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Note: Information contained in this report is the best available as of September 2002 and is subject to change.
Norway has a small industrial base apart from its oil and gas, shipping, and fishing industries, and its mainland (i.e. excluding oil and natural gas) economy is forecast to grow by 1.2% in 2002. Manufacturing activity was up 1.4% year-on-year for the second quarter of 2002. Norway's government is concerned about its economic welfare once its oil runs out, as is predicted by the end of the first half of the 21st century. Norway makes annual contributions to its Petroleum Fund, a financial safety net for the time when oil revenues decline (and a means of reducing the inflationary impact of oil revenues). The government was able to pay Norwegian krone (Nkr) 53.5 billion (about $7.1 billion) into the Petroleum Fund in the second quarter of 2002, for a total value of Nkr 605.4 billion.
A new center-right coalition took power in October 2001 after the Labor Party lost seats in the parliamentary election. The coalition consists of Prime Minister Kjell Magne Bondevik's Christian People's Party, the Conservative Party, and the Liberal Party. The government has sought to lessen government involvement in business and to lower taxes, though it remains quite involved in social and environmental policy. The government currently does not have plans to seek membership in the European Union.
Norway is part of the European Economic Area (EEA), but Norwegians have voted in two referenda against joining the European Union (EU). Recent polls have shown some increase in support for joining the EU. Norway has a history of state control over major industry, but this is beginning to change. Norway's reliance on oil revenues in the past resulted in a government preference for keeping Norwegian businesses under Norwegian control.
North Sea Oil and Natural Gas
Many of the world's major crude oil prices are linked to the price of the North Sea's Brent crude oil - about $150 billion in annual petroleum trade. Brent crude is a blend of North Sea crude oils and does not come exclusively from the Brent field. Because Brent crude is traded on the International Petroleum Exchange in London, fluctuations in the market are reflected in the price of Brent. Therefore, all other crude oils linked to Brent can be priced according to the latest market conditions. Brent production is forecast to fall precipitously from its current 400,000 barrels per day (bbl/d) by 2005, making the Brent price marker increasingly dated. Liquidity has fallen to about 10 cargoes per delivery month compared with 300-400 deals per month in the early 1990s. In response to this, pricing service Platts made a change effective July 10, 2002 allowing for substitution - at seller's option - of UK Forties and Norwegian Oseberg for Brent in an attempt to increase potential volumes and reduce volatility resulting from traders "cornering the market." The change has not been universally accepted, and it remains to be seen whether it will be successful. The International Petroleum Exchange (IPE), which runs the Brent futures market, appears to be waiting to see whether the over-the-counter market adopts Brent-Forties-Oseberg (BFO). The first full BFO contract was sold on August 8.
The late 1997-1998 oil price collapse had an adverse effect on North Sea production. In 1997 and 1998, North Sea oil production remained stable, whereas previous years had shown average annual increases of 400,000 bbl/d. The 1999-2000 oil price increase had the opposite effect: North Sea oil and gas production reached new heights in 2000, with oil production exceeding 6 bbl/d for the first time. However, the North Sea area is considered to be increasingly "mature," with few additional large discoveries likely to be made. Some predict that the North Sea will reach peak production of about 7 million bbl/d in the next two or three years, although technology developments could delay this. The average recovery rate for Norwegian fields is expected to eventually reach 44%. Because the North Sea is believed to be nearing its peak production, in both of the major North Sea producing nations, Norway and the United Kingdom (UK), government and industry are taking steps to restructure their oil and natural gas sectors to make them more internationally competitive and also are increasing cooperation between the two countries. On August 28, 2002, Norway and the UK released a joint plan to increase cooperation, cut costs, and raise output, especially on aging fields. However, taxation rates will remain unharmonized. Norway also signed a cooperation agreement with Russia that same day that opens energy dialogue on the Arctic Barents Sea shared by the two countries.
In November 2001, Norway's Energy and Oil Minister announced that Norway would cooperate with OPEC and cut crude oil production for the first half of 2002 in an effort to shore up prices in the face of sagging demand. Norway later agreed to cut production by 150,000 bbl/d, with target production at 3.02 million bbl/d. Rather than cutting production steadily across the period, Norwegian production cuts were concentrated in the last month of each quarter, i.e., March and June. A preliminary estimate of crude oil production for the first half of 2002 is 3.06 million barrels per day. In June, it was announced by the Oil and Energy Ministry that "The Norwegian government has decided not to extend the restriction on oil production into the second half of 2002." By this time, Brent prices were some $5 per barrel higher than they had been in November 2001. In late June, Norway informed operators that they could produce at 13% above field production limits in an effort to reach a government target of 3.02 million bbl/d of crude oil for 2002.
Oil service workers struck from July 5 until August 10, when the Norwegian oil industry association (OLF) and oil union Nopef arrived at a new agreement covering 3500 employees in oil service companies The oil industry reportedly suffered a loss of more than Nkr 330 million ($42.2 million) during the strike. A strike began September 10, 2002 by dock workers at Statoil's 205,000-barrels-per-day refinery in Mongstad, Norway, that would curb exports from one of Europe's key gasoline-producing plants. The strike could curb crude production from Norsk Hydro's Troll B and C platforms, which send their output to the terminal at the Mongstad refinery via pipelines.
Oil Sector Restructuring
In late 1999, Norsk Hydro completed its acquisition of Saga, reducing its public ownership, originally 51%, to 44%. In April 2001, the Norwegian parliament approved plans to sell between 10% and 25% of Statoil to private investors and to sell 15% of the SDFI to Statoil prior to Statoil's listing on the New York and Oslo stock exchanges. Norsk Hydro (taking the largest share) and eight other Norwegian North Sea operators were sold another 6.5% of the SDFI in March 2002. The remainder of the SDFI (78.5%) was reorganized into a new state company called Petoro. Petoro is the world's fifth largest oil and gas firm in terms of production, with estimated production of 1.4 million bbl/d of oil, though Petoro functions entirely as a management company, having no operations itself. Statoil completed its purchase of 15% of the SDFI in May 2001 for $4.24 billion, and on June 18, 2001, Norway sold 17.5% of its holding in Statoil in an initial public offering for $2.9 billion. These changes should introduce more efficiency into the system, as Statoil was uncompensated for managing the SDFI, and raise more capital for Statoil in order for it to compete globally as the company explores regions such as offshore west Africa and Venezuela.
Norsk Hydro sold two production licenses to Marathon Oil of the United States in July. There is speculation that Norsk Hydro may spin off its oil unit to focus on its aluminum and fertilizers businesses. Statoil is the most likely buyer, which would create a company with production approaching 1 million bbl/d of crude, condensate, and natural gas liquids. Statoil announced in May 2002 that it is selling its 7,000 bbl/d assets in the Danish North Sea to Denmark state oil company DONG for $127 million in order to concentrate on core areas.
Norwegian oil investment was about Nkr 56.9 billion ($7.5 billion) in 2001, an increase from the $6.2 billion invested in 2000, but down from the peak of NKr 80 billion ($10.6 billion) in 1998. Investment levels reflect expectations that Norway's oil production will remain roughly constant until 2004, and then begin a gradual decline. Oil fields and projects under development include: Fram West, Grane, Tune, and the Valhall Flanks and water injection. Three new offshore oil fields came on stream in the second half of 2001: Tambar, Glitne, and Huldra. Some important oil discoveries offshore Norway in the past 12 months include: Staerne, near the Norne field, with estimated reserves of 30 million barrels; increased reserves in the Oseberg unit; and additional oil at the Goliat continental oil shelf in the Barents Sea (estimates of 75-107 million barrels increased to 91-250 million barrels). Overall, about 250 million barrels of oil and condensate were added to Norwegian reserves in 2001. A total of 32 blocks were offered at the 17th Norwegian Continental Shelf licensing round in June 2002. Eleven companies will share blocks that comprise six production licenses. This round focused on the Norwegian Sea.
Ekofisk, in the southern North Sea sector, was the first North Sea oil field to be discovered, in the late 1960s, and developed, with production beginning in 1971. Since 1975, oil has been piped from Ekofisk to the UK (Teesside, England). There are currently 29 platforms installed in the area, some of which are in the British North Sea. The most recent phase of development began in 1994, when the Phillips group (the U.S. company that leads the Ekofisk operating consortium, which includes TotalFinaElf, Norsk Agip, Norsk Hydro, and Statoil) installed two new platforms at "Ekofisk II". Ekofisk II came onstream in August 1998. The Phillips license runs through 2028. In December 2001, it was decided by the government that Phillips would remove 14 of the 29 Ekofisk platforms between 2003 and 2018, at an estimated cost of $1 billion (NKr 8 billion). About 10% of the removal cost will be paid by Phillips, 72% by the Norwegian government, and the remainder will be paid by the other members of the consortium. Phillips plans to bring the steel structures and the topside of the concrete Ekofisk tank ashore for recycling, to leave the rest of the concrete tank and barrier wall in place, and also to leave about 150 miles of pipelines buried. Ekofisk's production (including Eldfisk, Embla, and Tor) is expected to be about 381,000 barrels per day of crude oil in 2002. The Valhall field's production continues to decline, with expected production in 2002 at 72,000 bbl/d. However, the recently approved Valhall water injection and the Valhall flanks should improve recovery from the field. The Yme field has ceased production.
Sleipner West was discovered in 1974, but Sleipner East went into production first, in 1993. Sleipner West is tied back into Sleipner East, and the fields share the same operations organization. Sleipner is mostly important for natural gas production, including liquids and condensate (2002 condensate production in East and West is estimated at 3.7 million cubic meters), but the Varg field is estimated to produce 8,300 bbl/d crude oil in 2002. Varg is scheduled to cease production within the next few years.
Moving to the northern North Sea sector, the Frigg-Heimdal area is also mostly important as a natural gas producing area, though the Balder and Jotun fields together are expected to produce about 124,000 bbl/d of crude oil in 2002. Balder was proven as early as 1967, though production did not commence until 1999. Shuttle tankers are loaded from a production ship tied to subsea-completed walls. Several structures close to Balder are being developed by Ringhorne platform. Jotun also commenced production in 1999, from a floating production, storage, and offloading vessel (FPSO) that is serviced by shuttle tankers.
The Statfjord area is one of the largest oil producing areas in the North Sea. The Statfjord field itself was discovered by Mobil in 1974, and it extends into the British North Sea. Production began from Statfjord A in 1979, from Statfjord B in 1982, and from Statfjord C in 1985. Production from the Statfjord North and Stafjord East subsea installations are tied back into Stafjord C. Statoil took over the operations from Mobil in 1987. Three large concrete platforms with storage cells have been installed on Statfjord. Britain's 14.5% share goes by pipeline via the Brent field to Scotland. Statfjord's production has exceeded the most optimistic expectations, but all Statfjord fields are now in decline. Norway's share of Statfjord crude oil production in 2002 (including North and East) is expected to be 205,000 bbl/d. Statfjord should continue producing until 2020.
The Snorre field, with production rising, has become the largest single field in the area, with 2002 production estimated to be 228,000 barrels per day. It was discovered in 1979, and production commenced in 1992 (see above). Norway's third largest field is Gullfaks, which, including West and South, is expected to produce 223,000 bbl/d in 2002. Gullfaks (including West) has declined by over 50% since its peak in 1995, but Gullfaks South (including Rimfaks and Gullveig) has had increasing production since it came online in 1998, to 70,000 bbl/d expected for 2002. Vigdis continues to decline from its peak in 1999, but Visund, which is east of Snorre, has had its production increase, with 2002 expected to be 43,000 bbl/d.
The various Oseberg fields (Oseberg, East, South, West) together are the largest oil producing fields in their area, whereas Troll is the largest gas field in the area. Oseberg began production in 1988, and peaked at about 500,000 bbl/d in 1996, and has declined since to about 176,000 bbl/d (including West), far below the capacity of the three platforms there. The surrounding East and South Oseberg fields have come online in 1999 and 2000, respectively, supplementing the declining production at Oseberg with 130,000 bbl/d expected for 2002. Both East and South peaked in 2001. There is a pipeline from Oseberg to the Sture terminal on the Norwegian coast, with tie-backs from East and South to Oseberg. A thin layer of oil underlies the entire Troll field, but it is only sufficiently thick for commercial recovery in the Troll West region. This is where Troll Phase II is expected to produce 316,000 bbl/d in 2002 - production has been relatively flat since 2000, though Troll achieved a daily record of 440,000 bbl in May 2002. There is a pipeline from Troll West to the Mongstad crude oil terminal on the Norwegian coast.
The Norwegian Sea has seen production increase at a higher rate than North Sea production in recent years, though it is in an earlier stage of development, the first field having come on stream in 1993. Total production for the area for 2002 is predicted to be 725,000 bbl/d. Much of the increase comes from the new Asgard field, which went into production in 1999, and now produces about 148,000 bbl/d. Norne's production also increased in 2001, though a slight decline is predicted for 2002. Heidrun's production has declined to less than that of the Norne field. Draugen's production has been flat in the past two years, but it is still has the highest production at about 200,000 bbl/d. Shuttle tankers are used to take oil from the platforms or production ships, as there is currently not an oil pipeline from the Norwegian Sea.
Natural Gas Exports
The effects of all these changes are yet to be seen, though the expectation is that the price of Norwegian natural gas will be reduced, at least in the short to medium run. A major constraint for upstream gas companies competing for sales in the newly deregulated market will be limited infrastructure to take the gas out, because various companies share the same pipeline. Norwegian gas arrives in Europe through the following trunklines: the Europipe I and Statpipe/Norpipe systems to Germany; the Zeepipe trunkline to Zeebrugge in Belgium; the NorFra line to Dunkerque in northern France; and the Europipe II line from Kårstø north of Stavanger to Emden. These Norwegian trunklines provide a combined gas transport capacity of 2.7 Tcf per year. There are also pipelines to the UK, including the new Vesterled pipeline, which opened in October 2001, with volumes at about 138 million cubic feet per day. Marathon is exploring the potential demand for its proposed Symphony natural gas pipeline, which would bring additional Norwegian natural gas to the UK through a link between the Heimdal complex and the Brae/Miller complex in the UK sector.
Statoil expects Norway's share of natural gas deliveries to continental Europe to rise from 14% in 1996 to 20% by 2005. The following companies currently buy Norwegian gas: Ruhrgas, BEB, Meeg, Thyssengas and Verbundnetz Gas (Germany), Gaz de France (France), Gasunie, SEP (the Netherlands), Distrigaz (Belgium), Enagas (Spain), Austria Ferngas, OMV (Austria), Snam (Italy), Energia (Italy), Polish Oil and Gas Company (Poland), Transgas (Czech Republic), and Centrica (UK). Germany is the largest natural gas market in continental Europe, and about 20% of the gas that Germany currently consumes comes from Norway. Ruhrgas expects Norway to supply 30% of Germany's imports. About half of the gas from the NorFra line transits through France to points in Italy and Spain, while the other half is consumed in France. By 2005, this pipeline is expected to supply one-third of France's total gas consumption.
In July 2001, Stoltenberg and Polish Prime Minister Jerzy Buzak signed a joint declaration for the deliveries of 177 billion cubic feet (Bcf) of natural gas from Norway annually. Existing Polish infrastructure cannot support significant imports from non-Russian sources, so a pipeline across the Baltic through either Sweden or Denmark was being planned, but it now appears unlikely that a natural gas pipeline to Poland will be built because of insufficient demand volumes. There is a competing plan to import liquefied natural gas (LNG) from Norway to a planned LNG terminal on Poland's Baltic Coast. Norway began piping a relatively small amount of gas through Germany in October 2000, based on an earlier contract signed in May 1999, for the delivery of 17.7 Bcf annually, under an agreement between Germany's Ruhrgas and Verbundnetz Gas and Poland's state-held gas monopoly.
The United Kingdom, the largest natural gas market in Europe, will also soon become an importer of Norwegian gas again. Norway had once supplied up to a quarter of British demand in the 1980s, but this dwindled as the Frigg field that supplied the gas was depleted. Vesterled will connect the existing Frigg pipeline with the Heimdale platform, which is already connected by pipeline to the Sleipner gasfields, and from there to other areas of the Norwegian North Sea such as the Ormen Lange gasfield that is scheduled to come on stream in 2006. In July 2001, BP announced a 15-year contract to buy 56.5 Bcf natural gas per year from Statoil. In June 2002, Centrica of the UK signed a 10-year deal with Statoil for the purchase of 483.5 million cubic feet per day, with prices linked to natural gas rather than oil.
Natural Gas Production
Troll is not the only active natural gas field in Norway's North Sea. Gas sales began in 1977 from Ekofisk and Frigg. Ekofisk, in the southern North Sea sector, supplies Ruhrgas, Gaz de France, Gasunie and Distrigaz. Ekofisk has declined from its peak in the late 1970s and a production spike in the 1990s, though it is still expected to produce 5.95 billion cubic meters (210 Bcf) in 2002. Frigg production is sold to British Gas, though Frigg has declined to the point that production is expected to cease sometime this year. Nearby Heimdal's declining production is also set to cease this year. Agreements on selling gas from Statfjord, Gullfaks and Heimdal were signed in 1981 and deliveries began in 1985 to Ruhrgas, BEB, Thyssengas, Gaz de France, Gasunie, Distrigaz, Elf and Meeg. Remaining commitments under these deals average six billion cubic meters per year (212 Bcf). Sleipner, East and West, is expected to produce 13.6 billion cubic meters (479 Bcf) in 2002; this gas is currently sold under the Troll gas sales agreements. Though Sleipner East is declining, most natural gas production is from Sleipner West, which continues to have sharply increasing production. The Norwegian share of gas from the field is piped through the Statpipe/Norpipe system to Emden in Germany via Kårstø, north of Stavanger.
Huldra commenced production with an unmanned platform in November 2001, with natural gas production steadily rising and already at about 350 million cubic feet per day (total expected production 3.19 billion cubic meters or 113 Bcf for 2002). Huldra also produces condensate and about 28,000 bbl/d of crude oil. The crude and condensate are piped to Veslefrikk B, and the gas is piped to Heimdal.
The Åsgard field on the Halten Bank in the Norwegian Sea is one of Norway's most important new projects. The field has been developed as a chain of four interconnected projects: development of Åsgard itself, construction of the Åsgard Transport gas trunkline from the field to the Kårstø gas treatment plant north of Stavanger, the Kårstø development project, and the Europipe II gas trunkline from Kårstø to Dornum in northern Germany. Gas production from the floating platform began in October 2000, and is expected to be 8.9 billion cubic meters (314 Bcf) in 2001. Statoil is the operator of the project, which is one of Norway's giant offshore developments, on par with Ekofisk and Troll. Subsea production installations in the field are planned to be the most extensive in the world, embracing a total of 51 wells grouped in 17 seabed templates. It will link the Halten Bank area to Norway's gas transport system in the North Sea.
Statoil now is developing the Halten Bank South area of the Norwegian Sea, having taken over as operator in January 2000 (Saga had been the operator). Recoverable reserves of the Halten Bank South fields are estimated at 140 billion cubic meters (almost 5 Tcf) of gas and about 440 million barrels of oil and condensate - on par with Åsgard. The Kristin field of the Halten Bank has already secured sales of up to 31 billion cubic meters (1.1 Tcf) from 2005 to 2016. ExxonMobil made the largest discovery of 2000 in this area, the Bella Donna field, with estimated reserves between 60 and 125 billion cubic meters (2.1-4.4 Tcf).
In March 2002, the Norwegian parliament approved Statoil's plans to develop the $5 billion Snohvit project. If it is completed, Snohvit will be the largest sub-sea liquefied natural gas (LNG) project in the world, as well as the most northerly as it is located in the Barents Sea. Approximately 201 Bcf per year of natural gas would be piped to the coast, liquefied, and transported to customers in Spain and the United States by means of four carriers. In June 2002, El Paso of the United States, announced that it had final Norwegian and U.S. government approval for its plans to import 1.8 million metric tons of LNG to the United States from Snohvit. This is over 40% of the project's capacity, and much of the LNG may be delivered to El Paso's Cove Point, Maryland regasification facility. Construction of Snohvit restarted in June as well.
The huge Ormen Lange field in the Norwegian Sea, Norway's second largest natural gas discovery with estimated reserves of of 14.1 Tcf, has its blocks divided into three production licenses, with the unusual characteristic that Statoil/SDFI has only a 30% share of one of the licenses, such that non-Norwegian companies are the majority owners of one of the licenses. Norsk Hydro is the operator in the development phase, and Shell will be the operator in the production phase. Gas production is planned to commence in 2007.
Norway is planning to construct three new natural gas-fired power plants. Construction of two natural gas-fired power plants by Naturkraft appears set to go ahead sometime this year. Naturkraft recently asked the government to extend its license to build these plants beyond 2004. This issue, which has not been completely resolved, is extremely important in Norway, as Prime Minister Bondevik's previous term of office ended in a vote of no confidence that overrode his opposition to the plants. Industrikraft Midt-Norge also plans to build a natural gas-fired plant, and has an allowance to emit 2.2 million tones of carbon dioxide per year. This 2X400 gas-fired combined heat and power plant in Skogn, central Norway is slated to begin construction in 2002. U.S.-based Mirant has bought 40% of five-member industrial consortium IMN, which will build, operate, and own the plant.
Norway has had a surplus of hydroelectric power in the past two years, but in drier years it must import electricity. In January 2001, E.On of Germany, Statkraft, and Elsam of Denmark agreed to free up capacity on key power cables linking the high tension electricity grids of Scandinavian countries to Germany, including the Skaggerrak cable, the only cable connecting western Denmark and Norway.
In May 2002, the European Free Trade Area (of which Norway is a member) informed the government that industry's exemption from taxation on electricity cannot continue. Consumers currently pay a 9% tax on electricity.
Sources for this report include: Economist Intelligence Unit,
Financial Times, Hart's European Petroleum Finance Week, International
Monetary Fund (IMF), Oil Daily, Norwegian Ministry of Oil and Energy,
Petroleum Economist, Petroleum Intelligence Weekly, Platt's Oilgram News,
Statoil, The Scotsman, DRI-WEFA, World Markets Energy .
Head of State: King Harald V
Prime Minister: Kjell Magne Bondevik (since October 2001)
Independence: October 26, 1905 (from Sweden)
Population (2001E): 4.5 million
Location/Size: Northern Europe, bordering the North Sea and the North Atlantic Ocean, west of Sweden/123,843 square miles (slightly larger than New Mexico)
Capital City: Oslo
Language: Norwegian (small Lapp- and Finnish-speaking minorities)
Ethnic Groups: Germanic (Nordic, Alpine, Baltic), Lapps (Sami) 20,000
Religions: Evangelical Lutheran 87.8% (state church), other Protestant and Roman Catholic 3.8%, none 3.2%, unknown 5.2%
Defense (8/98): Army, 28,900; Navy, 6,100; Air Force, 6,700 (including 16,500 conscripts)
* The total energy consumption statistic includes petroleum, dry
natural gas, coal, net hydro, nuclear, geothermal, solar, wind, wood and
waste electric power. The renewable energy consumption statistic is based
on International Energy Agency (IEA) data and includes hydropower, solar,
wind, tide, geothermal, solid biomass and animal products, biomass gas and
liquids, industrial and municipal wastes. Sectoral shares of energy
consumption and carbon emissions are also based on IEA data.
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Norwegian Petroleum Directorate
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File last modified: September 9, 2002