International Energy Outlook 1998

Between 1995 and 2020, the world’s annual consumption of electricity is projected to rise from 12 trillion kilowatthours to 23 trillion kilowatthours. The greatest increases are expected in developing Asia and in Central and South America.

Throughout the world, electricity is and will continue to be the fastest growing component of energy demand. Between 1995 and 2020, total world electricity demand is expected to rise from 12 trillion kilowatthours to 23 trillion kilowatthours (Table 25). Demand growth will be slowest in the industrialized countries; but even in the advanced economies, which currently account for about 60 percent of world electricity use, absolute and per capita consumption levels are expected to rise as new uses for electricity proliferate among residential, commercial, and industrial consumers. Aggregate demand for the industrialized countries in 2020 is projected to be more than 4 trillion kilowatthours higher than it was in 1995, exceeding 11 trillion kilowatthours.

In the developing countries, electricity demand is projected to grow at more than twice the rate of growth in the industrialized countries, with aggregate consumption more than tripling between 1995 and 2020, to 10 trillion kilowatthours. The greatest gains are expected in developing Asia and in Central and South America, where electricity demand growth has tended to outpace economic growth. Rising standards of living are leading to greater electrification and more intensive use of modern appliances, space heating, air conditioning, and lighting.

Highlights of recent developments in electricity markets around the world are as follows:

Table 25. World Net Electricity Consumption by Region, 1990-2020
(Billion Kilowatthours)

Growing electrification contributes substantially to rising world requirements for primary energy. However, growing reliance on electricity does not dictate increasing reliance on any particular source of primary energy input. As a result, there is considerable diversity among regions in the composition of energy use for electricity generation (Table 26). In aggregate, coal currently is the most widely used primary fuel, accounting for 36 percent of total fuel consumption for electricity production.

Coal is expected to maintain its share of the overall electricity generation market through 2020. China shows the largest increase in coal consumption over the forecast period, triple the increase for the United States. India’s coal use is expected almost to double. More than two-thirds of the overall increase in world coal consumption is expected to occur in China and India. North America’s coal consumption is expected to rise in absolute terms; however, some nations are expected to reduce their levels of coal use in both absolute and relative terms— notably, Germany and the United Kingdom, which in recent years have begun reducing subsidies for domestic coal production.

Renewable energy—primarily hydropower—is the next most important source of energy for power generation. Its relative share is expected to change little. Major hydropower developments in developing Asia will contribute substantial increments of energy for generation.

The most marked changes projected for primary energy use in electricity production involve nuclear power and natural gas. Of all the fuels used for electricity generation, natural gas is expected to show the largest increase in consumption. Due in large measure to advances in exploration and development technologies, the cost of finding natural gas reserves has fallen considerably in recent years [1], and the world’s natural gas reserves-to-production ratio has risen substantially. At the same time, power generation technologies have evolved to favor natural gas usage. The new technologies tend to economize on both capital and operating costs. Natural gas use for electricity is expected to rise from 16 percent of the total in 1995 to almost 25 percent in 2020. Increasingly, natural gas will be used as a fuel for baseload plants. Almost all regions of the world are expected to show substantial increases in the use of natural gas to generate electricity.

Increases in the availability of imported liquefied natural gas (LNG) have also led to greater usage of natural gas for power generation. Although currently accounting for just under 5 percent of world natural gas consumption, LNG imports have grown by 27 percent between 1992 and 1996 [2, p. 28]. Japan is the largest consumer of LNG, and South Korea has become a significant LNG importer in recent years. However, current economic uncertainties in Asia may slow near-term demand growth and lead to a postponement of several major LNG developments involving increased trade between Asian customers and Middle East suppliers. On the other hand, several Asian countries are accelerating the internal development of natural gas and electricity markets to economize on the foreign exchange costs associated with the use of imported oil.

By 2020 nuclear power generation is projected to be in decline. The growth in nuclear use in Asia is expected to be more than offset by reduced output in North America and, to a lesser extent, in Western Europe, where Sweden is implementing a program to phase out its nuclear program. Although the United States produces less nuclear power than Europe, the decline in U.S. nuclear power consumption will exceed the European reduction.

In summary, over the projection period, fossil fuel use will increase in relative importance as a prime mover for power generation. Even among Annex I countries, the share of fossil-based primary energy used for electricity generation will increase in the reference case, as will the absolute level of utilization. In the United States, nuclear power is projected to decline by 43 percent, coal use to rise by 25 percent, and natural gas use to triple.

Table 26. World Energy Consumption for Electricity Generation by Region and Fuel, 1995-2020
(Quadrillion Btu)

Electricity is a capital-intensive industry, perhaps the most capital-intensive of all industries. To meet global power projections, it is estimated that more than $2.3 trillion will have to be spent between 1995 and 2010 (Table 27). Roughly two-thirds of the investment will be needed in developing countries [3].

Particularly in the developing world, vast infusions of foreign capital will be required to sustain growth in electricity supply. Many developing countries are already coping with power shortages. The future power needs of such populous countries as Brazil, China, India, Indonesia, and Pakistan are immense, presenting investment demands beyond the financial means of their domestic capital markets or government resources. As a result, attracting foreign investment is critical to the successful expansion of the electric power sectors in these nations.

Throughout the world, a wide range of initiatives are underway to modify the regulatory arrangements affecting electric power supply and development. In emerging economies, the driving forces for change are capacity and capital shortages. Old arrangements wherein government enterprises developed and managed the provision of electricity services have been judged inadequate to cope with the change associated with buoyant economic development.

As a consequence, many countries are moving to privatize government enterprises and open entry for new enterprises, seeking to lower the cost and improve the availability of electrical services. The act of privatizing can ease capital shortage by replacing a credit-restrained management with one that has readier access to borrowing and superior ability to institute operating economies to free cash flow for investment. Removing entry barriers for domestic or foreign investors has spawned the development of independent power producers that significantly augment power generation capacity.

Table 27. Cumulative Projected Worldwide Electric Power Investments by Region, 1995-2010
(Billion Nominal Dollars)

Although global capital markets and the global pool of savings are considered adequate to the task of funding future electricity investments, for several nations investment funds may not be forthcoming unless difficult electricity policy reforms are adopted. These reforms are necessary in order to provide investors (both foreign and domestic) with expectations of achieving adequate rates of return at acceptable levels of risk. The state and methodology of policy reform varies widely among developing nations. Clearly, however, there is strong pressure toward reform. Significant policy reforms are underway in developed countries as well, where the pressure for reform stems from an expectation that increased competition will reduce the cost of electricity. The precise character of reform varies widely among countries, and in most areas it is still evolving.

Of all the regions, Asia is expected to show the most rapid increase in economic growth and electricity consumption over the next few decades. Whereas developing Asia accounted for only 16 percent of total world electricity consumption in 1995, it is expected to account for 42 percent of demand growth between now and 2020.

In part, China’s vast size will drive the growth of electricity demand. China, with 1.2 billion people, is the world’s most populous nation. It also has had one of the fastest growing economies in recent years, a trend that is projected to continue, although at a reduced rate.

Electricity consumption in China is expected to grow at a 5.8-percent annual rate over the forecast period. The high level of coal use in China’s electricity industry reflects the country’s ample coal reserves. China accounts for nearly one-third of all world coal production [4, p. 73] and has about 11 percent of the world’s coal reserves [2, p. 30]. As a consequence, coal accounted for 76 percent of China’s electricity fuel in 1995 (Figure 76). That share is expected to fall slightly by 2020, even while overall coal consumption increases threefold. Renewables (largely hydropower), which accounted for 19 percent of China’s electricity consumption in 1995, are expected to have a 14-percent share of the power market in 2020. Nuclear’s share is expected to rise from 1 percent in 1995 to 3 percent in 2020. As electricity fuels, oil (at about 6 percent) and natural gas (less than 1 percent) provide the remaining inputs to China’s electric power industry. The relative importance of both fuels is expected to change little over the forecast period.

Figure 76. Energy Consumption for Electricity Generation in China, 1995 and 2020

Sources: 1995: Derived from 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 (1998).

China recently broke ground on what is to be the largest hydroelectric project in the world, the Three Gorges Dam project. Upon completion in 2010, the project is expected to have a total capacity of 18.2 gigawatts and produce 85 billion kilowatthours of electric power per year [5, p. 76]. Largely due to the Three Gorges project, hydroelectric power production is expected to more than double between 1995 and 2010 but remain relatively flat for the remainder of the forecast period. (For a more detailed discussion of China’s Three Gorges Dam project, see pages 105-107.)

Rural electrification is a major goal of Chinese energy policy. Brownouts and blackouts are common, and electric power production has not kept pace with the rapidly expanding Chinese economy. It is estimated that one-tenth of China’s population—or roughly 100 million people—are currently without electricity. Per capita consumption in China is only 6 percent that of the United States [4].

China’s growing electric power investment needs on top of other investment needs has led to the encouragement of foreign investment in its electricity market. Between 1979 and 1996, 10 percent of the investment in China’s electric power industry was foreign [6]. Up until 1992, foreign investment in China’s electricity sector was limited to “overseas export/import bank financings, supplier credits, and other concessionary financing techniques.” Since 1992, the Chinese government has allowed foreign direct investment on a limited basis [7]. Relatively large investments in electric power by foreign entities require central government approval. In electricity most foreign investment has involved joint ventures of local and foreign entities, although build-operate-transfer (BOT) schemes have become a growing means of finance. Between 1996 and 2000, China intends to increase its electricity capacity by roughly half, at a cost of $100 billion. China is expecting foreign investors to fund roughly a quarter of this investment [7]. China has taken measures to increase direct access to world capital markets for its large electricity enterprises in recent years. In 1994, China listed two major holding companies with electricity generation assets on the New York Stock Exchange [8]. In addition, investment capital has also been raised through the issuance of non-investment grade debt in United States fixed income markets [9].

In late 1996, China approved a new BOT framework for the Laiban B power project, a 700-megawatt coal-fired plant [10]. The contract was awarded through a competitive bidding process that allowed the winning bidder to assume 100 percent ownership. The purchasers were Electricite de France and GEC Alsthom for $650 billion [11]. Unlike previous projects, where rates of return were negotiated, the cost per kilowatthour was negotiated, which provides the operators of Laiban B with a strong incentive to boost profits by reducing costs.

India’s position as the world’s second most populous nation, and one whose economic growth rate has increased in recent years, is expected to increase its consumption of electricity considerably over the forecast period. India is the other Asian giant. India’s population, at nearly 1 billion people, is second only to China’s. In Asia, India’s future electric power needs are also second only to China’s. Like China, India has in recent years stepped up its pace of economic growth. Currently, the Indian economy is expected to expand at about 5.5 percent per year through 2020. Electricity demand is expected to increase at a slightly higher rate of about 7 percent per year through 2005, before slowing to 4.4 percent between 2005 and 2020. At present, electricity shortages are a serious problem in India. Outages average 20 percent of demand during peak use hours and 10 percent during off-peak use [12].

Coal currently accounts for 78 percent of fuel use at India’s electric power stations (Figure 77). As in China, India’s high coal use is a reflection of its ample coal reserves. Renewable energy (almost entirely hydropower) is the next largest source of electricity supply in India. In 1995, renewables accounted for 14 percent of India’s electricity generation. Natural gas (at about 5 percent), oil (at 2 percent), and nuclear power (at just under 2 percent) provided the remaining fuels to India’s electricity industry. In the forecast, a growing role is projected for natural gas, nuclear, and renewables at the expense of coal and oil.

Figure 77. Energy Consumption for Electricity Generation in India, 1995 and 2020

To sustain the expected growth rate in electricity consumption, large investments in electricity infrastructure will have to be made. The Indian government is currently counting strongly on private sources for the necessary investment funds. Of the 40 gigawatts of generating capacity to be built between 1997 and 2002, nearly half is expected to be funded from private sources [13]. The central government’s expectation is that foreign capital will account for much of that investment.

In 1991, the national government enacted legislation to encourage greater private sector involvement in independent power production. India has further encouraged foreign investment by eliminating industrial licensing, privatizing state-owned companies, and reducing tariffs and trade restrictions on the importation of electricity equipment. In 1994, the central government announced that it would offer counter guarantees to eight power purchasing agreements approved and sponsored by state electricity boards [14]. Later, the government allowed foreign investors to obtain 100-percent ownership in electric power projects. Initially, foreign investment was restricted to power generation projects, but in 1997 the electricity laws were amended to allow foreign investment in transmission lines [15].

Although in general the central government in India has taken a leading role in promoting national electricity reform, state governments have also played a role in shaping electricity policy, and not always a supportive one. In India, the state electricity boards share responsibility along with the national government for the provision of electricity. State governments run their respective electricity industries through the state electricity boards. Each state has a board, which is a vertically integrated electricity operation providing generation, transmission, and distribution services. Currently, many of the boards are bankrupt, largely because, in response to political pressures, they have set electricity tariffs that have been insufficient to cover costs [14].

Legally, both the national and state governments are responsible for the production, transport, and distribution of electricity, although each government’s exact responsibility is unclear [16]. Decisions affecting electricity reform have often taken on a partisan political nature, as evidenced by a recent dispute between Enron and the state government in Maharashtra that has served to undermine India’s creditworthiness with the international financial community. In 1995, a newly elected nationalist Maharashtra state government decided to cancel a $2.8 billion power plant developed by the Enron Corporation after Enron and its partners (Bechtel Enterprises and the General Electric Company) had already spent $300 million. Enron later successfully renegotiated a deal with the state government in early 1996, which called for a reduction in electricity rates and eventually allowed the project to proceed. The plant is initially to use oil as a fuel, but Enron’s intention is to convert the facility so that it runs on imported LNG in future years.

Some Indian state governments have attempted to be more hospitable to foreign investment. Before the adoption of reform measures in Orissa, electricity shortages were common, tariffs were unsustainably low, and the state faced an insurmountable level of capital expenditures for much-needed industry upgrades and expansion. In April 1996, the Orissa state government appointed a new independent regulatory commission and did away with the former state electricity board [17]. Orissa was the first state to create an independent regulatory commission [18]. The regulatory commission was mandated with the task of setting tariffs, issuing licenses, conducting competitive procurement bids, and monitoring financial performance standards. Orissa also restructured its electricity industry along functional lines, creating different units responsible for generation, transmission, and distribution. Privatization of the state-owned electricity company, Grid Corporation is planned for 1998 [17]. Largely as a result of these reform efforts, foreign companies have targeted Orissa for electricity investments. For instance, the U.S.-based independent power producer AES plans to build two 250-megawatt coal plants in the state.

India’s neighbor to the northwest, Pakistan, has been one of the most aggressive of nations in adopting and implementing electricity reform. Although significantly smaller than India (Pakistan’s economy is approximately one-eighth the size of India’s), Pakistan has thus far attracted foreign investment sums into its electricity sector that easily exceed those committed to its neighbor. According to the World Bank, foreign direct investment commitments to Pakistan’s electricity sector of roughly $9 billion may even exceed commitments to electricity investments in China as well [19].

Two agencies are responsible for electricity supply in Pakistan. For Karachi, Pakistan’s largest city, power is the responsibility of the Karachi Electric Supply Corporation (KESC), and the Water Power Development Authority (WAPDA) has the responsibility for the rest of the country. These agencies are vertically organized electric utilities providing both electricity generation and distribution services. At the urging of the World Bank, WAPDA is being reorganized and separated along functional lines. In the future Pakistan intends to privatize both KESC and WAPDA.

To meet its growing power needs, Pakistan has actively encouraged private investment to build power generation plants. The Pakistani government is also encouraging BOT agreements, both for new power projects and for some of the thermal power stations managed by the country’s major utility. The first major project involving foreign investment is the 1,292-megawatt Hub Power Company plant, which was completed in 1997. A consortium of domestic and foreign companies have provided funding for Hub Power. Prominent among them are National Power of the United Kingdom (25-percent share), Xenel of Saudi Arabia (15-percent share), and Entergy of the United States (10-percent share).

By 1996, Pakistan had reached financial closure on at least 10 independent power projects. Foreign investors involved in these projects include the U.S. companies AES, Coastal Power, and El Paso Energy; Tomen, Mitsubishi, and Toyota Tsucsho of Japan; Siemens of Germany; and Southern Electric Power of the United Kingdom.

In mid-1997, several Southeast Asian nations experienced financial difficulties characterized by steep currency depreciations and sharp drops in domestic asset values. The crisis was in part precipitated by the accumulation of excessive levels of foreign debt, trade imbalances, and speculative financial investments. Whether it is purely a financial crisis, or whether it will have an impact on the real economies of these nations, is at the moment uncertain. Currently, the crisis has diminished, but the near-term growth prospects for Malaysia, Thailand, Hong Kong, Indonesia, South Korea, and the Philippines have been affected. Nonetheless, fairly rapid recovery and a resumption of relatively high rates of economic expansion are expected.

Electricity demand in Southeast Asia is expected to be nearly three times higher in 2020 than it was in 1995. Over the past decade, electricity growth has averaged in the range of 10 percent per year, a rate of growth that is expected to continue. Much incremental demand was powered by oil, and the area’s reliance on oil for generation is among the highest in the world. However, primary energy use is now being diversified. Taiwan and South Korea have nuclear capacity in place or under construction, and South Korea also consumes significant quantities of coal and growing quantities of imported LNG.

For the region as a whole, future capacity expansion islikely to favor natural gas. Malaysia, Thailand, Indonesia, and the Philippines all have pipeline-based power generation under construction or planned. In the long term, Indonesia hopes to phase out oil-fired generation to free up indigenous oil production for export. Malaysia and Thailand, along with Myanmar, are developing a gas pipeline network to exploit indigenous resources. The Philippines has little in the way of domestic fossil fuel resources, but natural gas discoveries offshore are expected to support large-scale independent power production within the decade. Both Taiwan and South Korea have significant plans for natural-gas-fired power generation; however, neither will have access to pipeline supplies, and thus they plan to rely on imported LNG.

To varying degrees, power shortages and high investment needs have induced changes in electric utility policy in several countries of Southeast Asia over the past decade. In the Philippines, power shortages led to the passage of legislation in the early 1990s that called for the eventual privatization of the nation’s electric utility enterprises. In 1993, the entry of independent power producers was legislatively approved. Fast track approval of electric power contracts was also introduced. An Omnibus Electric Power Act, which is currently pending approval, is expected to lead to the privatization of the National Power Company and to a separation of its functional operations into separate entities.

These policy measures were effective in solving the Philippines electricity crises. A recently evolved independent power producing industry today provides 35 percent of the country’s total generating capacity [20]. Currently, the Philippines has 33 independent power producers. Foreign investment has also played a critical role. Since 1990, an estimated $1 billion in foreign dollars has flowed into Philippine electricity investments [21]. Under its 1996-2005 plan, the Philippines expects investments of $19 billion in its electricity sector, 80 percent of which is expected to be private and 47 percent from overseas sources [20, 21].

Rapidly growing electricity consumption has induced electricity reform and encouraged the development of independent power projects in both Malaysia and Thailand. The Malaysian government aims to increase the country’s electricity generating capacity from 9,300 megawatts in 1995 to 33,000 megawatts by 2020. Currently, there are six independent power producers in various stages of development in Peninsular Malaysia.

In 1992, Thailand implemented several electricity industry reforms aimed at reducing the power of thenational electricity monopolies through commercialization and privatization. The eventual privatization of EGAT, Thailand’s state-owned electricity company, is planned [5, p. 341]. The Thai government has encouraged the development of an independent power production industry, and currently several independent power projects are underway. Thailand plans to allow independent power producers to provide over 4,000 megawatts of power by the year 2002, through BOT or build-own-operate (BOO) schemes. The Thai government intends to allow 100-percent foreign ownership in these projects [5, p. 342]. Currently, the U.S.-based companies Black and Veatch, Texaco, Unocal, and Westinghouse have acquired interests in Thai independent power [22].

To this point, government enterprises have dominated electricity supply development in South Korea and Taiwan, which have long been among Asia’s most rapidly growing economies. Electricity consumption has also grown rapidly in both countries and is expected to continue to do so in the future. Between 1986 and 1995, electricity consumption in South Korea and Taiwan more than tripled [4, p. 87].

South Korea’s electricity industry is dominated by the state-owned electricity company, the Korean Electric Power Corporation (KEPCO). Although the government of South Korea has indicated that it intends eventually to privatize KEPCO, no progress has been made to date.

South Korea is planning to significantly increase its use of natural gas, largely LNG, as an electrical fuel in future years. South Korea is the second largest importer of LNG after Japan [2, p. 28]. South Korea is also expected to rely increasingly on nuclear power as a source of electricity. In 1994, nuclear power provided about a third of its electricity [4, p. 93]. Coal accounted for 23 percent of South Korea’s electricity fuel market in 1995 and it is expected to maintain its share [5, p. 294].

As in South Korea, electricity in Taiwan is dominated by a single company, the state-owned Taiwan Power Company, (Taipower) [5, p. 315]. Taipower is a vertically integrated monopoly that provides generation, transmission, and distribution services. The electricity fuel market is almost evenly supplied by coal (23 percent), nuclear (20 percent), and oil (21 percent). Hydropower (17 percent), other renewables (11 percent), and natural gas (8 percent) account for the remainder of the market. In the future, Taiwan will increase its reliance on natural gas, coal, and oil and significantly reduce its reliance on nuclear power.

In Central and South America, electricity consumption has grown substantially in recent years and is expected to maintain a fast rate of growth in the future. Between 1986 and 1995, electricity consumption in this region grew at a 4-percent annualized rate [4, p. 88], and electricity demand in the region is projected to grow at a 4.0-percent annual rate. To fund the necessary growth in electricity infrastructure just through the year 2010, Central and South American nations will need to spend an estimated $108 billion [23].

Perhaps nowhere more than in Central and South America has there been a growing convergence between petroleum companies and electric power companies. Important progress in creating regional energy grids is underway for both natural gas and electricity. To this point, power generation in the region has relied heavily on hydropower, which will continue in the future; however, much of the future expansion of power generation will involve exploiting the region’s abundant natural gas resources (Figure 78). Natural gas pipeline projects costing nearly $7 billion are being implemented to connect natural gas producing areas in Argentina, Bolivia, Colombia, and Peru with consumers in Brazil and Chile. Other projects under consideration will connect Argentina with Paraguay and Uruguay [24, 25]. Much of the expected natural gas trade will fuel electric power plants in Brazil and Chile, both of which suffer from substantial air pollution problems and pending shortages of electric power supply. Among the participants in the natural gas pipeline projects are several U.S.-based companies, including CMS Energy, El Paso Energy, and Enron [26].

Brazil is far and away Central and South America’s largest economy. It is the world’s fifth most populous country and accounts for almost half of Central and South America’s economic output. Brazil is projected to account for 77 percent of the growth in the region’s electricity consumption between 1995 and 2020. Currently, hydroelectricity accounts for more than 90 percent of Brazil’s installed electricity capacity [27]. Over the 1995-2020 forecast period, Brazil’s electricity consumption is expected to increase at a rate of 5.3 percent per year. Much of that expansion will be based on fossil fuels, in particular, natural gas.

Figure 78. Energy Consumption for Electricity Generation in Central and South America, 1995 and 2020

Improved economic performance in Central and South America is a product of a variety of forces. Perhaps none is more important than reformed government policies that have promoted greater reliance on market forces to direct resource allocation and improve economic efficiency. Led by Chile, and later Argentina, there is a strong trend toward privatization across various industries and introduction of economic incentives to encourage greater domestic and international investment. The electric utility sector has been an important focus of reform efforts. In both Chile and Argentina the utility sector has been largely privatized.

In Brazil, the privatization process is underway but far from finished. Because of its size, in Brazil even partial progress involves many billions of dollars of new investment, much of which is coming from abroad. In the state of Sao Paulo, for instance, the former electric utility was transformed into 6 generation companies, 1 transmission company, and 14 distribution companies. Companhia Paulista de Foca e Luz, a Sao Paulo distribution company, was sold to a consortium of Brazilian companies for $3.02 billion. In the state of Rio Grande de Sol, the electricity distribution company, Cetro Oeste de Distribuicao de Energia Eletrica, was sold to U.S.-based AES Corp for $1.37 billion, and Norte-Nordeste de Distribuicao de Energia Eletrica was sold to U.S.-based Community Energy Alternatives and two Brazilian partners for $1.5 billion [28]. This was the second largest privatization in Brazil (the largest involved the sale of a mining company, Companhia Vale do Rio Doce SA). Public Service Enterprise Group and its partners agreed to purchase a 91-percent stake in one of the distribution companies for $1.49 billion [29]. Chile’s Chilectra has also invested in a Brazilian distribution company. Currently, the sale of the assets of the federally owned electricity company, Electrobras, is scheduled for 1998. Electrobras controls roughly half of all the generation capacity in Brazil.

In most other South American countries some form of regulatory reform and privatization is underway or about to begin; however, commitments to privatization and relaxation of restraints on private investment are not universal. Venezuela, for example, has postponed privatization plans for electricity, and only partial privatization has been approved in Bolivia, Peru, and Uruguay. Throughout the region, although the pace of reform may vary, the direction of change is consistently toward liberalization of conditions that would favor enhanced investment incentives.

In North America energy trends in the United States and Canada closely resemble those in Western Europe and Australia, in that energy demand growth of slightly more than 1 percent per year is projected—about half the rate of growth in GDP. In contrast, Mexico’s economic growth and energy demand are expected to be much more robust, in the range of 3 to 5 percent per year.

In both the United States and Canada, electricity consumption is expected to rise by about one-third over the forecast period and at a rate that exceeds growth in overall energy use. Although both countries have Annex I commitments under the Kyoto Protocol, current trends in primary energy use indicate growing reliance on fossil-based primary energy for power generation.

The United States is far and away the world’s biggest consumer of electricity, consuming one-third of the world’s total electricity supply. Electricity consumption in the United States is expected to grow at a modest 1.2-percent annual rate from 1995 through 2020. Electricity consumption growth is expected to trail overall economic growth, as is typical for an advanced industrial economy.

Over the forecast period, nuclear power’s role as a producer of electricity in the United States will diminish considerably. Nuclear power, which accounted for 20 percent of all U.S. electricity produced in 1995, is expected to account for only 9 percent in the year 2020 (Figure 79). The last nuclear power plant to be commissioned in the United States was completed in 1996 [30], and there are currently no plans to build any others. Natural gas will largely make up for the shortfall in nuclear production. Natural gas, which accounted for just under 10 percent of electricity production in the United States in 1995, is expected to claim a 22-percent share of the electricity market in 2020. Greater domestic production of natural gas and increased imports from Canada will accommodate the increase in natural gas use as an electricity generation fuel. Coal’s role as an electricity fuel is expected to change very little, accounting for 49 percent of the electricity fuel market in 1995 and 50 percent in 2020.

Figure 79. Energy Consumption for Electricity Generation in the United States, 1995 and 2020

Source: Energy Information Administration, Annual Energy Outlook 1998, DOE/EIA-0383(98) (Washington, DC, December 1997), Table A2.

Future Canadian electricity supply will also depend significantly less on nuclear power and more on natural gas. Canada has an abundance of hydroelectric resources and in 1995 obtained almost 60 percent of its electricity from hydropower, a level that is expected to increase slightly over the forecast period.

In Mexico, electricity demand growth is expected to exceed 4 percent per year as living standards rise and electrification is extended. The course of development in the Mexican economy is expected to resemble that seen in other emerging economies in Latin America and in Asia. Although energy use per capita has risen substantially in Mexico in recent years, electricity consumption is still a small fraction of that enjoyed by its northern neighbors. Mexico is expected to show a relatively rapid rate of electricity consumption growth over the forecast period.

As in the rest of North America, primary fuel use is expected increasingly to favor natural gas. Coal and nuclear power account for relatively little generation in Mexico, which currently relies on oil-fired plants for roughly half of its electricity needs (Figure 80). Both cost and environmental concerns are encouraging increased use of natural gas. The share of electricity fired by natural gas is expected to rise from 11 percent in 1995 to 27 percent in 2020. The rate of increase will be constrained more by infrastructure than by basic resource availability.

Figure 80. Energy Consumption for Electricity Generation in Mexico, 1995 and 2020

Electric utility regulatory reform is underway throughout North America. In the United States and Canada the driving force of reform is the expectation that increased competition will lower costs of electricity supply. In the United States, reforms are being carried out at both the national and State levels. In 1996, the national regulator, the Federal Energy Regulatory Commission, issued Order 888 and Order 889. Order 888 addresses the issue of open access and provides an additional guideline for the recovery of stranded costs [31]. Order 889 requires utilities to establish electronic systems on the availability of transmission capacity. Several States are also implementing reforms. Furthest along are California and several northeastern States. State-led reform efforts have often involved the creation of electricity pools, divestiture of transmission assets, the introduction of independent system operators, the adoption of different forms of pricing, and the unbundling of rates. Overshadowing efforts at electricity reform has been the problem of how to allocate the stranded costs largely associated with previous investments in nuclear power, which despite Order 888 are still yet unresolved.

As the use of natural gas for electricity generation has increased in recent years, there has been a growing integration of the U.S. natural gas and electricity industries. Just in the past few years, several large mergers and acquisitions have taken place between natural gas transmission and distribution companies and electricity companies. These transactions have been driven both by a changing economic environment and by regulatory changes.

Canada is also currently in the midst of several attempts to reform the commonwealth’s electricity sector. Most reform efforts are taking place at the provincial level. Recent reforms are motivated by a desire to reduce Canadian electricity costs. The reforms should also serve to integrate the U.S. and Canadian electricity markets more closely. As with State governments in the United States, 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 created a power pool for spot trading in electricity [32]. In 1996, the U.S. Federal Energy Regulatory Commission (FERC) approved a request by Alberta’s main utility, TransAlta Utility Corporation, to sell power in the United States [33].

Ontario and Quebec are respectively Canada’s first and second largest provinces and home to Canada’s two largest utilities, Ontario Hydro and Hydro Quebec. Ontario Hydro is owned by the provincial government of Ontario. In November 1997, the Ontario provincial government announced its intention to break up—but not privatize—Ontario Hydro along lines of business [34]. Under the proposed plan, the utility would be broken into two separate companies [35]. Electricity generation would become the responsibility of the newly created Electricity Generation Corporation, and transmission and distribution would become the responsibility of the newly created Ontario Electric Services Corporation.

Although the new generation company will continue to be owned by the provincial government, it is to be operated as a commercial enterprise, competing with outside producers, earning a profit, and paying taxes. The transmission and distribution company is expected to continue to be a regulated monopoly. Both the transmission and distribution segments are to provide open access to outside producers. An independent system operator is to be established as a “separate publicly controlled Crown Corporation to oversee operations of the new system and to ensure that customers receive access to electricity at reasonable prices and in the most efficient way possible” [35]. As in the United States, stranded costs largely associated with past investments in nuclear power have severely hampered Ontario’s attempts at electricity reform.

Hydro Quebec has targeted the U.S. market for future sales growth. Hydro Quebec currently owns Vermont Gas and has signed a deal with Enron to market electricity in the Northeast while selling Enron’s gas in Quebec. In April 1997, Hydro Quebec petitioned the FERC to sell electricity in the United States. In return, it would allow U.S. competitors to wheel electricity into Quebec. In November 1997, Hydro Quebec received FERC approval to sell power in the United States at market-based rates.

In Mexico, regulatory reform is designed to enhance the availability of investment capital to fund industry expansion. Until recently, foreign investment in energy-related activities was prohibited, and it is still prohibited in most upstream petroleum activities. However, regulations are being liberalized, especially for power generation and natural gas transmission and distribution. As a consequence, a variety of cogeneration and independent power generation projects have been proposed by U.S. sponsors, and some are already under construction.

Electricity consumption among Western European nations in IEO98 reference case is expected to grow by only 2.4 percent annually from 1995 through 2020. The moderate growth in electricity use reflects the region’s advanced state of economic development.

Of all regions, Western Europe relies most heavily on nuclear power as a source of electricity supply. Nuclear power accounts for a third of Western Europe’s electricity supply’ largely because France is the second largest producer of nuclear electricity after the United States. Coal ranks second as a source of electricity generation in Western Europe, followed by renewables (primarily hydropower), natural gas, and oil.

In future years, Western Europe is expected to reduce its reliance on nuclear power and, to a lesser extent, on coal- and oil-fired generation (Figure 81). Natural gas use is expected to grow. In 2020, the nuclear share of the electricity market is expected to be about one-fifth of the total. Although use of coal as a generation fuel is expected to increase over the forecast period, its share of the overall electricity fuels market is also expected to decline, to 21 percent from 27 percent in 1995. In recent years, coal production in the United Kingdom and Germany has fallen off dramatically. In the United Kingdom, the reduction is largely due to the coal industry’s privatization, the removal of coal subsidies, and the privatization of the electricity industry. In Germany, coal subsidies have been removed much more slowly, but German reunification and the retirement of a large number of former East Germany’s obsolescent coal-fired electricity plants, have resulted in a sharp drop in coal demand. The growing availability of natural gas imports from the former Soviet Union, Norway, and North Africa, in concert with environmental considerations, has encouraged greater use of gas as a fuel for electricity generation. Recent advances in gas-fired electricity generation technology that reduce overall capital requirements have also encouraged the switch to gas.

Figure 81. Energy Consumption for Electricity Generation in Western Europe, 1995 and 2020

Europe’s electricity industry is likely to become more integrated in the future. In 1997, the European Parliament adopted a directive with the intent to provide independent producers with greater access to other countries’ power networks [36]. Led by the United Kingdom, several Western European countries have undertaken important electricity reforms. To varying degrees these reforms have reduced government oversight and increased the role of market forces in balancing electricity supply and demand. Currently, Sweden and Norway operate a joint electricity pool, and Finland is scheduled to join the pool in early 1998.

The United Kingdom first began to privatize its electricity industry in 1990 and completed the final phase of privatization in 1996. Privatization of electricity in the United Kingdom occurred in the context of a wholesale privatization of several other state-owned industries. Through 1995, the treasury has raised more than $95 billion in revenue from privatization [37]. The United Kingdom’s electricity framework has become a model for electricity reforms elsewhere, most notably, in Argentina and Australia. Motivating the UK’s effort at electricity reform was the belief that the industry could be made more competitive through deregulation and privatization.

Other European nations have also implemented major electricity reform in recent years, but not all have privatized. Most nations have generally maintained state ownership while introducing market-oriented reforms. Major electricity reform efforts have been undertaken by Scandinavian nations. Sweden, for example, has moved toward competitive generation and distribution markets in local, regional, and national networks. In recent years, there have been several foreign investments in Sweden’s electricity sector. In 1996, Norway’s Statkraft purchased a share of Sweden’s Sydkraft for $179 million [38]. In addition to the Sydkraft purchase, a 25-percent share of Graninge was purchased by Electricite de France and a 12-percent share by Germany’s Preussen Elecktra [39]. Imatran Voima Oy (IVO), the state-owned Finnish power company, purchased a 50-percent share of Gullspangs Fraft, another Swedish utility [40].

In general, liberalization of regulatory rules throughout Europe is eroding national boundaries for industrial operation and for investment development strategies. Thus, throughout the area, the utility sector has become the potential focus of rivalry for a wide range of enterprises located in Europe and beyond. In Italy, for example, ENEL, the state-owned electricity company, is simultaneously being privatized while entering into investment alliances with two U.S. companies, Enron and Entergy. In Portugal, several foreign companies have invested in the country’s electricity industry, include EdF (of France), Endesa (of Spain), National Power (UK), and PowerGen (UK).

Electricite de France (EdF), Europe’s largest electricity company, is state owned. In recent years, it has sought to evolve from a national utility to an international energy company. As a consequence, it is involved in power projects in Argentina, Hungary, the Ivory Coast, Italy, Poland, Portugal, Spain, and Sweden. Similarly, Endesa, Spain’s largest utility, has recently acquired electricity assets in Argentina, Chile, Costa Rica, El Salvador, Germany, Guatemala, Morocco, Nicaragua, Panama, Peru, and Venezuela [41].

U.S. companies are similarly evolving into international enterprises. The Energy Policy Act of 1992 (EPACT) liberalized the rules governing U.S. utility investment in electricity assets abroad, leading to a surge in investment overseas by U.S. electric utilities (Figure 82). Since 1992, U.S. companies have acquired 7 of the 12 electricity distribution companies in the United Kingdom. In theAustralian state of Victoria, U.S. companies haveacquired interests in all of the five electricity distribution companies, three of the state’s five recently privatized electricity generation companies, and the state’s transmission network. U.S. electricity companies have also made sizable electricity investments in several developing countries, including Argentina, Bolivia, Brazil, Columbia, India, and Pakistan.

Note: These utilities include, in addition to electricity, natural gas distribution and sanitary services. However, the sharp upward climb in investments from 1994 through 1996 is almost entirely due to overseas electric utility investments by U.S. companies.
Source: U.S. Department of Commerce, Bureau of Economic Analysis, Survey of Current Business (Washington, DC, various issues).

Japan is Asia’s largest economy and its biggest consumer of electricity. Japan is the fourth largest electricity consumer in the world. Over the 1995 to 2020 forecast period, Japan is expected to show a relatively moderate electricity consumption growth rate of 1.8 percent per year, consuming more of all electricity fuels except for oil through 2020. Growth in natural gas consumption and coal and will outpace growth in the use of nuclear power and renewables (Figure 83). Japan’s use of oil as an electricity fuel is expected to decline as its older oil-fired generation plants, many of which were built before the 1973 oil price shock, are retired [5, p. 163]. Japan is one of the few nations currently expanding its use of nuclear power, which now accounts for roughly one-third of its electricity supply.

In recent years, Australia and New Zealand have achieved relatively high rates of economic growth among the industrialized economies. Electricity demand in Australasia is expected to average nearly 3.2-percent annual growth between 1995 and 2020. Australia has one of the world’s most efficient coal industries, and coal accounts for 92 percent of the fuel input to its Australia’s electricity industry. In contrast, New Zealand relies more heavily on hydroelectricity. Coal and hydropower are expected to continue to be the dominant sources of electricity for the two countries over the forecast period (Figure 84).

Figure 83. Energy Consumption for Electricity Generation in Japan, 1995 and 2020

The winds of regulatory change are blowing in Asia as well. The electricity industry in Japan is highly concentrated and dominated by 10 vertically integrated regional electric utilities [5, p. 155]. Japan, like the United States, has long had an electricity industry that was privately owned. Utility companies supply 75 percent of Japan’s electric power, the remainder being supplied by the national organizations responsible for the supply of nuclear power and large-scale hydro and thermal power. The 10 vertically integrated regional electricity companies jointly own and operate Japan’s national electricity transmission system [5, p. 155].

Figure 84. Energy Consumption for Electricity Generation in Australasia, 1995 and 2020

Currently, Japan has some of the highest electricity prices in the world. As a result, Japan is attempting to reform its electricity industry to increase competition. The goal of the effort is to cut electricity prices so that by the year 2001 they are comparable with those in other industrialized nations [42]. Japan has recently allowed independent power producers access to the grid and has encouraged regional utilities to purchase power directly from them [43]. Japan is also currently undertaking a study of its regulatory structure and the regulatory structures of other industrial nations to see what regulatory reform measures would best increase competition [44].

Since the early 1990s, Australia has undergone a series of national and state-sponsored electricity reform initiatives. The national government’s reform process began in 1991, with a commitment to a completely competitive power market by 1999. Regulatory reform was also introduced, allowing for competition in generation and rate-cap regulation (rather than rate-of-return regulation) in transmission and distribution. Electricity marketing is currently being treated as a separate segmental unit and is gradually being deregulated.

Like the United States, Australia has a federal system of government. Also as in the United States, electricity reforms in Australia embody both national and state efforts. Thus far, the state of Victoria (Australia’s second most populous state) has been the most aggressive in privatizing its state-owned energy industries. In 1995, Victoria began to privatize its electric power industry, in part in a manner modeled after the UK electric industry privatization program. Prior to privatization, the Victoria state government merged 29 electricity distribution companies into 5 companies, while splitting the state generating company into five enterprises, each with a power station. Since 1995, it has raised a total of $17 billion through the privatization of electricity assets [45].

There have also been some privatization efforts outside Victoria. Northern States Power (of the United States) purchased a 37-percent equity stake for its services in rehabilitating and operating the 1,680-megawatt Gladstone Plant in Queensland [46, pp. 47-48]. SCE Corporation (also of the United States), through its Mission Energy Corporation subsidiary, plans to build a $111 million power plant in Western Australia. Japan’s Sithe Energies is constructing Australia’s largest cogeneration plant, a 175-megawatt gas-fired plant near Sydney.

New Zealand started to privatize its electric power industry in 1987 in the midst of an ambitious attempt to introduce free-market economic reforms. An electricity transmission corporation was created in 1993, and monopolies in local distribution and retailing were eliminated. In 1995, the New Zealand government issued a new electricity policy designed to create a competitive power market. Over the past few years, a number of New Zealand’s electric utilities have been purchased by U.S. utilities. IES Industries took a minority interest in Powerco Limited and Central Power Limited [46, pp. 47-48]. Further, Utilicorp purchased 20 percent of the common stock in Power New Zealand, New Zealand’s second largest electric distribution company.

The Russian economy, which accounts for more than half of the economic output for the EE/FSU region, appears to have bottomed out in 1996 and to have shown slight positive growth in 1997. Russia is expected to move to a 3- to 5-percent economic growth path through the year 2001 [47]. Electricity consumption in the EE/FSU region is expected to follow a similar recovery path. For the 1995 through 2020 forecast period, electricity consumption is expected to grow at an annual rate of 2.2 percent for Eastern Europe and 1.2 percent for the FSU.

Energy resource availability differs markedly in Eastern Europe and the FSU. As a result, while Eastern Europe relies on its ample supplies of coal for nearly two-thirds of its electricity fuel supply, the FSU relies for almost half of its electricity fuel supply on natural gas, which it has in abundance. In 2020, in contrast, coal is expected to account for only about 40 percent of Eastern Europe’s generation fuel, with the difference made up by natural gas and renewables (Figure 85). Both the availability of increased natural gas to Eastern Europe from the FSU, and the desire to reduce severe air pollution problems in the area have been driving this trend. The FSU’s consumption of natural gas as a generating fuel also is projected to grow, largely in response to environmental concerns, while both coal and nuclear power generation are expected to decline in absolute and relative terms.

The electric power industries of Eastern Europe and the FSU are very different from those in other parts of the world. In much of the developing world, electricity capacity is currently straining to keep pace with rapid increase in demand. In the developed world, electricity is a mature industry and future expansion is expected to be incremental. In contrast, in Eastern Europe and the FSU, electricity has been an overdeveloped industry—with no capacity shortage—but an industry suffering from outdated technology. Electricity in Eastern Europe was also a major source of pollution. As a result, future electricity investments in EE/FSU countries will to a large extent be directed at upgrading their electricity industries to industrial world standards.

Figure 85. Energy Consumption for Electricity Generation in Eastern Europe, 1995 and 2020

Several of the countries of Eastern Europe have attempted to reform their electricity industries, motivated in part by the desire to ensure availability of the foreign fu

Region	History		Projections
Region	1990	1995	2000	2005	2010	2015	2020	Average Annual Percent Change, 1995-2020
Industrialized Countries	6,299	7,113	7,968	8,804	9,663	10,497	11,349	1.9
United States	2,713	3,163	3,318	3,601	3,877	4,115	4,308	1.2
EE/FSU	1,908	1,552	1,509	1,685	1,881	2,056	2,248	1.5
Developing Countries	2,224	3,102	3,886	5,007	6,220	7,684	9,548	4.6
Developing Asia	1,268	1,912	2,489	3,283	4,160	5,255	6,665	5.1
China	551	881	1,076	1,476	1,975	2,657	3,574	5.8
Other Developing Asia	717	1,030	1,413	1,807	2,185	2,598	3,091	4.5
Total World	10,431	11,767	13,363	15,495	17,764	20,237	23,145	2.7
Note: EE/FSU = Eastern Europe and the former Soviet Union. Sources: History: Energy Information Administration (EIA), International Energy Annual 1996, DOE/EIA-0219(96) (Washington, DC, February 1998). Projections: EIA, World Energy Projection System (1998).

Region and Fuel	1995	2000	2005	2010	2015	2020
Industrialized	77.4	85.8	91.5	97.0	102.0	106.2
Oil	5.2	5.5	5.4	5.4	5.5	5.6
Natural Gas	8.1	10.8	14.0	17.3	21.2	24.9
Coal	27.6	30.4	31.8	33.2	34.5	35.4
Nuclear	19.4	20.2	19.5	18.7	16.8	14.8
Renewables	17.2	18.8	20.7	22.5	24.0	25.6
EE/FSU	24.8	26.2	28.8	30.8	32.2	31.6
Oil	2.8	2.7	3.1	3.6	4.1	4.6
Natural Gas	9.5	10.7	12.3	13.9	15.2	16.8
Coal	6.8	6.7	6.7	6.2	5.3	5.0
Nuclear	2.7	3.0	3.1	3.1	2.9	0.0
Renewables	3.0	3.1	3.6	4.0	4.6	5.1
Developing	37.1	46.7	58.5	70.8	84.7	101.7
Oil	5.2	6.1	7.3	8.5	9.8	11.4
Natural Gas	4.6	6.5	8.8	11.6	14.4	17.8
Coal	16.3	20.7	25.8	31.9	39.4	46.5
Nuclear	1.2	1.5	2.4	3.2	3.6	6.5
Renewables	9.9	11.9	14.2	15.8	17.5	19.5
Total World	139.4	158.7	178.9	198.6	218.9	239.6
Oil	13.1	14.3	15.8	17.5	19.5	21.6
Natural Gas	22.2	28.1	35.2	42.8	50.9	59.5
Coal	50.7	57.9	64.3	71.2	79.2	86.9
Nuclear	23.3	24.7	25.0	24.9	23.3	21.3
Renewables	30.1	33.8	38.6	42.4	46.0	50.2
Note: EE/FSU = Eastern Europe and the former Soviet Union. Sources: 1995: Derived from Energy Information Administration (EIA), International Energy Annual 1996, DOE/EIA-0219(96) (Washington, DC, February 1998). Projections: EIA, World Energy Projection System (1998).

Investment Type	North America	Latin America	Western Europe	China	OECD Pacific Rim	East Asia	South Asia	Central and Eastern Europe	FSU	Middle East	Africa	World Total
Generation
Solid Fuel	94	22	102	222	51	100	71	19	24	2	27	734
Natural Gas	32	23	89	1	14	41	13	10	33	27	16	298
Oil	1	8	1	0	0	1	1	7	2	2	6	29
Nuclear	6	3	8	18	39	21	6	3	26	0	0	129
Renewable	17	52	15	67	5	6	48	5	13	3	5	235
Subtotal	149	108	215	308	108	169	139	44	98	34	54	1,426
Other Investments
Transmission	14	42	20	31	10	28	23	3	14	4	12	200
Distribution	54	36	78	84	39	61	60	11	30	10	19	480
General	14	17	20	43	10	17	21	6	14	5	7	173
Subtotal	82	94	118	156	59	105	103	19	58	18	38	854
Total	231	202	333	467	167	275	242	63	156	52	91	2,279
Annual Average	15	13	25	31	11	18	16	4	10	3	6	152
Note: North America includes Canada and the United States; Western Europe includes European Union countries, Finland, Switzerland, Iceland, Norway, and Turkey. OECD Pacific Rim includes Australia, Japan, and New Zealand. Central and Eastern Europe includes Albania, Bulgaria, Czech Republic, Hungary, Poland, Romania, Slovakia, former Yugoslavia. East Asia includes Brunei, Hong Kong, Indonesia, Kampuchea, Laos, Malaysia, North Korea, Papua New Guinea, Philippines, Singapore, Republic of Korea, Taiwan, Thailand, Vietnam, Pacific Islands, Afghanistan, Mongolia. South Asia includes Pakistan, India, Bangladesh, Nepal, Sri Lanka. Latin America includes Mexico and all South and Central American nations, as well as the nations of the Caribbean. Middle East includes Israel, Jordan, Iran, Iraq, Kuwait, Lebanon, Oman, Qatar, Saudi Arabia, Syria, United Arab Emirates, and Yemen. Source: Estimates by Resource Dynamics, based on International Energy Agency, World Energy Outlook 1995 (Paris, France, 1995), Capacity Constraints Scenario, base case.

Report#: DOE/EIA-0484(98)

Electricity