International Energy Outlook 1999

Natural gas is the fastest growing primary energy source in the IEO99 forecast. Because it is a cleaner fuel than oil or coal and not as controversial as nuclear power, gas is expected to be the fuel of choice for many countries in the future.

Prospects for natural gas demand worldwide remain bright, despite the impact of the Asian economic recession on near-term development. Natural gas consumption in the International Energy Outlook 1999 (IEO99) is somewhat increased from last year’s outlook, and the fuel remains the fastest growing primary energy source in the forecast period. Worldwide gas use more than doubles in the reference case projection, reaching 174 trillion cubic feet in 2020 from 82 trillion cubic feet in 1996 (Figure 31). Strongest growth is projected in the developing countries of Central and South America and Asia, but large incremental increases in demand are projected for industrialized countries as well.

Sources: History: Energy Information Administration (EIA), Office of Energy Markets and End Use, International Statistics Database and International Energy Annual 1996, DOE/ EIA-0219(96) (Washington, DC, February 1998). Projections: EIA, World Energy Projection System (1999).

In the industrialized countries, where gas markets are most mature, gas use is projected to grow by 2.2 percent over the 24-year projection period, more than twice as fast as the projected growth rate for oil consumption. Many industrialized countries view natural gas as a way to reduce greenhouse gas emissions and, as a result, are expected to expand their use of gas. Because natural gas is a cleaner fossil fuel than oil or coal and is not as controversial as nuclear power, it is expected to be the fuel of choice for many industrialized countries in the future.

Developing countries are also interested in the environmental benefits of using natural gas, but often they are more intent on using natural gas to diversify fuel mix. In particular, countries of Central and South America are expanding gas-fired electricity generation capacity at a rapid pace in an effort to diversify electricity sources. Heavy dependence on the non-emitting hydroelectric resources in the region has led to problems in maintaining the electricity supply in times of drought. Hydroelectricity and other renewable resources accounted for 77 percent of the energy consumed for electricity generation in Central and South America in 1996; by 2020 the share is projected to fall to 53 percent because of expanded natural gas use.

In developing Asia, the news regarding gas markets has been mixed, an obvious result of the economic crisis that began in 1997 and continued throughout 1998. Various projects have been delayed or scaled back. In Thailand, for example, the state power company reduced expected investment in gas projects by 30 percent for the 1998-2006 period. Activity in Indonesia has been hit even harder. On the other hand, there is fresh optimism that China will build a liquefied natural gas (LNG) regasification project in Guangdong, and there has been movement in the development of LNG projects in India—such as Enron’s finalized agreement to purchase LNG from Oman for its Dabhol power project.

As of January 1, 1999, proven world natural gas reserves,⁴ as reported by Oil & Gas Journal, were estimated at 5,145 trillion cubic feet, 58 trillion cubic feet higher than the estimate for 1998. Most of the increase in reserves is attributed to the developing countries, with a small increase in reserves of the industrialized regions and virtually no change in the reserves of Eastern Europe and the former Soviet Union (EE/FSU). In the industrialized regions, the decrease of 12 trillion cubic feet between 1998 and 1999 in Western Europe’s natural gas reserves was offset by the doubling of Australia’s reserves (from 19 to 45 trillion cubic feet) in industrialized Asia. In the developing countries, reserves in Central and South America declined by 3 trillion cubic feet between 1998 and 1999, but in every other region of the developing world, reserves increased. Proven reserve estimates increased by 13 trillion cubic feet for Africa, by 16 trillion cubic feet for Asia, and by 24 trillion cubic feet for the Middle East.

About 72 percent of the world’s natural gas reserves are located in the FSU and countries of the Middle East. Russia and Iran alone account for almost one-half of the world’s gas reserves (Table 11). In the industrialized world, reserves have remained fairly stable over the past 20 years. Reserves of the industrialized countries declined every year between 1993 and 1998, but in 1999 they increased by 10 trillion cubic feet because of the addition of 24 trillion cubic feet in Australia’s proven reserves (Figure 32). Reserves in the EE/FSU and the developing world have, in contrast, more than doubled over the past 24 years, although since 1994 reserves in the EE/FSU have remained flat.

Sources: 1975-1993: “Worldwide Oil and Gas at a Glance,” International Petroleum Encyclopedia (Tulsa, OK: PennWell Publishing, various issues). 1994-1999: Oil & Gas Journal (various issues).

Worldwide, natural gas reserves are more widespread geographically than oil reserves. Outside the EE/FSU and the Middle East, reserves are fairly evenly distributed, except for industrialized Asia (Figure 33). Moreover, despite high rates of increase in gas consumption, particularly over the past decade, most regional reserves-to-production ratios have remained high. Worldwide, the reserves-to-production ratio is estimated at 64.1 years [2, p. 20]. Central and South America has a reserves-to-production ration of about 72.7 years, the FSU about 86.2 years, and the Middle East and Africa both more than 100 years.

IEO99 projects considerable growth in natural gas markets in North America over the forecast period, with consumption increasing at an average annual rate of 1.7 percent per year. Consumption in the United States and Canada is expected to increase at rates of 1.6 and 1.7 percent per year, respectively, and consumption in Mexico is projected to increase by 3.8 percent per year. A significant portion of the growth in all three countries is expected to fuel electric power generation. The Canadian Gas Association projects that natural gas consumption for electric power generation in Canada will more than double between 1997 and 2010. The Energy Information Administration (EIA), in its Annual Energy Outlook 1999 (AEO99) [3], forecasts that natural gas consumption for electric power generation in the United States will also more than double over the same period, and the Comission Reguladora De Energia (CRE) expects overall Mexican natural gas demand to more than double, with approximately half the gas used to generate electricity.

Trade among the North American countries, especially between the United States and Canada, is projected to increase considerably. According to the AEO99 forecast, natural gas imports from Canada increase by 72 percent between 1996 and 2020, rising from 2.9 to 5.0 trillion cubic feet. Imports from Canada have until recently been constrained by pipeline capacity, and the expected increase in imports between 1996 and 2001—over 20 percent—is made possible by considerable new pipeline capacity coming on line during the period. While most of the new capacity provides access to supplies from Western Canada, where most of Canada’s approximately 65 trillion cubic feet of reserves are located, new capacity is also expected to provide access to Sable Island supplies in the offshore Atlantic. Gas fields with more than 3 trillion cubic feet of total reserves are located in the Sable Island area, and considerably more reserves are thought to lie in this offshore Atlantic region.

Several projects are currently proposed to increase import capacity from Canada into the United States, and although it is unlikely that all of the proposed projects will be built, EIA assumes that some combination of those projects will add approximately 2 billion cubic feet per day of pipeline capacity to access supplies in western Canadian and 0.4 billion cubic feet per day to access Sable Island supplies. Major projects include the Alliance project, which would bring gas from British Columbia to Chicago; the Northern Border expansion, which would extend the current system (which enters the United States at the Montana border) to Indiana and possibly to the Michigan-Canada border; and the Maritimes and Northeast project, which would move supplies from Sable Island into the Northeast United States [4].

Mexico serves predominantly as an export market for U.S. natural gas. Exports from the United States to Mexico are projected in AEO99 to grow more than sixfold between 1996 and 2020, from 0.03 to 0.19 trillion cubic feet per year. Although Mexico is rich in natural gas resources, most are located in southeastern Mexico, far from the primary consuming areas in the north and central regions of the country, and Mexico lacks the infrastructure to move the gas from the southern producing regions to the north. Consequently, it will likely be more expedient, at least for the near term, to satisfy increasing demand at least in part with imports from the United States.

Several projects have been proposed to increase capacity to flow gas from the United States to Mexico in anticipation of the increased demand for industrial use and electric power generation in northern Mexico. If completed, the proposed projects would more than double the current U.S. export capacity to Mexico. Export capacity from Mexico to the United States has not increased over the past several years, and no new projects have been proposed. The only indication of increased exports from Mexico to the United States is Pemex’s intention to export part of any increased production from the Burgos Basin in northeastern Mexico to the United States. Because of the favorable location of the Burgos Basin, Pemex plans to spend $5.5 billion over the next 15 years to increase Burgos production from 500 million cubic feet per day to 1,400 million cubic feet per day in 2001.

Mexico is making rapid progress with its plans to privatize natural gas distribution. The effort began in May 1995 with legislation that opened natural gas transmission, distribution, and storage to private investment and allowed private companies to import and export natural gas. Considerable expansion of the existing infrastructure is needed both to provide gas to fuel electricity generation and to provide access to the residential market, and much of the expansion will be accomplished by the private sector. Several distributorships have already been privatized, and Hector Olea, president of the Comision Reguladora de Energia, has indicated that 80 of the largest municipalities in Mexico will have residential gas service within 2 years. Four years ago, when the current administration came into power, only 10 to 15 cities had natural gas service [5].

In Western Europe, the IEO99 reference case projects increases in natural gas demand of 2.9 percent per year over the 24-year projection period, as compared with growth of 1.7 percent per year in North America and 2.2 percent per year in industrialized Asia. Total natural gas consumption in Western Europe is projected to reach 27 trillion cubic feet by 2020 (Figure 34). The fastest regional growth is expected in “other Europe,” where countries with less mature but rapidly expanding infrastructure, such as Greece, Spain, and Portugal, are included in the IEO99 forecast.

Several factors favor increased reliance on natural gas in Europe. Most important is access to abundant low-cost reserves. Although little new productive capability is available within continental Europe, abundant reserves are available for import from the North Sea, North Africa, and the FSU. Great strides continue to be made to install infrastructure to tap these reserves (see discussion on "Europe's New natrual Gas Pipelines"). In 1998, new pipeline links to the United Kingdom and Norwegian North Sea production became operational. One link—the UK-Belgium Interconnector—is designed to allow gas to flow to continental Europe or toward the United Kingdom, depending on short-run weather-related needs. These new links add to existing capability to bring natural gas into Europe not only from the North Sea but also from Russia, Algeria, and Libya. Supplementing these developments are a variety of interconnections within continental Europe that allow gas to flow throughout the continent. Norwegian, Russian, and Algerian gas can now be delivered to Italy, Spain, Austria, and Germany.

Various Eastern European and Balkan countries are gaining increasing access to larger and more diversified sources of gas. Strengthening European Union institutions are further contributing to growing natural gas use. In 1997, the European Union announced its natural gas directive, which is designed to enhance competition in natural gas markets. The directive seeks to free up access to pipeline transmission to enable more open dealing between natural gas consumers and suppliers. As a consequence, established pipeline companies are developing more diversified relationships with their customers and suppliers and unbundling, to varying degrees, the provision of transportation from other natural gas services. At this point, the process of regulating reform is incomplete and uneven across the region, but growing market opportunities combined with institutional pressure for change are causing revisions in established regulatory frameworks and methods of doing business.

The United Kingdom’s Interconnector pipeline, between Bacton, England, and Zeebrugge, Belgium, was completed on schedule. Gas began to flow through the Interconnector on October 1, 1998 (Table 12). The line was originally estimated to cost $762 million, but actual costs were 10 percent under budget. With a glut of new gas supplies available to European countries following a mild winter, natural gas prices fell substantially in Europe in 1998. As a result, it is likely that the Interconnector will be used to ship gas to the United Kingdom should there be a surplus of continental gas over the 1999 winter season [8]. This is an interesting reversal from the situation in 1997, when the Interconnector was expected to help alleviate Britain’s gas supply bubble.

The Interconnector links the United Kingdom’s gas transmission system with continental gas grids. It has the capability of exporting up to 706 billion cubic feet per year of natural gas to European customers. The line can be reversed to import 300 billion cubic feet per year into the United Kingdom, and increased compression capacity would make it possible for Britain to import even more.

Gas-fired electricity generation has grown rapidly in the United Kingdom in recent years. Indeed, between 1996 and 1997, natural gas generation grew by almost one-third, replacing coal- and oil-fired plants that were taken out of service or retired [9, p. 264]. In IEO99, total natural gas consumption is projected to nearly double between 1996 and 2020, and gas use for electricity generation increases fourfold over that same time period (Figure 35).

Although the British government approved the construction of five additional gas-fired power plants between May and December 1997, a moratorium on new gas plant construction was issued in December in response to concerns over what the so-called “dash for gas” was doing to the British coal industry [9, p. 264]. The government has also noted that it is concerned that the rush to increase gas-fired generation at the expense of coal would lead to an over-dependence on a single energy source, stifling market competition.

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).

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 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.

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 consumption 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.

Source: International Energy Agency, Natural Gas Information 1997 (Paris, France, 1998), p. IV.45.

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 payments. 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 Eastern 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 economically 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 Exploration 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 consumption potential and export capabilities.

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 Paran�-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 per day San Sebasti�n-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 Sebasti�n-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 Pac�fico pipeline, which would extend from the Province of Nequ�n, Argentina, to Concepci�n, 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 line (being developed by Pan-Am and British Gas), on which construction will begin early in 1999. Another is the Entre Rios-to-Casablanca line, which Ancap plans to build with a state-owned Uruguayan electricity company for a planned electric power plant in Casablanca. In addition, the 292-mile, 88 million cubic feet per day Paran�-Paysand� pipeline is being constructed by Uruguay’s UTE and ANCAP.

In Brazil, total demand for natural gas grew by 10.2 percent in 1997, driven by higher consumption in the industrial and power generation sectors, which increased their demand for natural gas by 12.1 percent and 7.8 percent, respectively [23, pp. 64-65]. Most of the developments in Brazil’s gas supplies focus on international contracts that bring gas from Argentina and Bolivia through several pipelines. In 1998, construction of the 1,973-mile, 285 million cubic feet per day Bolivia- to-Brazil pipeline began. The first portion of the Bolivia- to-Brazil pipeline—which will ultimately transport gas from the R�o Grande Natural Gas Plant located southeast of Santa Cruz de la Sierra, Bolivia, to Guarema, Brazil—was completed at the end of 1998, and Bolivian gas sales to Brazil are scheduled to begin in the first quarter of 1999 [25, 26]. The second portion, which will extend the line from Guarema to Porto Alegre in Brazil’s Rio Grande do Sul state, is expected to be in place by the end of 1999 [27].

In southern Brazil, authorities are trying to accelerate the construction of another pipeline that will connect gas reserves from Parana, Argentina, to Uruguayana, Brazil [23, pp. 64-65]. Natural gas from this pipeline will be used for a 450-megawatt gas-fired electric power plant being developed by AES Energy. In addition, state- owned energy company Petroleo Brasileiro (Petrobras) continues to develop its Natural Gas Project of Urucu, which will allow the distribution system to transport gas to Porto Velho for additional gas-fired electricity generation units.

There is movement to bring LNG to Brazil. In November 1998, Petrobras and Royal Dutch/Shell Group formed a joint venture to develop a regasification terminal about 20 miles south of Recife at Suape port in Pernambuco state. It will be South American’s first LNG regasification terminal [28]. The $200 million terminal is scheduled for completion by 2003 with an annual capacity of 1.5 million metric tons. Shell and Petrobras are looking to Trinidad and Tobago and Nigeria LNG projects for potential supplies.

Much of the increase in Brazil’s natural gas consumption will be used to fuel gas-fired electricity generation. According to the Sao Paulo state government, gas demand for power generation is expected to grow from virtually nothing at the present to more than 500 million cubic feet per day by 2003, accounting for all of the “more than 1 billion cubic feet per day in shipments slated to reach Sao Paulo” [29]. Many plants are either under construction or in the planning stages. AES Corp recently began constructing a 600-megawatt gas-fired plant at Uruguaiana in Brazil’s Rio Grande do Sul state [30]. The $250 million plant should be completed by the end of 2000, using gas imported from Argentina through a 273-mile pipeline currently under construction. Construction of a $400 million, 800-megawatt gas-fired plant near Sao Paulo, Brazil, by Entergy Power Group will begin in 2000, with completion scheduled for mid-2002 [30]. Entergy is also discussing plans for a second plant in the state of Rio de Janeiro. Brazil’s Coelba is planning to build a 240-megawatt gas-fired plant in either Bahia or Rio Grande do Norte for an estimated $100 million. The company will determine where the plant will be built, based on the package of subsidies and fiscal incentives each state government is willing to offer.

In Peru, the Camisea and Aguayt�a natural gas fields represent important potential sources of natural gas in South America [23, pp. 182-183]. In June 1996, Shell Exploration and Mobil Corporation signed a contract to develop the Camisea gas fields discovered by Shell in the 1980s. Estimates are that the Camisea fields contain between 11 and 20 trillion cubic feet of natural gas, which could supply Peru’s needs for more than 100 years.

In addition, several nearby natural gas finds announced in 1998 strengthen the area’s potential as a long-term source of natural gas from Peru. Unfortunately, the Camisea fields are remotely located—some 800 miles south of Lima—and the lack of a well-developed natural gas infrastructure has delayed the development of the reserves. Plans were to have Camisea in full production by 2010, but Shell and Mobil removed themselves from developing the estimated $3 billion project on July 15, 1998, saying they could not commit to phase 2 of the project under the government’s terms. The two companies were asking the Peruvian government to increase the gas price to $2.45 per million Btu, which the government declined to do [31]. Peru now plans to tender a three-stage project for Camisea in early 1999 [32]. The tenders will include developing the Camisea fields; constructing processing facilities; building a pipeline from the fields to the coast; and organizing the gas distribution system. The Peruvian government expects to see gas deliveries to Lima begin in 2003 [33].

Development of the Camisea and Aguayt�a fields has the potential of making Peru a net energy exporter by the beginning of 2000 [23, pp. 182-183]. The completion of the 155-megawatt gas-fired Aguayt�a power plant in May 1998 means that Peru is now generating 7 percent of its electricity with gas. The power plant was built by Maple Companies of Dallas, Texas and PanEnergy at a cost of about $254 million.

In Chile, the competition between the two Argentina-to-Chile pipeline projects, Gas Atacama (controlled by the U.S. CMS Energy and Chile’s Endesa) and Norandino (controlled mostly by Belgium’s Tractebel) continued in 1998. Gas Atacama has already secured 212 million cubic feet per day in contracts of its 300 million cubic feet per day capacity, mostly with its subsidiary, Nopel [34]. The state-run Chuquicamata copper mine is among the new customers it now hopes to pick up.

Power company Electroandina plans to bring its first two 400-megawatt gas-fired units into operation over the next 18 months. Along with Gas Atacama’s 710-megawatt Nopel plant and a transmission line from Argentina being built by the Gener electricity company, a serious oversupply of electricity could develop in northern Chile’s 1,200-megawatt grid.

Natural gas markets in Asia had mixed reactions to the Southeast Asian economic downturn that began in the spring of 1997. Many planned gas projects have been delayed or scaled back, most notably projects in hard-hit Thailand and Indonesia, although signs of gas demand growth are evident in China and India. In the IEO99 reference case, natural gas consumption in all of Asia is expected to maintain a healthy growth rate of 5.9 percent per year over the 24-year projection period. Gas use more than triples, reaching 34 trillion cubic feet in 2020, from the 1996 level of 9 trillion cubic feet (Figure 39).

Natural gas use in the countries of industrialized Asia rises from 3.3 trillion cubic feet in 1996 to 5.5 trillion cubic feet in 2020. The bulk of the increment is attributed to increases in gas demand in Japan, most of it in the form of LNG. Japan is the world’s largest importer of LNG. In 1997, the country imported 58 percent of the world’s LNG, some 47 million metric tons [2, p. 28]. In the short term, Japan’s demand for LNG is expected to be dampened by the country’s economic recession; however, several long-term plans to import LNG continued in 1998 (see discussion on "The Status of worldwide Liquefied Natural Gas"). Japan’s Osaka Gas signed an agreement with Oman LNG Company for the supply of 0.7 million metric tons per year of LNG over a 25 year period beginning at the end of 2000 [35]. Last year Osaka imported 5.3 million metric tons of LNG.

There are substantial natural gas reserves in Australia. Not surprisingly, 98 percent of the industrialized Asian gas production can be attributed to this country [46]. Australia exports about one-third of the natural gas produced in the form of LNG. Most of Australia’s LNG is exported to Japan, but the United States, Turkey, and Spain have also imported LNG from Australia in recent years.

Australia has plans to expand its LNG production, including proposals to develop the Gorgon LNG resources for export to China’s Guangdong province, as well as a plan to build a domestic LNG plant in Western Australia to supply gas to the West Kimberley region for power generation in remote towns such as Broome and Derby and in remote mining locations [44, 45]. Both projects are still in the planning stages. China has said it is committed to building an LNG demonstration project in Guangdong, but it has not committed to purchasing LNG from Australia, which would be necessary to justify construction of the Gorgon project.

Although some of the major emerging markets of developing Asia—including South Korea, Thailand, and Indonesia—are still in economic recession, natural gas developments in China and India seemed to be moving forward strongly at the end of 1998. China is poised to bring LNG to its southeastern Guangdong province and is discussing plans to pipe natural gas from Russia. Indeed, IEO99 projects China’s natural gas use to grow 14-fold from 1996 to 2020. Prospects for gas use in India are also optimistic in the IEO99 forecast. In 1998, after several years of indecision, India’s Petronet secured several supply contracts for LNG for its two LNG regasification projects, and Enron arranged LNG supplies for its Dabhol power plant.

China is becoming increasingly interested in pursuing the development of a natural gas infrastructure as it becomes more and more dependent on crude oil imports and as pollution problems resulting from heavy reliance on coal use worsen. Beijing is studying plans for several natural gas pipeline projects with Russia. Gazprom Board Chairman Rem Vyakhirev stated that Russia planned to supply China with between 1.1 and 1.3 billion cubic feet of natural gas per year from Western Siberia [47]. The timetable for construction has not been announced.

In October 1998, China and Australia announced intentions to build China’s first LNG facility to serve southern China’s Guangdong province [45]. The proposed demonstration project would involve an initial supply of 3 million metric tons of LNG and make it economically possible for Australia to move forward with its Gorgon project. The experimental LNG project at Guangdong would be built near Shenzhen just north of Hong Kong. It would cost an estimated $600 million and is expected to be completed by 2005 [48]. A detailed plan of the project is to be submitted in April 1999. An estimated 80 percent of the first 3 million tons of LNG are to be used for electricity generation. After 2 to 3 years, however, another 2 million tons of capacity would be added for residential and industrial use. There are additional proposals for two other terminals: one in Fujian province (north of Guangdong) and one in Shanghai. When completed in 2010, the three plants would require up to 15 million tons of LNG.

In India, Enron arranged the supply of 1.2 million tons per year of LNG for a 20-year period from Oman LNG [49]. Supplies are expected to begin in 2001 with the completion of the 1,624-megawatt phase 2 of the company’s Dabhol power plant in the western Indian state of Maharashtra (Dabhol’s 826-megawatt phase 1 will be fueled initially on naphtha or distillate, but the entire project will use natural gas once phase 2 is completed). Construction of the LNG import terminal along with regasification facilities at Dabhol began at the end of 1998 [50].

When completed and operating at full capacity, the Dabhol project will need 2 million tons of LNG per year. Beyond the supplies already secured from Oman LNG, additional supply may come from Qatar, where Enron has proposed its own LNG liquefaction plant to be commissioned in 1999 near the existing Qatargas and RasGas plants.

There are also plans to build two regasification terminals in India. The joint venture Petronet (set up by Indian state firms GAIL, ONGC, IOC, and BPCL) is developing one 5 million ton per year LNG terminal at Dahej (in the western state of Gujarat) and a 2.5 million ton per year LNG terminal at Cochin (in the southern province of Kerala) [51]. Both terminals will import LNG from Mobil Corporation and Qatar’s RasGas. Although final details of the supply agreement must be worked out, RasGas is expected to supply India with 7.5 million tons of LNG per year over a 20-year period [52]. First deliveries of the LNG are expected to begin in 2002. Petronet is also considering constructing a third terminal at Mangalore, and India’s Foreign Investment Board approved a proposal to construct an LNG terminal in Kakinada on the eastern coast in September 1998 [39]. British Gas International and the Yemen LNG Company signed a memorandum of understanding to begin the Pipavav LNG project in Gujarat with initial deliveries planned by mid-2003.

The success of these LNG projects will have an impact on the development of natural gas projects throughout India. Plans to develop a 1,900-megawatt gas-fired Kayamkulam stage-II project in the southern Indian state of Kerala will be carried out only if an LNG supply can be secured [53]. The success of negotiations with the Mobil and RasGas consortium of Qatar makes it more likely that the Kayamkulam stage-II will be constructed. The first 115-megawatt unit of the 350-megawatt Kayamkulam stage-I project of National Thermal Power Corporation—to be fueled by naphtha—began trial runs in November 1998.

The economic troubles of Southeast Asia have had a dampening affect on natural gas development in South Korea. The state-owned gas importer and supplier, Korean Gas Corporation (Kogas), recently revised downward its projections of LNG imports from 14.16 to 12.96 million metric tons in 1999 [54]. Most of the reductions are attributed to the electric power sector. Korean Electric Power Company (Kepco), the country’s electric power company, has informed Kogas it would like to reduce its planned LNG purchases for the period of 1999 to 2003 by 30 percent. As a result, Kogas has negotiated delivery delays under existing contracts and has scaled back spot market purchases.

Because Kogas is committed to purchase LNG under a number of medium- to long-term take-or-pay contracts, there is pressure to speed expansion of the country’s gas transmission infrastructure so that the gas can be redirected from electricity generation to residential, commercial, and industrial uses (Figure 40). Kogas has existing contracts with Brunei, Malaysia, and Indonesia, as well as two new 25-year contracts of 4 million metric tons each with Qatar’s Ras Laffan and Oman’s LNG project, which are scheduled to begin in 1999 and 2000, respectively.

Source: International Energy Agency, Natural Gas Information 1997 (Paris, France, 1998), p. IV.31.

Natural gas from Myanmar’s (formerly Burma) Yadana field started flowing to Thailand for the first time on July 30, 1998, on a trial basis—one month behind the original schedule [55]. The pipeline from the offshore field in the Gulf of Martaban to Thailand becomes the second cross-border pipeline in Asia after the Malaysia-Singapore line. In October, Thailand had to postpone commercial gas deliveries until April 1999, some 8 months behind the original schedule [56]. The Petroleum Authority of Thailand (PTT) was supposed to begin receiving Yadana gas in July 1998. However, completion of the entire 1,800 megawatt Ratchaburi plant will be between 8 and 9 months behind original schedules. PTT is trying to avoid the heavy contractual penalties under its 30-year take-or-pay contract with the Yadana consortium. Since July 30, PTT has only been able to take delivery of 5 million cubic feet per day of the 65 million cubic feet per day initial rate stipulated in the Yadana supply contract. Under the contract, PTT was committed to gradually raising its imports of Yadana gas to 525 million cubic feet per day 15 months after production began in July 1998. PTT has wanted to pay only for the amount of gas it actually receives. It was bound by the contract to also pay for undelivered gas at the end of the year.

Indeed, Thailand has had to scale back many of the projects it had undertaken prior to the economic recession that has followed the floating and then collapse of the national currency, the baht, in July 1997. The project delays are, in part, attributed to lowered gas demand than expected before the recession, but project development is also hindered by constraints on public finance imposed by agreements made with the International Monetary Fund for foreign currency loans to support Thailand’s external accounts. As a result, funding for gas infrastructure construction has been reduced substantially. PTT reduced planned expenditures by about 30 percent to $2.23 billion (U.S.) for 12 projects to be developed between 1998 and 2006 [57] (Table 13).

PTT has decided to postpone indefinitely a planned trunk line that was to run from Unocal’s Erawan gas field in the Gulf of Thailand to Ratchaburi [58]. The trunk line was to become the third in the Gulf of Thailand and was intended to bring natural gas from new fields, particularly those in the Malaysia-Thailand Joint Development Area, an offshore area in the southern Gulf jointly administered by Malaysia and Thailand. Other projects dropped include the Pailin to Songkhla and Songkhla to Yala projects, as well as the Surat Thani to Krabi and South Bangkok projects.

Natural gas reserves in the Middle East are second only to those in the FSU region. As of January 1, 1999, Middle East reserves accounted for 1,750 trillion cubic feet [59]. Middle Eastern gas use is expected to grow by 2.9 percent annually over the 24-year projection period, increasing from 5.4 trillion cubic feet in 1996 to 10.9 trillion cubic feet in 2020 (Figure 41). Gas is presently exported as LNG through projects in Abu Dhabi, Qatar, and Oman, but several pipeline projects have been proposed or are under development to supply gas to Asian countries such as India and Pakistan, as well as to Western European countries using Turkey as a transit.

Almost one-half of the Middle East’s gas reserves (812 trillion cubic feet) are in Iran, where many natural gas projects moved ahead in 1998. In August, the National

Iranian Oil Company announced that 43 oil and gas projects worth over $5 billion would be opened to international firms on a “buyback” basis [60].⁵ More than 70 companies responded to the buyback offers.

A $2 billion project to develop Iran’s South Pars gas and condensate field was proposed by a consortium of France’s Total, Malaysia’s Petronas, and Russia’s Gazprom in 1997, but the project was opposed by the United States as a violation of the Iran-Libya Sanctions Act, which imposes sanctions against companies that invest more than $20 million in energy ventures in the two countries [61]. In May 1998, the United States agreed to waive the U.S. sanctions, and gas production from the project is expected to begin in June 2001, providing 2 billion cubic feet per day to Iran’s domestic gas pipeline network [62].

Turkey has one of the fastest developing gas markets in the world. Its natural gas use has more than doubled over the past 6 years, from 122 billion cubic feet in 1990 to 277 billion cubic feet in 1996 [63]. The country has spent the past decade securing gas suppliers. In 1987, the former Soviet Union began providing natural gas through a pipeline completed in that year and running from the Bulgarian border to Istanbul and then to Ankara [64, p. 269]. In 1993, both Algeria and Qatar began supplying the country with LNG. And in 1996 Turkey signed a contract with Iran for the construction of a gas pipeline from Iran and about 88 billion cubic feet of natural gas per year beginning in 1999.

In October 1998, Turkey signed a 30-year preliminary agreement to buy natural gas from Turkmenistan by way of a 1,050-mile trans-Caspian pipeline [65]. Royal Dutch/Shell and Enron Corporation are preparing feasibility studies for exporting Turkmen gas to Turkey either through Iran or through the Caspian Sea, then crossing Azerbaijan and Georgia. The U.S. Government is opposed to a route through Iran.

Oman LNG announced that construction of a $2 billion plant at Qalhat will begin at the end of 1999, with two trains each with a capacity of 3.3 million tons per year [35]. In addition to a contract to supply Osaka Gas with 0.7 million tons of LNG per year for a 25-year period, Oman secured a 4.1 million ton per year gas supply agreement with Korea Gas Corporation (Kogas), with deliveries scheduled to begin in April 2000, and signed an agreement to supply 1.2 million tons per year to Enron’s Dabhol Power Project in western India, with options to increase the amount to 1.6 million tons per year [66]. Earlier plans to supply Thailand with LNG were canceled when Thailand’s projections for energy demand fell as a result of the Southeast Asian economic recession.

Abu Dhabi is attempting to expand its gas production for use in electricity generation and for use in injection in its oil fields to increase oil recovery. CMS Energy was chosen to build Abu Dhabi’s first privately owned electric power plant, the $770 million Al Taweelah A2 [64, p. 295]. Construction on the gas-fired project is scheduled to begin early in 1999, and it should be fully operational by August 2001. The emirate exports gas through its Das Island LNG project, mostly to Japanese customers, which account for over 5 million tons of LNG per year in contracts [64, p. 17]. There were plans to increase the Das Island capacity by some 200 billion cubic feet, but the Asian economic crisis makes it unlikely that the plans will go ahead in the short term.

Natural gas consumption in Africa is projected to rise from 1.8 trillion cubic feet in 1996 to 3.3 trillion cubic feet in 2020, an increase of 2.7 percent per year (Figure 42). Almost 92 percent of the continent’s gas reserves are contained in only four countries: Algeria, Nigeria, Libya, and Egypt.

Algeria has the largest natural gas reserves in Africa, with an estimated 131 trillion cubic feet. Most of the gas produced in the country is exported to Europe through two existing pipelines: the Transmed—which runs from Algeria’s Hassi R’Mel field through Tunisia to Italy—and the Maghreb-Europe—which also runs from the Hassi R’Mel field through Morocco to Spain’s Seville and to Portugal. In addition to Italy and Tunisia, Algeria is able to supply natural gas to Slovenia through the Transmed pipeline [64, p. 126].

Algeria also has a substantial number of LNG export contracts worldwide. It currently supplies France, Belgium, Spain, Italy, Turkey, Greece, and the United States with varying amounts of LNG. LNG plants at Arzew, Bethioua, and Skikda have all been renovated, increasing capacity at the three plants from 1.1 to 1.2 trillion cubic feet per year.

Nigeria has an estimated 35 percent of Africa’s natural gas proven reserves, about 120 trillion cubic feet [67]. At present, about 75 percent of the natural gas Nigeria produces (during oil production) is flared [64, p. 126]; however, several projects are underway to reduce the amount of flared gas, including schemes to increase domestic gas use, pipe gas to surrounding countries, export LNG to Europe and Turkey, and develop a gas-to-liquids project. The elimination of gas flaring in Nigeria would have reduced its total carbon emissions by half, or by about 13 million metric tons, in 1996.

Royal Dutch/Shell’s Shell Nigeria Limited plans to double the domestic use of natural gas within the next 5 years in Nigeria. The company plans to invest $38.7 million in local gas projects, including 68 miles of gas distribution pipelines. Shell recently signed to supply 80 million cubic feet of gas per day to Global Energy & Refining Nigeria.

Nigeria completed the first phase of its three-phase Escravos project in 1997. The $550 million project gathers and processes 165 million cubic feet of natural gas per day, all of which is consumed in Nigeria. The second phase will be for the export of 120 million cubic feet of gas per day to the West African Gas Pipeline (WAG). By the time the final phase—which is expected to capture another 300 million cubic feet per day—is completed, Nigeria will have almost entirely eliminated gas flaring.

Nigeria’s Bonny LNG project is expected to go on line in 2000, and 20-year supply contracts have already been signed with Gaz de France (14 billion cubic feet per year), Spain’s Enagas (56 billion cubic feet per year), and Turkey’s Botas (42 billion cubic feet per year). The $4.5 billion project consists of two liquefaction trains, export infrastructure, and a gas transmission system with a capacity of 254 billion cubic feet [64, p. 126].

The proposed WAG project moved a step closer to becoming a reality in 1998 as Chevron and the state-owned Nigeria National Petroleum Corporation signed a 20-year, 14.6 billion cubic feet per year contract to supply gas to a power plant in Ghana [68]. Construction on the $200 million, 220-megawatt power plant is expected to begin early in 1999. The 625-mile WAG line is not expected to be completed before 2001, and until that time, the power plant in Ghana will be fueled with crude oil supplied by Chevron.

Chevron and South Africa’s Sasol are working to develop a gas-to-liquids facility that would use some of the gas from the Escravos project’s final phase. The plant would convert natural gas into middle distillates such as jet fuel, diesel, and kerosene, and into intermediate feedstocks. Chevron and Sasol estimate that they could use 200 million cubic feet of feedstock gas per day to produce 20,000 barrels of diesel and other middle distillates per day. The project is still in the planning stages, however, and no time frame has been released.