Energy Information Administration
NORTH SEA
The North Sea is important to world energy markets because it is Europe's main oil and natural gas producing area. North Sea oil production primarily comes from Norway and the United Kingdom, with smaller amounts contributed by Denmark, the Netherlands, and Germany. Also, the region's large natural gas reserves make it a key supplier of European gas.
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GENERAL BACKGROUND
Norway's economy began slowing down after a strong
performance in 1996. The real gross domestic product (GDP) growth
rate fell about two percentage points from 5.3% in 1996 to 3.2%
through August 1997. Inflation is on the rise from 1.4% in 1996
to 2.6% thus far for 1997. However, the unemployment rate continues
its downward trend from 4.4% in 1996 to 3.5% for 1997. Norway's
current economic trends are expected to continue for 1998. Norway
has not experienced significant fallout from its 1994 rejection
of European Union (EU) membership, although non-membership may
make it difficult for Norway to attract inward direct investments
outside of its oil and gas industries. Norwegian supporters of
the EU may launch a new bid for membership, but it is unlikely
to happen in the newly elected parliament.
Parliamentary elections, held in September 1997,
pushed the country into a period of political uncertainty. Norway's
ruling Labor Party, although it remained the leading party in
parliament with 65 seats, was defeated in the parliamentary elections
with a net loss of 2 seats. Labor received only about 35% of the
vote and Prime Minister Torbjoern Jagland announced shortly after
the elections that he and his government would step down on October
13. During the campaign, Prime Minister Jagland indicated that
Labor neded at least 36.9% of the vote, the same support level
it received in national elections four years ago, to remain in
power.
One of the hottest topics in Norway today is the
debate over the county's state petroleum fund. The fund was set
up to absorb surplus oil and gas revenues and use them to support
Norway's ambitious pension and social welfare programs. The revenues
are invested abroad so that the fund will continue to provide
a safety net as revenues from Norway's oil and gas production
decline. According to the Ministry of Petroleum and Energy, Norway's
remaining discovered oil and gas resources will last for about
14 years and 80 years, respectively, at current rates of production
and proven reserves. Officials in Oslo estimate that the fund
will reach between $15.4 billion and $16.8 billion by the end
of 1997. Others have suggested however, that the government's
estimate may be conservative and that if the non-oil economy continues
to perform well, coupled with increased oil and gas production,
the fund could grow more quickly over the next decade. The pace
at which the fund grows also depends on parliament's annual decision
of how to allocate oil and gas revenues between the fund and the
national budget. Currently the fund represents about 10 percent
of Norway's GDP, and within 20 years it could represent between
130 and 150 percent of GDP. In early 1997, a decision was made
to shift about half of the fund from low-risk, high-liquidity
bonds and bills into equities. This decision stirred much debate
about how the fund should be structured and what affect it would
have on international equity markets.
The government recently implemented the NORSOK plan,
which aims to cut discovery-to-production lead times and costs.
The Petroleum Directorate estimated that future field development
costs could be cut by over 50 percent through increased use of
subsea technology, floating production platforms, horizontal drilling,
and extended reach and highly deviated wells. In addition, enhanced
oil recovery (EOR) techniques have raised estimates of remaining
recoverable reserves in several large fields. For example, in
October 1994, the Statfjord field's recoverable reserves were
raised by 200 million barrels and its ultimate recovery factor
increased to over 60 percent through the use of new technology.
Average recovery factors for the Norwegian North Sea have been
raised during the past 10 years from 35 percent to 45 percent.
Norway's oil production first began at the Ekofisk
field in 1971. In December 1994, the government approved a $3-billion
redevelopment plan for Phillips' Ekofisk system. Crude oil from
Ekofisk is piped to Teesside in the United Kingdom, while gas
is piped via the Norpipe to Emden, Germany. The Phillips' Ekofisk
IIA plan added a wellhead platform in 1996, and a transportation
platform is scheduled for 1998. After completion in late 1998,
state-owned Statoil will acquire a 5 percent stake in Ekofisk.
Subsequently, all royalty payments on production will cease. The
state also will acquire a 40 percent stake in the Norpipe pipelines.
The project will extend the Ekofisk's projected life well into
the next century, with an additional 280 million barrels of oil
anticipated for recovery.
The Troll field, near Bergen, is the largest oil
and gas field in the Norwegian North Sea. It came online in 1995.
Troll is divided into two structures. Troll East contains an estimated
46 Tcf of natural gas and 140 million barrels of condensate. Troll
West originally was thought to hold 600 million barrels of oil
and 650 billion cubic feet (Bcf) of associated gas. In June 1995,
however, Norsk Hydro announced that due to advances in drilling
technology, a total of 1 billion barrels would be recoverable
from Troll West. This implies an increase of $8 billion in the
field's value. Development of Troll began in 1986, after the signing
of long term gas supply contracts with companies in six European
countries. Gas production from Troll East will be piped to an
onshore processing plant at Kollsnes. Gas output is projected
to reach 1 Tcf per day after 2000 and to surpass production from
all other Norwegian gas fields combined. A consortium comprising
Statoil, Shell, Norsk Hydro, Saga, Elf, Conoco, and Total is developing
the Troll structures. The $4.8-billion project includes construction
of a 1,500-foot tall, 656,000-ton gravity base platform. Oil production
from Troll West began in September 1995. The developers project
a peak output of around 190,000 bbl/d. Oil production currently
is piped to an onshore terminal at Mongstad.
In June 1997, Statoil, Norway's state-owned oil and
gas company, completed asset swaps with five international oil
companies - British Petroleum, Chevron, Elf, Total, and Norsk
Hydro. Statoil exchanged both Norwegian and British assets with
BP and Chevron and traded interests in exploration licenses with
Norsk Hydro, Elf, and Total. The overall value of the non-cash
transactions was estimated at $683-$820 million and total reserves
were 340 million barrels of oil and 1.3 Tcf of natural gas. Statoil
indicated that the exchanges helped to meet its central goals
of strengthening its position in the Norwegian and UK continental
shelves and improving its long-term production profile.
On August 24, 1997, about 340 oil workers from the
OFS Federation of Oil Unions went on strike after rejecting a
7.8% pay raise offered by the Norwegian Shipowners Association.
For the union, the most important issue is the differences in
compensation for floating and fixed rig workers. The union contends
that workers on floating offshore rigs deserve the same pay and
benefits as workers on fixed offshore platforms. Initially, the
strike affected only five North Sea offshore oil rigs (drilling
mainly new wells) and did not interrupt Norway's daily oil production
of more than 3 million bbl/d. The initial strike forced the closure
of a floating hotel (flotel) used by Statfjord platform workers
and delayed the restart of the Norne field. After failing to reach
agreement, the union expanded the strike on September 10 to include
three more rigs including the West Epsilon rig operating in the
Sleipner field and the Poly Saga rig operating in the Yme field
both located in the Norwegian North Sea. At the time, the OFS
also threatened to expand the strike further unless its demands
were met. The expanded strike did force the 35,000-40,000 bbl/d
Yme field to shut down; but, the main impact of the strike continued
to be on exploration drilling. The impasse continued through the
end of September, and in an attempt to resolve the conflict, the
Norwegian Shipowners Association threatened to lock out all OFS
members, whether they were on strike or not, beginning on October
8. At the end of September, Statoil said that any escalation of
the strike could cost the company millions of dollars and claimed
that the strike was already costing the company about $700,000
per day due to the shutdown at the Yme field. Other companies
operating in the Norwegian sector of the North Sea echoed Statoil's
statements.
NATURAL GAS - Norway
The 46-Tcf Troll field is Norway's largest gas development
project and is expected to account for 80% of all of the country's
gas sales by 2005. Norway began producing gas in 1993 from the
1.5-Tcf Sleipner East field in order to satisfy its TGSA obligations
before Troll comes online. Gas from Sleipner East is transported
to Emden, Germany via the Statpipe and Norpipe pipelines. Constructed
in 1981, the Statpipe system is the primary gas gathering network
connecting Statfjord, Gullfaks, Troll, and the Sleipner satellite
fields. The 1.8-Bcf capacity Norpipe line is Norway's oldest oil
and gas export pipeline and was completed in 1977. Gas from Exxon-operated
Sleipner East also is carried to Zeebrugge, Belgium via the 1.2-Bcf
Zeepipe pipeline.
At present, Norway has committed to selling more
gas than it can supply under currently active and proposed gas
development projects. Consequently, the government looked at two
options to solve this problem. The first was development of the
Oseberg field's 3.2 Tcf associated gas cap as well as the 420-Bcf
Gullfaks gas cap. Since both fields are located near Troll, development
costs resulting from this option could be relatively low. The
second was development of the Smrerbukk, Smrerbukk South, and
Midgard fields, with a combined 7.9 Tcf of gas. Due to a 1994
agreement between Statoil and Saga, as well as an inexpensive
pipeline linkage plan, Norwegian gas producers chose this latter
option in November 1995. Under a fast-track development plan using
floating production platforms, oil and gas production could begin
by 1998. A new 450-mile, 1.1-Bcf/d pipeline (Europipe II) will
be built to carry gas to Germany and France starting in 2000.
Oseberg gas likely will be used to satisfy the next round of sales
contracts. Oseberg field development could occur by 2000.
Norway's increased future gas exports will necessitate
construction of new export pipelines and development of new gas
fields in its North Sea sector. In recent years, Norway opened
the Zeepipe II line linking the Sleipner East field and the Kollsnes
processing center with the Norpipe export system and the Europipe
linking the Sleipner area with Emden, Germany. During the summer
of 1997, Norway laid two more gas pipelines. The first was the
183-mile, 40-inch, Zeepipe IIB line. This pipeline is part of
the Statoil 2000 program and connects the Kollsnes shore terminal
to the Draupner riser complex in block 16/11. The line becomes
operational in October 1997 and marks the completion of the gas
transport system from the Troll field. The second pipeline was
the NorFra line running from the Draupner riser complex to Dunkerque,
France. The 42-inch line is 513 miles, a record length for a subsea
pipeline, and will have an initial transport capacity of 403 Bcf
per year. NorFra, Norway's fourth gas pipeline to the Continent,
runs through Danish, German, Dutch, and Belgian waters on its
way to France. In July 1997, Norway's oil and energy department
ordered Statoil to develop the Huldra natural gas field. The field
contains gas reserves of 706 Bcf, but Statoil had not planned
to develop Huldra until October 2000. With the new orders from
the Norwegian government, Huldra could begin supplying gas as
early as 1999. In addition to its North Sea sector, Norway plans
to fulfill its growing gas commitments by opening new fields and
pipelines in its Norwegian Sea and Barents Sea sectors as well.
In April 1997, Norway and the United Kingdom reached
agreement on a revised treaty governing the operation of the Frigg
North Sea pipelines. The original treaty came into force in July
1977 and only alllowed the use of the pipelines to transport gas
from the Frigg Field to the St. Fergus terminal in Scotland. Norway's
share of the UK gas market stood at 27% in 1985 but has since
fallen to 2% due to the restrictions on the Frigg pipelines from
the original treaty and a sharp increase in UK gas production.
With the Frigg field currently in decline and production expected
to end within the next few years, negotiations for revisions to
the treaty began in 1992. The revised treaty, signed in June 1997,
enables Norway to begin using the under-utilized Frigg pipelines
to transport gas from other fields in addition to the remaining
gas from the Frigg field. The treaty also enables Norway to sell
non-Frigg gas to UK customers and possibly to other Euopean customers
via interconnecting pipeline links. Furthermore, the potential
exists for UK gas producers to use spare capacity in the pipeline
for gas from UK fields.
In April 1997, Norway and The United Kingdom settled
a new framework agreement to govern future cross-border pipelines.
The new framework agreement facilitates the construction and operation
of future offshore pipelines that provide links across the continental
shelf boundary between Norwegian and UK oil and gas infrastructures.
It eliminates the need for separate treaties between Oslo and
London prior to constuction of new cross-border pipelines.
RECENT DEVELOPMENTS
Politically, the United Kingdom experienced significant,
even historic, changes in 1997. The first came in May 1997 during
the general election. On May 1, the general election resulted
in an overwhelming victory for the Labor Party. After 18 years
of Conservative Party rule, the United Kingdom had its first Labor
government since 1979. In addition, Labor received its largest-ever
majority. The final tally gave the Labor Party 418 seats out of
659 seats in the House of Commons and an overall majority of 177
seats. Following the election, the Labor Party elected Tony Blair
as the new Prime Minister, replacing the Conservative Party's
John Major. Thus far, the new government has received support
from other European countries. The administration has taken a
more constructive approach to EU issues and other policy initiatives
have been well received by the UK's European neighbors.
The second historic change came in the form of a
September referendum in Scotland. The people of Scotland were
given the opportunity to vote for the creation of a Scottish parliament.
England and Scotland have shared the same monarch since 1603 and
Scotland has been ruled by the British Parliament since 1707.
On September 11, nearly 70% of Scotland's eligible voters crowded
their polling places and almost 75% voted in favor of creating
a Scottish Parliament. Also, more than 60% of voters supported
giving the new parliament limited taxation power. The proposed
tax powers are limited to increasing or decreasing income taxes
by up to 3 percentage points. Prime Minister Blair and his Labor
Party supported the idea of creating a Scottish Parliament during
the campaign leading up to the May general election, and his support
continued through the referendum vote. The Scottish Parliament
is to open its first session in 2000, and although it gives Scotland
some measure of independence, it is far from a complete break
with England. Certain duties such as foreign relations and defense
would remain matters for the British Parliament. It remains to
be seen what effect a new Scottish parliament will have on UK
industries and how much control Scotland will have, if any, over
UK North Sea oil and gas fields. Some, such as the Scottish National
Party, have long maintained that Scotland should benefit more
from UK North Sea oil and gas revenues, arguing that many UK fields
are closer to Scotland's coastline than England's. They claim
that up to 90% of the revenues belong to Scotland. At present,
Scotland receives about 10% of total revenues from North Sea oil
and gas fields.
As the oil and gas industries' infrastructure in
the North Sea has increased, environmental issues have become
an increasing concern. In April 1997, three environmental groups,
including Greenpeace UK, appealed to the European Commission to
force the British government to comply with the European Habitats
Directive. This directive requires environmental impact assessments
prior to offshore oil and gas development projects. Environmentalists
claimed that Britain deliberately delayed implementing the directive
requirements in order to exempt its 17th offshore licensing round
for oil and gas exploration rights. In an unprecedented move,
Greenpeace applied for all of the licenses intending to turn the
22,000 square miles covered by the 17th licensing round into a
marine wildlife sanctuary. Britain's Department of Trade and Industry
(DTI) rejected the bid, and the licenses were granted to 14 oil
companies.
The UK's North Sea oil sector is considered mature,
with offshore oil production having begun in the 1970s. In 1997,
the UK's offshore and onshore crude oil production rose to 2.8
million bbl/d, up from 2.6 in 1996, 2.5 million bbl/d in 1995,
2.4 million bbl/d in 1994, and 1.9 million bbl/d in 1993. By 2000,
output could fall to 2 million bbl/d, depending on the impact
of world oil prices on the economic viability of future developments,
particularly in the West of Shetlands. However, there is a wide
range of output forecasts, which are highly dependent on new discoveries
and uncertain production lead times.
One of the most important issues for the UK's new
government is a review of the North Sea tax system. The review
is to be conducted jointly by the DTI, the Treasury, and the Inland
Revenue. Currently, mature fields are taxed at a high rate of
more than 70 percent. A mixture of royalties, petroleum revenue
tax, and corporation tax make up the taxes on these fields. In
contrast, new fields are charged only the 31 percent corporation
tax. The review is designed to insure that the government receives
an appropriate share of North Sea profits while making sure that
the UK North Sea sector remains attractive to investors. Some
argue that the tax burden on mature fields is too high, but also
too low on new fields. However, the United Kingdom will have to
balance its need for a fair return from offshore industry with
its need to maintain exploration in order to sustain production
levels and replace reserves. Industry opinions on the government's
review of offshore taxation were due at the end of September 1997,
and the review is scheduled to be completed in time for next year's
March budget.
Much of the activity in the UK's North Sea oil sector
has been focused on new field developments. In early 1997, two
new finds were announced. Hydrocarbons were confirmed at BP and
Shell's Suilven field in block 204/9 north of the Foinaven and
Schiehallion Fields. Further analysis is needed to determine the
commercial value of the find, but the UK government responded
by preparing two more blocks north of Suilven for licensing. The
find may also revive waning interest in the areas west of Shetland.
British Gas discovered an oil find in central North Sea block
15/23d. The site tested at over 7,500 b/d of oil with 9 mcf/d
of associated gas. Encouraged by the testing, British Gas is discussing
fast-track development plans with operators of nearby fields.
In June 1997, Talisman Energy received approval from
DTI to develop the Ross Field in blocks 13/28A and 13/29A. Drilling
for the first development well began in June with four more planned
prior to start-up, which is anticipated in September 1998. Reserves
are estimated to be between 60 and 100 million barrels of oil
and 20-30 Bcf of gas. Peak oil production is expected to reach
40,000 bbl/d by 1999. Pre-production expenses are estimated at
$300 million. A floating production, storage, and off-loading
vessel (FPSO) is being used to develop the Ross field with oil
exported via shuttle tanker and gas shipped to St. Fergus via
the UK Frigg pipeline. Talisman Energy holds a 51.99 percent interest
in Ross, Lasmo (ULX) 16.33 percent, Clyde Expro 14.49 percent,
BG Great Britain 13 percent, and Nippon Oil Exploration and Production
4.19 percent.
In mid-1997 Shell Expro, the North Sea division of
Shell UK, signed long-term integrated service contracts with service
contractors as part of its program to extend the life of many
existing oil and gas fields. The seven-year agreements, valued
at $1.05 billion, are expected to bring savings of 15% or more
on engineering and maintenance costs. Shell also hopes to eventually
convert the agreements into life-of-field deals. The contracts
are scheduled to come into force in early 1998.
In September 1997, US oil company Kerr-McGee was
awarded a contract from the UK to develop the Janice Field. Discovered
in 1990 about 170 miles south-east of Aberdeen, the field contains
an estimated 60-70 million barrels of recoverable oil reserves.
Production of 55,000 bbl/d is expected to begin by the end of
1998, and the development project will require a total investment
of about $400 million. Shortly after winning the contract for
Janice, Kerr-McGee awarded a contract to Norwegian-owned Aker
McNulty yard to upgrade an accommodation vessel to a floating
production unit.
In early October 1997, Amoco Exploration Company
and Amerada Hess announced an oil and gas discovery in the UK
central North Sea sector. The find is located in an area known
as Appleton Beta 160 miles off the cost of Scotland and close
to other possible new developments including Amoco's Halley field.
Flow rates produced 6,392 bbl/d of oil and 13.4 mcf/d of associated
gas. Amoco stated that the quality of the crude was exceptionally
high and very light. Amoco and Hess will prepare and submit a
development plan for government approval. Amoco holds a 51.54%
interest in Appleton with Amerada Hess holding the remainder.
NATURAL GAS - United Kingdom
In July 1997, Elf Exploration UK confirmed that two
pipelaying contracts were awarded to McDermott-ETPM for the North
Sea Central Graben gas/condensate development. The Central Graben
area includes Shell's Shearwater field and Elf's Elgin and Franklin
fields. The first contract covers engineering, procurement, installation
and commissioning of a 34-inch, 292-mile gas trunkline linking
the three fields with the Shell/Esso Bacton terminal in Southeast
England. According to Elf, the contract is worth about $324 million,
making the award the largest pipeline contract in the UK Continental
Shelf. The pipeline will be called the Shearwater Elgin Area Line
(SEAL). The second contract is for engineering, procurement, installation
and commissioning of a 24-inch liquids export pipeline connecting
the Elgin, Franklin, and Shearwater fields with the Marnock field.
The line will then hook up to a liquids line connecting the Etap
project with the BP Forties system. Export of gas and condensate
through these new pipelines is expected to begin in 2000.
In 1993, the UK announced plans for a gas export
pipeline connecting a terminal at Bacton, near Norwich, to Zeebrugge,
Belgium. The proposed 2-Bcf/d, reversible, "Interconnector"
pipeline is being developed by a consortium comprising British
Gas (40%), BP (10%), Conoco (10%), Elf (10%), Gazprom (10%), Amerada
Hess (5%), Distrigaz (5%), National Power (5%), and Ruhrgaz (5%).
In late 1994, the consortium announced that it had the financing
necessary to begin construction. Start-up is expected to coincide
with the Britannia field in 1998.
In early July 1997, the UK government announced its
decision to abolish the North Sea gas levy effective in April
1998. The levy was established in 1975 to prevent British Gas
from earning windfall profits on low cost gas fields. The abolition
of the gas levy is part of the UK's plan to liberalize the gas
market, and it should help other UK gas companies like Centrica
become more competitive.
DENMARK
THE NETHERLANDS
The Dutch gas industry, on the other hand, is in
better shape. In 1996, total gas production increased 399 Bcf
to 3.2 Tcf and offshore fields accounted for 968 Bcf of the total
up 92 Bcf. To control costs, the Dutch have employed measures
such as fast-track satellite tie-ins enhanced by drilling extended-reach
exploration wells from existing platforms. In addition, approximately
21 new offshore gas fields could be developed by the end of 1999.
In April 1997, the Dutch gas distributor Gasunie
confirmed that it is conducting a feasibility study for the construction
of a North Sea gas pipeline between Britain and Den Helder, a
northern Dutch city. In the short-term, the proposed pipeline
will enable Gasunie to import relatively cheap UK gas, and long-term,
it will place the Dutch company in a strategic position to broker
sales of Russian and Norwegian gas to the UK market. Eventually
the line may compete with the future Interconnector link between
Bacton, England and the Belgian port city of Zeebrugge.
GERMANY
ENERGY PROFILE - Norway
ENERGY PROFILE - United Kingdom
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OIL - Norway
Norway has 11.2 billion barrels of proven oil reserves,
the largest of any country in Europe. For the first half of 1997,
Norway produced 3.3 million bbl/d making it one of the world's
leading oil producers and the second largest oil exporter behind
Saudi Arabia. Most Norwegian North Sea crude oil has low sulfur
content and gravities in the 34o to 44o
API range. The majority of Norway's oil reserves, as well as current
output, is concentrated in or near the Statfjord, Oseberg, Gullfaks,
and Ekofisk fields. Due to their mature nature, presently recoverable
oil reserves in these fields represent only a fraction of original
reserves. In the last decade, exploration has not resulted in
significant new discoveries. The largest recent find was the Norne
field, discovered in 1991 and located in the Norwegian Sea. Much
of Norway's exploration has now moved to areas farther north.
Recently, Norway announced its 15th and 16th licensing rounds,
with most of the acreage located in the Norwegian Sea and Barents
Sea.
Norway holds 47.7 Tcf of natural gas reserves. The
Troll Gas Sales Agreements (TGSA) signed in 1986 were a crucial
step in guaranteeing a future export outlet for Norway's gas production.
Additional European gas deals include a January 1995 agreement
by Gaz de France to purchase 1.4 Tcf over a 26-year period beginning
in 2001. The deal provides Norway with a 35 percent share of the
French gas market. With existing sales contracts, Norwegian gas
reserves are predicted to last at least another century.
UNITED KINGDOM
Through August 1997, the United Kingdom's economic
outlook showed signs of improvement over the previous year. The
real gross domestic product (GDP) growth rate increased one percentage
point from 2.1% in 1996 to 3.1% for the first eight months of
1997. Thus far, the 1997 unemployment rate has dropped from 7.5%
in 1996 to 5.9%. However, inflation is slowly beginning to rise
from 2.4% in 1996 to 2.8%. These current trends are projected
to continue in 1998. Real GDP and unemployment are predicted to
remain about the same with inflation continuing to rise at the
same rate.
OIL - United Kingdom
The UK North Sea contains proven oil reserves of
4.5 billion barrels, the vast majority of which are in traditional
producing basins east of the British Isles. However, the DTI believes
new frontier areas, such as the West of Shetlands region, could
eventually double the UK's proven oil reserves. Most of the UK's
crude oil production ranges in gravity from 30o to
40o API, with most high quality crude being exported,
while cheaper, lesser quality (mainly from the Middle East) crude
oils are imported for refining.
The UK North Sea contains an estimated 24.7 Tcf of
natural gas reserves. Most of the UK's non-associated gas fields
are located in the Southern Gas Basin, adjacent to the Dutch North
Sea sector. Key producing gas fields include Amoco's 5.7-Tcf Leman,
and Shell's 1.7-Tcf Indefatigable and 0.8-Tcf Clipper. There are
several other large non-associated gas fields under development.
The biggest is the 2.6-Tcf Britannia field. In December 1994,
the government approved the field's $2.5-billion development.
A consortium consisting of two main partners, Chevron and Conoco,
as well as Union Texas, Sante Fe, Texaco, Phillips, Petrofina,
Amerada Hess, and Agip are developing the field. Production is
expected to start in late 1998. The field's output will peak at
an estimated 740-million cubic feet per day (mmcf/d) and 70,000
b/d of condensate. In preparation for the field to come online,
a new 27-inch pipeline was completed in June 1997. The 115-mile
line will transport gas from the Britannia field to the St. Fergus
terminal in Scotland with a peak capacity of 740 mmcf/d. The condensate
is expected to be exported via the Forties pipeline system. The
new pipeline is scheduled to come on stream when production at
Britannia begins in 1998.
In July 1997, the Danish ministry of Environment
and Energy announced plans for constructing a new natural gas
pipeline from the new South Arne field to a gas treatment facility
in Nybro on the west coast of the Jutland peninsula. The field
is operated by Amerada Hess, and the treatment facility is run
by DONG, the government-owned and sole concessionairy vendor of
oil and gas from the Danish North Sea. The 186-mile line is expected
to be operational by mid-1999 and cost about $250 million. With
a capacity of 459 mmcf/d, the pipeline will increase the total
transportation capacity of natural gas from the North Sea to Denmark
to 1.4 Bcf. The new pipeline will also connect to an existing
line running from the Harald field. A contract has been signed
for the production, storage, and personnel facilities at the South
Arne field, with the total investments in this combined oil and
gas production facility estimated at $500 million. The platform
at South Arne will process 50,000 bbl/d of oil and 71 mmcf/d of
gas with a concrete gravity base substructure storing up to 550,000
barrels of oil. In addition, Denmark's Energy Agency announced
a fifth licensing round in August 1997 offering all available
acreage in the Danish Central Graben area. The relaxed licensing
terms along with less state participation, introduced in the 4th
round in an attempt to attract foreign investors, will continue
to apply. In September 1997, the Energy Agency also released oil
and gas production forecasts for the near future. The Agency predicted
that oil and NGL production from the North Sea would continue
to climb over the next two years from about 243,000 bbl/d in 1997
to 314,000 bbl/d in 1999. Gas production is also predicted to
continue rising from an estimated 725 mmcf in 1997 to 795 mmcf
in 1999.
Dutch offshore oil production reached its peak in
September 1986, at 66,500 bbl/d. Since that time, production has
been declining. According to the Ministry of Economic Affairs,
total oil production for 1996 was down to a daily average of 45,500
bbl/d and total output from its eleven offshore producing fields
declined 19 percent from 1995. Many of The Netherlands' fields
have reached or are nearing the decommissioning stage. Fields
such as Kotter and Logger, both operated by Conoco, are expected
to cease production by the end of 1997 or early 1998. Conoco is
currently trying to sell the four platforms from the two fields.
Despite the decline, new field developments over the next few
years using low-cost minimum facilities and subsea systems should
at least maintain oil output for The Netherlands.
Germany's offshore oil industry comprises only two
producing fields, Schwedeneck-See and Mittelplate, both operated
by the German company RWE-DEA. For 1997, production at Schwedeneck-See
is expected to average 1,700 bbl/d while production at Mittelplate
is expected to average 11,000 bbl/d. The 14 production wells at
Schwedeneck-See should continue to produce until 2001, with Mirrelplate
lasting perhaps until 2030. A seventh well on Mittelplate should
be completed in the fall 1997 and should increase production.
However, Germany's most promising undeveloped offshore prospect
is Wintershall's A/6-B/4 gas project. The project is currently
in the approval process with the German government. The field
is estimated to contain reserves of up to 250 mmcf of gas, and
engineering work is scheduled to begin in 1998.
Minister of Oil and Energy: Ranveig
Froiland
Proven Oil Reserves (1/1/97): 11.2
billion barrels
Oil Production (1H 1997):
3.3 million barrels per day (bbl/d), of which 3.2 million b/d
is crude oil
Oil Production Capacity (1H 1997):
3.3 million bbl/d
Oil Consumption (1996E):
0.2 million bbl/d
Crude Oil Refining Capacity (1/1/97):
307,000 bbl/d
Total Gross Oil Exports (1996E):
3.2 million bbl/d
Natural Gas Reserves (1/1/97):
47.7 trillion cubic feet (Tcf)
Natural Gas Production (1996E):
1.45 Tcf
Natural Gas Consumption (1996E):
0.10 Tcf
Natural Gas Net Exports (1996E):
1.34 Tcf
Electrical Generation Capacity (1/1/96):
26.6 gigawatts
Electricity Generation (1996E):
103 billion kilowatt hours
Electricity Consumption (1995):
106.5 billion kilowatt hours
Coal Production (1996E):
0.3 million short tons
Coal Consumption (1996E):
1.6 million short tons
Major Systems: Statfjord,
Oseberg, Gullfaks, Ekofisk
Major Companies: Amoco,
BP, Conoco, Elf, Esso, Fina, Mobil, Norsk Hydro, Phillips, Saga,
Shell, Statoil, Total, Chevron
Secretary of State for Trade and Industry:
Margaret Beckett
Proven Oil Reserves (1/1/97): 4.5
billion barrels
Oil Production (1H 1997): 2.7
million bbl/d offshore (of which 2.4 million bbl/d is crude oil)
and 0.1 million bbl/d onshore
Offshore Oil Production Capacity (1H 1997):
2.8 million bbl/d
Oil Consumption (1996E):
1.85 million bbl/d
Crude Oil Refining Capacity (1/1/97):
1.9 million bbl/d
Total Gross Oil Imports (1996E)
1.2 million bbl/d
Total Gross Oil Exports (1996E):
2.1 million bbl/d
Natural Gas Reserves (1/1/97):
24.7 trillion cubic feet (Tcf)
Natural Gas Production (1996E):
3.17 Tcf
Natural Gas Consumption (1996E):
3.19 Tcf
Natural Gas Net Imports (1996E): 0.02
Tcf
Recoverable Coal Reserves (12/31/93):
2.76 billion short tons
Coal Production (1996E):
55.8 million short tons
Coal Consumption (1996E):
80.6 million short tons
Electrical Generation Capacity (1/1/96):
67.4 gigawatts
Electricity Generation (1996E):
310 billion kilowatt hours
Electricity Consumption (1996E): 305
billion kilowatt hours
Major Systems: Brent, Ninian, Forties,
Flotta, Fulmar
Major Fields: E. Brae,
Brent, Forties, Magnus, Miller, Scott
Major Companies: Amerada
Hess, Amoco, BHP, BP, Chevron, Exxon, Kerr-McGee, Mobil, Phillips,
Shell, Texaco
For more information on the North Sea, see these other sources on the EIA web site:
International Petroleum Statistics Report - EIA's latest monthly international petroleum data
International Energy Annual 1995 - Annual international energy data through 1995
Latest EIA Detailed Annual Data (1995) - Norway
Latest EIA Detailed Annual Data (1995) - United Kingdom
WORLD ENERGY Database for the International Energy Annual (requires Microsoft Access)
1996 CIA World Factbook - Norway
1997 CIA World Factbook - United Kingdom
U.S. International Trade Administration, Country Commercial Guide - Norway
U.S. International Trade Administration, Country Commercial Guide - United Kingdom
U.S. Department of Energy's Office of Fossil Energy's International section - Norway
U.S. Department of Energy's Office of Fossil Energy's International section - United Kingdom
Norway's Ministry of Industry and Energy
Norway's Ministry of Environment
Norwegian Petroleum Directorate
Statoil - Norway's state oil company
Norwegian Electric Power Research Institute
Norwegian Electricity Foundation
Links for United Kingdom
British Petroleum
Shell Oil
UK Energy Centre
Energy Links for the UK from Online Energy Services
Douglas MacIntyre
dmacinty@eia.doe.gov
Phone: (202)586-1831
Fax: (202)586-9753
URL: http://www.eia.doe.gov/cabs/northsea.htm