STATOIL ASA 20-F 2009
Documents found in this filing:
STATOILHYDRO ANNUAL REPORT ON FORM 20-F
Commission File No. 1-15200
*Listed, not for trading, but only in connection with the registration of American Depositary Shares, pursuant to the requirements of the Securities and Exchange Commission
Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Annual report on Form 20-F 2008Table of content
StatoilHydro's Annual Report on Form 20-F for the year ended 31 December 2008 ("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 and other related documents with the Securities and Exchange Commission, the SEC. It is also possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C. 20549, USA. You may also call the SEC at 1-800-SEC-0330 for further information about the public reference rooms and their copy charges, or you may log on to www.sec.gov. The report can also be downloaded from the SEC website at www.sec.gov.
StatoilHydro discloses on its website at www.statoilhydro.com/en/aboutstatoilhydro/corporategovernance/norwegiancodeofpractice/pages/statementofdifference.aspx, and in its Annual Report on Form 20-F (Item 16B) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under the New York Stock Exchange (the "NYSE") listing standards.
StatoilHydro publishes financial data in accordance with IFRS. StatoilHydro did not publish financial data in accordance with IFRS in 2006 as we previously presented financial data in accordance with US GAAP. For this reason, we have not provided selected financial data for 2005 and 2004 in this Annual Report and Form 20-F 2008. Selected financial data for those years presented in accordance with US GAAP is included in our 2006 Annual Report on Form 20-F.
StatoilHydro ASA and Det norske oljeselskap ASA signed a sales and purchase agreement on 12 October for the transfer of Det norske oljeselskap's 15% interest in the Goliat field to StatoilHydro ASA. The transaction has effect from 1 January 2008. Also on 12 October, StatoilHydro Petroleum AS and Det norske oljeselskap ASA agreed on a swap of minor interests in three other licences.
On 21 October, the European Commission announced that StatoilHydro has been granted permission to take over the bulk of the Jet retail chain in Scandinavia currently owned and operated by ConocoPhillips.
On 12 November StatoilHydro formed a strategic alliance with Chesapeake Energy Corporation to jointly explore unconventional gas opportunities worldwide. Under this agreement we will initially acquire a 32.5% interest in Chesapeake's Marcellus shale gas acreage.
On 11 December StatoilHydro completed the full acquisition of the Peregrino heavy-oil field offshore Brazil, after closing the deal to acquire the additional 50% stake from Anadarko and making StatoilHydro the operator.
Access to new areas
In Norway, StatoilHydro was offered interests in 12 production licences in the Awards of Predefined Areas 2007 (APA 2007) on the Norwegian Continental Shelf (NCS). The company will be the operator of nine of the licences
Production from Gamma Main Statfjord on the Oseberg field in the North Sea commenced on 12 April, only 18 months after the oil deposit was proved. Production started from seven fields on the NCS during 2008: Volve (12 February), Gulltopp (7 April), Oseberg Gamma Main Statfjord (12 April), Vigdis East (15 April), Theta Cook (26 June), Oseberg Delta (27 June) and Vilje (1 August). Internationally, production commenced on Mondo in Angola (1 January), Deep Water Gunashli in Azerbaijan (22 April), Saxi and Batuque offshore Angola (1 July), the Agbami in Nigeria (29 July) and South Pars in Iran (1 October).
Gas filling into the storage caverns in the Aldbrough project in the UK started in August. This is a cooperation project for natural gas storage between the British company SSE Hornsea Limited (SSEHL) and StatoilHydro.
Technology and new energy
The most complicated well in StatoilHydro's history was successfully completed and hydrocarbons were flowing up through the well at 9910 metres. This is thus the longest producing well in the world drilled from an offshore platform. The well provides the company with valuable knowhow.
Social responsibility and sustainable development
Production resumed on the Statfjord A platform 28 May, after four days of shutdown due to an oil leak Saturday 24 May. For safety reasons, a total of around 1,200 cubic metres of oil-containing water were pumped to sea. This was done to ensure safety on board the platform following a leak in a pipe inside one of the shafts of the installation. Oil protection equipment and oil booms were deployed to collect a thin oil film around the Statfjord A platform.
StatoilHydro submitted an external investigation report on the Libya matter to Norwegian and US authorities on 7 October. Consultancy agreements related to Norsk Hydro's earlier activities in Libya contain issues which could be problematic in relation to Norwegian and US anti-corruption legislation. The report has been submitted to the National Authority for Investigation and Prosecution of Economic and Environmental Crime in Norway (Økokrim), to the US Department of Justice (DoJ), the US Securities and Exchange Commission (SEC) and to the relevant Libyan authorities.
StatoilHydro and Indian oil company ONGC agreed on 6 February to jointly explore the potential of developing Carbon Capture and Storage (CCS), and CDM (clean development mechanism) projects in India.
Carbon injection and storage on the Snøhvit field started on 22 April. Instead of emitting the carbon dioxide (CO2) resulting from the well stream that comes from the Snøhvit field to the air, the CO2 is reinjected into the ground and stored in a formation which lies somewhat beneath the gas-bearing formations on the Snøhvit field.
StatoilHydro submitted a plan for carbon capture at Mongstad to the Ministry of Petroleum and Energy and the Ministry of the Environment. The plan addresses the most important challenges and sums up key issues associated with the technical feasibility of carbon capture at Mongstad. This is the first step along the way towards full-scale carbon capture at Mongstad.
StatoilHydro is an integrated oil and gas company based in Norway and present in approximately 40 other countries worldwide. We are the leading operator on the NCS and are also enjoying 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).
Entitlement oil and gas production outside Norway represented 17% of our total output, which averaged 1.751 mmboe per day in 2008.
As of 31 December 2008, we had proved reserves (including our share of reserves in affiliated companies of 127 mmbbl of oil) of 2201 mmbbl of oil and 537.8 bcm (equivalent to 19.0 tcf) of natural gas, corresponding to aggregate proved reserves of 5584. mmboe.
We are represented in approximately 40 countries and are engaged in exploration and production activities in 24 of them. As of 31 December 2008, 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 2300 service stations in Scandinavia, Poland, the Baltic States and Russia.
We are contributing to developing new energy resources, have ongoing activities in the fields of wind power and biofuels and are at the forefront in implementing technologies for carbon capture and storage (CCS).
In further developing our international business, we intend to utilise our core expertise in areas such as deep waters, 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.
Statoil was founded in 1972 and merged with Hydro's oil and energy business in 2007. We changed our name to StatoilHydro on 1 October, 2007.
Statoil ASA (Statoil) was founded by a decision of the Norwegian Storting (parliament) in 1972. As a result of Statoil's merger with the oil and energy business of Hydro (formerly Norsk Hydro), we have roots in the oil industry dating back to the 1960s when Hydro took part in the exploration of the NCS.
Statoil was 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 changed its name to Statoil ASA.
On 1 October 2007, the oil and energy assets of Hydro were merged with Statoil, 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 reflects the development of the former Statoil and Hydro on a carry over or combined basis for all periods presented.
Our history of involvement in the oil and gas industry began in earnest in 1965, when we were awarded licences by the Norwegian State to explore for petroleum on the NCS. We participated in the discovery of the Ekofisk field in 1969 and the Frigg field in 1971. The development of these discoveries brought us into the petroleum refining and marketing business.
In 1975, oil refining operations began at Mongstad in Norway, and in 1974, Mobil discovered the Statfjord field in the North Sea, which was of great significance for the further development of the Norwegian Continental Shelf (NCS). During the development of Statfjord, one of the world's largest offshore oilfields, we encountered great challenges. Statfjord came on stream in 1979 and we took over as operator eight years later. Today, we have a 44% interest in the field.
In the 1980s, both Statoil and Hydro became major players in the European gas market by obtaining 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. Both Statoil and Hydro became leading companies 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 through our alliance with BP. The foundations for the today's merged company were also laid with Hydro's acquisition of Saga Petroleum in 1999, and several major acquisitions in the Gulf of Mexico.
Since 1 October 2007, our business has grown as a result of substantial investments and acquisitions including the acquisitions of oil sand leases in Canada in 2007, and the acquisition of the remaining share in the Peregrino field in Brazil completed in 2008, for which field we also became the operator. Since October 2007 we also have had a 24% ownership share in Shtokman Development AG which is responsible for phase I of the Shtokman development a natural gas field located in the central part of the Russian sector of the Barents Sea.
Our most recent transaction involves a strategic agreement to jointly explore unconventional gas opportunities worldwide with Chesapeake Energy Corporation, the largest US producer of natural gas. Under these agreements StatoilHydro acquired an initial 32.5% interest in Chesapeake's Marcellus shale gas acreage covering 1.8 million net acres (7300 square kilometres) in the Appalachia region of the northeastern USA. For more information of this acquisition, see report section 3.2 Operational review-International E&P.
Statements referring to StatoilHydro's competitive position rely on a range of sources, including analysts' reports, independent market studies and our internal assessments of our market share.
Statements referring to StatoilHydro's competitive position in the Business Overview and Operational Review sections are based on what we believe to be true and, in some cases, they rely on a range of sources, including investment analysts' reports, independent market studies and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.
In StatoilHydro we are working towards our goals of continuing our strategy for profitable growth and upholding our ambition to increase equity production of oil and gas to 2012 and beyond, despite great uncertainty in the global economy and oil market.
In working towards our ambition to realise the full value potential of the NCS, we are developing international platforms for long-term growth, and we are gradually building a position within new energy. The company is well positioned to manage through the global economic downturn. A strong balance sheet and active cost management will enable the company to pursue this long term strategic direction.
The global economy entered into recession in the second half of 2008. Nevertheless, energy demand is expected to pick up and energy prices are expected to increase in the longer term.
Global GDP growth is currently expected to be negative in 2009. Within two to three years we expect global growth to return to the long term trend, within the range of 2.5 to 4%. The impact of the policy measures and government stimulus packages is unknown and intended positive effects therefore represent considerable uncertainties for these forecasts.
Crude oil price developments
Dated Brent entered into 2008 on a strong upward trend extending from 2007, and accelerated as financial investors increased positions in a search for more favourable yields. Strong support from a tight gasoil/diesel market and declining crude oil inventories led to an increasingly tight oil market, and the Brent dated reached a record high level of 144 USD/bbl in July 2008.
At this point an underlying tendency of slower global GDP growth and weakening product demand started to discourage investors. With a shift of both sentiment and outlook during 2008, crude oil prices were fundamentally different from the first half to the second and traded between 33 and 40 USD/bbl in December. Brent dated averaged 97.26 USD per barrel in 2008. The gas, power and EU ETS (Emission Trading Scheme) prices have broadly followed oil prices through 2008.
With the global economy deteriorating, the energy markets are expected to stay relatively weak in 2009 and possibly into 2010 and 2011. Over time as the macro economic situation improves, energy demand is expected to pick up and energy prices are expected to rise.
High cost environment
In recent years, the oil industry has focused largely on growing production and the resource base. As energy prices soared and the competition for resources intensified, the cost of building new production capacity increased steeply. The tightening of the supplier market intensified the cost push. With reduced oil demand and falling oil prices, this high cost environment is not seen as sustainable. If the oil price remains at current low levels, we expect costs to be reduced going forward.
StatoilHydro is continuing its strategy for value creation and growth and upholding its ambition to increase the equity production of oil and gas up to 2012, despite great uncertainty in the global economy and the oil market.
Overall strategic direction
In the short term, our main focus will be on delivering on our production targets and managing our cost base. This means delivering high operational performance, with a strong focus on HSE. In the longer term our focus is to develop the current project portfolio with quality and at a competitive cost to enable us to grow profitably.
Leveraging our technology and capabilities
Maximising long-term value creation on the NCS
We are focused on improving our HSE performance, regularity and drilling efficiency, and we plan to use Improved Oil Recovery (IOR) measures and other operational best practices to maximise the potential of our assets. We intend to highgrade our portfolio, through acquisitions and divestments.
Building and delivering profitable international growth
We will use our core expertise in areas such as deep waters, harsh environments and heavy oil and gas value chains to pursue new business opportunities around the world. We have already demonstrated this through our acquisition of the oil sands position in Canada, the Peregrino field in Brazil, and the US shale gas position - all of which represent new challenges and opportunities for us to apply our technology and experience. For a description of these acquisitions see Section 3.2 Operational Review - International E&P.
We will continously seek to high grade our portfolio, for instance as we have done in our long term partnership with Sonatrach on Cove Point, and our acquisition of the remaining 50% of Peregrino and its operatorship. StatoilHydro's history as a national oil company (NOC) also gives us a competitive advantage in developing new cooperative models with other NOCs that are seeking partners for developing their resource bases.
Developing profitable midstream and downstream positions
Creating a platform for new energy solutions and production
Using exploration as a key enabler for value creation
Our exploration strategy can be divided into three categories:
Frontier exploration aims at proving new fields in areas where the petroleum system remains unproven.
Growth exploration involves exploring for fields with stand-alone potential in areas where the petroleum system is known. We have a strong strategic focus on being an active operator with a view to shaping the future direction of our business.
Infrastructure-led exploration seeks to provide resources to existing infrastructure in a timely manner.
Using technological innovation and implementation as a key business enabler
Our ambition is to attain distinctiveness and industrial leadership in six specific technologies:
Technology makes a decisive contribution in all our activities, such as in field development in frontier deep waters, Arctic areas, heavy oil production, subsalt exploration, and environmental and climate issues. Our ambition is also to stay competitive in a broad range of core and emerging technologies along the energy provision value chain, including offshore wind and sustainable biofuel.
We aim to maintain the right course to capture future business opportunities and to develop smarter solutions to explore for and to produce energy in cost effective and environmentally friendly ways.
Exploration & Production Norway (EPN) consists of our exploration, field development and production operations on the NCS.
EPN is the operator of 42 developed fields that collectively produced more than three mmboe per day in 2008, which represented about 80% of the total production from the NCS. In 2008, our average daily oil and natural gas liquids (NGL) production was 824 mboe and our average daily gas production was 101.3 mmcm (37.1 bcf), totalling 1.461 mmboe per day.
We have ownership interests in exploration acreage throughout the licensed parts of the NCS, both within and outside our core production areas. We participate in 346 licences on the NCS and are an operator for 174 of them.
As of 31 December 2008, EPN had proved reserves of 1,396 mmbbl of crude oil and 498 bcm (17.58 tcf) of natural gas, which represents an aggregate of 4,529 mmboe.
Several factors are expected to contribute to StatoilHydro's equity production on the NCS, including increased production and drilling efficiency, more cost-effective operations, and improved recovery from existing fields.
Other important measures include development of new discoveries, the proving of new resources through intensive exploration activity, increased access to new licences, enhanced focus on health, safety and the environment (HSE), and optimal use of existing infrastructure.
Our overall strategy on the NCS is defined as:
Maintaining current production level
Higher regularity is expected to be achieved through improved well work, better reservoir management, de-bottlenecking of export infrastructure, improved planning of turnarounds and fewer topside plant failures.
Additional production is expected to be achieved by means of new capacity, including ramp-ups on Ormen Lange and Snøhvit, new field developments and implementation of IOR measures.
Tie-ins to existing infrastructure on fields that are in decline and/or have reached a critical point in their technical life will also have high priority. A well-balanced asset portfolio on the NCS with respect to regions and maturity is necessary to sustain total oil and gas production at current levels.
We need to achieve optimal development and exploitation of our existing portfolio in order to secure a solid foundation for future growth through continued high exploration activity. Active infrastructure-led exploration is a key factor in extending the life of the infrastructure in the tail-end production phase. However, access to new, prospective acreage is also necessary to maintain a high production level in the longer term.
One of our ambitions is to become one of the leading players in the Arctic by 2020. Considering the long lead times of field developments, a near-term opening of new acreage is imperative. Succeeding in new field developments in the northern areas of the NCS is a priority for StatoilHydro. Important efforts are currently underway to maintain stable operations in the Snøhvit LNG project, and to support a timely and robust development of the Goliat oil field. However, new high-quality exploration acreage remains a critical prerequisite for long-term success. To meet our ambitions in the northern area, we have to feasibly mitigate challenges in a range of areas - including geology and technology.
Safe and efficient operations are essential to our business
Our ongoing efforts to introduce one common operating model and common work processes on all our installations on the NCS, will enable us to utilize best practices, and optimise usage of our total resources to ensure safe and efficient operation.
Unit production costs on the NCS have been on a rising trend in recent years, in line with the industry development. StatoilHydro's management is implementing measures to contain future cost inflation.
The climate challenge
Industrial architect for NCS
Production increased by 3% from 2007 to 1461 mmboe/day.
International Exploration & Production (INT) is responsible for exploration, development and production of oil and gas outside the Norwegian Continental Shelf. INT will provide a major part of StatoilHydro's future production growth.
In 2008 the business area had production from 12 countries: Canada, the USA, Venezuela, Algeria, Angola, Libya, Nigeria, UK, Azerbaijan, Russia, Iran and China. In 2008 INT produced 24% of StatoilHydro's total equity production of oil and gas, and INT's share is expected to increase significantly in the future.
We have exploration licences in North America (Canada and the USA), Latin America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Morocco, Mozambique, Nigeria and Tanzania), the European, Caspian and Russian area (Denmark, the Faroes, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia).
The main sanctioned development projects in which we are involved are in Canada, the USA, Brazil, Angola and Ireland, and we believe we are well positioned for further growth through a substantial project portfolio that remains to be sanctioned.
The map shows our exploration and production areas.
Our long-term upstream growth ambition will mainly be achieved by growing internationally. Growth is being pursued through our four focus areas - deep waters, harsh environments, gas value chains and heavy oil.
These focus areas all draw upon our existing strong technical and project execution skills acquired through our experience from the NCS. We access new resources through advanced exploration activities, focused business development and long-term partnerships with national oil companies.
Our international access strategy has increased the scale of our operations in terms of produced volumes, reserves and technological and geographical breadth. We aim to build a robust, diverse and long-life portfolio with significant optionality and flexibility.
INT's near-term focus is on delivering on the production targets for 2012 communicated to the financial markets. Recent acquisitions have also given us significant operatorships that are in the exploration and planning phases, as well as the major Peregrino development project.
Major efforts are being made on making the transition from being a mainly North Sea player towards becoming a world class international operator. Over the last few years, StatoilHydro has built up a large resource base. We are working continuously to develop our inventory of projects into producing assets by looking at innovative technical and commercial solutions.
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 additional processing, transportation and storage capacity.
NG is 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 and the US.
In 2008, we sold 37.0 bcm (1.31 tcf) of natural gas from the NCS on our own behalf, in addition to approximately 32.0 bcm (1.13 tcf) NCS gas on behalf of the Norwegian State. StatoilHydro's total European gas sales, including third party gas, were 76.8 bcm (2.71 tcf) in 2008. 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 4.1 bcm (0.4 tcf) of gas in 2008, of which 2.3 bcm (0.1 tcf) was entitlement gas.
We have a significant interest in the NCS pipeline system owned by Gassled, which is the world's largest offshore gas pipeline transportation system, totalling approximately 7800 kilometres. This network links gas fields on the NCS with processing plants on the Norwegian mainland, as well as terminals at six landing points located in France, Germany, Belgium and the United Kingdom, providing us with flexible access to customers throughout Europe.
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 endeavour to achieve greater efficiency from our existing supply portfolio, to update and refine our commercial relationships with key customers and to establish new positions that will improve the flexibility of our operations. Through balancing, optimisation and trading activities, we plan to continue to create additional value on top of our long-term sales business.
StatoilHydro aims to further develop its 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. We plan to further develop the market position at the Cove Point terminal on the East Coast of the US. Our aquisition of a 32.5% share in the Marcellus gas deposit in the Appalachian basin is expected to significantly strengthen our US natural gas business in terms of production, reserves and marketing.
The main objective of NG's strategy is to improve our growth opportunities in all parts of the natural gas business and fully exploit the opportunities that changing market conditions provide us. This means increased focus on extracting value from the existing contracts and asset portfolio and increasing the value added from trading and optimisation activities beyond the landing point. It also entails increased internationalisation of the gas business, including activities in North America, LNG growth and the addition of new markets.
The main task for NG is to maximise value creation in markets that are constantly changing and deregulating, particularly Europe, making active use of the new opportunities offered and managing risks within acceptable parameters.
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 approximately 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 2100 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 2008, we had trading activity of 717 mmbbl of crude oil and condensate, approximately 30 million tonnes of refined oil products and 11.8 million tonnes of NGL. The refinery throughput was 15.2 million tonnes. In the energy and retail market, we sold approximately 13 billion litres in 2008, including eight billion litres of petrol and diesel.
M&M's 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. We will focus on further developing our position in North America to maximise the value creation from the group's crude production in the Gulf of Mexico, future production of extra heavy oil from Canada and Brazil, as well as our production imported to North America from other regions.
Oil Sales, trading and supply (OTS)
Our ambition is to maintain the competitiveness of Mongstad, Kalundborg and Pernis by exploiting technology in order to improve reliability, energy efficiency, maintenance and HSE performance. Our focus will be to increase the robustness of the sites, whilst adapting to changes in feedstock and market variations. Such changes may well include the increased upgrading of gasoils and heavy oils to diesel, and production and supply of Biofuels. The new combined heat and power (CHP) unit at Mongstad will improve energy efficiency when it starts up in 2010, and also lay a foundation for future improvements.
We will implement cost efficient and flexible liquid transportation solutions. The logistics solution will add value by allowing the possibility to combine cargoes and crude qualities, to enable a reduction in refinery feedstock costs and give flexibility to handle high tan and heavy crude oil. It will also be important to develop business concepts and related technology that are feasible across the Arctic area.
Energy and retail
Our ambition is to consolidate our downstream positions in Scandinavia, focusing on increasing profitability and establishing StatoilHydro as a leading supplier of bio fuels in selected markets. In Eastern Europe, we plan to build on our strong Baltic and Polish positions, and continue to evaluate market opportunities based on the Scandinavian marketing concept.
M&M experienced a challenging trading market in 2008, but were well positioned to cope with the unprecedented market conditions and volatile crude oil prices. These are the key events of 2008.
Technology & New Energy (TNE) is responsible for the development of technology and renewable energy contributing to global business success.
This means that TNE is responsible for ensuring 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, and safe, efficient and environmentally-friendly 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 and development, piloting, implementation and commercialisation of new technology.
Climate change, security of supply and a growing demand for clean energy are opening up new business opportunities. StatoilHydro is in a position to seize these opportunities by utilising long-standing core capabilities from the oil and gas industry. StatoilHydro's New Energy business unit is responsible for the company's business effort within renewable energy. The activities are grouped under renewable energy production, sustainable fuels, carbon dioxide management and technology development.
StatoilHydro's technology strategy focuses on generating long-term business value through identifying, developing and applying technologies that will secure the company's long term position as an internationally competitive organization.
The strategy is therefore focused on generating long-term business value through leading technology application. Its realization will demand a response from the entire technical community to increase the value of existing business, secure and develop platforms for further growth, and operate in new and more challenging environments. The strategy is upstream-motivated, although some weight is placed on energy diversification. Operational excellence and industry-leading HSE performance underpin all activities.
The corporate technology strategy is driven by the central business challenges, aiming to build even stronger industry positions. Technology is a key enabler to achieving this, and will make significant contributions to field development in frontier deep waters (for example, the Gulf of Mexico and Brazil) and Arctic areas, heavy oil production, subsalt exploration, and environmental and climate issues. The ambition is to achieve distinctiveness and industry leadership in selected technologies and to stay competitive in a broad range of core and emerging technologies along the energy provision value chain, such as offshore wind and sustainable biofuels.
Furthermore, IOR and improved drilling and well solutions are important to successfully growing our business. StatoilHydro has achieved some of the petroleum industry's highest recovery factors on the NCS by combining scientific and engineering capabilities and boldly introducing new technology. We intend to further advance the most important technologies to meet forthcoming Improved oil recovery (IOR) ambitions on the NCS and internationally. Drilling and well technology plays a key role in increasing production and ensuring regular delivery, and through its application we intend to achieve faster operations, reduced downtime, and improved well flow whilst improving safety during operations. Supplier cooperation and venture activities will remain important. We are also reviewing our intellectual property rights policy and clarifying our policy on technology acquisition in terms of proprietary development and cooperation as opposed to off-the-shelf purchasing.
Although the selected technologies are dealt with separately, it is important to note that leading industrial solutions depend on their successful combination.
Projects (PRO) is responsible for planning and executing all major development and modification projects , as well as project and operational procurement, including securing rig capacity based on a corporate rig strategy.
Our goal is to be world-class in terms of project execution and to deliver on time and within budget, in accordance with high HSE standards and agreed quality standards. To become a truly global energy player, it is essential that StatoilHydro is able to execute projects at the very highest level, and thereby strengthen the company's international competitiveness.
Our current portfolio consists of more than 120 modification and development projects in the execution phase, with an expected total investment cost of more than NOK 200 billion. A major part of the portfolio consists of activities related to ongoing redevelopment efforts, aimed at maximising production from the NCS.
Our strategy is to develop high quality projects as planned and in a safe and reliable manner.
Our ability to utilise the company's world-leading technology, execute projects in complex surroundings and demonstrate our core expertise in new markets is of vital importance for opening up new business opportunities. The fight for global resources is fierce, but familiar to StatoilHydro. The real challenge is inflicted by local market, local practices, new standards and new cultures. These unfamiliar settings impact price, availability, quality and lead times for deliveries.
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 - as well as the major heavy oil project offshore Brazil, Peregrino, which is 100% StatoilHydro owned and operated.
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, an increasing number of fields will need upgrading or renewal of drilling units, control systems, hydrocarbon processing systems, cranes and other major redevelopment efforts.
Developing sustainable solutions for clean renewable energy with a sound financial rationale is a key element in the group's strategy. We anticipate an increased focus on new energy projects in the years to come. In this context, the pre-sanctioning of two offshore wind projects, namely Hywind and Sheringham Shoal, serves as important milestones for PRO in 2008.
In order to handle our projects in the most efficient way, we intend to use inter-field project organisations to standardise tasks and continuously search for synergies between projects and contracts.
We are dependent on the cooperation of a highly professional supply industry. Therefore we seek to secure a high degree of diversity among our suppliers, and are continuously on the lookout for innovative solutions and access to the best qualified expertise and external resources.
Securing sufficient flexibility in changing market conditions is a key focus area and we expect our suppliers to adjust accordingly. We have seen increasing expenditure in the recent past but in the current worldwide economic situation, the time has come to optimize cost while improving quality, productivity and efficiency in collaboration with our suppliers. As an outcome, we expect that supplier costs will be reduced going forward.
While oil production on the NCS shows a falling trend, improved oil recovery will fight the decline. Production of natural gas is expected to increase and constitute a larger share of total production in the future.
In 2008 the total production from the NCS was 4.16 mmboe per day. Improved oil recovery from existing fields is an important factor in maintaining the current production level, and most of the IOR activities are related to the drilling of new wells. Natural gas production is increasing and we expect production of natural gas to constitute a larger share of total production in the future.
A major challenge for the industry has been to secure rig capacity, which is vital to increasing the recovery factor. A tight supplier market on the back of recent years' oil price increases has put upward pressure on rig rates, as well as overall oil service expenses.
The global financial crisis that escalated in September will probably have an impact on this situation. However, much of the rig fleet is on longer term contracts, so a considerable change is not likely to be seen before 2010 or 2011. The recent turmoil in the financial and commodity markets has sharpened the focus on capital efficiency and cost control. Investment plans have been prioritized, and our portfolio of field projects and exploration prospects has been trimmed and high graded. However, short-term IOR efforts are fairly robust.
Another challenge facing the companies on the NCS is that future production is expected to come from smaller and more complicated fields. New field development projects typically have more complex reservoirs and are technically more challenging than before. They will therefore demand more resources per barrel than the older and larger fields. As the NCS matures, the investment level is expected to remain at a high level.
We believe there is still a large undiscovered resource potential on the NCS, both in mature and frontier areas. According to estimates published by the Norwegian Petroleum Directorate, approximately one-third of the resources on the NCS are undiscovered. Existing infrastructure ensures profitability for small discoveries in mature areas that would not otherwise justify a stand alone development. The majority of the remaining large discoveries are expected to be located in the frontier areas.
Access to attractive acreage is an important factor in realising the potential of the NCS. In January 2009, 40 companies were awarded 34 new licences in the North Sea, the Norwegian Sea and the Barents Sea through Awards in Predefined Areas(APA) 2009. The annual APA concession system offers previously relinquished acreage and unawarded blocks offered in previous licensing rounds located in specific mature parts of the NCS. The APA system ensures that large areas close to existing and planned infrastructure are made available to the industry, and the APA area will be expanded as new exploration areas are matured.
The deadline for applications in the 20th licensing round expired on 7 November 2008 with a total of 46 companies submitting applications. According to a press release from the Norwegian Petroleum Directorate, this was one of the largest licensing rounds ever, and the oil companies' interest demonstrated "that new exploration areas on the Norwegian Shelf are competitive in an international perspective." Awards are planned for March/April 2009.
Ensuring safe and stable operation with no harm to people or the environment is an essential aspect of operating on the NCS, and there has been increased focus on this issue in recent years.
StatoilHydro's NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.
We have organised our production operations into four business clusters - Operations West, Operations North Sea, Operations North and Partner Operated Fields.
The 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.
In addition to the producing areas, we operate a significant number of exploration licenses. The exploration acreage is located both in undeveloped frontier areas as well as close to infrastructure and producing fields.
North Sea. The total licensed acreage in the North Sea covers 74,841 square kilometres. We operate 21,318 square kilometres and are partner in 12,229 square kilometres. Following the execution of work programme and prospectivity evaluation, one licence has been relinquished in the North Sea in 2008. In addition, six licences were partly relinquished and two licences were relinquished through farm-out in 2008. Three licences were awarded to us in the Awards in Predefined Areas 2007 (APA 2007) and we became operator of two of these. In addition, one licence was awarded as licence extension. Four licenses were awarded to us in the Awards in Predefined Areas 2008 (APA 2008) and we became operator of two of these.
Norwegian Sea. Total licensed acreage in the Norwegian Sea covers 37,033 square kilometres. We operate 13,587 square kilometres and are partner in 7,384 square kilometres. In the deepwater region we have interests in licences covering approximately 10,000 square kilometres. Following execution of work programme and prospectivity evaluation, six licences were relinquished in the Norwegian Sea in 2008; three in the deep water region and three in the shallow water region. In addition, four licences were partly relinquished in 2008. Four licences were awarded to us in the APA 2007, and we became operator of all of these. In addition, we acquired one new licence through farm-in in 2008. Two licenses were awarded to us in the Awards in Predefined Areas 2008 (APA 2008) and we became operator of one of these. In addition, two licenses were awarded as license extensions.
Through active portfolio management we seek to optimise our licence portfolio, and strengthen our core areas.
During 2008, we signed a sales and purchase agreement to aquire Det Norske's 15% share in Goliat in the Barents Sea and a swap involving a 10% share of Det Norske's participating interest in the Ragnarrock discovery on the Utsira Height in exchange for interests in two exploration licences in the Grane and Heimdal areas. Furthermore, several exploration licence transactions have been performed.
StatoilHydro has delivered an extensive exploration programme on the NCS in 2008. We participated in 39 exploration wells, resulting in 27 discoveries. This implies a success rate approaching 70%.
We operated 34 of the 39 exploration wells including 24 of the 27 discoveries. In addition, we operated nine exploration extensions where six resulted in discoveries.
The most important discoveries in 2008 were Dagny/Ermintrude (PL048/PL303) near Sleipner in the North Sea which has opened a new oil play in a mature gas province, and Snefrid South and Haklang (PL218) near the Luva discovery in the Norwegian Sea that could provide the basis for new gas infrastructure. The five wildcat exploration wells completed in the Barents Sea were all discoveries. Although the proven volumes in these wells have not met our most optimistic expectations, they have enhanced our understanding of the hydrocarbon potential in the area and will be important guides for our continued exploration activity in the Barents Sea. Nearly half of the discoveries proven in 2008 are located near existing infrastructure and are of small to medium size. These discoveries are critical to maximise the take-out in and around existing fields and most of them already have a planned tie-back solution.
The table below shows our exploration and development wells drilled on the NCS during the last three years.
forAt the end of 2008, we had a total of 1396 mmbbl of proved oil reserves and 498 bcm (17.6 tcf) of proved natural gas reserves on the NCS.
Measured in barrels of oil equivalent (boe), our proved reserves consist of 31% oil and 69% natural gas, based on total proved reserves on the NCS of 4529 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 2008 that would mean a significant change in the estimated proved reserves as of that date.
Further information on reserves can be found in note 34 - Supplementary oil and gas information - to our Consolidated Financial Statements.
In 2008, our total equity oil and NGL production in Norway was 302 mmbbl, and gas production was 37.1 bcm (1310 bcf), which represents an aggregate of 1.461 mmboe per day.
The following table shows the NCS production fields and field areas in which we are currently participating. Field areas are groups of fields operated as a single entity.
The following table shows our average daily equity production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2008, 2007 and 2006.
The following fields are currently under development on the Norwegian Continental Shelf.
The Alve field, in which we hold an 85% interest, is located in PL159B in the Norwegian Sea, 14 kilometres south west of the Norne field. The PDO was submitted to the Norwegian authorities in January 2007 and approved in March 2007. The field will be developed through the installation of a four-slot subsea wellhead template that will be tied back to the Norne Floating Production Storage Offloading (FPSO). Production is scheduled to start in early 2009. The total investment for the project is estimated to be NOK 2.7 billion. Production commenced on 19 March, 2009.
Gjøa is located in the North Sea and will be developed by installing a subsea production system and a semi-submersible production platform. Gas will be exported via 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 31.2 billion. We hold a 20% interest in Gjøa. Production is scheduled to start in late 2010.
The PDO for Skarv was submitted in June 2007 and approved by the Norwegian Parliament in December 2007. Skarv is an oil and gas field located in the Norwegian Sea, in which we have an interest of 36.165% and for which BP is the operator. Skarv extends across three production licences (PL212/262 Skarv and PL 159 Idun). The field is being developed with an FPSO vessel and five subsea installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. Production is expected to start in August 2011, and the total development cost is estimated by the operator BP to be NOK 36.4 billion.
Tyrihans, in which we hold an interest of 58.8%, is located in the Norwegian Sea and consists of two hydrocarbon accumulations: 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, four dedicated production/gas injection and one for injection of raw sea water. 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 14.9 billion.
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. The fields are located in the North Sea. Three four-slot templates will be installed, and production will be transported to the Gjøa installation in a common pipeline. The total investments for the project are estimated to be NOK 7.9 billion. Production is scheduled to start in late 2010.
The Yttergryta subsea gas and condensate field development, with an investment value of approximately NOK 1.4 billion, is an excellent example of a relatively small but significant project in our portfolio, since it was developed so quickly. The discovery was made in the summer of 2007 and the PDO was submitted in January 2008. Production drilling commenced in September 2008 and the wellstream will be tied back to Åsgard B platform via Midgard flow line for processing and further export. We hold a 45.75% interest in the project. Production started in January 2009.
The table below shows some key figures for our major development projects.
The following projects are being developed on the NCS to give existing installations a new lease of life or exploit new opportunities.
Oseberg Low Pressure involves the installation of two new production manifolds for low-pressure wells with tie-in to second stage separators. Production is planned to start in late 2009.
The Snorre Redevelopment project is defined as an IOR project and will contribute to achieve the Snorre Unit and Vigdis overall oil recovery ambition. The project includes a water injection pipeline from Statfjord C to the Vigdis field.
The Statfjord Late Life project will convert Statfjord into a mainly gas-producing field by changing the drainage strategy. 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 19.6 billion.
Troll Field projects includes the Troll B Gas Injection project and the Troll A P12 Pipeline Project. The main goal for these projects is IOR from Troll B and enabling the Troll field to maintain an average gas export capacity of 120 million standard cubic metres per day and a long term gas export capacity of 30 giga standard cubic metres per year.
The Troll B Gas Injection project includes two gas injectors in the Troll West Gas Province south. Start up is planned in 2011.
The Troll A P12 project includes a new 62.5 kilometres 36 inch pipeline between Troll A and Kollsnes, modifications on Troll A and interface with Kollsnes plant. Pipeline is planned to start in late 2011.
The Troll C - O2 Template, which will be located north west of the Troll C platform, is defined as an IOR project. The O2 Template will be tied back to the existing O1 Template, which is tied back to Troll C. Drilling 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. Production is planned to start in 2010.
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.
126.96.36.199 Operations North Sea
Operations North Sea covers a major part of StatoilHydro's production activity on the NCS, and there is focus on increasing and prolonging production in the area with priority on Improved Oil Recovery and the exploration and development of new fields.
Our producing fields in Operations North Sea are Troll, Fram, Sleipner, Kvitebjørn, Visund, Grane, Brage, Veslefrikk, Huldra, Glitne, Volve, Heimdal, Vilje and Vale. The area is dominated by the production of natural gas, as 59% of the equity production in 2008 was gas. The petroleum reserves are located under water depths of between 80 and 330 metres.
In 2008, StatoilHydro's share of the area's production was 250 mbbl of oil, condensate and NGL per day and 49 mmcm (1,732 mmcf) of gas per day, or 558 mboe in total per day.
Brage is an oilfield east of Oseberg in the northern part of the North Sea. The oil is sent piped to Oseberg and on through the pipeline in the Oseberg Transport System to the Sture terminal. A gas pipeline is tied back to Statpipe. A new discovery in the Knockando area in the early autumn proved very successfully and came on production in October this year.
Fram is connected to the Troll C platform for processing. Oil production started in 2003, and gas exports started in October 2007.
Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS using a stand-alone production system.
Grane is the first field on the NCS to produce heavy crude oil and is StatoilHydro's largest heavy oil field. The field is located to the east of the Balder field in the northern part of the North Sea. Oil from Grane is piped to the Sture terminal, where it is stored and shipped. Injection gas is imported to Grane in a pipeline from the Heimdal facility. As a consequence, Grane will, after around 25 years of oil production, produce the injected gas.
Heimdal is a gas field located in the northern part of the North Sea. Heimdal mainly operates as a processing centre for other fields. Huldra, Skirne and Vale deliver gas to Heimdal, and gas from Oseberg is also transported via Heimdal. Heimdal had reduced regularity in 2007, which contributed to reduced production on Heimdal Vale and Huldra.
Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. Condensate from the Sleipner field is transported to the gas processing plant at Kårstø. The gas from Sleipner has a high level of carbon dioxide, which is extracted on the field and re-injected into a sand layer beneath the seabed to reduce the carbon dioxide emissions to the air. We are currently exploring several prospects and discoveries in the Sleipner area that can potentially be tied in to Sleipner.
In November we started test production for oil in the thin oil layers in the gas province of Troll East.
Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. Huldra is located in the Viking Graben and developed by a (normally unmanned) platform, remotely controlled from the Veslefrikk field. Oil from Veslefrikk is exported through the Oseberg Transportation System, while gas is exported to Kårstø. Veslefrikk also processes condensate from Huldra.
The first oil flowed from the Vilje field to the Alvheim floating production, storage and offloading vessel (FPSO) on 1 August 2008. The Vilje field is located in the northern part of the North Sea, north of the Heimdal field. Vilje is the first StatoilHydro-operated field on the Norwegian continental shelf tied in to an installation that is run by another operator.
The Visund oilfield is located to the east of the Snorre field in the northern part of the North Sea. The field contains oil and gas in several tilted fault blocks with separate pressure and liquid systems. The oil is piped to Gullfaks A for storage and export. Gas is exported to the Kvitebjørn gas pipeline and on to Kollsnes.
Volve is an oilfield located in the southern part of the North Sea approximately 8 kilometres north of Sleipner East. The development is based on production from the Mærsk Inspirer jack-up rig, with Navion Saga used as a storage ship to hold crude oil before export. Gas is piped to the Sleipner A platform for final processing and export. Volve started producing in February 2008.
The Kvitebjørn field resumed production on 27 January 2009 after being shut down since August 2008 due to a gas leak created by damage caused to the Kvitebjørn gas pipeline. The damage, which was caused by a ship's anchor, was discovered during an inspection, and production was shut down. Production resumed in January 2008 after surveys showed that the pipeline could be temporarily used for export. Repair work was scheduled for summer 2008, but during preparatory work for the repair, critical equipment underwent extensive functional testing and parts of the equipment failed. Consequently, the repair was postponed until 2009. While making a routine inspection on the pipeline after the planned maintenance stop in August 2008, we discovered a gas leak from the pipeline and production was immediately stopped.
Gas exports from Visund, which also uses the pipeline, were also affected by the pipeline damage.
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 2008 was 355 mbbl per day of oil, condensate and NGL, and 19 mmcm per day (682 mmcf per day) of gas, or 477 mboe per day in total. Operations West is the leading oil producing area on the NCS and, even after 20 years of production, we believe there are still substantial opportunities for increased value creation.
We 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 IOR, and they have resulted in a prolongation of planned production beyond the current licence period for several of the fields.
In 2008, Operation West performed five turnarounds within the scheduled time frame and without severe HSE incidents.
The Gimle field is a Gullfaks satellite field and is operated as a separate Unit. Permanent production started in May 2006, converting the Gimle exploration well drilled from the Gullfaks C platform into a production well. By the end of 2008, Gimle consisted of two producers and one injector, all drilled as long-reach wells from the Gullfaks C platform.
Due to high depletion of the reservoir, production from Gullfaks South, Statfjord reservoir was temporarily shut down in October 2008. The production will be started up again when a new water injection well has been drilled.
Gullfaks has been developed with three large concrete production platforms. Oil is loaded directly into custom-built shuttle tankers on the field. Associated gas is piped to the Kårstø gas processing plant and then on to continental Europe. Four satellite fields, Gullfaks South, Rimfaks, Gullveig and Skinfaks, have been developed with subsea wells remotely controlled from the Gullfaks A and C platforms.
Gulltopp. A long-reach well has been 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 well was started up in 2008 producing considerably more than initially estimated.
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.
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. Production started June 2008.
Oseberg Gamma Statfjord is developed with two wells from Oseberg B. Oil production started in April, and water injection commenced in August 2008.
Theta Cook was drilled as an exploration well from Oseberg C, converted directly to an oil producer and started in June 2008.
Oseberg Field Centre celebrated 20 years of production in December 2008.
The PL 089 asset includes the Vigdis, Borg and the Tordis fields. The Tordis field and the southern part of the Borg field have been developed with seven subsea satellites and two templates tied back to Gullfaks C, where the oil and gas is processed and stored for offshore loading and export. A subsea separator, boosting and injection unit was installed on Tordis in 2007 (Tordis SSBI), and most of the water from Tordis was injected through a dedicated water injection well into the Utsira formation.
A leakage of produced water through the seabed was observed in May 2008, and the water injector was shut down resulting in reduced production from Tordis. The Tordis SSBI is planned to be started up in late 2009 or early 2010 with an alternative solution for the produced water disposal.
The Vigdis field was developed in 1997 with three subsea templates with a well stream through pipelines connected to Snorre A, where the oil is stabilised and exported to Gullfaks for storage and loading. The northern part of Borg is also produced via the Vigdis templates. The Vigdis Extension Phase 2 project was completed early in 2008.
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.
By July 2008 the Snorre field had produced 1000 mmboe of oil since field start-up.
Inspection revealed internal damage to three risers on Snorre B in the autumn of 2008, resulting in shut-down of risers and reduced production. The risers are expected to be replaced in late 2009 or early 2010.
Statfjord has been developed with three fully-integrated platforms supported by gravity base structures featuring concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Associated gas is piped through the Tampen link to the UK or, alternatively, to the Kårstø gas processing plant and then on to continental Europe. Three satellite fields (Statfjord Nord, Statfjord Øst 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.
During modification work in the equipment shaft on 24 May 2008 an oil leakage from hot-tap equipment occurred. This resulted in an explosive atmosphere in parts of the shaft, and 50-70 cubic metres oil was pumped to sea to avoid escalation. Most of the personnel on board were evacuated, and no personal injury occurred.
Due to integrity problems, the Statfjord Nord Satellite injection facility was shut down in November 2008. The field's production is currently reduced and is expected to be shut in early 2009. Equipment will be replaced during 2009.
Our producing fields in the Operations North area are Åsgard, Mikkel, Heidrun, Kristin, Norne, Urd, Njord and Snøhvit. The Yttergryta field started production in January 2009 and the Alve field started production in March 2009.
Our share of the area's production in 2008 was 250 mbbl per day of oil, condensate and NGL, and 46 mmcm per day (777 mmcf per day) of gas, or 314 mboe in total per day.
This region is characterised by petroleum reserves located at water depths between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult and have challenged the participants to develop new types of platforms and new technology, such as floating processing systems with subsea production templates. We plan to increase efficiency by further coordinating our operations in the area and by stemming the decline in production from the mature fields through increased seismic activity and well maintenance. In addition, we intend to expand our activities by utilising our installed production and transportation capacity before building new infrastructure.
The Heidrun platform is the largest concrete tension leg platform ever built. Most of the oil from Heidrun is shipped by shuttle tankers to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden in Norway. Additional gas volumes are exported through the Åsgard Transport System (ÅTS) to gas markets in continental Europe.
Kristin is a gas condensate field in the south-western section of the Operations North area. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and 170 degrees Celsius, respectively - are higher than any other developed field on the NCS. The stabilised condensate is exported to a joint Åsgard and Kristin storage vessel, and the rich gas is transported to shore via the ÅTS to the gas processing facility at Kårstø. In 2008, the last of twelve wells was completed and entered into production.
Mikkel is a gas and condensate field. Production from two seabed templates is tied to the subsea installation at Midgard for onward transport to the Åsgard B gas 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.
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.
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 offshore.
The natural gas is transported to shore through a 143-kilometre long pipeline and it is landed at Melkøya, where it is processed at our LNG plant. This plant 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 some uncertainties related to the timing of regular and stable operations. Performance and regularity has been significantly improved through 2008. One major maintenance stop in 2009 is planned to achieve further increases in capacity and regularity.
The Urd fields, Svale and Stær, are located ten kilometres and five kilometres north of the Norne field, respectively. The fields are produced through subsea facilities with the well stream tied back to the Norne FPSO.
The Åsgard field contains three fields: Smørbukk, Smørbukk South and Midgard. The field was developed with the Åsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the Åsgard C storage vessel. The subsea production installations are 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.
Partner-operated fields represent a significant proportion of StatoilHydro's oil and gas portfolio. The portfolio ranges from development projects to mature fields, and the complexity of these requires detailed knowledge of the areas involved.
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 field complex in operation on the Norwegian Continental Shelf. The operator is ConocoPhillips. It consists of the fields Ekofisk, Eldfisk and Embla (StatoilHydro's interest 7.604%) plus Tor (StatoilHydro's interest 6.639%). Ekofisk has been upgraded with several new platforms over the years, the latest was 2/4-M installed in 2005. Several new projects are being studied; a new Ekofisk Hotel and fields centre, a new Ekofisk South drilling platform and redevelopment of Eldfisk. Final decisions are expected to be taken during the next few years. These new platforms are expected to extend the field life beyond the current licence period which ends in 2028.
Ormen 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 at the end of 2007. StatoilHydro continues 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.
StatoilHydro has a 14.82% interest in the ExxonMobil-operated field Ringhorne East. The unitised field started production in March 2006. Three production wells have been drilled from the Ringhorne facility. Oil is transported via Ringhorne to Balder for offshore loading. Gas is exported via Jotun into Statpipe. A fourth production well is planned.
Sigyn, operated by ExxonMobil, is a gas and condensate field located 12 kilometres southeast of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. Our interest is 60%. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform.
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.
There has been no decommissioning of StatoilHydro-operated fields during the last three years.
The Norwegian government has laid down strict procedures for the removal and disposal of offshore oil and gas installations under the Convention for the Protection of the Marine Environment of the Northeast Atlantic, known as the OSPAR Convention. However, there has been no decommissioning of StatoilHydro-operated fields during the last three years. On partner-operated fields there has been removal activity at Frigg and Ekofisk.
The global financial crisis and the subsequent recession which the global economy entered in the second half of 2008 has inevitably also had an impact on the global upstream oil and gas industry.
We have witnessed high volatility in oil and gas prices with concerns about availability dominating the first half of 2008. As the reality of the current global situation became more evident in the second half of the year, prices were subsequently impacted by downward adjustments to energy demand forecasts. This combined with a heightened risk aversion in speculative capital led to oil (Brent dated) being traded around USD 100 lower in December 2008 than at July 2008's all time high of USD 144 per bbl.
The industry has experienced a rapid increase in costs and capital expenditures over the past three to four years. This has been both as a result of limited competition and capacity in the service industry together with increased complexity of new projects. Although it could be expected that lower oil and gas prices and a lower volume of overall industry activity would contribute to a downward pressure on costs in the services and manufacturing industry, the technical challenges from increasing project complexity are unlikely to relent and will maintain an upward structural pressure on costs. In this environment, the industry is expected to increase its focus on cost control and capital deployment efficiency through tightening prioritisation among existing opportunities.
International politics and adjustments to energy policies have also continued to influence the business environment in resource-rich countries across the world. In the short to medium term, there could be a potential for improved access and fiscal terms in some regions as a result of the global turmoil. However, it will not reduce the need for a continuous focus on building and leveraging technical and commercial capabilities in order to turn oil and gas resources into productive capacity.
In recent years the industry has been characterised by a much higher level of competition, both in terms of the number and type of participants. This is unlikely to change. However, the sharp fall in share prices generally combined with the degree to which companies have access to capital to fund their future developments could act as catalysts to create change in the competitive landscape.
The long-term challenge of providing the world with secure, affordable and environmentally acceptable energy remains as challenging a reality as ever. In combination, the above developments within the industry are likely to result in a continued highly competitive environment for scarce international upstream opportunities.
Our strategy is to develop key positions in four focus areas: deep water, heavy oil, gas value chains and harsh environments. It is also the framework for new growth and portfolio optimisation.
In November 2008, StatoilHydro formed a strategic alliance with Chesapeake Energy Corporation, USA. The deal was completed in December 2008, with the purchase of a 32.5% interest in Chesapeake's Marcellus shale gas acreage in the Appalachia region of the northeastern USA. We paid USD 1.3 billion in cash and will pay a further USD 2.1 billion in the form of a 75% carry on drilling and completion of wells during the period 2009 to 2012. We have the right to a 32.5% participation in additional Chesapeake leases in the Marcellus shale play. In addition, the strategic alliance includes jointly exploring unconventional gas opportunities worldwide. The Chesapeake deal is another step in developing our gas value chain business expertise outside of Europe.
In March 2008, we signed an agreement with Anadarko to acquire its remaining 50% interest of the Peregrino heavy oil field in Brazil. The transaction was formally closed on 11 December 2008, making StatoilHydro 100% owner and operator of the field. The sale was effective 1 January 2008. The oil production is expected to start in 2011 and StatoilHydro will subsequently become one of the largest foreign oil producers in Brazil.
In 2008 we closed the sale of all our shallow water assets on the Shelf in the Gulf of Mexico (GoM) to Mariner Energy, Inc. for a cash consideration of USD 0.2 billion. The transaction was accomplished through the sale of our wholly owned subsidiary Hydro Gulf of Mexico, LLC. The sale was effective 1 January 2008. StatoilHydro remains one of the largest acreage holders in GoM deepwater with a strategic focus on high prospectivity deepwater areas. See note 3 business combinations for more information.
On 9 February 2008, Sincor in Venezuela was transformed into an incorporated joint venture known as Petrocedeño, S.A. and partially nationalized. Our share was reduced from 15% in Sincor to 9.677% in Petrocedeño. The agreed compensation has been received in full from the Venezuelan government.
Renegotiations of PSAs by the NOC in Libya have resulted in a reduced equity share. Our equity share of production in Murzuq was reduced from 8.0% to 2.4% effective as of 1 January 2008. Renegotiations are ongoing for Mabruk.
In April 2008 we completed the divestment of our interest in the UK fields Dunlin (28.76%) and Merlin (2.35%), the Brent Pipeline system and the Sullom Voe Terminal located on the Shetland Islands to Fairfield and Mitsubishi. Effective date of sale was 1 January 2008.
Over the last years we have been continuously accessing new exploration licences with high resource potential and moderate risk at the drilling stage to maximise the number of impact wells.
We have exploration licences in North America (Canada and the USA), Latin America (Brazil, Cuba and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Morocco, Mozambique, Nigeria and Tanzania), the European, Caspian and Russian area (Denmark, the Faroes, Ireland, the UK and Azerbaijan), and the Middle East and Asia (Iran, India and Indonesia).
Since 2002 we have carried out a major global screening of oil and gas basins to rebuild our exploration portfolio and we have added significant resources and targeted new high-potential basins globally. In 2008 we have been high-grading the portfolio to better utilize the overall competence pool of StatoilHydro internationally.
In 2008 we have also been further high-grading prospects for our short-term drilling programme. This entails prioritising and sequencing the most prospective drilling targets, optimising allocation of the rig fleet and providing a dedicated exploration organisation. We will continue to high-grade the portfolio in 2009 and the years to come. We plan to drill approximately 35 wells in 2009.
We completed 40 wells in 2008 and nine were ongoing at 31 December 2008. Of 40 wells, eight were announced as discoveries at year end, one was annouced in first quarter 2009 and 18 are currently under evaluation. Five of the nine ongoing wells were completed in the first quarter 2009, and one of them have been announced as a discovery.
The areas where we entered or had significant activity in 2008 are presented below.
StatoilHydro is operator and partner in prospects off the coast of Newfoundland and we have acquired 1100 square kilometres of oil sand deposits in Alberta.
The licenses were awarded based on a work expenditure bid with no legal obligation to perform the work program. If no work program is committed during the five first years, 25% of the bid has to be paid. The licenses were formally awarded in January 2009.
In 2008 a 3D seismic survey was acquired and processed on the two operated licenses in the southern part of the Jeanne d'Arc Basin near the Terra Nova Field. StatoilHydro holds a 50% interest in both licenses.
Drilling operations at the Mizzen exploration well in license EL 1049 in the frontier Flemish Pass basin started at the end of the year with StatoilHydro as the operator with a 65% interest. The well is expected to be completed in 2009.
In 2009 activities will also include the planned drilling of an exploration well on EL 1092 operated by Petro-Canada. We have a 50% interest in this license. Evaluation of the existing licenses will aim to identify new drillable prospects.
188.8.131.52.2 The USA
StatoilHydro has significant activities in the USA, with more than 400 leases in our Gulf of Mexico portfolio, and several wells to be drilled in coming years. We were also awarded 16 leases in Alaska in 2008.
US Gulf of Mexico
During 2008 we completed nine exploration wells and appraisal wells. Appraisal well Big Foot 3, sidetrack number two, has confirmed the same pay intervals of the previously announced discovery and sidetrack well. Three additional wells were ongoing at year end. Two of them have been completed in first quarter with one announced discovery.
We were awarded 21 deepwater blocks in the Central Lease Sale 205 in the first quarter of 2008. We participated in the Central Lease Sale 206 and Western Lease Sale 207 held in 2008. Following the sales we were awarded 16 leases from Central Lease Sale 206 and five leases from Western Lease Sale 207 . We participated in the Central Lease Sale 208 in March 2009.There are no work commitments associated with Gulf of Mexico leases.
In 2008 we have signed an agreement with the Colombian oil company Ecopetrol America inc. under which the two companies will form a Joint Exploration Team for the Gulf of Mexico and drill three or more wells in the coming years. Ecopetrol will farm in with interests of 20 to 30% in the wells covered by the agreement.
We have contracted two newly built rigs, Maersk Developer (joint contract with Woodside) and Discoverer Americas, which are expected to arrive in the Gulf of Mexico during 2009. These rig slots will be used to drill exploration and appraisal wells on our operated exploration acreage. In addition we expect to participate as a partner in a number of exploration and appraisal wells.
We have interests in eight exploration licences in four different basins in offshore waters in Brazil. We are the operator of four of the licences.
We have one commitment well in BM-CAL-10, one in BM-CAL-7, two commitment wells in BM-C-33 and one commitment well in licence BM-C-47 from the 9th Bid Round, awarded in March 2008.
A 30% interest in blocks S-M-1105 and 1109 and the operatorship and a 40% interest in block S-M-1233 in the 8th Bid Round are still pending award by the government.
One exploration well spudded in 2008 in block BM-J-3 was completed in 2009. Petrobras is operator, and our share is 40%.
We are the operator and have 75% interest in the exploration phase for the Hassi Mouina block. This block extends over 23,000 square kilometres and is situated in the western/central part of the Sahara in an under-explored area.
Three discoveries were announced in 2008. In 2008 we were granted an additional two year exploration period which expires in March 2010. The extension included a 30% relinquishment of the licence area.
All commitments in the licence are fulfilled. In 2009 two additional appraisal wells will be completed. In addition to this a 3D campaign will be carried out across the discovery regions of the block.
During 2008 an internal team has worked on maturing the technical solutions for a possible commercial development of the Hassi Mouina discoveries.
StatoilHydro operates three exploration licences in Libya totalling over 23,000 square kilometres.
Area 94 covers an area of 9,849 square kilometres on the south-eastern Cyrenaica Platform with a commitment of one exploration well and 2D seismic. The commitment well was spudded in 2009. We have a 100% interest in this area.
Area 146 covers an area of 2,492 square kilometres in the Murzuk basin with a work commitment of 2D seismic and two exploration wells. We have a 100% interest in this area.
Area 171 covers an area of 11,305 square kilometres in the Kufra basin with a work commitment of two exploration wells and 2D seismic. The first commitment well was drilled in 4Q 2008. We have a 50% interest in this area.
In addition, we have a 20% exploration interest in Area 186, operated by Repsol. Nine wells were drilled during 2008.
We are operator with an 80% interest in two offshore exploration licences located in the Mediterranean, west of the Nile Delta in water depths ranging from sea level to 3000 metres. Production sharing agreements for both blocks were signed in July 2007.
El Dabaa Offshore (Block 9) covers an area of 8368 square kilometres. We are committed to drilling one exploration well and conducting 2D and 3D seismic surveys over a four-year period. We have acquired and are evaluating the seismic surveys. Drilling is planned to commence in 2010.
Ras El Hekma Offshore (Block 10) The block covers an area of 9802 square kilometres. The related work commitment includes 2D and 3D seismic surveys over a four-year period. 2D seismic acquisition and processing is complete. 3D seismic has been acquired and processing is scheduled for completion in 2009.
StatoilHydro holds interests in blocks 4/05, 15, 15/06, 17, 31 and 34 in Angola. Twelve wells were completed in 2008, with four announced as discoveries.
Block 4/05 in which we have a 20% interest is operated by Sonangol. The licence was given a two year extension with a well commitment. One exploration well was drilled in 2008.
Block 15 exploration licence with ExxonMobil as operator has expired. Areas with proven oil have been converted to Development Area (DA) and Provisional Development Areas (PDA). A total of 36 exploration and appraisal wells have been drilled on the original Block 15 and offspring DA's and PDA's. In 2008 two appraisal wells were drilled. We have a 13.33% interest in this block.
Block 15/06 in which we have a 5% interest is operated by Eni. The work commitment for Block 15/06 is extensive, covering 3D seismic surveys and the drilling of eight wells, to be carried out during the first five years of the exploration phase. The 3D commitment was fulfilled and two of the eight exploration wells were drilled in 2008, both announced as discoveries.
Block 17 in which we have a 23.33% interest is operated by Total. To date, a total of 32 exploration and appraisal wells have been drilled and all exploration commitments have been met. In 2008 two exploration wells were drilled.
Block 31 in which we have 13.33% interest is operated by BP. In 2008, five exploration wells were completed with two announced discoveries and to date a total of 26 exploration wells have been drilled in the block. The licence was given a two year extension with a commitment of four wells. The exploration period ends in 2010.
Block 34 in which we have a 50% interest is operated by the Angolan national oil company Sonangol P&P, and we are the technical assistant to the operator. In 2005, Sonangol P&P signed an agreement with the concessionaire to enter into the second exploration phase for Block 34 with a one well commitment. The licence was given a three year extension with no additional well commitment. The period expires in 2011.
StatoilHydro is operator for two deepwater exploration licences, OML 128 and OML 129. In addition, we have shares in two exploration licences, OPL 315 operated by Petrobras and OPL 242 operated by Ocean Energy (Devon).
OML 128. We have a 53.85% interest in OML 128. The Agbami field straddles OML 127 and OML 128. [OML 128] came on stream in July 2008. The remaining prospectivity in the licence will be re-assessed in 2009, based on information from the Bilah and NnwaDoro evaluations.
OML 129. We have a 53.85% interest in OML 129. There are two discoveries in the block, Bilah and Nnwa. Only one well has been drilled in the Bilah condensate discovery.
The Nnwa discovery extends into the Shell-operated Block OML 135 (known as the Doro structure). The joint StatoilHydro and Shell subsurface project which was started in 2007 was completed mid-2008 and the results have been presented to the Nigerian Authorities.
OPL 315. We have 45% interest in block OPL315. The licence is committed to carry out a work programme by February 2011 consisting of one well and a seismic survey.
OPL 242. We have a 15% interest in OPL 242. All exploration obligations have been fulfilled and we are in the process of relinquishing the licence.
We had interests in OPL 324 and OPL 256 but these blocks were relinquished in 2008.
StatoilHydro is operator with a 100% interest in Block 2. The total area of Block 2 is 11,099 square kilometres and it lies in water depths of between 400 and 3000 metres. This is a frontier area, as no wells have been drilled this far from the coast.
The exploration period started in 2007 and is divided into three stages:
A 6200-kilometre 2D seismic survey was acquired during the first quarter of 2008. Final processed data was delivered in January 2009. According to the latest estimates the earliest time for first drilling will be in 2011.
Our Statoil UK subsidiary produces oil and gas and conducts exploration on the UK continental shelf, where we have interests in more than 100 North Sea and Atlantic margin blocks.
StatoilHydro is a 30% partner in a group of Chevron-operated exploration licences west of Shetland. In late 2008 drilling commenced on an exploration well on Rosebank / Lochnagar North.
In 2008 Hess drilled a discovery well on the Amos Prospect which is located four kilometres south of Schiehallion. StatoilHydro has a 17.65% interest in this discovery.
In 2008 a high resolution 3D seismic survey and a pilot ocean bottom cable seismic programme were acquired over the Mariner Field. Also in 2008, a well was drilled on Bressay and tested. In addition, in this heavy oil area, StatoilHydro completed a well on the Broch Prospect (9/11e-14).
The Mariner and Bressay heavy oil fields have been established as development projects but with further appraisal drilling ongoing. These fields are described in report section 184.108.40.206.1 Operational review, International E&P-Fields in development and production-Europe, Caspian region and Russia-United Kingdom.
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.
A further appraisal well (SDX-5) was spudded in the south-eastern part of the structure in 2008, and is expected to be completed in 2009.
We signed an exploration, development and production sharing agreement (PSA) in 1998, with BP as operator, covering the Alov, Araz and Sharg structures.
We have a 15% interest in this PSA, which is located roughly 150 kilometres south-east of the Azeri capital of Baku. The contract area covers about 1400 square kilometres and is located in water depths of 450 to 800 metres. The structures are located in the area of the Caspian Sea that is the subject of a dispute between Azerbaijan and Iran, and, since the contract was signed, Iran has claimed that parts of the area are in Iranian waters. Negotiations with SOCAR, the State Oil Company of Azerbaijan, have resulted in a freezing of the licence fee until the border issue is resolved.
StatoilHydro was awarded a 50% interest in one lease with operatorship in 2008. We are now the operator of five licenses in the Faroe Islands and partner in one in which Chevron is the operator.
3D seismic operations have been conducted in licence 009 and 011 during 2008.
StatoilHydro has agreements which give us interests in the deepwater Kuma and Karama blocks off Indonesia, where the water depth ranges from 1000 to 2000 metres.
In 2008 we acquired 2297 square kilometres of 3D seismic data over the Karama PSC and have fulfilled our seismic work obligation. Within the Kuma PSC, 1044 square kilometres of 3D seismic data have been acquired. A contract for using the drillship Global Santa Fe Explorer was signed by a consortium of six oil companies including StatoilHydro in 2008. The contract is for two years with a one year extension option. The three commitment wells in the Karama PSC will be drilled in 2011, while the Kuma well is expected to be drilled in late 2010 or early 2011. Drilling preparations will be initiated for all operated and non-operated wells.
A two year extension of the Memorandum of Understanding (MOU) with Pertamina was signed in October 2008.
StatoilHydro has an agreement with the Indian state oil company Oil and Natural Gas Corporation (ONGC) that gives us access to exploration acreage off India, mostly in deep waters.
In July 2008 the Indian Government approved the assignment of a 10% participating interest in Block KG-DWN-98/2 to StatoilHydro in accordance with a previously signed farm-out agreement. Block 98/2 is located on the East coast of India in the Krishna Godavari Basin. ONGC is operator with a 65% interest. The block covers an area of 7295 square kilometres. Several discoveries have been made in the block, and both gas and oil have been encountered.
This section describes our international oil and gas reserves and explains changes that have had an effect on the reserves balance.
The proved reserves of the international business area increased by 2% in 2008, from 1039 mmboe to 1055 mmboe.
Several purchase and sale agreements and change of ownership were finalised in 2008 having effect on the international reserves balance:
- The purchase of Anadarko's 50% share in Peregrino was finalised late in 2008 and contributed positively to the international reserves balance.
- The sale of our Shelf portfolio in Gulf of Mexico was effective from 1 January 2008, resulting in reduction in proved reserves.
Acquisition of a share in the Marcellus shale gas play in the USA was completed December 2008, but no reserves are booked in 2008. With few wells in production, limiting the reserves that can be booked by the year end, StatoilHydro has not included the Marcellus shale in the 2008 proved reserves estimation.
North American Oil Sands Corporation was officially taken over by StatoilHydro in the middle of 2007, but the current maturity level and recovery techniques of the asset do not yet justify recognition of proved reserves.
The share of developed reserves at year-end is 536 mmboe, which is up 17.5% from 2007. Of the 2008 proved developed reserves, 406 mmboe are oil/NGL and 20.6 bcm (727 bcf) are natural gas. The increase in proved developed reserves is primary related to production start-up of developments in Angola and future development in fields in Azerbaijan and Libya.
The following table shows our total international proved reserves as of 31 December for each of the last three years. Further information on reserves can be found in note 34 - Supplementary oil and gas information - to our Consolidated Financial Statements.
This section describes our production outside Norway.
StatoilHydro's petroleum production outside Norway amounted to an average of 290 mboe per day entitlement production and 465 mboe per day equity production in 2008. The total annual entitlement production in 2008 was approximately 106 mmboe compared with 112 mmboe in 2007.
The first table shows our average daily entitlement production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2008, 2007 and 2006. New fields that came on stream in 2008 were Mondo and Saxi-Batuque in Angola, Deep Water Gunashli in Azerbaijan, Agbami in Nigeria and South Pars in Iran. In addition we purchased a 32.5% interest in the Marcellus shale gas acreage in the USA.
This section covers projects under development and fields in production. Pre-sanctioned projects including some discoveries in the early evaluation phase are also presented.
Exploration activities are described in report section 3.2.3, Operational review-International E&P-Exploration activity. This section often refers to a field's plateau production, which refers to yearly average equity production at plateau for a field 100% (not our share). Capacities also refer to the total field or facility, a 100% share.
The number of development wells as of 31 December 2008 for producing fields is provided under report section 3.2.5 Production above.
The total number of development wells in fields under development, that were already drilled or undergoing drilling as of year end 2008 was 127.
In Canada, oil sands represent a long term investment for the company and our Leismer Demonstration Project is on schedule. Offshore we have production from Hibernia and Terra Nova and two discoveries are under appraisal.
StatoilHydro is the operator of the Kai Kos Dehseh oil sands leases, and the first phase of the development is the Leismer SAGD Demonstration Project which will be developed with a capacity of 20,000 boe per day with initial production scheduled for late 2010. In 2007 we submitted an application to the Alberta regulatory authorities for the full 220,000 boe per day commercial SAGD project.
In 2007 we also submitted an application to the Alberta regulatory authorities for the construction of an upgrader to process bitumen into lighter synthetic crude. We withdrew this application in December 2008. Prohibitive construction costs, the state of the global economy, an uncertain oil price outlook and lack of legislative clarity are the main reasons for this decision. Oil sands are a long term investment for the company with a high degree of optionality in the timing of investments.
Discoveries Under Appraisal
The Hibernia Southern Extension project operated by ExxonMobil comprises the development of resources in several fault blocks to the south of the existing Hibernia Main Field. Fiscal negotiations with the provincial government began in 2008 and are still ongoing.. The field is planned to be developed via drilling from the Hibernia GBS platform. We have 10% interest in this field.
Terra Nova is producing from a floating production, storage and offloading vessel (FPSO), operated by Petro-Canada. Fifteen subsea producing wells are tied back to the FPSO. Terra Nova's production efficiency continues to be low due to a number of technical issues on the FPSO. Several initiatives are underway to improve production efficiency.
220.127.116.11.2 The USA
We have built a high quality deep water asset portfolio in the Gulf of Mexico by combining acquisitions and exploration. In 2008 we expanded into onshore gas through a 32.5% interest in Chesapeake Energy Corporation's Marcellus shale gas acreage.
We also formed a strategic alliance with Chesapeake to jointly explore unconventional gas opportunities worldwide.
The Marcellus Shale Gas play is located in the Appalachian region of the northeastern USA. In November 2008 we acquired a 32.5% interest in Chesapeake's Marcellus shale gas acreage. Production started in 2008 and drilling of new wells will continue in 2009. We also have the right to a 32.5% participation in additional Chesapeake leases in the Marcellus Shale play.
Discoveries under appraisal, Gulf of Mexico
St. Malo, located at Walker Ridge 678, is also an oil field operated by Chevron. We have 6.25% interest in St. Malo. In 2008 we drilled another appraisal well. St. Malo and Jack are in approximately 2,100 metres of water and separated by approximately 40 kilometres. The current plan is a joint development of the two fields and Chevron has formed a joint integrated project team for this purpose. In 2009 we plan to make a concept selection for the development of the two fields and to start front-end engineering and design.
We have a 27.5% interest in Big Foot which is a Chevron-operated discovery located in WR29. During 2008 appraisal drilling took place and will continue into 2009. We expect to make a concept selection in 2009.
The Caesar unit in which we have a 23.55% interest is operated by Anadarko and covers blocks GC683 and some surrounding blocks, including the Tonga discovery. A joint development is planned for Caesar and Tonga and the selected concept is a 4-well subsea tieback to the Anadarko-operated Constitution platform. During 2008 an appraisal well was drilled.
Fields under development
In Thunder Hawk we have a 25% interest and Murphy is the operator. It is located at Mississippi Canyon 734. The field is being developed with a floating semi-submersible platform 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
Lorien, located at Green Canyon 199, produces through a two-well subsea tie-back to Shell's Bullwinkle platform. Following Hurricanes Gustav and Ike, Lorien was shut-down due to damage to Bullwinkle. Production resumed in January 2009.
The Murphy-operated Front Runner field is located in Green Canyon 338/339. Production in 2008 has been relatively stable. However, due to complex geology with relatively weak reservoir communication, the production from Front Runner has been significantly lower than expected at production start in 2004. The gas-export line was damaged by Hurricane Ike. Gas export resumed in January 2009.
We also had production in 2008 from two small deepwater fields called Zia and Seventeen Hands. They are located at Mississippi Canyon 496 and 299, respectively.
Our current asset portfolio in Latin America comprises our interest in the heavy oil Peregrino development project in Brazil and an onshore extra heavy oil producing asset, the Petrocedeño Mixed Company, in Venezuela.
The Petrocedeño Mixed Company was formerly known as the Sincor project.
StatoilHydro has a long term view on its presence in Venezuela and has a 9.677% interest in the Petrocedeño project.
The Petrocedeño project involves the exploitation of extra heavy crude oil from the reservoirs in the Orinoco Belt. A diluting component is added in order for the extra heavy oil to be transported by pipeline to the coast where it is upgraded to a light, low-sulphur syncrude, destined for the international market. Petrocedeño, S.A., owned by the project partners, operates the field and is responsible for the development, operation, upgrading and marketing of its products.
In 2008 the Sincor project was transformed into an incorporated joint venture named Petrocedeño, S.A., which became operational starting from 9 February 2008. Our share was reduced from 15% in Sincor to 9.677% in Petrocedeño.
A major maintenance turnaround was carried out in early part of 2008. The maintenance tasks were performed as planned, although some of the important modification projects were postponed to 2009. During the turnaround, a much higher volume of extra heavy oil was produced than originally planned and marketed as diluted crude oil.
In 2008, we acquired Anadarko's remaining 50% share of the Peregrino oil field and became 100% owner and operator. By 2012 StatoilHydro is expected to become the largest international offshore operator in Brazil in terms of production.
The Peregrino field is a heavy oil field located in approximately 120 metres of water in the prolific Campos Basin offshore Brazil, about 85 kilometres off the coast of Rio de Janeiro.
The field is being developed with a Floating Production Storage and Offloading Vessel (FPSO) and two well head platforms with drilling capability. The first oil production is planned to come on stream in 2011 and we expect to reach a plateau production of 100 mboe per day within the first year of production. All development contracts have been entered into and the execution phase of the project is in progress.
We have interests in onshore producing assets in the North African countries of Algeria and Libya.
Our current development and production portfolio in Sub Saharan Africa comprises blocks 4/05, 15, 17 and 31 offshore Angola, and the production licences OML 127 and OML 128 offshore Nigeria.
Our main asset, In Salah, gives us a considerable gas position in Algeria. We are also producing liquids from the In Amenas field.
Fields in production
In addition to the operating activities at In Salah, drilling operations and a compression expansion project have been ongoing in 2008. The activities in 2009 will include startup of some of the compression stations and further work on preparing for the In Salah Southern Fields development. StatoilHydro is in charge of the compression project.
The In Amenas onshore development is the fourth largest gas development in Algeria, containing significant liquid volumes. 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. This project is currently producing at plateau level. The rights and obligations are governed by a production sharing contract, giving BP and StatoilHydro access to a share of the liquid volumes only. A continuous production drilling campaign is ongoing. Further preparations and maturing of the In Amenas Compression Expansion project is ongoing and will continue in 2009 with BP as lead.
The overall security and political situation continues to be sensitive and is monitored continuously. Appropriate measures are assessed based on the perceived risk level. This risk monitoring will continue through 2009.
We are well positioned for growth in Libya with two producing assets and our focus on technology-based IOR projects.
Fields in production
A Field Development Plan (FDP) for Mabruk Phase I (previously denoted phase V), covering the Dahra South East is expected to be approved by the Libyan National Oil Corporation (NOC) in 2009.
The NC 186 licence in the Murzuk area consists of several fields. We are producing from the A, B, D and H fields which were developed with one common processing facility. The oil from these fields is blended with oil from the neighbouring licence NC 115 and is then transported by pipeline to the Az Zawia terminal west of Tripoli.
The I/R oil field, which straddles across both the NC 115 and NC 186 licenses, started production in June 2008.
A FDP for the J and K fields was approved by both the partnership and NOC. The fields are expected to start production in 2010.
To avoid extensive flaring from the NC 186 fields, a gas utilization project is ongoing, with the aim of using the associated gas from the oil production for electricity generation. Start-up of the project is expected in 2009, when planned flaring in the 186 area will be eliminated.
The Angolan continental shelf is the largest contributor to StatoilHydro's production outside Norway. It yielded 117 mboe per day in entitlement production at the end of 2008, 40% of our total international oil and gas output.
FPSO vessels with subsea wellheads are the preferred oil-field development solution in deepwater Angola due to the great water depths, high production volumes and lack of infrastructure.
Block 17 is operated by Total and our interest is 23.33%. Production from the block currently comprises the Girassol, Jasmim, Dalia and Rosa development areas. The Girassol and Jasmim development areas both produce over the Girassol FPSO. The plateau production level, reached in 2005, was 250 mboe per day. The second FPSO, Dalia, has been producing at peak level of 240 mboe per day in 2008. Rosa is a tie-back field to the Girassol FPSO. The combined production on the Girassol FPSO has a capacity limit of 280 mboe per day.
The Pazflor project comprises the discoveries Perpetua, Acacia, Zinia and Hortensia. Pazflor was sanctioned in 2007. The FPSO is expected to have a production capacity of 200 mboe per day, with start-up scheduled in 2011.
The installed production capacity on block 17 will be approximately 700 mboe per day, after Pazflor starts production.
Work is ongoing to pursue the common development of four additional discoveries, Cravo, Lirio, Orchidea and Violeta (CLOV).
The Gas Export Project (GEP)
Block 15 is operated by ExxonMobil and our interest is 13.33%. Production from the block currently comprises five FPSOs for Kizomba A, Kizomba B, Xikomba, Kizomba C-Mondo and Kizomba C-Saxi Batuque. Mondo and Saxi-Batuque came on stream on 1 January and 1 July 2008 respectively.
Kizomba A, which encompasses the Hungo and Chocalho discoveries, commenced production in 2004. Marimba North is a tie-back to the Kizomba A FPSO. The peak production limit on the FPSO was then increased to 270 mboe per day, of which Marimba North produces 35 mboe per day. Kizomba B encompasses the Kissanje and Dikanza discoveries. Kizomba A and Kizomba B came off plateau during 2008. Xikomba is a small, isolated discovery producing from a leased FPSO. The combined Kizomba C production has already reached plateau levels of 200 mboe per day in 2008.
According to the PSA, all surplus gas from the offshore blocks is to be delivered to Sonangol. The Gas Gathering Project for Block 15 will collect all surplus gas from Kizomba A, B and C including satellites. The trunkline will connect to AnLNG piping going to AnLNG.
Work is also ongoing to pursue the development of two medium-sized discoveries: Clochas and Mavacola, which are called Kizomba Satellites Phase 1.
Block 31, an ultra-deep water licence, is operated by BP, and our interest is 13.33%. The common development of the first four discoveries in the northern part of the block, Plutao, Saturno, Venus and Marte (PSVM) was approved by the Concessionaire in July 2008. The PSVM will be developed via a new FPSO with a production capacity of 150,000 boe per day.
Work is also ongoing to pursue the development of PAJ, comprising the discoveries Palas, Astraea, and Juno.
Two to four additional production hubs are expected to be launched in this block.
Block 4/05 is operated by Sonangol P&P and our interest is 20%. This block includes the Gimboa field which was sanctioned in 2006. Peak production from the field is expected to be 35 mboe per day and the FPSO is expected to commence production in first half of 2009.
Work is also ongoing to pursue the development of Gimboa Phase 2, two small-sized discoveries, UMC-6 and UMC-7.
In Nigeria, we have an interest in the largest deepwater producing field, Agbami.
The Agbami field in deep waters off Nigeria has been developed with subsea wells connected to an FPSO. Production started up on 29 July 2008. Agbami, operated by Chevron, is located in licences OML 127 and OML 128, approximately 110 kilometres off the Nigerian coastline. Our interest in the unitised field is 18.85%. The Agbami field is expected to reach a plateau production of 250 mboe per day by late 2009.
There is renewed vigor by the Nigerian government to restructure the oil and gas sector. StatoilHydro is following the developments in the country. So far it is not possible to determine the impact of a potential regulation restructure.
With the Supreme Court judgement on the validity of the 2007 presidential election still being awaited, the political situation remains unstable, but there has been an improvement in the security situation in the strategically important oil region in the Niger Delta. The overall security and political situation is monitored continuously. We have developed rigorous security measures to protect our personnel and other assets. Appropriate measures are continuously being assessed based on the perceived risk level.
18.104.22.168 Europe, Caspian and Russia
We have interests in production and development assets in Ireland, the United Kingdom, Azerbaijan and Russia in addition to early phase evaluation assets in the United Kingdom and Denmark.
The Russian Shtokman field is an important part of our strategy to pursue opportunities in harsh arctic environments. Our ambition is to continue to build on our portfolio whilst pursuing opportunities to improve on the production and cost performance of our current producing assets, and bring existing discoveries through to development.
We also have representative offices in Kazakhstan and Turkmenistan.
StatoilHydro has been present in the United Kingdom (UK) since the early 1980s. We hold interests in four producing fields, Alba, Schiehallion, Jupiter and Caledonia and have several oil fields under appraisal, Bressay, Mariner, Mariner East and Rosebank.
Discoveries under appraisal
Rosebank (in which we have a 30% interest), a discovery made by Chevron in 2004, is located west of the Shetland Islands. The operator is currently drilling further appraisal wells.
Fields in production
Schiehallion, commissioned in 1998, is a floating, production, storage and offloader (FPSO) located west of the Shetland Island, and the operator is BP. We have 5.88% interest.
Jupiter is a gas field located in the southern part of the UK North Sea in which we have 30% interest. The operator is ConocoPhillips.
Caledonia is a small single well tie-back to the Britannia platform in the central part of the North Sea in which we have 21.32% interest, and where the operator is Chevron.
All fields are in a mature to late life stage of production.
We have 36.5% interest in the Corrib gas field which lies on the Atlantic Margin north-west of Ireland. The Corrib field development, operated by Shell, was sanctioned in 2001 and production start-up is currently expected at the end of 2010 or early 2011.
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 2004. Project execution was suspended in 2005 due to protests by local landowners. Following a comprehensive safety review of the onshore pipeline by the Irish authorities, work on the project recommenced in 2006. As part of a community consultation process, alternative pipeline routes have been identified, and the final planning application for the onshore pipeline is expected to be made in the second half of 2009. Currently, six of the seven offshore wells have been drilled. Construction of the gas terminal commenced in 2007 and is ongoing.
In the Danish sector of the North Sea we are a partner in the Hejre field, an undeveloped oil field.
Discoveries under appraisal
StatoilHydro has been present in Azerbaijan since 1992. 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 and the Alov, Araz and Sharg prospects described in the report section 22.214.171.124.2 Operational review-International E&P-Exploration activity-Europe, The Caspian Region and Russia-Azerbaijan.
We have an 8.5633% interest in the BP-operated ACG PSA. Production from the field commenced in 1997. The field has subsequently been developed through the ACG Phase I-III developments, which were brought on stream in the period 2005 to 2008. Additional production through the Chiraq Oil Project is expected to commence in 2013.
A gas leak originating underground was detected on the seafloor beneath the Central Azeri platform in the third quarter of 2008 and production from the platform was temporarily shut down. Although limited production from Central Azeri was resumed in December 2008, the gas leak is expected to have a negative effect on the production from ACG throughout 2009.
Export of hydrocarbons. Currently, crude oil from ACG is transported to the Mediterranean Sea through the 1760 kilometres Baku-Tbilisi-Ceyhan (BTC) Pipeline, in which we participate with an 8.71% interest. In August 2008, a fire occurred at a pipeline bolt. However, the impact on production from ACG was limited and the pipeline was brought back in operation three weeks after the incident. In the fourth quarter of 2008, the BTC Pipeline had an export capacity of more than 900 mbbl of oil per day.
The Shah Deniz area covers 860 square kilometres and lies at a water depth of between 50 and 500 metres. BP is the field operator and we have a 25.5% interest. We are the operator of the AGSC company covering gas sales, contract administration and business development for the Shah Deniz stage I. We are also the commercial operator of the South Caucasus Pipeline system (SCP) for gas transport to markets in Azerbaijan, Georgia and Turkey.
Shah Deniz Stage I commenced production in December 2006. The Stage 2 development of Shah Deniz is progressing through the investment decision process and is presently in the concept selection stage. Field reserves support a significant Stage 2 development which is likely to be on a similar or larger scale to Stage 1.
The Caspian region has long been viewed as an area with a substantial risk of increased economic, social and political instability. Although the general situation has improved, there are still political disputes that remain unsolved in both Azerbaijan and Georgia, and the recent events in Georgia show that the risks should not be underestimated.
StatoilHydro has been present in Russia since the early 1990s. We have one producing field, the Kharyaga oil field, and a 24% ownership share in Shtokman Development AG responsible for the Shtokman development phase I.
The Shtokman gas and condensate field is located in the Russian Barents Sea, and the Shtokman agreement gives StatoilHydro a 24% equity interest in Shtokman Development AG in which Gazprom (51%) and Total (25%) are the other two partners. The owners have seconded personnel to Shtokman Development AG, which is responsible for planning, financing, constructing and operating the infrastructure necessary for the first phase of the development. Shtokman Development AG will own and operate the infrastructure for 25 years from the start of commercial production. The implementation of the project is subject to a final investment decision which is planned to take place in 2010.
Field in production
The Kharyaga field will be developed in stages according to the terms of the PSA. Oil production commenced in 1999, with Phase 1 production of 10 mboe per day utilising three existing wells. Phase 2 was launched in 2000 to increase oil production and develop additional reserves. An additional 11 wells were drilled during this phase. Phase 3 has now been initiated with the aim of increasing production from 20 to 30 mboe per day. This phase involves drilling of more production and injection wells, a process upgrade and installation of gas treatment facilities.
StatoilHydro has interests in the South Pars project in Iran and the Lufeng field offshore China.
We are also pursuing business development opportunities in the region, and have representative offices in Indonesia, Singapore and Australia and in selected countries in the Middle East. We are also qualified as "Non-restricted Operator" in Iraq and may thereby tender as operator for any field in the two upcoming licence rounds in the country in 2009.
Gas production from South Pars Phase eight started in August 2008 and from Phase six in December 2008. Production from the third and final phase, South Pars Phase seven, is expected to commence after the summer of 2009.
StatoilHydro entered the South Pars project in 2002 as operator for the development of the offshore part of the South Pars Phases six, seven and eight under a buy-back contract with a 37% share during the development phase. Upon completing the development phase, StatoilHydro's obligation includes providing certain services to the National Iranian Oil Company (NIOC) during the operations phase; however, our involvement will be phased out once we have recouped our costs for the project.
Based on the two discoveries on the Anaran block, Azar and Changuleh, StatoilHydro discussed a Development Service Contract with NIOC.
StatoilHydro has an exploration and development service contract with NIOC for the Khorram-Abad block in Lurestan province in south-western Iran. The block covers 7400 square kilometres, and the work programme includes acquisition of 600 square kilometres of 2D seismic data and the drilling of three exploration wells. The gathering of seismic data was completed in the fourth quarter of 2008. There are at present no firm plans to drill the first well in the work programme.
See report section 5.1.1 Risk review - Risk factors- Risks related to our business, for additional information concerning the risk of US sanctions related to activities in Iran.
The Company will not make any future investments in Iran under the present circumstances; however, it is committed to fulfilling its buy-back contract obligations, principally for the offshore part of the South Pars phases six/seven/eight project.
StatoilHydro opened its first office in China in 1982. Today, our activities involve operating the Lufeng field and business development.
Lufeng will probably be shut down during 2009.
In 2007 StatoilHydro entered into a strategic partnership with China National Petroleum Corporation ("CNPC") through the signing of a Memorandum of Understanding relating to domestic and international exploration and production, LNG value chain and research and development. This cooperation has now been expanded to also cover new energy.
Fossil fuels will continue to be the prime source of incremental energy supply for several decades to come - and natural gas is expected to continue to be the fastest growing fossil fuel in OECD markets.
According to the International Energy Agency's (IEA) World Energy Outlook for 2008, fossil fuels will continue to be the prime source of incremental energy supply in the decades ahead. However, on a regional level, the growth in demand for specific fuels will vary. In developing countries, coal is expected to see the fastest growth in demand, whereas natural gas is expected to continue to be the fastest growing fossil fuel in the OECD markets.
In the IEA reference scenario, the world primary demand for natural gas will expand by just over half between 2006 and 2030, to 4,400 bcm, a rate of increase of 1.8% per year. The share of natural gas in total world primary energy demand is expected to increase to 22% in 2030. Some 57% of the projected increase in gas demand comes from the power sector, pushing up its share of global gas use from 39% today to 45%. Inter-regional gas trade is projected to more than double towards 2030, from 441 bcm in 2006 to more than 1000 bcm in 2030. The European Union expects the biggest increase in import volumes.
Natural gas can substitute for other fuels in almost any application. In many global scenarios for the mitigation of climate change, there is an implicit assumption that gas use will increase. Thus, 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 several main gas-producing countries. In consequence, international natural gas markets will be influenced by policy decisions in key producing and reserve holding countries such as Russia, Iran, Algeria and Qatar.
From around 2010, it is expected that Europe will need additional supplies of piped gas and/or LNG in order to cover demand. Gas from the NCS is attractive in the European market due to its high regularity and geographical location. We therefore expect that demand for gas from Norway will continue to increase in our primary gas markets, as domestic gas production elsewhere in Europe continues to decline.
The international gas industry is driven by several trends that have implications for our business:
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.
According to the IEA World Energy Outlook 2008, the estimated annual growth in global gas consumption in the period 2006 to 2030 will be 1.8%, slightly less than the estimate from last year.
Growth in gas demand in OECD Europe in the same period is expected to be 1.0% per annum. This translates to a demand for gas in OECD Europe in 2030 of approximately 694 bcm - up from the current level of some 550 bcm. The share of gas in total primary energy consumption is approaching 25% in the OECD countries in Europe, and is expected to reach almost 30% in 2030. Approximately 60% of the growth in gas consumption in the period is expected to come from the electricity sector. The IEA expects continued growth in demand for all sub-sectors of the European natural gas market.
We market and sell our 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. Furthermore, we market gas sourced from producing areas other than the NCS. Other major gas suppliers in Europe are Gazprom in Russia, Sonatrach in Algeria and Gasunie in the Netherlands. We believe that the Norwegian natural gas exports will remain highly competitive due to their reliability, access to the transportation infrastructure and proximity to key European markets such as the UK, Germany and France. In addition, natural gas is an attractive source of energy from an environmental perspective since it emits far less CO2 than coal and oil.
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 become more involved in the UK market - Europe's largest and most liberalised natural gas market.
Langeled, a new export pipeline, was put into operation in 2007, connecting the NCS to Easington in the UK. Another new infrastructure project called the Tampen Link, a pipeline from the Statfjord field on the NCS to the existing Flags pipeline on the UK continental shelf, was also completed in 2007.
The recent dispute between Russia and Ukraine regarding gas transit highlighted the importance of Russian gas supplies to European markets. In the years ahead Russian supplies are expected to grow further, and in the longer term the EU is set to import some 80% of its natural gas. In order to diversify supplies, European countries and companies are actively seeking to establish alternative supply solutions, mainly through LNG, but also by establishing new pipeline infrastructure from the Caspian region and from North Africa.
We believe that Europe will need additional sources of natural gas. We are participating in increasing gas production in Azerbaijan, with the Shah Deniz field in the Caspian Sea as a key asset. Gas is already exported from Azerbaijan to Georgia and Turkey through the South Caucasus Pipeline (SCP). In order to bring gas even further west we are participating in the Trans-Adriatic Pipeline (TAP) that will connect the Italian market with gas flowing westwards from Turkey, through Greece and Albania.
As the European energy market undergoes deregulation and structural changes, we believe that natural gas will play an increasingly important role. This trend will be reinforced by 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 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.
For information about the EU Gas Directive, please see report section 3.10.3 Operational review-Regulation-Gas directive of the European Union.
StatoilHydro is a long-term and reliable natural gas supplier enjoying a strong position in some of the world's most attractive markets. We are the second biggest gas supplier in Europe and the sixth largest in the world.
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, respectively) entered into a joint venture for the development, operation and maintenance of a salt cavern gas storage facility near Aldbrough, on the east coast of Yorkshire and close to the Easington terminal. On completion, the storage facility will comprise nine underground caverns. Statoil (UK) Limited owns one third of the storage capacity being developed, of which the SDFI has 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 during 2009, with full commercial operation of the nine cavern facility achieved during 2011. The design capacity for the storage facility is expected to be 420 mmcm. StatoilHydro's share of the total development cost is estimated to be NOK 0.7 billion.
In Germany, we hold a 30.8% stake in the Norddeutsche Erdgas-Transversale, or Netra, overland gas transmission pipeline, and a 23.7% stake in Etzel Gas Storage through our subsidiary StatoilHydro Deutschland. Currently, Etzel Gas Storage is increasing the working gas capacity with nine additional caverns. All partners in Etzel Gas Storage are participating in this project. The project is expected to be finalised within the calendar year 2009, according to schedule.
In the US, Statoil Natural Gas LLC (SNG) markets gas to local distribution companies, industrial customers and power generators. 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 regasification terminal in Maryland on the US east coast. The terminal interconnects 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. LNG is sourced from our Snøhvit LNG facilities in Norway and from third party suppliers, both spot and mid-term arrangements. In 2008 we delivered cargo number 100 of LNG to the Cove Point terminal. 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 early 2009. The expansion reflects our focus on the growing liquefied natural gas market in the US, at the same time as market access through Cove Point is strategically important to a potential Snøhvit phase 2 and other LNG projects under consideration by StatoilHydro. In addition it gives us more flexibility in sourcing third party LNG to the terminal.
The respective future shares of StatoilHydro and the SDFI on the Cove Point terminal, in addition to extra capacity and related commitments, are subject to further consideration, and the outcome may therefore have an impact on the extent of future commitments assumed and reported by StatoilHydro.
In 2008 we entered into a strategic agreement with Chesapeake Energy Corporation. The agreement is particularly important for NG in several ways. Firstly, it adds a major building block to our gas value chain position already established in the US - the world's largest and most liquid gas market, and secondly, we gain access to large reserves produced close to the highest paying market in the US. Also, it significantly strengthens our US gas position, building on our existing Cove Point LNG position and our well-established gas marketing and trading organisation in Stamford and the competence in our organisation. The agreement entails that over time, we will market and trade significantly higher volumes compared to the volumes today.
StatoilHydro has a 25.5% share in the Shah Deniz field in Azerbaijan and is the commercial operator for gas transportation and sales activities for Stage 1 development and heading the partners sales committee for the Stage 2 development. Turkey is the main market for gas from Stage 1 of the Shah Deniz development, and in addition Georgia and Azerbaijan are also part of the gas sales portfolio. 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 2008 and is expected to reach the plateau production in 2009 (8.6 bcm annually).
The Stage 2 development of Shah Deniz is currently in the Concept Selection phase of the operator BP's Capital Value Process. Field reserves support a significant Stage 2 production and are likely to be larger than in Stage 1. 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, the European Union and Russia. The progress of the marketing activities has been hampered by the lack of an intergovernmental agreement between Turkey and Azerbaijan on volumes for transit and sales into the Turkish market.
In February 2008, StatoilHydro signed an agreement with the Swiss EGL Group to establish a joint venture to develop, build and operate the Trans Adriatic Pipeline (TAP) from Greece, through Albania to Italy. StatoilHydro joined the TAP project as part of our efforts to provide attractive export options and ensure competition for the Shah Deniz gas in the European market, hence TAP will be competing with other pipelines to attract potential customers for gas from Shah Deniz. A final investment decision is linked to the Shah Deniz Stage 2 development.
The Norwegian gas pipeline system has been developed over the last 30 years to become an integrated gas pipeline system, connecting gas producing fields via processing plants on the Norwegian mainland to receiving terminals in Europe.
Norway's gas pipelines currently have a total length of 7800 kilometres. Since 2003, all gas pipelines with third party customers are unitized into a single joint venture, Gassled, with regulated third party access. The Gassled system is operated by the independent system operator, Gassco AS, a company wholly owned by the Norwegian State. In 2008, the Gassled system transported 94.6 bcm (3.3 tcf) of gas to Europe.
The Gassled system was expanded in 2006 with the Langeled pipeline from Nyhamna to Easington. The Tampen Link pipeline from the Statfjord platform to the British Flags pipeline system was included in 2007. In 2009 the Gassled system is further expanded through the merger of the Kvitebjørn gas pipeline, Norne Gas Transportation System and the Etanor ethane fractionation system at Kårstø. When new gas infrastructure facilities are merged into Gassled, the ownership shares are adjusted in relation to the relative value of the assets and each owner's relative interests.
StatoilHydro acts as technical service provider (TSP) for Gassco for the Kårstø and Kollsnes processing terminals as well as for the major part of the pipeline infrastructure system.
As an integrated pipeline network with high flexibility and regularity, we believe that the Norwegian gas pipeline system is an essential facility that ensures reliable supplies of natural gas to Europe.
The tables below show facts of the NCS gas pipelines, including transportation routes and daily capacities, and our ownership in Gassled and other terminals.
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. The treatment plant currently has a rich gas capacity of 88 mmcm per day. Products produced at Kårstø include ethane, propane, iso-butane, normal butane and naphtha and stabilized condensate. When all these elements have been separated from the gas, the remaining gas (dry gas) is sent to customers via the Statpipe, Europipe II and Rogass pipelines. The treatment plant has currently a dry gas export 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 the project name 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. The first project was successfully completed in 2008. Plans call for the completion of the remaining KEP2010 projects between 2010 and 2012. Civil work started late 2008. The KEP2010 workforce working on site will comprise around 500 personnel at any given time. In 2008 Kårstø produced 24.6 bcm of dry gas, 0.8 million tonnes of ethane, 3.2 million tonnes of LPG and 2.2 million tonnes of condensate/naphtha exported to customers worldwide.
As technical service provider (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 initially built to receive gas landed from the Troll field through two 36-inch pipelines. The plant currently has a design capacity of 147 mmcm per day. In 2008 an upgrade of the flash gas compressor and the condensate system was successfully completed to increase the robustness of the plant. In 2008, Kollsnes produced 33.8 bcm of dry gas and 82.8 mmcm of condensate.
StatoilHydro is required by the Norwegian State to manage, transport and sell 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, which typically run for 10 to 20 years or more. Under these contracts the purchasers agree to take daily and annual quantities of gas and, if the gas is not taken, they are obliged to pay for the contracted quantity. The majority of StatoilHydro's long-term sales contracts have reached plateau level.
Prices under traditional long-term contracts are generally tied to a formula based on the prevailing prices for substitute fuels to natural gas, typically heavy fuel oil and gas oil. By contrast, the most recent long-term gas sales contracts in the UK are priced with reference to a daily UK market gas price index. There can be significant price fluctuations during the life of the contract. Prices under the traditional long-term contracts are typically 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. However, the price formula, which allows for monthly or quarterly adjustment, does not pick up on all trends in the marketplace, e.g. changes in the taxation of gas and competing fuels imposed by national governments. Therefore, most of our long-term gas contracts contain contractual price adjustment mechanisms that can be triggered at regular intervals 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 2008, StatoilHydro was involved in commercial discussions (in lieu of price review) or in formal price review processes for approximately 70% of the volumes covered by our long-term sales contracts.
As the current economic recession unfolds, we expect the change in the global demand for oil products to be negative in 2009 and maybe in 2010.
We expect the current economic downturn will revert to the long term trend of two-and-half to four percent growth. We expect demand to increase in parallel with a recovery in the global economy. Such growth will mainly be seen in emerging markets, as environmental policies and low population growth will constrain oil demand in mature economies.
In the medium to long term, we see growth limitations in global oil supply capacity. Oil production outside OPEC countries has already showed signs of flattening out, mainly due to the natural decline in output from mature oil fields. Supply growth will mainly come from OPEC countries in the future. In the longer term, we also expect limitations to OPEC production, due to lack of investment capacity and policies to make the period of stable oil revenues last as long as possible. In this context, we see incentives to develop both unconventional oil resources and alternative sources of oil products. There is a need to develop technologies to do this in a more environmentally acceptable way.
In the longer term, oil demand will therefore be limited by supply capacity. The supply side will also set limitations as to the requirements for refinery capacity. A number of refineries are currently under planning and construction around the world, and despite some delays due to the economic downturn, refinery capacity is expected to be more than sufficient in the years ahead. However, with higher prices and limited supply, we expect oil to continue its trend towards becoming primarily a fuel source for transport, such as gasoline, jet fuel and diesel, and less of a source for energy for stationary use, such as heating. This will put further pressure on refineries to increase the yield of these desired products. Income from refining will therefore mainly come from the upgrading of heavy oil components into transportation fuel products.
In developed economies, the legislative drive to remove sulphur and other pollutants from oil products is seen coming to an end now that the goals have been achieved, and future regulations are expected to focus on biofuel or other renewable content. However, an issue remains as to whether new regulation will seek to migrate shipping away from using heavy fuel oil to using diesel, in order to cut emissions. That could put increased pressure on a diesel market that already looks tight due to a lack of sufficient diesel upgrading capacity.
We are one of the largest net sellers of crude oil in the world, operating from sales offices in Stavanger, Oslo, London, Singapore and Stamford, selling and trading crude oil, condensate, NGL and refined products.
We market and sell our own volumes of crude and NGLs, together with those of the Norwegian State and third party volumes. In 2008, we sold 717 mmbbl of crude oil and condensate. This included sales to our own refineries and other internal entities. The main crude oil market for StatoilHydro is in north-western Europe. In addition, we also sell volumes to North America and Asia. Most of the crude oil volumes are sold in the crude spot market based on publicly quoted market prices. Of the total volumes sold in 2008, approximately 45% were StatoilHydro volumes.
We are majority owner and operator of the Mongstad refinery and Tjeldbergodden methanol plant in Norway, sole owner and operator of the Kalundborg refinery in Denmark, and operate the Oseberg Transportation System including the Sture crude oil terminal.
We are majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil distillation capacity of 179 mbbl per day, and sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118 mbbl per day. In addition, we have the rights to 10% of the production capacity at the Shell operated refinery in Pernis, The Netherlands, which has a crude oil distillation capacity of 400 mbbl 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.
The Mongstad refinery is a medium-sized, modern and sophisticated refinery. It is linked to offshore fields, the Sture crude oil terminal and the Kollnes gas terminal, making it an attractive site for landing and processing hydrocarbons.
The Mongstad refinery, built in 1975, significantly expanded and upgraded in the late 1980s and subject to considerable investments over the last 15 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, a Shell subsidiary, which provides technical operational support, project development support and general technical advice to Mongstad.
Approximately 45% of Mongstad's total production is delivered to the Scandinavian markets and 55% is exported to north-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, 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.
The refinery reliability (i.e. on stream factor) was high in 2006 and 2007, but the site experienced some operational problems during 2008. In 2008 the largest turnaround in Mongstad's history was executed on schedule. There were no turnarounds in 2006 or 2007.
In 2006, we received final permission to build a combined heat and power plant (CHP plant) at Mongstad.
The CHP plant is part of a strategically important project for Manufacturing & Marketing. The use of heat from the CHP plant will result in significant improvements to 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, however the utilisation will be lower for the first years after the unit is expected to come in commercial operation in 2010. The plant is under construction, and will be operated by Dong Energy, with StatoilHydro paying an annual fee for its use. By the end of 2008, the progress of the total CHP investment project was 80%. There is also an agreement with the Troll licensees, that this facility will supply power to the Troll A gas platform and the associated onshore Kollsnes processing plant. In addition to the CHP plant, the CHP investment project includes a new gas pipeline from Kollsnes and necessary modifications at the refinery.
StatoilHydro is involved in several projects together with the Norwegian government that aim to develop solutions for carbon capture and storage (CCS) at Mongstad. These projects are further described in report section 126.96.36.199 Operational review-Technology and New Energy-Research and development-R&D initiatives.
The Kalundborg refinery is a small, yet highly efficient refinery. It has a high degree of flexibility, enabling it to produce a variety of products such as gasoline, jet fuel, diesel, propane and fuel oils to 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 Europe, 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 was a turnaround in 2007.
Kalundborg is a plant with high energy efficiency and high utilisation. The refinery has improved its performance significantly in recent years through several small investment projects aimed at increasing flexibility, and improving yield/product quality. It produces high quality products, including low-sulphur petrol, in accordance with EU specifications.
The Fuel Reduction Project, which reduces production of heavy fuel oil and increases the production of sulphur-free auto diesel, was started up in 2008.
The Methanol plant at Tjeldbergodden is the largest in Europe, and one of the most energy efficient in the world. It is supplied with natural gas from the Heidrun field in the Norwegian Sea through the Haltenpipe.
We own 81.7% of the plant, which has a maximum proven capacity of 0.92 mmtpa. The actual throughput in 2008 was 0.91 mmtpa.
We also own 50.9% of Tjeldbergodden Luftgassfabrikk DA, one of the largest air separation units (ASU) in Scandinavia, which also owns the first Norwegian natural gas liquefaction plant, located at Tjeldbergodden with an annual gas (methane) capacity of 36 mmcm (1.3 bcf). Our partners are AGA (37.8%) and ConocoPhillips (11.3%). The ASU supplies oxygen to the methanol plant and AGA markets and sells the industrial gases produced.
The Sture terminal receives crude oil through two pipelines from the Oseberg area and the Grane field in the North Sea. The terminal is part of Oseberg Transportation System in which StatoilHydro has a 36.2% stake.
The terminal has a storage capacity for 6.3 million barrels of crude.
Energy and Retail has approximately 11,000 employees, and consists of approximately 2,100 service stations and 350 truck stops in eight countries. We also market refined products directly to consumer and industrial markets.
The full-service stations in the Retail segment provide automotive fuels, car accessories and basic vehicle service products. In addition, most stations offer consumer goods, including fast food, convenience products and basic groceries. In 2008, these stations, together with automated stations, sold approximately 8.4 billion litres of petrol and diesel. Sales from truck stops accounted for additional sales of 1 billion litres.
The following table lists these retail outlets by region or country as of 31 December 2008 and our volume of automotive fuel sales for the year ended 31 December 2008.
In addition to the retail operations, Energy and Retail also supplies aviation and marine fuels, as well as a large number of Statoil-brand refined products. Such products include oil based heating 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.
The majority of Energy and Retail sales are generated in Scandinavia. We have an approximate transport fuel market share of 36% in Norway and 23% in Denmark. In Sweden our transport fuel market share is approximately 33%, based on sales from Statoil and Hydro branded stations together with truck site sales and bulk deliveries. Other service stations are located in Poland, Russia and the Baltic countries; Estonia, Lithuania and Latvia. We rank as a market leader, measured in terms of fuel volumes sold, in Estonia and Latvia with approximately 26% and 34%, respectively, of the local transport fuel market in 2008
Acquisition of Jet
The transaction is an important element in our endeavours to become the leading fuel company in Scandinavia.
The success of our business is closely related to the application of the advanced technological expertise that for the most part has been acquired through our exploration and production activities on the NCS.
Many major challenges have been addressed, including operating in the harsh weather and environmentally sensitive conditions of the Norwegian Sea, transporting oil and gas across the deep Norwegian trench, and draining complex petroleum reservoirs characterised by high pressures and high temperatures. Much of this experience is increasingly being applied to StatoilHydro's international operations.
The renewable energy industry continues to grow, driven by ambitions to increase the contribution of sustainable energy to the total energy supply. Despite the challenges associated with the current financial crisis we believe that the new energy industry has gathered sufficient momentum in recent years for it to continue to be an important focus area for StatoilHydro. Although energy production from renewables is still modest in most countries, wind power, solar energy and biofuels are developing into significant industries.
The Research and Development (R&D) business cluster concentrates on StatoilHydro's technology focus areas in which the company wishes to develop and sustain distinctive technology positions.
The R&D portfolio is structured in six programmes: Exploration, IOR - Reservoir Drilling & Well, New Development Solutions, Oil and Gas Value Chain, New Energy/New Ideas and Academia.
Research and Development expenditures were NOK 2.24, NOK 1.97 and NOK 1.62 billion in 2008, 2007 and 2006, respectively. R&D expenditures are partly financed by joint venture partners of StatoilHydro operated activities. Cooperation with external partners, for example academia, R&D institutes and suppliers are key to technology provision. Typically more than 50% of the R&D expenditure is external work.
As conventional fossil fuels become ever harder to find, our company is increasingly setting its sights on remote geographical areas and developing unconventional hydrocarbon sources such as tight gas, oil sands and building growth platforms in carbon-neutral energy sources (renewables).
In exploration technology, we are developing new basin and prospect concepts that enable better global screening, exploration drilling and quantitative prediction of basin prospectivity. In addition, we are working on identification, characterisation, and prediction of deep-water plays for exploration within complex geological settings. Incorporation of integrated geophysical and geological methodologies into next generation workflows results in continued improvement of subsurface imaging and interpretation. The goal is to considerably reduce the risk of drilling dry holes and 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. Important success factors here are data integration and faster model updates for integrated operations across disciplines, organisational entities and geographical areas. The objective is to achieve more reliable, better and swifter decisions. We develop fit-for-purpose modelling techniques for better and more efficient modelling of reservoir drainage, more efficient drilling and intervention solutions, and more cost effective well construction methods.
Innovative offshore field development solutions lead to a transition from topside to intelligent, remotely-operated, autonomous seabed facilities, coupled with ultra-long, subsea tie-backs and wellstream compression devices. However, we also see that compact processing technology developed for subsea applications has a substantial potential to improve efficient production on existing platforms. The aim is to improve regularity and performance for both new and producing fields. Furthermore, it is necessary to increase the knowledge about design and operation in ice-bound areas and in ultra-deepwater conditions. We have also started to develop technology for processing and transportation of offshore heavy oil.
The opportunities in gas value chain technology may lie in gaining greater access to, and cost-effectively developing, difficult unconventional gas resources. We are developing technology for processing and transportation of challenging gas as well as pipeline solutions for deep and ultra-deep assets. In supporting our M&M business we work on refining technology for handling challenging and unconventional crude oil.
The Calgary Heavy Oil Technology Centre was established early this year to strengthen our efforts in heavy oil technologies. The focus is on developing onshore extra heavy oil value chains and on improving recovery methods, water management and carbon capture.
The final demonstration of GTL technology on a semi-commercial scale was completed this year. This concludes a demonstration programme where a Joint Venture consisting of StatoilHydro together with partners Lurgi and PetroSA has demonstrated the technology.
Our commitment to environmental stewardship is twofold: meeting our objective of zero harm to the environment by expanding our toolkit of environmental monitoring and integrated risk-modelling systems, and secondly, by creating business in new energy sources. In addition to our present activities in offshore wind and biofuels, we plan to further investigate opportunities in renewable energy sources and carriers. We are working on cost and energy efficient carbon capture and storage (CCS) with no harm to the environment, and we believe technological innovation is the key to meeting a profitable, sustainable, low-carbon energy future. Integrating trend-breaking technologies such as biotechnology and other new ideas into the value chains is also part of our research and development effort.
As part of the research effort we are pursuing an extensive collaboration programme with academia in which we gain access to world class research within strategic areas for StatoilHydro. By stimulating the development of leading competence within the energy segment we also secure long term recruitment to science and technology.
By supporting collaboration between universities, research institutions and industry, we believe this also contributes to building a strong Norwegian petroleum cluster.
The New Energy portfolio has a particular focus on creating profitable business in the short and medium term through the Wind and BioFuels businesses.
Renewable Power Production
In May 2008 StatoilHydro approved the building of the Hywind pilot and this demonstration project will be the world's first full scale floating windmill. It is a 2.3 MW unit and is scheduled for operation off the west coast of Norway second half of 2009. Complementary offshore wind technologies are available through our equity positions in the Norwegian companies Sway AS and ChapDrive AS.
In 2008 we invested in Brightsource Energy, which develops technology for concentrated solar thermal power, and the Iceland Deep Drilling Project (IDDP), which is a joint-research programme within deep geothermal energy in Iceland.
Our existing technology investments have also begun to show promise. Pelamis, a wave energy device in which StatoilHydro has invested, was the technology chosen for the world's first wave energy park situated off the Portuguese coast. In addition, it has been selected for other new projects in the UK. Hammerfest Strøm AS, a tidal power technology company in which StatoilHydro participates together with Iberdrola/Scottish Power, has been selected to be used in projects planned by Scottish Power.
Being able to produce biofuels sustainably is a prerequisite for developing our biofuels business. We are working actively to prevent damage to biodiversity, ecosystems and areas of high conservation value and emphasise the greenhouse gas accounts in a life cycle perspective. Our aim is to contribute to positive local development through competence building and job creation.
Our activities within hydrogen are centred on both short and long-term options. Through our subsidiary Hydrogen Technologies we are actively developing and promoting ongoing sales of water electrolysis technology. We have also developed hydrogen station technologies aiming at the emerging markets within the transport sector.
StatoilHydro opened Norway's first hydrogen filling station in Stavanger in August 2006 and the second in Porsgrunn in June 2007. The stations are part of the national development project HyNor, in which StatoilHydro is a leading player. HyNor is a unique Norwegian joint industry initiative to demonstrate real life implementation of hydrogen energy infrastructure along a route of 580 kilometres from Oslo to Stavanger.
On Utsira, an island off the west of Karmøy, StatoilHydro owns and operates a hydrogen demonstration plant where electricity from wind turbines is used to provide power to the local society and to produce hydrogen. When wind speeds are not sufficient to provide enough electricity, the hydrogen plant is used to generate power.
By using this experience as a base and placing the main focus on storage, StatoilHydro intends to generate new business from CO2 management. The planned facilities at Mongstad will provide valuable experience in the transportation and storage of CO2.
StatoilHydro actively benefits from venture activities to access new technologies. In the autumn of 2008 it was decided to strengthen this activity by establishing a special purpose company, Energy Capital Management AS, to manage corporate venture activities within StatoilHydro. This move represents a further focus on venture capital as a tool to accessing new technologies, and will support StatoilHydro's technology strategy and help capitalise on today's ownership positions within the venture business.
StatoilHydro is the world's largest operator of offshore fields in water depths greater than 100 metres, and we have considerable experience in overcoming the challenges presented by harsh environments.
Nevertheless, there is a need to rapidly utilise new technology to increase the resource base and maximise production.
Technology & New Energy (TNE) is the centre of force for the development and implementation of new technology in the company. This is achieved by providing best practice support and expertise for our operations, developing world-class technical concepts for our development projects, and leading established corporate initiatives in order to improve our performance in exploration, IOR and integrated operations. In this manner, TNE will support the other business areas in achieving corporate targets for production growth, increased regularity, reduced costs and improved drilling efficiency.
Selected advances made in 2008 are summarised below:
The first set of 3D electromagnetic data (EM) was retrieved from the Troll area on the Norwegian Continental Shelf this year. Increased insight into acquisition and interpretation technology of the Troll data increases the use of EM in the exploration workflow and adds significantly to the use of EM data for subsurface identification of oil and gas. Electromagnetic data has potentially siginificant applications in hydrocarbon exploration by enabling the oil and gas to be detected in reservoirs instead of water. Combined with seismic data, the EM data can reduce uncertainty in exploration and lead to higher discovery rates.
The massive volume of exploration data and need for efficient analysis to ensure exploration success has led to the development of a proprietary version of Google Earth. The StatoilHydro Earth Exploration Toolbox, visualized in the Google Earth environment, is a significant step towards quick access and interpretation of exploration data, leading to an effective workflow for evaluating subsurface prospectivity. Such workflows assist the rapid development of subsurface geology models and increase the probability of locating prospective areas and layers for discovery of oil and gas.
StatoilHydro is now qualifying a new down-hole drilling tool, the Rotary Steerable System (RSS), together with Schlumberger. These tools will be used to drill sidetracks from old wells without removing the production tubing. A window out to the formation is made in one side of the old well and the RSS tool is then used to drill a new hole outside the window. This quick departure from the old well will dramatically increase the ability to reach reservoirs that could not be as efficiently reached before, if at all. The impressive steering characteristics of the tool also make it possible to reach targets further away from the old well and ultimately double the number of targets and recoverable reserves that can be reached with the use of this technology.
Current technology for capturing CO2 from flue gases is associated with significant energy requirements and large capital costs. Exhaust gas recirculation (EGR) is a method known to reduce costs and energy requirements, and StatoilHydro has monitored the technology for several years. A technology qualification programme is under development for EGR in connection with the General Electric Frame 9E gas turbines at Mongstad.
On the NCS, the trend is away from a portfolio of major development projects and towards subsea tie-in projects and complex redevelopment projects on existing installations where vital work must be timed to coincide with planned turnarounds.
The growing portfolio makes the shortage of engineering competence just as critical as in previous years, with respect to the number of available engineering personnel and the competence and quality of work delivered. In addition, increased international activity is expected to challenge our ability to utilise our competence and allocate our resources in the most efficient way. As a result, there is a risk that engineering may be negatively affected, which in turn, may influence construction and completion progress.
High activity levels on the NCS will make strong demands on our ability to execute projects as sanctioned and in accordance with our HSE target of zero harm. To succeed, we must challenge established models, ensure continuous improvement and establish best practice on the basis of experience.
As regards physical deliveries of goods and services, we have only seen moderate price decreases while the oil price plunged during the second half of 2008. This remains a concern, and it means that our long term investment plans are being revised. However, we anticipate a high activity level in 2009.
There is considerable diversity in our projects portfolio, ranging from new projects and improvements to existing assets to generate production growth on the NCS, to supporting the company's ambitions to become a global energy player.
On the NCS, projects such as Gjøa, Tyrihans, Morvin and Alve will contribute to continued production growth. Ormen Lange Offshore and Statfjord Late Life are examples of complex projects that are expected to contribute to optimising production from existing assets.
The following table gives a project overview
Another dimension of complexity to our business comes from executing projects internationally -- an essential part of fulfilling the group's ambitions to become a truly global energy player. Examples of PRO's contributions in this respect are the Leismer, In Salah and Peregrino projects.
To build an international reputation as a world-class implementer of projects, the way in which we deliver results is as important the results themselves. That means delivering on time and cost, and without compromising high HSE and ethical standards.
We continue to strengthen our solid position on the NCS with several large and complex new development projects currently being executed.
The largest project in our portfolio today is Gjøa, located west of the Sogn area. Gjøa is being developed with a semi-submersible production platform and five subsea templates The producing facility is designed in a way that makes it possible to process oil and gas from other smaller discoveries in the area in the future, such as Vega - a gas and condensate field that is being tied back to the platform in a joint pipeline.
The Gjøa platform will be provided with land-based electricity from Mongstad that is estimated to avoid emissions of 240,000 tonnes of carbon dioxide per year, equivalent to the annual emissions from 100,000 cars. At production start-up, expected to be in the autumn of 2010, we will hand over the operatorship of Gjøa to Gaz de France .
The Tyrihans field was discovered in 1982/1983 and the PDO was approved by the Norwegian authorities in February 2006.
The remaining work prior to the estimated start-up in mid-2009 consists of topside modifications on Kristin and Åsgard B and delivery of the subsea production system and seawater injection system.
Another ongoing project located on the Halten Bank is Morvin. Initially it was not regarded as commercially viable when it was discovered in 2001. However, an appraisal well in the summer 2006 verified sufficient recoverable reserves, and Morvin was subject to an accelerated development process. PDO was issued to the authorities on 1 February 2008, and approved 28 April 2008.
Morvin is a High Pressure High Temperature field, and is being developed with technology solutions copied from Kristin. The two templates, with a total of four production wells, are tied in to Åsgard B, 20 kilometres away. Templates and production pipeline were installed during summer 2008 and topside installation work has commenced. Production start-up is scheduled for late 2010.
The Yttergryta subsea gas and condensate field development is an example of a relatively small but unique project in our portfolio. The discovery was made in the summer of 2007, and production start-up took place on 5 Januar 2009, four months ahead of schedule. The wellstream is tied back to the Åsgard B platform for processing and further export.
The field was developed with seabed installations at depths down to 1100 metres, combined with an onshore plant at Nyhamna in Aukra municipality in Norway for processing and exporting the gas. The gas is exported through the world's longest subsea pipeline, Langeled, 1200 kilometres to Easington on the east coast of Britain. The gas can also be transported via the riser platform on the Sleipner field in the North Sea to customers on the European continent.
Following a gradual increase in production over the first two to three years, the field is expected to produce 70 million standard cubic metres of gas per day.
Large redevelopment programmes are currently underway at the Kårstø, Mongstad and Kollsnes production sites.
A total of approximately NOK 14 billion is currently being invested to ensure regularity of gas production, to prepare for future volumes, and to ensure that future HSE requirements from authorities are met by sanctioned projects offshore.
At Mongstad, the projects related to the construction of a Combined Heat and Power (CHP) plant are well underway. StatoilHydro is executing a major refinery upgrade and building a gas pipeline from Kollsnes to Mongstad in relation to this CHP plant. The latter has been completed by mid December 2008. In parallel, StatoilHydro is executing a large environmental project, called SMIL, which also is planned to be completed during 2009. The CHP plant is built and operated by DONG Energy and is planned to start up early in 2010.
At Kårstø, several smaller projects have been gathered together in the Kårstø Expansion Project 2010 (KEP 2010). The first part is a compressor upgrade which will make it possible to increase the pressure, and thus enable more stability in the gas flow through the export pipelines leaving Kårstø. This sub-project was completed in fourth quarter of 2008.
The second part of the project is a complete modernisation and upgrading of the security and control systems at the site, to prepare the plant for several more years of production and to meet stricter future HSE standards. A project replacing the NGL Metering stations was sanctioned late in 2008. The NGL Metering stations are planned to be started up by the end of 2011.
The Kollsnes Flash Gas and Condensate project is an upgrade of the existing system due to capacity and regularity limitations. The installation of a new flash gas compressor train and a new condensate treatment train was completed by the end of December 2008 and will contribute to increasing production and operating regularity at the Kollsnes processing plant. In addition, capacity for future production of 40 million standard cubic metres per day is built into the system.
We have a number of key projects taking place internationally, in such countries as Algeria, Canada, Brazil and the US.
In Algeria we are involved in onshore gas production and exploration activities. The In Salah Gas Compression project is part of the original development plan for In Salah, and it consists of turbine and electricity-driven gas compressor facilities that will be installed at Reg, Teg and Kretchba, respectively. The purpose of the new compressor facilities is to counteract the declining production rates from the three fields. Construction work has started with site preparations, prefabrication of pipes and equipment delivery. The project is behind schedule, but mitigating actions have been implemented to secure the schedule and prevent further delays.
On 4 March 2008, StatoilHydro signed an agreement with Anadarko to purchase Anadarko's remaining 50% share of the Peregrino field in Brazil. The agreement also involves transfer of the operatorship to StatoilHydro, and we now hold a 100% ownership share in the field. The transfer of project responsibility took effect on 2 June 2008, and was formally approved by the Brazilian petroleum authorities, Agencia National de Petróleo, on 11 December 2008.
The Peregrino field is located 85 kilometres off the Brazilian coast in approximately 100 metres of water. A development plan for Phase 1 was approved early 2007, containing two drilling and wellhead platforms and a floating vessel for production, storage and offloading of oil (FPSO). The first oil is planned to come on stream in 2011 and plateau production of 100 mboe per day is expected to be reached within the first year of production.
The project is progressing according to schedule, and the two wellhead platforms are currently under construction at Kiewit's yard in Corpus Christi, Texas. The FPSO vessel, Mærsk Nova, is being upgraded at the Keppel Tuas yard in Singapore, while the process facility is being fabricated at the Keppel yard in Batam.
On 12 December 2002, we became operator of the development of the offshore part of the South Pars phases six-seven-eight project in Iran. The South Pars offshore project phases six, seven and eight consist of three wellhead platforms with three pipelines for gas to shore, a condensate loading line and associated single point mooring (SPM) for condensate exports, the drilling of 27 production wells, the hook-up of three pre-drilled wells and required reservoir management.
A major part of our project portfolio consists of activities relating to ongoing redevelopment efforts, aimed at maximising production from the NCS.
As fields mature, production equipment needs upgrading. In the years ahead, a number of fields will need upgrading or renewal of drilling units, control systems, cranes and other major redevelopment efforts.
We endeavour to organise these tasks as field projects in line with coordinated master plans for the different fields, such as the various redevelopment projects taking place at Statfjord, Troll and Oseberg, among others.
The PDO for the Troll projects was submitted to the Ministry of Petroleum and Energy this summer. The Troll B Gas Injection project and the P12 pipeline to Kollsnes are both part of the PDO. The extension of the living quarters on Troll A and low-pressure production on Troll C are also vital projects in the Troll field.
The various redevelopment projects related to the Oseberg field represent a substantial investment aimed at ensuring the vitality of the field in the coming years. Vital projects include low-pressure production on Oseberg F, a heat recovery steam generator on Oseberg D, upgrading of the drilling unit at Oseberg B and upgrading of the Oseberg C Mud module.
Over the next few years, the Statfjord Late Life project will redevelop all three Statfjord installations from oil processing to gas processing facilities, thereby extending the lifetime of the field by several years. We expect the daily production of gas to exceed daily oil production on Statfjord in 2010.
The impact of the global economic turmoil on our employees and the labour market within our industry is not yet fully evident. We are planning for growth and need to maintain and further develop our core competencies.
Our overall strategic objective in 2008 has been to build a company culture that is based on our values and driven by performance. In everyday work life, this means that we create a positive working environment that makes our people attracted to, inspired by and committed to our company.
Our rapid international growth challenges our ability to maintain recruitment of highly skilled personnel from all countries in which we operate.
StatoilHydro employs approximately 29,500 people worldwide. Our people are central to the delivery of the StatoilHydro business strategy and sustainable development policy. In 2008 we continued to advance our people strategy, which focuses mainly on integrating post-merger best practices, maintaining cooperation with our unions, recruiting, developing skills and improving employee performance.
At 31 December 2008 and 31 December 2007, we had 29,500 employees worldwide. The table below provides the number of employees at year-end for each of the past 3 years and a breakdown of employees by geographic location.
The increase in employees by approximately 4100 or 16% from 2006 to 2007 can be primarily attributed to the merger between Statoil ASA and Hydro oil and energy activities.
Cooperation with Unions. Our cooperation with the unions has been improved, by redefining the agreement between the parties in ICEM. Our process for people performance, development and deployment has been simplified and improved.
Recruiting. The percentage of non-Norwegians working at our various locations in Norway has increased from 5.12% in December 2007 to 5.88% in December 2008. At the end of 2008, 11,400, or 39% of our people were employed outside Norway.
StatoilHydro is a knowledge and technology-based company and our people are highly qualified to do their work: 56% of the employees in StatoilHydro ASA have a university or college background, and having 27% have a craft certificate. StatoilHydro employs the most apprentices in Norway, with 176 apprentices joined our company in 2008. The total number of apprentices in StatoilHydro at December 2008 was 337.
At the end of December the average age of our employees at StatoilHydro ASA was 44 and the majority of our people, 69%, were between 35 and 55 years old, while 19.5% of our people were less than 35 years old. In 2008, the overall turnover at StatoilHydro ASA was 1.9%. The turnover percentage for women was 1.5%, and for men 2.1%.
We promote diversity of gender, age and ethnicity among our employees.
The importance of diversity is stated in our values and in our ethical codes of conduct. We aim to create the ame opportunities for all of our employees, regardless of gender, age on ethnicityand do not tolerate discrimination or harassment of any kind in our workplace.
By December 2008, 37% of our people were women, and 40% of the members on our board of directors were women. The proportion of female managers is 27%, and among managers under the age of 45, the proportion is 35%. Moreover, women are relatively well represented in the technical disciplines. In 2008, 25% of our staff engineers were women, and among staff engineers with up to 20 years' experience, the proportion of women is 28%. The proportion of female skilled workers in 2008 is 18%.
We work systematically with recruitment and development programmes in order to increase the number of women in male-dominated positions and discipline areas.
The reward system in StatoilHydro is gender neutral, meaning that men and women with the same position, experience and performance will be at the same salary levels. However, due to differences in types of positions and numbers of years' experience between women and men, some differences in compensation appear when comparing the general wage levels of men and women. On average, the earnings of female skilled workers are 93% of the earnings of their male colleagues. There are no significant differences between the earnings of female and male staff engineers.
In 2007 we completed the first phase of the integration between Statoil and Hydro. In 2008 we started the integration of our operational units.
One of our main actions in 2008 has been to complete the integration of our operating organisation in EPN, M&M and NG and to ensure a successful post-merger process for the parts of the organisation that were integrated in 2007.
During the first half of 2008, the integration planning committee, which consists of representatives from the corporate executive committee and the labour unions, has been involved in planning and designing the new operating model. From the 2nd quarter of 2008 and throughout 2009, project teams in the business areas that are involved in the second phase of the integration will complete the manning process and implement changes that the new operating model requires.
We have also carried out an integration monitoring survey which measures progress and satisfaction between our people and the merger process every three months. The results from 2008 indicate that the staff who were integrated in 2007 increasingly feel that they are being well taken care of, and that they have influence in decisions regarding their own working situation. For our people undergoing the integration in 2008 and 2009, the results are less positive.
Several activities have been carried out in order to ensure a successful post-merger process for the employees that were integrated in 2007. An integration research team, consisting of external researchers from the three research institutions International Research Institute of Stavanger, Institute for Research in Economics and Business Administration (SNF) and FAFO, have been assigned to deliver an independent evaluation of the entire integration process. The research programme will run for three years. So far, 13 professors and researchers, one PhD-candidates and 13 master students have been able to generate new knowledge and research about mergers and organisational outcomes based on data material and observations from the ongoing integration process in our company.
In 2009 one of our major post-merger activities will be to further strengthen the common and integrated company identity by launching our new vision and company name.
We emphasise the value of cooperation with our employees, and 69% of staff (StatoilHydro ASA) are members of a labour union. Our cooperation with employee representatives and labour unions is based on confidence and trust.
StatoilHydro emphasizes the value of cooperation with its employees, and 69% of the employees in the parent company are members of a labour union.
The agreement with ICEM (Link to ICEM), which is an international federation that represents trade unions worldwide, was renewed in 2008. We were the first company in the oil and gas industry to sign this agreement. The cooperation with ICEM enables exchange of information and further development of good working practices within our operations worldwide. The content in the agreement reflects our policies and values on areas such as industrial relations, human rights and labour standards and HSE.
The following table shows significant subsidiaries owned directly by the parent company, as well as the parent company's equity interest and the subsidiaries\' country of incorporation. In each case our voting interest is equivalent to our equity interest.
This section describes our oil and gas production and sales volumes.
The following table sets out 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
Proved oil and gas reserves were estimated to be 5584 mmboe at the end of 2008, compared to 6010 mmboe at the end of 2007.
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 management control, such as changes in oil and gas prices. While lower oil and gas prices normally allow less oil and gas to be recovered from the accumulations, StatoilHydro's proved oil and gas reserves under PSAs and similar contracts will generally increase as a result. StatoilHydro will receive larger quantities of oil and gas under the cost recovery and profit sharing arrangements of these contracts as a result of the decreased 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 2008 are expected to be produced in the period from year 2009 to 2021. 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 2008, 2007 and 2006.
A total of 222 mmboe proved reserves was added during 2008, of which 186 mmboe were proved developed reserves. The remaining 36 mmboe were proved undeveloped reserves.
The reserves replacement ratio was 34% in 2008, compared to 86% in 2007. The decrease in the reserve replacement ratio in 2008 compared to 2007 is mainly due to 2008 being a year with small reserve additions from sanctions of new development projects and high production. The average replacement rate for the last three years was 60%, including purchases, sales and reduction of sharehold interest in Petrocedeño.
The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, the sensitivity related to the timing of project sanctions, and the time lag between exploration expenditure and booking of reserves.
We review our petroleum reserves in the course of business as new information becomes available. This information can be related to remaining reserves, existing production performance, decisions related to development, production, acquisition and divestment of reserves and changes in economic conditions. In addition, information on proved oil and gas reserves, standardised measure of discounted net cash flows related to proved oil and gas reserves, and other information related to proved oil and gas reserves reported in note 34 - Supplementary oil and gas information - to our Consolidated Financial Statements, 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 for approval to the management responsible for the relevant business units and the Chief Executive Officer, this central group asks DeGolyer and MacNaughton, independent petroleum engineering consultants, to perform an independent evaluation of proved reserves. This was last performed as of 31 December 2008.
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 have provided us with a summary letter report describing their procedures and conclusions, a copy of which is included 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, both positive and negative. The accuracy of any reserve information is a function of the quality of available data and of engineering and requires interpretation and judgment. The requirements of the SEC with respect to the calculation of proved reserves set a standard for estimating reserves, which results in amounts that are reasonably certain technically and consistent with the economic, regulatory and operating conditions at the time the estimates are made. See note 34 - Supplementary oil and gas information - to our Consolidated Financial Statements, for further details on our proved reserves.
DeGolyer and MacNaughton, independent petroleum engineering consultants, have performed an independent evaluation of StatoilHydro's proved reserves as of 31 December 2008. A copy of a summary letter report from DeGolyer and MacNaughton, describing their procedures and conclusions, is included below.
DeGolyer and MacNaughton
February 13, 2009
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, 2008, attributable to StatoilHydro’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalents (MMboe):
StatoilHydro has advised us that its estimates of proved oil, condensate, LPG, and natural gas reserves are in accordance with the rules and regulations of the SEC. It is our opinion that the guidelines and procedures that StatoilHydro has adopted to prepare its estimates are in accordance with generally accepted petroleum reserves evaluation practices and are in accordance with the requirements of the SEC.
Our estimates of the proved reserves, as of December 31, 2008, attributable to StatoilHydro’s interests in the properties included in the Report are as follows, expressed in millions of barrels (MMbbl), billions of cubic feet (Bcf), and millions of barrels of oil equivalents (MMboe):
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.
DeGOLYER and MacNAUGHTON
/s/ Lloyd W. Cade
The principal Norwegian legislation applying to our petroleum activities in Norway are the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.
The principal Norwegian legislation applying to our petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of November 29, 1996 (the "Petroleum Act"), and the 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. We are dependent upon the Norwegian State for its approval of our NCS exploration and development projects and applications for production rates for individual fields.
Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible for resource management and for administering petroleum activities on the NCS. The main task of the Ministry of Petroleum and Energy is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Norwegian parliament or 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.
The most important type of license awarded under the Petroleum Act is the production licence, and the Ministry of Petroleum and Energy holds executive discretionary power to award a production licence and to determine the terms of that licence.
In 2008 we participated in 346 production license on the NCS. As a participant in licenses, we are subject to the regulations of the Norwegian licensing system.
The most important type of license awarded under the Petroleum Act is the production licence, and the Ministry of Petroleum and Energy holds executive discretionary power to award a production licence and to determine the terms of that licence. The Government is not entitled to award us a licence in an area until the Storting has decided to open the area in question for exploration. The terms of our production licenses are determinated by the Ministry of Petroleum.
A production licence grants the holder an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the licence. Notwithstanding the exclusive rights granted under a production licence, the Ministry of Petroleum and Energy has the power, in exceptional cases, to permit third parties to carry out exploration in the area covered by a production licence. For a list of our shares in production licences, see the report section 3.1.5 Operational review-E&P Norway-Production.
Production licences are normally awarded through licensing rounds. The first licensing round for NCS production licences was announced in 1965. The award of the first licences covered areas in the North Sea. Over the years the award of licences 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 licences in the Norwegian Sea. Beginning in 2003, the Norwegian government changed its policy on mature areas and introduced a scheme for award of production licences named "Award in Predefined Areas" (APA) in mature parts of the Norwegian Continental Shelf. The award of licences 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 licence applications from individual companies and group applications. This allows us to choose our exploration and development partners.
Production licences are awarded to joint ventures. As is the case for most fields on the NCS, our production activities are conducted through joint venture arrangements with other companies and in some cases with the Norwegian State through its wholly-owned company Petoro. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the license. Once a production licence 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 licence to licence, but a decision is normally reached when a certain number of the members and a percentage of the ownership interests, specified individually in each licence, have voted in favour of a proposal. The voting rules are structured so that a licensee holding more than 50% of a licence normally cannot vote through a proposal on its own, but will need the support of one or more of the other licensees. In licences awarded since 1996 where the SDFI holds an interest, the Norwegian State, acting through the SDFI management company, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the licence as to the Norwegian State's exploitation policies or financial interests. This veto right has never been used.
Under the joint operating agreements covering licences awarded prior to 1996, the management company that supervises the Norwegian State's SDFI interest, Petoro AS, has the power, with certain exceptions, to make decisions unilaterally in matters 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 licences 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. In 2008 we were the operator for 42 of our 48 production licenses. The operator is in practice always a member of the joint venture holding the production licence, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement. Under the joint operating agreement, an operator 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 licences 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 licence. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfil the obligations set out in the production licence, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years. The right to prolong the licence does not apply as a main rule to the whole of the geographical area covered by the initial licence, but only to a percentage, typically 50%. The size of the area which must be relinquished is determined at the time the licence is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production licence.
If natural resources other than petroleum are discovered in the area covered by a production licence, the Norwegian State may decide to delay petroleum production in the area. If such a delay is imposed, the licensees are, with certain exceptions, entitled to a corresponding extension of the period of the licence. 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 mbbl per day. In March 1999, the Norwegian State decided to increase the reduction to 200 mbbl per day. In the second quarter of 2000, the reduction was brought back to 100 mbbl per day. On 1 July 2000, this restriction was removed. By a royal decree of 19 December 2001, the Norwegian government decided that Norwegian oil production would be reduced by 150 mbbl per day from 1 January 2002 until 30 June 2002. This amounted to approximately a 5% reduction in output.
Licensees may buy or sell interests in production licences subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of interest in a licence, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. There are in most licences 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 licences. All of our licensing transactions entered into in 2008 were approved by the Ministry of Petroleum and Energy and the Ministry of Finance.
A licence from the Ministry of Petroleum and Energy is also required in order to establish facilities for transport and utilization of petroleum. When applying for such licences, the owners, which are in practice licensees under a production licence, must prepare a plan for installation and operation. Licences to 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. All of our applications for facility licenses submitted in 2008 have been granted by the Ministry of Petroleum and Energy.
Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for 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 licence 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 licence expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with expropriation of private property apply. None of our production licenses expired in 2008 and none are due to expire in 2009.
Licences 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 licence period.
StatoilHydro markets gas from the Norwegian continental shelf on our own and the Norwegian state's behalf. Gas is transported through the Gassled pipeline network to customers in Europe.
Gas sales contracts with buyers for the supply of Norwegian gas are concluded individually with each company.
The upstream gas transportation system consists of several pipelines owned by a joint venture called Gassled. We have a 32.10% interest in Gassled (32.88% including our indirect interest through our 28.58% holding in Norsea Gas AS) and are responsible for the technical operation of the majority of export pipelines and onshore plants in the processing and transportation systems for Gassled; see section 3.3.4 Operational review-Natural Gas-Norway's gas transport system.
The Norwegian authorities have issued regulations by a royal decree of 20 December 2002 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. Secondly, they established a system for access to the upstream gas transportation system that is compatible with company-based gas sales from the NCS. Thirdly, they provided for the new ownership structure of the upstream gas transportation system (Gassled).
Parts of the regulations have a general application and parts - including the tariffs - are 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 spare capacity, in accordance with regulations, is allocated to users with need requisite need for transportation of natural gas. Furthermore, the access regime consists of a secondary market where the capacity can be transferred between the users after the allocation in the primary market if the need for transportation changes.
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, in case of scarce capacity, consideration must first be given to the owners' duly substantiated needs for capacity, limited to twice the owner's equity interest in the upstream pipeline network.
Based on authorisation 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.
The EU Gas Directive, which has been included in the EEA Agreement and incorporated into Norwegian legislation, regulates the European gas market in conjunction with the gas Transmission Access Regulation of 2005.
Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that is continuing to be affected by changes in EU regulations and the implementation of such regulations in EU member sates. Such regulation affects our ability to expand or even maintain our current market position, as quantities sold under our gas sales contracts may be subject to a material change in gas prices as a result of the regulations under the EU Gas Directive.
The Directive requires that 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 2009. 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.
Our petroleum operations in Norway are subject to extensive regulation with regard to health, safety and the environment, or HSE.
Under the Petroleum Act, which is administered by the Ministry of Labour and Government Administration, our petroleum operations must be conducted in compliance with a reasonable standard of care, taking into consideration the safety of employees, the environment and the economic values represented by installations and vessels. The Petroleum Act specifically requires that petroleum operations be carried out in such a manner that a high level of safety is maintained and developed in accordance with technological developments. StatoilHydro established a system for monitoring the technical safety of its plants in 2001, and, as part of this system, it collects and interprets information from its operating activities and incorporates risk management in its operating activities.
We are required to maintain at all times a plan to deal with emergency situations in our petroleum operations. 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 licences 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 damage or loss as a result of pollution caused by any of our NCS licence areas can claim compensation from us without needing to demonstrate that the damage is due to any fault on our part. If the pollution is caused by a force majeure event, a Norwegian court may reduce the level of damages to the extent it considers reasonable.
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. 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 16.67% 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 percent 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 be offset to a great extent. Group distributions are not deductible in our offshore income.
Dividends received are subject to tax in Norway. The basis for taxation is 3% of the dividend amounts received and this is subject to the standard 28% income tax. Dividends from low-tax countries or portfolio investments outside the EEA will under certain circumstances be subject to the standard 28% income tax based on the full amounts received.
Capital gains from realisation of shares are taxable where the basis for taxation is 3 % of the gain which is subject to the standard 28% income tax. Capital losses from realisation of shares are not deductible. Exemptions exist for shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA where capital gains under certain circumstances will be subject to the standard 28% income tax and capital losses will be deductible.
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 expenses. Provisions for future abandonment costs are not tax deductible.
Carbon dioxide emissions tax. A special carbon dioxide emissions tax applies to petroleum activities on the NCS. The tax is NOK 0.45 for 2008 and NOK 0.46 for 2009 per standard cubic metre of gas burned or directly released and per litre of oil burned. From 2008, companies operating on the NCS 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 15.39 per kilogram of nitrogen oxide for 2008 and NOK 15.85 for 2009.
Alternatively to pay the nitrogen oxygen fee, companies may voluntarily agree to contribute to an industry nitrogen oxygen fund for the years 2008-2010. The contribution to the fund is NOK 11 per kilogram of nitrogen oxide emissions. We have entered into an agreement to contribute to the fund.
Area fee. After the expiration of the initial exploration period, the holders of production licences are required to pay an area fee. The amount of the area fee is set out in regulations promulgated under the Petroleum Act. In respect of most of the production licences, the initial annual area fee is currently NOK 7000 per square kilometre. The annual area fee is increased yearly by NOK 7000 until it reaches NOK 70,000 per square kilometre.
Taxation outside Norway
Generally, income from StatoilHydro's upstream production outside of Norway is subject to tax at the higher of the Norwegian on-shore rate (28%) or the prevailing rate of tax in the countries in which it operates. StatoilHydro is subject to excess (or "windfall") profit tax in some of the countries where it produces crude oil.
Production sharing agreements. Under a PSA, the host government typically retains the right to the hydrocarbons in place. The contractor under a PSA normally receives a share of the oil produced to recover its costs, and additionally is entitled to an agreed share of the oil as profit. The allocation of profit oil between the state and the contractors is typically increasing towards the state based on a success factor, such as surpassing certain specified internal rates of return, production rates or accumulated production. Normally, the contractors carry the exploration costs and risk prior to a commercial discovery and then are entitled to recover those costs during the producing phase. Fiscal provisions in a PSA contract are, to a large extent, negotiable and are unique to each PSA. Contractors to a PSA are generally insulated from legislative changes to a country's general tax laws.
Income tax regimes. Under an income tax/royalty regime, companies are granted licenses by the government to extract petroleum, and the state may be entitled to royalties in addition to tax based on the company's net taxable income from production. The fiscal terms surrounding these licenses are, in general, not negotiable and the company is subject to legislative changes to the tax laws.
The Norwegian state's direct participation in petroleum operations on the NCS
The Norwegian State's policy as an owner of shares of StatoilHydro 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 organised 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 licences and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licences and petroleum facilities in which we also hold interests.
As a result of changes in global markets and competitive conditions in the petroleum industry, the Norwegian State 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 led to:
Historically, we have marketed and sold the Norwegian State's oil and gas as a part of our own production, and the Norwegian State has elected to continue this arrangement.
Accordingly, at an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article 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 out below.
Our tasks. Our tasks under the owner's instruction are to market and sell the Norwegian State's oil and gas and to carry out all necessary tasks, other than those carried out jointly with other licensees under the production licence, 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 own natural gas volumes, a list has been established for deciding the priority between each individual field. To decide the ranking, a mathematical optimisation model is used 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 various fields are ranked in accordance with the assumed total value creation for the Norwegian State and us, assuming all of the fields meet our profitability requirements if we participate as a licensee, and the Norwegian State's profitability requirements if the State is a licensee. The list is updated annually or more frequently if 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.
Petoro AS - the SDFI management company
In 1985, the Norwegian State began taking a direct financial interest in production licences through the establishment of the SDFI, and in 2001, a new state-owned company, Petoro, was established to administer SDFI assets.
From the establishment of Statoil in 1972 and until 1 January 1985, the participation of the Norwegian State in production licences and facilities for transport and utilisation of petroleum took place entirely through Statoil. 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.
In connection with the restructuring, the Norwegian State established a new State-owned company, Petoro AS, in May 2001 which took over responsibility for, and the management of, the SDFI assets as licensee, in accordance with a new chapter of the Petroleum Act. The Norwegian State continues to be the beneficial owner of these assets. We continue to market and sell the Norwegian State's oil and gas together with our own oil and gas, pursuant to the owner's instruction described under report section 3.10.8 Operational review-Regulation-Marketing and sale of SDFI oil and gas. One of the tasks of Petoro AS is to supervise our compliance with the owner's instruction.
Petoro AS does not own any of the oil and gas produced under the licence interests it holds, 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.
Gassco AS - the gas transportation operating company
In connection with the restructuring of the Norwegian State's oil and gas interests in May 2001, the Norwegian State established a separate company, Gassco AS.
Gassco took over as operator of the natural gas transportation system previously operated by us on 1 January 2002. Gassco AS is wholly owned by the Norwegian State. The owners of the infrastructure systems appointed Gassco AS as the new operator.
The transfer of the operatorship to Gassco AS was made without consideration of, and does not affect existing arrangements, with respect to ownership or access to the natural gas transportation system or tariffs for transport. 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 3.3.4 Operational review-Natural Gas-Norway's gas transportation system.
In the oil and gas industry there is intense competition for customers, production licences, operatorships, capital and experienced human resources.
In recent years the oil and gas industry has experienced consolidation, as well as increased deregulation and integration in strategic markets.
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.
We have interests in real estate in numerous countries throughout the world, but no one individual property is significant to us as a whole. Plans have been announced for a new office building to be leased in Oslo.
Our principal offices located at Forusbeen 50, N-4035, Stavanger, Norway, comprise approximately 135,000 square metres of office space, and are owned by StatoilHydro.
A letter of intent has been signed with IT Fornebu Holding AS in Oslo for the long-term lease of a new 60,000 square metre office building to be built at Fornebu in Bærum municipality. The building will enable all of StatoilHydro's activities in the Oslo region to be collocated, and will be ready for occupation in the autumn of 2012. IT Fornebu Holding AS will be the owner and StatoilHydro will be the tenant.
For a description of our significant reserves and sources of oil and natural gas, see note 34 - supplementary oil and gas information in the Consolidated Financial Statements. in this report.
We have the following transactions with related parties, including state-owned entities and the bank DnB NOR:
Transactions with the Norwegian State
Transactions with other entities in which the Norwegian State is a major shareholder
Other transactions with the Norwegian State
The 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 3.10.8 Operational review-Regulation-Marketing and sale of the SDFI's oil and gas for more details.
Although StatoilHydro is majority-owned by the Norwegian State, it does not receive any preferential treatment with respect to licences granted by or under any other regulatory rules enforced by the Norwegian State.
Three employee-elected members of the board of directors and one member of the executive Committee each entered into loan agreements under this facility prior to 30 July 2002, and had, as of 31 December 2008, an aggregate total balance outstanding payable to DnB NOR under this loan facility of NOK 628,180. Members of the executive committee and the board of directors may not enter into loans under the foregoing programme.
Employees in certain employment levels are entitled to an interest free car loan from the company. Members of the executive committee and employee elected members of the board are generally excluded from this arrangement. As of 31 December 2008 none of the members of the executive committee had such loans, while one of the employee elected members of the board had a loan balance of NOK 260,555.
StatoilHydro delivered a strong operational performance in 2008 marked by record high equity production, the most expansive exploration programme ever and net operating income amounting to NOK 198.8 billion.
We also delivered significant synergies from the merger, and the ongoing integration and standardisation of offshore operations is aimed to further improve HSE results. These improvements will also increase StatoilHydro's flexibility and efficiency in the organisation.
With the addition of a strong balance sheet and active cost management, StatoilHydro is well positioned to manage through the global economic downturn. The group has the necessary strength and flexibility to pursue the long term strategic direction.
A downturn also represents an opportunity for improvements. We seek to reduce our own costs, improve quality and processes and work with our suppliers to bring industry costs down to more sustainable levels. The ongoing integration and standardisation of operational activities is a key element in our improvement agenda.
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).
Good operational performance is the best protection in times of uncertainty, and the merger was key to our continuous performance improvements. We delivered record production in 2008 and brought 12 new fields on stream.
In 2008, StatoilHydro delivered total liquids and gas entitlement production of 1.751 mboe per day, up 2% from 1.724 mboe per day in 2007. The contribution from international operations reached a record high and accounted for 18% of entitlement production. Total equity production increased by 5% from 2007 to 1.925 mboe per day in 2008. Strong production and high prices contributed to a net operating income of NOK 198.8 billion in 2008, compared to NOK 137.2 billion in 2007. The increase was mainly due to an increase in realised prices on both liquids and natural gas, measured in NOK, and was only partly offset by increased operating expenses caused by a higher activity level and new, more expensive fields coming on stream.
StatoilHydro delivered an extensive exploration programme in 2008. Of a total of 79 exploration wells completed before 31 December 2008, 40 were drilled outside the NCS. Thirty-five wells were declared as discoveries, of which eight are located outside the NCS. An additional eight wells have been completed since 31 December 2008. In 2008, 230 mmboe were added through revisions, extensions and discoveries. In total, the company achieved a reserve replacement ratio of 34% in 2008.
StatoilHydro maintained a high level of activity in progressing projects into production in 2008. Seven projects on the NCS and six international projects came on stream in 2008, and we also sanctioned 13 new projects for development, of which four are outside Norway.
During 2008, the group gained access to 20 new exploration licences in the Gulf of Mexico, Alaska, Brazil, Canada and the Faroe Islands. On the NCS we were granted access to 12 new licences, as operator in nine and as partner in three. In addition the group acquired a 15% interest in the Goliat field and a 10% interest in the Ragnarrock discovery on the NCS. In accordance with an agreement with Chesapeake Energy Corporation, StatoilHydro acquired a 32.5% interest in the Marcellus shale gas acreage in the USA. Statoilhydro also completed the purchase of the remaining 50% interest and became the operator of the Peregrino development offshore Brazil.
The report for 2007 was the first annual report in which financial statements for the merged StatoilHydro organisation was presented. Historical data was restated as if the merged company had existed for all periods.
Revenues and other income were NOK 133.2 billion higher than in 2007 and 134.5 million more than in 2006. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by StatoilHydro.
Revenues and other income totalled NOK 656.0 billion in 2008. This was NOK 133.2 billion more than in 2007 and NOK 134.5 billion more than in 2006. Most of the revenues 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 purchases net of inventory variations and sales, respectively.
Realised prices of liquids measured in NOK increased by 29% from 2007 to 2008. The increased prices of liquids contributed NOK 37.0 billion to the revenues, whereas the overall gas sales contributed NOK 6.1 billion and the increase in prices of natural gas contributed NOK 29.2 billion to the change. This was partly off-set by a decrease in liftings of liquids of NOK 9.0 billion.
Realised oil prices measured in NOK increased by 2% from 2006 to 2007. 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 partly off-set by a decrease in gas prices with a negative impact of NOK 10.4 billion.
The volumes of liquids lifted should 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 liquids from the fields. Total liquids liftings decreased from 1.081 mmboe per day in 2007 to 1.019 mmboe per day in 2008. From 2006 to 2007, total liquids liftings increased from 1.048 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 4.1.9 Financial performance-Strong operational performance-Reported volumes for more details on the PSA effects that cause differences between equity and entitlement volumes. See below for more details on the difference between lifted and produced volumes.
Total natural gas sales were 45.2 bcm (1,60 tcf) in 2008, 42.0 bcm (1.48 tcf) in 2007 and 40.2 bcm (1.42 tcf) in 2006. The 8% increase from 2007 to 2008 was mainly due to increased entitlement gas sales, but was partly offset by a net decrease in StatoilHydro third party sales volumes. The increase in entitlement sales volumes mainly relates to higher production from NCS in addition to the first full year of production from Shah Deniz in Azerbaijan. From 2006 to 2007, the increase of 1.8 bcm was mainly due to higher third party gas sales, and was partly offset by a net decrease in StatoilHydro entitlement sales volumes.
Net income (loss) from equity accounted investments. Our share of equity in net income of affiliates was NOK 1.3 billion in 2008, NOK 0.6 billion in 2007 and NOK 0.7 billion in 2006.
Other income was NOK 2.8 billion in 2008 compared to NOK 0.5 billion in 2007 and NOK 1.8 billion in 2006. The income in 2008 and 2007 was mainly related to gain from sale of assets whereas the income in 2006 was mainly related to a change in the write-down of inventory to production cost and gains from sales of assets.
Purchase, net of inventory variation includes the cost of the oil and NGL production that we purchase from the Norwegian State pursuant to the Marketing Instruction. The purchase, net of inventory variation amounted to NOK 329.2 billion in 2008 compared to NOK 260.4 billion in 2007 and NOK 249.6 billion in 2006. The increase from 2006 throughout 2008 was mainly caused by higher prices of liquids measured in NOK.
Operatingexpenses include field production costs and transport systems related to the company's share of oil and natural gas production. Operating expenses were NOK 59.3 billion in 2008 compared to NOK 60.3 billion in 2007 and NOK 44.8 billion in 2006. The 2% decrease from 2007 to 2008 was primarily due to restructuring costs related to the merger in 2007 and was only partly offset by increased costs related to start-up of new fields, higher activity and industry cost inflation in 2008. The 35% increase from 2006 to 2007 was primarily due to restructuring costs and other costs related to the merger, as well as higher operation and maintenance costs, increased transportation costs and new fields coming on stream.
Total liquids and gas production increased from 1.724 mmboe per day in 2007 to 1.751 mmboe per day in 2008. In 2006, total liquids and gas production was 1.708 mmboe per day. Equity production of oil and gas increased from 1.839 mmboe per day in 2007 to 1.925 mmboe per day in 2008. In 2006, equity production of liquids and gas was 1.780 mmboe per day.
Production cost per boe was NOK 38.1 for the 12 months ended 31 December 2008, compared to NOK 44.1 for the 12 months ending 31 December 2007.  In 2006, production cost per boe was NOK 28.4 (USD 4.44).
Based on equity volumes,  the production cost per boe for the two periods was NOK 33.5 and NOK 41.4, respectively. Normalised at a USDNOK exchange rate of 6.00, the production cost for the 12 months ending 31 December 2008 was NOK 38.6 per boe, compared to NOK 44.3 per boe for the 12 months ending 31 December 2007 and NOK 28.1 per boe for the 12 months ending 31 December 2006 . Normalised production cost is defined as a non-GAAP financial measure. 
The production cost per boe, both actual and normalised, has decreased significantly from 2007 to 2008, mainly due to a NOK 3,6 billion change in non-recurring restructuring costs relating to the merger in 2007, but the positive effect was partly offset by start-up of new fields, increased maintenance cost and general industry cost pressure.
Adjusted for restructuring costs and other costs arising from the merger recorded in the fourth quarter of 2007 and gas injection costs, the production cost per boe of equity production for the 12 months ending 31 December 2008 and 2007, was NOK 33.3 and NOK 31.2 respectively.
These figures have not been normalised for currency effects. Adjustments are made for certain costs related to the purchase of gas used for injection into oil-producing reservoirs. The adjustment facilitates comparison of field production costs with other fields which do not pay for their own gas used for injection into oil producing reservoirs.
Selling, general and administrative expenses include expenses related to the sale and marketing of our products, such as business development costs, payroll and employee benefits. These amount to NOK 11.0 billion in 2008, compared with NOK 14.2 billion in 2007 and NOK 10.8 billion in 2006. The 23% decrease from 2007 to 2008 was mainly due to restructuring costs related to the merger in 2007 and was only partly offset by increased costs related to higher activity and industry cost inflation in 2008. The 32% increase from 2006 to 2007 was also mainly due to restructuring costs and other costs arising from the merger in 2007, and was only partly offset by a pre-tax gain in 2006 of NOK 0.6 billion from the sale of Statoil Ireland.
Depreciation, amortisation and impairment includes depreciation of production installations and transport systems, depletion of fields in production, amortisation of intangible assets and depreciation of capitalised exploration expenditure. It also includes write-downs of impaired long-lived assets. These expenses amounted to NOK 43.0 billion in 2008, compared to NOK 39.4 billion in 2007 and NOK 39.5 in 2006.
The 9% increase in depreciation, amortisation and impairment expenses in 2008 compared to 2007 was due to impairment charges net of reversals of NOK 2.3 billion, mostly related to GoM, and an increase in production.
Exploration expenditures are capitalised to the extent that exploration efforts are considered successful, or pending such assessment. Otherwise, such expenditures are expensed. The exploration expense consists of the expensed portion of our exploration expenditure in 2008 and write-offs of exploration expenditure capitalised in previous years. The exploration expense was NOK 14.7 billion in 2008, NOK 11.3 billion in 2007 and NOK 10.7 billion in 2006.
In 2008, a total of 79 exploration and appraisal wells and nine exploration extension wells were completed, 48 on the NCS and 40 internationally. Thirty-five exploration and appraisal wells and six exploration extension wells have been declared as discoveries. In 2007, a total of 71 exploration and appraisal wells and two exploration extension wells were completed, 26 on the NCS and 47 internationally. Thirty-four exploration and appraisal wells and two exploration extension wells were declared as discoveries.
In 2007, a total of 71 exploration and appraisal wells were completed, 24 on the NCS and 47 internationally. In addition, two exploration extension wells were completed in the same period. Thirty-four of the exploration and appraisal wells were confirmed discoveries, 16 on the NCS and 18 internationally. Both exploration extension wells were discoveries.
In 2006, a total of 73 exploration and appraisal wells were completed, 18 on the NCS and 55 internationally. Five exploration extension wells were completed during the same period. Thirty-two of the exploration and appraisal wells were confirmed discoveries, eight on the NCS and 24 internationally. Two exploration extension wells were discoveries.
Net operating income was NOK 198.8 billion in 2008, compared to NOK 137.2 billion in 2007 and NOK 166.2 billion in 2006. The 45% increase from 2007 to 2008 was mainly due to higher realised prices on both liquids and natural gas, measured in NOK, and was only partly offset by increased operating expenses caused by a higher activity level and new, more expensive fields coming on stream.
The 18% decrease in net operating income from 2006 to 2007 was mainly due to an increase in operating, selling and administrative expenses stemming in part from restructuring and other costs arising from the merger, a negative change in derivatives, new fields coming on stream and increased activity levels. The restructuring costs and other costs arising from the merger were recorded primarily under operating and general and administrative expenses, and were allocated to the business areas where possible. Restructuring costs and other costs arising from the merger was primarily related to pensions and early retirement costs and impairment of assets in Sweden.
In 2008, net operating income was impacted of the following items: impairment charges net of reversals (NOK 4.8 billion), lower values of products in operational storage (NOK 2.8 billion), underlift (NOK 2.4 billion) and other accruals (NOK 2.3 billion) all impacted net operating income in 2008 negatively, while increased fair value of derivatives (NOK 1.8 billion), gains on derivatives to hedge the value of inventories (NOK 0.8 billion), gains on sales of assets (NOK 1.4 billion) and reversal of restructuring cost accrual (NOK 1.6 billion)
In 2007, net operating income was impacted of the following items: impairment charges net of reversals (NOK 2.8 billion), loss on derivatives to hedge the value of inventories (NOK 1.1 billion), other accruals (NOK 1.2 billion), restructuring cost accrual (NOK 6.7 billion) and other costs related to the merger (NOK 3.2 billion) all impacted net operating income in 2007 negatively, while increased fair value of derivatives (NOK 0.5 billion), overlift (NOK 1.6 billion), higher values of products in operational storage (NOK 1.5 billion) positively impacted net operating income in 2008.
In 2008, Net financial items amounted to a loss of NOK 18.4 billion, compared to a gain of NOK 9.6 billion in 2007.
The NOK 28.0 billion negative change from 2007 to 2008 was mostly attributable to NOK 32.6 billion in currency losses caused by a 29% weakening of NOK against USD in 2008 compared to a NOK 10.0 billion gain from a 14% strengthening of the NOK against the USD in 2007. The negative impact of currency exchange losses was partly offset by a NOK 9.9 billion increase in interest income and other financial items and a NOK 4.7 billion decrease in interest and other financial expenses.
Interest income and other financial items amounted to NOK 12.2 billion in 2008, compared to NOK 2.3 billion in 2007. The increase of NOK 9.9 billion mainly related to an increase in interest income of NOK 4.4 billion and an increase in income from securities of NOK 5.5 billion, mainly related to currency gains on USD denominated investments.
Interest and other financial expenses amounted to a net gain of NOK 2.0 billion in 2008, compared to a net loss of NOK 2.7 billion in 2007. The decrease of NOK 4.7 billion mainly related to a NOK 5.1 billion change in fair value adjustment of interest rate swap positions used to manage the interest rate risk on the external loan portfolio, due to a decrease in USD rates of 2.2% during 2008.
In 2007 net financial items amounted to an income of NOK 9.6 billion, compared to an income of NOK 5.1 billion in 2006. The 88% increase was principally the result of changes in currency gains and losses on the USD portions of our non-current financial liabilities outstanding and currency gains and losses on NOK hedging transactions. In both cases, currency gains and losses relate to changes in the USDNOK exchange rate, due to the weakening of the USD against the NOK.
Currency swaps are used for risk management purposes to hedge our long-term interest-bearing loans recorded in USD. As a result, the company's long-term debt portfolio is exposed to changes in the USDNOK exchange rate. The USD weakened by NOK 0.85 in relation to the NOK in 2007, compared to a weakening of NOK 0.51 in 2006.
Interest and other financial income amounted to NOK 2.3 billion in 2007, compared to NOK 3.7 billion in 2006. Interest and other financial expenses amounted to NOK 2.7 billion in 2007, compared to NOK 3.1 billion in 2006. The decrease in interest and other expenses was mainly due to a decrease in interest expenses on our long term loan portfolio, caused by currency effects and gains on interest rate swaps related to former Hydro long-term interest-bearing loan contracts. This portfolio was swapped from fixed to floating interest rate in the second half of 2007. These effects were partly offset by increased accretion expenses related to asset retirement obligations and a decrease in interest being capitalised. This was mainly due to the fact that fields such as Snøhvit and Ormen Lange came on stream in 2007.
Management of the portfolio of security investments, mainly related to equity securities, is held by our insurance captive, Statoil Forsikring AS, commercial papers is held by Statholding AS and liquidity funds is held by StatoilHydro ASA.
The Norwegian central bank's closing rate for USDNOK was 7.00 on 31 December 2008, 5.41 on 31 December 2007 and 6.26 on 31 December 2006. These exchange rates have been applied in StatoilHydro's financial statements.
In 2008 income taxes were NOK 137.2 billion, equivalent to a tax rate of 76.0%, compared to NOK 102.2 billion equivalent to a tax rate of 69.6% in 2007.
The increase in the tax rate in 2008 was mainly related to the net loss on financial items which is tax deductible at a lower tax rate than the average rate. In addition, the tax rate was increased by the deferred tax expense caused by currency effects in certain group companies which are taxable in a different currency than the functional currency. This was partly offset by the tax effect of a proportionally higher operating income being subject to a lower than average tax rate.
The effective tax rate is calculated as income taxes divided by income before taxes. Fluctuations in the effective tax rates from year to year are principally the result of non-taxable items (permanent differences), changes in the components of income between Norwegian oil and gas production, taxed at a marginal rate of 78%; other Norwegian income, including the onshore portion of net financial items taxed at 28%, and income in other countries taxed at the applicable income tax rates.
Adjusted for the non-recurring NOK 2.0 billion reduction in deferred tax liabilities relating to allocation of financial items with respect to the NCS and temporary differences in inter-company transactions, income taxes in 2006 were NOK 119.4 billion, equivalent to a tax rate of 69.7%. The tax rate in 2007 was lower than the adjusted tax rate in 2006, mainly due to higher net financial income and the increased effect of uplift deduction on the NCS. The lower tax rate was partly offset by relatively less income from outside the NCS being subject to lower taxation than the average tax rate.
In 2008, the Minority interest in net profit was NOK 0.005 billion, compared to NOK 0.5 billion in 2007. The minority interest is primarily related to the Mongstad crude oil refinery. In 2006, the minority interest in net profit was NOK 0.7 billion in 2006.
Net income was NOK 43.3 billion in 2008, compared to NOK 44.6 billion in 2007. The decrease was mainly due to a loss on financial items, high income taxes and increased operating expenses, and was only partly offset by higher prices on both liquids and natural gas, measured in NOK. In 2006, net income was NOK 51.9 billion and the decrease in 2007 was mainly due to lower operating income primarily because of restructuring costs and other costs arising from the merger, negative changes in derivatives and a higher tax rate, partly offset by higher net financial income.
The Board of Directors proposes an ordinary dividend of NOK 4.40 per share for 2008 to the Annual General Meeting, as well as NOK 2.85 per share in special dividend, making an aggregate total of NOK 23.1 billion. Ordinary dividend for 2007 was NOK 4.20 per share, as well as NOK 4.30 per share in special dividend, making an aggregate total of NOK 27.1 billion in 2007. In 2006, ordinary and special dividend was NOK 4.00 per share and NOK 5.12 per share, respectively, making an aggregate total of NOK 19.7 billion.
StatoilHydro expects entitlement production to remain at approximately 2008 levels in 2009. This assumes no adverse effects of potential reductions in OPEC quotas.
Maintenance activity is expected to have little impact on the equity production in the first quarter of 2009.
Capital expenditures for 2009, excluding acquisitions, are estimated to be around USD 13.5 billion. Approximately 50% of the forecasted investments for 2009 are in assets expected to contribute to growth in oil and gas production, about one third are related to investments in currently producing assets, with the remainder in other activities.
Unit production cost for equity volumes is estimated in the range of NOK 33 to 36 per barrel in the period from 2009 to 2012, excluding purchases of fuel and gas for injection. For 2009, the unit production cost is expected to be temporarily in the upper end of this range. The short term increase is expected to be caused by several large fields ramping up or preparing for production. In addition, some fields, such as ACG and Kvitebjørn, are not producing at full capacity. Furthermore, a high degree of maintenance during 2009 and continuing uncertainty regarding developments in the NOK/US dollar rate are expected to adversely affect the unit production cost in 2009.
StatoilHydro's ambition is to deliver a competitive ROACE compared with its peer group.
Exploration drilling is the primary tool for growing our business. We will continue to high-grade our large portfolio of exploration assets and we expect to maintain a high level of exploration activity in 2009, although slightly lower than in 2008. We expect to complete between 65 and 70 exploration and appraisal wells in 2009. Rigs have already been secured for most of the exploration drilling in 2009 and to some extent also for subsequent years. Exploration activity is estimated to amount to some USD 2.7 billion for 2009.
The year 2008 was one of the most volatile periods in the product, gas liquid and crude oil markets. While natural gas prices have been strong in Europe, crude oil and gas liquids prices decreased dramatically during the third and fourth quarters of 2008. We anticipate that crude oil and gas liquids prices will remain at relatively low levels and that prices will continue to be volatile at least in the near term.
The price development for natural gas is uncertain in the short term due to the financial turmoil. The natural gas market is also influenced by developments in the overall power market and the industrial segment in which gas competes with coal and fuel oil products, both having fallen significantly in price. Going forward, the value of natural gas in the power segment will increasingly be determined by competition with coal, renewable energy and nuclear energy. Climate policies and regulations will also be important factors in determining gas pricing.
New LNG capacity is coming on stream, and will be directed to the most favourable markets. As the amount of available LNG is anticipated to be substantial, there is a corresponding uncertainty related to the price effects to the relevant markets.
In the long term, we continue to have a positive view of gas as an energy source. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. In the US we believe that our position in the Marcellus shale gas acreage in combination with Gulf of Mexico production and our LNG regasification capacity position at Cove Point will provide a foundation for growth in our US market position in the years to come.
StatoilHydro's income could vary significantly with changes in commodity prices while volumes are fairly stable through the year. There is a small seasonal effect on volumes between winter and summer seasons due to normally higher off-takes of natural gas during cold periods. There is normally an additional small seasonal effect on volumes from a higher level of maintenance of offshore production facilities since generally better weather conditions allow for more maintenance work during the second and third quarter each year.
These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. See section 10 Forward looking statements.
Oil and natural gas are subject to internal transactions between our business segments before being sold in the market. We have established a pricing policy for transfers based on the market price.
The table details certain financial information for our four business segments: Exploration and Production Norway (EPN), International Exploration and Production (INT), Natural Gas (NG) and Manufacturing and Marketing (M&M). When combining business segment results, we eliminate intercompany sales. These include transactions recorded in connection with our oil and natural gas production in the EPN or INT segments, and also in connection with the sale, transport or refining of our oil and natural gas production in the M&M or NG segments.
EPN produces oil, which it sells internally to Oil Sales, Trading and Supply (OTS) in the M&M segment, which then sells the oil in the market. EPN also produces natural gas, which it sells internally to our NG segment, also for sale in the market. A large share of the oil and a small share of the natural gas produced by INT is also sold in the same way as the oil and the natural gas produced by EPN. The remaining oil and gas from INT is sold directly in the market. We 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 NG segments.
The transfer price formula for natural gas produced by EPN and marketed and sold by NG was changed as of 1 January 2008 in order to to better reflect fundamental changes in the markets for competing energies, for instance crude oil, for developments in natural gas markets and for changes in the natural gas sales contracts portfolio. The new internal price is linked to the gas market prices and it also better reflects the distribution of value creation between NG and EPN. In 2008 the transfer price was NOK 1.87 per scm. The change was effective as of 1 January 2008 and is reflected in our financial reporting, without restating prior periods. The average transfer price for natural gas per standard cubic metre was NOK 1.87 in 2008, NOK 1.39 in 2007 and NOK 1.36 in 2006. 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.
For additional information please refer to section 9.15 Segments in Notes to the Consolidated Financial Statements.
The table shows certain financial information for our four segments, including intercompany eliminations for each of the years in the three-year period ending 31 December 2008.
Our overall strategy on the NCS is to conduct safe, efficient and reliable operations and capture the full potential of the NCS by developing profitable oil and gas resources.
StatoilHydro has delivered an extensive exploration programme on the NCS in 2008. We participated in 39 exploration and appraisal wells, of which 27 resulted in discoveries. In addition, we completed nine exploration extensions, of which six resulted in discoveries. Total exploration expenditure was NOK 8.7 billion in 2008, compared with NOK 5.7 billion in 2007 and NOK 4.6 billion in 2006.
The total capital expenditure in 2008 was NOK 34.9 billion compared with NOK 31.1 billion in 2007 and NOK 29.2 million in 2006. Around half of our investments are related to new fields, while the other half are investments on existing fields.
In total, seven new fields came on stream on the NCS in 2008: Volve, Gulltopp, Gamma Main Statfjord, Vigdis Øst, Theta Cook, Oseberg Delta and Vilje.
Our production of oil and gas on the NCS averaged 1.461 mmboe per day in 2008, compared to 1.417 mmboe per day in 2007 and 1.474 in 2006.
Exploration and Production Norway generated total revenues of NOK 219.8 billion in 2008 and net operating income was NOK 166.9 billion. The average daily entitlement production in 2008 was 824 mbbl per day for oil and 637 mboe per day for gas.
We generated total revenuesof NOK 219.8 billion in 2008 and NOK 179.2 billion in 2007 and 2006. An increase of 31% in the average oil price in USD of oil sold by E&P Norway to Manufacturing and Marketing contributed NOK 54.6 billion, and a 35% increase in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas, contributed NOK 17.9 billion. Lifted volumes of natural gas increased by 6.7%, making a positive contribution of NOK 3.2 billion. This was offset by a negative currency exchange rate deviation of NOK 11.1 billion due to a 7.2% decrease in the USD/NOK exchange rate. In addition, other income increased by NOK 3.1 billion, mainly as a result of a change in the fair value of derivatives. Lifted volumes of crude oil decreased by 2.5%, making a negative contribution of NOK 3.1 billion.
From 2006 to 2007 there was an increase of 11% in the average oil price in USD of oil sold by E&P Norway to Manufacturing and Marketing contributed NOK 13.3 billion, and a 2% increase in the average transfer price in NOK of natural gas sold by E&P Norway to Natural Gas, contributed NOK 1.1 billion. This was offset by a negative currency exchange rate deviation of NOK 12.0 billion due to a 9% decrease in the USD/NOK exchange rate. Lifted volumes of crude oil decreased by 3%, making a negative contribution of NOK 3.8 billion, and there was a 2% decrease in lifted volumes of natural gas, making a negative contribution of NOK 0.9 billion. In addition, other income increased by NOK 2.4 billion, mainly as a result of higher income from derivatives and higher processing income.
The average daily lifting of oil in 2008 was 808 mbbl per day, compared to 831 mbbl per day in 2007 and 856 mbbl per day in 2006.
Average daily entitlement oil production in 2008 was 824 mbbl per day, compared to 818 mbbl per day in 2007 and 864 mbbl per day in 2006. The increased production from 2007 to 2008 was mainly related to start-up of the Volve field in February 2008, higher production at Kvitebjørn until the shutdown from August 2008 compared to 2007 when Kvitebjørn was shut down to allow safe drilling operations most of the year, new wells at Fram and building up production at Ormen Lange. The increase was partly offset by declining production from wells in the Grane, Norne, Troll Olje, Tordis, Visund and Sleipner fields.
The reduced production from 2006 to 2007 was largely caused by the shutdown of production on the Kvitebjørn field from 1 May 2007 in order to allow drilling operations to be carried out safely, as well as a natural decline on the Oseberg field. The reduction in production was partly offset by increased production from the Kristin field, which reached plateau level in late 2007.
The average daily entitlement gas production was 637 mboe per day in 2008 (equal to 101.3 mmcm or 3.58 mmcf), compared to 599 mboe in 2007 (equal to 95.2 mmcm or 3.36 mmcf) and 610 mboe in 2006 (equal to 97.0 mmcm or 3.42 mmcf).
Operating, general and administrative expenses were NOK 23.4 billion in 2008. Operating, general and administrative expenses were NOK 29.4 billion in 2007 and NOK 19.6 billion in 2006. Operating costs amounted to NOK 23.5 billion in 2008. Operating costs amounted to NOK 29.1 billion in 2007 and NOK 19.2 billion in 2006.
The decrease of NOK 6.0 billion in operating, general and administrative expenses from 2007 to 2008 was mainly due to a decrease in other expenses of NOK 6.8 billion, mainly due to restructuring costs as a result of the merger in 2007 and a decrease in transportation costs by NOK 1.3 billion in 2008 due to increased elimination and reduced booking. In addition, selling, general & administrative expenses decreased by NOK 0.4 billion and processing costs decreased by NOK 0.3 billion, from 2007 to 2008. This was partially countered by an increase of NOK 2.7 billion in operating plant costs, which was largely due to start up of new fields of NOK 1.1 billion, increased cost for gas purchased for injection at Grane by NOK 0.5 billion and increased operational activity.
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.
The unit production cost was NOK 37.31 per BOE in 2008 compared with NOK 46.26 per boe in 2007 and NOK 26.93 per boe in 2006. The total production cost was NOK 19.9 billion in 2008, compared with NOK 23.9 billion in 2007 and NOK 14.5 billion in 2006.
The 19% decrease from 2007 to 2008 is due to a decrease in costs of 17% and an increase in production of 3%. Indirect operating costs decreased by NOK 7.2 billion mainly due to restructuring costs as a result of the merger in 2007 and refund in 2008 of the licence partners' proportional share of the restructuring costs. Operating plant costs increased by NOK 2.7 billion, due to both higher activity and increased pressure on costs in the industry. NOK 1.1 billion is attributed to startup of new fields. Other variable costs increased by NOK 0.8 billion due to loss on sales of assets.
The 60% increase from 2006 to 2007 is due to both an increase in costs of 65% and a decrease in production of 4%. Indirect operating costs increased by NOK 5.5 billion due to restructuring costs as a result of the merger in 2007. Direct operating costs increased by NOK 3.2 billion, due to both higher activity and increased pressure on costs in the industry.
Depreciation, depletion and impairment expenses were NOK 24.0 billion in 2008. Depreciation, depletion and amortisation expenses were NOK 23.0 billion in 2007 and NOK 20.9 billion in 2006. The NOK 1.0 billion increase from 2007 to 2008 was mainly due to higher depreciation costs as a result of higher depreciation offshore due to increased production and changes in the portfolio of producing fields.
The NOK 2.1 billion increase from 2006 to 2007 was mainly due to higher depreciation costs as a result of asset retirement costs and higher depreciation offshore due to changes in the portfolio of producing fields.
Exploration expenditure (including capitalised exploration expenditure) in 2008 amounted to NOK 8.7 billion, compared to NOK 5.7 billion in 2007, and NOK 4.6 billion in 2006. The increase stems primarily from a higher number of wells drilled. The increase in exploration expenditure from 2006 to 2007 was mainly due to increased drilling and seismic activity, as well as to a significant increase in the area fee.
From 2006 to 2007 the drilling expenditure increased by approximately NOK 0.4 billion, while the increase in seismic activity amounted to NOK 0.3 billion. The increase in area fee was due to new regulations on the NCS and it contributed approximately NOK 0.4 billion to the increased costs.
Exploration expenses in 2008 were NOK 5.5 billion, compared to NOK 3.6 billion in 2007, and NOK 3.5 billion in 2006, mostly due to more wells being drilled.
In 2008, 39 exploration and appraisal wells and nine exploration extension wells were completed on the NCS, of which 27 exploration and appraisal wells and six exploration extension wells were discoveries. In 2007, 24 exploration and appraisal wells and two exploration extension wells were completed. Of these, 16 exploration and appraisal wells and both exploration extension wells resulted in discoveries.
In 2006, 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 seven exploration and appraisal wells were ongoing at the end of the fourth quarter of 2008. Ten exploration and appraisal wells have been completed since 31 December 2008. Of these, eight exploration and appraisal wells were discoveries: Obesum2, Visund S1, Dompap/Måke sidetrack, Fulla, Curran, Pan sidetrack, Katla and Asterix. Verona and Obelix were dry.
The reconciliation of exploration expenditure with exploration expenses is shown in the table below.
Net operating income in 2008 was NOK 166.9 billion compared to NOK 123.2 billion in 2007 and NOK 135.1 billion in 2006. The NOK 43.7 billion increase in 2008 was mainly due to price and volume effects and NOK 5.5 billion in restructuring and other costs arising from the merger in 2007.
The NOK 11.9 billion decrease from 2006 to 2007 was mainly due to price and volume effects, NOK 5.5 billion in restructuring and other costs arising from the merger, higher operating costs of NOK 3.2 billion, mainly due to higher operation and maintenance costs and well maintenance, increased depreciation, mainly due to higher asset retirement costs, which contributed NOK 2.1 billion to the decrease, an increase in other operating expenses of NOK 1.0 billion and processing and transportation costs increasing by NOK 0.4 billion in 2007.
We expect to continue our high level of exploration activity in 2009 and we plan to drill approximately 30-35 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 wells in frontier areas of the Norwegian Sea and in the Barents Sea. We have secured rig capacity for our drilling activity level in 2009.
A plan for development and operation (PDO) of the Goliat field in the Barents Sea has been submitted to the government by operator Eni. StatoilHydro has a 35% share in the field.
In the period leading up to 2012, several new fields are expected to commence production. Gjøa, Vega/Vega Sør and Morvin are expected to commence production in 2010, while the BP-operated Skarv field is expected to commence production in 2011.
Yttergryta is the first field that StatoilHydro as a joint company has developed from PDO to production start.
Three new fields will commence production during 2009; Yttergryta has already started producing, while Alve and Tyrihans will commence production later.
Our strategy is to develop key positions in four focus areas: deep water, heavy oil, gas value chains and harsh environments. It is also the framework for new growth and portfolio optimisation.
International exploration activities in 2008 have focused on high-grading our portfolio with strict prioritisation and sequencing of the drilling targets. Fourty exploration and appraisal wells were completed in 2008 and at year end eight of these were considered to be discoveries or confirmed discoveries. At year end, nine wells were pending final evaluation. The total exploration expenses were NOK 9.2 billion in 2008, compared with NOK 7.7 billion in 2007.
Our international entitlement production was 290 mboe per day in 2008 compared to 307 mboe per day in 2007. The average daily equity production of oil and gas was 465 mboe per day in 2008, compared to 422 mboe in 2007. Equity volumes represent produced volumes under a PSA contract that corresponds 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. Entitlement volumes lifted is the basis for revenue recognition, while equity production volumes affect operating costs more directly. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.
Acquisitions in 2008 included the purchase of 50% of the Peregrino project in Brazil, making StatoilHydro 100% owner and operator of the field. StatoilHydro formed a strategic alliance with Chesapeake Energy Corporation and acquired a 32.5% interest in Chesapeake's Marcellus shale gas acreage onshore USA. We closed the sale of all our shallow water assets on the Shelf in the Gulf of Mexico (GoM) to Mariner Energy, Inc. and divested our interests in the UK fields Dunlin (28.76%) and Merlin (2.35%).
The total capital expenditure of NOK 48.7 billion in 2008 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 Peregrino in Brazil and Marcellus Shale acreage in USA.
INT generated total revenues of NOK 46.1 billion in 2008 and net operating income was NOK 12.8 billion. The average daily entitlement production of liquid was 232 mbbl and the average daily entitlement production of gas was 59 mboe.
We generated total revenues of NOK 46.1 billion in 2008, compared to NOK 41.6 billion in 2007 and NOK 32.6 billion in 2006. The increase from 2007 to 2008 was mainly related to a 19% increase in realised liquid and gas prices, which contributed NOK 7.7 billion, gain from sale of assets, and income from affiliated companies which contributed NOK 2.2 billion. This was partly offset by a 11% decrease in the lifted volumes, which contributed negatively by NOK 5.4 billion.
The average daily liquid lifting was 211 mbbl in 2008, compared with 250 mbbl in 2007 and 191 mbbl in 2006.
The average daily entitlement production of liquid was 232 mbbl in 2008, compared with 252 mbbl in 2007 and 194 mbbl in 2006. The 9% decrease in average daily liquid production from 2007 to 2008 was mainly related to decreased production from ACG in Azerbaijan due to the Central Azeri gas leakage and Kizomba A in Angola coming off plateau, in addition to overall reduced entitlement volumes from PSA fields due to high realised prices. These decreases were partly offset by start-ups of Agbami in Nigeria and the Saxi-Batuque and Mondo fields in Angola.
The average daily entitlement production of gas was 59 mboe in 2008 (equivalent to 9 mmcm or 331 mmcf), compared to 55 mboe in 2007 (equivalent to 9 mmcm or 309 mmcf) and 40 mboe in 2006 (equivalent to 6 mmcm or 224 mmcf). The 7% increase in daily gas production from 2007 to 2008 was mainly related to ramp-up of production from Shah Deniz in Azerbaijan, and start-up of new gas fields in the GoM in the third and fourth quarter of 2007 (Q, Spiderman, San Jacinto). The increase was partly offset by divestment of the GoM shelf fields with effect from year end 2007 and reduced offtake and maintenance turnaround at the In Salah field in Algeria.
The average daily equity liquid and gas production was 465 mboe per day in 2008, compared with 422 mboe in 2007 and 304 mboe in 2006.
The unit of production cost based on entitlement volumes was USD 7.6 per boe in 2008 compared to USD 5.9 per boe in 2007 and USD 5.8 per boe in 2006. Measured in NOK, it was 42.2 per boe in 2008, 34.4 per boe in 2007 and 37.5 in 2006. The 23% increase in unit of production cost measured in NOK from 2007 to 2008 is mainly due to reduced entitlement production and increased cost related to new fields on stream, increased activity, inflation and industry cost pressure.
The unit of production cost based on equity volumes was USD 4.6 per boe in 2008 compared to USD 4.3 per boe in 2007 and USD4.50 per boe in 2006. Measured in NOK it was 42.2 per boe in 2008, 25.0 per boe in 2007 and 28.9 per boe in 2006. See report section 4.1.9 Financial performance-Strong operational performance-Reported Volumes for a description of entitlement and equity volumes.
Operating, general and administrative expenses decreased by NOK 0.1 to NOK 10.5 billion in 2008 compared to NOK 10.6 billion in 2007 and NOK 7.2 billion in 2006.
Depreciation, depletion and amortisation expenses were NOK 13.7 billion in 2008, compared with NOK 11.1 billion in 2007 and NOK 14.4 billion in 2006. The 23% increase in 2008 compared to 2007 was due to an increased net impairment write-down effect of NOK 0.9 billion mainly related to market conditions, and a NOK 1.7 billion increase in ordinary depreciation mainly due to new assets coming on stream and a change in the proved reserves estimates in 2008, which forms the basis for the unit of production depreciation.
Depreciation, depletion and amortisation expenses were NOK 11.1 billion in 2007, compared with NOK 14.4 billion in 2006. The 23 decrease in 2007 compared to 2006 was mainly due to the NOK 4.9 billion impairment write-down effect on depletion, depreciation and
Exploration expenditure was NOK 9.1 billion in 2008, compared with NOK 8.5 billion in 2007 and NOK 8.7 billion in 2006. The increase from 2007 to 2008 was mainly due to more expensive wells, higher field evaluation costs and delineation drilling on the oil sands project in Canada.
Exploration expenses were NOK 9.2 billion in 2008, compared with NOK 7.7 billion in 2007 and NOK 7.2 billion in 2006. The increase from 2007 to 2008 was mainly due to more expensive wells, higher field evaluation cost and delineation drilling on the oil sands project in Canada and impairment write-down effects mainly related to changes in market conditions. The increase was partly offset by an increased capitalisation rate.
In total, 40 exploration and appraisal wells were completed in 2008 and at year end, eight of these were considered to be discoveries or confirmed discoveries. At year end, nine wells were pending final evaluation. In 2007, 47 exploration and appraisal wells were completed, 18 of which were considered discoveries. In 2006, 55 exploration and appraisal wells were completed, 24 of which were considered discoveries.
Net operating income in 2008 was NOK 12.8 billion compared to NOK 12.2 billion in 2007 and NOK -3.3 billion in 2006. The increase was mainly related to the price effect which contributed NOK 7.7 billion and gain from sale of assets and income from affiliated companies of NOK 2.2 billion and other miscellaneous increases of NOK 0.2 billion, partly offset by decreased entitlement production contributing NOK 5.4 billion, increased depreciation, depletion and amortisation of NOK 2.6 billion and exploration NOK 1.5 billion.
Our exploration strategy remains unchanged, but we have adjusted our exploration activity somewhat due to changes in the oil price. We expect to drill approximately 30-35 international exploration and appraisal wells in 2009.
Ninety-six percent of our projected 2012 production is related to already-sanctioned fields. During 2009 we expect the Gimboa field in Angola and Tahiti and Thunder Hawk fields in the USA to start production. We expect our short term production to be affected by OPEC quotas.
Our exploration strategy remains unchanged as we view exploration as our primary growth tool. We will continue to look at acreage acquisitions in the areas that have high resource potential. However, we have adjusted our exploration activity somewhat due to changes in the oil price environment and therefore expect slightly lower activity in 2009 compared to last year.
Approximately 30-35 international exploration and appraisal wells are expected to be drilled in 2009. Rig capacity has been confirmed for this drilling.
We will continue to develop and execute new projects in the portfolio with a focus on cost consciousness and capital flexibility.
Gas exports from the NCS reached a record high in 2008 and are expected to grow further.
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 at a record level in 2008 and are expected to grow. In 2008, StatoilHydro sold 39.3 bcm entitlement gas. In addition, we sold 32.0 bcm NCS gas on behalf of the SDFI. Most of the gas was sold to European energy providers under long-term contracts. Our market share is approximately 20-25% in Germany and France and approximately 15% in the UK.
Two significant factors strongly influence our financial results: the external sales price and the internal transfer price.
In 2008, natural gas prices reached record highs. Our volume weighted average price was NOK 2.40 per scm in 2008, an increase of 45% from 2007. Most gas supply contracts in Europe are indexed towards oil products, such that a change in oil prices will affect the gas markets with some time delay (6-9 months). Increasing oil prices up until the summer months of 2008 were followed by high prices in the gas markets in late 2008. During the second half of 2008 oil prices fell sharply from more than 140 dollars per barrel to some 40 dollars per barrel. We expect this will affect natural gas prices in 2009.
All of the gas from the NCS sold by the Natural Gas business area is purchased from Exploration & Production Norway (E&PN). Previously, the internal transfer price formula was linked to the oil price for Brent Blend. A new market-based internal price for natural gas was put into effect from 1 January 2008. The transfer price formula for natural gas has been updated to better reflect fundamental changes in the markets for competing energies, i.e. crude oil, developments in natural gas markets and changes in the natural gas sales contracts portfolio. In 2008 the transfer price was NOK 1.87 per scm.
The total capital expenditure of NOK 2.0 billion in 2008 was lower than in previous years, mainly due to fewer pipeline, storage and processing plants being under development.
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 110.8 billion in 2008.
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 110.8 billion in 2008, compared with NOK 73.5 billion in 2007 and NOK 97.1 billion in 2006. The 51% increase from 2007 to 2008 was mainly due to the high prices for natural gas throughout 2008 compared with 2007, as well as a 10% increase in entitlement sales volumes.
The 24% decrease in total revenues from 2006 to 2007 was mainly due to declining natural gas prices measured in NOK in 2007 and negative changes in fair value of derivatives.
Cost of goods sold increased by 43% from 2007 to 2008 and decreased by 8% from 2006 to 2007. The increase from 2007 to 2008 is mainly related to a 34% increase in transfer price and higher NCS volumes purchased from E&PN. The decrease from 2006 to 2007 is mainly related to a decrease in the third party purchase price of natural gas, partly offset by a slight increase in the transfer price paid to E&PN.
Operating, selling and administrative expenses increased by 12% from 2007 to 2008 mainly due to higher transportation costs related to increased LNG transportation and increased booking of throughput capacity in Gassled in 2008. The 6% increase from 2006 to 2007 is mainly caused by early retirement cost accruals and increased accruals for removal costs.
In 2008, the net operating income was NOK 12.5 billion, compared to NOK 1.5 billion in 2007. The volume weighted average sales price increased by 45%, amounting in total to NOK 31.2 billion, of which the rise in European piped gas price contributed NOK 27.0 billion. Changes in European gas prices lag behind changes in crude oil prices.
Net operating income for 2007 was NOK 1.5 billion, compared with NOK 21.7 billion in 2006. The 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.
With effect from 2008, Natural Gas provides an explanation of the adjusted net operating income from its two main business activities: Processing and Transport and Marketing and Trading. Processing and Transport consists mainly of our share in Gassled and the Technical Service Provider role at Kårstø and Kollsnes. Marketing and Trading consists of our gas sales and trading activities. The Marketing and Trading activity carries the associated transportation costs within the Natural Gas segment. The split between business segments is only restated for 2007.
Net operating income in Processing and Transport was NOK 5.6 billion in 2008, compared to NOK 5.6 billion in 2007. Processing and Transport income increased by NOK 0.3 billion, while fixed operating expenses and depreciation increased by NOK 0.3 billion.
Net operating income in Marketing and Trading was NOK 7.0 billion in 2008, compared to a loss of NOK 4.1 billion in 2007. Marketing and Trading income increased by NOK 11.1 billion, mainly due to increased price (NOK 31.2 billion) and higher volumes sold (NOK 7.7 billion). The main offsetting factors to the increased income were NOK 24.2 billion in higher costs of goods sold, NOK 1.5 billion in increased operating expenses, NOK 0.5 billion increased depreciation expences, and NOK 0.2 billion increased selling and administrative expenses. The increased operating expenses are mainly due to higher transportation cost in 2008.
Total natural gas sales were 45.2 bcm (1.60 tcf) in 2008, 42.0 bcm (1.48 tcf) in 2007 and 40.2 bcm (1.42 tcf) in 2006. The 8% increase from 2007 to 2008 in gas volumes sold was mainly due to increased entitlement gas sales, but this was partly offset by a net decrease in StatoilHydro third party sales volumes. Third party gas is mainly used for portfolio balancing and optimisation and trading purposes. The increase in entitlement sales volumes mainly relates to higher production from NCS in addition to the first full year with production from Shah Deniz, Azerbaijan. Of the total natural gas sales in 2008, 39.3 bcm (1.39 tcf) was entitlement gas, including 1.4 bcm (0.05 tcf) of gas from Shah Deniz in Azerbaijan and 0.9 bcm (0.03 tcf) from Gulf of Mexico, and 2.6 bcm (0.92 tcf) was the SDFI's share of US piped gas.
The 4% increase from 2006 to 2007 in gas volumes sold was mainly due to increased third-party gas sales, but this was partly offset by a net decrease in StatoilHydro entitlement sales volumes. The decrease in entitlement sales volumes was mainly related to production problems on Kvitebjørn throughout 2007.
The weighted average gas price for our sales was NOK 2.40 per scm in 2008, compared to NOK 1.66 per scm in 2007, an increase of 45%. The increase in price from 2007 to 2008 was mainly due to an increase in prices for oil products (such as gas oil and fuel oil) and other competing energy sources, as well as higher 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. The weighted average price is only available from 2007.
The present economic downturn means that there is currently sufficient supply to meet demand. In the longer term, however, the market balance is more uncertain. Increasing transport distances and complexity of new resources suggest an increase in prices.
In the short term, the present economic downturn means that there is sufficient supply in Europe, Asia and North America to meet demand expectations. Balance in supply and demand will probably impact gas prices.
In the longer term, however, the market balance is more uncertain and the current economic impact on long term demand and the development of new gas projects are difficult to assess. Increasing transport distances and complexity of new resources would seem to suggest an upward price trend over time, ensuring sufficient prices to maintain supplies.
The short term gas market is affected by new LNG capacity coming on stream and reduced demand for energy. LNG in the Atlantic basin is responding to changes in prices between major markets, taking advantage of arbitrage opportunities. Our view on these events is that we have value creation potential through increased gas exports due to the proximity and flexibility 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. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. The trend for LNG as a link between regional markets is expected to continue as more LNG will come on stream, making gas a commodity that is driven by global development.
Our gas strategy remains firm. In 2009, we plan to have focus on on extracting maximum value from our long term gas sales portfolio through maintaining daily supply regularity and contract modernisation as a part of regular contract revisions. In addition, we will focus on participating in the short term gas markets in order to add value through balancing, trading and optimisation activities. Business development efforts will be concentrated on commercialising our position in the Shah Deniz field and our newly-acquired gas position in the US. This position in the Marcellus shale gas acreage, in combination with Gulf of Mexico production and our LNG regasification capacity position at Cove Point, will provide a foundation for growth in our US market position in the years to come.
In 2008, we experienced volatile market conditions and a worldwide economic downturn, further emphasising the importance of efficient operations and prudent project execution.
During 2008 we also continued the standardisation and simplification process throughout the business area, in order to increase efficiency.
Our total capital expenditure of NOK 6.8 billion in 2008 was higher than in previous years, triggered by high activity in projects and a major turnaround at the Mongstad refinery. Capital expenditure was NOK 4.8 billion in 2007 and NOK 2.5 billion in 2006.
We will continue to strengthen our global trading position by securing physical infrastructure and building physical third party positions based on our production in selected regions. Physical activity pertains to an actual commodity, and does not involve trading in financial instruments. The average daily third party crude volumes sold in 2008 were 0.53 mmbbl, compared to 0.52 mmbbl in 2007 and 0.42 mmbbl in 2006. Although 2008 has been a year with high financial uncertainty and increased counterparty risk, no credit losses have been realised on customer sales during the year.
Energy and retail
On 21 October 2008, the European Commission granted permission for StatoilHydro to take over the bulk of the Jet self-service retail chain in Scandinavia from ConocoPhillips. To comply with the terms set by the commission, StatoilHydro agreed to sell 80 of the 274 filling stations acquired. StatoilHydro will also be obliged to sell 118 Hydro stations in Sweden as part of the divestment package.
The transaction is an important element in our endeavours to become the leading fuel company in Scandinavia.
We also continued to strengthen our position as one of the leading suppliers of biofuels in Scandinavia and the Baltic countries during 2008. Biofuels are now available at more than 1,300 service stations in seven different countries.
In Manufacturing and Marketing, total revenues and other income increased to NOK 531 billion, mainly due to higher oil prices.
Total revenues and other incomeincreased from NOK 428 billion in 2007 to NOK 531 billion in 2008. The increase from 2007 to 2008 was mainly due to higher prices on crude and other oil products. The average crude price in USD increased by approximately 40% in 2008 compared to 2007, but was partly offset by the weakening of the average USD exchange rate by almost 4%.