Liquidity and capital resources-Material contracts, section 4.2.3 for details on the merger between Statoil and Norsk Hydro's oil and gas activities. Transactions with other entities in which the Norwegian State is a major shareholder As a result of the substantial percentage of industry in Norway controlled by the Norwegian State, there are many state-controlled entities with which we do business. The financial value of most such transactions is relatively small, and the ownership interest of the Norwegian State of such counter parties has not had any effect on the arm's-length nature of the transactions. In particular, in respect of the goods and services that we purchase, we purchase telephone services from Telenor ASA, a telecommunications company in which the Norwegian State holds a 53.9% 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 oil and natural gas liquids from the Norwegian State amounted to NOK 98,498 million (237 mmboe) and NOK 104,628 million (254 mmboe) in 2007 and 2006, respectively. Purchases of natural gas from the Norwegian State (excluding purchases from licences and sales on behalf of the Norwegian State) amounted to NOK 287 million and NOK 293 million in 2007 and 2006, respectively. The prices paid by StatoilHydro for the oil purchased from the Norwegian State are estimated market prices. In addition, StatoilHydro 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 us for its relative share of the costs related to certain StatoilHydro natural gas storage and terminal investments and related activities. See report section Regulation-Marketing and sale of the SDFI's oil and gas for more details. Employee Loans We have a general arrangement with DnB NOR whereby DnB NOR 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 for paying the interest rate difference will be dependent on the loan volume, but based on current interest rates would not exceed NOK 5 million per year. The three employee-elected members of the board of directors and two members of the executive Committee each entered into loan agreements under this facility prior to 30 July 2002, and had, as of 31 December 2007, an aggregate total balance outstanding payable to DnB NOR under this loan facility of NOK 149,076. Members of the executive committee and the board of directors may not enter into loans under the foregoing program. 4 Financial performance
The merger between Statoil and Hydro's oil and gas activities was a forceful reponse to increasing industry complexity and international competition. The merged StatoilHydro has an expanded technology base and stronger capabilities to execute larger and more demanding projects. The company has a broader global presence and a stronger portfolio of assets and resources. See previous sections for information about the nature and extent of our operations. The successful execution and completion of the merger on 1 October 2007, was a key milestone in a year with a historic high activity level. The entitlement production of oil and gas increased by 3%, 15 new projects commenced production, an extensive exploration programme was executed, and the company gained access to new high quality projects and exploration acreage. StatoilHydro delivered a solid annual result and is well positioned for future growth and value creation. The following tables show selected consolidated financial and statistical data for StatoilHydro. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU). The accounting policies applied by the Group also comply with IFRSs as issued by the International Accounting Standards Board (IASB).
4.1 High activity level in new organisation
StatoilHydro delivered a total oil and gas entitlement production in 2007 of 1.724 mmboe per day. The contribution from international operations was record high and accounted for 18% of the entitlement production. Solid performance, combined with high oil and gas prices, was partly offset by an increase in operating costs and a decrease in production on the Norwegian continental shelf (NCS). The net operating income for 2007 of NOK 137 billion was also affected by restructuring costs related to the merger totalling NOK 11.1 billion. The company reached major milestones in several projects on the NCS. During autumn 2007, the Ormen Lange project started production and export of gas to the UK, and was officially inaugurated in October. Also in October, the first LNG was shipped from the Snøhvit LNG plant on Melkøya. The LNG plant has suffered from operational challenges and there are still uncertainties related to the timing of regular and stable operations. In addition, eight projects on the NCS and five international projects came on stream in 2007. The company also sanctioned 13 new projects for development, of which four are outside Norway. In 2007 StatoilHydro delivered an extensive exploration programme. Of a total of 71 exploration wells, 47 were drilled outside of the NCS. The company participated in 36 discoveries, of which 18 were made internationally. During 2007, the company added 215 million boe in proved reserves from new discoveries and extensions. 325 million boe were added from revisions and improved recovery. In total, the company achieved a reserve replacement ratio of 86% in 2007.
During 2007, StatoilHydro gained access to new growth opportunities. In June, the company acquired North American Oil Sands Corporation and established a position in Canadian oil sands. The position in the deepwater US Gulf of Mexico was strengthened by accessing new exploration licences in ordinary lease sales. Towards the end of the year, the company was selected as a partner in the development of the offshore gas and condensate field Shtokman. In 2008, the company has to date strengthened its international foothold by signing an agreement to acquire the remaining 50% share and operatorship of the Brazilian Peregrino field as well as an additional position, the Kaskida discovery, in the US Gulf of Mexico. The transaction is subject to government approval and the acquisition of the Kaskida discovery is also subject to other parties not exercising preferential rights to purchase. As of 4 April, the company has been formally notified that two of such parties intend to exercise their preferential rights. As part of the merger process, the company executed a thorough evaluation of the organisation and operations. A potential of more than NOK 6 billion of annual synergies has been identified. These synergies confirm the significant value creation potential of the merger. The report for 2007 is the first annual report in which financial statements for the merged StatoilHydro organisation are presented. Historical data have been restated as if the merged company had existed for all periods. 4.1.1 Group profit and loss analysis
Revenues and other income totalled NOK 522.8 billion in 2007. This was NOK 1.3 billion more than in 2006. Most of the stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by StatoilHydro. We also market and sell the Norwegian State's share of oil from the NCS. All purchases and sales of the Norwegian State's production are recorded as Cost of goods sold and Sales, respectively.
From 2006 to 2007 realised oil prices measured in NOK increased by 2%. The increased oil prices contributed NOK 3.1 billion to the revenues, whereas the contribution from increased oil liftings was NOK 5.0 billion. Overall gas sales contributed with NOK 3.6 billion to the change. This was off-set by a decrease in gas prices with a negative impact of NOK 10.4 billion. The volumes of oil lifted will over time correlate with the volumes produced. However, the volumes may be higher or lower than production in any period due to operational factors affecting the timing of when we lift the oil from the fields. Total oil liftings increased from 1.048 mmboe per day in 2006 to 1.081 mmboe per day in 2007. Entitlement volumes lifted is the basis for the revenue recognition while equity production volumes more directly affect operating costs. See report section Reported volumes for more details on the differences between equity and entitlement volumes. See below for more details on the difference between lifted and produced volumes.
Total natural gas sales were 42.0 bcm (1.48 tcf) in 2007 and 40.2 bcm (1.42 tcf) in 2006. The increase was mainly due to higher third party gas sales, and was partly offset by a net decrease in StatoilHydro entitlement sales volumes. Net income (loss) from equity accounted investments. Our share of equity in net income of affiliates was NOK 0.6 billion in 2007 and NOK 0.7 billion in 2006. Other income was NOK 0.5 billion in 2007 compared to NOK 1.8 billion in 2006. The income in 2007 was mainly related to gains from sale of assets whereas the income the previous year was mainly related to a change in the write-down of inventory to production cost and gains from sales of assets. Cost of goods sold includes the cost of the oil and NGL production that we purchase from the Norwegian State pursuant to the Marketing Instruction. The cost of goods sold increased in 2007 to NOK 260.4 billion and was mainly due to higher oil prices 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 60.3 billion in 2007 compared to NOK 44.8 billion in 2006. The increase was primarily due to restructuring costs and other costs related to the merger, as well as higher operation and maintenance costs, increased transportation costs and new fields coming on stream. Total oil and gas production increased from 1,708 mmboe per day in 2006 to 1,724 mmboe per day in 2007. The increase in entitlement production was driven by a 31% increase internationally, which was partly offset by a minor decrease on the NCS. Equity production of oil and gas increased from 1,778 mmboe per day in 2006 to 1,839 mmboe per day in 2007. Unit production cost measured in NOK was NOK 44.1 (USD 8.12) per boe in 2007 compared to NOK 28.4 (USD 5.23) per boe in 2006. The increase was mainly due to restructuring costs, start-up of new fields, increased maintenance costs and general industry cost pressure. Adjusted for restructuring costs and other costs arising from the merger, the average production cost per boe for 2007 was NOK 35.7. This amount includes NOK 2.5 related to the cost of purchased gas for reinjection in support of oil production. Divided by equity volumes, the production cost measured in NOK was 41.4 per boe in 2007, an increase of NOK 14.1 per boe compared to 2006. Selling, general and administrative expenses include expenses related to the selling and marketing of our products such as business development costs, payroll and employee benefits and amounted to NOK 14.2 billion in 2007 compared to NOK 10.8 billion in 2006. The increase was mainly due to restructuring costs and other costs arising from the merger, partly offset by a pre-tax gain in 2006 of NOK 0.6 billion from the sale of Statoil Ireland. Depreciation, amortisation and impairment includes depreciation of production installations and transport systems, depletion of fields in production, amortisation of intangible assets and depreciation of capitalised exploration expenditure. It also includes write-downs of impaired long-lived assets. These expenses amounted to NOK 39.4 billion in 2007, compared to NOK 39.5 billion in 2006. A decrease of NOK 3.3 billion in depreciation, amortisation and impairment expenses in 2007 compared to 2006 was offset by higher asset retirement costs of NOK 2.1 billion and the start-up of new fields in 2007. The impairments of Gulf of Mexico shelf fields and Front Runner amounted to NOK 4.9 billion in 2006, compared to impairments in 2007 of Lufeng, Front Runner, Thunder Hawk and GoM shelf fields amounting to NOK 1.2 billion. Exploration expenditures are capitalised to the extent the 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 2007 and write-offs of exploration expenditure capitalised in previous years. The exploration expense was NOK 11.3 billion in 2007 and NOK 10.7 billion in 2006.
The increase of 6% in the exploration expense was mainly due to higher exploration activity, generally more expensive wells and an increase in the expensing of previously capitalised licences and well expenditure. In 2007, a total of 71 exploration and appraisal wells were completed, 24 on the NCS and 47 internationally. In addition, two exploration extension wells were completed in the same period. Thirty-four of the exploration and appraisal wells were confirmed discoveries, 16 on the NCS and 18 internationally. Both exploration extension wells were discoveries.
In 2006, a total of 73 exploration and appraisal wells were completed, 18 on the NCS and 55 internationally. Five exploration extension wells were completed during the same period. Thirty-two of the exploration and appraisal wells were confirmed discoveries, eight on the NCS and 24 internationally. Two exploration extension wells were discoveries. Net operating income was NOK 137.2 billion in 2007, compared to NOK 166.2 billion in 2006. The decrease was mainly due to an increase in operating, selling and administrative expenses stemming in part from restructuring and other costs arising from the merger of NOK 11.1 billion, negative change in derivatives of NOK 10.0 billion, new fields coming on stream and increased activity levels. The restructuring costs and other costs arising from the merger have been recorded primarily under operating and general and administrative expenses, and have been allocated to the business areas where possible.
Restructuring costs and other costs arising from the merger primarily relate to pensions and early retirement costs and impairment of assets in Sweden. In 2007 we reported a Net financial items income of NOK 9.6 billion, compared to a net financial items income of NOK 5.1 billion in 2006. The changes from year to year were principally the result of changes in currency gains and losses on the USD portions of our non-current financial liabilities outstanding and currency gains and losses on NOK hedging transactions. In both cases, currency gains and losses relate to changes in the USDNOK exchange rate, due to the weakening of the USD against the NOK. Currency swaps are used for risk management purposes to hedge our long-term interest-bearing loans recorded in USD. As a result, the company's long-term debt portfolio is exposed to changes in the USDNOK exchange rate. The USD weakened by NOK 0.85 in relation to the NOK in 2007, compared with a weakening of NOK 0.51 in 2006. Interest and other financial income amounted to NOK 2.3 billion in 2007, compared to NOK 3.7 billion in 2006. Interest and other financial expenses amounted to NOK 2.7 billion in 2007, compared to NOK 3.1 billion in 2006. The decrease in interest and other expenses was mainly due to a decrease in interest expenses on our long term loan portfolio, caused by currency effects and gains on interest rate swaps related to former Hydro long-term interest bearing loan contracts. This portfolio was swapped from fixed to floating interest rate in the second half of 2007. These effects were partly offset by increased accretion expenses related to asset retirement obligations and a decrease in interests being capitalised. This was mainly due to the fact that fields such as Snøhvit and Ormen Lange came on stream in 2007. Management of the portfolio of security investments, mainly related to equity securities held by our insurance captive, Statoil Forsikring AS, and commercial papers held by Statholding AS, resulted in a loss of NOK 0.2 billion in 2007, compared to a loss of NOK 0.6 billion in 2006. The Norwegian central bank's closing rate for USDNOK was 5.41 on 31 December 2007 and 6.26 on 31 December 2006. These exchange rates have been applied in StatoilHydro's financial statements. The effective Income tax rates were 69.6% and 69.7% in 2007 and 2006, respectively. Adjusted for the non-recurring NOK 2.0 billion reduction of deferred tax liabilities relating to new tax rules for allocation of financial items with respect to the NCS and temporary differences in intercompany transactions, the tax rate in 2006 was 70.9%. The tax rate in 2007 was lower than the adjusted tax rate in 2006, mainly due to higher net financial income and the increased effect of uplift deduction on the NCS. The lower tax rate was partly offset by relatively less income from outside the NCS being subject to lower taxation than the average tax rate. The effective tax rate is calculated as income taxes divided by income before income taxes and minority interest. Fluctuations in the effective tax rates from year to year are principally 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, taxed at 28%; and income in other countries taxed at the applicable income tax rates. In 2007, the Minority interest in net profit was NOK 0.6 billion, compared to NOK 0.7 billion in 2006. The minority interest primarily related to the Mongstad crude oil refinery. Net income was NOK 44.6 billion in 2007, compared with NOK 51.9 billion in 2006. The decrease was mainly due to a lower operating income primarily due to restructuring costs and other costs arising from the merger, negative changes in derivatives and a higher tax rate, partly offset by higher net financial income. The Board of Directors proposes an ordinary dividend of NOK 4.20 per share for 2007 to the Annual General Meeting, as well as NOK 4.30 per share in special dividend, making an aggregate total of NOK 27,085 million. 4.1.2 Group outlook
We expect to continue our high level of exploration activity in 2008 and we plan to drill approximately 70 exploration wells. On the NCS, a significant part of the drilling activity is expected to be in mature areas close to existing infrastructure. We also plan to drill several wells in frontier areas of the Norwegian Sea and in the Barents Sea. Internationally we plan to continue to pursue a high level of exploration activity combined with targeted business development consistent with our strategy to further grow our resource base. Rig capacity has been secured for the number of wells in the 2008 drilling programme, and we believe we are well positioned for further exploration drilling beyond 2008 based on our current drilling programme and rig commitments. Our entitlement production estimate for 2008 is approximately 1.75 mmboe per day (at USD 75 per barrel). 2007 was one of the most volatile periods in the product, gas liquid and crude oil markets. High prices were experienced during the year and we believe that prices will remain relatively high and volatile at least in the near term. Changes in supply, demand and cost of alternative fuels will be reflected in the price formation of natural gas. Higher development costs in the industry combined with the fact that the transportation distances between new supply regions and markets are increasing therefore suggest that gas prices may increase over time to ensure development of sufficient supplies. However, a number of other factors may still cause lower prices. For instance, prices in the shorter term gas market may be adversely affected by seasonal demand variations at the same time as new capacity and new fields are coming on stream towards 2010. The value of natural gas will also be influenced by the price development and regulation in the power segment where gas is competing with coal, renewable- and nuclear energy. We have also seen that gas markets are moving from being pure regional markets to being more influenced by global supply and demand balances. LNG in the Atlantic basin, for instance, is responding to changes in prices between major markets in Europe, the US and Asia, taking advantage of arbitrage opportunities, creating higher volatility. Our views on these events make us in sum believe that we have increased value creation potential by combining the proximity of our infrastructure to favourable markets with advanced marketing competence and skills. In 2008, we estimate organic capital expenditures for the group of approximately NOK 75 billion and approximately NOK 80 billion in 2009, assuming an exchange rate of USDNOK 6.0. Unit production cost for equity volumes is estimated in the range of NOK 33 to 36 per barrel in the period from 2008 to 2012, excluding purchases of fuel and gas for injection. It is our ambition to deliver a competitive ROACE compared with our peers. 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. 4.1.3 Segment performance and analysis
The following table details certain financial information for our four business segments. When combining business segment results, we eliminate intercompany sales. These include transactions recorded in connection with our oil and natural gas production in the Exploration & Production Norway (EPN) or International Exploration & Production (INT) segments and also in connection with the sale, transport or refining of our oil and natural gas production in the Manufacturing & Marketing (M&M) or Natural Gas (NG) segment. EPN produces oil, which it sells internally to Oil Sales, Trading and Supply in the M&M segment, which then sells the oil in the market. EPN also produces natural gas, which it sells internally to our NG business area, also for sale in the market. A large share of the oil and a small share of the natural gas produced by INT is also sold in the same way as the oil and the natural gas produced by EPN. The remaining oil and gas from INT is sold directly in the market. We have established a market price-based transfer pricing policy whereby we set an internal price at which our EPN business area sells oil and natural gas to the M&M and the NG segment. Management has recently decided to update the transfer price formula for natural gas produced by EPN and marketed and sold by NG to better reflect fundamental changes since the previous formula was set in 2002 in the markets for competing energies, i.e. crude oil, for developments in natural gas markets and for changes in the natural gas sales contracts portfolio. The change will be effective from 1 January 2008 and will be reflected in our financial reporting going forward, without restating prior periods. For sales of oil from EPN to M&M, the transfer price of oil is the applicable market reflective price minus a margin of NOK 0.70 per barrel. The transfer price of sales of natural gas from EPN to NG is NOK 0.32 per standard cubic metre, adjusted quarterly by the average USD oil price over the previous six months in proportion to USD 15 per barrel. The average transfer price for natural gas per standard cubic metre was NOK 1.39 in 2007 and NOK 1.35 in 2006. The table shows certain financial information for our four segments, including intercompany eliminations for each of the years in the two-year period ending 31 December 2007.
4.1.4 Exploration and Production Norway
Discovering new resources is a top priority. In 2007, we completed 24 exploration wells, of which 16 were discoveries. In addition, we completed two exploration extensions, of which both resulted in discoveries. Total exploration expenses were NOK 3.6 billion in 2007, compared with NOK 3.5 billion in 2006.
Six exploration wells have been completed so far in 2008. Four of these are discoveries: Gamma, Marulk, M-structure and Obesum. In addition one exploration extension is completed, Fram C-Øst, which was a discovery. We are focused on increased oil and gas recovery, and we invest in order to increase recovery rates for our fields. The continued drilling of new production wells is of major importance in countering the natural decline in production from mature fields on the NCS. In 2007, we drilled 66 new production wells and we plan to drill approximately 80 wells in 2008. Our production of oil and gas on the NCS averaged 1.417 mmboe per day in 2007, compared to 1.474 mmboe per day in 2006. Our total production was negatively affected by incidents that caused interruptions to production on the NCS and lower gas off-take in Europe than expected, which was partly offset by new projects coming on stream. In total, eight projects came on stream on the NCS in 2007, four on new fields and four reconfiguration/increased oil recovery projects. These projects make a substantial contribution to our production and transport capacity. Both Ormen Lange and Snøhvit came on stream in October and production also commenced from the Statfjord Late Life project, Tordis subsea processing, Skinfaks/Rimfaks IOR, Huldra Tail-end and Njord gas export. In addition, nine new projects were sanctioned in 2007. Volve started producing in February 2008. The total capital expenditure of NOK 31.1 billion in 2007 was higher than in previous years, as a result of many projects under development. Restructuring costs and other costs relating to the merger amounting to NOK 5.5 billion were charged to income in 2007. 4.1.4.1 Profit and loss analysis
We generated total revenues of NOK 179.2 billion both in 2007 and 2006.
An increase of 11% in the average oil price in USD of oil sold by E&P Norway to Manufacturing and Marketing contributed NOK 13.3 billion, and a 2% increase in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas, contributed NOK 1.1 billion. This was offset by a negative currency exchange rate deviation of NOK 12.0 billion due to a 9% decrease in the USDNOK exchange rate. Lifted volumes of crude oil decreased by 3%, making a negative contribution of NOK 3.8 billion, and there was a 2% decrease in lifted volumes of natural gas, making a negative contribution of NOK 0.9 billion. In addition, other income increased by NOK 2.4 billion, mainly as a result of higher income from derivatives and higher processing income. The average daily lifting of oil in 2007 was 831 mbbl per day, compared to 856 mbbl per day in 2006. Average daily entitlement oil production in 2007 was 818 mbbl per day, compared to 864 mbbl per day in 2006. The reduced production was largely caused by the shut down of production on the Kvitebjørn field from 1 May 2007 in order to enable safe drilling operations, as well as to a natural decline on the Oseberg field. Kvitebjørn started up again on 16 January 2008, and it is currently producing at full capacity, although it is expected to be shut down again for approximately three months from late June 2008 to allow for repair work on the damaged gas export pipeline. The reduction in production was partly offset by increased production from the Kristin field, which has now reached plateau level. The average daily entitlement gas production was 599 mboe in 2007 (equal to 95.2 mmcm or 3.36 mmcf), compared to 610 mboe in 2006 (equal to 97.0 mmcm or 3.42 mmcf). The unit production cost was USD 8.09 per boe in 2007 and USD 4.21 per boe in 2006. The unit of production cost measured in NOK was NOK 46.26 per boe in 2007 and NOK 26.93 per boe in 2006. The production cost mainly consists of operating plant costs. The 60% increase from 2006 to 2007 is due to both an increase in costs of 65% and a decrease in production of 4%. Indirect operating costs increased by NOK 5.5 billion due to restructuring costs as a result of the merger in 2007. Operating plant costs increased by NOK 3.2 billion, due to both higher activity and increased pressure on costs in the industry. Operating, general and administrative expenses were NOK 29.4 billion in 2007 and NOK 19.6 billion in 2006. Operating costs amounted to NOK 29.1 billion in 2007 and NOK 19.2 billion in 2006. The general and administrative cost elements in 2007 and 2006 largely consisted of research and development costs. The increase of NOK 9.8 billion in operating, general and administrative expenses from 2006 to 2007 was mainly due to an increase in other expenses of NOK 6.3 billion, mainly due to restructuring costs as a result of the merger in 2007 and an increase of NOK 3.2 billion in operating plant costs, which was largely due to an increase in well maintenance costs of NOK 0.9 billion, higher operation and maintenance costs of NOK 0.8 billion, higher production fees, mainly due to the introduction of nitrogen oxide charges of NOK 0.4 billion in 2007, Grane Gas purchases totalling NOK 0.3 billion, higher business development costs of NOK 0.3 billion and higher head office research and development costs of NOK 0.2 billion. In addition, processing costs increased by NOK 0.4 billion from 2006 to 2007. Depreciation, depletion and amortisation expenses were NOK 23.0 billion in 2007 and NOK 20.9 billion in 2006. The NOK 2.1 billion increase from 2006 to 2007 was mainly due to higher depreciation costs as a result of asset retirement costs and higher depreciation offshore due to changes in the portfolio of producing fields. Exploration expenditure (including capitalised exploration expenditure) in 2007 amounted to NOK 5.7 billion, compared to NOK 4.6 billion in 2006. The increase in exploration expenditure from 2006 to 2007 was mainly due to increased drilling and seismic activity, as well as to a significant increase in the area fee. Drilling expenditure increased by approximately NOK 0.4 billion, while the increase in seismic activity amounted to NOK 0.3 billion. The increase in area fee was due to new regulations on the NCS and it contributed approximately NOK 0.4 billion to the increased costs. Exploration expenses in 2007 were NOK 3.6 billion, compared to NOK 3.5 billion in 2006. In 2007, 24 exploration and appraisal wells and two exploration extension wells were completed. Of these, 16 exploration and appraisal wells and both exploration extension wells resulted in discoveries. In 2006, 18 exploration and appraisal wells and five exploration extension wells were completed, of which eight appraisal and exploration wells and two exploration extension wells were discoveries. Drilling of five exploration and two exploration extension wells was ongoing at year end 2007. The reconciliation of exploration expenditure with exploration expenses is shown in the table below.
Net operating income in 2007 was NOK 123.2 billion, compared to NOK 135.1 billion in 2006. The NOK 11.9 billion decrease in 2007 was mainly due to price and volume effects, NOK 5.5 billion in restructuring and other costs arising from the merger, higher operating costs of NOK 3.2 billion, mainly due to higher operation and maintenance costs and well maintenance, increased depreciation, mainly due to higher asset retirement costs, which contributed NOK 2.1 billion to the decrease, an increase in other operating expenses of NOK 1.0 billion and processing and transportation costs increasing by NOK 0.4 billion in 2007. 4.1.4.2 Outlook
We expect to continue our high exploration activity in 2008 and we plan to drill approximately 35 exploration wells on the NCS. A significant part of the drilling activity is expected to take place in mature areas close to existing infrastructure. We also plan to drill several wells in frontier areas of the Norwegian Sea and in the Barents Sea. We have secured rig capacity for our drilling activity level in 2008. Measures have been initiated to further improve both regularity on our installations and our drilling efficiency. The full effect of these improvement programmes is not expected to be realised in 2008, but will be essential if we are to reach our production ambition in 2012. There are uncertainties regarding production on Snøhvit. The LNG plant has suffered from operational challenges and there are still uncertainties related to the timing of regular and stable operations. Gas exports from Kvitebjørn and Visund will be halted during the repair of the Kvitebjørn gas pipeline in mid-2008. 4.1.5 International Exploration and Production
The strategy of International Exploration & Production (INT) is to access new resources through world-class exploration and focused business development and to move resources effectively into production through our proven project execution and operational experience from the NCS. International exploration activities were at a record level in 2007. During the year, we drilled 58 wells, 47 of which were completed. Eighteen wells have been announced as discoveries at year end. Several wells are still under evaluation. The total exploration expenses were NOK 7.7 billion in 2007, compared with NOK 7.2 billion in 2006. Acquisitions in 2007 included the purchase of 100% of the shares in North American Oil Sands Corporation and the acquisition of the UK heavy oil fields Mariner, Mariner East and Bressay. Our interests in these fields are 44.44%, 62% and 81.63%, respectively. In addition, a separate agreement has been concluded with the Canadian companies Silverstone and Wilderness for an acquisition of 30% interest in the Broch discovery in block 9/16. We signed a framework agreement with Gazprom to become a partner in the Shtokman development phase 1, giving us a 24% equity interest in Shtokman Development Company. In 2007, we divested ourselves of small mature producing assets in the shelf of the US Gulf of Mexico and in the UK. In 2007, our international entitlement production increased significantly to 307 mboe per day from 234 mboe per day in 2006. The average daily equity production of oil and gas was 422 mboe per day in 2007, compared to 304 mboe in 2006. The difference between entitlement and equity volumes is the result of deductions for among other things, royalty and the host government's share of profit oil under the terms of most PSA regimes. The total capital expenditure of NOK 36.2 billion in 2007 was higher than in previous years, triggered by many projects under development in addition to the acquisition of new assets to secure longer term growth, such as NAOSC in Canada and the UK heavy oil fields. Restructuring costs and other costs relating to the merger totalling NOK 1.3 billion were charged to income in 2007. 4.1.5.1 Profit and loss analysis
We generated total revenues of NOK 41.6 billion in 2007, compared to NOK 32.6 billion in 2006. The increase was mainly related to a 32% increase in lifted volumes, which contributed NOK 9.8 billion, and a 4% increase in realised oil prices in NOK, which contributed NOK 1.3 billion, partly offset by a 29% decrease in the realised gas price measured in NOK, which contributed negatively in the amount of NOK 1.5 billion.
The average daily oil lifting was 250 mbbl in 2007, compared with 191 mbbl in 2006. The average daily entitlement production of oil was 252 mbbl in 2007, compared with 194 mbbl in 2006. The 30% increase in average daily oil production from 2006 to 2007 was mainly related to the ramp up of production from Dalia, the West and East Azeri part of the ACG field and In Amenas, which started production in the fourth quarter of 2006, the start-up of new fields, such as Rosa and Marimba, which came on stream in the second and third quarters of 2007, respectively, as well as increased production from Terra Nova, which was shut down for most of 2006. This was partly offset by lower entitlement production under the PSAs in Angola. The average daily entitlement production of was 55 mboe in 2007 (equivalent to 9.35 mmcm or 330 mmcf), compared to 40 mboe in 2006 (equivalent to 6.80 mmcm or 240 mmcf). The 37% increase in daily gas production was mainly related to the start-up of new fields, such as Shah Deniz in the first quarter 2007 and the Eastern Gulf fields in the US GoM (Q, San Jacinto and Spiderman) in the third and fourth quarter 2007. The average daily equity oil and gas production was 422 mboe per day in 2007, compared with 304 mboe in 2006. The unit of production cost based on entitlement volumes was USD 5.87 per boe in 2007 and USD 5.84 per boe in 2006. Measured in NOK, it was 34.41 per boe in 2007 and 37.50 per boe in 2006. The 8% decrease in unit of production cost measured in NOK from 2006 to 2007 was mainly due to a decrease in the USDNOK exchange rate. The unit of production cost based on equity volumes was USD 4.27 per boe in 2007 and USD 4.50 per boe in 2006. Measured in NOK it was 25.04 per boe in 2007 and 28.87 per boe in 2006. See report section Reported Volumes for a description of entitlement and equity volumes. Operating, general and administrative expenses. Due to increased royalty and extraction tax in Venezuela and Canada, increased transport costs, new fields in production, increased costs related to the acquisition of NAOSC, pension and general operating costs, total operating, general and administrative expenses increased by NOK 3.5 billion from 2006 to 2007, of which restructuring costs and other costs arising from the merger amounted to NOK 1.3 billion. Depreciation, depletion and amortisation expenses were NOK 11.1 billion in 2007, compared with NOK 14.4 billion in 2006. The 23% decrease in 2007 compared to 2006 was mainly due to the NOK 4.9 billion impairment write-down effect on depletion, depreciation and amortisation accounts of US GoM shelf fields and Front Runner in our US portfolio in 2006. This decrease was partly offset by impairment write-downs of NOK 1.2 billion for Lufeng, Front Runner, Thunder Hawk and US GoM shelf fields in 2007. A change in the proved reserves estimates in 2007, which forms the basis for the unit of production depreciation, and increased depreciation from new assets coming on stream also contributed to the increase. Exploration expenditure was NOK 8.5 billion in 2007, compared with NOK 9.5 billion in 2006. The decrease was mainly due to higher drilling activity in 2006. Exploration expenses were NOK 7.7 billion in 2007, compared with NOK 7.2 billion in 2006. Increased exploration expenses were mainly related to higher expensing of exploration costs capitalised in previous years, partly offset by a decrease in exploration expenditure related to slightly lower drilling activity in 2007 than in 2006. In total, 47 exploration and appraisal wells were completed in 2007 and, at year end, 18 were considered to be discoveries or confirmed discoveries. At year end, fourteen wells were pending final evaluation. In 2006, 55 exploration and appraisal wells were completed, 24 of which were considered discoveries. Net operating income in 2007 was NOK 12.2 billion compared to NOK 3.9 billion in 2006. In addition to the price and volume effects, the increase was mainly related to a NOK 3.3 billion decrease in depreciation, amortisation and impairment expenses, which was offset by a NOK 3.5 billion increase in operating, general and administrative expenses of which restructuring and other costs arising from the merger amounted to NOK 1.3 billion, and a NOK 0.5 billion increase in exploration expenses. 4.1.5.2 Outlook
Seventy-five per cent of the new fields contributing to our 2012 production are sanctioned. The Mondo field came on stream in January 2008. Other fields planned for start-up in 2008 include Saxi Batuque and Gimboa in Angola, Agbami in Nigeria and ACG phase III in Azerbaijan. We plan to continue to pursue high exploration activity combined with targeted business development consistent with our strategy in order to further expand our resource base. We expect to continue to develop resources effectively into production through our proven project execution and operational experience from the NCS. Approximately 35 exploration and appraisal wells are expected to be drilled in 2008. Rig capacity has been secured for our drilling activity level in 2008, and we believe we are well positioned for exploration drilling beyond 2008 based on our current drilling programme and rig commitments. 4.1.6 Natural Gas
We are currently the second largest supplier of natural gas to Europe, with a market share of approximately 15% in Europe, including the volumes from the State's Direct Financial Interest. Gas exports from the NCS were again at a high level in 2007 and the level of NCS gas exports is expected to grow. In 2007, StatoilHydro sold 35.6 bcm entitlement gas. In addition we sold 31.2 bcm NCS gas on behalf of the SDFI. Most of the gas was sold to Continental energy providers under long-term contracts. Our market share in 2007 was approximately 20-25% in Germany and France and approximately 15% in the UK. In 2007, the first gas was delivered from the Shah Deniz field in Azerbaijan to Turkey, where the bulk of the gas is sold. At plateau level, Shah Deniz stage 1 is expected to produce around 8.6 bcm gas annually. A potential stage 2 of the Shah Deniz field is under development. Important strategic milestones for us in 2007 included the opening of the Tampen Link pipeline, the start-up of the Ormen Lange field and the first LNG shipment from Snøhvit. Two significant factors strongly influenced our financial results: the external sales price and the internal transfer price. In 2007, natural gas prices fell compared with the high level in 2006. Our average natural gas price for European piped gas was NOK1.69/cubic metre in 2007.
All of the gas from the NCS sold by the Natural Gas business area is purchased from Exploration & Production Norway. The internal transfer price formula is linked to the oil price for Brent Blend. High oil prices throughout 2007 have led to relatively high internal gas prices. In combination with the relatively low external sales prices for gas, our margins decreased significantly in 2007. In addition, losses on the fair value of derivatives also affected our results in 2007. The total capital expenditure of NOK 2.1 billion in 2007 was lower than in previous years, due to fewer projects being under development. In addition, three LNG vessels and associated LNG companies were transferred from Exploration & Production Norway to Natural Gas in 2007, amounting to NOK 2.4 billion. Restructuring costs and other costs relating to the merger totalling NOK 1.3 billion were charged to income in 2007. 4.1.6.1 Profit and loss analysis
The total revenues in the Natural Gas business mainly come from gas sales under long-term gas sales contracts and tariff revenues from transportation and processing facilities. Natural Gas generated revenues of NOK 73.4 billion in 2007, compared with NOK 97.1 billion in 2006. The 24% decrease from 2006 to 2007 was mainly due to declining natural gas prices measured in NOK in 2007 and negative changes in the fair value of derivatives.
The total natural gas sales were 42.0 bcm (1.48 tcf) in 2007 and 40.2 bcm (1.42 tcf) in 2006. The 4% increase from 2006 to 2007 in gas volumes sold was mainly due to increased third-party gas sales, but this was partly offset by a net decrease in StatoilHydro entitlement sales volumes. The decrease in entitlement sales volumes mainly relates to production problems on Kvitebjørn throughout 2007, and it was partly offset by the start-up of Ormen Lange in October 2007. Of the total natural gas sales in 2007, we sold 35.6 bcm (1.26 tcf) of entitlement gas, which included 0.8 bcm (0.03 tcf) of gas from Shah Deniz in Azerbaijan. The average gas price for our European gas sales was NOK 1.69 per scm in 2007, compared to NOK 1.94 per scm in 2006, a decrease of 13%. The decrease in price from 2006 to 2007 was mainly due to a decrease in prices for oil products (such as gas oil and fuel oil) and other competing energy sources, as well as lower gas prices on the National Balancing Point (NBP) in the UK. The sales of natural gas from In Salah are reported by the International Exploration & Production business area. Cost of goods sold decreased by 8% from 2006 to 2007, from NOK 61.3 billion to NOK 56.7 billion. The decrease in cost of goods sold mainly relates to a decrease in the third party purchase price of natural gas. This was partly offset by a slight increase in the transfer price paid to E&P Norway and an increase in third party purchase volumes from 2006 to 2007. Operating, selling and administrative expenses increased by 6% from 2006 to 2007. This was mainly related to early retirement cost accruals and increased accruals for removal costs. Net operating income for 2007 was NOK 1.6 billion, compared with NOK 21.7 billion in 2006. The decrease of NOK 20.1 billion was mainly due to a 13% decrease in prices for piped natural gas, which reduced income by NOK 9.5 billion, and negative changes amounting to NOK 10.3 billion in the fair value of derivatives. 4.1.6.2 Outlook
We believe there is sufficient supply in Europe, Asia and North America to meet demand expectations in the short term. In the longer term, however, the market balance is more uncertain and will depend on a number of factors, such as how demand responds to gas and energy prices, the development of LNG projects and potential new Russian supplies coming on stream. We believe that the future gas prices will provide efficient signals both to users of gas and owners of potential gas projects. Higher costs in the industry also suggest that sales prices may increase over time, thus ensuring sufficient supplies. The short term gas market is affected by new capacity and new fields coming on stream. We have also seen that LNG in the Atlantic basin is responding to changes in prices between major markets, taking advantage of arbitrage opportunities. The UK gas market has become more liquid and is able to absorb volumes from Ormen Lange without severe impacts on prices. Our view on these events is that we have value creation potential through increased gas exports due to the proximity of our infrastructure to favourable markets. In the long term, we continue to have a positive view of gas as an energy source for Europe. Indigenous production of gas in the EU is expected to decline, while demand for gas is expected to increase, particularly due to the lower carbon footprint of natural gas compared with oil and coal. The trend for LNG as a link between continental markets is expected to continue as more LNG will come on stream, making gas a commodity that is priced more on a global basis in the long term. In 2008, we plan to continue to seek added value through balancing, trading and optimisation, maximising the value of our gas sales portfolio and developing the next generation gas business. Key activities are expected to include planning with a view to utilising the expansion capacity at Cove Point, further preparation for a Shah Deniz stage 2 and focusing on maintaining a low cost level. Mitigation activities to meet our contractual obligations continue in 2008. The upgrading of the Kårstø gas plant and the expected start-up of the Aldbrough storage facility are both projects of great importance to us in 2008. Aldbrough is expected to start commercial operations in late 2008. The storage facility will provide us with a new tool for trading and optimisation activities. 4.1.7 Manufacturing and Marketing
In 2007, we continued to focus on streamlining the portfolio through investments and divestments, standardisation and simplification throughout the business area in order to create more value as well as an efficient and value chain-focused organisation. The total capital expenditure of NOK 4.8 billion in 2007 was higher than in previous years, triggered by high activity in projects and modifications at our refineries. Restructuring costs and other costs relating to the merger totalling NOK 1.2 billion were charged to income in 2007. Even though the NCS production of crude oil is decreasing, we are still continuing to strengthen our global trading positions and have increased our flexibility by trading in third party volumes. The average daily third party crude volume sold in 2007 of 524 mbbl was an increase of approximately 25% from 2006. Manufacturing Mongstad continued to have good regularity (97.8%) in 2007, but Tjeldbergodden had a planned but extended turnaround and a 30-day shutdown due to an interruption in gas deliveries during July and August. Kalundborg also had a planned but extended turnaround in parts of the refinery that lasted for 62 days. The Kalundborg plant came on stream again in June. Energy and retail We have maintained our leading energy and retail positions, and have the leading or second largest share in most of the markets in which we operate. In 2007, we sold our energy and retail business on the Faeroe Islands and entered into a purchase agreement with ConocoPhillips for the Scandinavian JET retail network of 271 unmanned service stations. The purchase is subject to approval by the EU Commission. We also strengthened our position as the leading supplier of biofuels in 2007. Biofuels are now available at more than 1,300 service stations in seven different countries. 4.1.7.1 Profit and loss analysis
Total revenues and other income increased from NOK 412 billion in 2006 to NOK 428 billion in 2007. The increase from 2006 to 2007 was mainly due to higher prices and volumes for crude and gas oil products. The average oil price increased by 12% from USD 63.2/bbl in 2006 to USD 70.50/bbl in 2007, which was partly offset by the weakening of the average USD exchange rate by almost 9% from USDNOK 6.42 in 2006 to USDNOK 5.86 in 2007.
Cost of goods sold increased from NOK 383 billion in 2006 to NOK 402 billion in 2007. This was primarily due to increased crude oil prices and volumes purchased. Operating, selling and administrative expenses increased by 3% in 2007 compared with 2006, mainly due to provisions for pension liabilities of NOK 0.7 billion largely related to early retirement. The whole amount is included in the restructuring costs relating to the merger and charged to income. Depreciation, amortisation and impairment totalled NOK 2.8 billion in 2007, compared with NOK 2.3 billion in 2006. The increase was mainly due to an increase in impairment loss in Energy & Retail Sweden, from NOK 0.2 billion in 2006 to NOK 0.95 billion in 2007, NOK 0.5 billion of which is included in restructuring costs relating to the merger and charged to income. In 2007, net operating income was NOK 3.8 billion, compared with NOK 7.3 billion in 2006. The difference was mainly due to increased early retirement pension costs of NOK 0.7 billion, negative currency effects of NOK 0.7 billion, a decrease in trading results of NOK 0.6 billion, a gain of NOK 0.6 billion in 2006 on the sale of our retail business in Ireland, and impairment loss and provisions of NOK 0.5 billion due to weak market conditions and restructuring of the retail business in Sweden. Oil Sales, trading and supply In 2007, net operating income was NOK 1.3 billion, compared with NOK 2.2 billion in 2006. The decrease in 2007 was mainly due to NOK 0.7 billion in currency losses, lower trading results of NOK 0.6 billion compared with 2006 and a deferred gain on inventories, which was partly offset by gains on operational storage. Manufacturing In 2007, net operating income was NOK 3.3 billion, compared with NOK 4.4 billion in 2006. The decrease in 2007 was mainly due to lower regularity and higher operating costs due to turnaround activities. The lower USDNOK exchange rate and lower capacity utilisation also contributed negatively. Margins were good at Mongstad, but they were lower than expected at Kalundborg due to high crude differentials and the delay in the fuel reduction project. The average contract price for methanol increased by 6% from EUR 300/tonne in 2006 to EUR 317/tonne in 2007. Energy and retail Net operating income was NOK 0 billion in 2007, compared with NOK 0.6 billion in 2006. We experienced increased revenues during 2007, mainly due to an increase of 8% in transport fuel volumes at our outlets, from 7.7 billion to 8.3 billion litres, together with an increase in margins. During the same period, margins on convenience products rose by 15%. The decrease in total net income was mainly due to increased impairment loss and provisions of NOK 0.6 billion in 2006 and NOK 1.1 billion in 2007, due to weak market conditions and restructuring of our retail business in Sweden. There was also a net gain of NOK 0.6 billion in 2006 related to the sale of our retail business in Ireland. 4.1.7.2 Outlook
Oil sales, trading and supply The year 2007 was one of the most volatile periods in the product, gas liquids and crude oil markets. High prices were experienced during the year and we believe that prices will remain high and volatile at least in the near term. Manufacturing The outlook for the refinery industry continues to be good and high utilisation is expected. Significant new refining capacity, however, is expected to come on stream over the next few years. Combined with lower global economic growth, this new capacity is expected to have a negative impact on margins in the industry. However, profitability will very much depend on our ability to utilise the available feedstock and deliver the optimal product qualities. The average crude oil is getting heavier and more sour, while product specifications have become more stringent. Both factors require additional processing flexibility and capacity. Fuel oil conversion is expected to increase, and bio-components are expected to increase their market share. After heavy cost-cutting in the 1990s, recent high margins have increased the focus on reliability and utilisation. Combined with high pressure in the labour and contractor markets, the cost trend has changed, and maintenance and upgrading is expected to require continued management attention. The high energy costs could also make new energy efficiency initiatives more attractive. Methanol prices are expected to return to a moderate level as new capacity in stranded gas areas becomes available. Europe is expected to continue to be a net importer of methanol, and European producers will therefore have a geographical advantage. Energy and retail The main growth in Energy and retail is expected to come from transport fuel, largely due to growth in diesel, and convenience, with a new indoor food range concept and lean operation. Subject to EU Commission approval, the acquisition of Jet in Scandinavia will allow us to strengthen our Scandinavian retail position. We have entered the St. Petersburg market in Russia, reinforcing our long-term ambition of sales growth in Eastern Europe. We already have a strong foothold in the Baltic countries and are expanding in Poland. We believe that use of heavy oil products in the stationary carries sector will gradually be replaced by either gas carriers (LNG and LPG), or other non-fossil energy carriers. 4.1.8 Eliminations and other operations
The years ended 31 December 2007 and 2006 Other operations consist of the activities of Corporate Services, Corporate Centre, Group Finance and the two corporate technical service providers, Technology and New Energy and Projects. In connection with our other operations, we recorded a loss before financial items, income taxes and minority interest of NOK 3.4 billion in 2007, compared with a loss of NOK 1.9 billion in 2006. The increase is primarily due to provisions made related to early retirement and pension benefits. 4.1.9 Reported volumes
In explaining revenues and changes in revenues, we report on . This is because we can only recognise income from volumes to which we have legal title, and such title typically arises upon lifting (that is, loading onto a vessel) of the volumes. Under PSA contracts, we are only entitled to receive and sell certain volumes as a percentage of volumes produced, and we therefore refer to entitlement volumes for revenue recognition purposes. The difference between equity and entitlement volumes is described in more detail below. Volumes of lifted oil and natural gas correlate over time with production, but they may be higher or lower than production for the period due to operational factors that affect the timing of when StatoilHydro-chartered vessels lift the oil from the fields. Volumes of natural gas produced on the NCS are deemed to be equal to lifted volumes of natural gas from the NCS. In explaining operating expenses, in total and production cost per barrel of oil equivalents, is a better indicator of activity levels than lifted volumes. Moreover, we believe equity volumes are a better indicator of the activity level under PSA contracts than entitlement volumes since our capital expenditure and operating expenses under such contracts are linked to equity production rather than entitlement volumes received. Equity volumes represent produced volumes under a PSA contract that correspond to StatoilHydro's percentage ownership in a particular field. Entitlement volumes, on the other hand, represent StatoilHydro's share of the volumes distributed to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes, whereas it is not applicable in most concessionary regimes, such as those in Norway, the UK, Canada and Brazil. Proved reserves are entitlement volumes recognised as reserves pursuant to SEC guidelines. They represent volumes that with reasonable certainty will be produced and to which we will have entitlement in the future. See the supplementary information in the financial statements on oil and gas producing activities for details about how we measure and report proven reserves. 4.2 Liquidity and capital resources
Based on IFRS. For the purpose of these ratios, earnings consist of the income before (i) tax, (ii) minority interest, (iii) amortisation of capitalised interest and (iv) fixed charges (which have been adjusted for capitalized interest) and after adjustment for unremitted earnings from equity accounted entities. Fixed charges consist of interest (including capitalised interest) and estimated interest within operating leases.
Cash flows from operating activities
Our primary source of cash flow consists of funds generated from operations. Net funds generated from operations for 2007 were NOK 93.9 billion, compared to NOK 88.6 billion in 2006. The increase of NOK 5.3 billion in cash flows from operating activities from 2006 to 2007 was mainly due to changes of NOK 12.4 billion in working capital, a decrease of NOK 8.6 billion in non-current items related to operating activities and a decrease of NOK 5.8 billion in taxes paid. These increases were partly offset by a decrease of NOK 21.5 billion in cash flows from underlying operations. Cash flows used in investing activities Net cash flows used in investing activities amounted to NOK 75.1 billion in 2007, compared with NOK 57.2 billion in 2006. Gross investments,defined as additions to property, plant and equipment (including intangible assets and long term share investments) and capitalised exploration expenditure, amounted to NOK 75.0 billion in 2007, compared to NOK 64.3 billion in 2006. Gross investments in 2007 were NOK 31.1 billion, NOK 36.2 billion, NOK 2.1 billion and NOK 4.8 billion in Exploration & Production Norway, International Exploration & Production, Natural Gas and Manufacturing & Marketing, respectively.
The difference between cash flows used in investing activities and gross investments in 2007 was mainly related to the effects of changes in long-term loans granted and other long-term items offset by proceeds from the sale of assets. In addition to the investments included in the table above, NOK 2.4 billion in LNG-related assets has been transferred from E&P Norway to the Natural Gas business area.
Cash flows used in financing activities Net cash flows used in financing activities in 2007 amounted to NOK 7.9 billion, compared to NOK 31.4 billion in 2006. The decrease in cash flows used in financing activities from 2006 to 2007 was mainly related to the settlement of the demerger balance with Norsk Hydro ASA on 1 October 2007, which was partly offset by increased dividends paid in 2007 compared to 2006.
New long-term borrowings at 31 December 2007 were NOK 1.7 billion, compared to NOK 0.1 billion at 31 December 2006. The repayment of long-term debt at 31 December 2007 was NOK 2.9 billion compared with NOK 2.3 billion at 31 December 2006 Cash flows used in financing activities in 2007 included a dividend of NOK 25.7 billion paid by Statoil ASA to shareholders related to the annual accounts for 2006, while the dividend paid by Statoil ASA to its shareholders in 2006 relating to the annual accounts for 2005 was NOK 17.8 billion. Current items Current items (total current assets minus total current liabilities) were NOK 25.5 billion at 31 December 2007, compared to NOK 43.8 billion at 31 December 2006. The decrease in net non-current financial liabilities from 2006 to 2007 was mainly related to an increase of NOK 13.1 billion in liquid assets, in combination with a decrease of NOK 4.8 billion in gross non-current financial liabilities due to the weakening of the USD in relation to NOK during 2007. We believe that, taking into consideration StatoilHydro's established liquidity reserves (including committed credit facilities), credit rating and access to capital markets, we have sufficient liquidity and working capital to meet our present and future requirements. Our sources of liquidity are described below. Liquidity Our cash flow from operations is highly dependent on oil and gas prices and our levels of production, and it is only influenced to a small degree by seasonality and maintenance turnarounds. Fluctuations in oil and gas prices, which are outside our control, will cause changes in our cash flows. We will use available liquidity to finance Norwegian petroleum tax payments (due on 1 April 1 and 1 October each year), any dividend payment and investments. Our investment programme is spread over the year. There may be a gap between funds from operations and funds required to fund investments, which will be financed by short and long-term borrowings. We intend to keep ratios relating to net debt at levels consistent with our objective of maintaining our long-term credit rating at least within the single A category. Our long-term and short-term ratings from Moody's are Aa2 and P-1, respectively. Our long-term rating from Standard & Poor's was raised to AA- in August 2007, reflecting the majority ownership by the Norwegian State. Standard & Poor's short-term rating of StatoilHydro is A-1+. The current rating outlook is stable from both agencies. As of 31 December 2007, we had liquid assets of NOK 21.6 billion, including NOK 18.3 billion in cash and cash equivalents and NOK 3.4 billion of current financial investments (domestic and international capital market investments). Approximately 54% of our liquid assets were held in EUR-denominated assets, 26% in NOK and 20% in USD, before the effect of currency swaps and forward contracts. As of 31 December 2006, we had liquid assets of NOK 8.6 billion, including NOK 7.5 billion in cash and cash equivalents and NOK 1.1 billion of current financial investments (domestic and international capital market investments). Approximately 20% of our liquid assets were held in NOK-denominated assets, 67% in USD and 13% in other currencies, before the effect of currency swaps and forward contracts. Compared to year end 2006, current financial investments increased by NOK 2.3 billion during 2007, and cash and cash equivalents increased by NOK 10.8 billion. The increase in liquid assets during 2007 was mainly due to a higher oil price, but it was somewhat offset by the weakening of the USD in relation to NOK during 2007. Our general policy is to maintain a liquidity reserve in the form of cash and cash equivalents in our balance sheet, and committed, unused credit facilities and credit lines in order to ensure that we have sufficient financial resources to meet our short-term requirements. Long-term funding is raised when we identify a need for such financing based on our business activities and cash flows, as well as when market conditions are considered favourable. As of 31 December 2007, the group had USD 2.0 billion available in a committed revolving credit facility from international banks, including a USD 500 million swing-line facility. The facility was entered into by us in 2004, and, after exercising of an extension option in 2006, it is available for drawdowns until December 2011. At year end 2007, no amounts had been drawn under the facility. In April 2007, we drew down a line of credit established in our favour on a bilateral basis by an international financial institution. The loan was denominated in USD and has a final maturity of five years. Non-current financial liabilities Gross non-current financial liabilities were NOK 50.5 billion at year end 2007, compared with NOK 54.8 billion at the end of 2006. The decrease was mainly due to the weakening of the USD in relation to NOK in 2007 and the repayment of long-term borrowings in 2007. For risk management purposes, currency swaps are used to ensure that StatoilHydro keeps long-term interest-bearing debt in USD. As a result, most of the group's non-current financial liabilities are exposed to changes in the USDNOK exchange rate. Net non-current financial liabilities amounted to NOK 25.5 billion at 31 December 2007, compared with NOK 43.8 billion at 31 December 2006. The decrease was mainly due to an increase of NOK 13.1 billion in liquid assets and a decrease NOK 4.8 billion in gross non-current liabilities, mainly due to the weakening of the USD in relation to NOK in 2007. For a reconciliation of net non-current financial investments with gross non-current financial liabilities, see report section Use and Reconciliation of Non-GAAP Financial Measures - Net debt to capital employed ratio for more information. The net debt to capital employed ratio, defined as net interest-bearing debt in relation to capital employed, was 12.4% as of 31 December 2007, compared with 20.5% as of 31 December 2006. The decrease in the net debt to capital employed ratio in 2007 was mainly related to a decrease in net debt and an increase in shareholders' equity. Our method of calculating the net debt to capital employed ratio includes certain adjustments, and it may therefore be considered to be a non-GAAP financial measure. The net debt to capital employed ratio without adjustments was 13.9% in 2007, compared with 21.4% in 2006. See report section Use and Reconciliation of Non-GAAP Financial Measures - Net debt to capital employed ratio for more information. The group's borrowing needs are mainly covered through the issuing of short-term and long-term securities, including utilisation of a US Commercial Paper Programme and a Euro Medium Term Note (EMTN) Programme (the limits of the programme being USD 2 billion and USD 3 billion, respectively), and through draw-downs under committed credit facilities and credit lines. Apart from the credit line drawn down in April 2007 described above, no material long-term borrowing took place in 2007. After the effect of currency swaps, 100% of our borrowings are in US dollars. Our financial policies take into consideration funding sources, the maturity profile of long-term debt, interest rate risk management, currency risk and management of liquid assets. Our borrowings are denominated in various currencies and swapped into USD, since the largest proportion of our net cash flow is denominated in USD. In addition, we use interest rate derivatives, primarily consisting of interest rate swaps, to manage the interest rate risk of our long-term debt portfolio. New long-term borrowings totalled NOK 1.7 billion in 2007 and NOK 0.1 billion in 2006. We repaid approximately NOK 2.9 billion in 2007and NOK 1.4 billion in 2006. The company's central finance function manages the funding, liability and liquidity activities at group level based on our adopted financial policies. 4.2.1 Table of principal contractual obligations and other commitments
The following table summarises our principal contractual obligations and other commercial commitments as of 31 December 2007. The following table includes contractual obligations, but excludes derivatives and other hedging instruments as well as asset retirement obligations, which for the most part are expected to lead to cash disbursements more than five years into the future. Obligations payable by StatoilHydro to unconsolidated equity affiliates are included gross in the table. Where StatoilHydro includes both an ownership interest and the transport capacity cost for a pipeline in the consolidated accounts, the amounts in the table include the transport commitments that exceed Statoil's ownership share. See also report section Risk review - Market risk - Quantitative and Qualitative Disclosures about Market Risk for more information.
Non-current debt in the above table represents principal payment obligations. For information on interest commitments relating to long-term debt, reference is made to Note 20 - Financial liabilities and Note 24 - Leases to our Consolidated Financial Statements included this report. Contractual obligations in respect of capital expenditures, acquisitions of intangible assets and construction in progress amounted to NOK 27.8 billion as of 31 December 2007, of which payments of NOK 13.2 billion are due within one year. The group's projected pension benefit obligation was NOK 52.8 billion and the fair value of plan assets amounted to NOK 35.2 billion as of 31 December 2007. Unrecognised actuarial gains and losses and unrecognised prior service cost amounted to NOK 0.4 billion as of 31 December 2007 and are reported as part of the Statement of Recognised Income and Expense (SORIE) (equity). Company contributions are mainly related to employees in Norway. This payment may either be paid in cash or be deducted from the pension premium fund. On 31 December 2007, the pension premium fund amounts to NOK 7.3 billion. The decision whether to pay in cash or deduct from the pension premium fund is made on an annual basis. The company contribution in 2007 was NOK 3.4 billion (exclusive of payroll tax), of which NOK 1.4 billion was a voluntary payment to the premium fund. The expected company contribution for 2008 is NOK 2.2 billion. 4.2.2 Investments
Our investments have increased due to more complex and challenging projects, expensive inorganic growth and cost increases due to a tight supplier market. Capital expenditure Our capital expenditure in our four principal business segments in 2006 and 2007 is described below, including the allocation per segment as a percentage of gross investments.
Capital expenditure is expected to amount to approximately NOK 75 billion in 2008 and NOK 80 billion in 2009. We experienced a step-up in exploration activities in both 2006 and 2007. Exploration expenditure in 2007 amounted to NOK 14.2 billion, compared to NOK 13.4 billion in 2006. Exploration expenditure is expected to further increase to approximately NOK 18 billion in 2008. The group expects to participate in the drilling of approximately 70 wells in 2008. However, no guarantees can be given with regard to the number of wells drilled, the cost per well and the results of drilling. Uncertainty related to the results of past and future drilling will influence the amount of exploration expenditure capitalised and expensed. See report section Critical accounting judgements and key sources of estimation uncertainty - Exploration and leasehold acquisition costs for further discussion. We use the "Successful efforts" method of accounting for oil and natural gas-producing activities. Expenditure on drilling and equipping exploratory wells is capitalised until it is clarified whether there are proved reserves. Expenditure on drilling exploratory wells that do not find proved reserves and geological, geophysical and other exploration expenditure is expensed. Unproved oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether major capital expenditure can be justified, may remain capitalised for more than one year. The main conditions are either that firm plans exist for future drilling in the licence or that a development decision is planned in the near future. Production cost per barrel is expected to increase as a result of tail-end production on mature fields on the NCS, PSA effects on production in international areas and continued pressure on costs in the industry. This section describes our estimated capital expenditure for 2008 with respect to potential capital expenditure requirements for the principal investment opportunities available to us and other capital projects currently under consideration. The figure is based on StatoilHydro developing organically and it excludes possible expenditures related to acquisitions. Therefore, the expenditure estimates and descriptions with respect to investments in the segment descriptions below could differ materially from the actual expenditure. For more information on the various projects in each of the segments, see the respective report sections described under Financial performance. E&P Norway. A substantial proportion of our 2008 capital expenditure is allocated to the ongoing development projects on Gjøa, Vega, Skarv, Alve, Morvin and Tyrihans, as well as the late-life projects on Statfjord and Gullfaks. International E&P. We currently estimate that a substantial proportion of our 2008 capital expenditure will be allocated to the following ongoing and planned development projects: Agbami in Nigeria, ACG and Shah Deniz in Azerbaijan, Saxi Batique in Angola, South Pars in Iran, with planned start-up of production in 2008; Tahiti in the Gulf of Mexico and Corrib in Ireland, with planned production start-up in 2009, and Leismer in Canada and Peregrino in Brazil, with planned production start-up in 2010. Natural Gas. In 2007 we finished the northern section of Langeled and the Tampen link pipeline. In addition, three LNG vessels and associated LNG companies were transferred from E&P Norway's assets to Natural Gas's assets with effect from 1 January 2007. We will continue to focus on increasing the capacity and flexibility of our gas transportation and processing infrastructure. This will be done through the expansion of the Kårstø processing plant, the Aldbrough gas storage project on the east coast of England and other investments. Manufacturing & Marketing. We are focusing our capital expenditure on our retail network and on upgrading our refineries to increase flexibility and increase the value of the refined products. In 2006, we received the final permit to build a combined heat and power plant (CHP plant) at Mongstad. It will be built and operated by the Danish company Dong under a long-term lease agreement, which StatoilHydro can take over after 20 years, free of charge. We and our partners at Mongstad and on Troll will invest NOK 2.7 billion in a gas pipeline from Kollsnes to Mongstad and refinery modifications in connection with the CHP plant. In addition to the CHP project, the main focus at Mongstad in the next three years will be on improvements to infrastructure. Finally, we may alter the amount, timing or segmental or project allocation of our capital expenditure in anticipation or as a result of a number of factors outside our control including, but not limited to:
4.2.3 Material contracts
See report section Operational review - Related party transactions and report section Shareholder information - Major Shareholders, for a description of certain agreements we have entered into with the Norwegian State. On 18 December 2006, Statoil and Norsk Hydro ASA announced that their respective boards of directors had agreed to a merger of Norsk Hydro's oil and gas activities and certain other related activities with Statoil. On 1 October 2007, the merger was completed (with effect from 1 January 2007), following which Statoil changed its name to StatoilHydro ASA. The merger was implemented by means of a demerger transaction effected in accordance with Norwegian law whereby the assets, rights and obligations relating to Norsk Hydro's oil and gas activities and certain related assets were transferred to the merged company for a consideration in the form of shares of Statoil to be issued to the shareholders of Norsk Hydro. Shareholders of Norsk Hydro received 0.8622 shares of the merged company for each Norsk Hydro share that they owned and 0.8622 ADSs in Statoil for each Norsk Hydro ADS that they owned. Following completion of the merger, the Norwegian State owned 62.5% of our shares. In accordance with the terms of the merger plan, with effect from 1 January 2007, the merged company took over certain assets, rights and obligations related to Norsk Hydro's activities, including:
4.2.4 Impact of inflation
Our results have in recent years been affected significantly by inflation in the cost of certain raw materials and services necessary for the development and operation of oil and gas producing assets, whereas other parts of our business are not exposed to similar cost pressures. While some of the cost pressure relates to capitalised expenditures thus only affecting our annual profit through increased depreciation, certain elements of operating expenditures have also been affected by this inflation. See our analysis of profit and loss as well as applicable outlook sections in report section Financial performance - High activity level in new organisation for details. As measured by the general consumer price index, inflation in Norway for the years ending 31 December, 2007 and 2006 was 0.9% and 2.6%, respectively. 4.2.5 Critical accounting judgements and key sources of estimation uncertainty
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU). The accounting policies applied by the group also comply with IFRS as issued by the International Accounting Standards Board (IASB). This means that we are required to make estimates and assumptions. We believe that, of the company's significant accounting policies (see Note 2 - Significant accounting policies to our Consolidated financial statements included in this report), the following may involve a greater degree of judgment and complexity, which in turn could materially affect the net income if various assumptions were changed significantly.
Critical judgements in applying accounting policies The following are the critical judgements, apart from those involving estimations (see below), that we have made in the process of applying the accounting policies and have the most significant effect on the amounts recognised in the financial statements Method of accounting applied for merger with the oil and gas assets of Norsk Hydro The merger between Statoil ASA and the oil and gas assets of Norsk Hydro has been accounted for using the carrying amounts of the assets and liabilities. When making this judgement the group considered firstly whether the Statoil ASA and the oil and gas assets of Norsk Hydro were under the common control of the Norwegian State, and secondly, given the conclusion that both entities were under the control of the Norwegian State, assessed what method of accounting would provide the most meaningful portrayal of the merger for accounting purposes. StatoilHydro concluded that such a reorganisation would be best presented using the carrying amounts of assets and liabilities, and reflecting all financial reporting as if such combination had existed for all periods presented. See note 2 Significant accounting policies-Basis for preparation and note 3 Merger with Hydro Petroleum for details on the merger and how it has been accounted for. Revenue recognition - gross versus net presentation of traded SDFI volumes of oil and gas production We market and sell the Norwegian State's share of oil and gas production from the NCS. We include the costs of purchase and proceeds from the sale of the SDFI oil production in Cost of goods sold and Revenue, respectively. In making the judgment we considered the detailed criteria for the recognition of revenue from the sale of goods set out in IAS 18 Revenue, and assessed in particular by analogy whether the risk and reward of the ownership of the goods had been transferred from the SDFI to the group. We also sell, in our own name, but for the Norwegian State's account and risk, the State's production of natural gas. This sale and related expenditures refunded by the State, are recorded net in the financial statements. In making the judgment we considered the same criteria as for the oil production and concluded that the risk and reward of the ownership of the gas had not been transferred from the SDFI to the group.
Key sources of estimation uncertainty The preparation of consolidated financial statements require that management make estimates and assumptions. The matters described below are considered to be the most important in understanding the judgments that are involved in preparing these financial statements and the uncertainties that could most significantly impact the amounts reported on the results of operations, financial position and cash flows. Proved oil and gas reserves. Oil and gas reserves have been estimated by internal experts in accordance with industry standards under the requirements of the U.S. Securities and Exchange Commission (SEC). An independent third party has evaluated our proved reserves estimates, and the results of such evaluation do not differ materially from management estimates. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements but not on escalations based upon future conditions. Reserve estimates are used when testing upstream assets for impairment. Proved and proved developed reserves are used when calculating the unit of production rates used for depreciation, depletion, and amortisation. Future changes in proved oil and gas reserves, for instance as a result of changes in prices, could have a material impact on unit of production rates used for depreciation and amortisation and for decommissioning and removal provisions, as well as for the impairment testing of upstream assets, which could have a material adverse effect on operating income as a result of increased depreciation and amortisation or impairment charges. See note 32 Supplementary oil and gas information to our Consolidated financial statements included in this report for details. Exploration and leasehold acquisition costs. Our accounting policy is to capitalise the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. We also capitalise leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgments on whether these expenditures should remain capitalised or written down due to impairment losses in the period may materially affect the operating income for the period. The following table itemises the ageing and categories of capitalised exploration expenditures and thus illustrates the risk profile of the capitalised amount as per 31 December 2007:
Unproved oil and gas properties are assessed for impairment on a quarterly basis or when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount. If, following evaluation, an exploratory well has not found proved reserves, the previously capitalised costs are tested for impairment. Exploratory wells that have found reserves, but classification of those reserves as proved depends on whether a major capital expenditure can be justified, may remain capitalised for more than one year. The main conditions are that either firm plans exist for future drilling in the license or a development decision is planned in the near future. Impairment/reversal of impairment. We have significant investments in property, plant and equipment and intangibles. Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired requiring the book value to be written down to its recoverable amount. Impairments are reversed if the conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgment and may to a large extent depend upon the selection of key assumptions about the future. Estimating the recoverable amount involves complexity in estimating relevant future cash flows based on future assumptions which are discounted to their present value. Impairment testing requires long-term assumptions to be made concerning a number of often volatile economic factors such as future market prices, currency exchange rates and future output, discount rates and political and country risk among others, in order to establish relevant future cash flows. Long-term assumptions for major factors are made at group level, and there is a high degree of reasoned judgment involved in establishing these assumptions, in determining other relevant factors such as forward price curves, in estimating production outputs, and in determining the ultimate termination value of an asset. See note 11 - Property, plant and equipment to our Consolidated financial statements included in this report for details of impairments recognised in the period. Decommissioning and asset retirement obligations. We have significant obligations to decommission and remove offshore installations at the end of the production period. Legal obligations associated with the retirement of non-current assets are recognised at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost is capitalised as part of the related non-current asset and allocated to expense over the useful life of the asset. It is difficult to estimate the costs of these decommissioning and removal activities, which are based on current regulations and technology. Most of the removal activities are many years into the future and the removal technology and costs are constantly changing. The estimates include assumptions of both the time required and the day rates for rigs, marine operations, heavy lift vessels and currency rates that can vary considerably depending on the assumed removal complexity. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgment. See note 22 - Asset retirement obligations and other provisions to our Consolidated financial statements included in this report for details of estimated obligations and the changes therein. Employee retirement plans. When estimating the present value of defined pension benefit obligations that represent a gross long-term liability in the consolidated balance sheet, and indirectly, the period's net pension expense in the consolidated statement of income, management makes a number of critical assumptions affecting these estimates. Most notably, assumptions made on the discount rate to be applied to future benefit payments, the expected return on plan assets and the annual rate of compensation increase have a direct and material impact on the amounts presented. Significant changes in these assumptions between periods can have a material effect on the accounts. See note 21 Pension obligations in the F-pages for details of estimated pension obligations, pension assets and the sensitivities to changes in assumptions. Derivative financial instruments and hedging activities. We recognise all derivatives on the balance sheet at fair value. Changes in fair value of derivatives that do not qualify as hedges are included in income. When not directly observable in active markets, the fair value of derivative contracts must be computed internally based on internal assumptions as well as directly observable market information, including forward and yield curves for commodities, currencies and interest. Changes in internal assumptions and forward curves could have material effects on the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in corresponding income or loss in the income statement. See note 28 - Financial instruments by category and note 29 - Financial instruments and hedging activities in our Consolidated financial statements included in this report for details of recognised assets and liabilities and sensitivities, respectively, related to financial instruments and hedging activities. Income tax. We annually incur significant amounts of income taxes payable to various jurisdictions around the world, and also recognises significant changes to deferred tax assets and deferred tax liabilities, all of which are based on management's interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon management's ability to properly apply at times very complex sets of rules, to recognise changes in applicable rules and, in the case of deferred tax assets, management's ability to project future earnings from activities that may apply loss carry forward positions against future income taxes. See note 9 - Income taxes in our Consolidated financial statements included in this report for details of amounts recognised as income tax assets, liabilities and expense. 4.2.6 Off balance sheet arrangements
We have entered into various agreements, such as operational leases and transportation and processing capacity contracts that are not recognised in the balance sheet. See report section Table of principal contractual obligations and other commitments for more information. We are not party to any off-balance sheet arrangements such as the use of Variable Interest Entities. 4.3 Use and reconciliation of Non-GAAP measures
We are subject to SEC regulations regarding the use of "non-GAAP financial measures" in public disclosures. Non-GAAP financial measures are defined as numerical measures that either exclude or include amounts that are not excluded or included in the comparable measures calculated and presented in accordance with generally accepted accounting principles, which in our case refers to IFRS. The following financial measures may be considered non-GAAP financial measures:
4.3.1 Return on average capital employed after tax (ROACE)
StatoilHydro uses ROACE to measure the return on capital employed, regardless of whether the financing is through equity or debt. In the company's view, this measure provides useful information, both for the company and for investors, regarding performance during the period under evaluation. We make regular use of this measure to evaluate our operations. Our use of ROACE should not be viewed as an alternative to income before financial items, income taxes and minority interest, or to net income, which are measures calculated in accordance with generally accepted accounting principles or ratios based on these figures. ROACE was 17.9% in 2007, compared with 22.9% in 2006. The decrease was mainly due to higher operating expenses as well as higher capital employed, and it was partly offset by increased net financial income. Adjusted for the effects of restructuring costs and other costs arising from the merger, ROACE was 19.9% in 2007, compared with 22.9% in 2006. ROACE is defined as a non-GAAP financial measure.
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