A shift toward gas is still expected, despite the release of a government white paper which concluded that the comparative costs of new gas-fired stations versus coal-fired power plants did not justify the scale and speed of the dash for gas. Gas-fired projects that already have full government consent may proceed. Officials indicate that, as a result, 9,000 megawatts of such generating capacity can be built in the next 3 years, adding an extra 584 billion cubic feet per year of gas demand in the United Kingdom by 2002 [10]. This increment would allow the gas share of power generation in the United Kingdom to grow to 48 percent and reduce the coal share to 20 percent, as compared with the 1997 mix of 27 percent for gas and 38 percent for coal.

In France, natural gas consumption is expected to grow from 1.3 trillion cubic feet in 1996 to 3.0 trillion cubic feet in 2020 according to the IEO99 reference case

projections. The bulk of gas use is currently in the residential and industrial sectors, and it is expected to remain there throughout the projection period, notwithstanding the growth in natural gas use for electricity generation [9. p. 116]. Natural gas penetration into the electric utility sector is expected to increase the current gas share from less than 1 percent to more than 9 percent by 2020. The main fuel for power generation in France is nuclear power, which is projected to maintain its dominant share in the coming decades.

Two major gas pipelines to serve France were completed in 1998. First, the NorFra pipeline began operating in October 1998, bringing gas from Norway's Draupner E platform (in the Norwegian North Sea) to Loon-Plage (in the western harbor of Dunkirk, France). The 520-mile pipeline cost nearly $1 billion to complete (including costs for converting the platform, installing the pipeline, and installing the receiving facilities at Dunkirk). The line is owned by a consortium of Statoil, Norsk Hydro, Shell, Esso, Elf, Saga, Conoco, Total, Neste, Mobil, and Agip. It is the world's longest subsea pipeline and will supply France with some 530 billion cubic feet of gas per year by 2005. Spare capacity from the NorFra will be used to ship Norwegian gas to Italy beginning in 2000 [11]. Gaz de France is building a new transit pipeline across France named the "Marches du Nord-Est" for the Norway-Italy gas transmission. Norway signed a 25-year contract with Italy in 1997 for the supply of 212 billion cubic feet of natural gas per year beginning in 2000.

The second major pipeline project completed in France was the 115-mile Artere des Hauts-de-France pipeline, which links the NorFra terminal at Dunkirk to the French pipeline system near the Gournay-sur-Aronde storage facility in Oise, north of Paris. Costing about $178 million, it is the largest high-pressure pipeline in France. The existing French pipeline system now allows

gas to transit from Norway to Spain, as well as accommodating imports from the Netherlands and Russia transiting through Germany, Austria, and Belgium (2, p. 28; 12, p. IV.16].

Gas consumption in Germany is expected to grow from 3.7 to 7.5 trillion cubic feet between 1996 and 2020 in the IEO99 reference case. Since Germany's reunification in 1989, natural gas use has grown fairly quickly, as West Germany developed East Germany's gas infrastructure and converted brown coal district heating plants to run on gas [9, p. 149].

The new German government of Social Democrats (SPD) and Greens took office in October 1998 and stated its intent to dismantle the country's nuclear power industry by 2002 (13). The new government is interested in increasing Germany's reliance on renewable energy sources, although wind power and hydroelectricity provided only 0.5 percent of Germany's 1997 primary energy requirements. Gas-fired capacity may increase as well, inasmuch as it will be difficult for the country to absorb the entire 30-percent nuclear share of electricity generation by 2002. On the other hand, the government has also proposed higher fossil fuel taxes for both electricity generation and the energy market at large, including a new tax on electricity generated from fossil fuels at 2 pfennigs per kilowatthour ($3.57 per million Btu). Taxes on natural gas would increase from 0.36 pfennigs per kilowatthour to 0.68 pfennigs per kilowatthour ($1.10 per million Btu). The SPD and Greens have announced that the revenues raised by the higher energy taxes will be used to fund job creation programs. The government had not released a timetable for implementing the new tax scheme at the time this report was prepared for publication.

One of the fastest-growing markets for gas in Western Europe is Spain (Figure 36). Natural gas demand has grown strongly in this country since the commission of the Maghreb-Europe pipeline from Algeria in 1996. According to the International Energy Agency, natural gas consumption expanded by 28 percent between 1996 and 1997 [12, p. III.300]. Spain has announced plans to install 10 gigawatts of combined-cycle gas turbine electric power plants (scaled back from an original 14 gigawatts, because the country already has excess generating capacity) [14].

In September 1998, Spain enacted its new Hydrocarbons Law, which will liberalize the country's gas markets by 2013 [15]. The Hydrocarbons Law expands on three natural I gas decrees issued by Spain's Ministry of Industry and Energy over the past 2 years [16]. It supplies third-party access to the existing Spanish gas infrastructure, allowing all electricity generators, industrial users, and cogeneration plants of more than 876 million cubic feet per year to negotiate for access to LNG terminals,

storage facilities, high-pressure pipelines that belong to the national gas grid, and international gas connectors. The new law will allow industrial users of more than 530 million cubic feet per year to switch from supplier Enagas beginning in 2000; by 2003 it will allow industrial users of more than 144 million cubic feet per year to switch suppliers. Only the United Kingdom has a more liberalized gas market in Europe.

Another European country that is only now beginning to develop its natural gas infrastructure is Portugal. The country began consuming natural gas in 1997, when gas supplied by Algeria through the Maghreb-Europe pipeline became available for import through Spain. Now, Transgas-Sociedade Portuguesa de Gas Natural has proposed the construction of an LNG terminal in Peniche, Setubal, or Sines [17]. No timetable has been set for a decision on the location of the LNG terminal, but Transgas has a 22-year supply agreement with Nigerian LNG for 12.4 billion cubic feet per year, beginning in 1999. Abu Dhabi and Trinidad are also considered potential LNG suppliers.

Eastern Europe and the Former Soviet Union

Although 1996 saw a reversal of the downward trend in natural gas markets in much of the EE/FSU region, markets in 1997 once again moved into decline. All but the Eastern European countries Poland and Slovakia showed decreases in consumption. Overall consump tion in the FSU, which accounted for 22.4 percent of the world's total consumption of natural gas in 1997, fell by 6.4 percent from 1996 levels [2].

Several FSU countries, including Turkmenistan, Ukraine, and Kazakhstan, are projecting GDP gains for 1998 and show evidence of being on the road to economic recovery. Russia, however, is in a state of financial, economic, and political turmoil. Inflation is increasing dramatically, and efforts to maintain a stable ruble have been abandoned as of August 17, 1998. The crisis is due in part to spillover effects of the East Asian economic crisis, which has curtailed the availability and raised the cost of foreign borrowing, and in part to the sharp decline in oil and gas prices. Russia, the world's largest exporter of natural gas and second largest exporter of oil, depends heavily on oil and gas export

revenues.

Gazprom, the Russian state gas company, controls more than 95 percent of Russia's natural gas production and is its largest taxpayer and hard currency earner. Because it has had difficulty making its tax payments due to nonpayment for supplies received by many of its customers, both domestic and foreign, Gazprom has resorted to curtailment of supplies in some instances and to barter in other instances in attempts to step up reduction in debts owed to the company. Bulk foodstuffs and participation

in the development of the portion of the Yamal-Europe pipeline crossing Belarus have been offered by Belarus in exchange for natural gas supplies. Food, steel pipes, and oil and gas equipment have been provided by Ukraine to clear debts owed for natural gas. Goods and services, along with participation in the construction of the section of the Yamal-Europe pipeline that will pass through Poland, have been pledged to Gazprom by Poland to satisfy debts. Moldova has agreed to give

Gazprom a 50-percent stake in its gas distribution network to clear part of its debt. Construction services have been agreed upon by Bulgaria to pay for part of the natural gas supplies it receives. The Russian government has prevented Gazprom from curtailing supplies to domestic users, and in August 1998 Gazprom agreed to begin making payments to reduce its tax debt in exchange for government pressure on domestic debtors to pay their gas bills.

The Russian government, which holds 40 percent of Gazprom stock, in August offered to sell 5 percent of its stake. Initially, the instability of Russian financial markets made the purchase unattractive to investors, and there were no takers. The government subsequently agreed to sell shares in blocks of 2.5 percent. Potential bidders included the German utility Ruhrgas, Royal Dutch/Shell, and Italy's Eni. Interfax news agency announced on December 21, 1998, that Ruhrgas—currently Gazprom's biggest export customer-had won the Gazprom stake for $660 million, $9 million above the Russian government's minimum requirement [1]. Gazprom itself has the option of selling another 7 percent of its own shares to foreign investors but is waiting for an upturn of the stock market to do so [18].

Russia is not alone among the FSU countries in being plagued by nonpayment for gas supplies. Uzbekistan cut off exports to Kazakhstan in 1996 for nonpayment, and Kazakhstan in return agreed to pay off its debt with Kazakh goods and with services such as transporting Uzbek products through Kazakhstan to other markets (19). Turkmenistan, once the second largest gas producer in the FSU, dropped its output by more than 50 percent in 1997 as a result of curtailment of gas deliveries to countries, such as Ukraine, that were behind in pay. ments. Turkmenistan's natural gas exports declined by 70 percent from 1996 levels, and it has fallen in position to fourth place in production in the FSU, behind Russia, Uzbekistan, and Ukraine. In February 1998, Turkmenistan entered into an agreement with Ukraine to supply gas through 2005, with barter for goods such as food and oil and gas supplies accounting for up to 60 percent of the payment [20].

Considerable restructuring of the natural gas industry is also underway in EE/FSU nations. In June 1998, an agreement was signed to break Gazprom into separate production, transmission, and distribution units; to allow greater access by independent producers to the pipeline system at the same rates as Gazprom's marketing unit, and to revise pipeline tariffs. The measures are to be introduced by July 1999 [21]. In August 1998 the Ukrainian government approved a plan to break up Urgazprom into three separate companies dealing with the production, transportation, and sale of natural gas [20]. In Azerbaijan, there is talk of restructuring Azerigas as part of Azerbaijan's goal to reduce imports significantly and become self-sufficient in natural gas. Foreign investment will be a critical component in the development of the natural gas industry in many of the EE/FSU countries. In addition to augmenting existing infrastructure, most countries need also to refurbish aging pipes and rehabilitate existing storage

and production facilities. Shell is exploring a possible joint venture with Romgas, the Romanian state gas company, to rejuvenate gas fields where production has declined, to expand the gas distribution network, and to increase gas storage capacity. As a result, Romania would be able to increase revenues for the transport of Russian gas to markets in the Balkans and Easter Europe, and to reduce its dependence on Gazprom for its own internal consumption needs [22].

Ukraine also hopes to reduce its dependence on natural gas imports by developing more of its own resources with the help of foreign investment. EuroGas, Inc., has agreed to develop coalbed methane resources in eastern and southwestern Ukraine; British Petroleum (BP) is looking into a joint venture to develop Ukrainian gas reserves; and Royal Dutch/Shell is evaluating the modernization of the country's pipeline infrastructure [20]. In Azerbaijan, legislation has been proposed to include foreign investment in the revamping of the country's natural gas industry.

Significant foreign investment has been made in the Yamal-Europe pipeline, which is Russia's primary infrastructure expansion project. Exports to Europe in the next decade are expected to increase significantly with the development of this project. Critics of the project. such as the World Bank, maintain that it is not economi cally sound in light of cheaper gas supplies available elsewhere, but Russia has too much invested to date to entertain thoughts of not proceeding. Other efforts include a feasibility study that Exxon and Japan Explo ration Company are undertaking on a pipeline to move Russian gas from the Sakhalin I pipeline to Tokyo and the Blue Stream export pipeline, which would carry Russian supplies under the Black Sea to Turkey. Although the Yamal project is by far the most significant of the projects proposed or underway, the Blue Stream project could have considerable impact.

In spite of some uncertainty regarding future developments in the region, IEO99 anticipates an eventual reversal of the overall downward trend in EE/FSU natural gas markets. Although consumption in the FSU is projected to remain level between 1996 and 2000, steady growth is expected after 2000, resulting in overall growth of 2.0 percent per year from 1996 to 2020 (Figure 37). Much higher growth is projected for Eastern Europe, where consumption is projected to grow steadily from 1996 and more than triple by 2020. The considerable foreign investment interest seen in developing the natural gas infrastructure of these countries will be a significant factor in increasing future consump tion potential and export capabilities.

Central and South America

Development of the natural gas markets in Central and South America remained strong throughout 1998. Much progress was made in installing the infrastructure needed to develop the region's natural gas industry. Several pipelines connecting Argentina and Uruguay, Brazil, and Chile were completed, as well as a number of gas-fired electricity generation plants. In the IEO99 reference case, gas use increases by 7.6 percent per year in the region between 1996 and 2020, increasing nearly sixfold over the projection period (Figure 38). Indeed, the gas share of total energy consumption increases from 18 percent in 1996 to almost 38 percent by 2020, supplying fuel for electricity generation as well as industrial, residential, and commercial consumers.

In Argentina, total natural gas consumption has increased by nearly 81 percent over the past decade [23, p. 37]. At the same time, the liberalization of energy markets in South America as a whole has given Argentina an opportunity to supply growing gas demand in Brazil, Chile, and Uruguay. Several major pipelines are now operating or are under construction to integrate this broader market framework.

There are two major pipelines under construction from Argentina to Brazil. The 273-mile Paraná-Uruguayana pipeline has a capacity of 88.3 cubic feet per day and will provide gas to a 500-megawatt thermal unit in Uruguayana by the end of 1998. The Gasoducto Mercosur will extend for 3,100 miles along the Santa Cruz de la Sierra-San Jorge Pablo pipeline.

Two major pipelines are already operating between Argentina and Chile: the 31-mile, 70.6 million cubic feet

1996 2000

2005 2010 2015 2020 Sources: 1996: Energy Information Administration (EIA), International Energy Annual 1996, DOE/EIA-0219(96) (Washington, DC, February 1998). Projections: EIA, World Energy Projection System (1999).

per day San Sebastián-Baudurria and the 283-mile, 177 million cubic feet per day Gas Andes pipeline, which extends from Mendoza, Argentina, to Santiago, Chile. There are future plans to increase capacity in the San Sebastián-Baudurria pipeline to 177 million cubic feet per day by the end of 1999.

There are also several pipelines under construction between Argentina and Chile. The Atacama pipeline is currently under construction and is expected to be used to fuel gas-fired electricity generators in Chile. It extends for 584 miles from northern Argentina to northern Chile and is being built by a consortium of Endesa, CMS, and YPF. The Norandino Pipeline also connects Argentina to Chile and is expected to compete with Atacama. Norandino is 544 miles long and will link the cities of Salta, Argentina, and Tocopilla, Chile. It is being built by a consortium of Tractabel, Edelnor, Electroandina, and Techint. Finally, there are plans to build the 329-mile, 35 million cubic feet per day Gas Pacífico pipeline, which would extend from the Province of Nequén, Argentina, to Concepción, Chile.

Argentina is also in the process of establishing the infrastructure needed to supply Uruguay with natural gas. In October 1998, the first Argentina-to-Uruguay natural gas pipeline was inaugurated at a cement plant of the Ancap oil company in Paysandu [24]. The 12-mile gas duct starts near the city of Colon in Argentina's Entre Rios province and leads to Paysandu. The $10 million (US) pipeline will provide gas mainly for the cement plant and, in the future, for residential use in the northern provinces of Uruguay. Several other projects are planned to link Uruguay and Argentina. The first is the 130-mile, $130 million Buenos Aires-to-Montevideo gas