International Energy Outlook 1999

Electricity continues to be the most rapidly growing form of energy consumption in the IEO99 projections. The strongest long-term growth in electricity consumption is projected for the developing countries of Asia.

Long-term growth in electricity consumption is expected to be strongest in the developing economies of Asia, followed by Central and South America (Figure 64). In the reference case for the International Energy Outlook 1999 (IEO99), the projected growth rates for electricity consumption in the developing Asian nations average nearly 5 percent per year from 1996 to 2020 (Table 17). Electricity consumption growth in Central and South America is projected to exceed 4 percent between 1996 and 2020. The projected increases in electricity use are based on expectations of rapid population and economic growth, greater industrialization, and more widespread household electrification. Developing nations are expected to account for 43 percent of the world’s total electricity consumption in 2020, compared with only 28 percent in 1996. With much of the world population today still having only limited access to electricity, a significant portion of the future growth in electricity use will result from the connection of more of the population to the electricity grid.

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

In future years, electricity will continue to be the most rapidly growing form of energy consumption, rising from 12 trillion kilowatthours in 1996 to almost 22 trillion kilowatthours in 2020 in the IEO99 reference case. Although demand for electricity, like other forms of energy, has been affected by recent global economic and financial problems, an economic turnaround is expected in a year or two, accompanied by a resumption of earlier trends in demand growth.

Collapsing financial markets and falling currencies can affect energy demand in several ways. For countries that are net importers of energy, a debased currency means that more of the currency must be expended on energy imports, as well as on other goods and services. If a country’s financial markets fail, economic growth and energy demand growth may be slowed as investments in development projects (including energy projects) become more risky and capital formation becomes more difficult. Corrective measures, such as raising domestic interest rates in order to restore stability to currency values and financial markets, may at the same time reduce economic growth, slow the growth of long-term investment, and depress aggregate energy demand.

The countries most immediately affected by the economic crisis that originated in Asia in mid-1997— Thailand, Malaysia, South Korea, Indonesia, and the Philippines—have undertaken various economic policies to restore economic growth, and there have been some positive signs that their economies are beginning to turn around. China and India have also been affected by the crisis, although not nearly as much. The IEO99 projections of electricity demand growth for these regions are substantially lower than last year’s projections out to the year 2000, but less so out to 2005 and hardly at all for 2020.

Annual growth in electricity consumption for the industrialized economies is expected to average 1.6 percent between 1996 and 2020, with continuing penetration of electric equipment in the end-use sectors counterbalanced by slowing population growth and higher energy efficiencies. Economic growth in the industrial economies has also been affected by the Asian crisis, largely through a slowdown in exports to Asian markets. In 1998, as a result of growing concerns that Asian economic problems had begun to affect the industrial world, several central banks reduced interest rates and eased monetary policies.

Japan, the largest economy in Asia and second largest in the world, continues to be a significant source of uncertainty. Its real GDP fell by 2.9 percent in 1998, according to WEFA Energy [1]. The Japanese government has, however, undertaken a $500 billion spending initiative aimed at reviving the economy. The Japanese central government’s expansionary fiscal policies in the past have generally proven inadequate to the task of restoring economic growth, and little improvement is expected for Japan’s economy in the near term.

In Russia, economic developments have grown more discouraging. Although difficulties in the Russian economy were heightened by events in Asia, the Russian government’s persistent inability to undertake meaningful—and much needed—domestic economic reform continues to be the main roadblock to economic recovery. A moratorium on servicing government debt and the Russian government’s recent plan to make good on payments on past-due salaries and pensions through printing money suggest that the Russian economy is likely to worsen further before getting better.

Downward pressure on financial markets and currencies in Central and South America was another fallout of the Asian economic crisis; however, not all of the region’s current economic problems can be attributed to events in Asia. Brazil, for instance, has found itself in need of a $42 billion credit from the International Monetary Fund, largely because of its huge government budget deficit [2]. The credit was needed both to keep the Brazilian financial system solvent and to stem a run on the Brazilian currency.

For the developing nations of Africa and the Middle East, both economic growth and electricity consumption growth are expected to fall midway between those projected for the industrialized economies and the developing economies of Asia and Central and South America. Rising electricity demand in the Middle East will be linked more strongly with rapid population growth than with increases in per capita electricity usage. The outlook for Africa is similar, but the growth in electricity demand is expected to be slightly higher as access to electricity grids becomes more widespread. Both the Middle East and Africa depend strongly on extractive industries for economic growth. In both regions, economic growth and electricity consumption growth will be shaped by developments in the supplies of and demand for raw materials and petroleum.

Natural gas is increasingly becoming the fuel of choice for new electricity projects around the globe (Table 18). Over the 1996-2020 projection period, natural gas is expected to gain share in North American electricity generation markets relative to coal and nuclear power. South America is expected to increase natural gas consumption to supplement its large base of hydroelectricity generation. Western Europe is moving from nuclear to greater reliance on gas. Eastern Europe is expected to move from coal to gas. And a major share of capacity expansion in Asia and the Middle East will rely on natural gas.

Overall, natural gas is expected to account for 25 percent of world electricity fuels market in 2020, as compared with 16 percent in 1996 (Figure 65). Favoring natural gas are increased confidence in the availability of future supplies, significant improvements in gas turbine technology, the relatively smaller negative effects of gas-fired generation on air quality than those of other fossil fuels, and the increasing availability of imported liquefied natural gas (LNG). Although currently accounting for only 5 percent of world gas consumption, LNG exports have grown by 38 percent since 1992 [6]. Algeria, Indonesia, and Malaysia are the largest exporters of LNG, and Japan, South Korea, and France are the largest importers [7].

Pipeline trade in natural gas, currently almost triple the volume of LNG trade, is also growing rapidly. In recent years, exports of natural gas from Canada to the United States, from Norway and Russia to Western Europe, and from Algeria to Italy and Spain have led the increase. Upon the completion of a number of pipeline projects under construction or now being planned in South America, Argentina and Bolivia will become major exporters of natural gas and Chile and Brazil will become major importers.

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

The nuclear share of the world electricity market is expected to drop sharply in the forecast, to 10 percent in 2020 from 17 percent in 1996. Nuclear power has lost its luster largely as a result of past cost overruns in building nuclear facilities, the high costs of decommissioning and spent fuel retirement, and growing environmental concerns. Both Sweden and Germany are committed to gradual phaseouts of nuclear power, and other industrialized nations are expected to reduce reliance on nuclear. In the United States, for instance, where nuclear power provided 20 percent of total electricity production in 1996, its share of the generation market is expected to fall to 8 percent by 2020. Only France and Japan are expected to continue to rely on nuclear power to the extent that they have in the past.

In the future, as in the past, coal is expected to dominate electricity fuel markets, although its share is projected to decline slightly, to about 35 percent in 2020 from 37 percent in 1996. China is expected to have the highest growth in electricity-related coal demand at more than 4 percent annually. In 2020, China is projected to account for nearly one-third of the world’s coal consumption for electricity generation, up from 17 percent in 1996. China has been the leading consumer of coal since 1982, followed by the United States. India’s coal consumption is also expected to grow strongly, along with its consumption of natural gas. In the United States, coal use in the electricity sector is projected to increase by about 1 percent per year between 1996 and 2020.

For the nations of Western Europe, coal consumption is expected to decline. Western European countries are relying on increasingly available natural gas supplies for future growth in electricity production. The elimination of subsidies in the United Kingdom was largely responsible for a 50-percent drop in the nation’s coal production between 1989 and 1997 and a greatly reduced role for coal in electricity generation. In recent years both coal production and consumption have also dropped off sharply in Eastern Europe and the former Soviet Union (EE/FSU), and further declines in coal consumption by electric utilities in the EE/FSU region are expected. In large measure, coal’s lost share of the EE/FSU electricity market will be taken over by natural gas.

The use of renewable energy sources (primarily hydropower) for electricity generation is expected to remain stable over the forecast period, accounting for 22 percent of total electricity supply in 2020, compared with 21 percent in 1996. For the world to maintain its present degree of reliance on hydroelectric power will require substantial capacity expansion, most of which is expected to occur in China and other Asian nations.

Currently, no other region is as dependent on hydroelectric power as is South America. Although the region accounts for only 5 percent of the world’s total electricity generation, it accounts for 18 percent of the generation from hydropower. South America is expected to increase its output of renewable-based electricity from 5.4 quadrillion Btu in 1996 to 7.7 quadrillion Btu in 2020, but increasing use of natural gas is also expected to reduce the region’s reliance on hydropower for electricity generation.

Among the developing countries of Asia, China and India account for more than two-thirds of renewable-based electricity generation. China’s growth in renewables will be strongly influenced by additional capacity associated with the gradual completion of the 18.2-gigawatt Three Gorges Dam and other large hydropower projects. The Three Gorges Dam project is scheduled to be fully operational by 2009. Although India currently produces far less hydroelectricity than China, renewables still accounted for 13 percent of India’s electricity generation capacity in 1996 and are expected to account for more than 18 percent of its capacity in 2020.

Overall, China is expected to add more to its electricity generation capacity than any other nation—more than twice the projected new capacity additions in the United States between 1996 and 2020. China is far and away the largest economy in developing Asia, accounting for roughly one-third of the region’s economic activity. China has also had the region’s fastest rate of economic growth in recent years. Although its growth has slowed, the Chinese economy appears to have weathered the worst effects of the Asian financial crisis.

China’s current 250,000 megawatts of installed electricity generation capacity is second only to that of the United States [12]. Electricity consumption in China is expected to grow at a 5.7-percent annualized rate over the 1996-2020 period. Despite substantial recent growth in electricity supply, per capita consumption of electricity is currently one-sixteenth of that in the United States, and 10 percent of China’s population has no access to the grid. Thus, future development will entail substantial additional investment in power supply.

China has the world’s second largest coal reserves and is both the world’s largest producer and consumer of coal. For the most part, however, the reserves lie in the interior region of the country, far away from coastal economic activity. China currently is promoting the building of minemouth electricity plants rather than constructing additional rail lines to transport coal to eastern regions [13]. China’s reliance on coal for electricity generation is expected to remain stable at roughly three-fourths of the total (Figure 66).

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

After coal, renewables account for the second largest share of China’s electricity generation market, having a 17-percent overall share in 1996. From 1996 to 2010 hydroelectric capacity is expected to double and its share of China’s total electricity generation is expected to increase, largely as a result of completion of the Three Gorges Dam and other large-scale hydropower projects. By the time it becomes fully operational in 2009, Three Gorges Dam will have an installed capacity of 18.2 gigawatts. After 2010, growth in renewable energy is expected to moderate, and its share of the electricity market is expected to fall.

Although nuclear power currently accounts for only a small share of China’s electricity generation (under 1 percent in 1996), its share is expected to be nearly 4 percent by 2020. The United States has recently removed export barriers to Chinese purchases of reactors from U.S. manufacturers [14, p. 62]. Companies from France, Japan, the United States, and the United Kingdom currently are planning or carrying out nuclear power construction projects in China.

Foreign investment has played a critical role in financing the expansion of China’s electric power infrastructure and is expected to be even more important in the future. Between 1979 and 1996, foreign investment accounted for 10 percent of China’s total investment in electricity generation: approximately $13 billion in foreign funds helped finance the construction of 87 Chinese power plants with a capacity of 58,000 megawatts [15]. For the 1996-2000 period, China expects foreign investment to supply 20 percent of its electric power investment capital [15]. To increase their access to overseas capital, several of China’s electricity companies have recently acquired listings on the New York Stock Exchange and stock exchanges in London and Hong Kong.

During the late 1980s China implemented electricity reforms aimed at reducing government’s managerial role in electricity supply [16]. In 1987 the government allowed for a “fuel cost rider” enabling generation companies to pass on higher fuel input costs to consumers. In 1998, electricity prices for rural areas were deregulated. These and other reforms were aimed at increasing the attractiveness of investments in China’s electricity sector. For example, in awarding a contract for the financing of the 700-megawatt coal-fired Laiban B power project, rather than negotiating an allowable rate of return, China’s government chose to auction off the project to the bidders offering the lowest price per kilowatt of capacity. Before the Laiban B deal, foreign investors had often criticized China’s allowable rates of return on electricity investment as being too low [17].

Second only to China among developing countries in terms of population and economic activity, India is expected to increase its consumption of electricity at a 4.9-percent average annual rate from 1996 through 2020. India’s heavy reliance on coal for electricity generation is expected to lessen somewhat over the next 25 years. By 2020, coal’s share of the market is expected to decline to 62 percent from 79 percent in 1996 (Figure 67). Natural gas will largely make up for coal’s lost share, accounting for 14 percent of the electricity fuels market in 2020, compared with 5 percent in 1996. India’s use of nuclear and hydropower for electricity generation is also projected to increase in the forecast.

As in China, foreign investment is key to the financing of India’s power sector expansion. The Indian government opened up the power sector to private investment in 1991 with the passage of an amendment to the 1948 Electricity Supply Act allowing for the construction of independent power projects. In December 1996, the Indian central government announced a new policy for electricity development [18]. Called the “Common Minimum National Plan for Power,” the policy intends to restructure and corporatize the state electricity boards, to allow them greater autonomy, and to allow them to operate along commercial lines. The plan also attempts to facilitate the approval process for private power projects selected for competitive bidding by the central government. In June 1998, the central government further eased its rules on foreign investment in the power sector. Automatic approval is to be given to projects in excess of 15 billion rubees (about $355 million) involving 100 percent foreign equity.

The removal of subsidies flowing from urban electricity consumers to rural users has been a serious issue as India has undertaken electricity reform. The subsidies have been substantial, and in some regions their removal would lead to sizable increases in rural electricity rates. The Indian government’s Electricity Regulatory Commission issued an ordinance in 1998 directed at rationalizing electricity tariffs and subsidy policies. Under the order, the state regulatory entities would have the authority to remove rural subsidies [19].

Other developing Asian nations are also expected to have rapid growth in electricity consumption over the coming years. Although in the near term many other Asian economies have slipped into recession—some for the first time in recent memory—their previous economic growth rates are expected to be reestablished over the next few years. Electricity consumption for the collective region is expected to grow at a 3-percent average annual rate between 1996 and 2020.

Coal plays a much smaller role in the electricity industries of other developing nations of Asia than it does in China and India. In 1996, the region as a whole depended on coal for 31 percent of generation, renewables for 21 percent, and oil for 20 percent. No other world region outside the Middle East currently depends so heavily on oil as a source of electricity generation. By 2020, however, oil is projected to account for only 16 percent of the electricity fuels market in the other developing Asia region. Renewables will also decline in importance, with a projected 16-percent share in 2020.

For the most part, natural gas is expected to supplant oil and renewables in the region’s electricity generation mix, increasing from 21 percent of the electricity fuels market in 1996 to 33 percent in 2020. In the near term, the most rapid growth will be in the use of imported LNG.

Foreign investors have played a role in funding many ongoing power projects in developing Asia; however, the Asian economic crisis has had a variety of negative effects on a number of projects. First, the reduced rate of economic growth has slowed electricity consumption, undermining the need for capacity expansion. Second, the crisis has also produced a sharp drop in currency values, effectively raising the costs of imported fuels. Third, many of the foreign investments are to be paid back in foreign currencies against which many of the region’s currencies have been depreciated. In total, an estimated 11 gigawatts of new capacity has been postponed or canceled [20]. Further, with the severe drop in the value of regional currencies, electricity prices have been raised extensively in order to meet financing obligations.

Nowhere has the crisis been more pronounced than in Indonesia. In addition to slowing the near-term projected growth of electricity demand, the crisis has brought about a major devaluation of the nation’s currency, the rupiah. Many of the power contracts signed by the state-owned power company, Perusahaan Listrik Negara (PLN), with independent power producers were completed when the Indonesian currency was at its pre-crisis exchange value of around 2,300 rupiahs to the dollar. Currently, a dollar trades for 7,500 rupiahs, making many contracts unsustainable. The PLN has been trying both to renegotiate the contracts and to raise domestic electricity prices.

Thailand has had more success in the renegotiation of its electricity contracts with private developers, and most private power agreements have been successfully renegotiated. In Malaysia, however, the 2,400-megawatt Bakun hydroelectric power project has been temporarily tabled until the central government agrees to sponsor the project, and the 1,500-megawatt Penang project remains delayed [20]. The Bakun hydroelectric power project was scheduled to be completed in 2002.

Japan’s annual growth in electricity consumption is expected to average 1 to 2 percent over the projection period, reflecting the nation’s advanced level of economic development and slow population growth. Currently, Japan produces one-third of its electricity with nuclear power, second only to France among the nations of the Organization for Economic Cooperation and Development (OECD). Japan is expected to continue construction of nuclear power plants, slightly increasing its reliance on nuclear power from 33 percent of its total electricity needs in 1996 to 34 percent in 2020 (Figure 68). On the other hand, growing public opposition to nuclear power could intensify in future years and, perhaps, reverse the nation’s commitment to the nuclear power option. Japan’s dependence on natural gas for electricity generation is also expected to grow slightly in the forecast, mostly in the form of LNG. Japan is by far the world’s largest importer of LNG, most of which comes from Indonesia and Malaysia.

Electricity prices in Japan are among the highest in the world. As a result, in April 1995, Japan amended its Electricity Business Act. The goals Japan sought to achieve via the amendment included forcing open access in generation and allowing nontraditional suppliers to engage in direct sales. Before the amendment, any sales by nontraditional suppliers required approval from one of Japan’s 10 traditional generation companies. The amendment also allowed for tariff reform, giving electricity suppliers more discretion over setting prices. Wholesale wheeling was also introduced. The amendment also included a regulatory reform initiative, adopting a performance-based model of price regulation that first appeared in the United Kingdom after its utility reform. Japan’s reforms were furthered in 1998, when the Ministry of Trade and Industry allowed industrial companies (i.e., nonutilities) to sell electricity directly to large consumers.

In the near term, Japan’s inability to extricate itself from its current economic difficulties has cast some doubt on the future of the Japanese economy and when it will return to its earlier growth trend. In the fall of 1998, the Japanese parliament passed a $500 billion reform package that is intended to recapitalize the Japanese banking industry. To date, there have been few signs of economic recovery in Japan.

For the forecast period, after developing Asia, Central and South America is projected to realize the fastest growth in electricity consumption. In the very near term, however, Central and South America is expected to be the most dynamic of all developing regions in terms of electricity consumption growth. In the IEO99 reference case, the region’s electricity use is expected to average 4.5-percent growth per year between 1996 and 2020. Brazil, which accounts for about half the region’s economic activity and population, is expected to see electricity consumption growth of nearly 5 percent annually.

Currently, roughly 30 percent of the population in Central and South America has no access to the grid, and per capita electricity consumption for the region is roughly 12 percent of that in the United States. By 2020, however, per capita electricity consumption in Central and South America is expected to nearly double.

Central and South America is projected to rely increasingly on natural gas as a fuel for electricity generation (Figure 69), with the gas share of the electricity market growing from 10 percent in 1996 to 34 percent in 2020. Currently, oil, coal, and nuclear together account for 14 percent of the region’s electricity generation. That share is expected to remain relatively stable over the forecast period.

The growth in natural gas use for electricity generation will depend on the completion of several major pipeline projects linking producing countries, such as Argentina and Bolivia, with consuming countries, such as Chile and Brazil. Once those projects are completed, a regional natural gas pipeline will be in operation in South America. In addition, a continent-wide market for electricity is also evolving in South America. Currently, Argentina, Brazil, Venezuela, Chile, and Ecuador are completing a unified electricity transmission system. The grid is being established in part to help diminish hydroelectricity shortages during droughts, which have been fairly serious in recent years [21].

Figure 69. Fuel Shares of Electricity Generation in Central and South America, 1996 and 2020

Uruguay, in an attempt to establish itself as a hub of regional electricity trade, is promoting a number of transmission and generation projects that would connect Argentina with Brazil through Uruguay [22]. In 1997, the governments of Argentina and Brazil signed a letter of understanding that allows for less government interference in electricity trade between the two countries [23]. Foreign companies are playing a growing role in providing electricity to the continent. Enron won the bid to construct an interconnection between Argentina and Brazil that will allow for the export of 1,000 megawatts of power from Argentina to Brazil. In 1997, National Grid of the United Kingdom announced plans to build a transmission line between the Argentine coast and the Andes at a cost of $250 million. Venezuela also intends to sell surplus electricity to Brazil [24], and Venezuela’s Edelca has proposed the construction of a 2,600- mile line linking the two countries [25].

The InterAndes electricity transmission line, when completed, will allow exports of electricity from Argentina to Santiago, Chile. The transmission line, being financed by Chilgener, Chile’s second largest electricity generator, will run 700 miles at a cost of $575 million. Chilgener will also build two 350-megawatt combined-cycle gas plants in Salta, Argentina, to provide the power. Santiago suffers from serious air pollution resulting in part from oil- and coal-fired electricity generation.

There is also a regional electricity grid evolving in Central America, although at a hesitant pace. In December 1995, the presidents of Costa Rica, El Salvador, Guatemala, Honduras, Nicaragua, and Panama endorsed a proposal to construct a $350 million, 930-mile high-voltage transmission line (SIEPAC) connecting Guatemala, Honduras, and Panama [26]. The transmission line is being financed by the Inter-American Development Bank, the government of Spain, and a Spanish utility. Although the grid is scheduled to be completed in 2003 or 2004, the parties involved have proceeded cautiously thus far in light of criticism from the World Bank [26].

Brazil is currently in the process of privatizing and deregulating its electricity industry. Privatization of electricity in Brazil has been taking place in the context of a concerted effort at overall economic reform. Privatization-related sales of the nation’s electricity assets will be among the world’s largest energy-related financial transactions in 1997, 1998, and 1999. By late 1997, roughly $60 billion in Brazilian electricity assets had been slated for privatization [3]. The privatizations have attracted billions of dollars in foreign investment, most of which came from U.S. companies.

Western Europe is projected to average roughly 2-percent annual growth in electricity consumption from 1996 to 2020—higher than the rate for the United States, Canada, or Japan—based in part on the expectation that current measures aimed at unifying the region both financially and economically will improve its long-term prospects for growth. Most of the increase is expected to be met by gas-fired generation. For more than two decades, Western Europe has been reducing its reliance on coal and oil as electricity generation fuels. They accounted for 40 percent and 22 percent of the region’s generation market, respectively, in 1970 but only 26 percent and 8 percent in 1996. By 2020, coal’s share of the market is expected to slip to 16 percent, and oil’s share is expected to remain at 8 percent (Figure 70).

Figure 70. Fuel Shares of Electricity Generation in Western Europe, 1996 and 2020

Only France is expected to retain a high degree of reliance on nuclear power, at 71 percent of electricity consumption in 2020 (compared with 80 percent in 1996). Other West European nations are expected to reduce their reliance on nuclear power [14, p. 56]. Germany, for instance, has announced plans for a complete phaseout of nuclear power, which currently supplies about 32 percent of its electricity generation. In the United Kingdom, reliance on nuclear power is expected to fall from 34 percent of the power market in 1996 to 19 percent in 2020. Sweden has long planned to phase out nuclear power but has delayed implementation several times.

Europe currently is undergoing a transition to a continent-wide wholesale market in electricity. A 1996 directive by the European Community requires all signatories to open their domestic electricity markets to new suppliers starting in February 1999.¹⁶ In the initial implementation period (during 1999), 25 percent of each participating nation’s electricity market is to be opened to competition. In 2006, signatory countries will be required to open up one-third of their electricity markets to new suppliers. Although the definition of competitive access is still being debated, the anticipated onset of competition has led to some transnational acquisitions by European electricity companies eager to engage in cross-border trade.

Western Europe has also seen some moves toward the introduction of consumer choice in the retail electricity market. The Nordic nations implemented fully competitive supply markets at the retail level in 1996, and today households in Finland, Norway, and Sweden are allowed to choose their electricity suppliers. The recently privatized electricity industry in the United Kingdom moved one step closer to full competition in 1998. In September, London residents became eligible to nominate their preferred electricity suppliers. In June 1999, virtually all households in England and Wales are scheduled to have the option of choosing a preferred electricity supplier.

In November 1998, the Russian government announced that it would be unable to pay the interest on debts to its international creditors for 1998 and 1999. Economic growth, which began to head in a positive direction in 1997 for the first time in 7 years, turned negative again in 1998. Several years of political instability, compounded most recently by financial insolvency, raise severe doubt about the prospects for recovery. However, most of the Eastern European nations maintained positive economic growth rates in 1997, and their projected growth rates in IEO99 are changed little from last year.

The FSU and much of Eastern Europe suffer from an antiquated electricity supply infrastructure. Future investment will be directed in large part to upgrading the industry to the standards of industrialized nations. Coal accounted for 26 percent of electricity generation in Eastern Europe and the FSU in 1996. By 2020, in contrast, coal’s share is expected to fall to 12 percent, largely being replaced by hydropower and Russian natural gas (Figure 71). Reliance on nuclear power in Eastern Europe is also expected to fall steadily over the forecast period.

Figure 71. Fuel Shares of Electricity Generation in Eastern Europe and the Former Soviet Union, 1996 and 2020

Electricity consumption in the United States is projected to increase at an average rate of 1.2 percent per year from 1996 to 2020—one of the smallest increases expected among the industrial economies. Demand growth in the United States has slowed considerably since the 1960s, when electricity consumption was rising at a rate of 7 percent per year. Saturation of households with electronic appliances and efficiency improvements in such appliances over time are responsible for the slower growth in total electricity consumption [27].

The United States is expected to significantly reduce its reliance on nuclear power as a source of electricity generation over the forecast period. Nuclear power, which accounted for 20 percent of total U.S. electricity generation in 1996, is expected to drop to 8 percent by 2020. Coal’s share of the U.S. electricity fuels market is expected to hold steady at roughly 50 percent (Figure 72), and the 20-percent share of renewables in 1996 is also expected to remain stable. Natural gas and, to a much smaller extent, coal will largely supplant nuclear power in the United States. No new nuclear power plants have come on line in the United States since 1996, and none is expected in the future. Deregulation, as it forces decisionmakers to address the issue of stranded costs, could hasten the move away from nuclear power.

Figure 72. Fuel Shares of Electricity Generation in the United States, 1996 and 2020

In 1998, California opened its market to the retail sale of electricity and became the first State to allow consumer choice of electricity providers at the household level. Early indications are, however, that the availability of consumer choice did not induce many household users to switch from their incumbent suppliers. Enron, which entered the California retail market more aggressively than any other company, pulled out just 3 weeks after it entered.

In 1998, California also started the California Power Exchange, establishing a deregulated market for electricity in the State for the first time. The Power Exchange is open to all buyers and sellers of electricity and provides a vehicle to bring electricity supply and demand together. An Independent System Operator was also established with the mandate of focusing on reliability.

The electricity industry and the financial industry have also become more interlinked in the United States and will continue to do so in the future. In 1996, trading in electricity futures started on the New York Mercantile Exchange. Further, in recent years, several utilities have set up trading operations and some have established relationships with financial institutions to better manage risk exposure in an era of growing volatility in electricity prices.

Regional wholesale markets have also emerged. The introduction of wholesale trading of electricity has seen some difficulties, however. In July 1998, a weather- related consumption spike in the Midwest was coupled with some unexpected loss of generation capacity. Together the developments led to nondelivery of some contracted electricity supplies and a 1-day runup of electricity prices to as high as $5,000 per megawatthour. Similar price spikes have occurred in the United Kingdom, Australia, and Alberta, Canada with the introduction of wholesale electricity markets.

Canada is also expected to see relatively slow growth in electricity consumption over the forecast period. Between 1996 and 2020, annual growth in Canadian electricity consumption is projected to average 1.4 percent.

Like the United States, Canada is expected to reduce its dependence on nuclear power over the coming years. Nuclear power, which accounted for 17 percent of Canada’s total electricity generation in 1996, is expected to provide only 7 percent of total supply in 2020. In all likelihood, Canada may reduce its dependence on nuclear power even more dramatically. Currently, Ontario is reevaluating the safety of its nuclear power industry. In late 1997 and early 1998, Ontario Hydro shut down seven of its older power plants, or 17 percent (4,300 megawatts) of its operating capacity. At present, it remains uncertain whether the plants will be brought back on line sometime after 2000 as was intended. Historically, the United States has been a net importer of electricity, primarily from Canada. If the plants are not reopened, the net flow of electricity across the U.S.-Canadian border could be reversed. Natural gas will in large measure make up for Canada’s reduced reliance on nuclear power and hydroelectricity.

Also like the United States, Canada is currently attempting to reform its electricity sector. Most reform efforts are taking place at the provincial level and are motivated by a desire to reduce electricity costs. The reforms should serve to integrate the U.S. and Canadian electricity markets more closely and increase electricity trade.

Provincial governments in Canada are largely responsible for electricity policy. In recent years the provincial government of Alberta has been a leader in electricity reform. Alberta’s Electric Utility Act of 1995 created a competitive market in generation, instituted location-based rates, and set up a power pool for spot trading in electricity [28].

In April 1997, Hydro Qu�bec petitioned the U.S. Federal Energy Regulatory Commission (FERC) for permission to sell electricity in the United States in return for allowing U.S. competitors to wheel electricity into Qu�bec. FERC Order 888 compels U.S. utilities to open their transmission lines to all newcomers, although they can refuse access to any supplier who fails to provide reciprocal treatment. Until deregulation, Canadian utilities were allowed to sell power only into U.S. transmission grids immediately adjacent to their provincial borders. Eastern New York State and parts of New England obtained some power from Hydro Qu�bec, and Ontario Hydro sold into western New York. In November 1997, Hydro Qu�bec received FERC approval to sell power in the United States at market-based rates. FERC attached no conditions to its decision, indicating that it was satisfied that Hydro Qu�bec had met the agency’s reciprocity requirement and had adequately opened its market to competitors. Hydro Qu�bec made a major concession to the FERC by agreeing to allow outsiders to transmit electric power over its grid to nine municipal wholesalers and one municipal cooperative, beginning in May 1997.

Mexico is expected to lead North America in electricity consumption growth, largely because of its higher projected rate of economic growth and its lower starting base in terms of per capita electricity consumption. Over the 1996-2020 period, Mexico’s electricity consumption is projected to grow at a rate of nearly 4 percent per year.

Plagued by serious air pollution, Mexico has been aggressively moving away from oil-fired generation to natural gas. In order to finance future electricity infrastructure to meet the needs of a rapidly growing population and economy, the Mexican government is actively encouraging the development of private power projects. Mexico currently allows private investment in independent power production, although all sales from such operations must be directly to the state-owned utility, Comision Federal de Electricidad (CFE). Several U.S. companies have undertaken investments in gas-fired generation facilities in Mexico. In February 1998, President Zedillo proposed to the Mexican congress that private companies should be allowed to invest in the leasing and construction of power plants and regional transmission lines. The proposal would allow large consumers of electricity to bypass the CFE and buy directly from generators [29].

South Africa accounts for 61 percent of all the electricity generated on the African continent and, in combination with Egypt, Algeria, Libya, and Morocco, 89 percent of the continent’s total electricity production. The continent as a whole is expected to see electricity consumption grow at a 3-percent annual rate from 1996 to 2020.

Several African countries have recently opened up their electricity sectors to private investment. Privatization efforts have been led by Morocco. In 1997, CMS Energy and the Swedish/Swiss company, Asea Brown Boveri, began construction on the Jorf Lasfar power plant. The $1.5 billion coal-fired plant will have a capacity of 1,360 megawatts upon completion in 2000 [30]. The plant, which is the largest of its kind to date in Africa, will eventually provide Morocco with about 30 percent of its electricity supply.

In 1996, the Egyptian cabinet approved the startup of a build-operate-transfer (BOT) program involving 1,600 megawatts of power [31]. The Ivory Coast is also using a BOT arrangement to finance, build, and manage major infrastructure projects without increasing its debt level. Twelve projects have been proposed thus far, and five have been awarded to private operators, including a new thermal electric generation facility near Abidjan [32]. Nigeria too is attempting to encourage foreign participation in electricity generation. In late 1998, Mobil announced that it had contracted to build a 350-megawatt natural-gas-fired independent power project in Nigeria [33].

Almost two-thirds of the economic output of the Middle East region is accounted for by Iran and Saudi Arabia, along with half the region’s electricity consumption. Iran is the most populous country in the Middle East, and Saudi Arabia has one of the highest per capita incomes. Other large users of electricity in the Middle East include Israel, Iraq, and Kuwait. Largely as a result of growth in the region’s dominant economies, electricity consumption in the Middle East is expected to grow at a 3-percent annual rate over the projection period. Among Middle Eastern nations, Israel took a step towards privatization recently. In 1996, Israel’s parliament passed a new electricity law allowing the Energy Minister to grant permits to independent power producers [31].

The Middle East depends heavily on petroleum to fuel its electricity generation. Oil-fired generation accounted for 38 percent of all electricity produced in 1996 and natural gas 36 percent—levels that are expected to continue throughout the forecast. Over the next few years, Iran is expected to complete its first nuclear power plant, and by 2020 nuclear power is expected to account for 2 percent of the region’s electricity production.