Europe`s gas supply industry grew before the establishment of the European Union (EU) as a number of independent, rigid structures intended to guarantee supply to customers.
The global trend towards privatization of state monopolies and the development of the EU with the aim of creating a Europe-widesingle market forced Europe`sgas industryto consider change.
Apart from Germany, virtually all Europe`s gas supply was delivered by state-owned monopolies. In the early 1990s, the U.K. dismantled British Gas plc and pushed for liberalization of other European gas industries along the same lines.
The drive for a single gas market in the EU centered around development of a European gas directive, which was agreed in late 1997 but which fell way short of the hopes of the liberalization lobby.
Though the move towards a completely open single European gas market eventually floundered, after much wrangling among energy ministers, the gas supply sector had nevertheless seen dramatic changes:
- British Gas had its U.K. domain carved up and offered to new independent suppliers, which were granted the right by government to deliver gas to customers through the British national grid.
- A group of U.K. gas producers and continental gas suppliers formed a company to build a pipeline from Bacton, U.K., to Zeebrugge, Belgium, to transport gas to European customers.
- The EU agreed to a diluted version of its gas directive, setting out plans for the opening of one third of the European gas market, comprising the large industrial customers most vociferous in support of competition in gas supply.
U.K. carve-up
During the 1990s, the U.K. government forced former monopolist British Gas to relinquish market share to new suppliers, first in industrial, then in commercial, and finally in residential markets.
The new suppliers were granted the right to supply gas through the British Gas grid on payment of a tariff.
British Gas reacted by splitting itself into two companies. One of them, BG plc, was to operate most of the former company`s U.K. and international exploration and production operations plus overseas downstream projects and the lucrative U.K. transport grid. The other company, Centrica plc, was established to operate some U.K. gas production and gas supply to customers, along with dwindling retail operations in the U.K.
In June 1997 BG bowed to the inevitable and accepted U.K. gas transport charge cuts forced on it by gas industry regulator Office of Gas Supply (Ofgas).
BG plc had failed in a bid to escape a government ruling in favor of massive cuts in gas transportation charges to third parties using its U.K. gas transmission grid.
The U.K.`s Monopolies & Mergers Commission (MMC) ruled that BG`s Transco unit must cut charges by 21% for the period April 1997 to March 2002.
MMC also decreed that along with the initial cut, BG must reduce transport charges by 2%/year for the rest of the control period.
The MMC requirement was a little tougher than that proposed by Ofgas when it called in MMC to solve its dispute with BG in October 1996.
Ofgas reckoned the cuts would lead to a 9% reduction in the annual gas bills of residential customers and a 5-7% reduction in gas costs for industrial and commercial customers.
Clare Spottiswoode, Ofgas director general, said: "As well as benefiting consumers, the MMC report will also be of benefit to shareholders because it provides a stable, predictable, and transparent regulatory regime for Transco."
BG didn`t see it like that. The company claimed the ruling would reduce its revenues by 5% in 1997-98, by a further 7% in 1998-99, and 1-2%/year in the following 3 years.
MMC also disregarded BG`s evaluation of its assets, assigning the company total assets of £11.6 billion ($18.6 billion), compared with BG`s estimate of £17 billion ($27.2 billion) true replacement costs.
David Varney, BG chief executive, said: "As a result of this fundamental change, BG intends to write down the value of the company`s assets in Transco by some £5 billion ($8 billion)."
Varney said BG rejected Ofgas`s proposal to slash transport charges because earnings would not be sufficient to maintain the gas network properly while allowing a fair return to shareholders.
"This is a tough settlement," said Varney, "but, provided we continue to improve our efficiency, one which we believe will enable us to manage and finance our business effectively.
"The MMC report has provided the opportunity to end a prolonged period of regulatory instability and uncertainty. To this end we have begun to work with Ofgas to translate MMC`s recommendations into new license terms."
In October 1997 BG formally accepted the pricing formula set by Ofgas for transportation of gas through the U.K. national grid by BG`s Transco unit, ending a long-running battle between BG and the regulator.
While MMC had recommended a 21% cut in Transco`s third party transportation charges, the final deal called for average transportation costs cuts of 25% in fiscal 1997-98.
"This announcement marks the end of a process begun in 1995," Spottiswoode said. "The result will be a considerable reduction in gas transportation charges to the benefit of all gas consumers."
Under the final deal, Ofgas will allow 50% of Transco`s income from independent gas suppliers to vary with throughput, as recommended by the MMC.
However, Ofgas increased its required cut in transport costs to 25% because gas demand was running above Transco`s estimates on which the MMC recommendation was based.
BG`s Varney said it seemed clear that the MMC recognized "the inherent uncertainty of demand for Transco`s services and carefully considered the proposed mechanism for dealing with it."
Meanwhile, Utility Buyers` Forum (UBF), a group of the U.K.`s largest commercial and public sector organizations, complained to Ofgas that the administrative costs of competitive gas supply outweighed price savings.
UBF said that as a result of administrative costs and unsolved billing errors, roughly half of its commercial and industrial members were no longer seeking to participate in the competitive gas market.
"Public sector organizations," said UBF, "which are obliged by law and public sector policy to seek formal competitive tenders for gas, were concerned that the failure of competition was wasting tax-payers` money on futile and inflexible tendering exercises."
Centrica, meanwhile, sought to reduce payments for gas under long-term take-or-pay agreements set up before the government forced it into competition.
In summer 1997 Centrica agreed with three gas suppliers over termination of deliveries from U.K. North Sea Beryl field.
Beryl gas supplies from Amerada Hess Ltd., Enterprise plc, and OMV (U.K.) Ltd. were to terminate on Oct. 1, 1998, in return for payment of compensation by Centrica. Details of the compensation were not disclosed. Beryl operator Mobil North Sea Ltd. agreed to end its contract earlier in return for assets interests.
In October 1997 Centrica concluded agreements for termination of the Welland field gas supply contract. U.K. North Sea Block 53/4a Welland is owned 75% by operator ARCO British Ltd. and 25% by Eastern Natural Gas (Offshore) Ltd., a unit of a U.K. electricity utility.
Centrica said the contract was terminated immediately in return for an undisclosed payment to ARCO and Eastern.
Also in 1997, U.K. gas market entrants began jockeying for market share.
In June Shell U.K. Ltd. bought the 50% shareholding in U.K. gas marketing joint venture Quadrant Gas Ltd. from partner Esso U.K. plc for an undisclosed sum.
Quadrant claimed to have been the first independent marketer to deliver natural gas to industrial and commercial users in the U.K.`s liberalized gas supply market.
The company claimed 6% of the U.K.`s commercial and industrial gas market and in 1995 made a profit of £1.5 million ($2.4 million) on turnover of £120 million ($192 million).
In June 1997 BG Exploration & Production began to sell off all exploration and production assets in seven out of 16 countries in which it operates, in a bid to tidy up its portfolio.
BG held an E&P portfolio built up hurriedly to counterbalance the U.K. government`s ending of the British Gas domestic supply monopoly.
Though BG did not initially reveal which assets were earmarked for sale, a BG spokesman confirmed they were likely to be small scale projects where the company was not operator.
The assets were to be sold in packages over 12 months and were expected to earn BG a total $500-1,000 million. The spokesman said the company was already in discussions for sale of some of the assets.
BG planned to retain nine core operating areas. The spokesman said the disposal would reduce the value of the company`s assets by less than 10%.
Among areas where BG planned to increase investment, the spokesman listed the U.K., an exploration license and liquefied natural gas project in Trinidad, Rosetta discovery offshore Egypt, Bongkot field off Thailand, Muturi discovery in Indonesia, and Karachaganak field in Kazakhstan.
In Karachaganak BG agreed to reduce its share from 42.5% to 32.5% through a sale to Texaco Inc. The deal was subsequently approved by the Kazakh government.
As the U.K. developed a spot gas market following liberalization, London`s International Petroleum Exchange reported growing trading volumes for its natural gas futures contracts.
A record 1,595 contracts changed hands on Sept. 23, 1997, representing more than two thirds of U.K. natural gas production. IPE said contracts representing a total of 3,000 MMBTU had been traded since the contracts were launched on Jan. 31, 1997.
Four companies subsequently joined IPE with a view to hedging their gas transactions: Alliance Gas Ltd., BP Gas, Enron Europe Ltd., and Westminster Clearing Ltd.
U.K. liberalization was not without problems for residential customers. In October 1997 Ofgas proposed changing the terms in licenses for independent gas suppliers following complaints of rogue sales teams in areas opened to gas competition.
Ofgas suggested license holders keep records of marketing complaints and submit them to Ofgas for publication at 3-month intervals. Companies that misled customers would be liable to pay compensation, while fines and suspensions of licenses would be used to ensure compliance with license terms.
Keen to expand as a way of dealing with increasing competition, in August 1997 British Gas Trading Ltd. began supplying electricity under its first power contract in the U.K. industrial and commercial market.
The customer was Hydrocarbon Resources Ltd., which like British Gas Trading was a unit of Centrica. Hydrocarbon Resources was set up to operate the North and South Morecambe gas fields in the U.K. Irish Sea. Under the contract, British Gas agreed to provide electricity to three onshore sites.
Frigg treaty
In May 1997 the governments of the U.K. and Norway agreed to a revision of the Frigg pipeline treaty which could lead to increased sales of Norwegian gas to the U.K. and even to the continent via the U.K.-Belgium Interconnector pipeline.
The Frigg treaty was signed in May 1976 to enable gas from Norway`s Frigg field to be delivered by pipeline to St. Fergus terminal north of Aberdeen.
In 1992 Norway requested permission to develop other gas fields in the vicinity of Frigg, but the U.K. government refused to allow gas from fields not mentioned in the treaty to be imported.
While Tim Eggar was U.K. energy minister, Britain appeared to be stalling over renegotiation of Frigg, though Eggar always maintained discussions were continuing.
In 1995, the U.K. relaxed its position, recognizing that its calls for establishment of liberalized gas markets across Europe were at odds with its stance over the Frigg treaty.
Frigg operator Elf Norge AS brought Frigg`s Froey satellite on stream in 1995, but only when Lord Fraser of Carmyllie took over as U.K. energy minister in 1996 did Frigg negotiations progress significantly.
The U.K. Department of Trade & Industry (DTI) said the revised Frigg treaty would enable Norway to sell non-Frigg gas to customers in the U.K. and other countries, and to offer spare capacity in the Frigg pipeline to U.K. operators.
The revised treaty also covered laying and operation of new offshore pipelines crossing the U.K.-Norway marine boundary and connections between British and Norwegian infrastructure.
The revisions, said DTI, "...should also enable new projects involving such pipelines to be agreed by both governments without the need to draw up a separate treaty for each project as has been the case to date."
Interconnector
The £450 million ($675 million) Interconnector pipeline from the U.K. to Belgium was designed to deliver 20 billion cu m/year of gas beginning Oct. 1, 1998.
By the time the U.K.-Belgian treaty permitting operation of the Interconnector was signed in December 1997, the offshore section of the pipeline had been laid and tested. Work was then under way on the compression terminal at Bacton and the receiving terminal at Zeebrugge.
By then interest holders in the pipeline, which formed Interconnector (U.K.) Ltd. to operate the pipeline, had clinched eight sales contracts amounting to a third of its capacity.
Interconnector shareholders were BG 40%; BP Exploration Operating Co. Ltd., Conoco (U.K.) Ltd., Elf Exploration U.K. plc, and Gazprom 10% each; and Distrigaz SA, Ruhrgas AG, Amerada Hess Ltd., and National Power plc 5% each.
Contracts for delivery of U.K. gas to Europe signed between February 1996 and November 1997 were Conoco to Wingas, 1 billion cu m/year for 10 years; BP to Wingas, 2 billion cu m/year for 10 years; BP to Ruhrgas, 1 billion cu m/year for 15 years; Centrica to Thyssengas 0.5 billion cu m/year for 7 years; Mobil to Norsk Hydro Agri, 0.8 billion cu m/year for 15 years; Centrica to Elsta, 1 billion cu m/year for 8 years; Centrica to Entrade & Delta, 0.7 billion cu m/year for 8 years; and Conoco to Gasunie, 1 billion cu m/year for 8.5 years beginning Apr. 1, 1999.
At the treaty signing Roger Cornish, managing director of Interconnector (U.K.), said: "In providing an efficient trading infrastructure, the Interconnector provides Europe with a mechanism for ensuring stability and security of supply well into the next century.
"It is also a vital impetus for the U.K. gas industry itself to discover and develop new gas reserves on the U.K. continental shelf."
While the Interconnector was built with exports from the U.K. to Europe in mind, there was provision to transport compressors from Bacton to Zeebrugge for installation to reverse the flow of gas, with capacity of 8.5 billion cu m/year, should market demand require it.
The opening of the pipeline was expected to bring lower gas prices in Continental Europe and shorter duration gas contracts, according to Wood Mackenzie Consultants Ltd., Edinburgh.
The analyst said that beyond 1998 it would no longer be possible to regard U.K. and continental gas markets as separate. However, the failure to agree on full market opening may dampen the Interconnector`s long-term market effects.
"An analysis of supply/demand fundamentals in selected European markets," said Wood Mackenzie, "shows a fully contracted future supply situation, particularly in Italy.
"In Germany, the only country with competing transmission systems, there is potential for future development of an oversupply position as the sum of gas supplies contracted by the competing players may exceed aggregate demand.
"Expectation of a future oversupply has been fueled by the significant number of infrastructure projects that have been commissioned to increase the delivery capabilities of the major producers supplying Europe, such as Russia with the Yamal pipeline, Algeria, Norway, and the U.K. through the Interconnector."
Wood Mackenzie said U.K. gas is 30% cheaper to customers than continental gas since the U.K.`s gas market liberalization, and the price difference is expected to shrink.
"As the U.K. traded gas market continues to develop," said the analyst, "attention is increasingly turning to the future development of gas trading on the continent.
"However, on the basis that continental European gas markets will for the foreseeable future evolve on the basis of negotiated access, the development of trading will be limited to specific locations where sufficient buyers and sellers exist.
"At Zeebrugge, such access is limited to the select few which have contractual access to Distrigaz`s transmission system, and/or hold equity in the Interconnector.
"Ownership of transmission systems guarantees a dominant position within the European gas market at this stage of its liberalization, where nondiscriminatory third party access is not assured."
Gas directive
As the Interconnector pipeline was being built, momentum grew for liberalization of European Union gas markets.
Though Britain stormed ahead of the rest of Europe with total market opening, the previously rigid governments of the Netherlands and Germany made the first tentative steps towards full debate about liberalization.
The gas directive was expected to reduce the power of state firms that dominated several continental countries` gas industries, and of private companies with virtual monopolies in some market sectors.
A liberalized Europe-wide gas market was expected to be good for the private sector in general. New suppliers would be able to enter the market, using new technology to give them an edge over existing suppliers.
In Germany in particular, established companies, as represented by its largest gas supplier Ruhrgas AG, campaigned against drastic changes, particularly third party access to pipelines.
Dr. Burckhard Bergmann, vice-chairman of Ruhrgas, told a gas conference in Oslo that the German economy ministry`s proposed amendment to the energy law, as presented to the Bundestag, threatened to withdraw special rights for pipeline operators without introducing any special obligations.
"The German gas industry firmly rejects unrestricted third party access," said Bergmann, "an approach which national legislation does not propose.
"In a country which has around 700 gas businesses and where several transmission companies have international shareholding structures, this would hardly be possible without a considerable regulatory effort."
Bergmann warned that antitrust reviews against companies alleged to have abused dominant positions could lead to problems because of the difference between federal and state governments.
"There can be no comparison with the U.K., Canada, and other countries," said Bergmann, "where uniform systems allow for blanket solutions. And if creeping regulation is not reason enough to reject compulsory third party access, the overriding reason for rejection is the threat to the effective operation of long term contracts, which are crucial for security of supply in countries which depend on imports.
"Not only that, compulsory third party access would upset the market balance between the few, centrally organized gas exporting nations and the consumer countries."
Ruhrgas feared that the EU`s gas directive would take effect before national legislation. This would have complicated Germany`s complex gas situation even further, said Bergmann, because of the EU`s stance on reciprocity in trade between member countries and between EU and nonmember states.
"Another interesting issue is the way in which the Interconnector will affect the continental market," said Bergmann. "Elements of British competition will be brought to the continent once the U.K. gas market docks with continental Europe.
"For the time being, at least, the role of the Interconnector as a transport vehicle for long term supply contracts will be less significant than originally expected. Long term export contracts with U.K. suppliers are well below initial expectations.
"The true significance of the Interconnector is more likely to emerge in terms of the short term supply-demand balance between the continent and the U.K.
"We expect the regulatory structure in the U.K. to generate some spot gas elements on the continent, although these will not be predominant. And we also expect the Interconnector to dampen erratic price developments such as we saw in the U.K. last winter. Seasonal pricing will probably become more pronounced.
"It would be wrong to think that the German gas industry needed the EU gas directive to open its eyes to market change and to meet the new challenges.
"From the very beginning, the private enterprise structure and organization of the industry, and the fact that the industry has to purchase its product on a competitive international market, has compelled it to be efficient and performance-oriented."
Management consultant Price Waterhouse polled top executives in 34 natural gas companies in 16 European states to gauge views on the European directive.
Seventy per cent of the executives regarded a single market as an attractive proposition, while 68% believed their companies were well or moderately well prepared for competitive supply.
Even before the conclusion of the wrangling of EU energy ministers, however, two thirds of the executives saw the directive would not be implemented as a single market agreement.
Price Waterhouse said established gas suppliers saw take-or-pay contracts as the major obstacle, whereas new or potential entrants saw negotiating access with gas transporters as the main obstacle.
The poll showed why achieving a single market was such an ambitious aim: 41% said the proposals did not go far enough; 34% thought they were about right. There were obvious differences between new or potential entrants and the companies already in place.
Nevertheless, two thirds of respondents said they thought a truly pan-EU gas market would be a reality within 10 years, while one fifth thought a single market would be achieved within 5 years.
At the World Gas Conference in Copenhagen in mid-1997, when gas directive optimism was at its highest for years, the effects of liberalization were nevertheless not expected to be uniformly beneficial.
Gerard Leger, vice-president and general manager of Schlumberger Industries Electricity & Gas Management, Paris, said he expected introduction of the directive to be followed by mergers among electricity and gas utilities.
Leger, whose division provides data collection and management systems to the electricity, gas, and water industries, said, "As the companies integrate horizontally, we hope they will play into our hands."
While Schlumberger was already negotiating with a number of companies over development of equipment to meet new market requirements, Leger said a lean period would follow the directive.
"As a rule of thumb," said Leger, "deregulation leads to a slowdown of activities. The utilities have to get an understanding of the new rules before they begin once more to invest.
"At the moment the U.K. market is at a low, after liberalization, while other European markets are going reasonably well because European gas suppliers are still expanding their infrastructure."
An executive of Itron Inc., a Spokane, Wash., supplier of automatic meter reading equipment to utilities worldwide, foresaw a slow take-off of business after liberalization.
"There will be a gradual expansion of business after the gas directive rather than an explosion," said Klaus Huschke, Itron`s senior vice-president international operations. "Utilities are conservative, and their decision processes are orderly and analytical.
"It took the U.S. quite a while before we saw explosive change among gas utilities, which behaved more aggressively than electricity and water companies."
Huschke said private gas suppliers in the U.S. adapted quickly to using remote automatic meter reading. Itron was negotiating with a number of utilities in Europe, where meter reading was still labor-intensive.
One potential benefit of the gas directive for equipment manufacturers was seen as increasing standardization of gas supply equipment specifications as cross-border projects flourished.
"Unity in specifications would be wonderful," said Huschke. "We could focus on adding extra capability to our products rather than on having to make our products fit a wide number of specifications."
Gas agreement
Late in 1997 European Union energy ministers agreed to open one third of Europe`s gas market to competition in a compromise which fell way short of original plans for a single European gas market.
A deal struck on Dec. 8, 1997 called for opening of the EU members` gas markets in three phases over 10 years, following a second reading of the draft directive by the European Parliament and formal adoption of the directive in first half 1998.
The agreement was cautiously welcomed by large industrial gas users, the main force behind the move to liberalization in Europe, but was seen as a victory for Europe`s gas monopolists over U.K. and Nordic reformers.
Governments and gas suppliers in the Netherlands, France, and Germany were particularly keen to block access to their domestic gas distribution grids under a single gas market.
An earlier draft directive based on similar plans for a single European electricity market failed to gain a consensus. In 1996 the EU vainly pursued success with a redrafted directive incorporating the monopolists` concerns.
The final agreement required member states to open 20% of their gas markets to competitive supply initially. After 5 years they would have to raise this to 28%, and after 10 years to 33%.
Only customers with gas consumption of more than 25 million cu m/year were initially deemed eligible to choose their supplier. This threshold would be reduced to 15 million cu m/year after 5 years and 5 million cu m/year after 10 years.
The EU`s energy council decided that all electricity producers, regardless of annual gas consumption, are also eligible for choice of gas supplier. "However," it said, "in order to safeguard the balance of their electricity market, member states may introduce a threshold, not exceeding the level decided for other industrial customers defined as eligible, for the eligibility of combined heat and power producers."
The EU gas supply market was estimated to be worth 100 billion European currency units (ECUs)/year ($90 billion/year). EU said the achievement of a common position was a decisive step towards establishment of an internal market for energy.
Although Norway was not a full member of the EU, the Norwegian state petroleum firm Statoil believed the directive could have a big impact on the country as a major gas exporter because of its membership of the European Economic Area, a group of countries with strong economic ties to EU.
Statoil said that Britain`s compromise proposal to include upstream pipeline networks in the directive, which was approved, provided for third party access to these facilities.
At the same time, said Statoil, governments could limit third party access under criteria specified within the directive, which EU felt should secure Norway`s national control over its offshore gas pipelines.
Peter Mellbye, Statoil executive vice-president, said, "Should the directive also apply to this area, the EU would intervene fundamentally in the ability of the Norwegian authorities to manage their own resources.
"Part of the basis for operating the transport network as an integrated part of the production system would be eliminated, and we`ll end up with a less effective solution than at present. "My understanding is that this view has been accepted in the final directive provisions. We`ve always had to compete with other suppliers. We`ll be girding ourselves to deal with market changes and increased competition, and we`ll still be strongly placed in relation to our rivals."
As the directive was agreed, Ruhrgas`s Bergmann was concerned that long-term take-or-pay contracts were still necessary to realize the long-term aims and capital-intensive projects important for European gas supply. Only the U.K. failed to protect take-or-pay contracts for the directive agreement, he said.
"Transport business will undoubtedly emerge," said Bergmann, "but constraints will result not least from the protection of existing long-term contracts on both the purchasing and sales sides.
"Pressure on margins will increase further. However, there has always been pressure on margins resulting from the relationship between producers and importers, but often the development of margins has not been correctly depicted.
"Pressure on margins does not necessarily mean lower profits for the industry. We at Ruhrgas try to preserve the company`s earning power by means of sales increases, cost management, and efficiency enhancement.
"We also expect some concentration in gas industries which are as pluralistic as in Germany. In addition, we anticipate some new elements of long-term contracts. Some of these are already incorporated in contracts between Norway and its continental customers.
"Finally, differences in tax regimes will become more critical in EU countries. After all, it is surely not acceptable that it should be preferable to build a gas-fired power station in the Netherlands rather than 100 km away on the other side of the German border because the difference in natural gas tax rates offsets the cost of electricity transmission over 200 km."
Two months before the gas directive was agreed the European Commission (EC) unveiled a strategy to boost development of combined heat and power (CHP) schemes.
The EC adopted a proposal by Energy Commissioner Christos Papoutsis to use tax incentives, setting of emission standards, and energy efficiency targets to promote CHP.
"The strategy we propose," said Papoutsis, "is another example of our determination to promote rational use of our energy resources and thus significantly reduce greenhouse gas emissions."
EC said a CHP scheme converts up to 85-90% of the energy content of fuels into electricity and heat, compared with only 30-40% efficiency of conventional electricity generating plants.
"The current 9% CHP penetration in the EU is well below what can be achieved technically and commercially," said the EC. "Doubling the current share to 18% by 2010 is realistically achievable and will bring major environmental benefits."
The EC estimated that doubling CHP capacity through replacing existing electric power and heat plants could reduce carbon monoxide emissions by 150 million metric tons/year, or 4% of total European CO emissions, by 2010.
The proposal called for CHP to receive an increased share of EU technical development funding and for negotiated agreements with industrial sectors where CHP could bring high levels of energy savings.
Future gas supplies
Abdelmadjid Attar, chief executive officer of the Algerian state firm Sonatrach, outlined his view of Europe`s gas supply problems at the Offshore Europe conference in Aberdeen in September 1997.
"With 4.2% of the world`s gas reserves and 16% of consumption, Europe is clearly the most dynamic element in the world gas industry," said Attar.
"Demand should continue to grow as a result of the power generation push to reach about 450 billion cu m in 2010 compared with 345 billion cu m in 1995.
"But Europe consumes its reserves rapidly. As from 2000, gas supplies from outside the EU will comprise the majority. Gas dependency could reach 55% in 2010 and 70% in 2020."
Attar said EU demand will be largely covered by continental Europe`s three long-standing suppliers-Algeria, Russia, and Norway-until 2010. Beyond 2010 market trends are cloudy.
In July 1997 Finland`s Neste Oy and Russia`s Gazprom set up a joint venture to study feasibility of building a pipeline to take Russian gas to Central Europe through Finland.
The 50-50 venture, North Transgas Oy, was expected to complete its plan by autumn 1998. Neste said route options were through western Finland to Sweden and on to Germany or via Finland through the Baltic Sea to Germany.
In August 1997 the European Commission (EC) announced aid with funding of feasibility studies for 21 projects designed to bridge missing links in Europe`s gas and electricity distribution grids.
The studies were expected to cost a total 15 million ECUs ($14 million), of which the EC would pay half, and were intended to help operators decide how projects would be implemented and when they would be carried out.
Among the gas projects was to be a detailed route design and preparation of a detailed environmental impact assessment by Edison SpA of an Italian extension of the Volta natural gas pipeline to take Russian gas from the Slovenian-Italian border to Ostiglia, 60 miles southwest of Venice.
Another study was to be conducted by Neste Oy for creation of a Nordic gas grid by linking the existing networks in Finland, Denmark, and Sweden. This would provide an additional route for Norwegian and Russian gas to market and may be extended to include the Baltic states.
Austria`s OMV Aktiengesellschaft was slated to undertake two studies, one for a new Austrian north-to-south pipeline known as Penta and one for a new underground storage facility at a junction of three pipelines at Baumgarten.
In Spain Enagas SA planned a seismic survey of potential underground natural gas storage facilities at Jumilla and Reus. Also Public Power Corp. of Greece planned a link to the Albanian gas grid.
Electricity distribution studies were to be for links between Sweden and Norway, U.K. and Norway, U.K. and the Netherlands, Greece and former Yugoslavia, and Greece and Bulgaria.
Papoutsis, the EC energy commissioner, said, "I wish to stress the vital role of trans-European energy networks in the evolving energy policy of the union, including the achievement of the single internal energy market, and in the implementation of the energy charter.
"The liberalization of energy flows requires adequate interconnections. In addition new supply lines and more thoroughly meshed grids are an important factor in reinforcing both overall security of supply and operational flexibility."
Meanwhile, Norway`s gas production capacity continued to grow. In August 1997 Norway`s Statoil let a 737 million kroner ($97 million) contract to M.W. Kellogg Ltd., London, for expansion of its gas treatment plant at KårstØ, southwest Norway.
Kellogg was to perform engineering, procurement, construction, and supervision, with completion slated for autumn 2000. The plant was to be expanded to handle gas from the Åsgard development off mid-Norway and was to include construction of a treatment plant, an ethane recovery unit, storage facilities, and jetties.
That same month Germany`s Wingas, a 65/35 joint venture between Wintershall AS and Russia`s Gazprom, started work on a new pipeline link for import of gas from Russia`s Yamal peninsula.
The Jagal pipeline was to run 330 km from Mallnow in Brandenburg to Ruckersdorf in Thuringia, where it would join up with the existing Stegal gas pipeline.
Jagal, slated for completion in mid-1999, was to form a part of the Yamal-Europe pipeline system, which is intended to carry Russian gas more than 4,000 km from Siberia to European markets.
Wingas said recent forecasts showed that Western Europe would require an extra 150 billion cu m/year of gas by 2010, one third of which would be met by the Yamal-Europe project.
The Jagal pipeline is to be 120 cm in diameter, said Wingas, with capacity to transport up to 28 billion cu m/year of gas. Capital cost was expected to be more than 1 billion Deutschemarks ($560 million).
Norway`s Statoil began talks with potential U.S. and Mediterranean customers for gas from the giant SnØhvit gas find in the Barents Sea off Northern Norway.
Statoil said SnØhvit and the nearby Askeladden and Albatross discoveries have estimated reserves of more than 10 tcf of gas. The state firm was planning to exploit these remote finds with subsea developments exporting gas to shore near Hammerfest for treatment and liquefaction.
Statoil said production could begin as soon as 2001.
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Gas suppliers have built an offshore link from the U.K.`s gas grid in Scotland to Northern Ireland. Later Phoenix Natural Gas built a pipeline to take gas from northern to southern Belfast, which was to be operational by the end of 1998. Here the Dredging International NV backhoe dredger Zenne works on Lough Belfast after crossing the lake was deemed preferable to routing the pipeline through the city. Photo courtesy of Dredging International.
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