|• STATOIL ANNUAL REPORT ON FORM 20-F • ARTICLES OF ASSOCIATION • FIXED CHARGES • RULE 13A-14(A) CERTIFICATION OF CHIEF EXECUTIVE OFFICER • RULE 13A-14(A) CERTIFICATION OF CHIEF FINANCIAL OFFICER • RULE 13A-14(B) CERTIFICATION OF CHIEF EXECUTIVE OFFICER • RULE 13A-14(B) CERTIFICATION OF CHIEF FINANCIAL OFFICER • CONSENT OF ERNST & YOUNG AS • CONSENT OF DEGOLYER AND MACNAUGHTON • REPORT OF DEGOLYER AND MACNAUGHTON • CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC • REPORT OF CAWLEY, GILLESPIE & ASSOCIATES, INC • COURTESY FILE ON FORM 20F|
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
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Ordinary shares of NOK 2.50 each 3,188,647,103
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Table of content
This section presents our performance in the following important areas: Income, cash flow, return, proved reserves, oil production and price, gas production and price, serious incidents, total recordable injuries and carbon dioxide emissions.
Statoil's Annual Report on Form 20-F for the year ended 31 December 2011 ("Annual Report on Form 20-F") is available online at www.statoil.com.
Statoil is subject to the information requirements of the US Securities Exchange Act of 1934 applicable to foreign private issuers. In accordance with these requirements, Statoil files its Annual Report on Form 20-F and other related documents with the Securities and Exchange Commission, the SEC. It is also possible to read and copy documents that have been filed with the SEC at the SEC's public reference room located at 100 F Street, N.E., Washington, D.C. 20549, USA. You may also call the SEC at 1-800-SEC-0330 for further information about the public reference rooms and their copy charges, or you may log on to www.sec.gov. The report can also be downloaded from the SEC website at www.sec.gov.
Statoil discloses on its website at http://www.statoil.com/en/about/corporategovernance/statementofcorporategovernance/pages/default.aspx, and in its Annual Report on Form 20-F (Item 16G) significant ways (if any) in which its corporate governance practices differ from those mandated for US companies under the New York Stock Exchange (the "NYSE") listing standards.
In 2011, Statoil delivered record net operating income. The value-creating Peregrino, Leismer and Gassled transactions, combined with strong oil and gas prices throughout the year, contributed to the strong financial results.
In 2011, production volumes were in line with expectations. Production start-up of new fields and ramp-up of production on existing fields combined with strong oil and gas prices enabled Statoil to deliver strong financial results and cash flows.
Statoil publishes financial data in accordance with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB) and as adopted by the European Union (EU).
Statoil delivered strong financial results and cash flows in 2011 as a result of production in line with expectations and high gas and liquids prices. We presented a technology-focused upstream strategy, we further streamlined the portfolio through divestments and acquisitions, and we delivered historic exploration results.
We were awarded interests in 11 production licenses on the NCS, and will be operator for eight of these licenses. One of the operatorships is in the Barents Sea, one in the Norwegian Sea and six are in the North Sea.
In Angola, the national oil company Sonangol announced that Statoil had been selected for operatorship and participation in several offshore pre-salt blocks.
We announced first oil production from the Leismer Demonstration Project in Canada. Statoil's oil sands leases are located in north east Alberta.
The Norwegian government decided to gather more facts relevant to a possible future impact assessment for Lofoten and Vesterålen. At the same time the government decided not to carry out an impact assessment for the duration of the current Norwegian parliament.
The Vega field in the North Sea and the Tyrihans subsea field in the Norwegian Sea were officially opened. The fields are expected to make important contributions to our production on the NCS.
At a ceremony in Bangkok, Statoil signed a Memorandum of Understanding (MoU) with PTT Exploration and Production of Thailand. Under the MoU, the companies will seek to cooperate in the areas of conventional and unconventional resources and liquefied natural gas (LNG) in a global setting.
In the Statfjord A operating plans, Statoil assumed that production shutdown may take place in 2014. Therefore we outlined a draft program for an impact analysis of platform removal, including a description of plans for cessation and decommissioning.
Statoil received the investigation report from the Petroleum Safety Authority Norway on the Gullfaks B gas leak on 4 December 2010. Statoil published its own investigation of the incident in February.
Two new fast-track development projects were launched on the NCS, namely Gamma/Harepus and Snorre B template.
Statoil and KazMunayGas signed a Heads of Agreement (HoA) on the Abay block in the Kazakhstani sector of the Caspian Sea. Under the HoA, the parties will conduct an evaluation of the hydrocarbon potential of the Abay block.
We started oil production on the Peregrino field offshore Brazil. This marked a safe and efficient start-up of Statoil's largest international operatorship to date.
A new oil find was made by Statoil immediately adjacent to the Peregrino field in the Campos Basin offshore Brazil.
Statoil farmed in to three offshore exploration licenses in Indonesia, significantly expanding our presence in the country.
Statoil and Petrobras signed a letter of intent to expand the cooperation between the companies in respect of exploration, and to assess how the two companies can benefit from operational synergies.
Statoil's first fast-track-project - Visund South - moved ahead as planned. The seabed template commenced its journey out to the field located south of Gullfaks in the North Sea.
Statoil and Sintef, an independent research organisation in Scandinavia, signed a new and comprehensive research framework agreement.
The plan for development and operation of the Valemon gas and condensate field in the North Sea was approved by the Norwegian parliament. Production start-up is expected in 2014.
Statoil celebrated its 10th anniversary as a listed company. We presented a technology-focused upstream strategy.
Statoil signed two agreements for the sale of the major part of Statoil's onshore wind power activities in Norway, enabling the group to focus more of its efforts on offshore wind projects.
Statoil awarded the contract for construction of two new drilling rigs specifically designed for use on mature fields on the NCS.
Statoil and partners Petoro AS, Det norske oljeselskap ASA and Lundin Norway AS made a significant oil discovery on the Aldous Major South prospect (PL 265) in the North Sea. Communication between the Aldous and Avaldsnes (PL 501) oil discoveries in the North Sea was confirmed, indicating that this is one field.
Lundin Norway AS, as operator for license PL501 located in the North Sea, announced increased estimated recoverable resources within the Avaldsnes discovery in production license PL501. Statoil confirmed a significant upside potential and that it would continue to collect and analyze data before concluding on updated estimates.
Statoil and Brigham Exploration Company announced that they had entered into a merger agreement for Statoil to acquire all of the outstanding shares of Brigham through an all-cash tender offer. The total equity value was approximately USD 4.4 billion. The US unconventional plays hold a substantial resource base and represent an increasingly important part of future energy supplies.
Statoil, together with partners Petoro AS, Det norske oljeselskap ASA and Lundin Norway AS, confirmed significant additional volumes in its appraisal well in the Aldous Major South discovery (PL265) in the North Sea.
Statoil, Chevron Canada and Repsol E&P Canada were named successful bidders for exploration rights on two land parcels in the Flemish Pass Basin, offshore Newfoundland and Labrador, Canada.
Statoil raised a total of USD 1.75 billion of debt in the capital markets. The transactions are expected to increase the financial flexibility of the company.
Statoil acquired a 30% participating interest from Tullow Oil in block 47 offshore Suriname.
Statoil decided to farm down three and exit five assets on the NCS for a total consideration of USD 1.625 billion. The buyer is Centrica, a UK based energy company and an established NCS player.
Statoil and Centrica entered into a long term gas sales agreement for the delivery of 5 billion cubic meters (bcm) per year from 2015 to 2025 to the UK market.
Statoil was awarded the operatorship and a substantial working interest in a large offshore exploration license in eastern Indonesia.
Statoil increased its sponsorship of the FIRST® (For Inspiration and Recognition of Science and Technology) LEGO League, involving the building of LEGO-based robots by young students. As part of the group's Heroes of Tomorrow sponsorship programme, the agreement represents the group's first global sponsorship agreement.
Statoil announced broad efforts to identify the direct and underlying causes of the Gullfaks C well control event on 19 May 2010. This was in response to post-incident orders from the Petroleum Safety Authority Norway.
Statoil is an integrated energy company that is primarily engaged in oil and gas exploration and production activities. Statoil's headquarters are in Norway, and the company has business operations in 41 countries and territories.
Statoil ASA is a public limited liability company organised under the laws of Norway and subject to the provisions of the Norwegian act relating to public limited liability companies (the Norwegian Public Limited Companies Act). Statoil is the leading operator on the Norwegian continental shelf (NCS). It is also expanding its international activities.
Entitlement oil and gas production outside Norway accounted for 19.6% of our total production, which averaged 1,650 mmboe per day in 2011.
As of 31 December 2011, we had proved reserves of 2,276 mmbbl of oil and 3,150 bcm (equivalent to 17,681 tcf) of natural gas, corresponding to aggregate proved reserves of 5,426 mmboe.
We have business operations in 41 countries and territories. As of 31 December 2011, there were 31,715 employees in the Statoil group. Of this total, 10,385 were employees of the Statoil Fuel & Retail group, in which we held a 54% majority ownership interest as of 31 December 2011.
We are among the world's largest net sellers of crude oil and condensate, and we are the second-largest supplier of natural gas to the European market. We also have substantial processing and refining operations. We are contributing to the development of new energy resources, have ongoing activities in the areas of offshore wind and biofuels, and are at the forefront of the implementation of technology for carbon capture and storage (CCS).
In further developing our international business, we intend to utilise our core expertise in areas such as deep water, heavy oil, harsh environments and gas value chains in order to exploit new opportunities and develop high-quality projects.
The Statoil group, the main business areas and staff functions are presented in the following sections of this report.
The figure below provides an overview of the countries and territories in which Statoil has business operations.
Statoil was formed in 1972 by a decision of the Norwegian Storting (parliament). It was listed on the stock exchanges in Oslo and New York in 2001.
Statoil was incorporated as a limited liability company under the name Den norske stats oljeselskap AS on 18 September 1972. As a company wholly owned by the Norwegian State, Statoil's role was to be the government's commercial instrument in the development of the oil and gas industry in Norway.
In 2001, the company became a public limited company listed on the Oslo and New York stock exchanges, and it changed its name to Statoil ASA. On 1 October 2007, the oil and gas division of Norsk Hydro ASA was merged with Statoil, and the company was given the temporary name of StatoilHydro. On 1 November 2009, the company changed its name back to Statoil.
We have grown in parallel with the Norwegian oil and gas industry, which dates back to the late 1960s. Initially, our operations primarily focused on exploration for and the production and development of oil and gas on the Norwegian continental shelf (NCS) as a partner.
In the 1970s, we commenced our own operations, made important discoveries and began oil refining operations, which have been of great importance to the further development of the NCS.
We grew substantially in the 1980s through the development of large fields on the NCS (Statfjord, Gullfaks, Oseberg, Troll and others). We also became a major player in the European gas market by securing large sales contracts for the development and operation of gas transport systems and terminals. During the same decade, we were involved in manufacturing and marketing in Scandinavia and established a comprehensive network of service stations.
The 1990s were characterised by substantial improvements in the production performance of our large fields. This was the result of intense technological development on the NCS. We laid the foundation for future improvements by becoming a leading company in the fields of floating production facilities and subsea development. The company grew strongly, expanded in new product markets and increased its commitment to international exploration and production.
Since 2000, our business has grown as a result of substantial investments on the NCS and internationally. Our ability to fully realise the potential of the NCS was strengthened through the merger with Hydro's oil and gas division, which also bolstered our global competitiveness.
In recent years, we have utilised our expertise to design and manage operations in various environments in order to grow our upstream activities outside our traditional area of offshore production. This includes the development of heavy oil and shale gas projects.
In October 2010, we successfully carried out an initial public offering (IPO) of Statoil Fuel & Retail ASA on the Oslo stock exchange (Oslo Børs), partially divesting and reducing our interest in the business relating to service stations.
2011 was a very significant year for Statoil. It started with the implementation of a new organisational model and reporting segments. Throughout the year, we delivered strong financial results and cash flows as a result of strong production in line with expectations and high gas and liquids prices. We delivered historic exploration results, particularly through the Skrugard prospect in the Barents Sea the Johan Sverdrup discovery in the North Sea and the Peregrino South discovery in Brazil. We also started oil production on the large Peregrino field off the coast of Brazil - Statoil's largest international operatorship to date.
We further streamlined our portfolio in 2011. On the divestment side, Statoil decided to divest a 24.1% direct and indirect stake in the Gassled natural gas transportation infrastructure joint venture, and entered into an agreement to farm down three and exit five assets on the NCS. On the acquisition side, Statoil and Brigham Exploration Company announced an agreement for Statoil to acquire all of the outstanding shares in Brigham. The transaction was completed in 2011.
The US unconventional plays constitute a substantial resource base and represent an increasingly important part of future energy supplies. Statoil has progressively developed industrial capabilities through early entrance into the Marcellus and Eagle Ford shale plays. Entering the Bakken and Three Forks tight oil plays and taking on operatorship is a significant new step for Statoil. We aim to position ourselves as a leading player in the fast-growing US onshore oil and gas industry.
Although petroleum-related activities on the NCS and internationally have accounted for the bulk of our business, we are increasingly participating in projects that focus on other forms of energy - such as offshore wind and carbon capture and storage (CCS) - in anticipation of the need to expand energy production, strengthen energy security and combat adverse climate change.
Information about Statoil's competitive position relies on a range of sources, including analyst reports, independent market studies and our internal assessments of our market share.
The information about Statoil's competitive position in the business overview and strategy, and operational review sections is based on a number of sources - including investment analyst reports, independent market studies, and our internal assessments of our market share based on publicly available information about the financial results and performance of market players.
We have endeavoured to be accurate in our presentation of information based on other sources, but have not independently verified such information.
A new corporate structure was implemented with effect from 1 January 2011. The changes were made in order to simplify the organisation, enhance value creation and clarify internal accountability.
The figure below illustrates the new corporate structure:
Development and Production Norway (DPN)
Development and Production International (DPI)
Development and Production North America (DPNA)
Marketing, Processing and Renewable Energy (MPR)
Technology, Projects and Drilling (TPD)
Global Strategy and Business Development (GSB)
Activities relating to the Exploration business area are allocated to and presented in the respective development and production segments.
The Other reporting segment includes activities in TPD, GSB, Corporate Staffs and Services, and activities related to the CFO.
After the successful listing on the Oslo Stock Exchange in October 2010, Statoil's remaining ownership share in the listed company Statoil Fuel & Retail ASA, is 54%. SFR is fully consolidated in Statoil's financial statements, and is reported as seperate reporting segment followed up by the CFO area. SFR is a leading road transportation fuel retailer that is present in eight countries in Scandinavia, and Central and Eastern Europe. SFR is also involved in the sale of stationary energy, marine fuel, aviation fuel, lubricants and chemicals. As of December 2011, SFR had a network of 2,305 service stations in its eight countries of operations. Statoil Fuel & Retail ASA also markets refined products directly to consumer and industrial markets.
Statoil's vision is "Crossing Energy Frontiers". It guides our long-term strategy as an upstream-oriented and technology-based energy company.
At the heart of our strategy is a strong focus on operations and HSE. We operate in an industry that is becoming increasingly complex. Access to and competition for resources is becoming more challenging. The pace of change will continue to increase in the future and the importance of quality in execution will be even higher - making safe and efficient operations more important than ever.
While the current global economic situation is fragile, non-OECD economies are still growing at an impressive rate. This factor should play a large role in keeping global energy demand high in the future.
Since the 2008 financial crisis, OECD countries have struggled to stage a stable and sustained recovery. Key economies are hampered by high sovereign debt and large deficits. Households and businesses remain very cautious, and a rebalancing of public and private balance sheets in the OECD will take time. Non-OECD economies, on the other hand, have remained relatively robust, growing at about three times the pace of the OECD average.
Global oil demand climbed slightly in 2011 as growth in non-OECD markets offset the decline in the OECD markets. In spite of muted demand, prices hovered around USD 110/bbl for much of 2011, in contrast to the period 2008-2009, when demand contraction led prices to fall to below USD 40/bbl. The ramp-up in prices as demand rebounded in 2010 reflected growing concern about future capacity additions, which, along with actual supply-side shocks, continued to play a role in maintaining high prices in 2011.
In gas markets, 2011 was marked by a 9% increase in LNG imports to Asia in the wake of the Fukushima tragedy. This increase contrasted with stagnant North American and declining European demand. The recovery in gas demand following the 2008-2009 recession heralded a new paradigm in pricing as continued aggressive development of unconventional gas in North America broke the link between Henry Hub and UK National Balancing Point (NBP) and Asian LNG prices. Henry Hub was below USD 4/MMBtu for much of 2011, whereas the UK NBP price was closer to USD 10/MMBtu, and Asian LNG prices were even higher, reflecting the willingness of buyers there to pay an energy security premium.
Given OECD weakness and non-OECD robustness, Statoil expects the world economy to grow by 3.1% annually over the coming 10 years, with an OECD annual average of 2.1% and a non-OECD annual average of 5.4%. This anticipated economic development pattern means increasing economic gravitation towards the East, at the expense of the West.
Solid non-OECD growth is expected to support energy demand over the next 10 years. In the period from 2011 to 2020, internal Statoil research suggests that growth in oil demand will average 1.0% (~0.8 mbpd) annually and will - along with continued concern about upstream capacity - support oil prices close to the levels seen recently. Statoil expects non-OPEC capacity to rise by only 0.3-0.4 mbpd per year on average going forward, which means increased demand for OPEC liquids and reduced OPEC spare capacity.
Statoil's internal research suggests that gas demand in Europe and North America will increase by 1-2% per year in the period up to 2020, while Asian demand will grow at around 5% per year in the same period. Both Europe and Asia will rely more on imported LNG to meet demand, which will probably result in upward pressure on prices. This contrasts with the situation in North America, where continued development of shale gas is expected to maintain downward pressure on prices in the short to medium term.
The current global economic situation is fragile, and the actual development path could be either more subdued or more buoyant than currently anticipated. As a result, energy prices could vary considerably in the short to medium term.
Production to reserve growth remains a key challenge for international oil companies, as it has been over the last five to ten years. We believe Statoil's compound average growth rate in the last decade (2.7%) is highly competitive. Access to new resources has been made more difficult as a result of increasing competition and tighter fiscal conditions in many resource-holding countries. Corporate responses to this situation have been varying mixes of moves into unconventional assets such as shale gas, increased focus on exploration, and the rationalisation of asset portfolios to strengthen balance sheets and reposition for growth.
Going forward, the decline of legacy fields and the increasingly technically challenging nature of new field developments are expected to put upward pressure on capital and operational expenditures. Together with depressed equity markets and tightening credit, this will put a strain on the liquidity of many industry players in the years ahead and may trigger industry restructuring.
Statoil aims to grow and enhance value through its technology-focused upstream strategy, supplemented by selective positions in the midstream and in low-carbon technologies.
Statoil made sound strategic progress in 2011. First, a major reorganisation was implemented at the beginning of the year, then an updated strategy was presented to investors in June.
Statoil's immediate priorities remain to conduct safe, reliable operations with zero harm to people and the environment, and to deliver production growth.
To succeed going forward we are focusing strategically on the following:
Revitalising Statoil's legacy position on the NCS
Current plans put the number of IOR projects at approximately 100. Future oil price expectations will extend the economic lifetime of most of the major fields, and thereby reduce the time criticality of many of the IOR projects. This will allow for greater flexibility in determining the optimal timing of these projects.
A number of larger field developments are currently in the project pipeline. They include the Luva, Dagny, Skrugard and Aldous/Avaldsnes fields, which are expected to contribute considerably to Statoil's total production over the period 2016-2020.
Of the approximately 40 smaller field development projects identified on the NCS, Statoil currently has nine projects in its fast-track development portfolio. Plans for development and operation have already been submitted for five of them (Skuld, Hyme, Stjerne, Vigdis North-East and Visund South) and two more (Visund North and Vilje South) have received licence approval. Fast-track developments are expected to contribute approximately 100,000 barrels of oil equivalent per day (boepd) by 2014.
Building offshore clusters
These countries include some of the most attractive basins in the industry - such as the USA (Gulf of Mexico [GoM] and onshore), Brazil, Angola and Azerbaijan (Caspian). Based on its efforts over the last 15-20 years, Statoil is now in a position to build at least three to five offshore clusters in select areas over the next eight to ten years.
Offshore clusters are areas that make a material contribution to total production, where Statoil is the operator and has a mix of assets in different stages of development, and where we possess considerable expertise, both below and above ground. Through the cluster focus, our goal is to achieve greater economies of scale, capture synergies and thereby increase profitability.
The first oil from the Peregrino field in Brazil was produced in 2011. We continue to work on ramping up Peregrino production, and, in the time ahead, we will focus on further developing the Peregrino area and maturing the existing exploration portfolio.
In Angola, we are working to optimise the non-operated portfolio, and to explore the significant pre-salt acreage we were awarded in 2011 (18,400 square kilometres). This is an exciting new play with parallels to the Brazilian pre-salt acreage.
In the GoM, Statoil was one of the first oil companies to be issued a permit to resume drilling after the Macondo incident. Here, besides managing our non-operated production, we are stepping up our efforts to mature, high grade and drill the best prospects in our drilling programme, and we continue to focus on developing improved subsurface capabilities in order to increase recovery rates.
Developing into a leading exploration company
To replicate this success we aim to balance the strengthening of our exploration portfolio in offshore clusters (North Sea, Angola, Brazil, the Caspian and the GoM) with frontier exploration and more high-impact wells to unlock new plays (e.g. the Norwegian Sea, Barents Sea and other Arctic areas, Tanzania and Indonesia).
More specifically, we will focus on:
Stepping up our activity in unconventional resources
Our priorities in unconventional resources include:
By 2020, we anticipate that North American production of unconventional resources will contribute in excess of 12% of Statoil's total oil and gas production.
Creating value from a superior gas position
In the medium to long term, our strategic thinking is directed towards the continued promotion of gas as an important part of meeting European objectives for energy security and emission reductions. Statoil has a pan-European perspective that includes North Africa (Algeria), the Caspian and LNG options, in addition to gas from the NCS. We strongly believe that natural gas is the most cost-effective bridge to a low-carbon economy.
Beyond Europe, Statoil's planned midstream gas and liquids activities in North America are progressing in step with the building of our upstream unconventional resources business. These activities encompass a mix of capacity commitments, ownership and/or operation of gathering, transportation and storage facilities, marketing alliances and trading operations. They are considered important in terms of both flow assurance and margin capture.
Continuing portfolio management to enhance value creation
The transactions signed and/or closed in 2011 (the Gassled farm-down, Brigham acquisition, Snøhvit farm-up, Valemon/Hild swap, the acquisition of Marcellus and Eagle Ford in-fill acreage and the NCS asset package sale to Centrica) further underpin our ability to redeploy capital and create value.
Utilising oil and gas expertise and technology to open new renewable energy opportunities
Our first priority in offshore wind will be to complete the Sheringham Shoal development in the UK. Beyond Sheringham Shoal, our aim is to utilise the experience gained to develop new projects. In addition, work also continues on developing the proprietary Hywind floating offshore wind concept. Whether at Sheringham Shoal or through Hywind, our overall ambition is to play an active role in reducing costs in order to make offshore wind profitable on a stand-alone basis.
CCS represents a key technology for reducing carbon emissions. We have become a world leader in the development and application of CCS, and we intend to build on our carbon storage experience (Sleipner, In Salah and Snøhvit projects) to position ourselves for a future commercial CCS business. We are maturing two carbon capture projects at present - the large-scale Technology Centre Mongstad testing facility and the full-scale Carbon Capture Mongstad plant.
We continually develop and deploy innovative technologies to achieve safe and efficient operations, and deliver on our strategic objectives. We have also defined four business-critical aspirations that we will strive to achieve over the next decade.
We believe that technology is a critical success factor in the business environment within which we operate. This environment is characterised by an increasingly broad and complex opportunity set, stricter demands on our licence to operate and tougher competition. In this context, technology is increasingly important for resource access, value creation and growth.
Our track record has demonstrated our ability to overcome significant technical challenges through the development and deployment of innovative technologies. At present, we are an industry leader in subsurface production and multiphase pipeline transportation.
Statoil's technology strategy is based on three main principles:
Prioritising business-critical technologies
Strengthening our licence to operate
Expanding our capabilities
Statoil's operational review follows the segments resulting from the new corporate structure implemented on 1 January 2011. However, certain disclosures about oil and gas reserves are based on geographical areas, as required by the SEC.
The new corporate structure is presented in the section Organisational structure.
In this chapter, the operations of each reporting segment are presented. Underlying activities or business clusters are presented according to how the reporting segment organises its operations. However, the Exploration operating segment's activities, which include group discoveries and the appraisal of new exploration resources, are presented as part of the various development and production reporting segments (Development and Production Norway and Development and Production International).
The operating segments TPD and GSB are included in the reporting segment Other.
As required by the SEC, Statoil prepares its disclosures about oil and gas reserves and certain other supplementary oil and gas disclosures based upon geographical area. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa and the Americas.
For further information about disclosures concerning oil and gas reserves and certain other supplementary disclosures based upon geographical area as required by the SEC, see the sections Operational review - Production volumes and price information and Operational review - Proved oil and gas reserves.
Development and Production Norway (DPN) consists of our field development and operational activities on the Norwegian continental shelf (NCS).
Development and Production Norway is the operator of 44 developed fields on the NCS. Statoil's equity and entitlement production on the NCS was 1.316 mmboe per day in 2011, which was about 71% of Statoil's total production. Acting as operator, DPN is responsible for approximately 72% of all oil and gas production on the NCS. In 2011, our average daily production of oil and natural gas liquids (NGL) on the NCS was 693 mboe, while our average daily gas production on the NCS was 99.1 mmcm (3.5 bcf).
We have ownership interests in exploration acreage throughout the licensed parts of the NCS, both within and outside our core production areas. We participate in 227 licences on the NCS and are operator for 171 of them.
As of 31 December 2011, Statoil had a total of 1,369 mmbbl of proved oil reserves and 444 bcm (15.7 tcf) of proved natural gas reserves on the NCS.
Activity levels in Development and Production Norway were high in 2011 with several new projects sanctioned - including eight fast-track projects.
Final investment decisions were made for the following projects:
* Partner-operated assets
Our NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.
We are extending production from existing fields through improved reservoir management and increased oil recovery (IOR) projects. We also operate a significant number of exploration licences.
Statoil's NCS portfolio consists of licences in the North Sea, the Norwegian Sea and the Barents Sea.
We have organised our production operations into four business clusters - Operations South, Operations North Sea West, Operations North Sea East and Operations North. The Operations South and Operations North Sea West and East clusters cover our licences in the North Sea. Operations North covers our licences in the Norwegian Sea and in the Barents Sea, while partner-operated fields cover the entire NCS and are included internally in the Operations South business cluster.
When possible, the fields in each cluster use common infrastructure, such as production installations and oil and gas transport facilities. This reduces the investments required to develop new fields. Our efforts in these core areas will also focus on finding and developing smaller fields through the use of existing infrastructure and on increasing production by improving the recovery factor.
We are making active efforts to extend production from our existing fields through improved reservoir management and the application of new technology.
Statoil takes an active approach to portfolio management on the NCS. By continuously managing our portfolio, we create value by optimising our positions in core areas and new growth areas in accordance with our strategies and targets
The highlights from 2011 are as follows:
For further details regarding the above-mentioned transactions see the section - Global Strategy and Business Developement (GSB) - GSB key events in 2011- below.
2011 was one of the best exploration years ever for Statoil on the NCS.
We made two Statoil-operated important oil discoveries during the year - the Aldous discovery (PL265) in the North Sea and the Skrugard discovery (PL532) in the Barents Sea. The number of exploration wells increased from 17 exploration wells and four exploration extensions completed in 2010 to 25 exploration wells and four exploration extensions of production wells completed in 2011. This increase is mainly due to the maturation of targets based on new knowledge gained from the extensive 2008 and 2009 drilling campaigns and new acreage awarded in the Norwegian government's 20th concession round.
The 2011 portfolio has been well-balanced and split between infrastructure-led exploration (ILX) and growth/frontier wells (higher volume potential). Eighteen of the 25 wells were wildcats drilled to test new prospects, and 15 of the wildcats were operated by us. Eleven of the 15 Statoil-operated wildcat wells were discoveries, while the three partner-operated wildcat wells were dry.
The Aldous Major South discovery in PL265 on the Utsira Height in the Sleipner area is situated 140 kilometres west of Stavanger and 35 kilometres south of the Grane field. The discovery was made in sandstone from the Jurassic age in a reservoir of very high quality. The licence was awarded to Statoil as operator in 2001. The partners are Petoro, Det norske and Lundin. Five wells have been drilled in the licence, four of which have encountered hydrocarbons. All the wells have contributed valuable information and understanding of the geological history of the area. The PL265 partnership will consider further exploration drilling to clarify the potential and optimal development solution.
The Avaldsnes discovery was made in PL501 in 2010, with Lundin as operator and Statoil and Mærsk as partners. Avaldsnes and Aldous are connected, and it is important going forward to gain a good understanding of the reservoir distribution between the two licences.
The Skrugard discovery is located about 250 kilometres off the coast from the Melkøya LNG plant in Hammerfest. The well proved to have excellent reservoir parameters, and the volume discovered is large enough for a new stand-alone development in the Barents Sea. One new wildcat well in this licence was spudded in late 2011 on the Havis prospect, with a discovery in early 2012. Following that, an appraisal well on the Skrugard discovery is being drilled after the Havis well in Q1 2012.
In addition to the Johan Sverdrup and Skrugard discoveries, we have made several commercial discoveries in the North Sea, such as Krafla, Krafla West, Opal and Rutil. These wells were drilled to add resources to our existing production installations. The Opal and Rutil discoveries are labelled fast-track candidates, which means that their development phases and production start-ups can be expedited.
We did not drill any wells in the Norwegian Sea deepwater region in 2011. The focus has been on interpreting and gaining an understanding of the 2010 well results in order to choose the right target for the next exploration well.
We were awarded 11 licences in the 21st concession round on the NCS - eight as operator and three as a partner. Four of our operatorships were awarded in the Barents Sea and four in the Norwegian Sea. All of the new licences in the Norwegian Sea are concentrated in the Luva area and fit well with the strategy for the area. In the Barents Sea, there is a strong focus on the licences surrounding the Skrugard discovery and the Hoop area, which is classified as a high-potential frontier area.
We have also been awarded interests in 11 production licences in the 2011 Awards for Pre-defined Areas (APA) on the NCS, eight of which are operatorships. In the North Sea, we will be operator in eight of the nine licences awarded, and we will participate as partner in one or two licences in the Norwegian Sea.
In June, the maritime border delimitation agreement was ratified by the Norwegian and Russian foreign ministers. The area is still immature. The Norwegian Ministry of Petroleum and Energy and the Norwegian Petroleum Directorate have completed the first phase of seismic acquisition in the Barents Sea East and have announced that they will complete phase two for the resolved area in 2012.
The table below shows our exploratory and development wells drilled on the NCS in the last three years.
Potential producing areas
The NCS is the backbone of our operations. We continue to explore and develop the NCS as an operator and partner using the best available technology and increasingly standardised development solutions.
The following fields are currently under development on the NCS, and they include both traditional and fast-track processes.
The Gudrun field is located in the North Sea. The field will be developed with a separate steel jacket-based process platform for separation of the oil and gas. Gas and partly stabilised oil will be transported in separate pipelines from Gudrun to Sleipner. Gas will be further transported through the Gassled system, while oil will be transported together with Sleipner condensate by pipeline to the Gassco-operated Kårstø plant near Haugesund. The plan for development and operation (PDO) was approved by the Norwegian authorities in June 2010. Production is estimated to start in 2014. The total investments are estimated to amount to NOK 18.5 billion. On 15 December 2010, Statoil signed an agreement with Marathon Petroleum Norge to buy their 20% share of the production licences covering the Gudrun field. As a consequence of this, Statoil's share in the development is now 75%, effective from 1 April 2011.
The jacket for the processing platform has been constructed by Aker Verdal. It was successfully installed in its field location in the last week of July 2011. Conductor driving was subsequently performed, and drilling of the first production well started on 6 September, four weeks ahead of schedule. A total of seven production wells will be drilled and completed prior to production start-up.
Valemon, which is located in the North Sea, will be developed with a steel jacket platform with gas, condensate and water separation. Drilling will be performed using a jack-up rig. Rich gas will be transported via the Huldra pipeline to Heimdal for processing. Sales gas will be transported in Vesterled to St Fergus, or, alternatively, in the Statpipe pipeline to Draupner. There will be a condensate tie-in to Kvitebjørn for stabilisation and further export in pipelines to Mongstad. The PDO for the Valemon field development, submitted to the Norwegian Ministry of Petroleum and Energy (MPE) in October 2010 was approved by the Norwegian parliament on 10 June 2011. The development cost of Valemon is currently estimated to be NOK 19.8 billion, and production start-up is estimated to take place during the fourth quarter of 2014. Statoil's ownership interest in Valemon is per 31.12.2011 64.275%. In October 2011, a sales agreement was made with Centrica Resources (Norge) AS for a 13% share of Valemon, reducing Statoil's ownership interest to 53.775%. This transaction is expected to be closed in the second quarter of 2012.
Contracts for the construction of the steel jacket (Heerema Vlissingen), for transportation and installation of the jacket (Heerema Marine Contractors) and a contract for the tie-in modifications on Kvitebjørn (Bergen Group Rosenberg) have all been awarded. In addition, the contract for drilling production wells has been awarded to Seadrill Offshore AS. The drilling rig West Elara is to be used for this operation.
Visund South is located in the Tampen area of the North Sea. The field was discovered in early 2009. Statoil is the operator, with an ownership interest of 53.2%. The PDO was formally submitted to the MPE on 21 January 2011, and it was approved by the Norwegian parliament on 10 June 2011. The development cost is currently estimated to be NOK 5.6 billion. The field will be developed with a subsea template tied back to the Gullfaks C platform. The template has been constructed by FMC Technologies. It was installed on the field in June 2011. Production drilling commenced on 11 September. Production is scheduled to start in the fourth quarter of 2012.
Hyme is an oil discovery in the Halten area of the Norwegian Sea, about 15 kilometres east of the Njord field. Statoil is operator and holds a 35% ownership interest in the discovery. The PDO for the field, which was submitted to the MPE on 12 May 2011, was approved by the MPE on 28 June. The development cost is currently estimated to be NOK 4,8 billion. The selected development concept includes a subsea template that will be tied back to the Njord A platform, one multilateral production well and one water injection well. Production start-up is scheduled for the first quarter of 2013.
Stjerne is an oil discovery in the Oseberg area, located 13 kilometres south west of the Oseberg South platform. Statoil is the operator and holds a 49.3% ownership interest. The discovery was made in March 2009 and it is being developed as a one-template subsea tie-in to the Oseberg South platform, with two oil production wells and two water injection wells for pressure support. The PDO for the field was submitted to the MPE on 2 May 2011 and approved by the MPE on 16 September 2011. The development cost is currently estimated to be NOK 5.5 billion. Production start-up is scheduled for the first quarter of 2013.
Vigdis North-East is an oil discovery made in 2009 approximately seven kilometres south west of the Snorre A platform in the Tampen area of the North Sea. Statoil is the operator and holds a 41.5% ownership interest. Vigdis North-East will be developed with a subsea template tied in to the Vigdis B subsea template. The oil will be processed on the Snorre A platform. The field will be developed with three oil production wells and one well for water injection. The PDO was submitted to the MPE on 12 April 2011 and approved by the MPE on 16 September 2011. The development cost is currently estimated to be NOK 4.5 billion. Production start-up is scheduled for December 2012.
Skuld is a development project covering the Dompap and Fossekall oil discoveries north east of the Norne field in the Norwegian Sea. Dompap was discovered in 2009 and Fossekall in April 2010. Statoil is operator and holds a 63.955% ownership interest in the development. The Skuld development concept contains of one subsea template at Dompap and two subsea templates on Fossekall, and a total of six oil production wells and three water injection wells. The subsea installations will be tied back to the Norne floating production storage and offloading vessel (FPSO) through a production flowline. The PDO for the development was submitted to the MPE 26 September 2011, and sanctioned 20 January 2012. The development cost is currently estimated to be NOK 10.6 billion. Production start-up is scheduled for early 2013.
Vilje South is a southern extension of the Vilje field, located north of Heimdal in the North Sea. Vilje South is described as a possible upside in the Vilje PDO (named Mygg). The development cost is currently estimated to be NOK 1.1 billion. Statoil is the operator and holds a 28.853% ownership interest. Vilje South will be developed as a single stand-alone subsea satellite well tied back to the existing subsea facility on Vilje, with production start-up scheduled for the third quarter 2013.
Skarv is an oil and gas field located in the Norwegian Sea in which Statoil has an interest of 36.165%, with BP as operator and E.ON Ruhrgas & PGNiG as the other partners. The field is being developed with an FPSO vessel and five subsea multi-well installations. Oil will be exported by offshore loading, and gas will be exported via the Åsgard export system. The operator currently expects production to start in the second quarter of 2012. The total development cost at the investment decision was estimated to be NOK 32 billion by the operator BP.
The PDO for Goliat was submitted in February 2009 and approved by the Norwegian authorities in June the same year. Goliat is the first oilfield to be developed in the Barents Sea. The field is being developed with subsea wells tied back to a circular FPSO vessel. The oil will be offloaded to shuttle tankers. The Goliat development is operated by Eni, which has an interest of 65%. Statoil is the only partner, with an interest of 35%. The operator expects production start-up to occur in late 2013. The operator has estimated the development costs for the field to be NOK 31 billion.
Marulk, in which Statoil holds an interest of 50%, is a gas and condensate field located in the Norwegian Sea 25 kilometres south west of Norne. The field was discovered in 1992. The final investment decision was taken in early 2010 and proved reserves were booked in 2010. The PDO was approved by the MPE in July 2011.The field is a subsea development with two wells tied back to Norne. Rich gas will be transported through the Norne pipeline and the Åsgard Transport System for processing to sales gas at Kårstø. Condensate will be stored and offloaded commingled with the Norne crude. Production is estimated to start in the second quarter of 2012. The operator estimates the total investments to be NOK 4 billion. The operator is Eni, but Statoil is carrying out the project work.
The table below shows some key figures as of 31 December 2011 for our major development projects.
The following projects are being developed on the NCS to extend the life of existing installations, increase oil recovery and exploit new profitable opportunities.
The Gullfaks B water injection upgrade project includes replacement of the pipeline from Gullfaks A to Gullfaks B, upgrading of the existing water injection system and increased water injection capacity on Gullfaks B. The project is expected to be completed in the first half of 2013.
The main purpose of the Kvitebjørn pre-compression project is to increase and accelerate gas and condensate recovery by facilitating low-pressure production. The project includes the installation of a turbine-driven compressor in a new module on the platform. Start-up is scheduled for December 2013.
The Njord North-West Flank project will enable Njord A to drill and produce from the NWF reservoir. Drilling started in October 2011 and production is scheduled to start in November 2012.
The Troll A 3rd and 4th pre-compressor project is described in the original PDO for the Troll field. The purpose of the project is to increase gas production by installing two extra pre-compressors on the Troll A platform. This will enable low-pressure production from the Troll East and West gas provinces. The project was sanctioned by the licence partners in the fourth quarter 2011. The investment costs are estimated to be NOK 11 billion. The expected completion date is the fourth quarter 2015. Statoil's ownership interest in the project is 30.584%. The Troll field is located in the northern part of the North Sea.
The Åsgard subsea compression project will install compact subsea compressors in the Midgard part of the Åsgard fields. The purpose of the project is to increase the recoverable reserves by introducing subsea compression of the wellstream. The Åsgard subsea compression project will implement a significant amount of new subsea technology, and will be the first implementation of subsea gas compression. The PDO was submitted to the Norwegian Ministry of Petroleum and Energy (MPE) in August 2011, and approval by the authorities is expected in early 2012. The investment cost for the project is estimated to be NOK 14 billion. The expected completion date is early 2015. Statoil holds a 34.57% ownership interest in the project.
We continued developing the NCS in 2011, and delivered strong results in a year marked with extensive turnarounds and operational challenges.
In 2011, our total entitlement oil and NGL production in Norway was 252 mmbbl, and gas production was 36.2 bcm (1,287 bcf), which represents an aggregate of 1.316 mmboe per day.
The following table shows the NCS production fields and field areas in which we are currently participating. Field areas are groups of fields operated as a single entity.
The following table shows our average daily entitlement production of oil, including NGL and condensates, and natural gas for each of the years ending 31 December 2011, 2010 and 2009.
Operations South includes a large part of Statoil's production activity on the NCS. The main producing fields in the Operations South area are Statfjord, Snorre, Tordis, Vigdis, Sleipner and partner-operated fields.
Statoil's share of the area's production in 2011 was 155 mbbl per day of oil, condensate and NGL, and 220 mboe per day of gas, or 375 mboe per day in total. Of this, partner-operated assets (see the section Partner-operated fields) accounted for 43 mbbl per day of oil, condensate and NGL, and 122 mboe per day of gas, or 165 mboe per day in total. Even after over 30 years of production from this area, we believe that there are still substantial opportunities for increased value creation.
Statoil has taken several initiatives to identify and implement measures to increase and prolong production from the Operations South area. These initiatives involve IOR, and they have resulted in a prolongation of planned production beyond the current licence period for several of the fields.
The Snorre field has been developed with two platforms and one subsea production system connected to one of the platforms (Snorre A). Oil and gas are exported to Statfjord for final processing, storage and loading. One satellite field, Vigdis, has been developed with a subsea tie-back to Snorre A.
The PL 089 licence includes the Vigdis, Borg and Tordis fields. The Tordis field and the southern part of the Borg field have been developed with seven subsea satellites and two templates that are tied back to Gullfaks C, where the oil and gas are processed and stored for offshore loading and export.
The Vigdis field was developed in 1997 with three subsea templates with a well stream through pipelines connected to Snorre A, where the oil is stabilised and exported to Gullfaks for storage and loading. The northern part of Borg is also produced via the Vigdis templates. The PDO for the Vigdis North-East Fast Track Project was approved by the MPE in September 2011, and production start-up is planned for the fourth quarter of 2012.
Statfjord has been developed with three fully integrated platforms supported by gravity base structures with concrete storage cells. Each platform is tied to offshore loading systems for loading oil into tankers. Associated gas is piped through the Tampen link to the UK or, alternatively, to the Kårstø gas processing plant and then on to continental Europe. Three satellite fields (Statfjord North, Statfjord East and Sygna) have been developed, each of them tied back to the Statfjord C platform. In 2005, an amended PDO was approved by the Norwegian authorities for the late-life production period for Statfjord. The Norwegian authorities granted a licence extension for the Statfjord area from 2009 to 2026. The plan is that Statfjord A production will be shut down in 2016.
Sleipner consists of the Sleipner East, Gungne and Sleipner West gas and condensate fields. Condensate from the Sleipner field is transported to the gas processing plant at Kårstø. The gas from Sleipner has a high level of carbon dioxide. It is extracted on the field and reinjected into a sand layer beneath the seabed to reduce carbon dioxide emissions to the air. We are currently exploring several prospects and discoveries in the Sleipner area that can potentially be tied in to Sleipner. Production from the Beta West structure in Sleipner West, which was discovered in 2009, was approved by the Norwegian Petroleum Directorate (NPD) in April 2011. The hydrocarbons from Gudrun will be piped to the Sleipner field. Oil and gas will be processed at Sleipner. The oil will be transported to Kårstø together with the Sleipner condensate, and the gas will be exported together with the Sleipner gas directly into the Gassled transportation system.
Operations North Sea West includes a large part of Statoil's mature production activity on the NCS. Our main focus is on increasing and prolonging production in the area, giving priority to increased oil recovery, exploration and new field development.
The main producing fields in the Operations North Sea West area are Gullfaks, Kvitebjørn, Visund, Grane, Brage, Gimle, Veslefrikk, Huldra, Glitne, Volve and Heimdal.
The petroleum reserves are located below water depths of between 80 and 335 metres. In 2011, Statoil's share of the area's production was 177 mbbl of oil, condensate and NGL per day and 96 mboe of gas per day, or 273 mboe per day in total.
The Gimle field is a Gullfaks satellite field that is operated as a separate unit. Permanent production started in May 2006, with the Gimle exploration well drilled from the Gullfaks C platform being converted into a production well. By the end of 2010, Gimle consisted of two producers and one injector, all drilled as long-reach wells from the Gullfaks C platform.
Brage is an oilfield east of Oseberg in the northern part of the North Sea. The oil is piped to Oseberg and then through the pipeline in the Oseberg Transport System to the Sture terminal. A gas pipeline is tied back to the Statpipe pipeline.
Glitne is an oilfield located about 40 kilometres north-west of Sleipner East. Glitne is the smallest field development on the NCS to use a stand-alone production system.
Grane is the first field on the NCS to produce heavy crude oil. It is Statoil's largest producing heavy oil field. The field is located to the east of the Balder field in the northern part of the North Sea. Oil from Grane is piped to the Sture terminal, where it is stored and shipped. Injection gas is imported to Grane by pipeline from the Heimdal facility. As a result, after around 25 years of oil production, Grane is producing injected gas as well.
Oil production from Gullfaks is gradually increasing after a well control incident at well C-06 A on Gullfaks C in May 2010. Oil production is currently significantly higher than was expected in January 2011. This is the result of active reservoir management and partially restored water injection, which is now optimised according to strict operational criteria. Production drilling operations have also been initiated on Gullfaks satellites, and two drilling rigs are now in operation. The repair of integrity-weakened wells is ongoing according to plan.
Statoil received the Petroleum Safety Authority Norway's investigation report on the gas leak that occured on Gullfaks B December 2010. Statoil published its own investigation of the incident in February 2011.The gas leak occurred in connection with the resetting of piping after maintenance of a choke valve in the wellhead area on the North Sea platform.
Heimdal is a gas field located in the northern part of the North Sea. Heimdal mainly operates as a processing centre for other fields. Huldra, Skirne and Vale deliver gas to Heimdal, and gas from Oseberg is also transported via Heimdal. The plan for development and operation (PDO) for Valemon was submitted in October 2010. Gas from this field will be carried via the existing pipeline from Huldra to Heimdal. The PDO was approved on 9 June 2011. The lifetime of the processing facility at the Heimdal Gas Centre will thereby be extended, enabling us to maintain important processing capacity in the area.
Pre-compression plans for the Kvitebjørn field are expected to increase the production of gas and condensate from the field by approximately 35 million standard cubic metres (mscm) of oil equivalent, thereby increasing the recovery rate from 55% to 70%. Work on production of the compressor has already started. Offshore installation is expected to take place from 2012 until completion in early 2014.
Veslefrikk is an oilfield located north of Oseberg in the northern part of the North Sea. Huldra is located in the Viking Graben and developed by a normally unmanned platform that is remotely controlled from the Veslefrikk field. Oil from Veslefrikk is exported through the Oseberg Transportation System, while gas is exported to Kårstø. Veslefrikk also processes condensate from Huldra.
The first oil flowed from the Vilje field to the Alvheim FPSO on 1 August 2008. The Vilje field, which is linked to the Alvheim field, is located in the northern part of the North Sea, north of the Heimdal field.
The Visund oilfield is located to the east of the Snorre field in the northern part of the North Sea. The field contains oil and gas in several tilted fault blocks with separate pressure and liquid systems. The oil is piped to Gullfaks A for storage and export. Gas is exported to the Kvitebjørn gas pipeline and on to Kollsnes. In April 2011, we had an incident with the Coflon risers that resulted in the risers having to be replaced and production being reduced. Three new risers were installed by November, making it possible to actively prioritise between wells in order to resume full production.
Volve is an oilfield located in the southern part of the North Sea approximately eight kilometres north of Sleipner East. The development is based on production from the Mærsk Inspirer jack-up rig, with Navion Saga being used as a storage ship for crude oil before export. Gas is piped to the Sleipner A platform for final processing and export.
Operations North Sea East is a major gas area that also contains significant quantities of oil. The area includes the Troll, Fram, Vega, Oseberg and Tune fields.
Statoil is committed to the development of the area, and important investments have been approved in 2011. They include the investment decision to install two new compressors in Troll A for NOK 11 billion and the fast-track development of Stjerne on Oseberg for NOK 5.4 billion. Both the Oseberg and Troll areas have significant prospective potential and new IOR projects are under evaluation.In 2011, Statoil's share of the area's production was 147 mbbl of oil, condensate and NGL per day and 159 mboe of gas per day, or 306 mboe per day in total.
The Troll area comprises Troll, Fram and Vega. Troll is the largest gas field on the NCS and a major oilfield.
The Troll field is split into three hydrocarbon-bearing regions: the Troll West Oil Province (TWOP), Troll West Gas Province (TWGP) and Troll East (TE). Oil-producing wells on TWOP and TWGP-South are tied into the Troll B platform, while oil wells on TWGP-North are tied into the Troll C platform. Most of Troll A's gas exports are produced on the giant condeep Troll A platform, which is located in the western part of the Troll East structure at a water depth of approximately 300 metres. Some gas is exported from Troll West as well. There is some limited communication between Troll East and Troll West.
Fram consists of Fram West and Fram East, both of which were awarded under the PLO90 production licence permit. Fram West is an oilfield with two subsea templates connected to Troll C. On Troll C, the gas is separated and exported via Troll A, while the rest is reinjected into the reservoir. Fram East produces from the F-East Sognefjord, C-West Sognefjord and C-West Etive reservoirs. The drainage strategy for the Sognefjord reservoirs is pressure maintenance through water injection.
The Vega field came on stream in December 2010. It consists of three provinces called Vega North, Vega Central and Vega South, which were previously organised under two licences and are now unitised into the Vega Unit. The production from Vega is sent to Gjøa and processed there. The Vega gas is sent to a processing facility at St Fergus (Scotland). NGL/oil production from Vega is exported through a pipeline from Gjøa that is connected to Troll oilpipe II, which transports oil and condensate to the Mongstad refinery.
The Oseberg area includes the main Oseberg field, which has been developed with field centre installations and the Oseberg C production platform, and two satellite fields - Oseberg East and Oseberg South - developed with production platforms. In addition, the Tune field and Oseberg West Flank have been developed with subsea installations and tied back to the Oseberg field centre. Oil and gas from the satellites are piped to the Oseberg field centre for processing and transportation. Oil is exported to shore through the Oseberg transportation system, and gas is exported through the Oseberg gas transportation system to Heimdal and on to market.
Our producing fields in the Operations North area are Åsgard, Mikkel, Yttergryta, Heidrun, Kristin, Tyrihans, Norne, Urd, Alve, Njord, Snøhvit and Morvin.
Our share of the area's production in 2011 was 214 mbbl per day of oil, condensate and NGL, and 149 mboe per day of gas, or 363 mboe per day in total.
The region is characterised by petroleum reserves located at water depths of between 250 and 500 metres. The reserves are partly under high pressure and at high temperatures. These conditions have made development and production more difficult, challenging the participants to develop new types of platforms and new technology, such as floating processing systems with subsea production templates. We plan to increase efficiency by further coordinating our operations in the area and by stemming the decline in production from the mature fields through increased seismic activity and well maintenance. In addition, we intend to expand our activities by utilising our installed production and transportation capacity before building new infrastructure.
The Heidrun platform is the largest concrete tension leg platform ever built. Heidrun was the first production platform in Operations North, with production start-up in 1995. Most of the oil from Heidrun is shipped by shuttle tanker to our Mongstad crude oil terminal for onward transportation to customers. Gas from Heidrun provides the feedstock for the methanol plant at Tjeldbergodden in Norway. Additional gas volumes are exported through the Åsgard Transport System (ÅTS) to gas markets in continental Europe.
Kristin is a gas and condensate field in the south west section of the Operations North area. The Kristin development is the first high-temperature/high-pressure (HTHP) field developed with subsea installations. The pressure and temperature in the reservoir - 900 bar and 170 degrees Celsius, respectively - are higher than on any other developed field on the NCS. The stabilised condensate is exported to a joint Åsgard and Kristin storage vessel, and the rich gas is transported to shore via the ÅTS to the gas processing facility at Kårstø.
Tyrihans started producing oil and gas in 2009, and the field was producing from seven wells by the end of 2011. In addition, gas is injected into two injection wells via Åsgard B. The Tyrihans development project is expected to be completed in 2012 with another two wells. All production volumes are processed on the Kristin platform.
Njord consists of two installations. Njord A is a platform with drilling facilities and a production plant for oil and gas. Njord B is a storage vessel for oil. The Njord field has produced oil since 1997, and gas export started in late 2007 via ÅTS and Kårstø.
The Norne field has been developed with a production and storage ship tied to subsea templates. This ship has processing facilities on deck and storage tanks for oil. Processed crude oil can be transferred over the stern to shuttle tankers. Norne is connected to gas markets in continental Europe through a link with ÅTS.
The Urd fields, Svale and Stær, are located ten and five kilometres north of the Norne field, respectively. The fields are produced through subsea facilities, with the well stream tied back to the Norne FPSO.
The Alve field, which consists of one producing well and a subsea template, was started up in March 2009. The field is produced through subsea facilities, with the well stream tied back to the Norne FPSO.
Snøhvit is the first field to be developed in the Barents Sea. Twenty wells are expected to produce natural gas from three gas reservoirs: Snøhvit, Askeladd and Albatross. By the end of 2011, Snøhvit was producing from nine wells, filling the plant capacity. All the offshore installations are subsea, which makes Snøhvit one of the first major developments without production facilities offshore. Snøhvit reinjects carbon dioxide from the liquefied natural gas (LNG) plant into a separate well/reservoir.
The natural gas, which is transported to shore through a 143-kilometre-long pipeline, is landed on Melkøya, where it is processed at our LNG plant. This plant is Europe's largest export factory for LNG, which is shipped to customers in Europe, the USA and Asia in tankers. The first shipment took place in late 2007. The LNG plant has also suffered from operational challenges in 2011, particularly in relation to problems with the heat exchangers, which are located in the heart of the LNG Plant (cold box). Their function is to bring down the temperature of the methane gas so that it liquidises at -164 degrees Celsius (see section Gas Sales and Marketing - LNG - for more information). Snøhvit carried out a major turnaround in 2011 after which regularity has been high. A new 24-hour production record for Snøhvit was set on 6 August 2011, corresponding to 109% of the original design capacity of the plant.
The Åsgard field comprises three fields: Smørbukk, Smørbukk South and Midgard. The field was developed with the Åsgard A production ship for oil, the Åsgard B semi-submersible floating production platform for gas and the Åsgard C storage vessel. The subsea production installations are among the most extensive in the world, with a total of 17 seabed templates. The Åsgard B platform is the largest floating gas processing centre in the world, and Åsgard A is one of the largest floating production ships ever built. The Åsgard development links the Haltenbanken area to Norway's gas transport system in the North Sea. Gas from the field is piped through the ÅTS to the processing plant at Kårstø and on to receiving terminals in Emden and Dornum in Germany. Oil produced at the Åsgard A vessel and condensate from the Åsgard C storage vessel are shipped from the field in shuttle tankers.
Mikkel is a gas and condensate field. Production from two seabed templates is tied to the subsea installation on Midgard for onward transportation to the Åsgard B gas processing platform.
Yttergryta produces from a single well, and the well stream is tied back to Åsgard B for processing.
Morvin started production on 1 August 2010. The field consists of two seabed templates with production from four wells. The last well was completed in spring 2011. The well stream with oil and gas is tied back to Åsgard B for processing. Morvin makes an important contribution to utilising the production capacity on Åsgard B.
Our partner-operated fields account for a significant proportion of our oil and gas portfolio. They range from development projects to mature fields. Production is expected to start up on Skarv and Marulk in 2012.
Ormen Lange, a deepwater gas field in the Norwegian Sea, is the second-largest gas field on the NCS. Statoil has a 28.916% interest in the field. Statoil was operator for the development phase, while Norske Shell became the operator for the production phase that began at the end of 2007. Statoil continues to execute the approved, but not yet completed subsea compression pilot. The selected development is an extensive subsea development at depths ranging from 850 to 1,100 metres. The well stream is transported to an onshore processing and export plant at Nyhamna. The gas is then transported through a dry gas pipeline, Langeled, via Sleipner to Easington in the UK.
Ekofisk was the first developed field complex to come into operation on the NCS. ConocoPhillips is the operator. It consists of the Ekofisk, Eldfisk and Embla fields (in which Statoil has an interest of 7.604%), plus Tor (in which Statoil has an interest of 6.639%). Ekofisk has been upgraded with several new platforms over the years, the latest being the 2/4-M drilling platform, which was installed in 2005. In early 2010, a final investment decision was made to build a new Ekofisk accommodation and field centre platform. With 550 beds, it will be the largest in the world. Investment decisions were made in 2010 for a new Ekofisk South project consisting of a new drilling platform with subsea water injection facilities and the redevelopment of Eldfisk, which consists of a new drilling and process platform. The new facilities are expected to extend the field life considerably beyond the current licence period, which ends in 2028. Redevelopment of Tor is under evaluation.
Sigyn, operated by ExxonMobil and in which Statoil has a 60% interest, is a gas and condensate field located 12 kilometres south east of the Sleipner A installation. The gas is exported from Sleipner A and the condensate is delivered to Kårstø. The development consists of three production wells on one subsea template, with two pipelines and one umbilical connecting it to the Sleipner A platform.
Statoil has a 14.82% interest in the ExxonMobil-operated Ringhorne East field. The unitised field started production in March 2006. Three production wells have been drilled from the Ringhorne facility. Oil is transported via Ringhorne to Balder for offshore loading. Gas is exported via Jotun into the Statpipe pipeline. A fourth and fifth production well are planned to be drilled in 2012.
Statoil has an 11.78% interest in the Enoch field, which is operated by Talisman. The field is a subsea development tied back to Brae A in the British sector. Production started in May 2007.
Gjøa, which is located in the North Sea, has been developed with a subsea production system and a semi-submersible production platform. Statoil was the operator during the development phase, while GDF SUEZ took over as operator from production start-up in November 2010. Statoil continues to execute the drilling and completion of the production wells into 2012. Gas is exported via the Far North Liquids and Associated Gas System (FLAGS) pipeline to St Fergus, and oil is exported via the Troll 2 pipeline to the Statoil-operated Mongstad refinery near Bergen. The Gjøa platform processes and exports volumes from both the Gjøa field and the neighbouring Vega fields. The platform is supplied with land-based electricity from Mongstad. Statoil has a 20% interest in Gjøa.
No Statoil-operated fields have been decommissioned during the last three years.
The Norwegian government has laid down strict procedures for the removal and disposal of offshore oil and gas installations under the Convention for the Protection of the Marine Environment of the Northeast Atlantic (the OSPAR Convention). No Statoil-operated fields have been decommissioned during the last three years, however. On partner-operated fields, there has been removal activity on Frigg and Ekofisk.
In 2011, Statoil commenced execution of the Troll-Oseberg Gas injection (TOGI) decommissioning project.
For further information about decommissioning, see note 24 to the consolidated financial statements, Asset retirement obligations, other provisions and other liabilities.
Statoil is present in several of the most important oil and gas provinces in the world, and Development and Production International (DPI) is expected to account for most of the company's future production growth.
Development and Production International is responsible for the development and production of oil and gas outside the Norwegian continental shelf (NCS).
In 2011, the reporting segment was engaged in production in 12 countries: Canada, the USA, Brazil, Venezuela, Angola, Nigeria, Iran, Algeria, Libya, Azerbaijan, Russia and the UK. In 2011, DPI produced 28.9% of Statoil's total equity production of oil and gas.
Statoil has exploration licences in North America (Gulf of Mexico, Canada and Alaska), South America and sub-Saharan Africa (Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania), Middle East and North Africa (Libya and Iran) and Europe and Asia (the Faeroes, Greenland, the UK, Azerbaijan and Indonesia).
The main sanctioned development projects in which DPI is involved are in the USA, Angola and Canada. We are well positioned for further growth through a substantial pre-sanctioned project portfolio, including a strengthened onshore US position through the acquisition of Brigham Exploration Company which was closed in December 2011.
The map shows Statoil's international exploration and production areas.
International development and production continued to grow in 2011 through the start-up of several important projects.
To enhance our US growth and commitment to shale plays in 2011, we acquired Brigham Exploration Company and increased our acreage in Marcellus and Eagle Ford.
In addition to the Bakken acquisition, we continue to deepen our existing positions. In the liquids-rich Eagle Ford, we have increased our acreage from 67,000 to 87,974 net acres. Similarly, we have deepened our position in Marcellus, with continued acreage acquisitions in the northern dry gas core and south-west liquids-rich area. The total Marcellus acreage has increased from 665,000 net acres to 689,000 net acres.
Divestments and other reductions of Statoil's international portfolio
With effect from January 2011, Statoil formed a joint venture with PTTEP of Thailand in its oil sands business and, as part of that transaction, sold PTTEP a 40% interest in the leases in Alberta, Canada. Statoil retains 60% ownership and operatorship of the oil sands project.
Statoil supports its international growth ambitions by accessing material acreage positions early in the exploration phase. Further focus is placed on drilling an increasing number of wells with significant discovery potential.
We have exploration licences in North America (Gulf of Mexico, Canada and Alaska), South America and sub-Saharan Africa (Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania), Middle East and North Africa (Libya and Iran), and Europe and Asia (the Faroes, Greenland, the UK, Azerbaijan and Indonesia).
We completed 16 wells in 2011. Five were announced as discoveries: the Mukuvo and Lira discoveries in Angola, the Gavea and Peregrino South discovery in Brazil and the Logan discovery in GoM.There were five dry wells, while six wellsare currently under evaluation. We plan to drill around 20 wells in 2012.
In Angola, Statoil was awarded operatorship in two new blocks and partnership in three new blocks in 2011. These blocks are all in the Angola pre-salt play.
Statoil acquired interests in six new licences in Indonesia in 2011.
Together with Chevron and Repsol, we were named successful bidders in Canada for exploration rights on two land parcels in the Flemish Pass Basin, off the coast of Newfoundland and Labrador. Statoil will be the operator of both licences, with a 50% interest.
During the second half of 2011, our exploration activities in the Gulf of Mexico returned to levels similar to before the Macondo incident, which Statoil was not involved in, and two Statoil-operated wells have been completed.
We entered Suriname in 2011 through a farm-in agreement with Tullow. We have acquired a 30% working interest in block 47, with a commitment to participate in a seismic survey.
Our two licences in Egypt - El Dabaa and Ras el-Hekma - expired in 2011, after we had completed the work programme to which we were committed. We drilled one well in the El Dabaa licence, which was dry. Final closure is ongoing.
We reduced our share in three of our licences in the Faroes during 2011, selling 49% in License 006, and 50% in License 009 and License 011 to ExxonMobil. We retain a 50% interest and operatorship in each of these licenses.
Areas with drilling or significant Statoil-operated seismic activity in 2011
The areas where we had significant activity in 2011 are presented below:
Exploratory wells in Eurasia (excl. Norway), Americas and Africa
Statoil has significant activities in the USA, with approximately 300 exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska. We are also an operator and partner in exploration licences off the coast of Newfoundland in Canada.
Statoil is operator and partner in exploration licences off the coast of Newfoundland (11,138 square kilometres).
In 2011, Statoil operated a well on the Fiddlehead prospect in the Jeanne d'Arc Basin and an appraisal well on the Mizzen discovery in the Flemish Pass Basin. The drilling operations were completed successfully and safely. Statoil successfully completed a 1,600 square-kilometre seismic 3D programme on the EL1123 licence, Cupids. We also participated in the Suncor Energy-operated Ballicatters discovery in the Jeanne d'Arc Basin.
We have strengthened our offshore position in Canada and our Arctic portfolio through agreements with Chevron Canada and Repsol E&P Canada. The agreements involve three major basins off the coast of Canada: the Flemish Pass and Orphan basins off the coast of Newfoundland, and the Beaufort Sea located in Canada's high north. These new joint ventures over large land blocks in deep water represent important strategic steps for Statoil in the offshore sector in Canada, providing us with access to large potential resources and increasing the optionality of our exploration portfolio.
Statoil Canada, Chevron Canada and Repsol E&P Canada were named successful bidders for exploration rights on two land parcels in the Flemish Pass Basin, off the coasts of Newfoundland and Labrador. Statoil will be the operator of both licences with a 50% interest. Chevron Canada will have a 40% interest and Repsol E&P Canada 10%. This offers promising growth opportunities near the Statoil-operated Mizzen discovery.
Statoil intends to continue exploration activities in 2012, with one Statoil-operated well and one partner-operated well.
Statoil has significant activities in the USA, with approximately 300 exploration leases in the Gulf of Mexico (GoM) and 66 in Alaska. Drilling activity has returned to a level similar to that before the Macondo incident.
US Gulf of Mexico
Statoil participated in the Deep Blue appraisal well (Noble is the operator) and is currently participating in the Kakuna exploration well (Nexen is the operator) and the Heidelberg appraisal well (Anadarko is the operator). Upon completion of the Heidelberg well in early 2012, Statoil intends to commence drilling of the Bioko Paleogene prospect, which has already been awarded a permit.
Exploration activity in the Gulf of Mexico in 2012 is expected to include three Statoil-operated exploration wells and participation in approximately four partner-operated wells.
In 2011, Statoil secured a cross assignment in the Bioko prospect with ConocoPhillips, and, together we farmed down a participation interest in the Bioko well to Shell. Statoil also succeeded in swapping interests in the Kilchurn/Innsbruck prospects with Marathon.
We have exploration licences in Brazil, Cuba, Suriname, Venezuela, Angola, Mozambique and Tanzania.
Statoil has interests in seven exploration licences in four different basins off the coast of Brazil, and it is the operator for four of the licences.
In 2011, we completed two Statoil-operated wells in the Campos Basin, plus three sidetracks in BM-C-47. The second well and third sidetrack were drilled in BM-C-7. All wells and sidetracks proved oil and added significant reserves to the greater Peregrino area.
We participated in the Gavea and Pão de Açucar exploration wells in BM-C-33, which were both discoveries. Pão de Açucar was announced in February 2012 as a significant discovery, and its development potential together with Gavea is under evaluation by the partnership. BM-C-33 is located in the Campos Basin.
In the Camamu-Almada basin, located outside Salvador, we farmed down 10% of the Petrobras-operated licence BM-CAL-7 and 15% of the Statoil-operated BM-CAL-10 to Gran Tierra. During 2011, we drilled one well in BM-CAL-10, which was dry.
Statoil also participated in one licence in the Espirito Santo basin, BM-ES-32, where the Indra discovery is located. BM-ES-29 was relinquished in 2011 after we had completed the committed work programme. The interests in three blocks that we won in the eighth round in the Santos Basin are pending award.
In 2012, Statoil expects to operate one appraisal well and take part in at least two non-operated exploration wells.
Statoil holds interests in blocks 4/05, 15, 15/06, 17, 22, 25, 31, 38, 39 and 40 in Angola.
In December 2011, Statoil was awarded licences for the operatorship of and participation in several pre-salt blocks off the coast of Angola. Statoil was awarded the following blocks as operator:
Statoil was awarded the following blocks as partner:
We are engaged in extensive exploration activity in Angola. A number of wells were drilled in 2011, and more are expected to be drilled in and after 2012. We have interests varying from 5% to 50% in four blocks.
In Block 4/05, which is operated by Sonangol and assisted by Statoil, we completed the remaining commitment exploration well in January 2011.
In Block 31, which is operated by BP, a total of 31 exploration wells have been drilled. We are working to mature existing discoveries into future developments on the remaining acreage.
In Block 15/06, which is operated by ENI, several exploration and appraisal wells have been drilled this year.
In Block 15, work is being initiated to mature existing discoveries as tie-ins to existing infrastructure.
In Block 17, appraisal drilling was carried out in 2011 and is expected to continue into 2012.
Block 34 was relinquished in 2011 after completion of the committed work programme.
Statoil is the operator for two large frontier offshore blocks in the East Africa region - block 2 in Tanzania and area 2&5 in Mozambique. The blocks have water depths of between 1,000 and 3,000 metres.
We have exploration licences in Libya and Iran.
However, the company will not make any future investments in Iran under the present circumstances (see the section International Fields - Middle East and North Africa - Iran). Our two licences in Egypt, El Dabaa and Ras el-Hekma, expired in 2011, after completion of the committed work programme. We drilled one well in the El Dabaa licence, which was dry. Final closing is ongoing.
We have exploration licences in the Faroes, Greenland, the UK, Azerbaijan and Indonesia.
Statoil has interests in eight production-sharing contract (PSC) licences in Indonesia. We operate Karama and Halmahera II, and are partners in Kuma, North Ganal, North Makassar, West Papua IV, Obi and Halmahera Kofiau.
We acquired interests in six licences during 2011. The North Ganal and North Makassar PSCs are located in the North Makassar Strait. The West Papua IV, Obi, Halmahera Kofiau and Halmahera II PSCs are located in the eastern part of Indonesia.
We are the operator of Halmahera II PSC. Eni is the operator of North Ganal PSC, while Niko Resources is the operator of the remaining licences. We have a commitment to drill one well in the North Makassar PSC and one in the North Ganal PSC. We only have commitments to conduct seismic surveys in the other PSC.
One well in the Kuma PSC was drilled in 2011 and the result is still under evaluation. A seismic acquisition programme was started in 2011 and is expected to continue into 2012. Three wells in the Karama PSC and one well in the North Makassar PSC are planned to be drilled during 2012.
In 2011, Statoil's petroleum production outside Norway amounted to an average of 334 mboe per day of entitlement production and 534 mboe per day of equity production.
Our total annual entitlement production in 2011 was approximately 334 mboe per day, compared with approximately 332 mboe per day in 2010.
The first table below shows DPI's average daily entitlement production of liquids and natural gas for the years ending 31 December 2011, 2010 and 2009.
The table below provides information about the fields that contributed to production in 2011.
The table below shows equity and entitlement production per country in 2011.
Major efforts are under way to make the transition from a mainly Norwegian offshore player to a world-class international operator.
DPI is working continuously to develop the inventory of projects into producing assets by looking at innovative technical and commercial solutions.
This section covers projects under development and fields in production. Significant pre-sanctioned projects, including some discoveries in the early evaluation phase, are also presented. A field's plateau production is often referred to in this section. It means the yearly average equity production at plateau for a field for a 100% ownership share. Capacities also refer to the whole field or facility.
Exploration activities are described in the report section Operational review - Development and Production International (DPI) - International exploration.
Statoil's development and production activities in North America comprise interests and operations in several areas and basins.
Statoil has activities in the US Gulf of Mexico, the Appalachian region, south-west Texas, the Williston Basin, off the East Coast of Canada and in the oil sands of Alberta, Canada. We also have a representative office in Mexico City.
The oil sands business remains an important long-term investment, and the Leismer Demonstration Project has been operational since early 2011. Offshore, we have production interests in Hibernia and Terra Nova, and interests in two development projects.
The Leismer Demonstration Project started its first commercial production on 11 January 2011, and it produced approximately 3.7 mmbbls of bitumen in 2011. All of the project's production wells have been drilled and completed, with all four well pads in steam-assisted gravity drainage (SAGD) production mode. The Leismer Demonstration Project is connected to the existing pipeline infrastructure at our Cheecham terminal, which connects to a third-party pipeline that runs to the Edmonton area. In 2011, production ramp-up and operational performance exceeded our prior expectations.
Our second oil sands development, Corner, is currently in an early stage of development.
To determine the extent of the exploitable oil sands deposits in Alberta, more than 872 wells were drilled in the region from 2003 to 2011. Extensive seismic surveys were also carried out during the same period.
During the 2010-2011 winter drilling programme, 126 wells were drilled for the purpose of further delineation of the oil sands reservoirs, for the observation and monitoring of production operations, and for water source/ water disposal for both near and longer-term development projects. A total of 182.7 square kilometres of 3D seismic was also shot during the winter of 2010-2011. Drilling activities will continue during the 2011-2012 winter evaluation programme, along with 3D and 4D seismic coverage.
Offshore fields in production
Terra Nova produces from an FPSO and is operated by Suncor Energy. The Terra Nova field is also in decline, with gross production rates averaging 43,000 barrels of oil per day (Statoil 15%) in 2011. One development well was delivered in 2011, with positive results. Development drilling of the field is planned to continue in 2012. Terra Nova production was limited in 2011 due to the occurrence of hydrogen sulphide (H2S) in the producing reservoir. The partnership plans to execute a major off-station capital programme in 2012 to remediate the H2S issue.
Offshore development projects
The Hibernia Southern Extension Unit, which is operated by ExxonMobil, comprises the development of resources in several fault blocks to the south of the existing Hibernia field. The field is planned for development as a satellite to the Hibernia field. Statoil's unitised interest is currently 10.5%. The project achieved early delivery of two producing wells in 2011. The development part of the project, which consists of the installation of a subsea template for water injection, has been sanctioned by the partnership and is expected to be on stream in 2014. Production from the producing wells will be limited until the development is completed.
The onshore Marcellus and Eagle Ford shale gas investments became key contributors to our North American production. Offshore, the USA continues to deliver production expectations and to progress a strong pipeline of Gulf of Mexico development projects.
Our joint venture acreage is concentrated around the developing core regions, most notably north-east Pennsylvania (PA), south-west Pennsylvania and north-west West Virginia (WV). We have engaged in a number of trades and purchases to consolidate our position in these areas. We see encouraging signs concerning estimated ultimate recovery rates (EUR), very strong initial production rates from north-east PA, and above pro-forma production rates in south-west PA and WV, with an upside on liquids. Statoil and Chesapeake will continue to acquire high-grade acreage around the most prospective areas of the play and will build up production from the areas. The operator was running 23 rigs in the play at the end of 2011.
Through agreements with Enduring Resources, LLC and Talisman Energy Inc., Statoil acquired 67,000 net acres in the Eagle Ford shale formation in south west Texas in 2010. Statoil and Talisman formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale formation. Together, Statoil and Talisman initially held 134,000 net Eagle Ford acres and associated assets and production in the joint venture. The venture has continued to acquire acreage within the play, with a net acreage position of over 87,974 acres at the end of 2011. Statoil's daily equity production was 5,200 boe by the end of 2011 from 100 wells. The operator was running ten rigs in the play at the end of 2011.
The acquisition of Brigham Exploration Company, which was finalised in December 2011, gives Statoil strategic exposure to US unconventional plays, which are believed to contain a substantial resource base and represent an increasingly important part of future energy supplies. Statoil's daily equity production was 26,200 boe for December. For more information on the acquisition, please refer to the section Global Strategy and Business Development (GSB) Key events in 2011.
Offshore Gulf of Mexico
Fields in production
Production started in July 2009 from the Thunder Hawk oilfield located in Mississippi Canyon block 734. We have a 25% interest in this Murphy Oil-operated development, which consists of a semi-submersible floating production facility located in Mississippi Canyon block 736. The processing capacity is approximately 45,000 boe/d. The gross average daily production is declining and was 12,900 boe in 2011. A fourth well has been approved by the partners. It is expected to be in production by the middle of 2012.
Spiderman, a deepwater gas field, is part of the Anadarko-operated Independence Hub, which is a floating production facility located in Mississippi Canyon block 920. Statoil has an 18.3% interest in the field. The gross average daily production in 2011 was approximately 22,000 boe/d. The Independence Hub is owned by third parties. It has a processing capacity of approximately one billion cubic feet of natural gas per day. Statoil has contractual rights to 12.7% of the total capacity through May 2012 and 6.4% for five years thereafter.
The Murphy-operated Front Runner oilfield is located in Green Canyon blocks 338/339/382. Statoil has a 25% interest in Front Runner, which started production in 2004. The field produces while carrying out simultaneous drilling activities from a rig situated on a spar floating production facility. Gross average daily production was 7,000 boe/d in 2011.
In addition Statoil has a 30% interest in the Noble Energy-operated Lorien oilfield located in Green Canyon block 199, and 35% in Zia, located in Mississippi Canyon block 299.
Fields under development
Tahiti Phase 2 will add two producing and three water-injection wells to the existing architecture. Injection from the first two water-injection wells is expected to start in the first quarter 2012, while first oil from additional producers is expected in the first quarter 2013.
Statoil has a 25% working interest in the Jack oilfield, located in Walker Ridge blocks 758/759, and a 21.5% working interest in St. Malo, located in Walker Ridge block 678. St. Malo and Jack are located at a water depth of approximately 2,000 metres and are approximately 40 kilometres apart. The two fields are operated by Chevron and will be developed jointly with subsea wells connected to a centrally-located production platform. The Jack and St. Malo projects were sanctioned in September 2010 and the first oil is expected in late 2014.
Statoil has a 27.5% interest in Big Foot, located in Walker Ridge block 29. Big Foot is operated by Chevron and will be developed with a dry tree tension leg platform with a drilling rig. The Big Foot project was sanctioned in December 2010. The first oil from Big Foot is scheduled in late 2014.
Discovered in 2007, Julia (ExxonMobil 50% and Statoil 50%) is one of the major discoveries in Paleogene, with a significant in-place volume. In October 2008, ExxonMobil (operator) filed for Suspension of Production (SOP) based on a subsea tie-back concept or, alternatively, a stand-alone facility; which was denied by Minerals Management Service (now Bureau of Ocean Energy Management - BOEM). In May 2011 the Director of Hearing and Appeals ("OHA") issued a decision upholding BOEM's SOP denial and overruling the prior Interior Board of Land Appeals ("IBLA") decision (2009), which was in favour of the Julia partners. In August 2011, Statoil and ExxonMobil filed separate appeals in the federal court system challenging the OHA Director's decision. In parallel, Julia owners were engaged in settlement negotiations with the Department of Interior (DOI) and Department of Justice (DOJ) to resolve the SOP issues. At the same time, the Julia partners negotiated with the Jack and St Malo partners to secure an amendment to the production handling agreement (PHA) for Julia's re-entry into the Jack and St Malo host. A settlement agreement was signed with DOI and DOJ at the end of December 2011. On 18 January, the US District Court signed and filed its Order approving the Julia settlement and dismissed the case. The settlement is final. In early January 2012, the PHA amendment was also signed by the Jack and St Malo host owners and Julia partners. ExxonMobil, operator for Julia, is gearing up and plans to restart the project in the second quarter of 2012. The first oil is expected by mid-2016.
Our development and production activities in South America and sub-Saharan Africa comprise the Peregrino operatorship in Brazil, the Petrocedenõ project in Venezuela, the Agbami offshore field in Nigeria and four Angolan offshore blocks.
Statoil is the operator of the Peregrino offshore field, which started production in April 2011. We are among the largest foreign offshore operators in Brazil in terms of production.
The Peregrino field is a heavy oil field located in approximately 120 metres of water in the prolific Campos Basin, about 85 kilometres off the coast of Rio de Janeiro.
The field came on stream on 9 April 2011. It is producing the oil from two well head platforms with drilling capability to an FPSO for final processing. Our share of the production was 15.7 mboe per day in 2011. Design capacity is 100,000 barrels of oil per day.
In May 2010, Statoil agreed to form a joint venture and sell 40% of the Peregrino field to Sinochem Group. Statoil retained 60% ownership, and operatorship of the field. The transaction was formally signed on 14 April 2011 after being approved by the Brazilian government.
Work is also ongoing to develop the Peregrino South and South West discoveries.
Statoil has a 9.7% interest in Petrocedeño, one of the largest extra-heavy crude oil projects in Venezuela.
The Petrocedeño project involves the extraction of extra-heavy crude oil from reservoirs in the Orinoco Belt. A diluting component is added in order to enable the extra-heavy crude oil to be transported by pipeline to the coast, where it is upgraded to a light, low-sulphur syncrude destined for the international market. Petrocedeño, S.A, which is owned by project partners PDVSA, Total and Statoil, operates the field and markets the products.
Statoil's share of Petrocedeño production in 2011 was 13.6 mboe per day, which is below design capacity. A recovery programme is ongoing to improve the situation.
We have been present in Venezuela since 1994 and have a long-term commitment to the country based on the participation in Petrocedeño and Venezuela's large oil reserves.
The Angolan continental shelf is the largest contributor to Statoil's production outside Norway. It yielded 176 mboe per day in equity production in 2011, 33.0% of Statoil's total international oil and gas output.
Block 17 is operated by Total. Our interest is 23.3%. Production from the block currently comprises five development areas produced over three FPSOs. The Girassol, Jasmim and Rosa development areas are produced over the Girassol FPSO and the Dalia development area over the Dalia FPSO. This year, the Pazflor development came on stream, producing to the Pazflor FPSO. The combined equity production from block 17 was 113.9 mboe per day in 2011.
The Pazflor project, which comprises the Perpetua, Acacia, Zinia and Hortensia discoveries, came on stream on 24 August 2011. The expected production capacity of the FPSO is 220 mboe per day.
The CLOV project consists of the Cravo, Lirio, Orchidea and Violeta discoveries. The project was sanctioned in mid-2010 and it is currently under development. CLOV will be produced over a new FPSO, with an expected production capacity of 160 mboe per day. The first oil is expected in 2014.
An IOR initiative to fill excess capacity on the Girassol FPSO was implemented in 2011. Additional projects are under development on block 17. The IOR projects include subsea tie-backs, infill wells, and the use of multi-phase pumps.
Block 15 is operated by Esso Angola, a subsidiary of ExxonMobil. Our interest is 13.3%. Statoil's equity production from block 15 was 58.8 mboe per day in 2011. Production here stems from the Kizomba A, Kizomba B, Kizomba C-Mondo and Kizomba C-Saxi Batuque FPSOs. In addition, one satellite, Marimba, is producing through a subsea tie-back to the Kizomba A FPSO. The Xikomba FPSO ceased production in March 2011. It is now being decommissioned.
Kizomba Satellites phase 1, consisting of two discoveries, Clochas and Mavacola, was sanctioned by the partnership in 2009. It is currently under development. The first oil is scheduled for 2012.
Possible development of the Kizomba Satellites phase 2 is being evaluated. The project includes the Bavuca, Kakocha and Mondo South discoveries.
Block 31 is an ultra-deepwater licence operated by BP. Our interest is 13.3%. The development of the first four discoveries in the northern part of the block - Plutao, Saturno, Venus and Marte (PSVM) - was approved by the concessionaire in July 2008, and it is now under execution. PSVM will be developed via a new FPSO with a production capacity of 150 mboe per day. The first oil is scheduled for 2012. Work is also ongoing to pursue a second development in the southern part of block 31.
Block 4/05 is operated by Sonangol P&P, and Statoil's interest is 20%. This block includes the Gimboa field. The equity production was 3.4 mboe per day in 2011.
Block 15/06 is operated by Eni, and Statoil's interest is 5%. Work is currently being done to progress a development solution for the discoveries on the block. .
Gas Gathering Projects: Pursuant to the production sharing agreement (PSA), all surplus gas from the fields in Angola is to be delivered to Sonangol, which owns the gas. No income will be generated from the transfer of gas, and costs and investments related to the projects will be recovered through the PSA.
The delivery of commissioning gas from block 15 to the Angola LNG Terminal started in the second quarter of 2011. The export of gas from block 17 with injection into block 2 started in December 2010. The pipeline from block 2 to the Angola LNG Terminal was completed in 2011. It is ready to start deliveries to the terminal.
In Nigeria, we have a 20.2% interest in the largest deep water producing field, Agbami.
The Agbami field is produced from subsea wells connected to an FPSO. It is located about 110 kilometres off the coast of Nigeria and is operated by Chevron. The field is producing close to the nominal plateau rate of 250 mboe per day.
The National Assembly is still debating the Petroleum Industry Bill (PIB), which will most likely increase the government take if passed.
Together with our partner Chevron we are currently in arbitration with the national oil company NNPC over the interpretation of certain clauses in the production sharing contract (PSC) that governs our share of Agbami.
The security situation in Lagos and the rest of south west Nigeria is normally medium to high depending on the time of day. While the kidnapping of middle- to high-income Nigerians does take place, it is relatively rare. Robberies and car snatching are more common place. There is, however, an increase in piracy and other waterborne crime. There has been no impact on large crude oil tankers in 2011. Convoy and security vessels are used to protect supply ships and other smaller vessels. Kidnappings are on the rise in the Delta area in the south. The security situation is similarly serious in the north east.
Statoil's development and production in the Middle East and North Africa in 2011 primarily encompassed Algeria, Libya, Egypt, Iran and Iraq.
In this region, Statoil is active as a joint operator in the producing fields In Salah and In Amenas in Algeria. The upstream assets in Algeria supplement Statoil's strong position as a supplier to the European gas market. In 2011, Statoil has been an active partner in licences in Libya and Iraq and it was also the operator for two exploration licences in Egypt in 2011.
Due to the political situation in Libya, Statoil's Libyan operations and production were stopped in February 2011. The Murzuq field resumed production on 13 November 2011 and the Mabruk field resumed production on 12 January 2012.
Statoil also has offices in Abu Dhabi and Iran.
Our main assets, In Salah and In Amenas, are the third-largest and fourth-largest gas developments in Algeria. The developments of the In Salah Southern Fields and In Amenas Gas Compression Project were sanctioned in 2010.
Fields in production
A contract of association, including mechanisms for revenue sharing, governs the rights and obligations of the joint operatorship between Sonatrach, BP and Statoil.
In the In Salah Gas Compression Project, gas compression facilities were installed on the three existing northern fields in 2010, and compression has started on all three fields.
The In Amenas onshore development is the fourth-largest gas development in Algeria. It contains significant liquid volumes. Production efficiency is high, although occasional capacity restrictions due to priorities in the export pipeline system remain an issue.
The facilities are operated through a joint operatorship between Sonatrach, BP and Statoil where Statoil's share of the investments (working interest) is 45.9%. Production has reached plateau level. The rights and obligations are governed by a production sharing contract that gives BP and Statoil access to a share of the liquid volumes. A continuous production drilling campaign is ongoing.
Fields in development
The In Amenas Gas Compression Project, which is led by BP, was sanctioned in late 2010. The compressors are expected to come on stream early in 2013. This will make it possible to reduce well head pressure and maintain the contractual production commitment.
The Hassi Mouina exploration phase has been extended until September 2012 . Statoil is currently assessing the technical solutions for and the commercial attractiveness of a potential development.
Statoil was the offshore operator for the development of phases 6, 7 and 8 of the South Pars gas and condensate field in the Persian Gulf until its completion in 2009. Statoil will not make any future investments in Iran under the present circumstances.
The National Iranian Oil Company (NIOC) took over as the formal operator of South Pars after its completion. Statoil assisted the NIOC for a limited transitional period in accordance with the contractual framework for the development phase. The technical service agreement (TSA) concluded at the end of March 2011, in accordance with the contract.
Statoil has previously taken part in exploration and drilling activities in the country on the Anaran block. Work on this project has been stopped. Statoil also holds a licence for exploration of the Khorramabad block. No activity is planned for this licence.
A small staff is working to secure the outstanding contractual cost recovery and remuneration for Statoil for the development and exploration contracts. Considerable progress has been made during 2011.
In a letter from the US Department of State dated 1 November 2010, Statoil was informed that the company is no longer considered to be a company of concern with regard to its previous Iran-related activities, since the Secretary of State chose to apply the "Special Rule" in the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010.
See the section Risk review - Risk factors - Risks related to our business for additional information about the risk of sanctions relating to activities in Iran.
Due to political unrest in February 2011, Statoil's operations were suspended in Libya. Work is now ongoing to restore production in full on the Murzuq and Mabruk oil fields.
Due to the outbreak of political unrest in Libya, Statoil's Libyan operations were suspended in February 2011 and the fields stopped production on 21 February (Murzuq) and 26 February (Mabruk). Statoil's office in Libya was closed on 20 February 2011. All Statoil expatriate staff and their families were safely evacuated from the country. The local staff were paid wages during the unrest and, as order was restored, they were involved in the reestablishment of the office in the capital, Tripoli. The office was opened 20 March 2012.
The Murzuq field resumed production on 13 November 2011. The NC 186 licence in the Murzuq area consists of seven fields (A, B, D, H, I/R, J and K). Akakus Oil Operations is the operating company for the Murzuq NC 186 license, with Repsol as the lead partner for the international oil companies. . Statoil's share of investments (working interest) in the NC 186 license in the Murzuq field is 10%. The oil from the Murzuq fields is transported by pipeline to the Az Zawia terminal west of Tripoli for lifting by ship.
The Mabruk oilfield resumed production in January 2012. The field is located in licence C-17 in the Sirte basin. Mabruk Oil Operations is the operating company for the Mabruk C-17 license, with Total as the lead partner for the international oil companies. Statoil's share of investments (working interest) in the c-17 license in the Mabruk field is 12.5%. The field has been producing since 1995. The Dahra south-east project was sanctioned in 2009.
Work to fully restore production is ongoing in both areas.
In 2010, Statoil and Lukoil entered into an agreement with the Iraqi authorities for the development of the West Qurna 2 field. However, Statoil has now started the process of transferring its 18.75% share to Lukoil.
The parties to the contract were the Iraqi state's South Oil Company and a consortium of contractors consisting of the Iraqi state's North Oil Company (25% and state partner), Lukoil, (56.25% and operator) and Statoil (18.75%). The development and production service contract for the West Qurna 2 field was offered as a service contract under which the contractors receive cost recovery plus a remuneration fee. Lukoil and Statoil's bid for West Qurna 2 included a production plateau level of 1,800 mboe per day.
However, Statoil has agreed with Lukoil and the Iraqi authorities to start the process of transferring its 18.75% share in the West Qurna 2 development project to the operator Lukoil. The booked reserves have been adjusted accordingly.
Development and Production in Europe and Asia primarily comprises Azerbaijan, Russia, United Kingdom and Ireland.
Statoil is active in several partner-operated licences in this region, including the major producing fields Shah Deniz and Azeri-Chirag-Guneshli in Azerbaijan. The upstream assets in Azerbaijan are a significant supplement to Statoil's strong position as a supplier to the European gas market. Statoil is also a partner in the Shtokman gas field in Russia, together with Gazprom and Total. Shtokman is a long-term resource that can enhance our upstream gas position while making Statoil a supplier from the north east. In the United Kingdom, Statoil has several oilfields under appraisal and it holds interests in three producing fields.
Statoil has been present in Azerbaijan since 1992, and has invested more than USD 5 billion. The two fields Azeri-Chirag-Gunashli and Shah Deniz contribute around 100 mboe per day of equity production to Statoil.
Statoil has a 8.6% stake in the Azeri-Chirag-Gunashli (ACG) field and an 8.7% stake in the 1,760-km Baku-Tbilisi-Ceyhan (BTC) pipeline that is used to transport most of ACG oil to the southern Turkish port of Ceyhan, enabling Azeri crude to be shipped to the world markets. The ACG field is operated by BP and is governed by a production sharing agreement (PSA) signed in 1994 with a duration of 30 years. In 2011, the field produced an average of 718 mboe per day.
The Chirag Oil Project sanctioned by the ACG partnership in 2010 is progressing according to plan. The first production from this project is scheduled for late 2013, and it is planned to add some 185 mboe per day in new production to ACG.
In addition to the share in ACG, Statoil has a 25.5% share in the Shah Deniz gas and condensate field, and a 25.5% share in the South Caucasus Pipeline, which transports the Shah Deniz gas from Azerbaijan through Georgia to the eastern Turkish border. The condensate from Shah Deniz is transported through the BTC pipeline to Ceyhan in Turkey. The Shah Deniz field is operated by BP and Naftiran Intertrade Company (NICO) has a 10% interest in this field. Statoil runs the Azerbaijan Gas Sales Company, which has been established to manage gas allocation and sales to customers in Azerbaijan, Georgia and Turkey. Statoil is also the commercial operator of the South Caucasus Pipeline Company, which is responsible for the commercial operations around the South Caucasus Pipeline. Shah Deniz Phase 1 has been in production since 2006. Shah Deniz produced 115 mboe per day of gas and 38 mboe per day of condensate in 2011. The PSA expires in 2031.
In 2007, the Shah Deniz partners decided to start maturing the second phase of the Shah Deniz field development. The concept for the Shah Deniz Phase 2 field development was agreed by the partners in late 2010. Project development operator BP estimates annual production from Shah Deniz Phase 2 to be 16 bcma of gas per year and about 100 mboe per day of condensate. The current plan is to make a final investment decision around the middle of 2013. That would mean first gas from the Shah Deniz Phase 2 development in late 2017.
The licences in Alov, Araz and Sharg expired in 2011 and were handed back to the State Oil Company of Azerbaijan (SOCAR). Operator BP has not been able to do any field work on these licences, as they are located in the disputed zone between Azerbaijan and Iran.
Statoil has been present in Russia since the late 1980s. We have a 24% ownership interest in Shtokman Development AG, which is responsible for the Shtokman development phase one. We also have a 30% ownership interest in the Kharyaga oilfield.
Field in production
During 2011, production has been maintained at plant capacity level. Phase 3 and the Phase 3 Extension development are ongoing, and 24 wells have been drilled.
Field under planning
Statoil has several oilfields under appraisal in the United Kingdom (UK) and it holds interests in three producing fields.
Fields in production
The Schiehallion oilfield is located west of the Shetland Islands. BP is the operator and Statoil has a 5.9% interest. In July 2011, the Schiehallion partnership sanctioned the redevelopment of the field and the acquisition of a new FPSO vessel. This is expected to extend production until at least 2035. Schiehallion produced 0.8 mboe of oil and gas per day in 2011.
Jupiter is a gas field located in the southern part of the UK North Sea. ConocoPhilips is the operator of the field, and Statoil has a 30% interest. Jupiter production is currently very low (~ 5 million standard cubic feet per day). The joint venture is discussing abandonment plans. Jupiter produced 0.4 mboe of gas per day in 2011.
Discoveries under appraisal
Rosebank, a discovery made by Chevron in 2004, is located west of the Shetland Islands. Statoil has a 30% interest in this field. The partnership is currently working towards concept selection for the field development.
Statoil has a 36.5% interest in the Corrib gas field, which lies on the Atlantic Margin north-west of Ireland. The Shell-operated Corrib field development was sanctioned in 2001, and work towards the first gas is ongoing.
The project has been delayed for some years mainly due to lengthy consideration of planning applications both for the terminal and the onshore section of pipeline and a controversial challenge that Shell experienced in 2005 when a small number of local landowners refused to allow Shell E&P access to their land to proceed with construction work relating to the onshore section of pipeline.
Now the construction of the gas terminal is 95% complete and preservation work is ongoing to maintain the condition of the equipment pending commissioning. Planning permission and other governmental consents for the tunnel required to lay the onshore pipeline under the estuary were obtained during the first quarter of 2011. Work started on the tunnel launch compound in July once all preconditions had been met. Groundwork is ongoing and the civil engineering contractor has been mobilised to site.
Six subsea wells have been drilled and the pipeline from field to shore is in place. The link line connecting the terminal to the Irish gas grid is in place. Production start-up is now anticipated to take place in 2014 at the earliest.
Marketing, Processing and Renewable Energy (MPR) is responsible for the transportation, processing, manufacturing, marketing and trading of crude oil, natural gas, liquids and refined products, and for developing business opportunities in renewables.
We run two refineries, two gas processing plants, one methanol plant and three crude oil terminals. We are also responsible for developing a profitable renewable energy position.
MPR is also responsible for marketing gas supplies originating from the Norwegian state's direct financial interest (SDFI). In total, we are responsible for marketing approximately 80% of all Norwegian gas exports.
In 2011, we sold 36.1 bcm (1.3 tcf) of natural gas from the Norwegian continental shelf (NCS) on our own behalf, in addition to approximately 33.5 bcm (1.2 tcf) of NCS gas on behalf of the Norwegian state. Statoil's total European gas sales, including third-party gas, amounted to 79.8 bcm (2.9 tcf) in 2011, of which 39.5 bcm (1.4 tcf) was gas sold on behalf of the Norwegian state. That makes us the second-largest gas supplier to Europe.
In 2011, we also sold 671 million barrels of crude oil and condensate, approximately 15 million tonnes of refined oil products from our own refineries, and 14 million tonnes of natural gas liquids (NGL). Tjeldbergodden produced approximately 865,000 tonnes of methanol. Our international trading activities make us one of the world's largest net crude oil sellers.
The MPR business activities are organised in the following business clusters:
In 2011, the gas market was characterised by volatility in both market prices and customer off-take. Refinery margins and trading margins were weaker than in 2010. The operation of facilities has been stable, and HSE results have improved since 2010.
The Natural Gas business cluster is responsible for Statoil's marketing and trading of natural gas worldwide, for power and emissions trading and for overall gas supply planning and optimisation.
Natural Gas (NG) is also responsible for marketing gas originating from the SDFI. NG also manages Statoil's asset ownership in gas infrastructure, such as the processing and transportation system for Norwegian gas (Gassled).
NG's business is conducted from Norway (Stavanger) and from offices in Belgium, the UK, Germany, Turkey, Azerbaijan and the USA (Houston and Stamford).
In 2011, we sold 36.1 bcm (1.3 tcf) of natural gas from the NCS on our own behalf, in addition to approximately 33.5 bcm (1.2 tcf) of NCS gas on behalf of the Norwegian state. Statoil's total European gas sales, including third-party gas, amounted to 79.8 bcm (2.9 tcf) in 2011 of which 39.5 bcm (1.4 tcf) was gas sold on behalf of the Norwegian state.
In addition, we sold 5.5 bcm (0.2 tcf) of gas originating from our international positions, mainly in Azerbaijan and the USA, of which 2.7 bcm (0.1 tcf) was entitlement gas.
We are a significant shipper in the NCS pipeline system owned by Gassled*, which is the world's largest offshore gas pipeline transportation system, totalling approximately 8,100 kilometres. This network links gas fields on the NCS with processing plants on the Norwegian mainland and with terminals at six landing points located in France, Germany, Belgium and the UK. It thereby gives us access to customers throughout Europe.
*Statoil had a 5% ownership interest in the system at the end of 2011.
In 2011, the nuclear accident in Japan led to greater gas power generation and higher LNG imports from European sources, while the US gas market became self-sufficient with a relatively low cost shale gas supply.
In the longer term, we believe that natural gas will be an increasingly attractive commodity. According to the IEA World Energy Outlook 2011, estimated global gas consumption in 2035 will be 55% higher than 2009 levels, reaching 4,750 bcm per year.
European natural gas prices were driven by a number of factors. Strong European storage injection levels coupled with the pull of LNG volumes towards Asia following the events in Japan supported prices through the summer, but a warm start to the winter of 2011-2012 contributed to low demand, relatively low winter prices and low storage withdrawals.
The interplay between coal and gas-fired power plant dispatch, which forms the basis for the coal switching price, was a key determinant of European gas prices throughout 2011. Coal prices remained relatively stable during the first three quarters of 2011 but fell by nearly USD 15/tonne in the fourth quarter of 2011 due to lack of support from Asian coal demand and concerns about economic growth weighing on commodity markets. Gas prices, in turn, remained above the coal switching price for most of the year due to the global tightness in LNG availability. The decline in coal prices, combined with a slide in carbon emissions prices, effectively meant that coal strengthened its position as the preferred fuel for power generation and reduced demand for gas. As a result, gas-to-power demand in 2011 was on average 22% lower than 2010 levels.
We anticipate continued high demand for LNG over the next five years and expect that the pending nuclear policy decisions in Japan and other countries with nuclear power will create uncertainty with regard to the market direction. As we believe global demand for natural gas will continue to grow, predominantly in Asia, we expect that any global LNG oversupply will diminish towards the middle of the decade as demand growth outpaces supply, despite new production capacity coming on stream. We expect European demand to grow due to increased demand for gas for power generation.
Liberalisation creates new opportunities and new business models in the gas sector, both with regard to added value as a result of efficiency gains and with regard to building a more substantial portfolio of sales directly aimed at large industrial customers and local distribution companies. Access to downstream markets has traditionally presented challenges, since capacity has been booked by incumbent companies. The Third Package (draft legislation from the EU) will introduce measures that should address capacity congestion and result in gradual improvements in market access and liquidity as the legislation is implemented across Europe. The integration of the gas and electricity markets also presents us with new business opportunities.
The EU is set to import some 75% of its natural gas by 2020 due to declining domestic gas production. In order to diversify supplies, European countries and companies are actively seeking alternative supply solutions. Moreover, Europe will need additional new sources of natural gas, since the global LNG market is expected to divert more gas to the growing Asian economies. We believe we are well positioned to supply part of this additional natural gas demand.
The gas market in OECD Europe is expected to grow from the current level of 550 bcm to approximately 630 bcm by 2030. The competitiveness of gas is expected to drive its share of total energy consumption from 25% today to 29% in 2030. Most of this growth is expected from increasing installation of gas power generation capacity.
Since the European energy markets are continuously facing changes in regulation and structures, we believe that natural gas will play an increasingly important role. We expect this trend to be reinforced as Europe pursues its long-term target of moving to a low-carbon economy, as reflected in the European Commission's "Energy Roadmap 2050".
The natural gas system in North America still shows few concrete signs of the structural changes in demand required to fully realise the benefits of the unconventional revolution in the USA, but there are more positive indications. The low-price environment and large global fuel spreads are incentivising new outlets for domestic gas resources. Most notable is Cheniere Energy's proposed LNG export facility, which has received an export licence, signed both off-take and construction agreements, and appears to be on track to commence operations in the 2015-16 timeframe. This would eventually make it the first such facility in the continental USA. Further plants look to have a more difficult time, due to the commercial arrangements that most proposed builders are asking off-take customers to accept, and potential export licensing headwinds. These new markets for US natural gas are needed to firm up prices, which would positively impact producers.
Statoil is a long-term, reliable natural gas supplier with a strong position in some of the world's most attractive markets.
Our group-wide gas trading activity is mainly focused on the UK gas market (National Balancing Point), which is a significant market in terms of size and the most liberalised market in Europe. We also take part in other liquid trading points, such as the PegN (Peg Nord) in France, TTF (Title Transfer Facility) in the Netherlands, the Zeebrugge Hub in Belgium and Gaspool/NCG in Germany.
Statoil has end-user sales business based in Belgium and the UK, serving major customers in Belgium, the UK, the Netherlands and France.
In 2004, Statoil (UK) Limited and SSE Hornsea Limited (subsidiaries of Statoil and Scottish and Southern Energy Plc, respectively) entered into a joint venture for the development, operation and maintenance of a salt cavern gas storage facility near Aldbrough on the east coast of Yorkshire, near the Easington terminal. The storage facility was officially opened on 27 June 2011. It comprises nine underground caverns that have been formed by using seawater to leach out salt water deposits around two kilometres underground. Statoil (UK) Limited owns one-third of the storage capacity being developed, of which the Norwegian State's direct financial interest (SDFI) will have access to 48.3%. The facility has been developed and is operated by SSE Hornsea Limited. Six of the nine caverns at Aldbrough are already storing gas. Full commercial operation of the nine-cavern facility is scheduled for 2012. When fully commissioned, Aldbrough will have the capacity to store around 330 million cubic metres of gas.
In Germany, we hold a 30.8% stake in the Norddeutsche Erdgas-Transversale (Netra) overland gas transmission pipeline, and a 23.7% stake in Etzel Gas Storage through our subsidiary Statoil Deutschland. Etzel Gas Storage is currently increasing its working gas capacity by 10 additional caverns, one of which was completed in 2009. Eight caverns were handed over to commercial operation in 2010, and the last one was handed over in 2011. All partners in Etzel Gas Storage are participating in this project.
The CPX capacity also includes downstream pipeline capacity from the Cove Point terminal to Leidy in Pennsylvania and gas storage capacity at Leidy.
Through Statoil, SDFI pays for a share of the capacity at the Cove Point regasification terminal, downstream pipeline capacity and storage capacity. LNG is sourced from the Snøhvit LNG facility in Norway and from third-party suppliers.
SNG also markets the equity production from Statoil's assets in the US Gulf of Mexico.
In 2008, Statoil entered into a strategic agreement with Chesapeake Energy Corporation relating to Marcellus shale gas. This strengthens Statoil's natural gas position in the USA by providing access to large gas reserves geographically near the north east, which, historically, is the highest-paying gas market. This also results in a significant increase in the volume of gas marketed and traded by Statoil in the USA.
In 2009, SNG concluded transportation agreements with Tennessee Gas Pipeline (a subsidiary of El Paso Corp) and Texas Eastern Transmission (a subsidiary of Spectra Energy Corp), ensuring Statoil the right to transport up to two bcm per year/200,000 mcf/day directly from the Northern Marcellus production area to New York City and surrounding areas. The expected in-service date is late 2013 or early 2014.
In 2010, SNG concluded a transportation agreement with National Fuel Gas Supply Corporation for up to 3.2 bcm per year (320,000 mcf/day). This agreement will enable Statoil to transport gas on a direct path from the Northern Marcellus production area to the US/Canadian border at Niagara Falls, thereby providing access to the attractive urban areas of eastern Canada. The expected in-service date is November 2012.
In December 2010, Statoil and Talisman formed a 50/50 joint venture for the purpose of developing assets in the Eagle Ford shale. NG will market Statoil's share of the gas production. The Eagle Ford equity production is a valuable addition to Statoil's oil and gas market portfolio in North America.
In 2011, Statoil Natural Gas LLC has entered into two long-term gas sales agreements with a major Canadian gas distributor. Under both agreements, Statoil will deliver gas to our counterparty at Niagara Falls on the US-Canadian border. Our counterparty has contracted for transportation capacity on the Trans Canada Pipeline (TCPL) from Niagara Falls to the Enbridge Central Delivery Area (ECDA), which covers the greater Toronto market area. The start of delivery for both deals is November 2012, which aligns with the in-service date for Statoil's Northern Access transportation capacity.
The stage 2 development of Shah Deniz is currently in the late stages of the concept selection phase of operator BP's capital value process. Field reserves support stage 2 production. In October 2011, the governments of Turkey and Azerbaijan signed an intergovernmental agreement relating to the sale of gas to Turkey and transportation through Turkey to the European markets. On the same date, the Shah Deniz Consortium entered into a gas sales agreement for 6 bcm per year and a transit agreement for 10 bcm per year with Botas in Turkey. Together with key partners in Shah Deniz, Statoil is currently negotiating sales contracts with several marketing companies in Europe and assessing alternative routes for bringing the gas into Europe.
Over the last 30 years, the Norwegian gas pipeline system has been developed into an integrated system connecting gas-producing fields with receiving terminals in Europe via processing plants on the Norwegian mainland.
The total length of Norway's gas pipelines is currently 8,100 kilometres. All gas pipelines on the NCS with third-party customers are owned by a single joint venture, Gassled, with regulated third-party access. The Gassled system is operated by the independent system operator Gassco AS, a company wholly owned by the Norwegian state. In 2011, the Gassled system transported 94.2 bcm (3.3 tcf) of gas to Europe.
Statoil's ownership interests in Gassled have been adjusted twice in 2011. With effect from 1 January 2011, Petoro's interests increased by approximately 7% and all other parties reduced their interests proportionally. Statoil's ownership was reduced to 29.1% from 1 January 2011. Similar adjustments were made to the ownership interest in Zeepipe Terminal JV and Dunkerque Terminal DA.
In June 2011, Statoil entered into an agreement for partial divestment of its ownership interest in Gassled from 29.1% to 5.0%. The divested interest of 24.1% has been purchased by the financial investment company Solveig Gas Norway AS. The transaction was approved by the government authorities in December 2011, and the divestment date was 30 December 2011. The divestment does not affect Statoil's position as the largest shipper in Gassled.
When new gas infrastructure facilities are merged into Gassled, the ownership interests are adjusted in relation to the relative value of the assets and each owner's relative interest. Hence, Statoil's future ownership interest in Gassled may change as a result of the inclusion of new infrastructure.
Statoil is the technical service provider (TSP) for Gassco with respect to the Kårstø and Kollsnes processing terminals, as well as for most of the gas pipeline and platform infrastructure system.
As an integrated pipeline network with high flexibility and regularity, we believe that the Norwegian gas pipeline system is an essential facility in terms of ensuring reliable supplies of natural gas to Europe.
The tables below present facts about the NCS gas pipelines, including transportation routes and daily capacities, and about our ownership in Gassled and receiving terminals.
As technical service provider (TSP), Statoil is responsible for the operation, maintenance and further development of the Kårstø gas processing plant on behalf of the operator Gassco.
Kårstø processes rich gas and condensate (light oil) from the NCS received via the Statpipe pipeline, the Åsgard Transport pipeline and the Sleipner condensate pipeline. The processing plant currently has a rich gas capacity of 88 MSm3/d. Products produced at Kårstø include ethane, propane, isobutane, normal butane, naphtha and stabilised condensate. When all of these products have been separated from the rich gas, the remaining gas (dry gas) is sent to customers via the Statpipe, Europipe II and Rogass pipelines. The processing plant currently has a dry gas export capacity of 77 MSm3/d.
Since 2008, the Kårstø processing plant has been undergoing comprehensive upgrading in order to meet safety and technical requirements, and future needs. The Kårstø Expansion Project (KEP) is the project name for several projects aimed at making the Kårstø facilities more robust and ensuring safe and efficient operation. The project investment is estimated to be around NOK 6 billion. The plan is to complete the remaining sub-projects in 2012.
As technical service provider, Statoil is responsible for the operation, maintenance and further development of the Kollsnes gas processing plant on behalf of the operator Gassco.
The Kollsnes plant was initially built in 1996 to receive gas from the Troll field in two 36-inch pipelines. The treatment process at Kollsnes involves separating out the NGL, and compressing the dry gas for export via Statpipe, Zeepipe, Europipe I and Franpipe. The processing capacity at Kollsnes has increased several times since the facility became operational. In 2010, the Kollsnes projects (KOP) started with the aim of maintaining the high regularity of the plant. In addition, a third 36-inch pipeline from the Troll field to Kollsnes was installed. Kollsnes also receives gas from the Visund, Kvitebjørn and Fram fields. These volumes are processed through the NGL plant. The Kollsnes gas processing plant currently has a design capacity of 143 MSm3/day.
The Troll field is a swing producer based on customer off-take. During the year, monthly off-take generally varies between 25% and 100%.
Statoil manages, transports and markets approximately 80% of all NCS gas and has a growing US gas position. In Europe, the gas is sold through long-term contracts with major European utilities, and a growing proportion is direct sales.
These direct sales are carried out with large industrial users, power producers and local distribution companies, and through short-term contracts and trading on European liquid marketplaces (hubs) in the UK and on the Continent. In the USA, gas is sold through a mix of contracts and trading on liquid marketplaces.
Due to the relatively large size of the NCS gas fields and the extensive cost of developing new fields and gas transportation pipelines, a large proportion of Statoil's gas sales contracts are long-term contracts that typically run for 10 to 20 years or more.
The long-term contracts contain flexibility arrangements guaranteeing a minimum annual off-take - the so-called take-or-pay quantity - and they provide daily flexibility for the customer. Prices in traditional long-term contracts are generally tied to a formula based on the prices for substitute fuels for natural gas, typically heavy fuel oil and gas oil. In our gas portfolio, we also have gas sales contracts that are priced with reference to a gas spot market index. There can be significant price fluctuations during the life of the contract. Most of the traditional long-term gas contracts contain contractual price adjustment mechanisms that can be triggered by the buyer or seller at regular intervals, or under certain given circumstances. In the last two years, the outcome of such discussions for values covered by long-term sales contracts has generally been the introduction of a small proportion of spot price indexation and/or limited reduction in the volume obligation for the buyer, and increased access to the continental spot markets for Statoil.
Statoil expects to continue to optimise the market value of the gas delivered to Europe through a mix of long-term contracts and short-term marketing and trading opportunities. This is done both as a response to customer needs and in order to capture new business opportunities as the markets become more liberalised.
Crude oil, liquids and products (CLP) adds value through the processing and sale of the group's and the Norwegian State's direct financial interest (SDFI) production of crude oil and natural gas liquids.
CLP is responsible for the group's transportation, marketing and trading of crude oil, natural gas liquids and refined products, including methanol. We are responsible for the commercial operation of two refineries (Mongstad, Norway and Kalundborg, Denmark) and the commercial operation of two crude oil terminals (Mongstad, Norway and South Riding Point, Bahamas). Our international trading activities make us one of the world's largest net crude oil sellers.
In 2011, MPR sold 671 million barrels of crude oil and condensate, approximately 15 million tonnes of refined oil products from our own refineries and 14 million tonnes of natural gas liquids (NGL).
The year 2011 had strong prices for Brent crude and significant volatility. The supply disruptions caused by the political turmoil in North Africa and the Middle East were important factors. The market for physical crude was tight and in backwardation.
The 2011 price for Brent crude averaged USD 111 per barrel, more than USD 30 higher than in 2010, and also significantly higher than the USD 97 per barrel from the previous record year of 2008. After starting 2011 at around USD 95 per barrel, Brent reached highs above USD 125 per barrel in April, and thereafter oscillated between USD 100 and USD 120 per barrel.
There are two main reasons why prices were strong in 2011. In 2010, oil demand growth came in at a record-high level of 2.9 mboe per day, as world demand rebounded quickly from the 2008-2009 recession, led by strong growth in non-OECD countries. This tightened global oil inventories sharply during the fourth quarter of 2010 and the first quarter of 2011, and we entered 2011 without much of the excess capacity that had formed in the oil market during the financial crisis of 2008-2009.
The "Arab spring" raised the general level of uncertainty attached to oil supplies from this region, and the outbreak of the Libyan civil war in February took 1.5 mboe per day of light sweet crude off the market. In addition, a string of production disruptions in some key producing countries wiped out much of the anticipated oil supply growth. Saudi Arabia and other key Persian Gulf member states responded by raising oil production, but not by enough to cover the entire loss of Libyan volumes. As a consequence, global oil inventories were reduced further. By late summer, they were near five-year lows, but increased slightly during the fourth quarter of 2011 compared to five-year lows.
As crude supply has lagged behind demand throughout 2011, the market for physical crude has been very tight. The market has been in backwardation throughout the year. The loss of Libyan crude exports as well as the many minor disruptions in North Sea production also led to strong premiums for North Sea light sweet crudes, and for Brent versus other global markers. In the USA, a lack of infrastructure to bring the rapidly increasing volumes of shale oil produced in the Midwest region to market led to sharp discounts for the inland WTI crude marker, which at some points traded as much as USD 25 per barrel below Brent crude. This dislocation has eased after the announcement that a key pipeline will be reversed to enable crude flows south to the US Gulf Coast. However, rapid changes in US inland oil balances will continue to cause turbulence on the North American crude market.
Increasing worries about the state of the global economy and about the sovereign debt situation in Europe and the USA capped the rally in crude prices and have led to significant volatility over the course of the year. However, due to the tight fundamentals in the oil market, crude has remained strong despite the increasing economic and financial headwinds. The nuclear disaster in Fukushima in Japan in March had a mixed effect on markets and added to volatility, but, over time, it has led to additional oil demand for power generation after most nuclear plants were taken off the grid for security checks.
Statoil is one of the world's major net sellers of crude oil, operating from sales offices in Stavanger, Oslo, London, Singapore, Stamford and Calgary and selling and trading crude oil, condensate, NGL and refined products.
We market Statoil's own volumes and the SDFI's equity production of crude oil and NGL, in addition to third-party volumes. In 2011, our total sales of crude and condensate were equivalent to 671 million barrels, including supplies to our own refineries. The main crude oil market for Statoil is north-west Europe. In addition, we sell volumes to North America and Asia. Most of the crude oil volumes are sold in the spot market based on publicly quoted market prices. Of the total 671 million barrels sold in 2011, approximately 41% were Statoil's own equity volumes.
The Product and Refinery Optimisation (PRO) unit is responsible for optimising and marketing Statoil's total production of 15 million tonnes of refined products from the refineries at Mongstad (Norway) and Kalundborg (Denmark). We also market the 865,000 tonnes of methanol from the Tjeldbergodden plant (Norway). In addition to equity volumes, we sell approximately 14 million tonnes of products in north-west Europe, the USA, and in the trans-Atlantic basin.
We are responsible for optimising commercial utilisation of the crude terminal located at Mongstad and the South Riding Point crude oil terminal in the Bahamas. We are also responsible for Statoil's crude and LPG liftings at the Sture terminal.
Marketing activities are also optimised through lease contracts and long-term agreements for the utilisation of third-party assets.
Statoil holds the lease for the South Riding Point crude oil terminal in the Bahamas until 2049, which includes oil storage as well as loading and unloading facilities. We also operate the Mongstad terminal and have shared ownership with Petoro.
South Riding Point
In 2011, we upgraded the terminal to enable the blending of crude oils, including heavy oils. The blending is carried out onshore, and from ship to ship at the jetty.
This terminal is intended to both support our global trading ambitions and improve our handling capacity for heavy oils. We expect the new blending facilities and full terminal capacity to strengthen both our marketing and trading positions in the North American market. The terminal is also an important part of our plans to market our own volumes of heavy oil.
In addition to the existing lease period, we have an option to extend the agreement for an additional 30 years until 2079.
Crude oil is landed at Mongstad via two pipelines from Troll, by dedicated vessels from Heidrun and by crude vessels from the market.
The terminal supports Statoil's global trading, blending and transhipment of crudes and is an important tool in the marketing of North Sea crudes.
Processing and manufacturing is responsible for the safe, reliable and efficient operation of Statoil's onshore facilities.
This includes the refineries at Mongstad and Kalundborg, the methanol production plant at Tjeldbergodden and the gas processing plants at Kårstø and Kollsnes. It does not include the LNG plant at Melkøya, however. That plant is operated by DPN.
Processing and manufacturing is also responsible for the operation of the Oseberg Transportation System and the oil terminal at South Riding Point in the Bahamas.
We are the majority owner (79%) and operator of the Mongstad refinery in Norway, which has a crude oil and condensate distillation capacity of 220,000 barrels per day. We are the sole owner and operator of the Kalundborg refinery in Denmark, which has a crude oil and condensate distillation capacity of 118,000 barrels per day. In addition, we have rights to 10% of production capacity at the Shell-operated refinery in Pernis in the Netherlands, which has a crude oil distillation capacity of 400,000 barrels per day. Our methanol operations consist of an 81.7% interest in the gas-based methanol plant at Tjeldbergodden, Norway, which has a design capacity of 0.95 million tonnes per year.
We also operate the Oseberg Transportation System (36.2% interest), including the Sture crude oil terminal. The terminal was built to receive crude from the Oseberg field by pipeline. Since 2003, it has also received crude from the Grane field pipeline. Oseberg blend (after stabilisation), Grane blend and some LPG are exported, while some LPG and naphtha is piped to Mongstad combined with condensate from the Kollsnes gas processing plant.
Processing and manufacturing performs the role of technical service provider (TSP) for the Kårstø and Kollsnes gas processing plants, in accordance with the technical service agreement between Statoil and the operator Gassco. Processing and manufacturing also performs the TSP role for Transport Net (Norway's gas transport system) and the oil terminal at South Riding Point, Bahamas. For further information on Kårstø, Kollsnes, Transport Net and South Riding Point, see Natural Gas and Crude oil, liquids and products, respectively above.
The following table shows operating statistics for the plants at Mongstad, Kalundborg and Tjeldbergodden.
Due to the challenging refining market, Statoil initiated a five-year programme to improve the competitive position of our onshore facilities through increased efficiency, reduced operating expenses and value creation. The improvement programme reached its yearly target for 2011.
The Mongstad refinery is a medium-sized, modern refinery. It is linked to offshore fields, the Sture crude oil terminal and the Kollsnes gas processing plant, making it an attractive site for landing and processing hydrocarbons.
The Mongstad refinery, which was built in 1975, was significantly expanded and upgraded in the late 1980s. It has been subject to considerable investment over the last 15 years in order to meet new product specifications and improved energy efficiency. A medium-sized, modern refinery, it is directly linked to offshore fields through two crude oil pipelines, through a natural gas liquids (NGL)/condensate pipeline to the crude oil terminal at Sture and the gas processing plant at Kollsnes, and by a gas pipeline to Kollsnes. This makes Mongstad an attractive site for landing and processing hydrocarbons and for the further development of our oil and gas reserves. Statoil owns 79% of the refinery, while Shell owns the remaining 21%.
In addition to the refinery, the main facilities at Mongstad consist of a crude oil terminal, an NGL process unit and terminal (Vestprosess), and a combined heat and power plant (CHP). Statoil owns 65% of the crude terminal. A large proportion of its crude oil comes via two direct pipelines from the Troll field. The storage capacity is 9.4 million barrels of crude.
Statoil owns 34% of Vestprosess, which transports and processes NGL and condensate. The Vestprosess pipeline connects the Kollsnes and Sture plants to Mongstad. The NGL is fractionated in the Vestprosess NGL unit to produce naphtha, propane and butane.
The CHP plant is 100% owned by Dong Generation Norge AS. It produces electric heat and power from gas received from Troll and from the refinery.
The Mongstad refinery can manufacture products to meet different specifications through in-line blending during ship loading.
The refinery's reliability (on-stream factor) was high in 2010 and 2011, and we carried out a major turnaround in 2010. Capacity utilisation (the proportion of available plant capacity actually used) has been reduced depending on the market situation.
The new CHP plant started commercial operation on 20 December 2010, and it is part of a strategically important project. The plant improves the Mongstad refinery's energy efficiency and has a capacity of approximately 280 megawatts of electric power and 350 megawatts of process heat. The plant will have a gradual start-up phase as the refinery needs less steam due to a changed feedstock pattern, lower throughput and the postponement of projects. The plant is operated by Dong Energy, with Statoil paying an annual tariff for its use. In addition to the CHP plant, the CHP investment project included a new gas pipeline from Kollsnes and necessary modifications at the refinery.
In 2011, Statoil decided to continue its investment in the upgrade of its Coker plant (DCR project) to ensure a more effective process and improve working conditions.
Together with the Norwegian government, Statoil is involved in several projects that aim to develop solutions for carbon capture and storage (CCS) at Mongstad. See chapter 3.3.6 Renewable energy for further information.
The Kalundborg refinery is a small but flexible oil refinery. While this enables it to produce a variety of products, its main products are low-sulphur gasoline and diesel for markets in Denmark and Sweden.
The refinery is connected via two pipelines (one gasoline and one gas oil) to our terminal at Hedehusene near Copenhagen, and most of our products are therefore sold locally.
Kalundborg's refined products are also supplied to other markets in north-west Europe, mainly Scandinavia.
The following table shows the approximate quantities of refined products (in thousand tonnes) produced by Kalundborg in the periods indicated.
The refinery's reliability (on-stream factor) was good in 2011 and on a par with its best years. The throughput in 2011 was lower due to a planned maintenance turnaround and the economic downturn. The product yield from the refinery is well positioned in relation to the expected future demand structure in the European market.
The methanol plant at Tjeldbergodden is the largest in Europe and one of the most energy efficient in the world. It is supplied with natural gas from the Heidrun field in the Norwegian Sea through the Haltenpipe pipeline.
Statoil owns 81.7% of the plant, which has a maximum proven capacity of 0.92 million metric tonnes per year (mmtpa). The actual throughput in 2011 was 0.86 mmtpa, compared to 0.80 mmtpa in 2010.
Statoil also owns 50.9% of Tjeldbergodden Luftgassfabrikk DA, one of the largest air separation units (ASU) in Scandinavia.
The Sture terminal receives crude oil in two pipelines from the Oseberg area and the Grane field in the North Sea. The terminal is part of the Oseberg Transportation System in which Statoil has a 36.2% interest.
The terminal has a storage capacity of 6.3 million barrels of crude.
The processing facilities at Sture stabilise Oseberg crude oil and recover LPG mix (propane and butane) and naphtha. Oseberg Blend and Grane crude qualities and LPG mix are exported. LPG and naphtha are also transported through the Vestprosess pipeline to Mongstad.
The LPG processing capacity is a maximum 68 tonnes/hour. The import capacity is approximately 96,000 cm/d of Oseberg blend, and approximately 40,000 cm/d of Grane oil.
Our renewable energy business focuses in particular on developing business in areas where we may have a competitive edge as a result of our offshore oil and gas expertise. Key areas are offshore wind and carbon capture and storage (CCS).
Full-scale carbon capture Mongstad (CCM)
The full-scale carbon capture plant is a mega-project due to its size, complexity and uniqueness in relation to the technology involved. The project planning will have to reflect that the capture plant is to be integrated with the existing CHP and refinery in production. Through the Mongstad project, Statoil is supporting the realisation of a complete value chain for carbon capture, transport and storage. A final investment decision for this project is expected in 2016.
SFR is a leading road transportation fuel retailer with a presence in eight countries across Scandinavia and central and eastern Europe. The group is also involved in the sale of stationary energy, marine fuel, aviation fuel, lubricants and chemicals.
SFR was established in May 2010 as a separate legal entity within the Statoil group. In October 2010, Statoil ASA transferred all activities relating to the fuel and retail business to SFR. Following an initial public offering, the shares of SFR were listed on the Oslo Stock Exchange (Oslo Børs) on 22 October 2010. Statoil ASA is the majority shareholder in SFR, holding 54% of the shares. SFR's results are consolidated in Statoil ASA's financial statements.
SFR is a leading Scandinavian road transportation fuel retailer with over 100 years of operations in the region. SFR has also established a strong presence in Poland, Latvia, Lithuania, Estonia and Russia.
As of 31 December 2011, SFR had a network of 2,305 fuel stations across its eight countries of operation, comprising a combination of full-service stations - which have integrated convenience stores - and automated fuel stations and truck stops. Of these,1,739 fuel stations are located in Denmark, Norway and Sweden, and 566 are located in Poland, Latvia, Lithuania, Estonia and Russia.
In addition, SFR is involved in the sale of stationary energy (mainly heating oil, kerosene, LPG and heavy fuel for industrial purposes) and marine fuel (marine gas oil and heavy fuel) as well as aviation fuel, lubricants and chemicals.
Statoil Fuel & Retail recorded a strong financial performance in Scandinavia in 2011, but noted more challenging conditions in central and eastern Europe.
The retail road transportation fuel business primarily involves the sale of various gasoline fuels, diesel fuels, biofuels, and, in some markets, LPG for use in private and commercial vehicles, motorcycles and trucks.
These fuels are dispensed from pumps located at fuel stations that can either be manned, full-service stations that generally have an integrated convenience store, or self-service automated fuel stations with limited or no sales personnel on site and that do not have an integrated convenience store. In some markets, there is often an additional network of truck stops dedicated to the needs of commercial vehicles, which may be automated or part of full-service fuel stations, but which have dedicated lanes with high-speed pumps and other infrastructure to cater for large vehicles such as trucks.
The non-retail road transportation fuel business involves bulk sales of some or all of the road transportation fuels described above to industrial and commercial customers, such as car rental fleets, road construction crews, bus services and factories, and to independent resellers or retailers. Non-retail road transportation fuel sales frequently involve delivering fuel directly to the end-user's own in-house fuel storage facilities, although a number of SFR's wholesale customers also purchase products directly from the company's terminals and depots using their own transportation systems.
With respect to customers, road transportation fuel is sold to both customers purchasing road transportation fuel in their individual capacity for personal use ("B2C") and to business or commercial customers purchasing road transportation fuel in connection with their work or profession ("B2B").
In addition to the sale of road transportation fuel, the retail road transportation fuel business also involves sales of a broad range of convenience products and services from convenience stores that are an integrated part of full-service fuel stations. The range of convenience products and services provided at fuel station convenience stores includes candy, snacks, drinks, and tobacco. It can also include a wider range of products, such as fast food and vehicle-related products, as well as the provision of certain vehicle-related services, such as air/water, car wash and car rental. The range of fuel station convenience products and services varies between fuel station operators and occasionally between different fuel stations with the same operator. Some fuel station operators focus mainly on car accessories and car-related products and services, while others focus more on food-related products, such as fast food, coffee, baked goods and beverages.
Technology, Projects and Drilling (TPD) is an internal function that is responsible, as a global service provider to Statoil, for delivering projects and wells and for providing support through global expertise, standards and procurement.
TPD business priorities:
TPD is also responsible for promoting Statoil as a technology group, including developing and implementing new technological solutions.
Statoil has revised its corporate technology strategy, which sets the strategic direction for how technology development and implementation can address the challenges and contribute to achieving the corporate ambitions for 2020 and beyond.
In 2011, TPD delivered innovation, technology implementation, procurement strategies, project execution, safe and efficient drilling, and well operations.
The research and development (R&D) business cluster is responsible for carrying out research to meet Statoil's business needs.
A world-class research and development organisation is crucial in order to support Statoil's growth ambition and to solve complex technology challenges on the NCS and internationally.
Statoil's R&D portfolio is organised in seven programmes covering the main upstream building blocks where Statoil is growing. The R&D organisation operates and further develops laboratories and large-scale test facilities and has an academia programme that addresses cooperation with universities and research institutes.
R&D expenditure has been approximately NOK 2.1 billion per year for the last three years. Cooperation with external partners such as academic institutions, R&D institutes and suppliers is crucial in relation to technology.
Statoil has four research centres in Norway, a heavy oil technology centre in Canada and an R&D office in Beijing (China). In addition, we have expanded our R&D activities with offices in Rio de Janeiro (Brazil), Houston (USA) and St. John's (Canada), close to many of our international operations.
New development solutions
Oil and gas value chain
New energy and HSE
Heavy Oil Technology Centre
Gulf of Mexico and Brazil
By supporting collaboration between universities, research institutions and industry, we also contribute to building a strong Norwegian petroleum cluster. Through the R&D programmes and our international offices, we also cooperate with international universities and organisations in countries such as Canada, the USA, China and Brazil.
Selected technology advances and important milestones 2011:
Heavy Oil Technology Centre
New energy and HSE
New development solution, and lab and test facilities
Technology excellence (TEX) is responsible for delivering technical expertise to projects, business developments and assets globally, and for new technology and the corporate technology strategy.
TEX is a leader in the application of new technology in Statoil and in the oil and gas industry. Our technological expertise in areas such as petroleum technology, subsea and marine technology, facilities and operations technology and HSE enhances Statoil's operational performance. Technology development and implementation are used to promote and achieve corporate targets for production growth, increased regularity, reserve growth, reduced costs and improved drilling efficiency. Technology excellence also supports innovators and entrepreneurs in connection with technology development and commercialisation activities.
Selected technology advances and important milestones in 2011:
Subsea gas compression - a technological quantum leap
Fast track: moving from tailor-made to ready-made
New model for calculating NOx emissions
Optimal gas turbine water wash
Improved technology on Snøhvit brings significant energy savings
Large cost reductions on Valemon and Gudrun
Improved oil recovery
Projects (PRO) is responsible for planning and executing all major facilities development, modification and cessation projects in Statoil.
PRO aims to be world class in terms of project performance, delivering cost-efficient projects on time and in accordance with high HSE standards and agreed quality standards. To become a truly global energy player, Statoil must be capable of executing projects at the very highest level.
PRO will continue to emphasise competitive cost and quality in design and execution in order to improve performance and be fit to face the fiercer competition of tomorrow. Great efforts are made to set the direction of the key drivers in Statoil's projects in the early phase, when the possibility of influencing costs and value creation is greater.
Experience transfer from fast-track projects is the key, in particular in simplification and swift implementation of improvements. Fast-track projects are subsea tie-in projects in which standardised solutions are used to reduce the time from discovery to production from five to 2.5 years. Reducing costs by 30% is also an ambition for fast-track projects.
Important milestones 2011
List of PRO's main deliveries:
Drilling and well (D&W) is responsible for providing efficient well deliveries, ensuring fit-for-purpose drilling facilities and providing expertise and advice to all Statoil's drilling and well activities.
D&W will seek to industrialise drilling operations by exploiting new technologies for intelligent and safe well construction. The goal is to increase cost-effective drilling and improve HSE. D&W will continue to target enhanced operational excellence, and the outlook going forward indicates strong activity, with the delivery of several new rigs and the takeover of Brigham, Eagle Ford and Marcellus. Exploiting new technology to increase efficiency and secure necessary resources will be a critical success factor.
The most important part of our operational excellence is safe drilling and well operations worldwide. We experienced a decreasing rate of serious HSE incidents, falling objects frequency and accidental spills. There were no serious well control incidents in 2011 (the last incident was in July 2010).
D&W has delivered 87 wells offshore, an increase of 36% since 2010. In addition, almost 33% of the wells were exploration wells - up from 11% in 2010. There were also 12 international exploration wells - including side tracks - in 2011, compared with zero in 2010. The number of rig years increased from 32 to 37 years. The figures reflect the positive effects of Statoil's simplified and cost-effective drilling strategy.
D&W's onshore activity delivered 125 exploration wells in Canada during the winter drilling programme.
Statoil has issued an invitation to tender for a new type of drilling rig specially designed for use on mature fields on the NCS. The rigs delivered to the NCS in recent years were primarily designed for operation in deep water. However, as many discoveries on the NCS have become smaller (with exceptions such as Aldous, Avaldsnes and Skrugard), it is becoming more important to increase drilling activity in mature fields in order to realise their full potential. The purpose is to make the drilling and completion of production wells cost efficient and safer, and to boost oil recovery.
Procurement (PSR) is responsible for ensuring cost-efficient procurement on a global basis that is aligned with Statoil's business needs, and for managing Statoil's supply chain.
The annual value of Statoil's procurements is more than NOK 100 billion from approximately 12,000 active suppliers. They are procurements for projects, maintenance and operations, drilling and well, and business support. Our procurement process is based on competition and the principles of openness, non-discrimination and equality. Our suppliers contribute significant value to Statoil, and to our partners and customers. We therefore encourage and facilitate collaboration with our suppliers through communication and managing supplier relations. By maintaining strong relations with high-quality suppliers, Statoil aims to ensure lasting long-term competitive advantages. Our procurement approach and how we collaborate and work together with high-quality suppliers will be crucial in relation to enabling technology development and innovation.
PSR develops the supplier base through linking demand in Statoil with suppliers globally. The Asia-Pacific region has for the past few decades experienced staggering industrial development, and it now has a large number of suppliers to the oil and gas industry. China has led development in this region. It is the world's most expansive industrial nation, capable of delivering high quality on competitive terms. We believe that we will see many suppliers from this region becoming valuable to Statoil in the years to come, complementing our existing supplier base and securing capacity and quality.
Statoil aims to make sustainable investments that benefit the communities and countries in which we operate. We do this by creating local content and generating positive spin-offs from our core business in support of development ambitions wherever we are present. We promote local sourcing and work with local businesses as suppliers and contractors where they exist. We invest in developing sustainable and competitive local enterprises. We support education and skills building in the local community and among our suppliers and contractors in order to build lasting capacity and to help them develop the skills standards and certifications required to work in the oil and gas industry.
Several rig initiatives
We have launched several initiatives:
Cat A - light well intervention vessels
The ambition of the new Global Strategy and Business Development (GSB) organisation is to bring together Statoil's corporate strategy, business development, and merger and acquisition activities to actively drive growth and corporate development.
GSB was established as a new business area in 2011, with its main office in London. GSB sets the strategic direction for Statoil and identifies, develops and delivers opportunities for global growth. This is achieved through close collaboration across geographic locations and business areas. Statoil's renewed strategy, which was launched in June 2011, plays an important role in guiding Statoil's business development focus.
GSB's business activities are organised in the following areas:
GSB will spearhead inorganic moves towards Statoil's growth target as outlined in our renewed strategy.
GSB initiated, executed and concluded several large-scale business development projects in 2011 that reflect Statoil's strategic direction. Active portfolio management has realised substantial value and further strengthened Statoil's growth potential.
Below are the highlights from the past year:
In October 2011, Statoil and Brigham Exploration Company in the United States announced that they had entered into an agreement for Statoil to acquire all of the outstanding shares in Brigham for USD 36.50 per share through an all-cash tender offer. Subsequently, in December 2011, Statoil announced the successful completion of the tender offer, with more than 92.2 per cent of the outstanding shares of Brigham's common stock tendered. Statoil acquired all of the outstanding shares prior to year end. The total equity value of the acquisition was approximately USD 4.4 billion.
Brigham's principal business activity is centred around the development of the Bakken and Three Forks tight oil formations, which are considered to be among the largest oil accumulations in the United States. Statoil believes that such unconventional resource bases will be an increasingly important part of future energy supplies.
The following table shows significant subsidiaries owned directly by the parent company, as well as the parent company's equity interest and the subsidiaries' country of incorporation as of 31 December 2011.
Our voting interest in each case is equivalent to our equity interest.
Statoil's operational review accords with its segment's operations as of 31 December 2011, whereas certain disclosures about oil and gas reserves are based on geographical areas as required by the Securities and Exchange Commission (SEC).
For further information on extractive activities, refer to the sections Operational review - Development and Production Norway and Operational review - Development and Production International, respectively.
Statoil prepares its disclosures for oil and gas reserves and certain other supplemental oil and gas disclosures based upon geographical areas as required by the SEC. The geographical areas are defined by country and continent. They consist of Norway, Eurasia excluding Norway, Africa and the Americas.
For further information about disclosures for oil and gas reserves and certain other supplemental disclosures based upon geographical areas as required by the SEC, refer to the section Operational review - Proved oil and gas reserves.
This section describes our oil and gas production and sales volumes.
The following table shows our Norwegian and international entitlement production of crude oil and natural gas for the periods indicated. The stated production volumes are the volumes that Statoil is entitled to pursuant to conditions laid down in licence agreements and production sharing agreements. The production volumes are net of royalty oil paid in kind and of gas used for fuel and flaring. Our production is based on our proportionate participation in fields with multiple owners and does not include production of the Norwegian state's oil and natural gas. Production of an immaterial quantity of bitumen is included in crude oil production.
The following tables present the average unit of production cost based on entitlement volumes and realised sales prices.
Proved oil and gas reserves were estimated to be 5,426 mmboe at year end 2011, compared with 5,325 mmboe at the end of 2010.
Statoil's proved reserves are estimated and presented in accordance with Securities and Exchange Commission (SEC) Rule 4-10 (a) of Regulation S-X, revised as of January 2009, and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins, as issued by the SEC staff. For additional information, see Critical accounting judgements and key sources of estimation uncertainty; Key sources of estimation uncertainty; Proved oil and gas reserves in note 2 Significant accounting policies to the consolidated financial statements. For further details on proved reserves, see also note 33 - Supplementary oil and gas information - to the consolidated financial statements.
Changes in proved reserves estimates are most commonly the result of revisions of estimates due to observed production performance, extensions of proved areas through drilling activities, or the inclusion of proved reserves in new discoveries through the sanctioning of development projects. These are sources of additions to proved reserves that are the result of continuous business processes and can be expected to continue to add reserves at some level in the future.
Proved reserves can also be added or subtracted through the acquisition or disposal of assets. Changes in proved reserves can also be due to factors outside management control, such as changes in oil and gas prices. While higher oil and gas prices normally allow more oil and gas to be recovered from the accumulations, Statoil will generally receive smaller quantities of oil and gas under production sharing agreements (PSAs) and similar contracts. These changes are included in the revisions category in the table below.
The principles for booking of proved gas reserves are limited to contracted gas sales or gas with access to a robust gas market.
In Norway, we recognise reserves as proved when a development plan is submitted, since there is reasonable certainty that such a plan will be approved by the regulatory authorities. Outside Norway, reserves are generally booked as proved when regulatory approval is received, or when such approval is imminent. Reserves from new discoveries, upward revisions of reserves and purchases of proved reserves are expected to contribute to maintaining proved reserves in future years.
Approximately 87% of our proved reserves are located in politically stable countries within the Organisation for Economic Co-operation and Development (OECD). Norway is by far the most important contributor in this category, followed by the United States of America (USA), Canada, Ireland and the United Kingdom (UK).
10% of our total proved reserves are related to production sharing contracts (PSCs) in non-OECD countries such as Angola, Algeria, Nigeria and Libya in Africa, Azerbaijan and Russia. Other non-OECD reserves are related to concessions in Brazil and Venezuela, representing approximately 3% of our total proved reserves and included in proved reserves in the Americas.
Significant additions to our proved reserves in 2011 were:
New discoveries with proved reserves booked in 2011 are all expected to start production within a period of five years.
More details relating to changes in proved reserves can be found under separate descriptions by geographical area below.
Summary of proved oil and gas reserves as of 31 December 2011.
Our proved reserves of bitumen in the Americas are included as oil in the table above as they represent less than 4% of our proved reserves, which is regarded as immaterial.
Basis for equivalents as presented in the section Terms and definitions.
The reserves replacement ratio increased to 1.17 in 2011 from 0.87 in 2010. The increase in the reserves replacement ratio in 2011 is mainly due to large positive revisions, as well as the Brigham acquisition and increased ownership interests in the Norwegian fields Gudrun, Snøhvit and Valemon in 2011. The 2011 reserves replacement, excluding purchases and sales of petroleum in place, is 1.01. The average replacement ratio for the last three years was 0.92, including purchases and sales.
The usefulness of the reserves replacement ratio is limited by the volatility of oil prices, the influence of oil and gas prices on PSA reserve booking, sensitivity related to the timing of project sanctions, and the time lag between exploration expenditure and the booking of reserves.
Proved reserves in Norway
A total of 4,165 million boe is recognised as proved reserves in 63 fields and field development projects on the Norwegian continental shelf (NCS), representing 77% of our total proved reserves. Of these, 52 fields and field areas are currently in production, 45 of which are operated by Statoil. Several new field development projects sanctioned during 2011 are adding new proved reserves categorised as extensions and discoveries. Production experience, further drilling and improved recovery on several of our producing fields in Norway also contributed positively to the revisions of the proved reserves in 2011. This includes decisions to invest in the upgrading of drilling facilities or installation of facilities for compression on fields such as Snorre, Njord and Åsgard.
Of the proved reserves on the NCS, 3,175 million boe or 76% are proved developed reserves. 67% of the total proved reserves are gas reserves, related to large offshore gas fields such as Troll, Ormen Lange, Snøhvit, Kvitebjørn, Oseberg, Visund and Tyrihans.
In the North Sea, five new field developments were sanctioned during 2011 and are carrying proved reserves for the first time: Hild, Stjerne, Svalin, Visund North and Vigdis North-East, all except Hild operated by Statoil. Increased equity interests in the ongoing field development projects Gudrun and Valemon added new proved reserves categorised as purchase of petroleum in place.
In the Norwegian Sea, development plans have been approved for the Hyme and Skuld projects, adding new proved reserves as extensions and discoveries.
In the Barents Sea, Statoil's ownership interest in the Snøhvit field has increased, adding new proved reserves categorised as purchase of petroleum in place.
The 2011 reserves replacement ratio for the NCS was 1.03, including purchases and sales.
Proved reserves in Eurasia excluding Norway
In this area we have proved reserves of 222 million boe related to six fields in the countries Azerbaijan, Russia, Ireland and the United Kingdom. Eurasia excluding Norway represents 4% of our total proved reserves, Azerbaijan being the main contributor with the Shah Deniz and Azeri-Chirag-Gunashli fields. All fields are producing, except for the Corrib field in Ireland, which is still under development and anticipated to start production in 2014 at the earliest. We do not carry proved reserves at year end 2011 related to our interest in the Jupiter field in the United Kingdom, as this is likely to permanently close down production in the near future.
An insignificant amount of reserves in Iran related to production entitlement following our previous activities in this country is included and no reserves related to Iraq are included.
Of the proved reserves in Eurasia, 168 million boe or 76% are proved developed reserves. 51% of the total proved reserves in this area are oil reserves and 49% are gas reserves.
Proved reserves in Africa
We recognise proved reserves of 390 million boe related to 21 fields and field developments in several West and North African countries; Algeria, Angola, Libya and Nigeria. Angola is the major contributor to the proved reserves in this area, with 16 of the 21 fields.
In Angola we have proved reserves in four blocks; Block 4, Block 15, Block 17 and Block 31, with production from all blocks except Block 31. Four discoveries in Block 17 , called the CLOV project, and two discoveries in Block 15, Clochas and Mavacola, are under development. In Block 31, all four discoveries in the PSVM project are under development.
Of the total proved reserves in Africa, 272 million boe or 70% are proved developed reserves. 80% of the total proved reserves in this area are oil reserves and 20% are gas reserves.
Proved reserves in the Americas
In North and South America, we have proved reserves equal to 650 million boe in a total of 19 fields and field development projects. This represents 12% of our total proved reserves. Fourteen of these fields are located in the United States (USA), four in Canada and two in South America. The most important new contribution to our reserves is the Bakken asset, from the acquisition of Brigham Exploration Company in late 2011, adding 122 million boe of proved reserves. These are primarily reserves in the Bakken and Three Fork tight oil plays in the Williston basin, located principally in the state of North Dakota in the USA.
In the USA, six out of ten fields in the Gulf of Mexico and the onshore tight reservoir assets Marcellus, Eagle Ford, Bakken and Three Forks are all in production. In the Gulf of Mexico, field development is ongoing at Caesar Tonga, Big Foot, Jack and St. Malo. The Big Foot development is carrying economic proved reserves for the first time from 2011. Further drilling in the Marcellus and Eagle Ford assets has increased the proved reserves in 2011, and these additions are expressed as extensions.
The Hibernia South Extension field off the coast of Canada was sanctioned and started production during 2011, and it is carrying proved reserves for the first time. In Canada, proved reserves are related both to offshore field developments and to the Leismer Demonstration Project in our oil sands leases in Alberta.
In 2010, we announced the sales of a 40% interest in the Peregrino field in Brazil and a 40% interest in the oil sands leases in Alberta, Canada. These sales have now been approved and the effect on the 2011 proved reserves statement is 66 million boe sale of reserves-in-place.
In 2011, we converted approximately 230 million boe from undeveloped to developed proved reserves.
Start-up of production from the Hibernia South Extension off the coast of Canada, Pazflor in block 17 in Angola and Peregrino in Brazil increased our developed reserves by 54 million boe during the year. The rest of the converted volume is related to development activities on producing fields.
The sanctioning of new projects, such as Hild, Hyme, Skuld, Stjerne and Svalin (M structure) in Norway, Hibernia South Extension off the coast of Canada and Big Foot in the Gulf of Mexico added a total of 97 million boe of proved undeveloped reserves in 2011. In addition, the Brigham acquisition in late 2011 added significant volumes to both our proved developed and undeveloped reserves.
As of 31 December 2011, the total proved undeveloped oil and gas reserves amounted to 1,599 million boe, 62% of which are related to fields in Norway. The Snøhvit, Troll and Tyrihans fields, with continuous development activities, represent the largest undeveloped assets in Norway together with fields not yet in production, such as Skarv, Gudrun, Goliat and Valemon. The positive change in total proved undeveloped reserves for Norway in 2011 is linked to inclusion of the new developments sanctioned in 2011, with Skuld and Hild being the most important. Moreover, significant positive revisions for our NCS producing fields have increased both the developed and undeveloped proved reserves. The largest assets with respect to undeveloped proved reserves outside Norway are Peregrino in Brazil and Petrocdeño in Venezuela, together with the US onshore developments in Bakken, Marcellus and Eagle Ford. The increase in proved undeveloped reserves outside Norway in 2011 is partially due to the inclusion of the Bakken reserves, but also to an increase for other onshore developments in this region as a consequence of drilling progress during the year.
In 2011, Statoil incurred NOK 70 billion in development costs relating to assets carrying proved reserves, NOK 51 billion of which was related to moving proved undeveloped reserves to developed reserves.
Due to the nature of large fields with continuous development activity, such as Heidrun, Oseberg, Snøhvit and Troll in Norway, Azeri-Chirag-Gunashli in Azerbaijan, Leismer oil sands in Canada (SAGD) and Petrocedeño in Venezuela, these fields contain reserves that are expected to remain undeveloped for five years or more. All these projects are large field developments, five of them offshore, with several billion dollar investments having been made in complex infrastructure. The development of these fields will require extensive, sustained drilling of wells for a long period of time. A large proportion of the central facilities are already in place, and a significant part of the total investments have been made. It is highly unlikely that these field development projects will be prematurely terminated, since this would result in a significant loss of capital. One of our fields with undeveloped proved reserves, the Corrib gas development in Ireland (operated by Shell), has been under development for more than five years. Most of the offshore and onshore facilities are in place. Construction of the final pipeline section has now commenced and the field is anticipated to start production in 2014.
Additional information about proved oil and gas reserves is provided in note 33 - Supplementary oil and gas information - to our consolidated financial statements.
Statoil's annual reporting process for proved reserves is coordinated by a central team of experts.
The Corporate Reserves Management (CRM) team consists of experts in geosciences, reservoir and production technology and financial evaluation. The team has an average of more than 20 years' experience in the oil and gas industry. CRM reports to the senior vice president of finance and control in the Technology, Drilling and Projects business area and is thus independent of the Development & Production business areas in Norway, North America and International. All the reserves estimates have been prepared by our own technical staff, with the exception of the 2011 proved reserves in the Bakken asset representing 2.3% of our total proved reserves, which have been prepared by the external petroleum engineering consultants Cawley, Gillespie & Associates, Inc. (CG&A). A report summarising CG&A's evaluation is included as Exhibit 15 (a)(v).
Although the CRM team reviews the information centrally, each asset team is responsible for ensuring that it is in compliance with the requirements of the SEC and our corporate standards. Information about proved oil and gas reserves, standardised measures of discounted net cash flows related to proved oil and gas reserves and other information related to proved oil and gas reserves, is collected from the local asset teams and checked for consistency and conformity with applicable standards by CRM. The final numbers for each asset are quality controlled and signed off by the responsible asset manager, before aggregation to the required reporting level by CRM.
The aggregated results are submitted for approval to the relevant business area management teams and the corporate executive committee and finally presented to the board's audit committee.
The person with primary responsibility for overseeing the preparation of the reserves estimates is the chair of the CRM team. The person who presently holds this position has a Bachelor's degree in Earth Sciences from the University of Gothenburg, and a Master's degree in Petroleum Exploration and Exploitation from Chalmers University of Technology in Gothenburg, Sweden. She has 26 years' experience in the oil and gas industry, 25 of them with Statoil. She is a member of the Norwegian Petroleum Society and vice-chair of the UNECE Expert Group on Resource Classification (EGRC).
DeGolyer and MacNaughton report
A reserves audit report summarising this evaluation is included as Exhibit 15 (a)(iii).
Operational statistics include information about acreage and the number of wells drilled.
Productive oil and gas wells and developed and undeveloped acreage
A gross value reflects wells or acreage in which we have interests (presented as 100%). The net value corresponds to the sum of the whole or fractional working interest for Statoil in gross wells or acreage.
The total gross number of productive wells at the end of 2011 includes 383 oil wells and 20 gas wells with multiple completions or wells with more than one branch.
The largest concentrations of developed acreage in Norway are in Troll, Ormen Lange, Snøhvit and Oseberg areas. In Africa, the Algerian gas development projects In Amenas and In Salah represent the largest concentrations of developed acreage (gross and net).
Our largest undeveloped acreage concentration in Eurasia excluding Norway is now in Indonesia with some 57% of the total of this geographical area. In 2011 we acquired six new licenses in Indonesia, with Halmahera II representing the largest acreage. Our largest acreage concentration in Africa is the Hassi Mouina blocks in Algeria representing about one-third of the total net acreage in Africa.
After the acquisition of Brigham Exploration Company (Bakken), together with the acreage in the Marcellus and Eagle Ford plays, most of our developed and undeveloped acreage in the Americas is now located onshore USA, some 25% of our net acreages in Americas. Also the offshore acreage in Gulf of Mexico represents a large share of the undeveloped acreage with some 20% of our net acreages in Americas. Significant parts of our acreage in this region are also related to the Camamu-Almada Basin off the coast of Brazil, the oil sands areas located in the Athabasca region of Alberta, Canada, and our licences off the coast of Newfoundland, Canada.
Net productive and dry oil and gas wells drilled
In connection with our oil sands development in the Athabasca region of Alberta, we also drilled 62 wells in 2011 to map and delineate the bitumen pay. All of these wells were logged and 44 wells were cored.
Exploratory and development drilling in process
A stable level of long-term commitments for contract years 2011-2014.
On behalf of the Norwegian State's direct financial interest (SFDI), Statoil is responsible for managing, transporting and selling the Norwegian State's oil and gas from the Norwegian continental shelf (NCS). These reserves are sold in conjunction with our own reserves. As part of this arrangement, Statoil will deliver gas to customers under various types of sales contracts. In order to fulfil the commitments, we will utilise a field supply schedule that ensures the highest possible total value for Statoil and SDFI's joint portfolio of oil and gas.
The majority of our gas volumes in Norway are sold under long-term contracts with take-or-pay clauses. Statoil's and SDFI's annual delivery commitments under these agreements are expressed as the sum of the annual contract quantities (ACQ). As of 31 December 2011, the long-term commitments from NCS for the Statoil/SDFI arrangement amounted to a total of approximately 24 tcf (675 bcm).
In the contract years 2011 to 2014, the total ACQ for the respective years are: 2.23, 2.27, 2.30 and 2.30 tcf (63.2, 64.3, 65.2 and 65.1 bcm) per year. Our currently developed gas reserves in Norway are more than sufficient to meet our share of these commitments for the next three years.
The principal legislation governing our petroleum activities in Norway is the Norwegian Petroleum Act and the Norwegian Petroleum Taxation Act.
The principal legislation governing our petroleum activities in Norway and on the NCS is currently the Norwegian Petroleum Act of 29 November 1996 (the "Petroleum Act") and the regulations issued thereunder, and the Norwegian Petroleum Taxation Act of 13 June 1975 (the "Petroleum Taxation Act"). The Petroleum Act sets out the principle that the Norwegian State is the owner of all subsea petroleum on the NCS, that exclusive right to resource management is vested in the Norwegian State and that the Norwegian State alone is authorised to award licences for petroleum activities. We are dependent on the Norwegian State for approval of our NCS exploration and development projects and our applications for production rates for individual fields.
Under the Petroleum Act, the Norwegian Ministry of Petroleum and Energy is responsible for resource management and for administering petroleum activities on the NCS. The main task of the Ministry of Petroleum and Energy is to ensure that petroleum activities are conducted in accordance with the applicable legislation, the policies adopted by the Norwegian parliament, the Storting, and relevant decisions of the Norwegian State. The Ministry of Petroleum and Energy primarily implements petroleum policy through its powers to administer the awarding of licences and to approve operators' field and pipeline development plans. Only plans that comply with the policies and regulations adopted by the Storting are approved. As set out in the Petroleum Act, if a plan involves an important principle or will have a significant economic or social impact, it must also be submitted to the Storting for acceptance before being approved by the Ministry of Petroleum and Energy.
We are not required to submit any decisions relating to our operations to the Storting. However, the Storting's role in relation to major policy issues in the petroleum sector can affect us in two ways: firstly, when the Norwegian State acts in its capacity as majority owner of our shares and, secondly, when the Norwegian State acts in its capacity as regulator:
Although Norway is not a member of the European Union (EU), it is a member of the European Free Trade Association (EFTA). The EU and the EFTA Member States have entered into the Agreement on the European Economic Area, referred to as the EEA Agreement, which provides for the inclusion of EU legislation covering the four freedoms - the free movement of goods, services, persons and capital - in the national law of the EFTA Member States (except Switzerland). An increasing volume of regulation affecting us is adopted in the EU and then applied to Norway under the EEA Agreement. As a Norwegian company operating both within EFTA and the EU, our business activities are subject to both the EFTA Convention governing intra-EFTA trade and EU laws and regulations adopted pursuant to the EEA Agreement.
Production licences are the most important type of licence awarded under the Petroleum Act, and the Norwegian Ministry of Petroleum and Energy has executive discretionary power to award and set the terms for production licences.
As a participant in licences, we are subject to the regulations of the Norwegian licensing system. For an overview of our activities and shares in our production licences, see Operational review - Development and Production Norway.
Production licences are the most important type of licence awarded under the Petroleum Act, and the Ministry of Petroleum and Energy has executive discretionary powers to award a production licence and to decide the terms of that licence. The Norwegian Government is not entitled to award us a licence in an area until the Storting has decided to open the area in question for exploration. The terms of our production licences are decided by the Ministry of Petroleum and Energy.
A production licence grants the holder an exclusive right to explore for and produce petroleum within a specified geographical area. The licensees become the owners of the petroleum produced from the field covered by the licence. Notwithstanding the exclusive rights granted under a production licence, the Ministry of Petroleum and Energy has the power, in exceptional cases, to permit third parties to carry out exploration in the area covered by a production licence.
Production licences are normally awarded in licensing rounds. The first licensing round for NCS production licences was announced in 1965. The award of the first licences covered areas in the North Sea. Over the years, the awarding of licences has moved northward to cover areas in both the Norwegian Sea and the Barents Sea. In recent years, the principal licensing rounds have largely concerned licences in the Norwegian Sea. However, in the future, we expect an increase in licencing rounds concerning licences in the Barents sea.
The Norwegian State accepts licence applications from individual companies and group applications. This allows us to choose our exploration and development partners.
Production licences are awarded to joint ventures. As is the case for most fields on the NCS, our production activities are conducted through joint venture arrangements with other companies and, in some cases, with the Norwegian State through its wholly-owned company Petoro AS. The members of the joint venture are jointly and severally responsible to the Norwegian State for obligations arising from petroleum operations carried out under the licence. Once a production licence is awarded, the licensees are required to enter into a joint operating agreement and an accounting agreement regualting the relationship between the partners. The Ministry of Petroleum and Energy decides the form of the joint operating agreements and accounting agreements.
The governing body of the joint venture is the management committee. In licences awarded since 1996 where the State's Direct Financial Interest (SDFI) holds an interest, the Norwegian State, acting through Petoro AS, may veto decisions made by the joint venture management committee, which, in the opinion of the Norwegian State, would not be in compliance with the obligations of the licence with respect to the Norwegian State's exploitation policies or financial interests. This veto power has never been used.
The day-to-day management of a field is the responsibility of an operator appointed by the Ministry of Petroleum and Energy. The operator is in practice always a member of the joint venture holding the production licence, although this is not legally required. The terms of engagement of the operator are set out in the joint operating agreement, under which the operator can normally terminate its engagement by giving six months' notice. However, with the consent of the Ministry of Petroleum and Energy, the management committee may instruct the operator to continue to perform its duties until a new operator has been appointed. The management committee can terminate the operator's engagement by giving six months' notice through an affirmative vote by all members of the management committee other than the operator. A change of operator requires the consent of the Ministry of Petroleum and Energy. In special cases, the Ministry of Petroleum and Energy can order a change of operator.
Licensees are required to submit a plan for development and operation (PDO) to the Ministry of Petroleum and Energy for approval. For fields of a certain size, the Storting has to accept the PDO before it is formally approved by the Ministry of Petroleum and Energy. Until the PDO has been approved by the Ministry of Petroleum and Energy, the licensees cannot undertake material contractual obligations or commence construction work without the prior consent of the Ministry of Petroleum and Energy.
Production licences are normally awarded for an initial exploration period, which is typically six years, but which can be shorter. The maximum period is ten years. During this exploration period, the licensees must meet a specified work obligation set out in the licence. The work obligation will typically include seismic surveying and/or exploration drilling. If the licensees fulfil the obligations set out in the production licence, they are entitled to require that the licence be prolonged for a period specified at the time when the licence is awarded, typically 30 years. As a rule, the right to prolong a licence does not apply to the whole of the geographical area covered by the initial licence, but only to a percentage of the area, typically 50%. The size of the area that must be relinquished is determined at the time the licence is awarded. In special cases, the Ministry of Petroleum and Energy may extend the duration of a production licence.
If natural resources other than petroleum are discovered in the area covered by a production licence, the Norwegian State may decide to delay petroleum production in the area. If such a delay is imposed, the licensees are, with certain exceptions, entitled to a corresponding extension of the licence period. To date, such a delay has never been imposed.
If important public interests are at stake, the Norwegian State may instruct us and other licensees on the NCS to reduce the production of petroleum. The last time the Norwegian State instructed a reduction in oil production was in 2002.
Licensees may buy or sell interests in production licences subject to the consent of the Ministry of Petroleum and Energy and the approval of the Ministry of Finance of a corresponding tax treatment position. The Ministry of Petroleum and Energy must also approve indirect transfers of interests in a licence, including changes in the ownership of a licensee, if they result in a third party obtaining a decisive influence over the licensee. In most licences, there are no pre-emption rights in favour of the other licensees. However, the SDFI, or the Norwegian State, as appropriate, still holds pre-emption rights in all licences.
A licence from the Ministry of Petroleum and Energy is also required in order to establish facilities for the transportation and utilisation of petroleum. When applying for such licences, the owners, who in practice are licensees under a production licence, must prepare a plan for installation and operation. Licences for the establishment of facilities for the transportation and utilisation of petroleum will normally be awarded subject to certain conditions. Typically, these conditions require the facility owners to enter into a participants' agreement. Ownership of most facilities for the transportation and utilisation of petroleum in Norway and on the NCS is organised in the form of joint ventures of a group of licence holders. The participants' agreements are similar to the joint operating agreements.
Licensees are required to prepare a decommissioning plan before a production licence or a licence to establish and use facilities for the transportation and utilisation of petroleum expires or is relinquished, or the use of a facility ceases. The decommissioning plan must be submitted to the Ministry of Petroleum and Energy no sooner than five years and no later than two years prior to the expiry of the licence or cessation of use of the facility, and it must include a proposal for the disposal of facilities on the field. On the basis of the decommissioning plan, the Ministry of Petroleum and Energy makes a decision as to the disposal of the facilities.
The Norwegian State is entitled to take over the fixed facilities of the licensees when a production licence expires, is relinquished or revoked. In respect of facilities on the NCS, the Norwegian State decides whether any compensation will be payable for facilities thus taken over. If the Norwegian State should choose to take over onshore facilities, the ordinary rules of compensation in connection with the expropriation of private property apply.
Licences for the establishment of facilities for the transportation and utilisation of petroleum typically include a clause whereby the Norwegian State can require that the facilities be transferred to it free of charge on expiry of the licence period.
We market gas from the NCS on our own behalf and on the Norwegian State's behalf. Gas is transported through the Gassled pipeline network to customers in the UK and mainland Europe.
Most of our and the Norwegian State's gas produced on the NCS is sold under long-term gas contracts to customers in the European Union (EU). The EU internal energy market has been high on the European Commission's agenda, and this market has thus been subject to continuous legislative initiatives. Such changes in EU legislation may affect Statoil's marketing of gas. In 2009, the European Commission issued a third legislative package for an internal EU gas and electricity market. It has yet to be fully implemented in the EU Member States' national laws, however.
The Norwegian gas transport system, that is to say the pipelines and the terminals through which all licensees on the NCS transport their gas, is owned by a joint venture, Gassled. The joint ownership structure is intended to ensure the effectiveness of the system and to prevent conflicts of interest. The Norwegian Petroleum Act of 29 November 1996 establishes the basis for non-discriminatory third-party access to the Gassled transport system. The pertaining Petroleum Regulations set out the objective and non-discriminatory provisions for access to available capacity. The access regime provided for therein consists of a regulated primary market where the right to book spare capacity is allocated to users with a need to transport natural gas. The access regime also allows for a secondary market where capacity can be transferred between users after allocation in the primary market if transportation needs have changed after the initial booking.
To further ensure neutrality, the petroleum regulations stipulate that all booking and allocation of capacity is based on standard procedures and administrated by an independent system operator, Gassco AS, a company wholly owned by the Norwegian State. Spare capacity is released for pre-defined time periods at announced points in time and with specific time limits within which bookings must be placed with the operator online. If the total of the bookings exceeds the spare capacity, the spare capacity is allocated to the shippers of gas by applying an allocation formula. If there is no available capacity in the booking system and some of the reserved capacity is not utilised, Gassco may make the unutilised capacity available to other shippers on an interruptible basis.
The tariffs for use of capacity in the transport system are determined by applying a formula set out in separate tariff regulations stipulated by the Ministry of Petroleum and Energy. The Ministry's main objective when setting the tariffs is to ensure that the profits are extracted in the production fields on the NCS and not in the transport system. The tariffs are paid on the basis of booked capacity, not on the basis of the volumes actually transported.
For further information, see Operational Review - Marketing, Processing and Renewable Energy - Natural Gas - Norway's gas transport system.
Our petroleum operations are subject to extensive laws and regulations relating to health, safety and the environment (HSE).
Following the incident that occurred on the BP-operated Macondo well in the deepwater Gulf of Mexico, USA, in April 2010, the Norwegian Ministry of Petroleum and Energy announced that the incident could result in changes to laws and regulations concerning activities on the NCS. After a review of the regulations, no changes were imposed.
However, on 27 October 2011, the European Commission proposed a new offshore safety regulation with the objective of reducing the risk of a major incident in European Union (EU) waters and limiting the consequences should such an incident occur. The draft regulation is now subject to a consultation procedure among the EU Member States, which is not expected to conclude until late 2012. If enforced in the EU and subsequently adopted in the European Economic Area (EEA) of which Norway is part, the regulation would apply to our activities on the NCS. The effects, if any, of it are not possible to foresee until the legislative process is finalised.
In 2001, Statoil established a system for monitoring the technical safety of its facilities and plants. As part of this system, it collects and interprets information from, and incorporates risk management into, its operating activities.
The Petroleum Safety Authority Norway has the regulatory responsibility for safety, emergency preparedness and the working environment for all offshore and onshore petroleum-related activities in Norway. Following the Macondo incident, permission from the Petroleum Safety Authority Norway to start drilling a new well is now dependent on the applicant's ability to handle a potential blow-out, and the applicant must demonstrate the actions it would undertake to shut down the affected well.
We are required at all times to have a plan to deal with emergency situations in our petroleum operations. During an emergency, the Norwegian Ministry of Labour/ Norwegian Ministry of Fisheries and Coastal Affairs/Norwegian Coastal Administration may decide that other parties should provide the necessary resources, or otherwise adopt measures to obtain the necessary resources, to deal with the emergency for the licensees' account.
In our capacity as holder of licences under the Petroleum Act, we are subject to strict statutory liability in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licences. This means that anyone who suffers damage or loss as a result of pollution from any of our NCS licence areas can claim compensation from us regardless of whether the claimant can demonstrate fault on our part. If the pollution is caused by a force majeure event, a Norwegian court may reduce the damages to a level it considers reasonable.
In addition, current and proposed fuel and product specifications, emission controls and climate change programmes under a number of environmental laws could have a significant effect on the production, sale and profitability of many of our products. There are also environmental laws that require us to remediate and restore areas damaged by the accidental or unauthorised release of hazardous materials or petroleum associated with our operations. These laws may apply to sites that Statoil currently owns or operates, sites that it or its prdecessors' previously owned or operated or sites used for the disposal of its and other parties' waste.
We anticipate that the HSE laws and regulations to which we are subject, both in Norway and around the world, are likely to have an increasing impact on our operations. It is difficult, however, to accurately predict the effects of future legislative developments in this regard on our future earnings and operations. Some risk of HSE costs and liabilities is inherent in our activities, which is also the case for our peers in the industry. We cannot guarantee that material costs and liabilities will not be incurred; however, we do not currently expect any material adverse effects on our financial position or results of operations relating to compliance with such laws and regulations.
We are subject to ordinary Norwegian corporate income tax and to a special petroleum tax relating to our activities offshore Norway. Our NCS activities are also subject to a special carbon dioxide emissions tax and a nitrogen oxide tax in Norway.
Under our production licences, we are obliged to pay an area fee to the Norwegian State. Below is a summary of certain key aspects of the Norwegian tax rules that apply to our operations.
Corporate income tax
The maximum rate of depreciation of development costs related to offshore production installations and pipelines is 16.67% per year. Depreciation starts when the cost is incurred. Exploration costs may be deducted in the year in which they are incurred. Financial costs related to the offshore activity are calculated directly based on a formula set out in the Petroleum Tax Act. The financial costs deductible under the offshore tax regime are the total financial costs multiplied by 50% of tax values divided by the average interest-bearing debt. All other financial costs and income are allocated to the onshore tax regime.
Any tax losses can be carried forward indefinitely against subsequent income earned. Fifty per cent of losses relating to activity conducted onshore in Norway can be deducted from NCS income subject to the 28% tax rate. Losses on foreign activities cannot be deducted from NCS income. Losses on offshore activities are fully deductible from onshore income.
By using group contributions between Norwegian companies in which we hold more than 90% of the shares and votes, tax losses and taxable income can be offset to a great extent. Group distributions are not deductible from our offshore income.
Dividends received are subject to tax in Norway. The basis for taxation is 3% of the dividend received, which is subject to the standard 28% income tax rate. Dividends from low-tax countries or portfolio investments outside the EEA will, under certain circumstances, be subject to the standard 28% income tax rate based on the full amounts received.
Capital gains from the realisation of shares are taxable. The basis for taxation is 3% of the gain, which is subject to the standard 28% income tax. Capital losses from the realisation of shares are not deductible. Exceptions apply to shares held in companies domiciled in low-tax countries or portfolio investments outside the EEA, where, under certain circumstances, capital gains will be subject to the standard 28% income tax rate and capital losses will be deductible.
Special petroleum tax
Carbon dioxide emissions tax
Nitrogen oxide emissions tax
As an alternative to paying the nitrogen oxide tax, companies can voluntarily agree to contribute to an industry nitrogen oxide fund. A fund agreement has been signed for the years 2011-2017. The contribution to the fund is NOK 11 per kilogram of nitrogen oxide emissions. We have entered into an agreement to contribute to the fund.
Taxation outside Norway
Generally, income from Statoil's upstream production outside Norway is subject to tax at the higher of the Norwegian onshore rate (28%) or the prevailing tax rate in the countries in which it operates. Statoil is subject to excess (or "windfall") profit tax in some of the countries in which it produces crude oil.
Production sharing agreements (PSA)
Income tax regimes
The Norwegian State's policy as a shareholder in Statoil has been and continues to be to ensure that petroleum activities create the highest possible value for the Norwegian State.
Initially, the Norwegian State's participation in petroleum operations was largely organised through Statoil. In 1985, the Norwegian State established the State's Direct Financial Interest (SDFI) through which the Norwegian State has direct participating interests in licences and petroleum facilities on the NCS. As a result, the Norwegian State holds interests in a number of licences and petroleum facilities in which we also hold interests. Petoro AS, a company wholly owned by the Norwegian State, was formed in 2001 to manage the SDFI assets.
We market and sell the Norwegian State's oil and gas as part of our own production. The Norwegian State has chosen to implement this arrangement.
Accordingly, at an extraordinary general meeting held on 27 February 2001, the Norwegian State, as sole shareholder, revised our articles of association by adding a new article that requires us to continue to market and sell the Norwegian State's oil and gas together with our own oil and gas in accordance with an instruction established in shareholder resolutions in effect from time to time. At an extraordinary general meeting held on 25 May 2001, the Norwegian State, as sole shareholder, approved a resolution containing the instruction referred to in the new article. This resolution is referred to as the owner's instruction.
The Norwegian State has a coordinated ownership strategy aimed at maximising the aggregate value of its ownership interests in Statoil and the Norwegian State's oil and gas. This is reflected in the owner's instruction to Statoil. It contains a general requirement that, in our activities on the NCS, we must take account of these ownership interests in decisions that could affect the execution of this marketing arrangement.
The owner's instruction sets out specific terms for the marketing and sale of the Norwegian State's oil and gas. The principal provisions of the owner's instruction are set out below.
The Norwegian State's oil and NGL is lifted together with our oil and NGL in accordance with applicable lifting procedures for each individual field and terminal.
Withdrawal or amendment
There is intense competition in the oil and gas industry for customers, production licences, operatorships, capital and experienced human resources.
Statoil competes with large integrated oil and gas companies, as well as with independent and state-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. Oil and gas prices and demand, exploration and production costs, global production levels, alternative fuels, and government - including environmental - regulations are key factors affecting competition in the oil and gas industry.
Statoil's ability to remain competitive will depend, among other things, on its management continuing to focus on reducing unit costs and improving efficiency, maintaining long-term growth in our reserves and production through continuing technological innovation. It will also depend on our ability to seize international opportunities in areas where our competitors may also be actively pursuing exploration and development opportunities. We believe that we are in a position to compete effectively in each of our business segments.
We have interests in real estate in many countries throughout the world, but no one individual property is significant to us as a whole.
Our head office, which is located at Forusbeen 50, N-4035, Stavanger, Norway, comprises approximately 135,000 square metres of office space and is owned by Statoil.
During 2011, Statoil's new 65,500-square-metre office building located on the outskirts of Norway's capital Oslo was under construction in accordance with the long-term lease agreement signed in 2010 between Statoil as tenant and IT-Fornebu AS as owner. The new office will provide an environmentally friendly workplace for up to 2,500 employees. The building will be made available to Statoil by 1 September 2012 at the latest, and the move to the new offices is planned to be completed in mid-October 2012.
For a description of our significant reserves and sources of oil and natural gas, see note 33 - Supplementary oil and gas information in the consolidated financial statements in this report.
We have the following transactions with related parties.
Transactions with the Norwegian State
Transactions with other entities in which the Norwegian State is a major shareholder
Other transactions with the Norwegian State
The significant amounts included under the item Payables to equity accounted investments and other related parties in note 25 Trade and other payables to the financial statements, are amounts payable to the Norwegian State for these purchases. The prices paid by Statoil for the oil purchased from the Norwegian State are estimated at market prices. In addition, Statoil sells the Norwegian State's natural gas in its own name, but for the account and risk of the Norwegian State.
The Norwegian State compensates Statoil for its relative share of the costs related to certain Statoil natural gas storage and terminal investments and related activities. See the section Operational review- Applicable laws and regulations-SDFI oil & gas marketing & sale, for more details.
Although the Norwegian State is Statoil's majority owner, Statoil is not given preferential treatment with respect to licences granted by the Norwegian State or under any other regulatory rules enforced by the Norwegian State.
Members of the corporate executive committee and the board of directors may not take up loans under the current programme. None of the three employee-elected members of the board of directors and none of members of the corporate executive committee had any balances outstanding under this arrangement as of 12 March 2012.
Employees at certain levels are entitled to an interest-free car loan from the company. Members of the corporate executive committee and employee-elected members of the board are generally excluded from this arrangement, and none of them had any balances outstanding as of 12 March 2012.
Family members of corporate executive committee members or directors, who are also employees of Statoil, may participate in the employee loan and/or car loan programmes and may have balances outstanding.
Statoil's corporate assembly includes six employee representatives and three employee observers who, as part of their remuneration, may have balances outstanding under the company's employee loan and/or car loan programmes.
Other related party transactions
Among other things, Statoil takes out insurance policies for physical loss of or damage to our oil and gas properties, liability to third parties, workers' compensation and employer's liability, general liability, pollution and well control.
Our insurance policies are subject to:
Our well control policy, which covers costs relating to well control incidents (including pollution and clean-up costs), is subject to a gross limit per incident. The gross limits for our two most significant geographical areas, the NCS and the Gulf of Mexico (GoM), USA, are:
The limits assume a 100% ownership interest in a given well and would be scaled to be equivalent to our percentage ownership interest in a given well. Our SIR for well control policies varies between NOK 7.6 million and NOK 100 million per loss on the NCS depending on our percentage ownership interest in the well and certain other factors. Our SIR in the GoM would be approximately USD 10 million (approximately NOK 60 million) per incident assuming 100% ownership. In addition to the well control insurance programmes, we have in place a third-party liability insurance programme with a gross limit of USD 800 million (approximately NOK 4,800 million) per incident. The SIR is insignificant (maximum NOK 6 million).
We have a variety of other insurance policies related to other projects worldwide for which we have limited SIR.
There is no guarantee that our insurances will adequately protect us against liability for all potential consequences or damages.
Statoil's overall strategic objective is to build a globally competitive company and an exceptional place to perform and develop.
During the last few years, Statoil has expanded into new business activities, both geographically and into emerging technologies, such as deepwaters, heavy oil and shale gas. In order to succeed in these activities, we must have the right organisational and people capabilities, as well as the ability to attract new talents globally.
Through global people policies, Statoil aims to ensure consistent common standards across the organisation. Together with our values and ethics code of conduct, our people policies are the most important guidelines for the people processes. We endeavour to ensure a good match between the professional interests and goals of every employee and the needs of the business. Through our global development and deployment process, we endeavour to offer challenging and meaningful job opportunities. Statoil remains committed to providing financial and non-financial rewards that attract and motivate the right people, and it continues to focus on equal opportunities for all employees.
Through the Statoil 2011 reorganisation, effective from 1 January 2011, Statoil has accelerated the development of new leaders, and significantly expanded the proportion of female and international leaders.
The Statoil group employs approximately 32,000 employees. Of these were approximately 10,400 employees within the Statoil Fuel & Retail group, of which we held a 54% majority ownership interest as of 31 December 2011. Approximately 20,000 of Statoil group's employees are employed in Norway and approximately 12,000 outside Norway.
Statoil works systematically with recruitment and development programmes in order to build a diverse workforce by attracting, recruiting and retaining people of both genders and different nationalities and age groups across all types of positions. In 2011, Statoil recruited 1,900 new employees worldwide. While 70% were recruited to jobs in Norway, 18% were recruited to our business in North America, reflecting our growth ambitions in that region. In 2011, 43% of our new hires were women and 65% other nationalities than Norwegian.
We believe Statoil's low turnover rates reflect a high level of satisfaction and engagement among its employees, which is also supported by the results of the annual organisational and working environment survey. In Statoil ASA, the total turnover rate for 2011 was 1.4%. The figure opposite provides an overview of the total turnover rate by gender and age in Statoil ASA from 2009 to 2011 (number excluding the reporting segment SFR).
We are committed to building a workplace that promotes diversity and inclusion through its people processes and practices.
At 31 December 2011, the overall percentage of women in the company was 37%, and 40% of the board of directors were women, and 20% of the corporate executive team were women. The focus on diversity issues is also reflected in the company's people strategy. We aim to increase the number of female managers, and we endeavour to give equal representation to men and women in leadership development programmes. At the end of December 2011, the total proportion of female managers in Statoil was 31%, and, among managers under the age of 45, the proportion was 32% (number excluding the reporting segment SFR).
We also devote close attention to male-dominated positions and discipline areas. In 2011, 26% of staff engineers were women, and among staff engineers with up to 20 years' experience, the proportion of women was 30 %.
The reward system in Statoil is non-discriminatory and supports equal opportunities, which means that, given the same position, experience and performance, men and women will be at the same salary level. However, due to differences between women and men in types of positions and number of years' experience, there are some differences in compensation when comparing the general pay levels of men and women.
Statoil's cooperation with employee representatives and trade unions is based on confidence, trust and continuous dialogue between management and the people in various cooperative bodies.
In Statoil, 68% of the employees in the parent company are members of a trade union. Work councils and working environment committees are established where required by law or agreement. Town hall meetings are also used for information and consultations in accordance with requirements and usage in each country.
In Norway, the formal basis for collaboration with labour unions is established in the Basic Agreements between the Confederation of Norwegian Enterprise (NHO) and the five Statoil unions.
During 2011, management and employee representatives have collaborated closely in important processes such as the evaluation of the offshore operations model and measures to follow up safety incidents on the NCS. In these processes we believe that we have endeavoured to engage in open and honest communication both inside and outside formal meeting arenas.
Statoil delivered strong financial results and cash flows in 2011. Production was lower than 2010 but in line with expectations and important strategic progress was made. Discoveries were made in 22 out of 41 exploration wells.
Net operating income was up by 54% compared with 2010. Net operating income in 2011 was positively impacted by higher prices for both liquids and gas, unrealised gains on derivatives, gains on sale of assets mainly related to the reduction of interests in Peregrino, the Kai Kos Dehseh oil sands and Gassled. Reduced net impairment losses also added to the increase in net operating income. Lower volumes of both liquids and gas sold and increased operating expenses partly offset the increase in net operating income.
Strategic portfolio optimisation in 2011 included the sale of interests in Peregrino and Kai Kos Dehseh oil sands, the Gassled divestment and the Brigham acquisition. The NCS portfolio was further streamlined through a farm down agreement of assets with Centrica, which is expected to be closed in the second quarter of 2012.
Statoil achieved a reserve replacement ratio (RRR) of 1.17 in 2011, of which the organic RRR was above 1.0. The RRR for oil was 1.45, including the effect of sales and purchases.
The board of directors is proposing a dividend of NOK 6.50 per share for 2011.
As stated in note 2 Significant accounting policies, Statoil changed its policy for accounting for jointly controlled entities under IAS 31 Interests in Joint Ventures, from the application of the equity method to the proportionate consolidation method with effect from 2011. Proportionate consolidation has been retrospectively applied in the consolidated financial statements, and the years ended 31 December 2010 and 2009 have been restated accordingly.
Statoil delivered strong financial results and strong cash flows in 2011, despite reduced production and increased operating expenses.
In 2011, Statoil delivered total entitlement liquids and gas production of 1,650 mboe per day, down 3% from 1,705 mboe per day in 2010. Total equity liquids and gas production decreased by 2% from 2010, to 1,850 mboe per day in 2011, mainly caused by reduced water injection at Gullfaks, challenges primarily related to risers, maintenance shut downs and deferral of gas sales. In addition, expected reductions due to natural decline on mature fields and suspended production in Libya contributed to the decrease. This decrease was partly offset by production from start-up of new fields, ramp-up of production on existing fields and increased ownership shares.
Despite reduced production, net operating income was up 54% at NOK 211.8 billion in 2011, compared to NOK 137.3 billion in 2010. The increase was mainly attributable to higher prices for both liquids and gas, reduced net impairment losses, unrealised gains on derivatives and gains on sale of assets mainly related to the sale of interests in Peregrino, the Kai Kos Dehseh oil sands and Gassled in 2011. Lower volumes of both liquids and gas sold, increased operating expenses and net impairment losses partly offset the increase in net operating income.
Statoil's exploration programme for 2011 totalled 41 exploration wells completed before 31 December 2011. Sixteen of them were drilled outside the Norwegian continental shelf (NCS). A total of 22 wells were announced as discoveries during 2011. Seventeen of them are located on the NCS.
In 2011, 599 mmboe of proved reserves were added through revisions, extensions and discoveries, compared to additions of 526 mmboe in 2010, also through revisions, extensions and discoveries.
Statoil achieved a reserve replacement ratio of 117% in 2011, compared to 87% in 2010. The increase in 2011 is related to positive revisions of the proved reserves in several of our producing fields, newly sanctioned field development and increased recovery projects, several new wells in production in the Marcellus and the Eagle Ford shale gas acreage and purchase of the Bakken oil play in North America.
Statoil progressed two new projects into production in 2011: the Peregrino field in Brazil and the Pazflor field in Angola both came on stream.
Sales volumes include our lifted entitlement volumes, the sale of SDFI volumes and our marketing of third-party volumes.
We take part in the production of oil and natural gas volumes, and incur capital expenditures and operating expenses on the basis of such equity volumes. Under certain production-sharing agreements (PSAs), a portion of the equity production is distributed to the relevant government before arriving at the volumes that we are ultimately entitled to sell (entitlement volumes). The timing of our lifting of our share of entitlement volumes may cause there to be a difference at any given time between our share of entitlement volumes and the volumes lifted. This difference is called overlift if we have lifted more than our share of the entitlement production, and underlift if our cumulative lifting is less than our share of the entitlement volumes. The lifted volumes and volumes in inventory are the basis for what we can sell to third parties. Revenues are based on lifted volumes.
In addition to our own volumes of lifted entitlement production and production in storage, we market and sell oil and gas owned by the Norwegian state through the Norwegian state's share in production licences. This is known as the State's Direct Financial Interest, or SDFI. For additional information, see the section Operational review - Applicable laws and regulations- SDFI oil & gas marketing & sale. The following table shows SDFI and Statoil sales volume information for crude oil and natural gas, as applicable, for the periods indicated. The Statoil natural gas sales volumes include equity volumes sold by the segment MPR, natural gas volumes sold by the segment DPI and ethane volumes.
For more information on the differences between equity and entitlement production, sales volumes and lifted volumes, see the section Financial analysis and review - Operating and financial review 2011 - Definitions of reported volumes.
Net operating income was NOK 211.8 billion in 2011, a 54% increase compared to 2010 mainly due to higher prices, reduced net impairment losses, unrealised gains on derivatives and gains on sale of assets.
Total revenues and other income amounted to NOK 670.2 billion in 2011 compared to NOK 529.9 billion in 2010 and NOK 465.4 billion in 2009. Most of the revenues stem from the sale of lifted crude oil, natural gas and refined products produced and marketed by Statoil. In addition, we also market and sell the Norwegian State's share of liquids from the NCS. All purchases and sales of the Norwegian State's production of liquids are recorded as purchases net of inventory variations and sales, respectively, while sales of the Norwegian State's share of gas from the NCS are recorded net.
The NOK 118.6 billion increase in revenues from 2010 to 2011 was mainly attributable to higher prices for both liquids and gas, partly offset by lower volumes of both liquids and gas sold. The variance on unrealised net gains on derivatives contributed NOK 12.0 billion to the increase in revenues between the years. Average prices of liquids measured in NOK increased by 28% from 2010 to 2011, contributing NOK 43.2 billion to the increase in revenues, while average gas prices measured in NOK increased by 21%, contributing NOK 18.3 billion. The increase was partly offset by a 6% decrease in liftings of liquids and a 4% decrease in total liftings of gas, with off-setting effects of NOK 9.9 billion and NOK 4.1 billion, respectively.
The NOK 64.5 billion increase in revenues from 2009 to 2010 was mainly attributable to higher prices for liquids and increased volumes of gas sold, partly offset by lower gas prices, reduced volumes of liquids sold and losses on derivatives. Realised prices of liquids measured in NOK increased by 27% from 2009 to 2010, contributing NOK 34.6 billion to the increase in revenues, while increased volumes of gas sold contributed NOK 5.9 billion to the increase in revenues. The increase was partly offset by a 7% decrease in liftings of liquids with a negative contribution of NOK 10.1 billion, while gas prices were down by 10% in 2010, affecting revenues negatively by NOK 9.5 billion.
Over time, the volumes lifted and sold will equal our production of entitlement volumes, but they may be higher or lower in any period due to differences between the capacity of the vessels lifting our volumes and the actual entitlement production in the period.
Total liquids liftings were 910 mboe per day in 2011, a decrease of 6% compared to 2010. Total liquids liftings were 969 mboe per day in 2010, a decrease of 7% compared to 2009 when total liquids liftings were 1,045 mboe per day. The average underlift was 34 mboe per day in 2011. In 2010, the average overlift was 1 mboe per day and in 2009, the average underlift was 21 mboe per day.
Entitlement volumes lifted form the basis for revenue recognition, while equity production volumes affect operating costs more directly. See the report section Financial analysis and review - Operating and financial review 2011 - Sales volumes, for more details on the production-sharing agreement (PSA) effects that cause differences between equity and entitlement volumes. See below for more details on the difference between lifted and produced volumes.
Total entitlement liquids and gas production decreased from 1.705 mmboe per day in 2010 to 1.650 mmboe per day in 2011. In 2009, total entitlement liquids and gas production was 1.806 mmboe per day.
Total equity liquids and gas production decreased from 1.888 mmboe per day in 2010 to 1.850 mmboe per day in 2011. In 2009, total equity production of liquids and gas was 1.962 mmboe per day.
The 2% decrease in total equity production in 2011 compared to 2010 was primarily caused by reduced water injection at Gullfaks, riser inspections and repairs, maintenance shut downs and deferral of gas sales. In addition, expected reductions due to natural decline on mature fields and suspended production in Libya contributed to the decrease. This decrease was partly offset by production from start-up of new fields, ramp-up of production on existing fields and increased ownership shares. Total entitlement production decreased by 6% from 2010 to 2011 and was impacted by the reduction in equity production and by increasing PSA effects.
The 4% decrease in total equity production in 2010 compared to 2009, was primarily caused by relatively higher maintenance activity in 2010 leading to production shutdowns, limitations in the gas transportation system from the NCS because of planned maintenance, production permit restrictions on the Ormen Lange field, various operational issues and a natural production decline on several mature fields. The decrease in equity production was partly compensated by production from the start-up of new fields and ramp-up on existing fields. Total entitlement production decreased by 6% from 2009 to 2010. It was impacted by the same factors as equity production and also by changes in profit tranches for some of our fields in Angola and higher prices leading to reduced entitlement shares on other fields.
The production cost per boe of entitlement volumes was NOK 48.4 for the 12 months ending 31 December 2011, compared with NOK 42.8 for the 12 months ending 31 December 2010. In 2009, the production cost per boe was NOK 38.4. Equity volumes represent produced volumes under PSA contracts that correspond to Statoil's ownership percentage in a specific field, while entitlement volumes represent Statoil's share of the volumes distributed to the partners in the field, which are subject to deductions. Production costs are incurred on the basis of our equity production. The management therefore believes that unit of production cost based on equity production is a better measure of cost control than unit of production cost based on entitlement volumes.
Based on equity volumes, the production cost per boe for the 12 months ending 31 December 2011 and 2010 was NOK 43.1 and NOK 38.6, respectively. In 2009, the production cost per boe was NOK 35.3. Adjusted for restructuring costs, reversal of restructuring costs and other costs arising from the merger recorded in the fourth quarter 2007 and gas injection costs, the production cost per boe of equity production for the 12 months ending 31 December 2011 and 2010, was NOK 42.4 and NOK 37.9, respectively. The corresponding figure for 2009 was NOK 35.3.
Adjustments are made for certain costs relating to the purchase of gas used for injection into oil-producing reservoirs. The adjustment facilitates comparison of field production costs with other fields that do not pay for their own gas used for injection into oil-producing reservoirs.
The increase in adjusted production cost per boe from 2010 to 2011, is mainly related to higher costs from fields preparing for production start-up and entering the production ramp-up phase resulting in a relatively higher cost per boe from new fields coming on stream.
Net income from associated companies was NOK 1.3 billion in 2011, NOK 1.2 billion in 2010 and NOK 1.5 billion in 2009.
Other income was NOK 23.3 billion in 2011, compared to NOK 1.8 billion in 2010 and NOK 1.4 billion in 2009. The significant increase in other income from 2010 to 2011 stems mainly from gains on sale of assets primarily related to the reduction of interests in Peregrino, the Kai Kos Dehseh oil sands and Gassled on 2011. The increase in other income from 2009 to 2010 was mainly related to a gain on sale of assets and insurance proceeds relating to business interruptions.
Purchase [net of inventory variation] includes the cost of the liquids production purchased from the Norwegian State pursuant to the Owners Instruction. See section Operational review - Applicable laws and regulations- SDFI oil & gas marketing & sale for more details. The purchase, net of inventory variation amounted to NOK 319.6 billion in 2011, compared to NOK 257.4 billion in 2010 and NOK 205.9 billion in 2009. Both the 25% increase from 2009 to 2010 and the 24% increase from 2010 to 2011 were mainly caused by higher liquid prices measured in NOK.
Operating expenses and selling, general and administrative expenses include field production costs, costs incurred for transport systems related to the company's share of oil and natural gas production, expenses relating to the sale and marketing of our products, such as business development costs, payroll expenses and employee benefits.
In 2011, operating expenses and selling, general and administrative expenses amounted to NOK 73.6 billion, an increase of NOK 4.8 billion over 2010 when operating expenses and selling, general and administrative expenses were NOK 68.8 billion. The 7% increase reflects mainly the higher activity level in 2011 related to start-up and ramp-up of production on various fields, increased transportation and processing costs, and increased ownership shares. Also, changes in removal estimates, higher tariffs and royalties paid and increased business development costs added to the increase in expenses.
In 2010, operating expenses and selling, general and administrative expenses amounted to NOK 68.8 billion, an increase of NOK 1.5 billion over 2009 when operating expenses were NOK 67.3 billion. The 2% increase was mainly attributable to higher operating costs related to preparation for start up on new fields, and a provision for an onerous contract in 2010. The increase was partly offset by lower transportation costs because of reduced production, cost reductions from cost saving activities and a reversal of a provision for an onerous contract relating to Cove Point terminal.
Depreciation, amortisation and net impairment losses 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 impairment of property, plant and equipent and reversals of impairments. These total expenses amounted to NOK 51.4 billion in 2011, compared with NOK 50.7 billion in 2010 and NOK 53.8 billion in 2009. Included in these totals were net impairment losses of NOK 2.0 billion for 2011, NOK 4.8 billion for 2010 and NOK 7.2 billion for 2009.
Depreciation, amortisation and net impairment losses increased by 1% in 2011 compared to 2010 mainly because of higher depreciation from new fields and assets coming on stream, the impact on depreciation from revisions of removal and abandonment estimates. The increase was partly offset by the impact of lower production, increased reserve estimates and lower net impairment losses. The 6% decrease in depreciation, amortisation and net impairment losses in 2010 compared with 2009 was mainly due to lower impairment losses in 2010 and lower entitlement volumes.
Exploration expenditures are capitalised to the extent that exploration efforts are considered successful, or pending such assessment. Otherwise, such expenditures are expensed.
The exploration expenses consist of the expensed portion of our exploration expenditure and impairment of exploration expenditure capitalised in previous years. In 2011, the exploration expenses were NOK 13.8 billion, a 12% decrease since 2010, when exploration expenses were NOK 15.8 billion. Exploration expenses were NOK 16.7 billion in 2009.
Exploration expenses decreased by 12% in 2011 compared to 2010, mainly because successful drilling resulted in a higher portion of exploration expenditures being capitalised, and because a lower portion of exploration expenditure capitalised in previous years was expensed in 2011 compared to 2010. The 5% decrease in exploration expenses from 2009 to 2010 was mainly due to lower drilling activity and a smaller proportion of exploration expenditure capitalised in previous years being impaired. The decrease was partly offset by higher oil sands delineation drilling expenses, higher seismic expenditures and higher pre-sanctioning costs.
In 2011 Statoil completed 41 exploration and appraisal wells, 25 on the NCS and 16 internationally. A total of 22 wells were announced as discoveries in the period, 17 on the NCS and five internationally. In 2010, a total of 35 exploration and appraisal wells were completed, 17 on the NCS and 18 internationally. A total of 19 wells were announced as discoveries in the period, 12 on the NCS and seven internationally. In addition, four exploration extension wells were completed on the NCS in 2010, three of which were announced as discoveries. In 2009, a total of 68 exploration and appraisal wells and two exploration extension wells were completed, 41 on the NCS and 29 internationally. Thirty-eight exploration and appraisal wells and two exploration extension wells were declared as discoveries in the period.
Net operating income was NOK 211.8 billion in 2011, compared with NOK 137.3 billion in 2010 and NOK 121.7 billion in 2009.
The 54% increase from 2010 to 2011 was primarily attributable to higher prices for both liquids and gas, reduced net impairment losses, unrealised gains on derivatives and gains on sale of assets mainly related to the reduction of interests in Peregrino, the Kai Kos Dehseh oil sands and Gassled in 2011. Lower volume of both liquids and gas sold and increased operating expenses partly offset the increase in net operating income. The 13% increase from 2009 to 2010 was primarily attributable to higher prices for liquids, partly offset by lower gas prices, reduced volumes of liquids sold, and losses on derivatives.
In 2011, impairment losses net of reversals (NOK 0.9 billion), underlift and other adjustments, negatively impacted net operating income, while gain on sale of assets (NOK 22.6 billion), higher fair value of derivatives (NOK 12.0 billion), higher values of products in operational storage and reversal of an onerous contract related to the Cove Point Teminal provision (NOK 0.7 billion), had a positive impact on net operating income.
In 2010, net operating income was negatively affected by impairment losses net of reversals (NOK 4.8 billion), lower fair value of derivatives (NOK 2.9 billion) and a provision for an onerous contract relating to the Cove Point terminal in the USA (NOK 0.8 billion), while overlift and gain on the sale of assets (NOK 1.3 billion) had a positive impact on net operating income.
In 2009, net operating income was negatively affected by impairment losses net of reversals (NOK 12.2 billion) and underlift, while higher fair value of derivatives (NOK 2.2 billion), other accruals, gain on the sale of assets (NOK 0.5 billion) and reversals of restructuring costs (NOK 0.3 billion) all had a positive effect on net operating income in 2009.
Net financial items amounted to a gain of NOK 2.1 billion in 2011, compared with a loss of NOK 0.4 billion in 2010. The positive change of NOK 2.5 billion was mostly attributable to fair value changes on interest rate swap positions of NOK 4.3 billion, due to US dollar interest rates decreasing on average 1.3% in 2011, compared with US dollar interest rates decreasing on average 0.5% in 2010, partly offset by an increase in losses on financial investments of NOK 2.0 billion.
Net foreign exchange gains in 2011 were NOK 0.4 billion compared with net foreign exchange losses in 2010 of NOK 1.8 billion. The changes were mainly related to changes in currency derivatives used for currency and liquidity risk management, partly offset by currency effects on the working capital.
Interest income and other financial items amounted to NOK 1.3 billion in 2011, compared with NOK 3.1 billion in 2010. The NOK 1.8 billion decrease from 2010 to 2011 was related to a NOK 2.0 billion decrease in gains from financial investments, mainly on equities and commercial paper, in combination with a NOK 0.1 billion increase in interest income from financial investments, receivables and assets.
Interest and other finance expenses amounted to a net income of NOK 0.4 billion for 2011, compared with a net expense of NOK 1.7 billion for 2010. The change of NOK 2.1 billion was mostly due to fair value changes on interest rate swap positions relating to the interest rate management of non-current bonds. For 2011, fair value gains amounted to NOK 6.9 billion compared to fair value gains in 2010 of NOK 2.6 billion. The NOK 4.3 billion increase in 2011 is offset by increased finance expenses of NOK 1.4 billion mainly due to the Pernis impairment and the Heidrun redetermination in 2011.
In 2010, net financial items amounted to a loss of NOK 0.4 billion in 2010, compared with a loss of NOK 6.7 billion in 2009. The positive change of NOK 6.3 billion from 2009 to 2010 was mostly attributable to fair value changes on interest rate swap positions, due to decreasing US dollar interest rates in 2010, compared with increasing US dollar interest rates in combination with a 17% weakening of the US dollar in relation to NOK in 2009.
Net foreign exchange losses in 2010 of NOK 1.8 billion and net foreign exchange gains in 2009 of NOK 2.0 billion are mainly related to currency derivatives used for currency and liquidity risk management. They are partly offset by currency effects on the working capital.
Interest income and other financial items amounted to NOK 3.2 billion for 2010, compared with NOK 3.7 billion for 2009. The NOK 0.5 billion decrease was mainly related to a NOK 0.4 billion decrease in interest income on current financial assets in combination with a NOK 0.2 billion decrease in interest income on net financial investments.
Interest and other finance expenses amounted to a net expense of NOK 1.8 billion for 2010, compared with a net expense of NOK 12.5 billion for 2009. The decrease of NOK 10.7 billion was mostly due to fair value changes on interest rate swap positions relating to the interest rate management of external loans. For 2010, fair value gains amounted to NOK 2.6 billion. Correspondingly, fair value losses for 2009 amounted to NOK 6.6 billion.
Income taxes were NOK 135.4 billion in 2011, equivalent to an effective tax rate of 63.3%, compared with NOK 99.2 billion in 2010, equivalent to an effective tax rate of 72.5%, and NOK 97.2 billion in 2009, equivalent to an effective tax rate of 84.6%.
The decrease in the effective tax rate from 2010 to 2011 was mainly due to capital gains on sale of assets in 2011 with lower than average tax rates and recognition of previously unrecognised deferred tax assets in 2011. As part of the purchase price allocation ((PPA) for the acquisition of Brigham Exploration Company an amount of NOK 8.7 billion of deferred tax liabilities was recognised. As a result of the recognition of these deferred tax liabilities, previously unrecognised deferred tax assets of NOK 3.1 billion related to deferred tax losses in other parts of the United States operations were recognised in 2011.
The decrease in the effective tax rate from 2009 to 2010 was mainly due to high taxes in 2009 caused by higher taxable income than accounting income in companies that are taxable in other currencies than the functional currency. The decrease in the effective tax rate was also caused by relatively lower income from the NCS in 2010 compared with 2009. Income from the NCS is subject to a higher 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), and changes in the components of income between Norwegian oil and gas production, taxed at a marginal rate of 78% and income from other tax jurisdictions. Other Norwegian income, including the onshore portion of net financial items is taxed at 28%, and income in other countries is taxed at the applicable income tax rates in those countries.
In 2011, the non-controlling interest in net profit was NOK 0.3 billion, compared to NOK 0.4 billion in 2010 and NOK 0.6 billion in 2009. The non-controlling interest in 2011 is primarily related to Statoil's 54% ownership of Statoil Fuel & Retail, starting in October 2010, and the 79% ownership of Mongstad crude oil refinery.
Net income was NOK 78.4 billion in 2011, compared to NOK 37.6 billion in 2010 and NOK 17.7 billion in 2009.
The 108% increase from 2010 to 2011 was mainly due to the increased net operating income, positively impacted by higher liquids and gas prices. Also, gains from sale of assets, increased unrealised gains on derivatives, gains on net financial items and a lower effective tax rate contributed positively to the increase in net income. Lower volumes of liquids and gas sold and higher operating expenses partly offset the increase in net income compared to 2010. The 112% increase from 2009 to 2010 was mainly due to increased net operating income as a result of higher revenues from liquids and a lower net financial loss, only partly offset by higher income taxes.
The board of directors will propose for approval at the annual general meeting an ordinary dividend of NOK 6.50 per share for 2011, an aggregate total of NOK 20.7 billion. In 2010, the ordinary dividend was NOK 6.25 per share, an aggregate total of NOK 19.9 billion. In 2009, the ordinary dividend was NOK 6.00 per share, an aggregate total of NOK 19.1 billion.
Equity production for 2012 is estimated to grow by around 3% compound annual growth rate (CAGR) based on the actual 2010 equity production. Organic capital expenditures for 2012 are estimated at around USD 17 billion.
Organic capital expenditures for 2012 (i.e. excluding acquisitions and capital leases), are estimated at around USD 17 billion including expenditures relating to our new assets from the recent Brigham acquisition.
The company will continue to mature its large portfolio of exploration assets and expects to complete around 40 wells with a total exploration activity level in 2012 similar to the 2011 level for an expenditure around USD 3 billion, excluding signature bonuses.
Statoil has an ambition to continue to be in the top quartile of its peer group for unit of production cost.
Planned turnarounds are expected to have a negative impact on the quarterly production of liquids and gas of approximately 20 mboe per day in the first quarter of 2012, all of which are planned outside the NCS. In total, the turnarounds are estimated to have an impact on equity production of around 50 mboe per day for the full year 2012, of which most are liquids.
Equity production for 2012 is estimated to grow by around 3% compound annual growth rate (CAGR) based on the actual 2010 equity production. Deferral of gas production to create value, gas off-take, timing of new capacity coming on stream and operational regularity represent the most significant risks related to the production guidance.
We expect prices for crude oil to continue to be volatile in the short to medium term, but at a relatively high level. Oil product prices will in general follow those of crude oil. Refining margins were low in 2011 due to overcapacity and competition for available crude oil cargoes. Refinery closures at the end of 2011 should lead to less overcapacity and slightly better margins in the near term. The refining industry is expected to still face major challenges in 2012. Even though global oil demand has recovered from 2009 levels, refinery overcapacity persists.
We believe that global oil demand will continue to increase moderately in 2012 and continue to grow at roughly the same pace over the next few years, as economic growth is expected to stay at moderate levels. The shift of higher oil consumption in emerging markets, and lower oil consumption in mature regions, is expected to continue. Emerging markets, led by China, are expected to increase usage of oil for industrial production, construction and transportation. Western Europe and the US are expected to see a fall in oil demand, primarily due to efficiency gains in the transportation sector and less intake from stationary facilities. Diesel demand in Europe is expected to be robust, but a surplus of European gasoline supply will need to be sold to other markets.
Supply of natural gas liquids (NGL) is expected to increase significantly, especially as supply associated with new US shale gas production reaches the market. European NGL production is likely to remain high as volumes associated with oil fields are replaced by NGL volumes from non-associated production. The increase in LPG availability is expected to find solid demand from the premium residential/heating segment, and as feedstock into the price-sensitive petrochemical industry. Naphtha is used in both the petrochemical and transportation sectors.
We continue to take a positive long-term view of gas as an energy source. Domestic production of gas in the EU continues to decline, while demand for gas is expected to increase in the long term, particularly due to the lower carbon footprint of natural gas compared with oil and coal. In the USA, the current increase in shale gas supply combined with a milder than normal winter has led us to expect relatively low gas prices in the short term. However, movement in exploration focus away from shale gas towards more shale liquids rich areas, together with an increase in new demand sources such as additional gas for power and, to a lesser extent, export markets via LNG, are expected to support prices in the medium to long term.
Statoil's income could vary significantly with changes in commodity prices, even if volumes remain stable through the year. There is a small seasonal effect on volumes in the winter and summer seasons due to normally higher off-takes of natural gas during cold periods. There is normally an additional small seasonal effect on volumes as a result of the higher maintenance activity level on offshore production facilities during the second and third quarters each year, since generally better weather conditions allow for more maintenance work.
These forward-looking statements reflect current views about future events and are, by their nature, subject to significant risks and uncertainties because they relate to events and depend on circumstances that will occur in the future. See the Forward-looking statements section for more.
Oil and natural gas are subject to internal transactions between our reporting segments before being sold in the market. We have established a pricing policy for transfers based on the estimated market price.
A new corporate structure was implemented from 1 January 2011. Prior periods have been restated to be comparable, see the Consolidated financial statements - note 4 Segments - for further information.
The table below details certain financial information for our five reporting segments: Development and Production Norway (DPN), Development and Production International (DPI), Marketing, Processing and Renewable Energy (MPR), Fuel & Retail (SFR) and Other. The Other reporting segment includes activities within Global Strategy and Business Development; Technology, Projects and Drilling; and Corporate Staffs and Services.
We eliminate intercompany sales when combining the results of reporting segments. These include transactions recorded in connection with our oil and natural gas production in DPN or DPI and also in connection with the sale, transportation or refining of our oil and natural gas production in MPR and SFR.
DPN in Statoil Petroleum AS produces oil and natural gas, which it sells internally to MPR in Statoil ASA. A large share of the oil produced by DPI is also sold from legal entities holding the relevant license to MPR. The remaining oil and gas from DPI is sold directly in the market. For intra-company sales and purchases, Statoil has established a market based transfer pricing methodology for the oil and natural gas that meets the requirements as to applicable laws and regulations.
In 2011, the average transfer price for natural gas per standard cubic metre was NOK 1.64 per scm. The average transfer price was NOK 1.27 per scm in 2010 and NOK 1.39 in 2009. For oil sold from DPN to MPR, the transfer price is the applicable market-reflective price minus a margin of NOK 0.70 per barrel.
For additional information please refer to the Consolidated Financial Statements - note 4 Segments.
The following table shows certain financial information for the five segments, including inter-company eliminations for each of the years in the three-year period ending 31 December 2011.
The following tables show total revenues by geographic area.
In 2011, Development and Production Norway delivered strong financial results and strong cash flows, despite reduced production.
Net operating income in 2011 was NOK 152.7 billion, compared with NOK 115.6 billion in 2010. Strategic portfolio optimisation in 2011 included the Centrica transaction which is expected to be closed in the second quarter of 2012, the increased ownership interests in Heidrun and Snøhvit and an active year maturing and sanctioning new projects. Our production of oil and gas on the NCS averaged 1,316 mboe per day in 2011, compared with 1,374 mboe per day in 2010 and 1,450 mboe per day in 2009.
DPN generated total revenues of NOK 212.1 billion in 2011 and its net operating income was NOK 152.7 billion. The average daily entitlement production was 693 mboe per day for liquids and 624 mboe per day for gas.
Total revenues and other income were NOK 212.1 billion in 2011, NOK 170.7 billion in 2010 and NOK 158.7 billion in 2009. An increase of 39% in the average price in USD of oil sold by DPN to MPR accounted for NOK 43.8 billion of the increase in revenues, and an increased gas price in NOK of sold gas, also made a positive contribution of NOK 13.4 billion in 2011.
This was partly offset by a negative currency exchange rate deviation of NOK 11.5 billion due to a 7% decrease in the USD/NOK exchange rate in 2011. Furthermore, a 5% decrease in lifted volumes of liquids accounted for NOK 5.2 billion of the decrease in revenues and a 7% decrease in lifted volumes of gas accounted for NOK 3.4 billion of the decrease in revenues.
There was an increase in total revenues and other income fromNOK 158.7 billion in 2009 to NOK 170.7 billion in 2010. An increase of 32% in the average price in USD of oil sold by DPN to MPR accounted for NOK 29.3 billion of the increase in revenues, and a minor increase in lifted volumes of natural gas, also made a positive contribution of NOK 0.2 billion. This was partly offset by a decrease of 9% in lifted volumes of liquids, making a negative contribution of NOK 8.9 billion and a negative currency exchange rate deviation of NOK 4.7 billion due to a 4% increase in the USD/NOK exchange rate in 2010. Furthermore, an 8% decrease in the average transfer price in NOK of natural gas sold by DPN to MPR reduced revenues by NOK 4.1 billion.
The average daily lifting of liquids in 2011 was 673 mboe per day, compared with 711 mboe per day in 2010 and 778 mboe per day in 2009. Over time, the volumes lifted and sold will equal the volumes produced, but they may be higher or lower in any period due to differences between the capacity of the vessels lifting our volumes and the actual entitlement production in the period, see section Definitions of reported volumes for more information. The average daily underlift was 19 mboe per day in 2011 compared with an average overlift of 6 mboe overlift per day in 2010 and an average underlift of 6 mboe per day in 2009.
The average daily production of entitlement liquids in 2011 was 693 mboe per day, compared with 704 mboe per day in 2010 and 784 mboe per day in 2009. The decrease in liquids production is mainly related to Gullfaks reduced water injection and turnaround, Visund turnaround and riser inspection and repair, and Volve shut down due to anchor problems. In addition, expected reductions due to natural decline on mature fields contributed to the decrease. These effects were partly offset by new production at Morvin, Vega and Gjøa, increased production at Tyrihans and Sleipner, low decline rate and increased ownership share at Heidrun.
The decrease in production from 2009 to 2010 was mainly related to the Gullfaks C-06 well control incident in May 2010, Operations West water injection issues and a decline in the main field on Gullfaks, reduced capacity at Kollsnes, a lower production permit than expected on Ormen Lange and operational challenges on Kristin and Oseberg. The negative effect on average daily production was approximately 70 mbbl in 2010. In addition, we had expected production profile reductions due to a natural decline on mature fields. The decrease was partly offset by increased production at Morvin and Tyrihans.
The average daily production of entitlement gas was 624 mboe per day in 2011 compared with 669 mboe in 2010 and 666 mboe in 2009.
Operating expenses and selling, general and administrative expenses were NOK 24.7 billion in 2011, compared with NOK 23.6 billion in 2010 and NOK 23.5 billion in 2009. In 2011, expenses increased mainly due transportation tariffs (Troll and Oseberg), increased ownership in Heidrun and new fields coming on stream (Beta West, Vega and Morvin). Operating plant costs remained stable compared to 2010. The increase of NOK 0.1 billion from 2009 to 2010 was due to increased operating plant costs and other expenses, partly offset by a decrease in transportation costs due to lower lifting of liquids.
Depreciation, amortisation and net impairment losses were NOK 29.6 billion in 2011, compared with NOK 26.0 billion in 2010 and NOK 25.7 billion in 2009. The increase in 2011 compared with 2010 is mainly related to new fields on stream, increased removal/abandonment estimates, re-determination at Heidrun and increased investments on mature fields, partly offset by decreased depreciation due to reduced production and increased proved reserves. The NOK 0.3 billion increase from 2009 to 2010 was mainly related to increased investments on mature fields, partly offset by a change in the producing fields portfolio.
Exploration expenditure (including capitalised exploration expenditure) in 2011 amounted to NOK 6.6 billion, compared with NOK 6.0 billion in 2010 and NOK 8.2 billion in 2009. The increase from 2010 to 2011 was mainly due to a higher number of wells being drilled in 2011, as well as a higher average Statoil share per well, compared to 2010. Seismic costs were higher in 2011 due to increased regional focus in the Barents and Norwegian Sea, related to surveys for the 22nd concession round and the purchase of Norwegian Petroleum Directorate (NPD) seismic in Nordland 7. The decrease in exploration expenditure from 2009 to 2010 was mainly due to lower activity and fewer wells being drilled in 2010.
Exploration expenses in 2011 were NOK 5.1 billion, compared with NOK 5.5 billion in 2010 and NOK 5.2 billion in 2009.
In 2011, 25 exploration and appraisal wells and four exploration extension wells were completed on the NCS, of which 17 exploration and appraisal wells and one exploration extension well were announced as discoveries.
In 2010, 17 exploration and appraisal wells and four exploration extension wells were completed on the NCS, of which 12 exploration and appraisal wells and three of the exploration extension wells were announced as discoveries. Higher exploration expenditure due to higher drilling activity in 2011 have been offset by increased capitalised exploration costs as more discoveries have been made in 2011.
In 2009, 39 exploration and appraisal wells and two exploration extension wells were completed on the NCS, of which 31 exploration and appraisal wells and both of the exploration extension wells were announced as discoveries.
The drilling of four exploration and appraisal wells was ongoing at the end of 2011. The reconciliation of exploration expenditure with exploration expenses is shown in the table below.
Net operating income in 2011 was NOK 152.7 billion, compared with NOK 115.6 billion in 2010 and NOK 104.3 billion in 2009. The NOK 37.1 billion increase in 2011 was mainly due to increased liquid prices. The NOK 11.3 billion increase in 2010 was mainly due to increased liquid prices.
In 2011, an unrealised gain on derivatives (NOK 5.2 billion) and gain on sale of assets (NOK 0.1 billion) positively impacted net operating income. Underlift, a change in future settlement related to a sale of a license share (NOK 0.4 billion) and an adjustment related to pension costs (NOK 0.2 billion) negatively impacted net operating income.
In 2010, an unrealised gain on derivatives (NOK 2.1 billion), an adjustment related to pension and other provisions (NOK 0.9 billion), overlift (NOK 0.4 billion) and gain on sales of assets (NOK 0.4 billion) positively impacted net operating income in 2010, partly offset by a refund of historic gas purchase (NOK 0.1 billion) that negatively impacted net operating income 2010.
In 2009, an unrealised gain on derivatives (NOK 1.5 billion), a change in future settlement related to a sale of a lisence share (NOK 0.5 billion), restructuring costs (NOK 0.3 billion) and a refund of a historic gas purchase (NOK 0.3 billion) had a positive impact on net operating income 2009, while underlift (NOK 0.8 billion) and provision for a take-or-pay contract (NOK 0.2 billion) had a negative impact on net operating income.
In 2011, Development and Production International delivered strong financial results and entitlement volumes on par with 2010.
Net operating income in 2011 was NOK 32.8 billion, compared with NOK 12.6 billion in 2010. Strategic portfolio optimisation in 2011 mainly included the 40% divestment of ownership interests in Peregrino in Brazil and Kai Kos Dehseh oil sands in Canada. DPI's entitlement production of oil and gas averaged 334 mboe per day in 2011, compared with 332 mboe per day in 2010 and 357 mboe per day in 2009. The average daily equity production of liquids and gas was 534 mboe per day in 2011, compared with 514 mboe per day in 2010 and 512 mboe per day in 2009.
Equity volumes represent produced volumes corresponding to Statoil's percentage of ownership in a particular field. Entitlement volumes represent Statoil's share of the volumes distributed to the partners in the field. Under a production sharing agreement (PSA) entitlement volumes are subject to deductions for, among other things, royalties and the host government's share of profit oil. Entitlement volumes lifted are the basis for revenue recognition, while equity production volumes affect operating costs more directly. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the license. The distinction between equity and entitlement is relevant to most PSA regimes. The main countries in which Statoil operates under PSAs are Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.
Our international portfolio has been further strengthened in 2011 through the acquisition of more than 375,000 acres in the Bakken and Three Forks tight oil plays in the Williston Basin in North Dakota and Montana in the US on 1 December 2011 through the acquisition of Brigham Exploration Company. In addition, Statoil acquired additional acreage in the Marcellus shale gas and Eagle Ford shale oil plays in the US during 2011. An overview of portfolio transactions in 2011 is presented the section Operational review - Development and Production International - The DPI portfolio.
In total, 16 exploration and appraisal wells were completed in 2011 and five wells were announced as discoveries. At year end, six wells were pending final evaluation. The total exploration expenses were NOK 8.7 billion in 2011, compared with NOK 10.3 billion in 2010.
In 2011, DPI generated total revenues and other income of NOK 70.9 billion and a net operating income of NOK 32.8 billion. The average daily entitlement production of liquids was 252 mboe per day.
DPI generated total revenues and other income of NOK 70.9 billion in 2011 compared with NOK 51.0 billion in 2010 and NOK 41.8 billion in 2009. The increase from 2010 to 2011 was mainly related to a gain of NOK 14.2 billion from the sale of 40% ownership interests in Peregrino and Canadian oil sands assets and a 28% increase in realised liquid and gas prices measured in NOK, with a positive contribution of NOK 12.5 billion. The increase was partly offset by a 2% reduction in lifted volumes, which contributed negatively in the amount of NOK 3.0 billion and a net reduction in other income of NOK 3.8 billion.
The increase from 2009 to 2010 was mainly related to a 25% increase in realised liquid and gas prices that made a positive contribution of NOK 9.4 billion and a 63% increase in other income that made a positive contribution of NOK 1.2 billion. The increase was partly offset by a 4% reduction in lifted volumes, which contributed negatively in the amount of NOK 1.4 billion.
The average daily lifting of liquids was 237 mboe per day in 2011, compared with 258 mboe per day in 2010 and 267 mboe per day in 2009. Over time, the volumes lifted and sold will equal our production of entitlement volumes, but they may be higher or lower in any period due to differences between the capacity and timing of the vessels lifting our volumes and the actual entitlement production during the period, see section Definition of reported volumes for more information. The average daily over/underlift in 2011, 2010 and 2009 was 1 mboe per day in overlift, 8 mboe per day in overlift and 2 mboe per day in underlift, respectively.
The average daily entitlement production of liquids was 252 mboe per day in 2011, compared with 263 mboe per day in 2010 and 283 mboe per day in 2009. The 4% decrease in average daily liquids entitlement production from 2010 to 2011 was mainly related to a higher PSA effect due to changes in profit tranches and higher prices leading to reduced entitlement shares, turnaround on Azeri, Chirag & Gunashli (ACG) in Azerbaijan and decline in production profiles in several fields in Angola. The decrease was partly offset by start-up of Peregrino in Brazil and Pazflor in Angola. The 7% decrease in average daily liquids entitlement production from 2009 to 2010 was mainly related to a higher PSA effect due to changes in profit tranches and higher prices leading to reduced entitlement shares, a decline in production profile and operational issues in several fields in Angola, and a reduced ownership share in the Mabruk field in Libya.
The average daily entitlement production of gas was 82 mboe per day in 2011 (equivalent to 13 mmcm or 460 mmcf per day), compared with 68 mboe per day in 2010 (equivalent to 11 mmcm or 384 mmcf per day) and 74 mboe in 2009 (equivalent to 12 mmcm or 413 mmcf per day). The increase in daily gas production from 2010 to 2011 was mainly related to U.S. onshore production at Marcellus with an increased number of wells online and at Eagle Ford which was acquired in December 2010. The decrease in daily gas production from 2009 to 2010 was mainly related to a decline in mature fields in the Independence Hub in the US Gulf of Mexico.
The average daily equity liquids and gas production was 534 mboe in 2011, compared with 514 mboe in 2010 and 512 mboe in 2009.
Purchase [net of inventory variation] was NOK 0.7 billion in 2011, compared with NOK 0.0 billion in 2010 and NOK 1.1 billion in 2009. The increase from 2010 to 2011 was mainly related to diluent purchases for Leismer operations that started in January 2011.
Operating expenses and selling, general and administrative expenses were NOK 14.9 billion in 2011, compared with NOK 11.4 billion in 2010 and NOK 9.5 billion in 2009. The 30% increase from 2010 to 2011 is mainly due to ramp-up of Marcellus and Eagle Ford in the U.S and production start-up of Peregrino in Brazil, Pazflor in Angola and Leismer in Canada in 2011. In addition, royalty payments on Tahiti increased expenses in 2011. The 20% increase from 2009 to 2010 is mainly due to increased preparation for operations on the Peregrino field in Brazil.
Depreciation, amortisation and net impairment losses were NOK 13.8 billion in 2011, compared with NOK 16.7 billion in 2010 and NOK 17.1 billion in 2009. The 17% decrease from 2010 to 2011 was mainly due to a net reduction in impairments of NOK 3.6 billion based on a net impairment of NOK 1.5 billion in 2010 compared with a net impairment reversal of NOK 2.1 billion in 2011. In addition, ordinary depreciation increased by NOK 0.7 billion in 2011 compared to 2010, due to ramp up of Marcellus in the U.S and start-up on Peregrino in Brazil and Pazflor in Angola. The increase was partly offset by lower production and increased reserves in various other fields. The 3% decrease from 2009 to 2010 was mainly due to decreased depreciation as proved reserves increased in 2010, partly offset by increased net impairments.
Exploration expenditure was NOK 12.2 billion in 2011, compared with NOK 10.8 billion in 2010 and NOK 8.7 billion in 2009. The increase from 2010 to 2011 was mainly due to higher drilling costs. Slightly lower drilling activity in 2011 was offset by more expensive wells in Brazil and Indonesia. Seismic expenditures increased due to high seismic activity in 2011. The increase from 2009 to 2010 was mainly due to increased exploration drilling costs and higher oil sands delineation drilling, increased higher seismic expenditures and higher pre-sanctioning costs.
Exploration expenses were NOK 8.7 billion in 2011, compared with NOK 10.3 billion in 2010 and NOK 11.5 billion in 2009. Despite increased drilling costs in 2011, exploration expenses decreased, primarily due to increased capitalisation of exploration expenditures in 2011 compared to 2010. The reduction from 2009 to 2010 was mainly due to a reduction in the amount of previously capitalized exploration expenditure that was expensed, which was partly offset by more oil sands delineation drilling, higher seismic expenditures and higher pre-sanctioning costs.
In total, 16 exploration and appraisal wells were completed in 2011 and five wells were announced as discoveries. In 2010, 18 exploration and appraisal wells were completed and six wells were announced as discoveries. In 2009, 29 exploration and appraisal wells were completed and seven wells were announced as discoveries.
Net operating income in 2011 was NOK 32.8 billion, compared with NOK 12.6 billion in 2010 and NOK 2.6 billion in 2009. The increase from 2010 to 2011 was primarily attributable to a gain from the sale of the Peregrino and Canadian oil sands assets and increased liquids prices, partly offset by increased operating expenses and selling, general and administrative expenses.The increase from 2009 to 2010 was mainly related to increased liquids prices.
In 2011 impairment reversals of NOK 2.4 billion positively impacted net operating income whereas an underlift negatively impacted net operating income.
In 2011, MPR experienced higher European gas prices and margins, and good operational performance in the production facilities.Lower margins from trading of liquids, storage strategies and refining partly offset the increase.
Gas prices developed positively in 2011 compared to 2010. Our volume-weighted average sales price was NOK 2.08 per scm in 2011 and NOK 1.72 per scm in 2010, an increase of approximately 21%. The volume-weighted average sales price was NOK 1.90 per scm in 2009.
The majority of our long-term gas supply contracts in Europe are indexed to oil products, which means that a change in oil prices affects the realized gas prices of these supply contracts after a certain time delay (typically 6-9 months). Oil prices increased, and this positively affected the development of natural gas prices. In addition, the gas indexed prices increased in 2011.
All of Statoil's gas produced on the NCS is sold by MPR, purchased from DPN at a market-based internal price. The gradually increasing natural gas sales prices in 2011 were largely offset by an increase in the internal purchase price. Our average internal purchase price for gas was NOK 1.64 per scm in 2011, up from NOK 1.27 per scm in 2010, an increase of 29%. The average internal purchase price for gas was NOK 1.38 per scm in 2009.
Natural gas sales volumes in 2011 were 50.4 bcm, compared to 52.8 bcm in 2010, a decrease of 5% mainly related to lower entitlement production in 2011. Natural gas volumes in 2009 were 49.8 bcm. Statoil sold 39.0 bcm of entitlement gas in 2011 compared to 41.7 bcm in 2010 and 41.4 bcm in 2009. In addition, we sold 33.5 bcm of NCS gas on behalf of the Norwegian State's direct financial interest (SDFI). Most of the gas was sold to European energy providers under long-term contracts.
Sales of third party volumes of natural gas amounted to 11.4 bcm in 2011, compared to 11.1 bcm in 2010, an increase of 3%. The increase was mainly due to optimisation and balancing of our portfolio. The sales of third party volumes of natural gas amounted to 8.4 bcm in 2009.
With an average of crude, condensate and NGL sales of 2.3 mmbbl per day in 2011, we are one of the world's largest net sellers of such products. Of these daily sales, approximately 0.96 mmbbl are sales of our own volumes, 0.91 mmbbl are sales of third party volumes and 0.45 mmbbl are sales of SDFI volumes. Our average sales volume was 2.3 mmbbl per day in 2010 and 2.4 mmbbl per day in 2009. The average daily third-party volumes sold in 2011 were 0.91 mmbbl, compared to 0.84 mmbbl in 2010 and 0.70 mmbbl in 2009.
Refinery throughput in 2011 was higher than in 2010 due to a higher on stream factor in 2011 and turnaround in 2010 at the Mongstad refinery. This was partly offset by the Kalundborg refinery, which had a lower on stream factor in 2011 compared to 2010, due to larger turnaround in 2011. The methanol production in 2011 was 8% higher than in 2010, mainly due to turnaround in 2010.
The refining industry continued to face major challenges in 2011. Even though global oil demand was high, refinery overcapacity was still present. The overcapacity is particularly challenging in the Atlantic Basin (countries accessible for shipment on the Atlantic Ocean), where some refineries decided to close operations permanently or temporary during 2010 and 2011. The refining reference margin was 2.3 USD/bbl in 2011 compared to 3.9 USD/bbl in 2010, a reduction of approximately 42% due to overcapacity in the market. The refining reference margin was 3.0 USD/bbl in 2009.
The Sheringham Shoal offshore wind farm in the UK where Statoil has an ownership interest started electricity production from the first wind turbines in August 2011. The major parts of Statoil's onshore wind power activities in Norway were sold during 2011.
For Marketing, Processing and Renewable Energy, net operating income increased from NOK 6.1 billion in 2010 to NOK 24.7 billion in 2011.
The previously reported FCC refining margin has been replaced by a new refining reference margin. The refining reference margin is a typical, average gross margin of our two refineries, Mongstad and Kalundborg, and therefore has a higher correlation with our actual margins.
Total revenues and other income were NOK 610.0 billion in 2011, compared to NOK 493.6 billion in 2010 and NOK 422.7 billion in 2009. The increase in total revenues and other income from 2010 to 2011 was mainly due to higher prices for gas, crude and other oil products, increased volumes of crude sold and a gain related to the sale of the 24.1% interest in Gassled (NOK 8.4 billion). The increase was partly offset by reduced natural gas volumes sold. The average crude price in USD increased by approximately 40% in 2011 compared to 2010, but this was partly offset by a weakening of the average USD/NOK exchange rate by almost 7%. The volume-weighted average sales price for gas increased by 21%. The increase was due to an increase in gas price for contracts linked to oil products as well as gas indexed prices. Total natural gas sales volumes decreased by 5%, mainly related to lower entitlement production in 2011.
The increase from 2009 to 2010 was mainly due to higher prices for crude and other oil products, partly offset by 10% lower volume-weighted average sales price for natural gas. Total natural gas sales volumes increased by 6% mainly due to increased third party volumes. The average crude price in USD increased by approximately 29% in 2010 compared to 2009, but this was partly offset by a weakening of the average USD/NOK exchange rate by almost 4%.
Purchase [net of inventory variation] was NOK 550.5 billion in 2011, compared to NOK 452.1 billion in 2010 and NOK 370.2 billion in 2009. The increase from 2010 to 2011 was mainly due to higher prices for volumes purchased, partly offset by a weakening of the average USD/NOK exchange rate. The increase from 2009 to 2010 was mainly due to higher prices for liquids purchased, partly offset by a lower transfer price for natural gas from DPN.
Operating expenses and selling, general and administration expenses were NOK 28.8 billion in 2011, compared to NOK 29.3 billion in 2010 and NOK 27.1 billion in 2009. The decrease in expenses from 2010 to 2011 was mainly due to reversal of the onerous contract provision in connection with a re-gasification terminal in the USA (Cove Point), reduced Gassled transportation tariffs and asset removal obligation, partly offset by new time charter shipping contracts, increased transportation activity in the USA and operation of the new combined heat and power plant (CHP) at Mongstad. The increase in expenses from 2009 to 2010 was mainly related to the onerous contract provision at Cove Point in 2010 and due to the reversal in 2009 of a 2008 provision of NOK 1.3 billion relating to a take-or-pay contract.
Depreciation, amortisation and net impairment losses were NOK 6.0 billion in 2011, compared to NOK 6.0 billion in 2010 and NOK 9.2 billion in 2009. In 2011 we had higher impairment losses related to refinery assets, an impairment loss related a gas fired power station and increased depreciation on new Mongstad refinery units, offset by reversal of an impairment loss in connection with Cove Point and lower depreciation driven by the Gassled divestment. The impairment of refinery assets reflects lower refinery margins due to continued overcapacity in the market. Determining recoverable value is sensitive to changes in refinery margins and exchange rates, and subsequent changes in these factors could result in additional impairment changes. The decrease in 2010 was mainly due to higher impairment losses related to refinery assets and intangible assets related to Cove Point in 2009.
In 2011, the net operating income was NOK 24.7 billion, compared to NOK 6.1 billion in 2010 and NOK 16.3 billion in 2009. The net operating income in 2011 was positively impacted by a gain related to the sale of the 24.1% interest in Gassled (NOK 8.4 billion), a positive change in fair value of derivatives (NOK 4.6 billion), a gain due to periodisation of inventory hedging effects (NOK 2.3 billion), a reversal of a provision and an impairment in connection with Cove Point (NOK 1.6 billion), a gain on operational storage, higher margins on marketing and trading of gas, and a net gain on sale of wind assets (NOK 0.1 billion). Negative effects on net operating income in 2011 were impairment losses related to refinery assets and a gas fired power station (NOK 3.8 billion and NOK 0.3 billion, respectively), weaker trading results for crude oil, products and gas liquids, a decrease in volumes of gas sold, and lower refining margins.
Net operating income in 2010 was positively impacted by a gain on operational storage, and higher refining margins and methanol prices. Negative effects on net operating income in 2010 were a negative change in fair value of derivatives (NOK 4.1 billion), an impairment loss on a refinery asset (NOK 2.9 billion), a decrease of 10% in the volume-weighted average sales price reducing the marketing and trading margins, loss due to periodisation of inventory hedging effects (NOK 1.0 billion), a provision for an onerous contract in connection with Cove Point (NOK 0.9 billion), lower contribution from our processing and transport operations, a loss related to an onerous sales contract (NOK 0.4 billion), weaker results in liquids trading and turnarounds at the Mongstad and Kalundborg refineries.
Net operating income in 2009 was positively impacted by a gain due to a positive change in fair value of derivatives (NOK 2.7 billion), gain from a price change for our operational storage, a reversal of a take-or-pay contract provision (NOK 1.3 billion), strong marketing and trading margins both for natural gas and crude. Negative effects on net operating income in 2009 were an impairment loss on refinery assets (NOK 5.4 billion), a loss on inventory hedge positions that do not qualify for hedge accounting (NOK 2.0 billion), and low refining margins and methanol prices.
MPR consists of three product areas: Natural Gas processing and transportation, Natural Gas marketing and trading and Crude Oil processing, marketing and trading. Natural Gas processing and transport activities mainly consist of our share in Gassled. Natural Gas marketing and trading activities consist of our gas sales and trading activities, including the transportation costs associated with the Natural Gas activity. Crude Oil processing, marketing and trading activities mainly consist of our oil sales and trading activities in addition to our refinery activities, the Tjeldbergodden Methanol plant and our three crude oil terminals.
Net operating income in Natural Gas processing and transportation was NOK 13.5 billion in 2011, compared to NOK 5.5 billion in 2010. The increase was due to the gain related to the sale of the 24.1% interest in Gassled and reduced depreciation related to the Gassled interest sold, partly offset by reduced tariffs in Gassled and the 3.7% reduction in ownership share in Gassled with effect from 1 January 2011.
Net operating income in Natural Gas processing and transportation amounted to NOK 5.5 billion in 2010, compared to NOK 7.3 billion in 2009. The reduction was due to reduced income from Gassled, mainly due to a closure of a compressor at Kårstø, some regularity problems at Kårstø and Kollsnes, and production maintenance work during the third quarter of 2010.
Net operating income in Natural Gas processing and transportation is expected to be significantly lower in 2012 than 2011 due to the sale of the 24.1% interest in Gassled, in particular the NOK 8.4 billion gain in 2011 and Statoil's reduced ownership interest to 5% after the sale.
Net operating income in Natural Gas marketing and trading was NOK 14.0 billion in 2011, compared to NOK 2.8 billion in 2010. The increase was mainly due to a large positive change in fair value derivatives (positive NOK 4.6 billion in 2011, compared to negative NOK 4.1 billion in 2010), reversal of provisions relating to an onerous contract accrued for in 2009 and 2010 (positive NOK 1.6 billion in 2011, compared to negative NOK 0.9 billion in 2010), and slightly higher margins on our gas sales due to higher prices. The increase was partly offset by lower entitlement volumes and impairment loss in 2011 related to a gas-fired power station (NOK 0.3 billion).
Net operating income in Natural Gas marketing and trading in 2010 was NOK 2.8 billion, compared to NOK 10.9 billion in 2009. The decrease was largely due to a large negative change in derivatives (negative NOK 4.1 billion in 2010, compared to positive NOK 2.7 billion in 2009). In addition, a positive volume deviation in 2010 compared to 2009 was more than offset by a negative margin deviation due to decreased sales prices and a lower contribution from trading. A decreased provision relating to an onerous contract (NOK 0.9 billion in 2010, compared to NOK 1.0 billion in 2009) partly offset the decreased net operating income.
Total natural gas sales volumes were 50.4 bcm in 2011 (1.78 tcf), 52.8 bcm (1.87 tcf) in 2010 and 49.7 bcm (1.76 tcf) in 2009. The 5% decrease in total gas volumes sold from 2010 to 2011 was mainly related to lower entitlement production in 2011. The 6% increase in gas volumes sold from 2009 to 2010 was mainly due to increased third party volumes.
In 2011, the volume-weighted average sales price for gas was NOK 2.08 per scm, compared to NOK 1.72 per scm in 2010, an increase of 21%. The increase was due to an increase in gas price for contracts linked to oil products as well as gas indexed prices. The volume-weighted average sales price was NOK 1.90 per scm in 2009. The decrease of 9% was mainly due to extraordinarily high prices in the first quarter 2009 as a result of the peak in oil product prices in 2008.
Net operating income in Crude Oil processing, marketing and trading was a loss of NOK 2.4 billion in 2011, compared to a loss of NOK 1.6 billion in 2010. The increased loss in 2011 was mainly due to lower margins from trading of crude oil, products and gas liquids, and storage strategies in an unfavourable and challenging market, lower refining margins and higher impairment losses related our refinery assets (NOK 3.8 billion in 2011, compared to NOK 2.9 billion in 2010). The negative changes were partly offset by a positive change in periodisation of inventory hedging effects (a gain of NOK 2.3 billion in 2011 compared to a loss of NOK 1.0 billion in 2010), a loss accrued for related to an onerous sales contract in 2010 (NOK 0.4 billion), and higher gain on operational storage in 2011 compared to in 2010.
Net operating income in Crude Oil processing, marketing and trading in 2010 was a loss of NOK 1.6 billion compared to a loss of NOK 1.4 billion in 2009. The increased loss was mainly due a lower gain on operational storage in 2010 compared to in 2009, reversal of a take-or-pay contract accrual in 2009 (NOK 1.3 billion), a loss related to an onerous contract regarding a sales contract (NOK 0.4 billion), and weaker trading results. The weaker trading results were mainly due to lower gains from storage strategies under prevailing market conditions, with a flattened contango price structure, and losses due to the price drop in May 2010. The negative changes were partly offset by lower impairment losses on our refinery assets (NOK 2.9 billion in 2010, compared to NOK 5.4 billion in 2009), a positive change in periodisation of inventory hedging effects (a loss of NOK 1.0 billion in 2010 compared to a loss of NOK 2.0 billion in 2009), increased average refining margin and increased contract price for methanol.
Net operating income was NOK 1.9 billion in 2011, a decrease of 21% compared to 2010.
The decreased in net operating income was primarily explained by gain of NOK 0.3 billion from the sale of Swedegas in 2010 and the difficult market conditions in central and eastern Europe in 2011.
Total SFR revenue and other income increased from NOK 65.9 billion in 2010 to NOK 73.7 billion in 2011, driven by higher underlying refined oil products prices.
At the end of 2011, Statoil's ownership interest in Statoil Fuel & Retail ASA was 54%.
Total revenue and other income increased from NOK 65.9 billion in 2010 to NOK 73.7 billion in 2011, driven by higher underlying refined oil products prices.
Road transportation fuel volumes for the full year were 8.4 billion liters down by 0.1 billion liters compared with 2010. In addition, convenience revenues increased by NOK 0.5 billion in 2011 due to increased basket size, favourable initiatives within the food line and car wash areas, as well as increased duties for tobacco. Total revenue and other income in the aviation and lubricants business increased by NOK 0.25 billion and NOK 1.1 billion respectively, due to increased underlying refined oil product prices in 2011 compared with 2010.
Total revenues and other income increased from NOK 57.4 billion in 2009 to NOK 65.9 billion in 2010. The increase was mainly driven by higher underlying refined oil product prices and increased road transportation fuel volumes of 5.9%. The increase in road transportation fuel volume was primarily due to organic growth and the consolidation of JET-branded stations in the second half of 2009. The cold weather and high electricity prices in the first and fourth quarter of 2010 resulted in higher demand for stationary energy, such as heating oil, compared with the same period in 2009.
Purchase [net of inventory variation] increased from NOK 54.8 billion in 2010 to NOK 63.6 billion in 2011, explained by the same factors described under total revenues and other income. Purchase, net of inventory variation increased from NOK 46.9 billion in 2009 to NOK 54.8 billion in 2010, explained by the same factors described under total revenues and other income.
Operating expenses and selling, general and administrative expenses were down 5% to NOK 7.1 billion in 2011, mainly due to stringent cost control and effects from the cost savings programme. The cost savings programme targets cost elements across Fuel & Retail`s value chain, aiming at reducing purchases as well as operating expenses. This was partly offset by increased stand-alone and separation costs of NOK 0.1 billion, due to SFR being a separate publicly listed company.
Operating expenses and selling, general and administrative expenses decreased by 8% in 2010 compared with 2009. The decrease was mainly driven by divestments of non-core business activities, improved portfolio management, reduced credit losses in Central and Eastern Europe and the closure of stations with low throughput and profitability in Scandinavia during 2010. This decrease was partly offset by increased administrative expenses due to increased corporate headquarter costs as Fuel & Retail was separated from Statoil ASA and listed on the Oslo stock exchange in October 2010.
Depreciation, amortisation and net impairment losses decreased from NOK 1.3 billion in 2010 to NOK 1.2 for the full year 2011, primarily due to an impairment in 2010 of NOK 0.1 billion. Depreciation, amortisation and net impairment losses totalled NOK 1.3 billion in 2010, compared with NOK 1.2 billion in 2009. The increase was mainly due to impairment of NOK 0.1 billion in 2010, which was largely related the Fuel & Retail network in Lithuania.
In 2011 net operating income decreased by NOK 0.5 billion, to 1.9 billion compared with 2010. The decrease was primarily explained by the gain of NOK 0.3 billion from the sale of Swedegas in the first quarter of 2010. .
In 2010, net operating income was NOK 2.4 billion, compared with NOK 1.3 billion in 2009. Net operating income in 2010 was positively impacted by increased volumes and the effect of improved micro market pricing and implementation of the company owned company operated (COCO) fuel concept. Moreover, the consolidation of JET-branded stations in the second half of 2009 and continued implementation of cost reductions and efficiency initiatives, including divestments of non-core business activities, contributed to increased net operating income in 2010 compared with 2009. A gain of NOK 0.3 billion from the sale of Swedegas was also included in other income in 2010.
The Other reporting segment includes activities within Global Strategy and Business Development; Technology, Projects and Drilling; and Corporate Staffs and Services.
In 2011, the Other reporting segment recorded a net operating loss of NOK 0.3 billion, compared to a net operating income of NOK 0.6 billion in 2010, and a net operating loss of NOK 0.7 billion in 2009. The decrease in net operating income from 2010 to 2011 was mainly driven by a gain from the sale of Tampnet, a communication network between offshore installations, to HitecVision in 2010. The increase in net operating income from 2009 to 2010 was driven by the gain on sale of Tampnet.
This section explains some of the terms used when reporting volumes, such as lifted entitlement volumes, equity volumes, entitlement volumes and proved reserves.
Volumes that explain revenues
Volumes of lifted liquids (crude oil, condensate and natural gas liquids) and natural gas correlate with production over time, but they may be higher or lower than entitlement production for the period due to operational factors that affect the timing of the lifting of the liquids from the fields by Statoil-chartered vessels. Volumes of natural gas produced on the NCS are deemed to be equal to lifted volumes of natural gas from the Norwegian continental shelf (NCS).
Volumes of lifted liquids and natural gas may be sold or put into storage. The volumes that give rise to revenues from the sale of liquids and natural gas in the period are therefore equal to lifted volumes plus changes in inventories of liquids and natural gas.
Volumes that explain operating expenses
Equity volumes represent produced volumes that correspond to Statoil's percentage ownership interest in a particular field. Entitlement volumes, on the other hand, represent Statoil's share of the volumes distributed under a PSA to the partners in the field, which are subject to deductions for, among other things, royalties and the host government's share of profit oil. Under the terms of a PSA, the amount of profit oil deducted from equity volumes will normally increase with the cumulative return on investment to the partners and/or production from the licence. The distinction between equity and entitlement is relevant to most PSA regimes. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Libya, Nigeria and Russia.
Volumes of proved reserves
We believe that our established liquidity reserves, credit rating and access to capital markets provide us with sufficient working capital for our foreseeable requirements.
Statoil delivered strong cash flows in 2011, mainly as a result of increased cash flows from operating activities and continued portfolio optimisation.
Cash flows provided by operations
Cash flows provided by operations amounted to NOK 80.8 billion in 2010, compared with NOK 73.1 billion in 2009. The increase of NOK 7.7 billion was primarily due to higher cash flows from income before tax and NOK 8.2 billion lower tax payments. These changes were partly offset by a negative change in working capital of NOK 15.2 billion between 2010 and 2009. The use of cash from working capital in 2010 of NOK 10.6 billion was mainly due to an increase in trade and other receivables as a result of higher prices for gas and liquids. In addition, increase in current financial investments of NOK 7.2 billion reflected use of excess cash in 2010 for financial investments.
Cash flows used in investing activities
Approximately 45% of the investments in 2011 were investments in assets expected to contribute to growth in oil and gas production, including capitalized exploration, while approximately 20% relate to investments in currently producing fields. The remaining 5% represent investments in Statoil's other activities and 30% are related to the acquisition of Brigham Exploration Company.
In 2010, cash flows used in investing activities amounted to NOK 76.5 billion, an increase of NOK 1.4 billion from 2009.
Approximately 54% of the investments in 2010 were investments in assets expected to contribute to growth in oil and gas production, while approximately 32% relate to investments in currently producing fields. The remaining 14% represent investments in Statoil's other activities.
Gross investments amounted to NOK 84.4 billion in 2010, approximately at the same level as in 2009, when gross investments amounted to NOK 86.2 billion.
Cash flows used in investing activities are reconciled with gross investments in the table below. For 2011, other changes include additions to property plant and equipment and intangible assets related to Brigham Exploration Company. In 2011 and 2010, the difference between cash flows to investments and gross investments is largely related to proceeds from sales of assets. In 2009, the difference between cash flows to investments and gross investments is largely related to financial lease.
Cash flows used in/provided by financing activities
New non-current bonds in 2011 amounted to NOK 10.1 billion, compared with NOK 15.6 billion in 2010. NOK 7.4 billion of non-current bonds was repaid in 2011, compared with NOK 3.2 billion in 2010.
Net cash flows used in financing activities in 2011 include a dividend of NOK 19.9 billion paid by Statoil ASA to shareholders relating to the annual accounts for 2010, while the dividend paid by Statoil ASA to its shareholders in 2010 relating to the annual accounts for 2009 amounted to NOK 19.1 billion.
Net cash flows used in financing activities in 2010 amounted to NOK 0.9 billion, compared with cash flows provided of NOK 11.3 billion in 2009. The NOK 12.2 billion change was mainly related to a net change in non-current bonds of NOK 29.2 billion due to fewer new bonds being issued in 2010 compared with 2009. The change was partly offset by a change in the net cash flow from non-controlling interests of NOK 5.1 billion. This was mainly related to cash received from Statoil Fuel & Retail ASA shareholders for 46% of Statoil Fuel & Retail's shares, a change of NOK 4.0 billion in dividends paid and a change of NOK 7.9 billion in net current bonds, bank overdrafts and other (other includes collateral liabilities that are used as the security for trading activities).
New non-current bonds in 2010 amounted to NOK 15.6 billion, compared with NOK 46.3 billion in 2009. Of the total new non-current bonds in 2010, NOK 4.0 billion is related to the funding of Statoil Fuel & Retail ASA. The proceeds from the SFR drawdown were applied to repay intercompany debt to Statoil ASA. NOK 3.2 billion of non-current bonds was repaid in 2010, compared with NOK 4.9 billion in 2009.
Net cash flows used in financing activities in 2010 include a dividend of NOK 19.1 billion paid by Statoil ASA to shareholders relating to the annual accounts for 2009, while the dividend paid by Statoil ASA to its shareholders in 2009 relating to the annual accounts for 2008 amounted to NOK 23.1 billion.
The following tables contain selected financial information relating to our balance sheet and financial ratios that form part of the basis for the subsequent analysis of financial assets and liabilities.
Gross interest-bearing financial liabilities were NOK 131.5 billion at the end of 2011, while net interest-bearing financial liabilities before adjustments were NOK 71.0 billion. The net debt to capital employed ratio before adjustments was 19.9%.
The increase of NOK 15.7 billion was due to increases in current assets such as inventories of NOK 4.1 billion, trade and other receivables of NOK 28.5 billion, current financial investments of NOK 8.4 billion, cash and cash equivalents of NOK 10.1 billion and decrease in other current receivables of NOK 0.1 billion. This was partly offset by increases in current liabilities such as bonds, bank loans, commercial papers and collateral liabilities of NOK 8.1 billion, current tax payable of NOK 7.6 billion, trade and other payables of NOK 20.2 billion and a decrease in other current liabilities of NOK 1.1 billion.
We believe that, given Statoil's established liquidity reserves (including committed credit facilities) and Statoil's credit rating and access to capital markets, Statoil has sufficient working capital for its foreseeable requirements. Our main sources of liquidity are described below.
Management of the portfolio of security investments, mainly related to equity securities, is held by our insurance captive, Statoil Forsikring AS, and commercial papers and money market investments held by Statoil ASA.
As of 31 December 2011, cash and cash equivalents and current financial investments amounted in total to NOK 60.5 billion, including NOK 40.6 billion in cash and cash equivalents and NOK 19.9 billion in current financial investments (domestic and international capital market investments). Cash and cash equivalents include NOK 4.3 billion deposited with Statoil's US dollar-denominated bank account in Nigeria. There are certain restrictions on the use of cash from Statoil's Nigerian operations following an injunction against Statoil by the Nigerian courts relating to an on-going litigation claim. Both the injunction and the disputed claim have been appealed. Of the total restricted cash at 31 December 2011, NOK 3.9 billion is no longer to be reported as restricted cash from March 2012. Approximately 42% of our liquid assets were held in NOK-denominated assets, 25% in USD, 10% in CHF, 9% in EUR and 14% in other currencies (GBP, DKK), before the effect of currency swaps and forward contracts.
As of 31 December 2010, cash and cash equivalents and current financial investments amounted in total to NOK 42.0 billion, including NOK 30.5 billion in cash and cash equivalents and NOK 11.5 billion in current financial investments (domestic and international capital market investments). Cash and cash equivalents include NOK 2.6 billion deposited with Statoil's US dollar-denominated bank account in Nigeria. Approximately 44% of our liquid assets were held in EUR-denominated assets, 21% in USD, 16% in NOK and 19% in other currencies (GBP, DKK, CAD, BRL), before the effect of currency swaps and forward contracts.
Our general policy is to maintain a liquidity reserve in the form of cash and cash equivalents in our balance sheet, and committed, unused credit facilities and credit lines in order to ensure that we have sufficient financial resources to meet our short-term requirements. Long-term funding is raised when we identify a need for such financing based on our business activities and cash flows, and when market conditions are considered favourable.
The USD 3 billion multi-currency revolving credit facility that Statoil ASA, guaranteed by Statoil Petroleum AS, has available from a group of 20 international banks, had its term extended by one year until December 2016. Through one more extension option the facility may be further extended to December 2017. Up to one third of the facility may be utilised in the form of swing line advances, i.e. drawdowns available on a same day notice and with maximum maturities of ten days.
To secure financial flexibility, Statoil ASA issued new debt securities in 2011 in the amount of USD 0.65 billion maturing in November 2016, USD 0.75 billion maturing in January 2022 and USD 0.35 billion maturing in November 2041 (an aggregate amount of NOK 10.1 billion). Correspondingly, Statoil ASA issued new debt securities in 2010 in the amount of USD 1.25 billion maturing in August 2017 and USD 0.75 billion maturing in August 2040 (an aggregate amount of NOK 11.5 billion). All of the bonds are guaranteed by Statoil Petroleum AS.
On 1 November 2010, Statoil Fuel & Retail ASA drew down NOK 4.0 billion on its term loan facility, maturing in 2013. The facility is part of a multicurrency term and revolving loan facility in the aggregate amount of NOK 7.0 billion that has been entered into with nine international banks. In addition to the NOK 4.0 billion three-year term loan already drawn, the total facility agreement includes a NOK 3.0 billion five-year revolving loan facility.
In 2012, Statoil aims to continue to secure financial flexibility and, depending, among other things, on oil and gas price developments, it may issue bonds should market conditions be viewed as attractive. See the section Risk review - Risk management - Managing financial risk for more information about liquidity.
Gross interest-bearing financial liabilities
At 31 December 2010, the financial lease of NOK 8.6 billion related to the Peregrino FPSO vessel, was reclassified from non-current bonds, bank loans and finance lease liabilities to held for sale. In the second quarter of 2011 the financial lease of NOK 4.9 billion related to Statoil's share of the Peregrino FPSO vessel, was reclassified from held for sale to non-current bonds, bank loans and finance lease liabilities.
Gross interest-bearing financial liabilities were NOK 111.5 billion at 31 December 2010, compared with NOK 104.1 billion at 31 December 2009. The NOK 7.4 billion increase was due to a combination of an increase of NOK 3.8 billion in non-current bonds, bank loans and finance lease liabilities and an increase of NOK 3.6 billion in current bonds, bank loans, commercial papers and collateral liabilities .
For risk management purposes, currency swaps are used to ensure that Statoil keeps non-current interest-bearing financial liabilities in USD. As a result, most of the group's non-current bonds, bank loans and finance lease liabilities are exposed to changes in the USD/NOK exchange rate.
Net interest-bearing financial liabilities
Net interest-bearing financial liabilities adjusted were NOK 76.0 billion at 31 December 2011, compared with NOK 77.4 billion at 31 December 2010. The decrease of NOK 1.4 billion was mainly related to an increase in cash and cash equivalents and current financial investments of NOK 18.5 billion, partly offset by an increase in gross interest-bearing financial liabilities of NOK 20.0 billion and an increased change in non-GAAP adjustments to net interest-bearing financial liabilities before adjustments of NOK 2.7 billion.
The net debt to capital employed ratio
The net debt to capital employed ratio adjusted was 21.1% at 31 December 2011, compared with 25.5% at 31 December 2010. The 4.4 % decrease was mainly related to a decrease in net interest-bearing financial liabilities adjusted of NOK 1.4 billion in combination with an increase in capital employed adjusted of NOK 57.4 billion.
In the calculation of net interest-bearing liabilities adjusted, we make certain adjustments, which make net interest-bearing liabilities and the net debt to capital employed adjusted ratio non-GAAP financial measures. For an explanation and calculation of the ratio, see the section Financial analysis and review - Non-GAAP measures - Net debt to capital employed ratio.
The group's borrowing needs are mainly covered through the issuing of short-term and long-term securities, including utilisation of a US Commercial Paper Program and a Euro Medium Term Note (EMTN) Programme (program limits being USD 4 billion and USD 8 billion, respectively) as well as issues under a US Shelf Registration Statement, and through draw-downs under committed credit facilities and credit lines. After the effect of currency swaps, 100% of our borrowings are in USD.
The management of financial assets and liabilities take into consideration funding sources, the maturity profile of non-current bonds, interest rate risk management, currency risk and the management of liquid assets. Our borrowings are denominated in various currencies and swapped into USD, since the largest proportion of our net cash flow is denominated in USD. In addition, we use interest rate derivatives, primarily consisting of interest rate swaps, to manage the interest rate risk of our long-term debt portfolio. The company's central finance function manages the funding, liability and liquidity activities at group level.
Cash, cash equivalents and current financial investments
Cash and cash equivalents were NOK 40.6 billion at 31 December 2011, compared with NOK 30.5 billion at 31 December 2010. Current financial investments, which are part of our cash management, amounted to NOK 19.9 billion at 31 December 2011, compared with NOK 11.5 billion at 31 December 2010.
The table summarises our principal contractual obligations and other commercial commitments as of 31 December 2011.
The table includes contractual obligations, but excludes derivatives and other hedging instruments as well as asset retirement obligations, as these obligations for the most part are expected to lead to cash disbursements more than five years in the future. Obligations payable by Statoil to unconsolidated equity affiliates are included gross in the table. Where Statoil includes both an ownership interest and the transport capacity cost for a pipeline in the consolidated accounts, the amounts in the table include the transport commitments that exceed Statoil's ownership share. See also the report section Risk review - Risk management - Disclosures about market risk, for more information.
Non-current financial liabilities in the table represent principal payment obligations. For information on interest commitments relating to long-term debt, reference is made to note 22 - Bonds, bank loans and finance lease liabilities and note 27 - Leases, to our Consolidated Financial Statements included in this report.
Contractual commitments relating to capital expenditures, acquisitions of intangible assets and construction in progress amounted to NOK 40.1 billion as of 31 December 2011, payment of NOK 25.2 billion of which are due within one year.
The group's projected pension benefit obligation was NOK 75.0 billion, and the fair value of plan assets amounted to NOK 52.0 billion as of 31 December 2011. Actuarial losses amounted to NOK 7,364 million as of 31 December 2011 and are reported as part of the Consolidated statement of comprehensive income. Company contributions are mainly related to employees in Norway.
Our investments in 2011 were higher than in 2010 mainly due to the acquisition of Brigham Exploration Company.
This section describes our estimated capital expenditure for 2012 relating to potential capital expenditure requirements for the principal investment opportunities available to us and other capital projects currently under consideration. The figure is based on Statoil developing organically, and it excludes possible expenditures relating to acquisitions. The expenditure estimates and descriptions of investments in the segment descriptions below could therefore differ materially from the actual expenditure. For more information about the various projects in each of the segments, see the respective sub-sections described under the operational and financial review.
We finance our capital expenditures both internally and externally. For more information, see the section Financial analysis and review - Liquidity and capital resources - Financial assets and liabilities.
A substantial proportion of our 2012 capital expenditure will be spent on ongoing and planned development projects in Norway such as Dagny, Goliat, Gudrun, Hyme, Luva, Skarv, Skuld, Valemon, Visund South, the Gullfaks fields and IOR projects.
We currently estimate that a substantial proportion of our 2012 capital expenditure will be spent on the following ongoing and planned development projects internationally: CLOV, PSVM and Pazflor in Angola, In Salah Southern Fields in Algeria, Corrib in Ireland, Jack, St. Malo and BigFoot in the US Gulf of Mexico, Marcellus, Eagle Ford and Bakken onshore USA, and Peregrino in Brazil.
We currently estimate that most of the 2012 capital expenditures spent on midstream and downstream projects will be related to transport solutions for Marcellus Shale Gas, Eagle Ford and on the NCS.
As illustrated in the section Financial analysis and review - Liquidity and capital resources - Principal contractual obligations, we have committed to certain investments in the future. The proportion of estimated investments that we have committed to at year end 2011 will decline with time. The further into the future, the more flexibility we will have to revise expenditure. This flexibility is partly dependent on the expenditure our partners in joint ventures agree to commit to.
We use the "successful efforts" method of accounting for oil and natural gas-producing activities. Expenditure on drilling and equipping exploratory wells is capitalised until it is clarified whether there are proved reserves. Expenditure on drilling exploratory wells that do not find proved reserves and geological, geophysical and other exploration expenditure is expensed. Unproved oil and gas properties are assessed quarterly; unsuccessful wells are expensed. Exploratory wells that have found reserves, but where classification of those reserves as proved depends on whether major capital expenditure can be justified, may remain capitalised for more than one year. The main conditions are either that firm plans exist for future drilling in the licence or that a development decision is planned in the near future.
Finally, we may alter the amount, timing or segmental or project allocation of our capital expenditure in anticipation of or as a result of a number of factors outside our control, including, but not limited to:
Our results in recent years have been affected by increases in the price of raw materials and services that are necessary for the development and operation of oil and gas-producing assets.
Although price pressure has abated since it peaked in 2008, our results have been significantly affected in the last few years by inflation in the cost of certain raw materials and services that are necessary for the development and operation of oil and gas-producing assets. Other parts of our business are not exposed to similar cost pressures.
While some of the cost pressure relates to capitalised expenditures and thus only affects our annual profit through increased depreciation, certain elements of operating expenditures have also been affected by this inflation. See our analysis of profit and loss as well as the Group outlook section in the section Financial analysis and review - Operating and financial review 2011.
As measured by the general consumer price index, average annual inflation in Norway for the years ended 31 December 2011, 2010 and 2009 was 1.2%, 2.5% and 2.1% respectively.
This section describes key sources of estimation uncertainty and the critical judgements that the group has made when applying accounting policies.
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). This means that we are required to make estimates and assumptions. We believe that, of the company's significant accounting policies (see note 2 - Significant accounting policies, to our consolidated financial statements included in this report), the following may involve a greater degree of judgement and complexity, which, in turn, could materially affect the net income if various assumptions were significantly changed.
Critical judgements when applying accounting policies
Revenue recognition - gross versus net presentation of traded SDFI volumes of oil and gas production
Statoil sells, in its own name, but for the Norwegian State's account and risk, the State's production of natural gas. These gas sales, and related expenditures refunded by the State, are shown net in Statoil's financial statements. In making the judgment, Statoil considered the same criteria as for the oil production and concluded that the risk and reward of the ownership of the gas had not been transferred from the SDFI to Statoil.
Proportionate gain recognition when forming joint ventures by reducing shares in subsidiaries
Key sources of estimation uncertainty
Statoil is exposed to a number of underlying economic factors, such as liquids prices, natural gas prices, refining margins, foreign exchange rates, interest rates as well as financial instruments with fair values derived from changes in these factors, which affect the overall results. In addition, Statoil's results are influenced by the level of production, which in the short term may be influenced by for instance maintenance programmes. In the long term, the results are impacted by the success of exploration and field development activities.
The matters described below are considered to be the most important in understanding the key sources of estimation uncertainty that are involved in preparing these financial statements and the uncertainties that could most significantly impact the amounts reported on the results of operations, financial position and cash flows.
Proved oil and gas reserves have been estimated by internal experts on the basis of industry standards and governed by criteria established by regulations of the SEC, which requires the use of a price based on a 12-month average for reserve estimation. The Financial Accounting Standards Board (FASB) requirements for supplemental oil and gas disclosures align with the SEC regulations.
Reserves estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbons volumes, the production, historical extraction recovery and processing yield factors and installed plant operating capacity. For future development projects, proved reserves estimates are included only where there is a significant commitment to project funding and execution and when relevant governmental and regulatory approvals have been secured or are reasonably certain to be secured. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. An independent third party has evaluated Statoil's proved reserves estimates, and the results of such evaluation do not differ materially from management estimates. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. Unless evidence indicates that renewal is reasonably certain, estimates of economically producible reserves only reflect the period before the contracts providing the right to operate expire. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence within a reasonable time. Future changes in proved oil and gas reserves, for instance as a result of changes in prices, could have a material impact on unit of production rates used for depreciation and amortisation.
Expected oil and gas reserves are the estimated remaining, commercially recoverable quantities, based on Statoil's judgment of future economic conditions, from projects in operation or justified for development. Recoverable oil and gas quantities are always uncertain and the expected value is the weighted average, or statistical mean, of the possible outcomes. Expected reserves are therefore typically larger than what is referred to as proved reserves as defined by the SEC rules, which should be based on existing economic conditions and operating methods and with a high degree of confidence (at least 90% probability) that the quantities will be recovered. Expected oil and gas reserves have been estimated by internal experts on the basis of industry standards and are used for impairment testing purposes and for calculation of asset retirement obligations. Reserves estimates are based on subjective judgments involving geological and engineering assessments of in-place hydrocarbons volumes, the production, historical extraction recovery and processing yield factors, installed plant operating capacity and operating approval limits. The reliability of these estimates at any point in time depends on both the quality and quantity of the technical and economic data and the efficiency of extracting and processing the hydrocarbons. Future changes in expected oil and gas reserves, for instance as a result of changes in prices, could have a material impact on asset retirement obligations, as well as for the impairment testing of upstream assets, which could have a material effect on operating income as a result of changed impairment charges.
Exploration and leasehold acquisition costs. Statoil capitalises the costs of drilling exploratory wells pending determination of whether the wells have found proved oil and gas reserves. Statoil also capitalises leasehold acquisition costs and signature bonuses paid to obtain access to undeveloped oil and gas acreage. Judgments as to whether these expenditures should remain capitalised or written down due to impairment losses in the period may materially affect the operating income for the period.
Impairment/reversal of impairment. Statoil has significant investments in property, plant and equipment and intangible assets. Changes in the circumstances or expectations of future performance of an individual asset may be an indicator that the asset is impaired requiring the book value to be written down to its recoverable amount. Impairments are reversed if conditions for impairment are no longer present. Evaluating whether an asset is impaired or if an impairment should be reversed requires a high degree of judgement and may to a large extent depend upon the selection of key assumptions about the future.
Unproved oil and gas properties are assessed for impairment when facts and circumstances suggest that the carrying amount of the asset may exceed its recoverable amount and at least annually. If, following evaluation, an exploratory well has not found proved reserves, the previously capitalised costs are tested for impairment. Subsequent to the initial evaluation phase for a well it will be considered a trigger for impairment testing of a well if no development decision is planned for the near future, and there moreover is no concrete plan for future drilling in the licence. Impairment of unsuccessful wells is reversed, as applicable, to the extent that conditions for impairment are no longer present.
Estimating recoverable amounts involves complexity in estimating relevant future cash flows, based on assumptions about the future, and discounted to their present value. Impairment testing requires long-term assumptions to be made concerning a number of often volatile economic factors such as future market prices, refinery margins, currency exchange rates and future output, discount rates and political and country risk among others, in order to establish relevant future cash flows. Impairment testing frequently also requires judgement regarding probabilities and probability distributions as well as levels of sensitivity inherent in the establishment of recoverable amount estimates, and consequently in ensuring that the recoverable amount estimates' robustness where relevant is factored sufficiently into the impairment evaluations and reflected in the impairment or reversal of impairment recognised in the financial statements. Long-term assumptions for major economic factors are made at group level, and there is a high degree of reasoned judgement involved in establishing these assumptions, in determining other relevant factors such as forward price curves, in estimating production outputs, and in determining the ultimate termination value of an asset.
Employee retirement plans. When estimating the present value of defined pension benefit obligations that represent a gross long-term liability in the balance sheet, and indirectly, the period's net pension expense in the statement of income, management make a number of critical assumptions affecting these estimates. Most notably, assumptions made about the discount rate to be applied to future benefit payments, the expected return on plan assets and the annual rate of compensation increase have a direct and potentially material impact on the amounts presented. Significant changes in these assumptions between periods can have a material effect on the financial statements.
Asset retirement obligations. Statoil has significant obligations to decommission and remove offshore installations at the end of the production period. Legal and constructive obligations associated with the retirement of non-current assets are recognised at their fair value at the time the obligations are incurred. Upon initial recognition of a liability, that cost is capitalised as part of the related non-current asset and allocated to expense over the useful life of the asset.
It is difficult to estimate the costs of these decommissioning and removal activities, which are based on current regulations and technology, considering relevant risks and uncertainties. Most of the removal activities are many years into the future and the removal technology and costs are constantly changing. The estimates include assumptions of both the time required and the day rates for rigs, marine operations and heavy lift vessels that can vary considerably depending on the assumed removal complexity. As a result, the initial recognition of the liability and the capitalised cost associated with decommissioning and removal obligations, and the subsequent adjustment of these balance sheet items, involve the application of significant judgement.
Derivative financial instruments. When not directly observable in active markets, the fair value of derivative contracts must be computed internally based on internal assumptions as well as directly observable market information, including forward and yield curves for commodities, currencies and interest. Changes in internal assumptions and forward curves could materially impact the internally computed fair value of derivative contracts, particularly long-term contracts, resulting in corresponding impact on income or loss in the consolidated statement of income.
Income tax. Statoil annually incurs significant amounts of income taxes payable to various jurisdictions around the world, and also recognises significant changes to deferred tax assets and deferred tax liabilities, all of which are based on management's interpretations of applicable laws, regulations and relevant court decisions. The quality of these estimates is highly dependent upon management's ability to properly apply at times very complex sets of rules, to recognise changes in applicable rules and, in the case of deferred tax assets, management's ability to project future earnings from activities that may apply loss carry forward positions against future income taxes.
This section describes various agreements that are not recognised in the balance sheet, such as operational leases and transportation and processing capacity contracts.
We have entered into various agreements, such as operational leases and transportation and processing capacity contracts, that are not recognised in the balance sheet. For more information, see the section Financial analysis and review - Liquidity and capital resources - Principal contractual obligations and note 27 - Leases to the Consolidated financial statements.
We are not party to any off-balance sheet arrangements such as the use of variable interest entities, derivative instruments that are indexed to our own shares and classified in shareholder's equity, or contingent assets transferred to an unconsolidated equity.
The group is party to certain guarantees, commitments and contingencies that, pursuant to IFRS, are not necessarily recognised in the balance sheet as liabilities. See note 28 - Other commitments and contingencies in the Consolidated financial statements, for more information.
This section describes the non-GAAP financial measures that are used in this report.
We are subject to SEC regulations regarding the use of "non-GAAP financial measures" in public disclosures. Non-GAAP financial measures are defined as numerical measures that either exclude or include amounts that are not excluded or included in the comparable measures calculated and presented in accordance with generally accepted accounting principles, which in our case refers to IFRS.
The following financial measures may be considered non-GAAP financial measures:
We use ROACE to measure the return on capital employed, regardless of whether the financing is through equity or debt.
In the company's view, this measure provides useful information for both the company and investors about performance during the period under evaluation. We make regular use of this measure to evaluate our operations. Our use of ROACE should not be viewed as an alternative to income before financial items, income taxes and minority interest, or to net income, which are measures calculated in accordance with generally accepted accounting principles or ratios based on these figures.
ROACE was 22.1% in 2011, compared to 12.6% in 2010 and 10.6% in 2009. The increase from last year was due to doubling of net income adjusted for financial items after tax, slightly offset by a 15% increase in capital employed. The increase from 2009 to 2010 was due to an increase in net income adjusted for financial items after tax, partly offset by a relatively lower increase in capital employed.
(1) Calculated Tax on Financial Items for the year is calculated as the net financial items multiplied by the statutory tax rate in the jurisdiction in which the financial items arose.
In order to evaluate the underlying development in production costs, the production cost is computed on the basis of entitlement volumes and equity volumes.
Significant parts of Statoil's international production are subject to production-sharing agreements with countries' authorities. Under these agreements, we cover our share of the operating expenditures relating to the equity volumes produced. Our international production costs are thus affected by the amount of equity barrels produced, more than by the entitlement volumes received. In order to exclude the effects that production-sharing agreements have on entitlement volumes (PSA effects), we also provide the unit of production cost based on equity volumes.
The following is a reconciliation of our overall operating expenses with production cost per year as used when calculating the unit of production cost per oil equivalent of entitlement and equity volumes.
Entitlement volumes are highly affected by the PSA effects. On average, equity volumes exceeded entitlement volumes by 200 mboe per day in 2011, 182 mboe per day in 2010 and 156 mboe per day in 2009. With the same cost basis, but higher volumes, the cost per barrel of equity volumes produced will always be lower than the cost per barrel of entitlement volumes. Based on equity volumes, the average production cost was NOK 43.1 per boe in 2011, compared with NOK 38.6 per boe in 2010 and NOK 35.3 per boe in 2009. The adjusted production cost per boe for 2011 was NOK 42.4, compared with NOK 37.9 per boe in 2010 and NOK 35.3 per boe in 2009 based on equity volumes. The adjustments to production cost are reversal of cost related to merger, restructuring and gas injection costs.
In the company's view, the calculated net debt to capital employed ratio gives a more complete picture of the group's current debt situation than gross interest-bearing financial liabilities.
The calculation uses balance sheet items relating to gross interest bearing financial liabilities and adjusts for cash, cash equivalents and short-term investments. Certain adjustments are made, since different legal entities in the group lend to projects and others borrow from banks. Project financing through an external bank or similar institution will not be netted in the balance sheet and will over-report the debt stated in the balance sheet in relation to the underlying exposure in the group. Similarly, certain net interest-bearing debts incurred from activities pursuant to the Owners Instruction from the Norwegian State are set off against receivables on the Norwegian State's direct financial interest (SDFI).
The net interest-bearing debt adjusted for these two items is included in the average capital employed.
The table below reconciles the net interest-bearing liabilities adjusted, capital employed and net debt to capital employed adjusted ratio with the most directly comparable financial measure or measures calculated in accordance with GAAP.
(1) Adjustments other interest-bearing elements are cash and cash equivalents adjustments regarding collateral deposits classified as cash and cash equivalents in the balance sheet but considered as non-cash in the non-GAAP calculations as well as financial investments in Statoil Forsikring classified as current financial investements.
We prepare our consolidated financial statements in accordance with International Financial Reporting Standards (IFRS) as adopted by the EU and as issued by the International Accounting Standards Board.
We prepared our first set of consolidated financial statements pursuant to IFRS for 2007. The IFRS standards have been applied consistently to all periods presented in the consolidated financial statements and when preparing an opening IFRS balance sheet as of 1 January 2006 (subject to certain exemptions allowed by IFRS 1) for the purpose of the transition to IFRS.
Our overall risk management approach includes identifying, evaluating and managing risk in all our activities to ensure safe operations and to achieve our corporate goals.
We are exposed to a number of risks that could affect our operational and financial performance. In this section, we address some of the key risk factors.
This section describes the most significant potential risks relating to our business, such as oil prices, operational risks, competition and international relations.
A substantial or prolonged decline in oil or natural gas prices would have a material adverse effect on us.
It is impossible to predict future price movements for oil and natural gas with certainty. A prolonged decline in oil and natural gas prices will adversely affect our business, the results of our operations, our financial condition, our liquidity and our ability to finance planned capital expenditure. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators could lead to further reviews for impairment of the group's oil and natural gas properties. Such reviews would reflect the management's view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the results of our operations in the period in which it occurs. Rapid material and/or sustained reductions in oil, gas and product prices can have an impact on the validity of the assumptions on which strategic decisions are based and can have an impact on the economic viability of projects that are planned or in development. For an analysis of the impact of changes in oil and gas prices on net operating income, see Risk Review - Risk management.
Exploratory drilling involves numerous risks, including the risk that we will encounter no commercially productive oil or natural gas reservoirs. This could materially adversely affect our results.
We are exposed to a wide range of health, safety, security and environmental risks that could result in significant losses.
Our crisis management systems may be ineffective.
If we fail to acquire or find and develop additional reserves, our reserves and production will decline materially from their current levels.
In a number of resource-rich countries, national oil companies control a significant proportion of oil and gas reserves that remain to be developed. To the extent that national oil companies choose to develop their oil and gas resources without the participation of international oil companies or if we are unable to develop partnerships with national oil companies, our ability to find and acquire or develop additional reserves will be limited.
Our future production is highly dependent on our succeeding in finding or acquiring and developing additional reserves. If we are unsuccessful, we may not meet our long-term ambitions for growth in production, and our future total proved reserves and production will decline, adversely affecting the results of our operations and financial condition.
We encounter competition from other oil and natural gas companies in all areas of our operations, including the acquisition of licences, exploratory prospects and producing properties.
Some of our competitors are much larger, well-established companies with substantially greater resources. In many instances, they have been engaged in the oil and gas business for much longer than we have. These larger companies are developing strong market power through a combination of different factors, including:
These companies may be able to pay more for exploratory prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects, including operatorships and licences. They may also be able to invest more in developing technology than our financial or human resources permit. Our performance could be impeded if competitors were to develop or acquire intellectual property rights to technology that we require or if our innovation were to lag behind the industry. For more information on the competitive environment, see Operational Review - Competition.
Our development projects and production activities involve many uncertainties and operating risks that can prevent us from realising profits and cause substantial losses.
Our development projects and production activities on the NCS also face the challenge of remaining profitable. We are increasingly developing smaller satellite fields in mature areas, and our activities are subject to the Norwegian State's relatively high taxes on offshore activities. In addition, our development projects and production activities, particularly those in remote areas, could become less profitable, or unprofitable, if we experience a prolonged period of low oil or gas prices or cost overruns.
We face challenges in achieving our strategic objective of successfully exploiting growth opportunities.
Our ability to successfully implement this strategy will depend on a variety of factors, including our ability to:
As we pursue business opportunities in new and existing markets, we anticipate significant investments and costs in connection with the development of such opportunities. We may incur or assume unanticipated liabilities, losses or costs associated with assets or businesses acquired. Any failure by us to successfully pursue and exploit new business opportunities could result in financial losses and inhibit growth.
Any such new projects we acquire will require additional capital expenditure and will increase the cost of our discoveries and development. These projects may also have different risk profiles than our existing portfolio. These and other effects of such acquisitions could result in our having to revise either or both of our forecasts with respect to unit production costs and production.
In addition, the pursuit of acquisitions or new business opportunities could divert financial and management resources away from our day-to-day operations to the integration of acquired operations or properties. We may require additional debt or equity financing to undertake or consummate future acquisitions or projects, and such financing may not be available on terms satisfactory to us, if at all, and it may, in the case of equity, be dilutive to our earnings per share.
The sovereign debt situation in Europe may affect our business.
We may fail to attract and retain senior management and skilled personnel.
We face challenges in the renewable energy sector.
We may not be able to produce some of our oil and gas economically due to the lack of necessary transportation infrastructure when a field is in a remote location.
Some of our international interests are located in politically, economically and socially unstable areas, which could disrupt our operations.
Our operations are subject to political and legal factors in the countries in which we operate.
The likelihood of these occurrences and their overall effect on us vary greatly from country to country and are not predictable. If such risks materialise, they could cause us to incur material costs and/or cause our production to decrease, potentially having a material adverse effect on our operations or financial condition.
Due to the outbreak of political unrest in Libya in February 2011, the USA, UN, EU and several countries implemented certain sanctions, and Statoil's Libyan operations were suspended. While the sanctions on Libya were largely lifted by the end of 2011 and our production in Libya is resuming, the future impact of the unrest and potential political changes is uncertain.
Our activities in certain countries could lead to US and other sanctions
On 30 September 2010, the US State Department announced that Statoil was eligible to avoid sanctions under the Comprehensive Iran Sanctions, Accountability and Divestment Act of 2010 (CISADA) relating to its activities in Iran because Statoil had pledged to end its investments in Iran's energy sector. In 2009, Statoil had voluntarily provided officials from the US State Department with information about its activities and investments in Iran. CISADA came into effect on 1 July 2010. Among other things, CISADA amends certain sections of the Iran Sanctions Act of 1996 (ISA). CISADA requires the President of the United States to sanction companies that make investments that enhance Iran's ability to develop petroleum resources or provide or facilitate the production or importation of refined petroleum products into Iran. Such sanctions could include prohibiting transactions in foreign exchange in which the sanctioned entity has any interest, prohibiting transfers of credit or payments via financial institutions in which the sanctioned entity has any interest, prohibiting property transactions by the sanctioned entity in which the property is subject to the jurisdiction of the United States, the denial of US bank loans,and restrictions on the importation of goods produced by the sanctioned company.
In 2010, the UN and the EU adopted new restrictive measures in relation to Iran. With effect from 14 January 2011, Norway adopted similar regulations. These restrictive measures cover the areas of trade, financial services, energy and transport, as well as additional measures relating to visa bans and asset freezes. In 2011, the US imposed additional sanctions against Iran, including restrictions on transactions with the Central Bank of Iran and lower monetary thresholds for permitted investments in Iran that could contribute to Iran's development of petroleum resources or production of petrochemical products. There is further legislation pending in the US Congress, and additional sanctions may be enacted against Iran. In January 2012, the EU imposed a ban on Iranian origin crude, among other measures, to be phased in over a period of months.
Our activities in Cuba consist of a 30% interest in six deepwater exploration blocks acquired from operator Repsol-YPF in 2006. As of 31 December 2011, we had invested USD 12.5 million in these projects. These activities are not material to our business, financial condition or results of operations, as the total amount invested in these operations represented less than 0.02% of our total assets as of 31 December 2011. While Statoil prequalified to become an operator in Cuba in the first quarter of 2011, this did not led to increased exposure in 2011.
We are also aware of initiatives by certain US states and US institutional investors, such as pension funds, to adopt or consider adopting laws, regulations or policies requiring among other things divestment from, reporting of interests in, or agreeing not to make future investments in, companies that do business with countries designated as state sponsors of terrorism. These policies could have an adverse impact on investment by certain investors in our securities.
We are exposed to potentially adverse changes in the tax regimes of each jurisdiction in which we operate.
Our insurance coverage may not adequately protect us.
In light of the incident at the BP-operated Macondo well in the Gulf of Mexico, we may not be able to secure similar coverage for the same costs. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable.
We face foreign exchange risks that could adversely affect the results of our operations. Our business faces foreign exchange risks because a large percentage of our revenues and cash receipts are denominated in USD, while sales of gas and refined products can be in a variety of currencies, and we pay dividends and a large part of our taxes in NOK. Fluctuations between the USD and other currencies may adversely affect our business and can give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues. See Risk review - Risk management - Managing financial risk - Market risk.
We are exposed to risks relating to trading and supply activities.
Although we believe we have established appropriate risk management procedures, trading activities involve elements of forecasting and Statoil bears the risk of market movements, the risk of significant losses if prices develop contrary to expectations, and the risk of default by counterparties. See Risk review - Risk management - Managing financial risk for more information about risk management. Any of these risks could have an adverse effect on the results of our operations and financial condition.
Failure to meet our ethical and social standards could harm our reputation and our business.
We set ourselves high standards of corporate citizenship and aspire to contribute to a better qualify of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.
The crude oil and natural gas reserve data in this annual report are only estimates, and our future production, revenues and expenditures with respect to our reserves may differ materially from these estimates.
Many of the factors, assumptions and variables involved in estimating reserves are beyond our control and may prove to be incorrect over time. The results of drilling, testing and production after the date of the estimates may require substantial upward or downward revisions in our reserve data. In addition, fluctuations in oil and gas prices will have an impact on our proven reserves relating to fields governed by production sharing agreements (PSAs), since part of our entitlement under PSAs relates to the recovery of development costs. Any downward adjustment could lead to lower future production and thus adversely affect our financial condition, future prospects and market value.
This section discusses potential legal and regulatory risks related to the legal context of our business operations, such as having to comply with new laws and regulations.
Compliance with health, safety and environmental laws and regulations that apply to Statoil's operations could materially increase our costs. The enactment of such laws and regulations in the future is uncertain. We incur, and expect to continue to incur, substantial capital, operating, maintenance and remediation costs relating to compliance with increasingly complex laws and regulations for the protection of the environment and human health and safety, including:
For example, under the Norwegian Petroleum Act of 29 November 1996, as a holder of licences on the NCS, we are subject to statutory strict liability in respect of losses or damage suffered as a result of pollution caused by spills or discharges of petroleum from petroleum facilities covered by any of our licences. This means that anyone who suffers losses or damage as a result of pollution caused by operations in any of our NCS licence areas can claim compensation from us without having to demonstrate that the damage is due to any fault on our part.
Furthermore, in countries where we operate or expect to operate in the near future, new laws and regulations (such as the offshore safety regulation proposed by the European Commission on 27 October 2011, if such regulation is adopted by the European Economic Area), the imposition of stricter requirements on licences, increasingly strict enforcement of or new interpretations of existing laws and regulations, the aftermath of operational catastrophes in which we or members of our industry are involved or the discovery of previously unknown contamination may require future expenditure in order to, among other things:
In particular, following the BP Deepwater Horizon oil spill in the US Gulf of Mexico, a number of regulatory changes were instituted in the US, such as the requirement to develop and implement a safety and environmental management system (SEMS programme), the drilling safety rule and the workplace safety rule. In 2011, the US authorities issued guidance to the SEMS programme. Furthermore, on 11 January 2011, the US National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its final report that set forth a number of recommendations for changes in environmental laws and regulations for offshore operations in 2010. The US government may choose to implement some of these recommendations, which could result in delays in obtaining drilling permits, approvals of exploration or oil spill response plans. Compliance with any additional regulatory requirements could require us to incur significant costs. Any such changes, delays or recertification could have a material adverse effect on our operations, results or financial condition. See also Operational Review-Applicable laws and regulations-HSE regulation.
Compliance with laws, regulations and obligations relating to climate change and other environmental regulations could result in substantial capital expenditure, reduced profitability as a result of changes in operating costs, and adverse effects on revenue generation and strategic growth opportunities. In addition, many of our mature fields are producing increasing quantities of water with oil and gas. Our ability to dispose of this water in environmentally acceptable ways may have an impact on our oil and gas production. Our investments in oil sands, shale gas and unconventional resource technologies, such as hydraulic fracturing, also may cause us to incur additional costs as regulation of these technologies continues to evolve which could affect our operations and profitability with respect to these operations.
If we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment, we could fail to live up to our aspirations of zero or minimal damage to the environment and of contributing to human progress.
The formation of a competitive internal gas market within the European Union (EU) and the general liberalisation of European gas markets could adversely affect our business.
Most of our gas is sold under long-term gas contracts to customers in the EU, a gas market that will continue to be affected by changes in EU regulations and the implementation of such regulations in EU member states. The general liberalisation of EU gas markets could affect our ability to expand or even maintain our current market position or result in a reduction in prices in our gas sales contracts.
Directive 2003/55/EC sets forth the right of third parties to non-discriminatory access to networks and to LNG and gas storage facilities. Increased access to markets has a downside insofar as it increases network access for all market participants and, therefore, competition for capacity at interconnection points within the EU. This may result in upward pressure on the price we pay for capacity at those points.
The EU initiative that is likely to impact the gas market is a scheme for greenhouse gas emission allowances trading for the cost-effective reduction of such emissions. This strengthens and extends the Emissions Trading Scheme (ETS). The Community-wide quantity of carbon allowances issued each year will decrease in a linear manner from 2013. The ETS can have a positive or negative impact on us, depending on the price of carbon, which will consequently impact the development of gas-fired power generation in the EU.
A further focus area of EU energy policy is supply security, which has led to increased focus on projects that diversify gas supplies to the EU. As a result, the Caspian region, where Statoil is participating in the Shah Deniz field, has received increasing attention from the EU. Solutions aimed at bringing Caspian gas to Europe continue to receive political support from the EU in an attempt to resolve the complex transportation issue in the region.
Political and economic policies of the Norwegian State could affect our business.
If the Norwegian State were to take additional action under its extensive powers over activities on the NCS or to change laws, regulations, policies or practices relating to the oil and gas industry, our NCS exploration, development and production activities and the results of our operations could be materially and adversely affected. For more information about the Norwegian State's regulatory powers, see Operational Review - Applicable laws and regulations.
This section discusses some of the potential risks relating to our business that could derive from the Norwegian State's majority ownership and from our involvement in the SDFI.
The interests of our majority shareholder, the Norwegian State, may not always be aligned with the interests of our other shareholders, and this may affect our decisions relating to the NCS.
The Norwegian Parliament, known as the Storting, and the Norwegian State have resolved that the Norwegian State's shares in Statoil and the SDFI's interest in NCS licences must be managed in accordance with a coordinated ownership strategy for the Norwegian State's oil and gas interests. Under this strategy, the Norwegian State has required us to continue to market the Norwegian State's oil and gas together with our own oil and gas as a single economic unit.
Pursuant to the coordinated ownership strategy for the Norwegian State's shares in Statoil and the SDFI, the Norwegian State requires us in our activities on the NCS to take account of the Norwegian State's interests in all decisions that may affect the development and marketing of our own and the Norwegian State's oil and gas.
The Norwegian State directly held 67% of our ordinary shares as of 28 February 2012. A two-thirds majority is required to decide matters put to a vote of shareholders. The Norwegian State therefore effectively has the power to influence the outcome of any vote of shareholders due to the percentage of our shares it owns, including amending our articles of association and electing all non-employee members of the corporate assembly. The employees are entitled to be represented by up to one-third of the members of the board of directors and one-third of the corporate assembly.
The corporate assembly is responsible for electing our board of directors. It also makes recommendations to the general meeting concerning the board of directors' proposals relating to the company's annual accounts, balance sheet, allocation of profit and coverage of loss. The interests of the Norwegian State in deciding these and other matters and the factors it considers when casting its votes, especially under the coordinated ownership strategy for the SDFI and our shares held by the Norwegian State, could be different from the interests of our other shareholders. Accordingly, when making commercial decisions relating to the NCS, we have to take the Norwegian State's coordinated ownership strategy into account, and we may not be able to fully pursue our own commercial interests, including those relating to our strategy for the development, production and marketing of oil and gas.
If the Norwegian State's coordinated ownership strategy is not implemented and pursued in the future, then our mandate to continue to sell the Norwegian State's oil and gas together with our own oil and gas as a single economic unit is likely to be prejudiced. Loss of the mandate to sell the SDFI's oil and gas could have an adverse effect on our position in our markets. For further information about the Norwegian State's coordinated ownership strategy, see Operational review - Applicable laws and regulations- The Norwegian State's participation.
Our overall risk management approach includes identifying, evaluating and managing risk in all of our activities. In order to achieve optimal corporate solutions, we base our risk management on an enterprise-wide risk management approach.
Statoil defines risk as a deviation from a specified reference value and the uncertainty associated with it. A positive deviation is defined as an upside risk, while a negative deviation is a downside risk. The reference value is expectation - most likely a forecast, percentile or target. We manage risk in order to ensure safe operations and to reach our corporate goals in compliance with our requirements.
We have an enterprise risk management (ERM) approach, which means that we:
All risks are related to Statoil's value chain, which denotes the value that is added in each step - from access, maturing, project and operation to market. In addition to the economic impact these risks could have on Statoil's cash flows, we also try to avoid HSE and integrity-related incidents (such as accidents, fraud and corruption). Most of the risks are managed by our principal business area line managers. Some operational risks are insurable and are managed by our captive insurance company operating in the Norwegian and international insurance markets.
Our corporate risk committee (CRC) is headed by our chief financial officer and its members include representatives of our principal business areas. It is an enterprise risk management advisory body that primarily advises the chief financial officer, but also the business areas' management on specific issues. The CRC assesses and advises on measures aimed at managing the overall risk to the group, and it proposes appropriate measures to adjust risk at the corporate level. The CRC is also responsible for reviewing, defining and developing our risk policies. The committee meets at least six times a year to decide our risk management strategies, including hedging and trading strategies, together with risk management methodologies. It regularly receives risk information relevant to the group from our corporate risk department.
We have developed policies aimed at managing the financial volatility inherent in some of our business exposures, and, in accordance with these policies, we enter into various financial and commodity-based transactions (derivatives). While the policies and mandates are set at the group level, the business areas responsible for marketing and trading commodities are also responsible for managing commodity-based price risks. The interest, liquidity, liability and credit risks are managed by the company's central finance department.
The following section describes in some detail the market risks to which we are exposed and how we manage these risks.
The results of our operations depend on a number of factors, most significantly those that affect the price we receive in Norwegian kroner (NOK) for our products.
The factors that influence the results of our operation include: the level of crude oil and natural gas prices, trends in the exchange rate between the US dollar (USD) - in which the trading price of crude oil is generally stated and to which natural gas prices are frequently related - and NOK, in which our accounts are reported and a substantial proportion of our costs are incurred; our oil and natural gas production volumes, which in turn depend on entitlement volumes under PSAs and available petroleum reserves, and our own, as well as our partners' expertise and cooperation in recovering oil and natural gas from those reserves; and changes in our portfolio of assets due to acquisitions and disposals.
Our results will also be affected by trends in the international oil industry, including possible actions by governments and other regulatory authorities in the jurisdictions in which we operate, or possible or continued actions by members of the Organization of Petroleum Exporting Countries (Opec) that affect price levels and volumes, refining margins, the cost of oilfield services, supplies and equipment, competition for exploration opportunities and operatorships, and deregulation of the natural gas markets - all of which may cause substantial changes to existing market structures and to the overall level and volatility of prices.
The following table shows the yearly averages for quoted Brent Blend crude oil prices, natural gas average sales prices, refining reference margins and the USD/NOK exchange rates for 2011, 2010 and 2009.
The illustration shows how certain changes in the crude oil price, natural gas contract prices and the USD/NOK exchange rate, if sustained for a full year, could affect our financial results in 2012.
The estimated sensitivity of our financial results to each of the factors has been estimated based on the assumption that all other factors remain unchanged. The estimated effects on our financial results would differ from those that would actually appear in our consolidated financial statements because our consolidated financial statements would also reflect the effects of depreciation, trading margins, exploration expenses, inflation, potential tax system changes and any hedging programmes in place.
Our oil and gas price hedging policy is designed to support our long-term strategic development and our attainment of targets by protecting financial flexibility and cash flows.
Fluctuating foreign exchange rates can have a significant impact on our operating results. Our revenues and cash flows are mainly denominated in or driven by USD, while our operating expenses and income taxes payable largely accrue in NOK. We seek to manage this currency mismatch by issuing or swapping non-current financial debt in USD. This debt policy is an integrated part of our total risk management programme. We also engage in foreign currency management in order to cover our non-USD needs, which are primarily in NOK. We manage the risk arising from our interest rate exposure through the use of interest rate derivatives (primarily interest rate swaps) based on a benchmark for the interest reset profile of our non-current financial liabilities portfolio. In general, an increase in the value of USD in relation to NOK can be expected to increase our reported earnings. Please see notes 7, 30 and 31 to the consolidated financial statements for quantitative and qualitative disclosures about market risk.
We sell the Norwegian State's share of oil and natural gas production from the NCS. Amounts payable to the Norwegian State for these purchases are included as "Accounts payable - related parties" in the consolidated balance sheets. The pricing of the crude oil is based on market-reflective prices. NGL prices are based on either attained prices, market value or market-reflective prices.
Statoil sells, in its own name, but for the Norwegian State's account and risk, the State's natural gas production. These sales, as well as related expenses refunded by the State, are shown net in our financial statements. Expenses refunded by the State include expenses incurred in connection with activities and investments that are necessary in order to secure market access and optimise the profit from the sale of the Norwegian State's natural gas. For sales of the Norwegian State's natural gas, both for our own use and to third parties, the payment to the Norwegian State is based on prices attained, a net-back formula or market value. We purchase a small proportion of the Norwegian State's gas. For further details, see the section Operational review-Related party transactions.
High oil prices have contributed to higher earnings and profitability from international projects with production sharing agreements (PSAs) than previously anticipated. Under a PSA, the partners are generally entitled to production volumes that cover the development costs and an agreed share of the remaining volumes. When oil prices are high, this means that these projects will move from a phase where earnings cover development costs to a phase where profits are generated at an earlier point in time. In PSA contracts, the higher the oil price, the sooner the field is profitable and the smaller the share of production that goes to the partners. The actual effect varies between different agreements and countries. These tax regimes are often asymmetric - i.e. the company's upside is somewhat limited, while the company is fully exposed to the downside. See Financial analysis and review - Sales volumes, for a description of the impact of the PSA effects.
Historically, our revenues have largely been generated by the production of oil and natural gas on the NCS. Norway imposes a 78% marginal tax rate on income from offshore oil and natural gas activities (a symmetrical tax system). See Operational review-Applicable laws and regulations-Taxation of Statoil. Our earnings volatility is moderated as a result of the significant proportion of our Norwegian offshore income that is subject to a 78% tax rate in profitable periods, and the significant tax assets generated by our Norwegian offshore operations in any loss-making periods. Most of the taxes we pay are paid to the Norwegian State. Dividends received in Norway are 97% exempt from tax, with the remaining 3% taxed at the ordinary rate of 28%. For dividends received from companies in a low-tax jurisdiction within the European Economic Area (EEA), the 97% exemption only applies if real business activities are conducted in that jurisdiction. Dividends received from companies in non-EEA countries are 97% exempt if the Norwegian recipient has held at least 10% of the shares for a minimum of two years and the foreign country is not a low-tax jurisdiction.
Government fiscal policy is an issue in several of the countries in which we operate, such as, but not limited to, Venezuela, USA, Nigeria, Algeria and Angola. For instance, government fiscal policy could require royalties in cash or in kind, increased tax rates, increased government participation, and changes in terms and conditions as defined in various production or income-sharing contracts. Our financial statements are based on currently enacted regulations and on any current claims from tax authorities regarding past events. Developments in government fiscal policy may have a negative effect on future net income.
Financial risk management
In order to achieve the above effects, the group has centralised trading mandates (financial positions taken to achieve financial gains, in addition to established policies) so that all major/strategic transactions are coordinated through our corporate risk committee (CRC). Local trading mandates are therefore relatively small.
Our financial risk management covers market risks, including commodity price risk, interest rate risk, currency risk and equity price risk, liquidity risk, and credit risk.
The group has established guidelines for entering into contractual arrangements (derivatives) in order to manage its commodity price, foreign currency rate and interest rate risk. The group uses both financial and commodity-based derivatives to manage the risks in revenues and the present value of future cash flows.
Commodity price risk
Derivatives associated with crude oil and petroleum products are mainly traded on the InterContinental Exchange (ICE) in London, the New York Mercantile Exchange (NYMEX), the OTC Brent market, and in crude and refined products swap markets. Derivatives associated with natural gas and electricity are mainly OTC physical forwards and options, Nordpool forwards and futures traded on the NYMEX and ICE.
The term of oil and refined oil product derivatives is usually less than one year, and the term for natural gas and electricity derivatives is up to three years. The commodity price risk is managed by the crude oil, liquids and products and natural gas organisations in the Marketing, Processing and Renewable Energy business area. The risks are managed in the trading currencies of the commodities in question, and not necessarily in the functional or reporting currency of the company.
Our cash inflows are largely denominated in or driven by USD, while our cash outflows mainly derive from tax and dividend payments in NOK, as well as certain investments, payments of salaries and various other costs payable in NOK. Accordingly, our exposure to foreign currency rates is primarily related to the USD/NOK exchange rate. We seek to manage this currency mismatch by issuing or swapping non-current financial debt into USD.
We further seek to manage short-term currency mismatches by using derivative instruments for both currency and liquidity management purposes. Typically, we purchase NOK during the course of a calend