Report#: DOE/EIA-0484(98)

Natural Gas

Reserves
Regional Activity

Natural gas is expected to be the fastest-growing primary energy source in the world over the next 25 years. In the IEO98 reference case, gas consumption grows by 3.3 percent annually through 2020, as compared with 2.1-percent annual growth for oil and renewables and 2.2 percent for coal. By 2020, the world’s consumption of natural gas is projected to equal 172 trillion cubic feet, more than double the 1995 level (Figure 43). Much of the growth is expected to fuel electricity generation worldwide (Figure 44), but resource availability, cost, and environmental considerations will also contribute to growing use of gas in industrial, residential, and commercial sector applications.

Figure 43. World Natural Gas Consumption in Three Cases, 1970-2020

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 (1998).

Worldwide there is a great deal of construction activity to develop gas distribution and transmission systems. According to the International Pipe Line and Offshore Contractors Association, 53,000 miles of new pipeline are expected to be installed between 1998 and 2000, including 34,000 miles of natural gas pipelines [1]. The survey included only firm projects that have secured financing and did not include projects in the former Soviet Union and China.

Figure 44. Natural Gas Use for Electricity Generation and for All Other Uses,
1995-2020

Sources: 1995: Energy Information Administration (EIA), Office of Energy Markets and End Use, International Energy Annual 1996, DOE/EIA-0219(96) (Washington, DC, February 1998). Projections: EIA, World Energy Projection System (1998).

Gas demand will grow fastest in the developing countries of the world. IEO98 expects gas consumption in the developing countries to grow by about 5.6 percent annually over the next 25 years, compared with 2.5 percent per year in the industrialized countries and 2.4 percent in Eastern Europe and the former Soviet Union (EE/FSU) (Figure 45). Gas use in developing Asia grows by more than 7 percent annually over the forecast period, despite the recent economic downturn in the region. While some expensive gas projects in the developing nations of Asia may be postponed, many others are continuing as planned.

Robust activity is also continuing in Central and South America to develop the infrastructure needed to deliver natural gas to industrial consumers and electric power generators. In the region as a whole, natural gas consumption grows by 6.7 percent annually over the projection period. In Brazil, gas use is expected to increase by about 14 percent per year. The countries of Central and South America are moving to diversify fuel sources for power generation. Hydropower has dominated electricity generation in the region, but rapid demand growth and periodic water shortages have led to some power shortages. Natural gas is an attractive alternative to oil- and coal-fired generation. Construction on several major pipelines and various power plants and industrial operations began in 1997, including work on the $2 billion Bolivia-Brazil pipeline.

Figure 45. World Natural Gas Consumption by Region, 1970-2020

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 (1998).

In 1997 Eastern European countries like the Czech Republic—currently heavily dependent on the FSU to meet their natural gas needs—began efforts to diversify their natural gas supplies. The Czech Republic signed a 20-year contract with Norway’s Gas Negotiating Committee to purchase a peak level of 106 billion cubic feet of gas per year. Natural gas consumption in the EE/FSU is expected to grow by 2.4 percent annually between 1995 and 2020; but the region’s strongest growth occurs in the countries of Eastern Europe, where economic recovery occurs more rapidly over the forecast than in the FSU. Annual gas consumption growth approaches 4.0 percent per year in Eastern Europe, compared with only 2.2 percent per year in the FSU.

In the industrialized world, gas demand grows by 85 percent over the forecast horizon, reaching 76 trillion cubic feet in 2020. Some of the most robust growth among the industrialized countries occurs in Western Europe, where gas demand is expected to increase by 3.8 percent annually over the 25-year projection period. The European Union has agreed on a timetable for instituting the European Gas Directive, which will allow for the deregulation of West European gas markets. Privatization and restructuring of the electric utility sector beyond the requirements of the Gas Directive have already occurred in many European countries where there are plans to increase natural gas use for generating electricity. Moreover, in a number of Western European countries, plans for reducing greenhouse gases include the use of natural gas to replace more carbon-intensive coal- and oil-fired generating capacity.

Some key developments supporting the world’s natural gas markets in 1997 include:

• Installation of NorFra, the world’s longest subsea pipeline, was completed in August 1997. The pipeline extends more than 520 miles from Draupner, offshore Norway, to Dunkirk, France. Gas delivery to France is scheduled to begin in October 1998 [2].
  
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• Vibrant growth in Central and South America was demonstrated by the completion of the GasAndes pipeline. This pipeline, completed in August 1997, provided the first natural gas supplies to Santiago, Chile. Beginning in October, 60 million cubic feet per day of natural gas was supplied from Mendoza, Argentina, for use by the Chilean gas distributor, Metrogas, through the pipeline. Progress was also made on other major pipeline projects, including the Bolivia-Brazil pipeline and the Atacama pipeline, in 1997.
  
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• Development of Iran’s South Par natural gas field moved closer to reality as Total, Gazprom, and Petrogas signed a $2 billion contract to develop 2 billion cubic feet per day from the field. Despite the threat of penalty from enforcement of the 1996 U.S. Iran-Libya Sanctions Act, plans for the South Par project were finalized in 1997. Gas from the project will eventually be exported to Turkey, perhaps as early as 1999. As a method to deter international terrorist activities in Libya and Iran, the Sanctions Act penalizes non-U.S. firms investing more than $40 million (reduced to $20 million in August 1997) in the energy industries of the two countries.
  
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• Substantial planned increase in pipeline capacity between the United States and Canada is underway. U.S. imports of natural gas, primarily from Canada, are forecast in the Annual Energy Outlook 1998 (AEO98) to increase from 2.9 to 5.2 trillion cubic feet between 1995 and 2020, with more than half the increase occurring by 2000. Most of the capacity expansion needed to support the increase between now and 2000 is either already under construction or in the planning stages. Although year-to-date 1997 figures reflect little increase, imports are expected to expand as planned capacity comes on line.

Reserves

As of January 1, 1998, proven world natural gas reserves,⁵ as reported by Oil & Gas Journal, were estimated at 5,086 trillion cubic feet, 141 trillion cubic feet higher than the estimate for 1997. All the increases in reserves are attributed to the developing countries, with virtually no changes in the industrialized regions or the EE/FSU. Small reserve declines in developing Asia were more than offset by increases in the Middle East (109 trillion cubic feet), Africa (20 trillion cubic feet), and Central and South America (14 trillion cubic feet).

About 73 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 half of the world’s gas reserves (Table 19). In the industrialized world, reserves have remained fairly stable over the past 20 years, although they have continued to decline since 1993 (Figure 46). Reserves in the EE/FSU and developing countries have, in contrast, more than doubled over the past two decades.

Figure 46. World Natural Gas Reserves by Region, 1975-1998

Sources: 1975-1997: “Worldwide Oil and Gas at a Glance,” International Petroleum Encyclopedia (Tulsa, OK: PennWell Publishing, various issues). 1998: Oil & Gas Journal, Vol. 95, No. 53 (December 31, 1997), pp. 38-39.

Worldwide, natural gas reserves are more widespread geographically than oil reserves. Outside the EE/FSU and the Middle East, reserves are fairly evenly spread, except in the Industrial Pacific region (Figure 47). Moreover, despite high rates of increase in gas consumption, especially in the past 10 years, most regional reserves-to-production ratios have remained high. Central and South America has a reserves-to-production ratio of about 70.2 years, the FSU 81.1 years, and the Middle East and Africa both more than 100 years [3, p. 20].

Table 19. World Natural Gas Reserves by Country as of January 1, 1998

Figure 47. World Natural Gas Reserves by Region as of January 1, 1998

Source: Oil & Gas Journal, Vol. 95, No. 53 (December 31, 1997), pp. 38-39.

Regional Activity
North America

The IEO98 forecast shows a 55-percent increase in North American natural gas consumption, from 25.4 trillion cubic feet in 1995 to 39.4 trillion cubic feet in 2020. Consumption in the United States and Canada is projected to grow by 49 and 53 percent, respectively, and consumption in Mexico by 180 percent (Figure 48). Growth in natural gas consumption in other areas of the world is even faster than the growth in North American consumption (with the exception of Mexico), and North America’s share of total world natural gas consumption declines from 32 percent in 1995 to 23 percent in 2020. North America’s share of natural gas consumption in industrialized countries also falls, from 62 percent in 1995 to 52 percent in 2020.

Figure 48. Natural Gas Consumption in NorthAmerica by Country, 1970-2020

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 (1998).

In all three North American countries electric utility sector restructuring is either underway or under consideration, and the primary driving force behind the projected increases in natural gas consumption is its use as a fuel for electricity generation. In EIA’s Annual Energy Outlook 1998 (AEO98) reference case, natural gas consumption in the U.S. electricity generation sector almost triples between 1995 and 2020, from 3.4 trillion cubic feet a year in 1995 to 9.9 trillion cubic feet in 2020. The increase stems from expectations of expanded utilization of existing gas-fired power plants, additions of new turbines and combined-cycle facilities, and the opening up of new opportunities for gas-fired generation as a result of restructuring in the electric utility industry. Although the greatest anticipated increase in U.S. natural gas consumption is in the electricity generation sector, increases are also projected for all the end-use sectors.

The Canadian Gas Association (CGA) expects strong growth in Canadian natural gas consumption for power generation, projecting that consumption in the power generation sector will more than double between 1997 and 2010, from about 158 billion cubic feet in 1997 to 321 billion cubic feet in 2010. The strongest growth is expected between now and 2001, as electricity sector restructuring takes hold. The CGA indicates that its forecast is heavily influenced by the restructuring of the electricity sector that is currently either underway or anticipated in many provinces. While growth in gas use in the residential and commercial sectors is expected to slow as a result of conservation and efficiency improvements, the CGA still anticipates modest growth for those sectors as well [4].

In Mexico, the Comision Federal de Electricidad (CFE), the state utility that currently serves 99 percent of the Mexican power market, has been exploring options for the restructuring of the electricity sector for about 2 years. Although no clear restructuring strategy has yet emerged, strong growth for natural gas consumption for power generation is anticipated. Natural gas demand for power generation has grown by more than 5 percent per year for several years, and the CFE hopes to install 13 gigawatts of predominantly gas-fired combined-cycle new capacity over the next 5 years (the CFE has indicated that it plans to have 47 gigawatts of installed capacity by 2006). In addition, conversions of 12 existing fuel-oil plants to natural gas are expected to increase gas demand at those units from 22 million cubic feet per day in 1996 to 872 million cubic feet per day in 1999. A major impetus for the conversions is environmental concerns. By 2006, overall CFE gas consumption is expected to quintuple from the current rate of 500 million cubic feet per day [5].

Infrastructure expansion is both underway and expected to continue throughout North America to meet increasing demand. More than 40 pipeline construction projects, including 10 new pipelines, were completed in the United States in 1997, adding more than 6.6 billion cubic feet per day of capacity [6]. The AEO98 projects continued expansion of interstate pipeline capacity between now and 2020, with the biggest increases along corridors that move Canadian and Gulf Coast supplies to markets in the eastern half of the United States. Increases in storage capacity are projected for most regions of the United States. A considerable increase in pipeline capacity both within Canada and between Canada and the United States is expected to provide access to western Canadian supplies and Sable Island supplies in the offshore Atlantic, significantly enhancing the possibilities for trade between the United States and Canada.

Trade between the United States and Mexico is also expected to grow, with U.S. exports to Mexico increasing to help meet Mexico’s anticipated consumption growth. Two new natural gas export lines to Mexico, totaling 237 million cubic feet per day of new capacity, were placed in service in 1997. The completion of the lines increased U.S. export capability to Mexico by 27 percent [6]. A past hindrance to imports of U.S. gas supplies into Mexico has been a 6-percent tariff on U.S. gas imported into Mexico. On June 13, 1997, a petition signed by the Natural Gas Supply Association and four others was filed with the U.S. Trade Representative, seeking early elimination of the tariff [7]. The request is now being considered by trade officials of both countries. The tariff, paid by Mexican businesses and consumers, has kept U.S. supplies from competing with natural gas produced by Mexico’s monopoly supplier, Petroleos Mexicano (PEMEX). Its elimination would foster competition between PEMEX and imported gas and lower the overall cost of gas in Mexico [8].

Privatization of Mexico’s natural gas industry—begun in May of 1995 with the mandated liberalization of the transmission, distribution and storage of natural gas— continues. Eight distributorships have already been privatized (three have completed the process and five have been awarded permits), and four additional concessions are slated to be offered in the near future [9, p. 155]. PEMEX is currently preparing a tender to be issued in early 1998 for Mexico’s first natural gas storage project, reportedly to be both built and operated by private companies [10].

Although the Mexican constitution prohibits foreign participation in oil and gas exploration, production and refining, there has been speculation that the government would try to allow foreign firms to produce gas in the northern Mexico’s Burgos Basin by designing a contract that would be a service contract with performance incentives tied to output. PEMEX has called a tender for the development of Burgos Basin fields in order to increase domestic supplies in the area and head off competition from U.S. producers, which are gaining access to the region as a result of the opening of the natural gas pipeline sector to foreign investment [11].

Western Europe

Western Europe is expected to see some of the most rapid growth in natural gas consumption among the industrialized countries. In the IEO98 forecast, gas use in Western Europe rises from 13 trillion cubic feet in 1995 to more than 32 trillion cubic feet in 2020 (Figure 49). In large part, the growth can be attributed to the privatization that many European countries are currently undergoing in the energy sector, as well as government encouragement to develop the natural gas infrastructure as a way of reducing greenhouse gas emissions. In addition, the European Union (EU) is attempting to liberalize Europe’s energy markets, and year-long negotiations resulted in an approved timetable for the EU’s Gas Directive, which allows for the deregulation of Western Europe’s gas markets (see box on page 54).

Figure 49. Natural Gas Consumption in Western Europe, 1970-2020

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 (1998).

The United Kingdom started to liberalize its natural gas markets in 1986, and they should be fully open by the end of 1998. The market restructuring has resulted in substantial growth in gas-fired electric power generation in the country and plans for further expansion in the future. Since 1990, 11.4 gigawatts of combined-cycle gas-fired electricity generation capacity has been built in the United Kingdom. An additional 4.5 gigawatts of capacity is currently under construction, 7.5 gigawatts has been approved for construction, and an additional 7.9 gigawatts has been proposed, which may or may not receive approval [14, p. 263]. In 1996 alone, 2.3 gigawatts of new gas-fired electricity generating capacity was added.

The current status of Western European natural gas pipelines is shown in Figure 50. In October 1998, the Interconnector pipeline should be completed, linking Bacton, England, and Zeebrugge, Belgium. The pipeline will have an export capacity from Bacton to the continent of 706 billion cubic feet per year and an import capacity of 388 billion cubic feet per year. While it seems unlikely that the United Kingdom will be able to use the Interconnector to export substantial gas to the European continent until gas prices rise, several export contracts have been signed with the German utilities Wingas, Ruhrgas, and Thyssengas for a total of 1,589 billion cubic feet, and with Norsk Hydro for an additional 424 billion cubic feet. The contract periods range from 7 to 15 years, beginning at the end of 1998; thus, between 18 and 70 billion cubic feet per year will be delivered under each contract [15] (Table 20). These contracts will allow German utilities to diversify their gas supplies.

Figure 50. Current Status of Western European Natural Gas Pipelines, 1997

Source: DRI/McGraw-Hill, Towards a Competitive European Natural Gas Market (Lexington, MA, November 1997), p. 100.

Table 20. Contracts in Place for Natural Gas Sales from the United Kingdom’s Interconnector to MainlandEurope

Other countries in Western Europe will be able to take advantage of their resource bases or strategic geographic positions in the fast-growing gas sector. In Norway, for example, rich natural gas reserves are used mainly as an export commodity and for fairly moderate consumption in the country’s offshore oil and gas facilities [16]. In fact, plans to construct two 350-megawatt gas-fired power plants on Norway’s west coast to supply electricity to Sweden and Finland were met with protest from environmental groups, which argued that the additional thermal capacity would increase the country’s greenhouse gas emissions (virtually all Norway’s electricity is generated by hydroelectricity). Government approval was given to the plants, which are scheduled to begin operating in 1999, but it will be difficult to build additional plants in the future because of the environmental considerations. Interestingly, the resulting gas-generated electricity would replace coal-fired generation in Sweden and Finland, thus reducing the regional emissions.

Norway secured several natural gas export contracts in 1997, including a contract to supply 1,412 billion cubic feet to Gaz de France over a 26-year period beginning in 2001. The gas will be delivered to France through the NorFra pipeline, currently the world’s longest subsea pipeline. Another long-term NorFra supply contract was signed with Italy’s Snam. Between 353 and 424 billion cubic feet of gas per year will be supplied for 25years to Italy beginning in 1999-2000. A small contract (for 25 million cubic feet per day) was also signed with Ireland’s Bord Gais Eireann for 1 year [17]. The gas will be shipped from the Froy field through the Frigg pipeline to St. Fergus in Scotland and from there to Ireland through Bord Gais’ subsea pipeline. The contract will account for 25 percent of Ireland’s total gas supply.

Norway has also taken steps to penetrate the East European gas market. The first contract by an East European country—the Czech Republic—for Norwegian gas was signed in April 1997. Norway will supply the Czech Republic’s state gas importing company, Transgas, with 106 billion cubic feet per year for a 20-year period [18]. Gas deliveries began in May 1997.

In 1985, Norway supplied about 27 percent of the gas used in the United Kingdom from its share of the Frigg field [16]. But a sharp increase in UK gas production, coupled with declining output from Frigg and the refusal of the British government to authorize new gas imports, has caused the Norwegian share to drop to about 2 percent. Talks between the two countries began in 1996. Norway resolved problems with the United Kingdom in 1997 and now is able to export gas to the United Kingdom through the Frigg pipeline [19].

Norway has taken steps to bolster its natural gas infrastructure in order to accommodate the increased opportunities for gas exports. Gas is presently exported through the Europipe and Norpipe to Emden, Germany, and through the Zeepipe to Zeebrugge, Belgium. In 1995, Norwegian authorities approved construction of the NorFra System, which will run from the Sleipner area fields to Dunkirk, France. The Europipe II line, direct from Kårstø to Emden, should be built before 2000. The two planned export pipelines will help Norway meet the terms of existing contracts that will increase its gas exports to nearly 2,648 billion cubic feet per year.

Austria has the geographic vantage to become a major natural gas distribution point for Siberian gas supplies to western and southeastern Europe [20, pp. 19-20]. ÖMV, the largest oil company in Austria, has completed or begun construction on a number of pipeline projects designed to move gas into the European market, such as the Trans-Austria-Gasline (TAG), a 237-mile dual pipeline running across Austria from the Slovak border and supplying 90 percent of its gas to Italy’s Snam. ÖMV is in the process of increasing the TAG pipeline capacity. At the end of 1998, the completed line will have a total capacity of 23 billion cubic meters. Other lines include the 152-mile West-Austria-Gasline, which runs from the Slovak border to upper Austria and Germany and supplies Russian gas to Germany and France; the 16-mile South-East-Gasline, which supplies gas to Italy, France, Slovenia, and Croatia; and the 74-mile Hungaria-Austria-Gasline.

In Germany, several pipeline projects currently are underway, the three most important being Trans Europa Naturgas Pipeline (a Ruhrgas/Snam joint venture), Wedel Line (Bielefeld to Aachen), and a pipeline from Schnaitsee to the Austrian border. Trans Europa Naturgas Pipeline will expand an existing system that stretches from the German-Dutch border near Aachen to the Swiss-German border at Schwoerstadt with a line that will run parallel to the existing line. Rising demand in southern Germany and Switzerland has created the need for additional capacity, which should be completed by 2000 [14, pp. 156-158]. The first portion of the 50-mile Wedel line has been completed, connecting Bielefeld to Soest. Construction on the second portion (136 miles from Soest to Aachen) is scheduled to begin early in 1998, and the entire pipeline should be completed by the end of the year. The Wedel line will enable German Wingas to supply gas to the Ruhr region, currently dominated by Ruhrgas.

Many other countries of Western Europe, including Italy, Spain, Greece, and Turkey, have extensive plans to increase natural gas use. In Italy, gas supplies are being secured from both pipeline and liquefied natural gas (LNG) sources. Snam, a subsidiary of the Italian oil and gas company Eni, has contracts with Gasunie (theNetherlands), Sonatrach (Algeria), and Gazprom (Russia) for a combined 1,236 billion cubic feet of gas imports per year [14, pp. 185-186]. Italy consumed 1,921 billion cubic feet of natural gas in 1995 [21, p. 8]. Snam has also signed an agreement to import between 212 and 282 billion cubic feet per year from Norway beginning in 2000 [14, p. 185]. Eni and Russia’s Gazprom have contracted to provide Italy with an additional 194 billion cubic feet of gas per year. A project to double capacity on the Algeria-to-Italy Transmed pipeline to 847 billion cubic feet per year is already under construction. Enel signed a contract with Algeria’s Sonatrach for the supply of 141 billion cubic feet of natural gas per year beginning in 1997, to be shipped through the Transmed 2 pipeline.

In addition to pipeline gas, Italy plans to increase the amount of LNG it imports. Snam plans to construct its second LNG terminal at Monfalcone, northwest of Trieste in the Gulf of Venice. The project would involve the construction of a terminal with an initial annual capacity of 282 billion cubic feet of methane, which could be expanded to 424 billion cubic feet. The existing Snam LNG terminal at Panigaglia near La Sezia, in the Gulf of Genoa, has a capacity of 106 billion cubic feet per year.

Enel had signed a contract to purchase 124 billion cubic feet of gas from the Bonny LNG project in Nigeria over a 20-year period. At the end of 1996, however, the company canceled the contract, after determining that it would be unable to construct an LNG receiving terminal on the Luscany coast because of the costs associated with adhering to environmental stipulations attached to the project.

In 1993, the first Norwegian gas was imported to Spain [14, pp. 236-237]. The gas is piped via the French grid at 71 billion cubic feet per year. An even more important development for Spanish gas is the 859-mile Maghreb pipeline, which connects Seville, Spain, with the Hassi R’Mel gas fields in Algeria. The pipeline, with a potential capacity of 635 billion cubic feet per year, will also extend into Portugal. The first gas through Maghreb (initial capacity 247 billion cubic feet per year) arrived in Spain at the end of 1996.

Greece is attempting to introduce gas consumption in order to diversify its energy supplies, decrease dependence on oil and lignite, and reduce greenhouse gas emissions. The state-owned utility, DEPA, started importing gas from Bulgaria and Russia in July 1997 through a Bulgarian pipeline [20, pp. 49-50]. The company has contracts in place to supply natural gas to electric utilities and 17 industrial companies.

So far, there are plans for gas use in five Greek cities: Athens, Kavalla, Thessalonika, Volos, and Piraeus. A 248-mile pipeline should connect them, and Russia and Algeria are expected to supply all of the gas consumed in Greece. The first gas deliveries from Russia to Thessalonika and Athens began in July 1997, through a 310-mile pipeline that runs from Bulgaria to Athens. The gas pipeline is designed to transport 247 billion cubic feet per year. Prometheus Gas—a joint venture between Russia’s Gazprom and Greece’s Kopelouzos—along with Stroytransgas and Zangas is also constructing a 372-mile distribution pipeline.

In addition, the European Investment Bank (EIB) is funding the construction of a high-pressure gas transmission and distribution system in Greece. The project is the largest energy investment (Ecu 200 million) in Greece by the EIB. The system includes a pipeline running from the Greek-Bulgarian border at Kula to Aghia Triada near Athens, plus an offshore pipeline running from Aghia Triada to Revithoussa Island and an LNG receiving terminal. The project is jointly supported by the EIB, the EU’s Structural Fund, and the European Coal and Steel Community.

Turkey has extensive plans to increase natural gas use for electric power production. The country is attempting to attract enough foreign investment to install 4.2 gigawatts of gas-fired capacity [22]. A call for bids for six build-own-operate power plants was offered in early 1997. The proposed gas-fired plants include two 700-megawatt plants in Gebze, one 700-megawatt plant in Adapazari (near Istanbul), one 700-megawatt plant in Ankara, and a 1,400-megawatt plant on the west coast in Izmir. Several pipeline projects have been proposed to supply gas to these facilities, as well as several LNG terminals. In addition, the state-owned gas transportation company, Botas, is expanding its gas transmission network along the Black Sea and the Aegean.

Turkey’s plans to import gas from Turkmenistan through a pipeline under construction across Iran led to some controversy with the United States in 1997. The project initially appeared to be in violation of the U.S. Iran-Libya Sanctions Act; however, because Iran will only receive transit fees for moving the gas to Turkey, the United States determined that Turkey was not in violation of the Sanctions Act. The willingness of major world energy companies, such as France’s Total, to risk violating the U.S. Sanctions Act clearly demonstrates how lucrative the Turkish gas markets are expected to become.

Eastern Europe and the Former Soviet Union

IEO98 projects a reversal of recent trends in natural gas markets in Eastern Europe and the former Soviet Union (EE/FSU). Natural gas consumption in the region as a whole is projected to grow from 23.4 trillion cubic feet in 1995 to 42.7 in 2020, an increase of 83 percent (Figure 51). The highest growth is projected for Eastern Europe, where consumption is projected to more than double, increasing from 2.7 trillion cubic feet in 1995 to 7.3 trillion cubic feet in 2020. Consumption growth in the FSU is projected to increase by 72 percent over 1995 levels by 2020, with slight growth between now and 2000 and most of the growth occurring in the post-2000 period. The projected growth in Eastern European is more rapid, with a relatively steady rise throughout the forecast.

Figure 51. Natural Gas Consumption in the EE/FSU Region, 1970-2020

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 (1998).

The FSU accounts for more than 40 percent of the world’s natural gas reserves. With more than 34 percent of the world’s proven reserves, Russia far exceeds any other country in production potential. Other FSU republics with significant reserves are Azerbaijan, Kazakhstan, Turkmenistan, Ukraine, and Uzbekistan, with reserves ranging from 0.1 percent of the world total for Azerbaijan to 2.0 percent for Turkmenistan [23]. Eastern European countries, although attempting to diversify their supply options, are heavily dependent on the FSU to meet their currently increasing natural gas demand. Proved reserves in all of Eastern Europe currently account for less than 0.5 percent of the world total.

As political and economic conditions stabilize within the EE/FSU, the downward trend in natural gas production and consumption seen between 1990 and 1995 is already beginning to be reversed. Natural gas production for 1996 in the FSU was 1.4 percent above 1995 levels, with increases in almost all of the gas-producing republics. Russia, the major producer (accounting for 25.1 percent of the world’s total production), increased its output by 1.0 percent; Uzbekistan, the second largest producer, increased by 0.8 percent; and Turkmenistan and Kazakhstan increased by 9.0 and 8.5 percent, respectively. Only Azerbaijan saw a decline, with production dropping by 4.5 percent from 1995 levels, primarily because of problems in recovering associated gas from its primary production source. FSU consumption increased by 0.7 percent over 1995 levels.

Russia significantly slowed its decline in natural gas consumption from 5.1 percent between 1994 and 1995 to 0.3 percent between 1995 and 1996. All the other major consuming republics, with the exception of Azerbaijan and Kazakhstan, showed increases. While Eastern European production declined in general, consumption increases were seen throughout the region [3, pp. 23 and 26].

In both Russia and Turkmenistan, production significantly outpaced consumption in 1996, with the excess production exported to satisfy both foreign demand and demand in other FSU republics. Very little gas is consumed internally in Turkmenistan, and most of its output went to other republics, in particular, Ukraine. Russia and Turkmenistan together accounted for 95 percent of the gas trade among the FSU republics, with Kazakhstan and Uzbekistan accounting for the other 5 percent [24, p. 57]. To date, most of Uzbekistan’s gas production has been consumed internally. Although there is considerable potential for increased production to meet export demand, particularly to Ukraine, it has so far failed to materialize [24, p. 11]. Kazakhstan consumed most of its production internally and was in addition dependent on imports to satisfy a large portion of its gas demand.

Trade among the FSU republics has been in decline in the 1990s, in part because of a history among the importing republics of nonpayment for supplies and the subsequent amassing of enormous debt for natural gas, causing reluctance on the part of shippers to provide more gas until payments are made. Reduction of amassed debt was significant in 1996, and Ukraine alone reduced its debt from 7.03 billion rubles to 2.27 billion rubles. Russia had in the past treated Ukraine leniently, not only because Ukraine was Russia’s largest gas market, but also because 90 percent of Russian export gas moved through Ukraine [24, p. 60]. Belarus, also significantly in arrears in gas debts, plans to reduce part of its debt through participation in the building of theportion of the Yamal-Europe pipeline that transits Belarus.

Infrastructure expansion within the EE/FSU is underway to meet projected demand growth. Russia, especially, is planning significant infrastructure expansion in order to serve expanding European markets. The most significant undertaking is the development of the Yamal gas fields in northern Siberia and the construction of the Yamal-Europe pipeline through Belarus and Poland to move the gas to market. Unlike other significant Russian gas fields, where the gas is in shallow reservoirs and easily developed, the Yamal fields are located in an area with extreme climatic conditions, and production costs in the Yamal fields will far exceed production costs at current producing fields. The additional cost of building the pipeline needed to serve these remote fields will significantly increase the cost of gas supplies from the region.

Russia has long felt that development of the Yamal fields will be necessary to supplement declining production in already developed fields and meet projected increases in natural gas demand; however, there has been considerable speculation in the trade press recently as to whether the development of the remote Yamal fields is necessary in the near future. Some analysts feel that demand increases can be satisfied by the development of lower cost sources, such as satellite fields in current producing regions, perhaps for the next 10 to 12 years [25]. Another blow to the development of the Yamal fields may have been dealt by the announcement of a strategic alliance between Gazprom and Royal Dutch Shell on November 17, 1997, one thrust of which will be the development of the gigantic Zapolyarnoye gas and condensate field in West Siberia. Significant output from the field would compete with higher priced Yamal gas [26].

Regardless of what eventually happens with the Yamal fields, earlier stages of the project will continue as planned. The Yamal pipeline project is being constructed from the market back, with the earliest stage designed to deliver gas to Germany and Poland from fields where the infrastructure is already in place. Work is underway on sections crossing Poland and Belarus, which will help reduce Gazprom’s near-total dependence on Ukraine for moving its gas to Europe [27, p. 12]. Large amounts of gas are expected to flow into Germany by the end of 1998, and some sections of the pipeline are already carrying gas from new Siberian fields into Europe [27, p. 11]. Elsewhere in the EE/FSU region, considerable infrastructure expansion is either planned or underway.

Privatization and foreign investment continue to make inroads in the EE/FSU, where until recently most of the natural gas industry had been controlled by national governments. Since Gazprom relaxed rules barring foreign investors last year, international banks have been pouring money into the gas industry, with export projects—in particular, the construction of the Yamal-Europe pipeline—attracting most of the big loans. Gazprom shares, long barred to foreign investors, have been successfully traded on the London stock market since October 1996 [28]. The strategic alliance with RoyalDutch Shell also signals the change in Russian sentiment toward foreign investment in its gas industry.

In March 1997, Kazakhstan signed a foreign investment law establishing a state committee on investment, and privatization is expected to have a significant impact onthe gas industry over the next several years. Turkmenistan is inviting foreign participation in the area of natural gas exploration and development, and the oil and gas industry is being restructured. Foreign investment in Uzbekistan has also increased dramatically, and several foreign companies have expressed interest in exploration and development joint ventures.

Central and South America

In Central and South America, vigorous expansion of the natural gas infrastructure is continuing. The region’s natural gas consumption is expected to grow to five times its 1995 level by 2020, reaching 13 trillion cubic feet. In Brazil alone, gas use is expected to grow by 14 percent annually through 2020, to 4.3 trillion cubic feet. In 1995, 2.6 trillion cubic feet of natural gas was consumed in the entire region [21, p. 8] (Figure 52).

Figure 52. Natural Gas Consumption in Brazil and Other Central and South America,
1970-2020

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 (1998).

Argentina is attempting to solidify its position as a gas supplier to Chile and Brazil. As part of this effort, the 290-mile, $350 million gas pipeline, GasAndes, began operating in August 1997, the first gas line link between Argentina and Chile [29]. The pipeline will be able to deliver 350 million cubic feet per day, initially transporting gas from the La Mora compressor station in the Mendoza area of Argentina to Santiago, Chile.

Two additional pipelines linking Chile and Argentina are being developed: the Atacama project (a $750 million project consisting of a 575-mile pipeline to be built from northern Argentina to northern Chile and two 355-megawatt gas-fired electric power plants by a consortium of Endesa, CMS Energy, and Argentina’s Astra and Pluspetrol Energy) and the Norgas-Latin America (a $400 million, 550-mile pipeline to be built from Salta, Argentina, to Tocopilla, Chile, by a consortium consisting of Edelnor, Electroandina, YPF, and Tecpetrol) [30; 9, pp. 39-40]. Companies involved in developing the two plans agree that constructing two parallel pipelines is excessive [31]. In fact, constructing both lines will triple capacity by 2003, whereas demand is expected only to double. Nevertheless, talks to reach a compromise on the projects broke down in October 1997, and it appears that both projects will be constructed.

The Atacama project advanced in 1997 as GasAtacama (a joint venture of CMS and Endesa) awarded a contract for laying the 250-mile pipeline. Construction is expected to begin in January 1998. The $750 million project, which should be completed in early 1999, will provide gas from Argentina to power plants and industrial customers in northern Chile [32]. The Atacama also involves two 35-megawatt gas-fired generating plants in the port of Mejillones, both of which are scheduled to begin operating in 1999 [31].

Although there is substantial activity in developing gas infrastructure between Chile and Argentina, the prospects for exporting to Brazil are even greater. The most prominent project for Brazil is the $2 billion Bolivia-Brazil pipeline, a 1,875-mile line to run from Santa Cruz, Bolivia, to Porto Alegre, Brazil [33]. There are also plans to export gas from northeastern Argentina to industrial customers in southern Brazil [9, pp. 39-40]. Argentina’s YPF and Brazil’s Petrobas are studying the possibility of constructing a pipeline from Argentina to Sao Paolo, Brazil, including a proposed 1,400-mile pipeline from Argentina’s Aguarague, Acambuco, and Ramos fields to Sao Paolo.

In northeastern Brazil, construction is continuing on the 230-mile Guamare-Pecem pipeline, running from the Rio Grande do Norte gas fields to the industrial areas of Ceara [34]. The project, scheduled to begin operating by mid-1998, will deliver 106 million cubic feet per day. When it is fully operational and another link is added, the Guamare-Pecem system should be able to deliver 565 million cubic feet per day—as much as the Bolivia-Brazil pipeline.

The government of Colombia also would like to increase that country’s access to gas dramatically. The government announced in 1997 that it intended to extend natural gas access to 80 percent of the population by 2010 [9, pp. 126-127]. Government plans include a $27 billion investment in the country’s energy infrastructure, with $3 billion dedicated to the construction of a nationwide natural gas supply system. Although legislation to allow the privatization of state-owned Ecogas failed in May 1997, privatization of the distribution system has begun, and two of Colombia’s largest distributors already have been privatized. Enron acquired Ecopetrol’s share of the country’s largest distributor, Promigas, in early 1996, and in 1997 Ecopetrol’s shares of Gas Natural were purchased by Spain’s Gas Natural.

Middle East

Natural gas consumption in the Middle East is projected to grow by 2.6 percent annually over the 25-year forecast (Figure 53). Electricity generation consumes the largest share of natural gas use in the region, because of its clean-firing qualities, convenience of use, and moderate costs relative to oil. Energy policy trends are further promoting diversification of supply, substituting gas for oil so that oil can be exported, and substituting gas in domestic consumption in place of imported oil. Gas has made only modest inroads in residential and commercial use in Saudi Arabia, Algeria, and Iran [35, pp. 41-42].

Figure 53. Natural Gas Consumption in the Middle East and Africa, 1970-2020

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 (1998).

There have been increasing efforts to develop Middle Eastern LNG for export, especially to Asia. Algeria, Qatar, Oman, and the United Arab Emirates’ (UAE) Abu Dhabi all have developed LNG schemes [35, p. 42]. The expansion of LNG sales is impeded somewhat, however, by the challenge of high costs associated with processing and delivering LNG in special refrigerator ships. In recent years, contract provisions for LNG have included the flexibility to allow customers to gauge prices to the fluctuations in crude oil prices or to negotiate lower prices in exchange for large supply volumes. Algeria’s exports to Distrigas in the United States have been linked to the average U.S. price for delivered gas. Qatar has linked LNG prices to a 3-month average delivered LNG price to Japan (thereby indirectly linking the LNG prices to crude oil prices) and has lowered the floor price in the Korea Gas Corp-Ras Laffan contract. Mobil, the operator of Qatar’s Ras Laffan, has even agreed to the lower floor price in exchange for larger sales volumes and has guaranteed part of the Ras Laffan debt if prices fall below $1.90 per million Btu.

Iran has the world’s second largest natural gas reserves, second only to Russia. DRI/McGraw-Hill estimates that, given current production levels, the Iranian reserves could last for almost 600 years [35, p. 167]. Developing the 321 trillion cubic feet South Pars field, which accounts for an estimated 40 percent of Iran’s gas reserves, is a priority for the Iranian government [36]. The development of these reserves should help Iran maintain its oil output by using gas in enhanced oil recovery gas injection schemes, as well as providing a potentially important export commodity.

In September 1997, the energy companies Total (France), Gazprom (Russia), and Petronas (Malaysia) signed a $2 billion agreement with the Iranian National Petroleum Company to develop 2 billion cubic feet per day of the South Pars reserves. The agreement was signed despite the threat of sanctions under the U.S. Iran-Libya Sanctions Act of 1996. The South Pars gas is to be used for domestic consumption, reinjection to enhance oil output, and ultimately for export to Turkey. Iran is committed to providing Turkey with 300 million cubic feet per day of gas beginning in 1999 [37]. Pakistan and India are also potential customers for Iran’s gas, either by pipeline or as LNG.

There are several proposals for bringing natural gas to Israel. Israel is discussing the possibility of importing LNG from Qatar and also importing gas by pipeline directly from Egypt or Saudi Arabia [35, pp. 185-186]. The $4 billion Qatar LNG import project would provide Eliat with gas for residential use, as well as for export to Europe. Saudi Arabia could also be a potential source of natural gas, supplying Saudi gas from the Tabuk field to Israel through a 62-mile pipeline.

Egypt is another potential Israeli supplier. In November 1993, Egypt agreed in principle to sell gas to Israel. Gas would be delivered through a 180-mile pipeline from Egypt’s Delta region across the Gaza Strip into Israel. Most of the gas would be consumed for electricity generation, though sales are not expected to begin before 2005.

Expanding the gas sector is a priority for the government of the UAE, particularly in Abu Dhabi which accounts for 97 percent of the Emirates’ proven reserves. The UAE would like to increase domestic use of natural gas, use for oil field reinjection in enhanced oil recovery schemes, and LNG exports. One of the largest gas-bearing structures in the world is the UAE’s offshore, nonassociated Khuff reservoir, which has not yet been fully developed [35, p. 258]. Khuff gas is expected to be transported to Dubai for oil field injection to extend the life of Dubai’s oil fields.

In addition to the Khuff, expansion is expected to take place at the onshore Bab field—known as the Onshore Gas Development. Increased capacity from the Onshore Gas Development will be used to fuel electricity generation, as well as oil field injection. Much of Abu Dhabi’s offshore gas production is being used to supply LNG exports for mostly Japanese customers. Capacity at Das Island doubled in 1994 with the construction of a third LNG train, raising capacity to more than 5 million tons of LNG per year. An expanded long-term contract was signed with Abu Dhabi’s largest gas customer, the Japanese utility TEPCO, and an increasing number of spot gas sales have been made into Asian and European markets.

Africa

Ninety percent of all current natural gas consumption in Africa is attributed to four countries: Algeria, Egypt, Libya, and Nigeria [21, p. 9]. Natural gas consumption in Africa is projected to grow to 3.4 trillion cubic feet by 2020, slightly more than doubling from the 1995 level.

Algeria has one of the largest gas fields in the world—the Hassi R’Mel field, which has more than 85 trillion cubic feet of reserves [35, pp. 68-69]. Gas exports are a major source of income for Algeria, and export infrastructure is being developed quickly, despite the country’s economic problems. The capacity of the Transmed pipeline from the Hassi R’Mel field to Italy (via Tunisia) is being doubled from 459 billion cubic feet to 918 billion cubic feet. The 1,460-mile Transmed has been operating since 1983, supplying Tunisia, Italy, and Slovenia. Four long-term Transmed contracts are currently in place [35, p. 68]: 688 billion cubic feet per year to Italy’s Snam beginning in 1983 and ending in 2019; 18 billion cubic feet per year to Tunisia’s ETAP beginning in 1983 and ending in 2019; 21 billion cubic feet per year to Slovenia’s Petrol Ljubljana beginning in 1992 and ending in 2007; and 141 billion cubic feet per year to Italy’s Enel beginning in 1995 and ending in 2015.

A second major pipeline linking Algeria to the European markets is the Maghreb, which runs from the Hassi R’Mel field to Seville, Spain (through Morocco), was completed in October 1996, and an extension from Spain to Portugal was completed in February 1997 [38]. The 849-mile Maghreb will allow Algeria to ship gas as far as Germany through the European pipeline network [35, p.68]. The cost of the Algeria-Spain segment was $1.9 billion, and the extension to Portugal was estimated at $500 million. The World Bank, European Investment Bank, and national governments helped finance the project.

Algeria has also been renovating its LNG plants at Bethiou, Arzew, and Skikda, which were constructed in the early 1970s with a combined capacity of about 1,094 billion cubic feet per year. Subsequent work on the project has increased capacity to 1,200 billion cubic feet per year. There are 11 existing contracts for 911 billion cubic feet of Algeria’s LNG, with more than one-third of the contracted gas to be delivered to Gaz de France [35, p. 69].

In Nigeria, major efforts have been undertaken to end gas flaring in the country’s oil fields. Shell Petroleum Development Corporation of Nigeria (SPDC) has planned four gas gathering projects to collect gas for Nigeria’s Escravos-Lagos Pipe Network to use in various power plants and industrial applications in Odidi, South Forcados, Escravos, and the Greater Ughelli area of Delta State [39]. The Odidi project alone is expected to cost $250 million and will be used to collect some 80 million cubic feet of gas per day [40].

Chevron and the Nigerian National Petroleum Corporation initiated the Escravos Gas Project to reduce flaring and to recover the gas and condensate from Chevron’s offshore oil fields [41]. By September 1997, the project was producing 145 million cubic feet of gas, which was sold to the Nigerian Gas Company for industrial end users. The project also produces 8,000 barrels of liquefied petroleum gas and natural gas liquids per day. Recently, however, funding problems have forced Chevron to delay work on the second phase of the Escravos project, which was to expand the gas gathering system so that another 120 million cubic feet of gas per day could have been processed [42].

Nigeria has plans to develop a natural gas network for domestic consumption, using $50 million in funding from the World Bank [35, pp. 124-125]. In addition, a number of export projects are either under consideration or already under construction, including plans to develop the $260 million West African Gas Pipeline Project to provide Nigerian gas for electricity generation and for industrial customers in Ghana, Benin, and Togo [43]. Ghana is expected to consume about 75 percent of the gas from the pipeline at a proposed 300- to 400-megawatt gas-fired power plant at Takadi and at the Valco aluminum smelting plant.

Although several African LNG projects to supply Europe and the United States have been under consideration for years, the Nigerian Bonny LNG project is farthest advanced. With a cost estimated at around $4.5 billion, the project consists of gas transmission systems, two liquefaction trains, and export infrastructure with a capacity of 254 billion cubic feet. It is scheduled to be completed by 1999, with first scheduled deliveries to begin in 2000. Agreements for the LNG have been arranged with Spain’s Enagas (56 billion cubic feet per year); Turkey’s Botas (32 billion cubic feet year); and France’s Gaz de France (18 billion cubic feet per year). Italy’s Enel pulled out of an agreement to purchase 124 billion cubic feet per year—by far the largest share of Bonny LNG output—in December 1996 because of difficulties the utility was having in securing an LNG reception terminal. The dispute was resolved in October 1997 when Gaz de France offered to accept Italy’s delivery at the Montoir LNG terminal in Brittany [44].

Asia

The 1997 Asian currency crisis resulted in the delay of many energy projects in developing Asia. Nevertheless, many natural gas projects in this part of the world are going forward, although some of the more expensive gas projects, such as the Natuna gas pipeline project and the Omani LNG project, face delays. The IEO98 forecast does not expect a long-term slowdown of economic growth in the region. In developing Asia, natural gas consumption is projected to grow nearly sixfold over the 25-year period, from 4.7 trillion cubic feet in 1995 to 27.7trillion cubic feet by 2020. In industrialized Asia (Australia, Japan, and New Zealand) gas use grows at a more conservative pace of 1.6 percent annually, from 3.1trillion cubic feet in 1995 to 4.6 trillion cubic feet in 2020 (Figure 54).

Figure 54. Natural Gas Consumption in Asia byRegion, 1970-2020

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 (1998).

Thailand was hit particularly hard by the economic downturn. The economic recession has meant that many energy projects in the country are being renegotiated. The 50-percent devaluation of the Thai baht between May and October 1997 led to a postponement of a number of gas projects. Oman LNG announced that both the Petroleum Authority of Thailand (PTT) and Oman LNG had agreed to suspend the unsigned 25-year LNG agreement that would have brought 1 million tons of LNG per year to Thailand beginning in 2001, rising to 1.7 million tons in 2003 and 2.2 million in 2004 [45]. The PTT had wished to delay taking the Oman LNG by 10 years, because projections for gas demand for the next decade have been cut by 20 percent [46].

A project designed to pipe natural gas from Indonesia’s Natuna gas field in the South China Sea also faces delay and renegotiation since Thailand’s economic downturn. Indonesia’s state-owned Pertamina negotiated a 2-year delay for PTT’s purchase of Natuna gas, moving the startup date for the contract from 2003 to 2005 [47]. Moreover, price negotiations are expected to delay deliveries another 2 years, so that the first Natuna gas would be delivered to Thailand in 2007. PTT wanted to renegotiate the price of Natuna gas from the original terms to a price below that of gas from the Malaysia-Thailand Joint Development Area; however, Pertamina would not agree. Originally, Thailand was to begin purchasing 500 million cubic feet per day from the Natuna project, increasing to 1 billion cubic feet per day after 2 years.

Despite the cuts, a number of natural gas projects are going forward, and a substantial number of companies still are interested in working on gas projects in Thailand. Unocal corporation announced in mid-November 1997 that it expected development on the first phase of its Pailin field—with production of 165 million cubic feet per day scheduled to begin at the end of 1998—to continue on schedule [48]. Moreover, in October, the U.S. energy company Enron signed a partnership with a Thai engineering company, EMC, to “pursue investment opportunities in infrastructure projects” in Thailand that will include natural gas pipelines and electric power plants [49]. The Canadian natural gas company, Nova Corporation, announced in November that it had an interest in participating in construction of gas pipelines and electric power plants in Thailand, in particular a third natural gas trunk line planned for the Gulf of Thailand [50].

PTT also signed an agreement in November to purchase gas from two fields in the Gulf of Thailand from Rutherford-Moran Oil Corporation [51]. The corporation already supplies PTT with 100 million cubic feet per day of gas. The new agreements will increase that amount to 300 million cubic feet per day when production at the two gas fields begins at the end of 1999.

Malaysia continued some aggressive gas development in 1997. There is concern that the country might face power shortages in the long term, accentuated by the indefinite postponement of the large-scale Bakun hydroelectric project earlier in the year in response to a combination of environmental criticism and the Asian economic crisis. As a result, Malaysia has decided to increase its gas-fired power generation capacity [52]. Malaysia has committed to accept delivery of 300 million cubic feet per day of the first production from the Malaysia-Thailand Joint Development Area (JDA), which should begin operating in late 1999. Because it will take time for the electricity generating infrastructure to catch up with the gas production, much of the first gas is expected to be used by a proposed petrochemical plant.

Exploration in the JDA has been quite successful, with 10 trillion cubic feet of gas already discovered. Malaysia’s Petronas and U.S. Triton Energy (forming the joint venture, Malaysia-Thailand Joint Authority—MTJA) believe another 10 trillion cubic feet of gas could be discovered [52]. In fact, in November 1997, the MTJA confirmed the discovery of an eighth field in the JDA, called Wira-1, with a gas flow of 9.1 million cubic feet per day. Four other finds were made in 1997 alone.

Pakistan is attempting to expand its natural gas consumption, which already accounts for almost 40 percent of its primary energy consumption [21, pp. 180, 186]. The country currently produces virtually all its own gas, but consumption is expected to overtake production soon, and efforts have been made to secure supplies from outside sources. In 1997, Unocal announced that Pakistan would be linked to Turkmenistan in a Central Asia Gas Pipeline project [53]. The790-mile pipeline would deliver up to 2 billion cubic feet per day of natural gas from southeastern Turkmenistan’s border to Multan, Pakistan, with a guarantee that up to 25 trillion cubic feet of gas could be supplied through the pipeline from the country’s Dauletabad field. The consortium of six companies and the Turkmenistan government are also considering adding a 400-mile extension to the pipeline, which would take gas to New Delhi, India, as well.

India is in the process of developing its import, transmission, and distribution grid to allow gas to penetrate major cities more rapidly. In an attempt to attract foreign investment in the natural gas sector, shares of the state-owned Gas Authority of India Limited (GAIL) were placed on the Bombay Stock Exchange in May 1997 [54]. GAIL was actually formed only 13 years ago. The company manages India’s only major gas pipeline, the HBJ, which is used to deliver gas from the Bombay High field and other offshore fields to the cities of Hazira, Bijaipu, and Jagdishpu, as well as other northwest Indian cities. Most of the gas moved by HBJ is used at large electric power plants and for fertilizer plants, but the government would like to increase residential and small commercial use.

In 1994, GAIL and the British BG plc (formerly British Gas) formed Mahanagar Gas, a distribution company that currently serves more than 3,000 domestic customers in Mumbai (formerly Bombay) [55]. BG plc is also working on bringing a 615-megawatt gas-fired power plant to Pipavav in Gujarat State that would burn imported LNG.

Royal Dutch Shell is attempting to bring LNG into India’s southern state, Tamil Nadu [56]. The company is working with Britain’s PowerGen to import Omani LNG for use in a 1.4-gigawatt power plant. Omani LNG should become available by 2000. Shell has also applied to India’s Industry Ministry for permission to construct an LNG and regasification terminal capable of handling 2.7 million tons of LNG per year [57]. The terminal would be constructed in Hazira, in the western state of Gujarat. Initially all gas would be used in industrial applications in Hazira, but it would be possible to expand the terminal to supply other customers after 2001.

China has plans to double its natural gas production capacity to 1.1 trillion cubic feet by 2005 according to China National Petroleum Corporation [58]. In the country’s Ninth Five-Year Plan period (1996-2000), China expects to increase gas exploration, with the goal of adding 3.9 trillion cubic feet to the current 41.4 trillion cubic feet of proven natural gas reserves [59]. In 1997, the Changqing Petroleum Prospecting Administration announced plans to move into full-scale exploration of the Erdos Basin gas field located at the intersection of the Shaanxi-Gansu-Shanxi provinces and Ningxi Hui, Inner Mongolia, autonomous regions [60]. Erdos Basin has 10.2 trillion cubic feet of proven natural gas reserves, with an annual capacity of nearly 30 billion cubic feet of gas. In June 1996, gas supplies began to move to Xi’an, the capital of northwest China’s Shaanxi Province, and in September 1996, to Beijing.

Arco, China National Offshore Oil Corporation (CNOOC), and Kuwait Foreign Petroleum Exploration Company are jointly developing the offshore, 3 trillion cubic foot Yacheng 13-1 gas field [61]. Most of the Yacheng gas is delivered to the Black Point Power Plant in Hong Kong by way of a 480-mile subsea pipeline. A second pipeline delivers gas to Hainan Island. Arco and CNOOC also signed an agreement to develop three Ledong gas fields in the South China Sea, which were discovered in 1996 by a subsidiary of CNOOC.

In 1997 there was some progress in bringing natural gasto China’s residential sector [62]. Gas from the Changqing gas field began supplying residential customers in Beijing in October 1997. A 533-mile gas pipeline from Jingbian County to Beijing was completed in July 1997 and is able to supply the city with 353 million cubic feet of gas per day.

In industrialized Asia, natural gas consumption is expected to increase by 50 percent over the next 25 years. For Japan, a 1.5-percent annual rate of increase is projected. Recent setbacks in Japan’s nuclear industry—including a series of accidents that have led to increasing public opposition to nuclear power (for example, the December 1995 sodium leak that caused the shutdown of the Monju reactor in Tsuruga, and the March 1997 fire at a nuclear waste handling facility in Tokaimura [63]— may result in faster-paced growth in gas-fired generation as a substitute for the extensive nuclear expansion anticipated by the Japanese nuclear industry only 2 years ago [64]. Currently there are 244 gas utilities in Japan, 71 of which are public utilities. They provided gas to 23.6 million customers in 1996, a 30-percent increase from 18.7 million gas customers in 1985 [65]. The country is already the largest importer of LNG in the world. In 1996, Japan imported 62 percent of the world’s 3,600 billion cubic feet of LNG exports [3, p.28].

The Asian currency crisis might also affect natural gas consumption in Japan. Developing Asian countries like Thailand are scaling back on plans to purchase LNG, and the resulting glut in LNG supplies means that Japan is in a position to negotiate deals for reduced prices [66]. In addition, Japan—along with South Korea and China—has shown interest in establishing a gas pipelineroute from Russia’s East Siberian Irkutsk region inKovtyktinskoye. A 2,170-mile pipeline from Kovtyktinskoye across China extending to the Yellow Sea with a subsea pipeline to Japan would cost an estimated $10 billion to construct [67].

The currency crisis has also affected plans to expand the LNG industry in Australia. There were plans to double the size of Woodside Petroleum’s North West Shelf LNG project, along with Chevron’s Gorgon offshore gas project in the North West Shelf Region, and the BHP Petroleum-Phillips Petroleum Bayu Undan joint venture in the Timor Sea [68]. However, the economic downturn in the region, which will make it more difficult to market the additional gas, might slow down these expansions.