International Energy Outlook 1999

Coal’s share of world energy consumption falls slightly in the IEO99 forecast. Coal continues to dominate many national fuel markets in developing Asia, but it is projected to lose market share to natural gas in some other areas of the world.

Historically, trends in coal consumption have varied considerably by region. Despite declines in some regions, world coal consumption has increased from 84 quadrillion British thermal units (Btu) in 1985 to 93 quadrillion Btu in 1996. Regions that have seen increases in coal consumption include the United States, Japan, and developing Asia. Declines have occurred in Western Europe, Eastern Europe, and the countries of the former Soviet Union. In Western Europe, coal consumption declined by 30 percent (on a Btu basis) between 1985 and 1996, displaced in considerable measure by growing use of natural gas and, in France, by nuclear power. The countries of Eastern Europe and former Soviet Union (EE/FSU) saw an even sharper decline in coal use during the period (a 39-percent decline), primarily the result of reduced economic activity.

Although coal has lost market share to petroleum products, natural gas, and nuclear power, it continues to be a key source of energy, especially for electric power generation. In 1996, coal accounted for 25 percent of the world’s primary energy consumption (down from 27 percent in 1985) and 38 percent of the energy consumed worldwide for electricity generation (Figure 43).

Sources: 1996: 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 (1999).

In the International Energy Outlook 1999 (IEO99) forecast, coal’s share of total energy consumption falls only slightly, from 25 percent in 1996 to 23 percent in 2020. Its historical share is nearly maintained, because large increases in energy use are projected for the developing countries of Asia, where coal continues to dominate many national fuel markets. Together, two of the key countries in the region, China and India (Figure 44), are projected to account for 33 percent of the world’s total increase in energy consumption over the forecast period and 90 percent of the world’s total increase in coal use (on a Btu basis).

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).

With the exception of China, coal for electricity generation will account for virtually all the projected growth in coal consumption worldwide. In the non-electricity sectors, other energy sources—primarily, natural gas and electricity—are expected to gain market share. In China, however, coal continues to be the primary fuel in a rapidly growing industrial sector, in view of the nation’s abundant coal reserves and limited access to alternative sources of energy. Consumption of coking coal is projected to decline slightly in most regions of the world as a result of technological advances in steelmaking, increasing output from electric arc furnaces, and continuing substitution of other materials for steel in end-use applications.

Because the Kyoto Protocol is not currently a legally binding agreement, the IEO99 projections do not reflect the commitments made by the signatory countries to reduce or moderate their emissions of greenhouse gases. If their commitments do become legally binding, however, it is likely that the coal outlook for the industrialized countries will differ substantially from the IEO99 projections (see discussion on "Impacts of the Kyoto Protocol on the U.S. and Japanese Energy Markets"). In IEO99, coal consumption in the industrialized countries is projected to increase by 12 percent over the forecast period, rising from 35.8 quadrillion Btu in 1996 to 40.0 quadrillion Btu in 2020.

The recent Asian financial crisis has a direct impact on the IEO99 projections. The crisis has led to a substantial devaluation of currencies in many of the countries of developing Asia, as well as in the industrialized countries that depend on export markets in the region. As a result, many projects to build coal-fired power plants in Asia have been delayed or canceled, and patterns of international coal trade have changed significantly.

In future years, coal will face tough challenges, particularly in the environmental area. Increased concern about the harmful environmental impacts associated with coal use has taken a toll on coal demand throughout industrialized areas. Coal combustion produces several air pollutants that adversely affect ground-level air quality.

One of the most significant pollutants from coal is sulfur dioxide, which has been linked to acid rain. Many of the industrialized countries have implemented policies or regulations to limit sulfur dioxide emissions. Such policies typically require electricity producers to switch to lower sulfur fuels or invest in technologies (primarily flue gas desulfurization (FGD) equipment) that reduce the amounts of sulfur dioxide emitted. China, the world’s largest emitter of sulfur dioxide, has been successful in reducing ambient sulfur dioxide levels in major urban areas in recent years but has been unable to restrain the growth of sulfur emissions overall (see discussion "China: Emissions of Sulfur Dioxide and Particulates").

A recent study completed by the International Energy Agency reported that most of the coal-fired capacity in Southeast Asian countries is not fitted with FGD equipment, primarily because of cost but also because most plants in the region currently use low-sulfur coal [4]. The study concludes that public concern over pollution in Southeast Asia is likely to increase as living standards rise, but at present the emphasis is on increasing electricity generation to satisfy demand and ensure economic growth.

In late 1998, approximately 5,000 villagers in southern Thailand staged a protest against plans for three new coal-fired power plants in the region [5]. Although the plants are being designed to burn imported low-sulfur coal, residents living nearby were under the impression that locally produced, high-sulfur lignite was to be used. Many people living in close proximity to the Mae Moe lignite-fired plant in northern Thailand have suffered serious respiratory problems attributed to high levels of sulfur dioxide emissions.

In addition to sulfur dioxide, increased restrictions on emissions of nitrogen oxides, particulates, and carbon dioxide are likely, especially in the industrialized countries. Although the potential magnitudes and costs of additional environmental restrictions for coal are uncertain, it seems likely that costs for coal-fired generation will increase. The costs of natural-gas-fired generation are not likely to be affected as much. For nuclear and hydropower, which compete with coal for baseload power generation, the future is unclear. Proposals have been put forth in several of the developed countries to phase out nuclear capacity in full or in large measure. In other countries, it has become difficult to site new capacity because of unfavorable public reaction. The siting of new large hydroelectric dams is also becoming more difficult because of increased environmental scrutiny. In addition, suitable sites for new large hydropower projects are limited.

By far the most significant emerging issue for coal is the potential for a binding international agreement to reduce emissions of carbon dioxide and other greenhouse gases. On a Btu basis, the combustion of coal produces more carbon dioxide than that of natural gas or of most petroleum products [11, Table B1]. Carbon dioxide emissions per unit of energy obtained from coal are nearly 80 percent higher than from natural gas and approximately 20 percent higher than from residual fuel oil—the petroleum product most widely used for electricity generation. In the IEO99 forecast, carbon emissions are projected to rise between 1990 and 2010 in many countries, including increases of 33 percent for the United States, 17 percent for Japan, and 9 percent for Western Europe (Figure 46). On the other hand, carbon emissions for the former Soviet Union are projected to be 33 percent lower in 2010, and emissions in Eastern Europe are projected to be 10 percent lower. Ratification of the Kyoto Protocol could have a substantial adverse impact on coal, particularly in the United States, which relies heavily on coal to meet its energy needs and faces relatively severe cutbacks in carbon emissions from those currently projected for 2010 (Figures 46 and 47).

Figure 46. Projected Cumulative Growth in World Carbon Emissions by Region, 1990-2010

Source: Energy Information Administration, World Energy Projection System (1999).

Sources: 1996: Energy Information Administration (EIA), Office of Energy Markets and End Use, International Energy Annual 1996, DOE/EIA-0219(96) (Washington, DC, February 1998). 2010: EIA, World Energy Projection System (1999).

In the IEO99 forecast, coal continues to be the second largest source of carbon emissions, accounting for 36 percent of the world total in 2020. Oil, at 39 percent in 2020, remains the largest source of carbon emissions, and natural gas accounts for almost all the remaining portion. By country, the world’s dominant coal consumers—the United States and China—were also the top two contributors to world carbon emissions in 1996, at 24 percent and 13 percent of the world total, respectively (Figure 48). By 2020, however, the U.S. share of world carbon emissions is projected to decline to 20 percent, while China’s share increases to 21 percent. The substantial increase in carbon emissions in China over the period is attributable to expectations of strong economic growth and the country’s continuing reliance on coal as its primary source of energy.

Sources: 1996: Energy Information Administration (EIA), Office of Energy Markets and End Use, International Energy Annual 1996, DOE/EIA-0219(96) (Washington, DC, February 1998). 2020: EIA, World Energy Projection System (1999).

Total recoverable reserves of coal around the world are estimated at 1,088 billion tons—enough to last another 210 years at current production levels (Figure 49).⁸ Although coal deposits are widely distributed, 60 percent of the world’s recoverable reserves are located in three regions: the United States (25 percent); FSU (23 percent); and China (12 percent). Another four countries—Australia, India, Germany, and South Africa— account for an additional 29 percent. In 1996, these seven regions accounted for 81 percent of total world coal production [12, Table 2.5].

Note: Data represent recoverable coal reserves as of January 1, 1997.
Source: Energy Information Administration (EIA), Office of Energy Markets and End Use, International Energy Annual 1997, DOE/EIA-0219(97) (Washington, DC, March 1999), Table 8.2.

Quality and geological characteristics of coal deposits are other important parameters for coal reserves. Coal is a much more heterogeneous source of energy than is oil or natural gas, and its quality varies significantly from one region to the next and even within an individual coal seam. For example, Australia, the United States, and Canada are endowed with substantial reserves of premium coals that can be used to manufacture coke. Together, these three countries supplied 85 percent of the coking coal traded worldwide in 1997 (see Table 15).

At the other end of the spectrum are reserves of low-Btu lignite or “brown coal.” Coal of this type is not traded to any significant extent in world markets, because of its relatively low heat content (which raises transportation costs on a Btu basis) and other problems related to transport and storage. In 1996, lignite accounted for 19 percent of total world coal production (on a tonnage basis) [12, Tables 2.5 and 5.4]. The top three producers were Germany (206 million tons), Russia (106 million tons), and the United States (88 million tons). As a group, these countries accounted for 41 percent of the world’s total lignite production in 1996. On a Btu basis, lignite deposits show considerable variation. Estimates by the International Energy Agency for coal produced in 1996 show that the average heat content of lignite from major producers in countries of the Organization for Economic Cooperation and Development (OECD) varied from a low of 4.3 million Btu per ton in Greece to a high of 12.3 million Btu per ton in Canada [13, pp. II.19-II.22].

The large increases in coal consumption projected for China and India are based on an outlook for strong economic growth (6.5 percent per year in China and 5.1 percent per year in India) and the expectation that much of the increased demand for energy will be met by coal, particularly in the industrial and electricity sectors (Figure 50). The IEO99 forecast assumes no significant changes in environmental policies in the two countries. It also assumes that necessary investments in the countries’ mines, transportation, industrial facilities, and power plants will be made.

Sources: 1980 and 1996: 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). 2020: EIA, World Energy Projection System (1999).

Coal remains the primary source of energy in China’s industrial sector, primarily because China has limited reserves of oil and natural gas. In the non-electricity sectors, most of the increase in oil use comes from rising demand for energy for transportation. Growth in the consumption of natural gas comes primarily from increased use for space heating in the residential and commercial sectors. A substantial portion of the increase in China’s demand for both natural gas and oil is projected to be satisfied by imports.

In the electricity sector in China, coal use is projected to grow by 4.0 percent a year, from 8.9 quadrillion Btu in 1996 to 22.9 quadrillion Btu in 2020. In comparison, coal consumption by electricity generators in the United States is projected to rise by 1.1 percent annually, from 18.0 quadrillion Btu in 1996 to 23.5 quadrillion Btu in 2020. One of the key implications of the substantial rise in electricity coal demand in China is that large financial investments in new coal-fired power plants and in the associated transmission and distribution systems will be needed. The projected growth in coal demand implies that China will need approximately 375 gigawatts of coal-fired capacity in 2020.⁹ In 1996, China had approximately 154 gigawatts of fossil-fuel-fired (coal, oil, and gas) generating capacity [12, Table 6.4].

In China, 62 percent of the total increase in coal demand is projected to occur in the non-electricity sectors, for steam and direct heat for industrial applications (primarily in the chemical, cement, and pulp and paper industries) and for the manufacture of coal coke for input to the steelmaking process. Strong growth in steel demand is expected in China as infrastructure and capital equipment markets expand.

In India, projected growth in coal demand occurs primarily in the electricity sector. Between 1996 and 2020, coal use for electricity generation in India is projected to rise by 3.0 percent per year, from 4.4 quadrillion Btu in 1996 to 8.9 quadrillion Btu in 2020. This growth implies that India will need approximately 130 gigawatts of coal-fired capacity in 2020.¹⁰ In 1996, India’s total fossil-fuel-fired generating capacity amounted to 70 gigawatts [12, Table 6.4].

In the remaining areas of developing Asia, a substantial rise in coal consumption is expected over the forecast period, based on projected strong growth in coal-fired electricity generation in South Korea, Taiwan, and the member countries of the Association of Southeast Asian Nations (primarily Indonesia, Malaysia, the Philippines, Thailand, and Vietnam). In the electricity sector, coal use in the other developing countries of Asia (including South Korea) is projected to rise by 3.7 percent per year, from 2.4 quadrillion Btu in 1996 to 5.7 quadrillion Btu in 2020.

With the exception of South Korea, electric utilities in the countries of developing Asia are expected to add little in the way of new coal-fired generating capacity over the forecast period [14]. Rather, most of the new coal-fired plants are to be built by independent power producers (IPPs). While much of the planned new IPP capacity was seen as a relatively sure bet a couple of years ago, the recent financial crisis has caused delays and cancellations of many of the projects planned or under construction [15].

The primary problems affecting IPP projects in the region relate to the sharp devaluation of currencies and the current economic crisis, which has caused a slowdown in the growth of both economic output and energy demand. Currency devaluations in the region have proved to be problematic for IPP projects primarily because of pressure being placed on them to accept lower prices for their electricity than were originally agreed to in their long-term contracts with electricity distributors (typically national utilities) [16, 17, 18, 19]. Because most of the costs of IPP projects in the region are based in U.S. dollars, the acceptance of lower prices by project owners would mean lower or negative returns on project investments. On the other hand, the electricity distributors are not in a position to raise rates to end-use consumers of electricity, because national governments in the region typically have control over end-use prices and are unwilling to grant requests for increases, given the current economic crisis. Reduced expectations for future growth in electricity demand also mean that less new generating capacity will be needed than previously expected, delaying or eliminating the need for some of the planned IPP projects.

The profitability of the power plants owned and operated by state-owned utilities in the region also has been adversely affected, because capital, operating, and maintenance costs incurred by the utilities have generally risen by substantial amounts since the onset of the regional economic crisis. Three main factors contribute to the cost increases: (1) payments for imported fuels usually are denominated in U.S. dollars and, thus, have increased with recent devaluations in Asian currencies; (2) equipment, much of which is imported, is denominated in U.S. dollars; and (3) interest payments have increased because of a recent downgrading of bonds issued by utilities in the region.

In Japan, coal consumption is projected to increase at a much slower pace than in the other countries of Asia. In the electricity sector, coal use is projected to rise at a rate of only 1.1 percent per year, from 1.4 quadrillion Btu in 1996 to 1.8 quadrillion Btu in 2020. The projected increase implies that Japan will need to build less than 10 gigawatts of new coal-fired generating capacity between 1996 and 2020. This is substantially different from the most recent outlook provided by Japan’s Ministry of International Trade and Industry, which projects the need for 24 gigawatts of new coal-fired capacity between 1997 and 2008 [20]. The IEO99 projections show slightly slower growth in Japan’s overall electricity demand and stronger growth in natural-gas-fired electricity generation.

In Western Europe, environmental concerns play an important role in the competition among coal, natural gas, and nuclear power. Recently, other fuels—particularly natural gas—have been gaining an increasing economic advantage over coal. Coal consumption in Western Europe has declined by 35 percent over the past 7 years, falling from 927 million tons in 1989 to 600 million tons in 1996. The decline was slightly smaller on a Btu basis, at 28 percent, reflecting the fact that much of the decline was accounted for by reduced consumption of low-Btu lignite in Germany. The decline in coal consumption is expected to continue over the forecast period, but at a slower rate.

Between 1989 and 1996, German lignite production declined by 247 million tons [12, Table 5.4]. The sharp decline in German lignite production followed the conversion from lignite-based town gas¹¹ to natural gas in the eastern states of Germany after reunification in 1990, as well as substitution of natural gas and other fuels for lignite in home heating [13, p. II.201; 21]. A second factor was the collapse of industrial output in the eastern states. Reduced economic activity in eastern Germany contributed to an 8.5-percent decline in total energy consumption in Germany between 1988 and 1994. In the IEO99 forecast, further declines in lignite production in Germany are projected to be small in view of the competitiveness of German lignite with other imported fuels and planned investments to refurbish or replace existing lignite-fired plants using best available combustion and pollution control technologies. A new 900-megawatt lignite plant to be built in the Rheinland area of Germany is expected to be the most up-to-date lignite-based power station in the world when it is completed in 2002, boasting a 43-percent conversion efficiency [13, p. I.189].

The recent trend in the consumption of hard coal in Western Europe is closely correlated with the trend in the production of hard coal.¹² Following the closure of the last remaining coal mines in Belgium in 1992 and Portugal in 1994, only four member States of the European Union—the United Kingdom, Germany, Spain, and France—continue to produce hard coal [22]. Since 1989, all four of these countries have seen their output of hard coal decline. In Germany, Spain, and France, recent agreements between the governments, mining companies, and labor unions on future coal production subsidies indicate that further declines in output are forthcoming. In the United Kingdom, production subsidies have been phased out, forcing coal producers into direct competition with North Sea gas and international coal.

In the United Kingdom, hard coal production declined from 111 million tons in 1989 to 56 million tons in 1996 [12, Tables 5.2 and 5.3]. Most of the decline resulted from privatization in the electricity sector, which led to a rapid increase in gas-fired generation at the expense of coal [13, Table 3.3; 23, Table 3.3]. Substantial improvements have been made in the country’s mining operations in recent years, with average labor productivity rising from less than 1,000 tons per miner-year in 1989 to 2,600 tons per miner-year in 1996 [13, Table 6.5a].

Despite productivity improvements and domestic production costs that are approaching parity with imported coal, British coal producers continue to face an uncertain future [24, p. 33]. Many coal contracts between producers and utilities negotiated before the privatization of the coal industry in 1994 expired at the end of March 1998 [22, p. 21; 24]. In late 1997, initial negotiations on the renewal of the contracts indicated a strong preference among British utilities to switch from coal to natural gas. The potential negative impacts on the British coal industry and mining jobs prompted the issuance of a temporary moratorium on the construction of new gas-fired generating plants by the British government [25, 26]. In addition, Britain’s energy minister requested an analysis of the nation’s power industry to evaluate how the issues of fuel diversity and security of supply should be considered in the approval process for new power projects. In 1996, electricity producers in the United Kingdom consumed 60 million tons of coal, representing 77 percent of the country’s total coal consumption [27].

The study—the Energy Review White Paper—was completed by the United Kingdom’s Department of Trade and Industry in October 1998 [24]. The report considered issues related not only to the diversity and security of energy supply but also to the design, operation, and structure of the electricity market. One of the key findings of the review was compelling evidence that distortions in the country’s wholesale electricity market (the electricity pool) are encouraging the displacement of generation from existing plants with generation from new gas-fired plants. The distortions were attributed to several factors, including the following: (1) the bidding process for the wholesale market allows small generators (e.g., new gas-fired plants) to bid a low price for their generation, thus assuring that their plants will be fully dispatched while receiving the price submitted by the highest bidder (typically large generators with coal-fired capacity) for each time period during the day; and (2) inadequate competition, particularly in the coal-fired generation sector, has led to prices in the wholesale market that are higher than necessary. In response to the study’s findings, the British government has initiated a program of reforms in the electricity market intended to create a more competitive environment—one in which existing coal-fired capacity will be able to compete more effectively with generation from new gas-fired plants.

Coal subsidies continue to support high-cost production of hard coal in Germany, Spain,¹³ and France. For 1996, the European Commission authorized coal industry subsidies of $6,947 million in Germany, $1,116 million in Spain, and $863 million in France [22, pp. 34-36].¹⁴ In each country, the average subsidy per ton of coal produced exceeds the average value of imported coal (Table 14), and all three are currently taking steps to reduce subsidy payments, acknowledging that some losses in coal production are inevitable.

Germany’s hard coal production, which is highly subsidized, declined from 88 million tons in 1989 to 58 million tons in 1996 [12, Tables 5.2 and 5.3]. In March 1997, the federal government, the mining industry, and the unions reached an agreement on the future structure of subsidies to the German hard coal industry. Subsidies to the industry are to be reduced from DM10.5 billion in 1996 to DM5.5 billion by 2005, resulting in an estimated decline in production to 33 million tons [13, pp. I.193-I.194]. The agreement calls for the closure of 8 to 9 of Germany’s 19 hard coal mines, resulting in an estimated decline in employment from 55,000 miners in 1996 to about 36,000 in 2005. In the IEO99 reference case, increased imports of coal are expected to compensate for a portion of the expected decline in output from indigenous mines.

In Spain, hard coal production declined from 29 million tons in 1989 to 20 million tons in 1996 [12, Tables 5.2 and 5.3]. In 1997, an agreement reached between the government, labor unions, and the electricity sector allows subsidized coal production to continue in Spain through 2005, with output set to decline gradually to 15 million tons per year [13, pp. I.195-I.196]. In the electricity sector, the share of domestic coal that must be used in power generation will be reduced from the current level of about 40 percent to 15 percent. Spain’s coal mine labor force will be reduced from 24,000 in 1996 to approximately 18,000 by 2005 through retirement and voluntary separations.

In France, production of hard coal declined from 14 million tons in 1989 to 8 million tons in 1996 [12, Tables 5.2 and 5.3]. A modernization, rationalization, and restructuring plan submitted by the French government to the European Commission at the end of 1994 foresees the closure of all coal mines in France by 2005 [22, p. 36]. The coal industry restructuring plan was based on a “Coal Agreement” reached between France’s state-run coal company, Charbonnages de France, and the coal trade unions. Over the forecast period, consumption of hard coal in Spain and France is expected to decline roughly in accordance with the reductions in indigenous coal production, as other fuels—primarily natural gas, nuclear, and renewable energy—are expected to compensate for most of the reduction in domestic coal supply.

Coal use in other major coal-consuming countries in Western Europe is projected either to decline or to remain close to current levels. In the Scandinavian countries (Denmark, Finland, Norway, and Sweden), environmental concerns and competition from natural gas are expected to reduce coal use there over the forecast period. The government of Denmark has stated that its goal is to reduce the amount of coal use in the country’s energy mix to 2 percent by 2030 [28]. In 1996, coal accounted for 39 percent of the country’s total primary energy supply [13, p. II.172].

Italy’s coal consumption is projected to remain relatively constant in the IEO99 forecast. Factors in favor of increased coal use in Italy include: (1) a National Energy Plan which states that coal is underutilized in the country’s energy mix; and (2) recent capital investments (environmental and coal-handling equipment) at two of the country’s multifuel-fired generating plants so as to better accommodate the use of coal [13, p. III.125; 27, sec. 11.8]. On the other hand, Italy has a strong environmental lobby and a strong oil and gas lobby, and current and planned investments in gas pipeline infrastructure promise to increase the supply of natural gas to Italy substantially over the forecast period [27, sec. 11.8; 29].

Partly offsetting the declines in coal consumption elsewhere in Europe is a projected increase in consumption of indigenous lignite for electricity generation in Greece. Under an agreement reached by the countries of the European Union in June 1998, Greece committed to capping its emissions of greenhouse gases by 2010 at 25 percent above their 1990 level [30]—much less severe than the emissions target for the European Union as a whole, which must reduce its emissions to 8 percent below those in 1990 by 2010 [31].

In the EE/FSU countries, the process of economic reform continues as the transition to a market-oriented economy replaces centrally planned economic systems. The dislocations associated with institutional changes in the region have contributed substantially to declines in both coal production and consumption. Coal consumption in the EE/FSU region has fallen by 562 million tons since 1988, reaching 885 million tons in 1996 [12, Table 1.4]. In the future, total energy consumption in the EE/FSU is expected to rise, primarily as the result of increasing production and consumption of natural gas. In the forecast, coal’s share of total EE/FSU energy consumption declines from 25 percent in 1996 to 13 percent in 2020, and the natural gas share increases from 41 percent in 1996 to 55 percent in 2020.

The three main coal-producing countries of the FSU—Russia, the Ukraine, and Kazakhstan—are facing similar problems. All three countries have developed national programs for restructuring and privatizing their coal industries, but they have been struggling with related technical and social problems. Of the three, Kazakhstan has shown the most rapid progress, as many of the country’s mines have been purchased and are now operated by international energy companies [32].

In Russia and the Ukraine, efforts have been aimed primarily at shutting down inefficient mines and transferring associated support activities—such as housing, kindergartens, and health and recreation facilities—to local municipalities. The closure of inefficient mines in both countries has been slow, however, leading to delays in the scheduled disbursement of money, via loans, from the World Bank. In both countries, coal-mining regions continue to wield considerable political clout, putting pressure on the leadership via strikes and their ability to influence election results [33, 34]. In late 1998, Prime Minister Yevgeniy Primakov announced that privatization procedures in Russia’s coal industry should be suspended [35]. He indicated that “public stability [in the country] depends on the situation in the coal industry,” and that privatization efforts have not led to the expected improvements in productivity. To date, the World Bank has provided $900 million in loan assistance to the Russian coal industry and $150 million to the Ukraine [34, 36, 37, 38]. The Bank plans to disburse an additional $400 million and $150 million to the Russian and Ukrainian coal industries, respectively, when specific conditions of progress are met.

The transfer of support activities from mining associations to local municipalities has also been problematic. Most of the planned transfers in Russia and the Ukraine have already occurred, but the municipalities do not have sufficient funding [39]. Thus, the quality of health care and other services in mining communities has deteriorated considerably. Even efficient mines in Russia and the Ukraine are not without problems. Payment arrears of large customers have been making it nearly impossible for mines to pay workers and purchase needed mining supplies and equipment [40].

Poland is the key coal producer and consumer in Eastern Europe. In 1996, coal consumption in Poland totaled 179 million tons, 43 percent of Eastern Europe’s total coal consumption for the year [12, Table 1.4]. Poland’s hard coal industry produced 150 million tons in 1996, and lignite producers contributed an additional 69 million tons [12, Tables 5.2, 5.3, and 5.4]. In other Eastern European countries, coal consumption is dominated by the use of low-Btu subbituminous coal and lignite produced from local reserves. In 1996, the region’s other important coal-consuming countries were the Czech Republic (17 percent of the region’s total coal use), Romania (12 percent), Serbia (10 percent), Bulgaria (8 percent), and Hungary (5 percent). Eastern Europe relies heavily on local production, with seaborne imports of coal to the region totaling only 6 million tons in 1997 [41].

At present, Poland’s hard coal industry is operating at a loss [42]. Over the past several years, a number of coal industry restructuring plans have been put forth for the purpose of transforming Poland’s hard coal industry to a position of positive earnings, eliminating the need for government subsidies. The most recent plan was announced by Poland’s Ministry of the Economy in April 1998. It calls for the closure of 24 of the country’s 50 unprofitable mines over the next 4 years, reducing the total number of mines in Poland from 65 in 1998 to 41 by 2002. In addition, the restructuring plan aims to reduce the number of miners by nearly one-half, from 245,000 in 1998 to 138,000 by 2002 [43]. The government hopes to achieve most of the planned reduction in force through normal retirements and voluntary separations. All miners leaving the industry before retirement age (either voluntarily or involuntarily) under the restructuring program will receive financial compensation packages and assistance in either moving to a new job or establishing a business.

The Polish government projects that sales of hard coal from domestic mines will decline from 100 million tons in 1998 to 88 million tons by 2010 and to 77 million tons by 2020. The World Bank has indicated its willingness to loan the Polish government up to $1 billion over a 3-year period to help cover the costs of the restructuring program, including economic assistance for miners leaving the industry [44]. The program assumes full liberalization of coal pricing and complete liberalization of trade in coal by the year 2000.

In North America, coal consumption is concentrated in the United States, which, at 983 million tons, accounted for 93 percent of the regional total in 1996. By 2020, U.S. coal consumption is projected to rise to 1,275 million tons. With its substantial supplies of coal reserves, the United States has come to rely heavily on coal for electricity generation and continues to do so over the forecast. Coal provided 52 percent of total U.S. electricity generation in 1996 and is projected to provide 49 percent in 2020 [45]. To a large extent, EIA’s projections of declines in both minemouth coal prices and coal transportation rates are the basis for the expectation that coal will continue to compete as a fuel for U.S. power generation. In Canada and Mexico (the other countries of North America), coal consumption is projected to rise from 74 million tons in 1996 to 92 million tons in 2020.

Canada’s increased use of coal in the IEO99 forecast results primarily from the expected retirement of some of the country’s older nuclear units after 2010, and the subsequent need to replace that generation [46]. Between 2010 and 2020, Canada’s nuclear generation is projected to decline by 22 percent. In addition, a temporary decrease in Canada’s nuclear generation results in some increase in coal consumption early in the forecast. During the summer of 1997, Ontario Hydro shut down 7 of its 19 nuclear reactors for major overhauls after the discovery of widespread safety and performance problems [47]. Of the 7 units shut down, 4 are located at the utility’s Pickering station and 3 at its Bruce station [48, pp. 3-4]. Their combined capacity is 3.6 gigawatts.

As in other parts of the world, natural gas is expected to be the fuel of choice for most new generating capacity in Mexico. In 1996, Mexico consumed 14 million tons of coal. Two coal-fired generating plants, operated by the state-owned utility Comision Federal de Electricidad (CFE), consume approximately 10 million tons of coal annually [49], most of which originates from domestic mines.

Currently, CFE has plans to switch its dual-fired Petacalco plant, located on Mexico’s Pacific coast, from oil to coal [50]. The plant has burned fuel oil since its startup in 1995, but CFE wants to switch most, if not all, of the plant’s six generating units to coal by sometime in 1999. The utility estimates that the 2.1-gigawatt plant will require more than 5 million tons of imported coal annually. A coal import facility adjacent to the plant, with an annual throughput capacity of more than 9 million tons, will serve both the power plant and a nearby integrated steel mill [51].

In Africa, coal production and consumption are concentrated almost entirely in South Africa. In 1996, South Africa produced 227 million tons of coal, 71 percent of which was routed to domestic markets and the remainder to exports [12, Table 2.5]. South Africa ranks third in the world in coal exports, behind Australia and the United States, and is projected to maintain that position over the forecast. South Africa holds the distinction of being the world’s largest producer of coal-based synthetic liquid fuels. In 1996, almost one-fifth of the coal consumed in South Africa (on a Btu basis) was used to produce coal-based synthetic oil, which in turn accounted for more than one-fourth of all liquid fuels consumed in South Africa during the year [13, 52].

For Africa as a whole, coal consumption is projected to increase by 48 million tons between 1996 and 2020, primarily to meet increased demand for electricity. Contributing to the increase in electricity demand is South Africa’s commitment to an aggressive electrification program, which aims to increase the percentage of households connected to the electricity grid from 44 percent at the end of 1995 to 75 percent by 2000 [52, 53]. There are also substantial opportunities for trade in electricity and natural gas between South Africa and neighboring countries. New power transmission lines have been completed or are planned to facilitate flows of electricity between South Africa, Mozambique, Zimbabwe, Swaziland, and Namibia [52]. Such international connections could open new markets for underutilized or idle coal-fired power plants in South Africa.

Elsewhere in Africa, the completion of four additional coal-fired units at Morocco’s Jorf Lasfar plant near Casablanca should increase coal consumption there from about 2 million tons in 1996 to more than 5 million tons [54, 55]. When all units are completed, the plant is expected to account for approximately one-third of Morocco’s total power generation.

Coal has not been an important source of energy in Central and South America, accounting for less than 6 percent of the region’s total energy consumption since 1970. In the electricity sector, hydroelectric power currently meets much of the region’s electricity demand. Over the forecast period, both hydropower and natural gas are projected to fuel much of the projected increase in electricity generation.

In 1996, Brazil accounted for 67 percent of South America’s total coal demand (on a Btu basis), with Colombia, Chile, and Argentina accounting for much of the remaining portion. In Brazil, the steel industry accounts for almost two-thirds of the country’s total coal consumption, relying on imports of coking coal to produce coke for use in its blast furnaces [13, p. III.13]. In the forecast, increased use of coal for steelmaking (both coking coal and coal for pulverized coal injection) accounts for much of the projected increase in Brazil’s coal consumption [56]. New power projects in Colombia and Brazil account for most of the remaining growth in coal consumption projected for South America [57].

In Central America, petroleum products and hydropower are the key sources of primary energy consumption (accounting for 70 and 24 percent of the total, respectively, in 1996) [58]. The only coal consumption in the region is a small quantity used in Panama for industrial purposes [56, p. 65]. Coal use in the region is set to increase somewhat, however, with the completion of a 120-megawatt coal-fired generating plant in Guatemala in 1999 [59, 60]. The plant, being built by a consortium of U.S. and Guatemalan companies, will be the first coal-fired power plant in Central America.

Turkey accounts for most of the coal consumed in the Middle East. In 1996, a total of 72 million tons of coal was consumed in Turkey, most of it low-Btu, locally produced lignite (approximately 7.3 million Btu per ton) [12, Tables 2.5 and 5.4; 13, p. II.21]. Over the forecast period, Turkey’s coal consumption (both lignite and hard coal) increases by 22 million tons, primarily to fuel additional coal-fired generating capacity.

Israel and Iran accounted for most of the remaining 8 million tons of coal consumed in the Middle East in 1996 [12, Table 1.4]. Over the forecast, Israel’s coal consumption is projected to rise by approximately 5 million tons with the completion of two new coal-fired generating plants between 1999 and 2005 [13, pp. III.125 and III.133; 61]. Israel’s state-owned utility, Israel Electric Corporation, estimates that coal-fired plants will meet approximately 60 percent of the country’s electricity needs in the post-2000 period [62]. In Iran, approximately 1 million tons of coal consumption has been met historically by indigenous suppliers [12, Table 2.5]. In addition, Iran’s National Steel Corporation imports approximately 0.5 million tons of coking coal annually [63, 64].

The amount of coal traded in international markets is small in comparison with total world consumption. In 1997, world imports of coal amounted to 530 million tons (Table 15 and Figure 51), representing 10 percent of total consumption. By 2020, coal imports are projected to rise to 659 million tons, accounting for a 9-percent share of world coal consumption. Although coal trade has made up a relatively constant share of world coal consumption over time and should continue to do so in future years, the geographical composition of trade is shifting.

Sources: 1985: Energy Information Administration (EIA), Annual Prospects for World Coal Trade 1987, DOE/EIA- 0363(87) (Washington, DC, May 1987). 1997: International Energy Agency, Coal Information 1997 (Paris, France, September 1998); Financial Times Energy Press, International Coal Report, Coal Year 1998 (London, UK, May 1998); and EIA, Quarterly Coal Report, October-December 1997, DOE/ EIA-0121(97/4Q) (Washington, DC, May 1998). 2020: EIA, National Energy Modeling System, run IEO99.D012099B.

In recent years, international coal trade has been characterized by relatively stable demand for coal imports in Western Europe and expanding demand in Asia (Figure 52). Rising production costs in the indigenous coal industries in Western Europe, combined with continuing pressure to reduce industry subsidies, have led to substantial declines in production there, creating the potential for significant increases in coal imports; however, slow economic growth in recent years and increased electricity generation from natural gas, nuclear, and hydropower have curtailed the growth in coal imports. Conversely, growth in coal demand in Japan, South Korea, and Taiwan in recent years has contributed to a substantial rise in Asian coal imports.

*Data for Asia exclude China, India, and Australasia.
Note: Production and imports include data for anthracite, bituminous, and subbituminous coal.
Sources: Energy Information Administration, Office of Energy Markets and End Use, International Statistics Database.

The recent worldwide financial crisis has introduced some changes and uncertainties in international coal markets, affecting trade patterns and prices from late 1997 to the present. In international markets, coal prices are negotiated in U.S. dollars. Thus, as a result of recent currency devaluations against the dollar, coal producers in countries such as Australia and South Africa have been able to lower their export prices substantially while continuing to receive the same or higher prices in local currencies [19, 48, 65].¹⁵ Their coal sales have consequently increased, primarily at the expense of other exporting countries, and lower prices have been paid by coal importers. At present, it is not clear how long the current problems in financial markets will persist. Clearly, a reversal in the Australian and South African currencies from the current downward trend would lead to an increase in coal export prices.

Despite recent setbacks, Asia’s demand for imported coal remains poised for additional increases over the forecast period, based on strong growth in electricity demand in the region and the need for additional coal-fired generating capacity. Continuing the recent historical trend, Japan, South Korea, and Taiwan are projected to account for much of the regional growth in coal imports over the forecast period.

Japan continues to be the world’s leading importer of coal and is projected to account for 27 percent of total world imports in 2020 [67], the same share as in 1997 [13, Table 4.2]. In 1997, Japan produced 5 million tons of coal for domestic consumption and imported 143 million tons. The closure of Japan’s Miike mine in March 1997 leaves the country with only about 3.5 million tons of production capacity at two remaining coal mines [68]. Production at those mines is expected to end when the government eliminates industry subsidies in 2001, leaving all of Japan’s coal requirements to be met by imports [13, p. I.180; 69].

As the leading importer of coal, Japan has been influential in the international coal market. Historically, contract negotiations between Japan’s steel mills and coking coal suppliers in Australia and Canada established a benchmark price for coal that was used later in the year as the basis for setting contract prices for steam coal used at Japanese utilities [70]. Other Asian markets also tended to follow the Japanese price in settling contracts.

Japan’s influence, however, has declined somewhat over the past several years, and the benchmark pricing system that was so influential in setting contract prices was abandoned by Japan’s steel mills in 1996. What seems to be occurring in the Asian coal markets is a shift away from contract purchases to the spot market. Liberalization of the Japanese electricity market is placing increased cost-cutting pressure on utilities, making them less inclined to accept some benchmark price negotiated by any of the other individual utilities. The shift to more competitive coal markets in Asia implies that coal producers in Australia and other exporting countries will be under increased pressure to reduce mining costs in order to maintain current rates of return. It also means that less competitive suppliers, such as the United States, will find it difficult to increase or maintain coal export sales to the region.

China and India, which import relatively small quantities of coal at present, are expected to account for much of the remaining increase in Asian imports. Imports by China and India have the potential to be even higher than the projected amount, but it is assumed in the forecast that domestic coal will be given first priority in meeting the large projected increase (2.3 billion tons) in coal demand.

During the 1980s, Australia became the leading coal exporter in the world, primarily by meeting increased demand for steam coal in Asia. Some growth in exports of coking coal also occurred, however, as countries such as Japan began using some of Australia’s semi-soft or weak coking coals in their coke oven blends. As a result, imports of hard coking coals from other countries, including the United States, were displaced. Australia’s share of total world coal trade, which increased from 17 percent in 1980 to 33 percent in 1997, is projected to reach 38 percent in 2020 [71]. Australia should continue as the major exporter to Asia, continuing to meet approximately one-half of the region’s total coal import demand.

Coal imports to Europe are projected to decline slightly over the forecast period. Most of the decline occurs in the countries of Western Europe, where strong environmental lobbies and competition from natural gas are expected gradually to reduce the reliance on coal for electricity generation. Coking coal consumption in Western Europe is also expected to decline over the forecast period. Improvements in the steelmaking process will continue to reduce the amount of coal required for steel production, and strict environmental standards are expected to result in the closure of some of the region’s older coke batteries.

With the exception of Germany, coal imports to Western Europe are not expected to increase to compensate for reductions in indigenous coal production. Rather, increased use of natural gas, renewable energy, and nuclear power (primarily in France) is expected to fill the gap in energy supply left by the continuing declines in the region’s indigenous coal production. Declines in coal imports by Western European countries in the IEO99 forecast are partially offset by small increases projected for Turkey, Romania, Morocco, Israel, and Croatia.

In 1997, the leading suppliers of imported coal to Europe were the United States (24 percent), South Africa (21 percent), and South America (15 percent). Over the forecast period, low-cost coal from South America is projected to meet an increasing share of European coal import demand, displacing some coal from such higher cost suppliers as the United States and Poland.

Compared with European and Asian coal markets, imports of coal to North and South America are relatively small, amounting to only 50 million tons in 1997 (Table 15). Brazil imported 34 percent of the 1997 total, followed by Canada (30 percent) and the United States (15 percent) [13, p. I.128]. Almost all (91 percent) of the imports to Brazil were coking coal [13, p. III.13].

Over the forecast period, coal imports to the Americas increase by 13 million tons, with most of the additional tonnage going to Brazil and Mexico, both of which are expected to import additional amounts of coal for use at integrated steel plants [56, 72, 73]. Coal imports to the Brazilian steel industry are projected to rise substantially as the result of strong growth in domestic steel demand and a continuing switch from charcoal to coal coke. In addition to coking coal, Mexico is projected to import additional quantities of steam coal for electricity generation. Additional imports of coal to the Americas are projected to be met primarily by producers in Colombia, Venezuela, and Australia.

Historically, coking coal has dominated world coal trade, but its share has steadily declined, from 55 percent in 1980 to 40 percent in 1997 [74]. In the forecast, its share of world coal trade continues to shrink, falling to 34 percent by 2020. In absolute terms, despite a projected decline in imports by the industrialized countries, total world coking coal trade is projected to show a slight increase over the forecast period as the result of increased demand for steel in the developing countries. Increased imports of coking coal are projected for South Korea, Taiwan, India, Brazil, and Mexico, where expansions in blast-furnace-based steel production are expected.

Factors that contribute to the decline in coking coal imports in the industrialized countries are continuing increases in steel production from electric arc furnaces (which do not use coal coke as an input) and technological improvements at blast furnaces, including greater use of pulverized coal injection equipment and higher average injection rates per ton of hot metal produced. One ton of pulverized coal (categorized as steam coal) used in steel production displaces approximately 1.4 tons of coking coal [75, 76]. In 1996, the direct use of pulverized coal at blast furnaces accounted for 13 percent of the coal consumed for steelmaking in Japan and the European Union [13, Tables 3.9 and 3.10; 27].