International Energy Outlook 2011
Release Date: September 19, 2011 | Next Scheduled Release Date: April 2013 | Report Number: DOE/EIA-0484(2011)
Electricity
Overview
figure data In the IEO2011 Reference case, electricity supplies an increasing share of the world's total energy demand, and electricity use grows more rapidly than consumption of liquid fuels, natural gas, or coal in all end-use sectors except transportation. From 1990 to 2008, growth in net electricity generation outpaced the growth in delivered energy consumption (3.0 percent per year and 1.8 percent per year, respectively). World demand for electricity increases by 2.3 percent per year from 2008 to 2035 and continues to outpace growth in total energy use throughout the projection period (Figure 72).
World net electricity generation increases by 84 percent in the Reference case, from 19.1 trillion kilowatthours in 2008 to 25.5 trillion kilowatthours in 2020 and 35.2 trillion kilowatthours in 2035 (Table 11). Although the 2008-2009 global economic recession slowed the rate of growth in electricity use in 2008 and resulted in negligible change in electricity use in 2009, worldwide electricity demand increased by an estimated 5.4 percent in 2010, with non-OECD electricity demand alone increasing by an estimated 9.5 percent.
In general, projected growth in OECD countries, where electricity markets are well established and consumption patterns are mature, is slower than in non-OECD countries, where a large amount of demand goes unmet at present. The electrification of historically off-grid areas plays a strong role in projected growth trends. The International Energy Agency estimates that 21 percent of the world's population did not have access to electricity in 2009—a total of about 1.4 billion people [207]. Regionally, sub-Saharan Africa is worst off: more than 69 percent of the population currently remains without access to power. With strong economic growth and targeted government programs, however, electrification can occur quickly. In Vietnam, for example, the government's rural electrification program increased access to power from 51 percent of rural households in 1996 to 95 percent at the end of 2008 [208].
Non-OECD nations consumed 47 percent of the world's total electricity supply in 2008, and their share of world consumption is poised to increase over the projection period. In 2035, non-OECD nations account for 60 percent of world electricity use, while the OECD share declines to 40 percent (Figure 73). Total net electricity generation in non-OECD countries increases by an average of 3.3 percent per year in the Reference case, led by annual increases averaging 4.0 percent in non-OECD Asia (including China and India) from 2008 to 2035 (Figure 74). In contrast, total net generation in the OECD nations grows by an average of only 1.2 percent per year from 2008 to 2035.
figure data The outlook for total electricity generation is largely the same as projected in last year's report. However, the projected mix of generation by fuel in the IEO2011 Reference case has changed. The largest difference between the two outlooks is for natural-gas-fired generation—which is 22 percent higher in this year's outlook in 2035. The more optimistic outlook for generation from natural gas-fired power plants is a result of a reassessment of available gas supplies. This year's IEO includes an upward revision in potential gas supplies, largely because of increases in unconventional supplies of natural gas in the United States and other parts of the world. The increase in the natural gas share of generation to a large extent displaces coal-fired generation, which is 14 percent lower than in last year's report. In addition, projected nuclear power generation is 9 percent higher, and generation from renewable sources is 3 percent higher in 2035 than projected in IEO2010. The nuclear projection does not reflect consideration of policy responses to Japan's Fukushima Daiichi nuclear disaster, which are likely to reduce projected nuclear generation from both existing and new plants. Liquids-fired generation, in contrast, is 3 percent lower in this year's projection.
The IEO2011 projections do not incorporate assumptions related to limiting or reducing greenhouse gas emissions, such as caps on carbon dioxide emissions levels or taxes on carbon dioxide emissions. However, the Reference case does incorporate current national energy policies, such as the European Union's "20-20-20" plan and its member states' nuclear policies; China's wind capacity targets; and India's National Solar Mission.28
Electricity supply by energy source
The worldwide mix of primary fuels used to generate electricity has changed a great deal over the past four decades. Coal continues to be the fuel most widely used for electricity generation, although generation from nuclear power increased rapidly from the 1970s through the 1980s, and natural-gas-fired generation grew rapidly in the 1980s and 1990s. The use of oil for electricity generation has been declining since the mid-1970s, when oil prices rose sharply.
The high fossil fuel prices recorded between 2003 and 2008, combined with concerns about the environmental consequences of greenhouse gas emissions, have renewed interest in the development of alternatives to fossil fuels—specifically, nuclear power and renewable energy sources. In the IEO2011 Reference case, long-term prospects continue to improve for generation from both nuclear and renewable energy sources—primarily supported by government incentives. Renewable energy sources are the fastest-growing sources of electricity generation in the IEO2011 Reference case, with annual increases averaging 3.1 percent per year from 2008 to 2035. Natural gas is the second fastest-growing generation source, increasing by 2.6 percent per year, followed by nuclear power at 2.4 percent per year. Although coal-fired generation increases by an annual average of only 1.9 percent over the projection period, it remains the largest source of generation through 2035. However, the outlook for coal, in particular, could be altered substantially by any future national policies or international agreements aimed at reducing or limiting the growth of greenhouse gas emissions.
Coal
figure dataIn the IEO2011 Reference case, coal continues to fuel the largest share of worldwide electric power production by a wide margin (Figure 75). In 2008, coal-fired generation accounted for 40 percent of world electricity supply; in 2035, its share decreases to 37 percent, as renewables, natural gas, and nuclear power all are expected to advance strongly during the projection and displace the need for coal-fired-generation in many parts of the world. World net coal-fired generation grows by 67 percent, from 7.7 trillion kilowatthours in 2008 to 12.9 trillion kilowatthours in 2035.
The electric power sector offers some of the most cost-effective opportunities for reducing carbon dioxide emissions in many countries. Coal is both the world's most widely used source of energy for power generation and also the most carbon-intensive energy source. If a cost, either implicit or explicit, is applied to carbon dioxide emissions in the future, there are several alternative technologies with no emissions or relatively low levels of emissions that currently are commercially proven or under development and could be used to displace coal-fired generation.
Natural gas
Over the 2008 to 2035 projection period, natural-gas-fired electricity generation increases by 2.6 percent per year. Generation from natural gas worldwide increases from 4.2 trillion kilowatthours in 2008 to 8.4 trillion kilowatthours in 2035, but the total amount of electricity generated from natural gas continues to be less than one-half the total for coal, even in 2035. Natural-gas-fired combined-cycle technology is an attractive choice for new power plants because of its fuel efficiency, operating flexibility (it can be brought online in minutes rather than the hours it takes for coal-fired and some other generating capacity), relatively short planning and construction times, relatively low emissions, and relatively low capital costs.
Prospects for natural gas have improved substantially relative to last year's outlook, in large part because of the revised expectations for unconventional sources of natural gas, especially shale gas,29 both within the United States and globally. The additional resources will allow natural gas supplies outside North American to be used as LNG to supply markets that have few domestic resources. As a result, natural gas markets are expected to remain well supplied and prices relatively low in the mid-term, and many nations are expected to turn to natural gas, rather than more expensive or more carbon-intensive sources of electricity, to supply their future power needs.
Liquid fuels and other petroleum
With world oil prices projected to return to relatively high levels, reaching $125 per barrel (in real 2009 dollars) in 2035, liquid fuels are the only energy source for power generation that does not grow on a worldwide basis. Nations are expected to respond to higher oil prices by reducing or eliminating their use of oil for generation—opting instead for more economical sources of electricity, including natural gas and nuclear. Even in the resource-rich Middle East, there is an effort to reduce the use of petroleum liquids for generation in favor of natural gas and other resources, in order to maximize revenues from oil exports. Worldwide, generation from liquid fuels decreases by 0.9 percent per year, from 1.0 trillion kilowatthours in 2008 to 0.8 trillion kilowatthours in 2035.
Nuclear power
Electricity generation from nuclear power worldwide increases from 2.6 trillion kilowatthours in 2008 to 4.9 trillion kilowatthours in 2035 in the IEO2011 Reference case, as concerns about energy security and greenhouse gas emissions support the development of new nuclear generating capacity. In addition, world average capacity utilization rates have continued to rise over time, from about 65 percent in 1990 to about 80 percent today, with some increases still anticipated in the future. Finally, most older plants now operating in OECD countries and in non-OECD Eurasia probably will be granted extensions to their operating licenses.
While IEO2011 was in preparation, a large earthquake and tsunami struck the northeast coast of Japan, severely damaging nuclear power plants at Fukushima Daiichi [209]. Although the full extent of the damage remains unclear, the event is almost certain to have a negative impact on Japan's nuclear power industry, at least in the short term, and it is also likely to reduce projected nuclear generation from both existing and new facilities as governments formulate their policy responses to the disaster. The IEO2011 Reference case was not revised to take the March 2011 natural disaster into account, but the uncertainty associated with nuclear power projections for Japan and for the rest of the world has increased.
A number of issues could slow the development of new nuclear power plants. In many countries, concerns about plant safety, radioactive waste disposal, and nuclear material proliferation could hinder plans for new installations. Moreover, the explosions at Japan's Fukushima Daiichi nuclear power plant in the aftermath of the March 2011 earthquake and tsunami could have long-term implications for the future of world nuclear power development in general. Even China—where large increases in nuclear capacity have been announced and are anticipated in the IEO2011 Reference case—has indicated that it will halt approval processes for all new reactors until the country's nuclear regulator completes a "thorough safety review"—a process that could last for as long as a year [210]. Germany, Switzerland, and Italy already have announced plans to phase out or cancel all their existing and future reactors, indicating that some slowdown in the growth of nuclear power should be expected. High capital and maintenance costs may also keep some countries from expanding their nuclear power programs. Finally, a lack of trained labor resources, as well as limited global capacity for the manufacture of technological components, could keep national nuclear programs from advancing quickly.
IEO2011 provides the status of international radioactive waste disposal programs in the box on page , which identifies the most common approaches to radioactive waste disposal and, where available, their costs and schedules. Storage and disposal costs remain an important life-cycle consideration in the decision to add nuclear generation capacity. Future IEOs will address supply chain uncertainties as well as uncertainties related to construction costs and uranium enrichment. Despite such uncertainties, the IEO2011 Reference case projects continued growth in world nuclear power generation. The projection for nuclear electricity generation in 2035 is 9 percent higher than the projection published in last year's IEO.
On a regional basis, the Reference case projects the strongest growth in nuclear power for the countries of non-OECD Asia (Figure 76), averaging 9.2 percent per year from 2008 to 2035, including increases of 10.3 percent per year in China and 10.8 percent per year in India. China leads the field with nearly 44 percent of the world's active reactor projects under construction in 2011 and is expected to install the most nuclear capacity over the period, building 106 gigawatts of net generation capacity by 2035 [211]. Outside Asia, nuclear generation grows the fastest in Central and South America, where it increases by an average of 4.2 percent per year. Nuclear generation worldwide increases by 2.4 percent per year in the Reference case.
To address the uncertainty inherent in projections of nuclear power growth over the long term, a two-step approach is used to formulate the outlook for nuclear power. In the short term (through 2020), projections are based primarily on the current activities of the nuclear power industry and national governments. Because of the long permitting and construction lead times associated with nuclear power plants, there is general agreement among analysts on which nuclear projects are likely to become operational in the short term. After 2020, the projections are based on a combination of announced plans or goals at the country and regional levels and consideration of other issues facing the development of nuclear power, including economics, geopolitical issues, technology advances, environmental policies, supply chain issues, and uranium availability.
Hydroelectric, wind, geothermal, and other renewable generation
Renewable energy is the fastest-growing source of electricity generation in the IEO2011 Reference case. Total generation from renewable resources increases by 3.1 percent annually, and the renewable share of world electricity generation grows from 19 percent in 2008 to 23 percent in 2035. More than 82 percent of the increase is in hydroelectric power and wind power. The contribution of wind energy, in particular, has grown swiftly over the past decade, from 18 gigawatts of net installed capacity at the end of 2000 to 121 gigawatts at the end of 2008—a trend that continues into the future. Of the 4.6 trillion kilowatthours of new renewable generation added over the projection period, 2.5 trillion kilowatthours (55 percent) is attributed to hydroelectric power and 1.3 trillion kilowatthours (27 percent) to wind (Table 13).
Although renewable energy sources have positive environmental and energy security attributes, most renewable technologies other than hydroelectricity are not able to compete economically with fossil fuels during the projection period except in a few regions or in niche markets. Solar power, for instance, is currently a "niche" source of renewable energy, but it can be economical where electricity prices are especially high, where peak load pricing occurs, or where government incentives are available. Government policies or incentives often provide the primary economic motivation for construction of renewable generation facilities.
Wind and solar are intermittent technologies that can be used only when resources are available. Once wind or solar facilities are built, however, their operating costs generally are much lower than the operating costs for fossil fuel-fired power plants. However, high construction costs can make the total cost to build and operate renewable generators higher than those for conventional plants. The intermittence of wind and solar can further hinder the economic competitiveness of those resources, because they are not operator-controlled and are not necessarily available when they would be of greatest value to the system. Although the technologies currently are not cost-effective, the use of energy storage (such as hydroelectric pumped storage, compressed air storage, and batteries) and the dispersal of wind and solar generating facilities over wide geographic areas could mitigate many of the problems associated with intermittency.
Changes in the mix of renewable fuels used for electricity generation differ between the OECD and non-OECD regions in the IEO2011 Reference case. In the OECD nations, most of the hydroelectric resources that are both economical to develop and also meet environmental regulations already have been exploited. With the exceptions of Canada and Turkey, there are few large-scale hydroelectric projects planned for the future. As a result, most renewable energy growth in OECD countries comes from nonhydroelectric sources, especially wind and biomass. Many OECD countries, particularly those in Europe, have government policies, including feed-in tariffs (FITs),30 tax incentives, and market share quotas, that encourage the construction of such renewable electricity facilities.
In non-OECD countries, hydroelectric power is expected to be the predominant source of renewable electricity growth. Strong growth in hydroelectric generation, primarily from mid- to large-scale power plants, is expected in China, India, Brazil, and a number of nations in Southeast Asia, including Malaysia and Vietnam. Growth rates for wind-powered generation also are high in non-OECD countries. The most substantial additions to electricity supply generated from wind power are expected for China.
The IEO2011 projections for renewable energy sources include only marketed renewables. Non-marketed (noncommercial) biomass from plant and animal resources, while an important source of energy, particularly in the developing non-OECD economies, is not included in the projections, because comprehensive data on its use are not available. For the same reason, off-grid distributed renewables—renewable energy consumed at the site of production, such as off-grid photovoltaic (PV) panels—are not included in the projections.
Global efforts to manage radioactive waste from nuclear power plants
Prospects for nuclear power generation have improved in recent years, as many nations have attempted to diversify the fuel mix for their power generation sectors away from fossil fuels while also addressing concerns about greenhouse gas emissions. Nuclear power generators do not emit the greenhouse gases produced by fossil fuel generators. However, they do produce radioactive waste that must be managed.
In the IEO2011 Reference case, nuclear electricity generation nearly doubles from 2008 to 2035. Such an increase would be accompanied by significant increases in the accumulation of spent fuel rods and other nuclear waste in countries with nuclear power plants. Managing nuclear waste is a long-term issue. Governments must protect the public and environment from exposure to highly radioactive materials for hundreds or thousands of years into the future. And although there is general international agreement about how waste disposal should be approached, implementing management plans has proven to be politically complicated. As a result, few of the countries that currently have nuclear generation programs in operation have solidified their long-term plans for managing nuclear waste.
There are two forms of nuclear waste: spent nuclear fuel (SNF) and high-level radioactive waste (HLW), which results from the processing of SNF for re-use in nuclear power reactors. If SNF is not reprocessed, the normal management approach is long-term storage, either on site at nuclear power stations or at centralized interim storage facilities followed by deep geological disposal in a repository. This approach to waste management is known as the "direct disposal option."
In the United States, SNF is stored at the country's 104 operating nuclear reactors. In Sweden it is stored at a single site, the Central Interim Storage Facility for Spent Nuclear Fuel at Oskarshamn. France reprocesses its spent nuclear fuel to recover plutonium and uranium for use in fabricating new mixed-oxide fuel for its nuclear power plants, and it has successfully commercialized the process. Reprocessing greatly reduces the volume of nuclear waste for which disposal is necessary, but some components of the HLW cannot be recycled and must be vitrified (solidified in a glass-like matrix), stored, and eventually placed in a repository.
In selecting a nuclear waste management approach, several countries, including the United States, have opted for direct disposal in order to reduce the risk of nuclear weapons proliferation that is associated with the reprocessing option. The International Atomic Energy Agency's (IAEA) Joint Convention on the Safety of Spent Fuel Management and on the Safety of Radioactive Waste Management, which entered into force on June 18, 2001, recognizes that at the technical level disposal of nuclear waste in a deep geological repository ultimately represents the safest method of managing nuclear waste [212]. Many countries are investigating geological disposal and are committed to the approach in principle, including the 13 countries that produce more than 80 percent of the world's nuclear power: Belgium, Canada, China, Finland, France, Germany, Japan, South Korea, Spain, Sweden, Switzerland, the United Kingdom, and the United States.
Only a few countries provide reliable data on the costs of geological disposal. Their estimates generally are contained in national reports to the IAEA under the provisions of the Joint Convention or, alternatively, in published accounts of total life-cycle costs for their nuclear power systems. Disposal costs are affected by such factors as the type and quantity of waste that requires disposal, the design of the waste repository and its period of operation, and the country's waste management strategy (direct disposal or reprocessing). National cost estimates for the management of spent nuclear fuel vary widely:
- In the United States, a facility with storage capacity for 70,000 metric tons of heavy metal (MTHM) is estimated to cost $96.18 billion (2007 dollars) or about $707 per kilogram of heavy metal [213].
- In Japan a 29,647 MTHM storage facility is estimated to cost $25 billion (2007 dollars) or about $851 per kilogram of heavy metal [214].
- In Sweden a 9,741 MTHM storage facility is estimated to cost $3.4 billion (2007 dollars) or about $350 per kilogram of heavy metal [215].
Regional electricity outlooks
In the IEO2011 Reference case, the highest growth rates for electricity generation are in non-OECD nations, where strong economic growth and rising personal incomes drive the growth in demand for electric power. In OECD countries—where electric power infrastructures are relatively mature, national populations generally are expected to grow slowly or decline, and GDP growth is slower than in the developing nations—demand for electricity grows much more slowly. Electricity generation in non-OECD nations increases by 3.3 percent per year in the Reference case, as compared with 1.2 percent per year in OECD nations.
OECD electricity
Americas
The countries of the OECD Americas (the United States, Canada, Chile, and Mexico) currently account for the largest regional share of world electricity generation, with 26 percent of the total in 2008. That share declines as non-OECD nations experience fast-paced growth in demand for electric power. In 2035, the nations of the OECD Americas together account for only 19 percent of the world's net electric power generation.
The United States is by far the largest consumer of electricity in the region (Figure 77). U.S. electricity generation—including both generation by electric power producers and on-site generation—increases slowly, at an average annual rate of 0.8 percent from 2008 to 2035. Canada, like the United States, has a mature electricity market, and its generation increases by 1.4 percent per year over the same period. Mexico/Chile's electricity generation grows at a faster rate—averaging 3.2 percent per year through 2035—reflecting the current less-developed state of their electric power infrastructure (and thus the greater potential for expansion) relative to Canada and the United States.
There are large differences in the mix of energy sources used to generate electricity in the four countries that make up the OECD Americas, and those differences are likely to become more pronounced in the future (Figure 78). In the United States, coal is the leading source of energy for power generation, accounting for 48 percent of the 2008 total. In Canada, hydroelectricity provided 60 percent of the nation's electricity generation in 2008. Most of Mexico/Chile's electricity generation is currently fueled by petroleum-based liquid fuels and natural gas, which together accounted for 66 percent of total generation in 2008. The predominant fuels for generation in the United States and Canada are expected to lose market share by 2035, although electricity generation continues to be added. Coal-fired generation declines to 43 percent of the U.S. total, and hydropower falls to 54 percent of Canada's total in 2035. In contrast, in Mexico/Chile, natural-gas-fired generation increases from 48 percent of the total in 2008 to 58 percent in 2035.
Generation from renewable energy sources in the United States increases in response to requirements in more than half of the 50 States for minimum renewable shares of electricity generation or capacity. Although renewable generation in 2035 in the IEO2011 Reference case is 17 percent lower than in last year's outlook (due to a variety of factors, including lower electricity demand, a significant increase in the availability of shale gas, and revised technology and policy assumptions), the share of renewable-based generation is expected to grow from 9.7 percent in 2008 to 14.3 percent in 2035. The projection for electricity generation from other renewables sources also has dropped, as a result of lower expectations for biomass co-firing. U.S. Federal subsidies for renewable generation are assumed to expire as enacted. If those subsidies were extended, however, a larger increase in renewable generation would be expected.
Electricity generation from nuclear power plants accounts for 16.9 percent of total U.S. generation in 2035 in the IEO2011 Reference case. Title XVII of the U.S. Energy Policy Act of 2005 (EPACT2005, Public Law 109-58) authorized the U.S. Department of Energy to issue loan guarantees for innovative technologies that "avoid, reduce, or sequester greenhouse gases." In addition, subsequent legislative provisions in the Consolidated Appropriation Act of 2008 (Public Law 110-161) allocated $18.5 billion in guarantees for nuclear power plants [216]. That legislation supports a net increase of about 10 gigawatts of nuclear power capacity, which grows from 101 gigawatts in 2008 to 111 gigawatts in 2035. The increase includes 3.8 gigawatts of expanded capacity at existing plants and 6.3 gigawatts of new capacity. The IEO2011 Reference case includes completion of a second unit at the Watts Bar nuclear site in Tennessee, where construction was halted in 1988 when it was nearly 80 percent complete. Four new U.S. nuclear power plants are completed by 2035, all brought on before 2020 to take advantage of Federal financial incentives. One nuclear unit, Oyster Creek, is projected to be retired at the end of 2019, as announced by Exelon in December 2010. All other existing nuclear units continue to operate through 2035 in the Reference case.
In Canada, generation from natural gas increases by 3.8 percent per year from 2008 to 2035, nuclear by 2.2 percent per year, hydroelectricity by 0.9 percent per year, and wind by 9.9 percent per year. Oil-fired generation and coal-fired generation, on the other hand, decline by 1.0 percent per year and 0.6 percent per year, respectively.
In Ontario—Canada's largest provincial electricity consumer—the government plans to close its four remaining coal-fired plants (Atikokan, Lambton, Nanticoke, and Thunder Bay) by December 31, 2014, citing environmental and health concerns [217]. Units 1 and 2 of Lambton and units 3 and 4 of Nanticoke were decommissioned in 2010 [218]. The government plans to replace coal-fired generation with natural gas, nuclear, hydropower, and wind. It also plans to increase conservation measures. With the planned retirements in Ontario, Canada's coal-fired generation declines from about 104 billion kilowatthours in 2008 to 88 billion kilowatthours in 2035.
The renewable share of Canada's overall generation remains roughly constant throughout the projection. Hydroelectric power is, and is expected to remain, the primary source of electricity in Canada. From 60 percent of the country's total generation in 2008, hydropower falls to 54 percent in 2035. As one of the few OECD countries with large untapped hydroelectric potential, Canada currently has several large- and small-scale hydroelectric facilities either planned or under construction. Hydro-Quebec is continuing the construction of a 768-megawatt facility near Eastmain and a smaller 150-megawatt facility at Sarcelle in Québec, both of which are expected to be fully commissioned by 2012 [219]. Other hydroelectric projects are under construction, including the 1,550-megawatt Romaine River project in Quebec and the 200-megawatt Wuskwatim project in Manitoba [220]. The IEO2011 Reference case does not anticipate that all planned projects will be constructed, but given Canada's past experience with hydropower and the commitments for construction, new hydroelectric capacity accounts for 25,563 megawatts of additional renewable capacity added in Canada between 2008 and 2035.
Wind-powered generation, in contrast, is the fastest-growing source of new energy in Canada, with its share of total generation increasing from less than 1 percent in 2008 to 5 percent in 2035. Canada has plans to continue expanding its wind power capacity, from 4.0 gigawatts of installed capacity at the end of 2010 [221] to nearly 16.6 gigawatts in 2035 in the Reference case. Growth in wind capacity has been so rapid that Canada's federal wind incentive program, "ecoENERGY for Renewable Power," which targeted the deployment of 4 gigawatts of renewable energy by 2011, allocated all of its funding and met its target by the end of 2009 [222].
In addition to the incentive programs of Canada's federal government, several provincial governments have instituted their own incentives to support the construction of new wind capacity. After the success of its Renewable Energy Standard Offer Program, Ontario enacted a feed-in-tariff that pays all sizes of renewable energy generators between 10 cents and 80 cents (Canadian) per kilowatthour, depending on project type, for electricity delivered to the grid [223]. The two programs have helped support robust growth in wind installations over the past several years, and installed wind capacity in the province has risen from 0.6 megawatts in 1995 to 1,457 megawatts in February 2011 [224]. Continued support from Canada's federal and provincial governments—along with the sustained higher fossil fuel prices in the IEO2011 Reference case—is expected to provide momentum for the projected increase in the country's use of wind power for electricity generation.
The combined electricity generation of Mexico and Chile increases by an average of 3.2 percent annually from 2008 to 2035—more than double the rate for Canada and almost quadruple the rate for the United States. In Mexico, the government has recognized the need for the country's electricity infrastructure to keep pace with the fast-paced growth anticipated for electricity demand. In July 2007, the government unveiled its 2007-2012 National Infrastructure Program, which included plans to invest $25.3 billion to improve and expand electricity infrastructure [225]. As part of the program, the government has set a goal to increase installed generating capacity by 8.6 gigawatts from 2006 to 2012 [226].
Natural-gas-fired generation in Mexico and Chile more than doubles in the Reference case, from 147 billion kilowatthours in 2008 to 418 billion kilowatthours in 2035. With Mexico's government expected to implements plans to reduce the country's use of diesel and fuel oil for power generation [227], the country's demand for natural gas strongly outpaces growth in electricity production, leaving it dependent on pipeline imports from the United States and LNG from other countries. Currently, Mexico has one LNG import terminal, Altamira, operating on the Gulf Coast and another, Costa Azul, on the Pacific Coast. A contract tender for a third terminal at Manzanillo, also on the Pacific Coast, was awarded in March 2008, and the project is scheduled for completion by 2011 [228].
Chile also has been trying to increase natural gas use for electricity generation in order to diversify its fuel mix. In 2008, nearly 40 percent of the country's total generation came from hydropower, which can be problematic during times of drought. An unusually hot and dry summer in Chile in 2010-2011 has resulted in the country's worst drought in several decades and threatens power shortages [229]. The government has instituted emergency measures to ensure power supplies, launching a nationwide energy conservation program and also increasing imports of LNG through its two regasification terminals. Although Chile can import natural gas from Argentina through existing pipelines, supplies have not always been reliable. Beginning in 2004, Argentina began to restrict its gas exports to Chile because it was unable to meet its own domestic supplies, leading Chile to develop its LNG import capacity [230].
Most of the renewable generation in Chile and Mexico comes from hydroelectric dams. Hydroelectric resources provide about 85 percent of the region's current renewable generation mix, with another 9 percent coming from geothermal energy. There are plans to expand hydroelectric power in both countries in the future. In the IEO2011 Reference case, hydroelectric power accounts for almost 75 percent of Mexico/Chile's total net generation from renewable energy sources in 2035. In Mexico, there are two major hydroelectric projects underway: the 750-megawatt La Yesca facility, scheduled for completion by 2012, and the planned 900-megawatt La Parota project, which has been delayed and may not be completed until 2018 [231].
In addition to efforts to diversify its electricity fuel mix, Chile has a number of new hydroelectric plants planned or under construction. In October 2010, the 150-megawatt La Higuera and 158-megawatt La Confluencia hydro projects on the Tinguiririca River were completed [232]. The two run-of-river projects were constructed in a joint venture by Australia's Pacific Hydro and Norway's SN Power Invest. Pacific Hydro also has plans to construct another 650 megawatts of hydroelectric capacity on Chile's Upper Cachapoal River. Construction on the first phase of the development began in 2009. The first hydro plant in the system, the 111-megawatt Chacayes power plant, is scheduled for completion in October 2011. The entire development should be completed in 2019, when the 78-megawatt Las Maravillas project is scheduled to begin operation [233].
There is virtually no wind or solar generation in Mexico at present, but the Mexican government's goal of installing 2.5 gigawatts of wind capacity on the Tehuantepec Isthmus by 2012 has encouraged wind development in the short term [234]. The 161-megawatt Los Vergeles project and the Oaxaca II, III, and IV projects—totaling more than 300 megawatts—are due for completion in 2011 and 2012, respectively. In Baja California even larger projects are under development, such as the 1,200-megawatt Sempra and the 400-megawatt Union Fenosa projects [235]. Further, Mexico's goal of reducing national greenhouse gas emissions to 50 percent of 2002 levels by 2050 is expected to spur wind and solar installations in the future [236].
Chile expanded its total installed wind capacity to 167 megawatts in early 2011 and has granted environmental approval to an additional 1,500 megawatts of wind projects [237]. Still, the penetration of wind and solar generating capacity in Chile remains modest throughout the projection, with their share of Mexico and Chile's combined total electricity generation rising from less than 0.1 percent in 2008 to 3 percent in 2035.
OECD Europe
Electricity generation in the nations of OECD Europe increases by an average of 1.2 percent per year in the IEO2011 Reference case, from 3.4 trillion kilowatthours in 2008 to 4.8 trillion kilowatthours in 2035. Because most of the countries in OECD Europe have relatively stable populations and mature electricity markets, most of the region's growth in electricity demand is expected to come from those nations with more robust population growth (including Turkey, Ireland, and Spain) and from the newest OECD members (including the Czech Republic, Hungary, Poland, and Slovenia), whose projected economic growth rates exceed the OECD average. In addition, with environmental concerns remaining prominent in the region, there is a concerted effort in the industrial sector to switch from coal and liquid fuels to electricity.
Renewable energy is OECD Europe's fastest-growing source of electricity generation in the Reference case (Figure 79), increasing by 2.5 percent per year through 2035. The increase is almost entirely from wind and solar. OECD Europe's leading position worldwide in wind power capacity is maintained through 2035, with growth in generation from wind sources averaging 6.4 percent per year, even though the Reference case assumes no enactment of additional legislation to limit greenhouse gas emissions. Strong growth in offshore wind capacity is underway, with 883 megawatts added to the grid in 2010, representing a 51-percent increase over the amount of capacity added in 2009 [238].
The United Kingdom is expected to spearhead the growth in OECD Europe's offshore wind capacity. Although there is debate within the country over the costs and benefits of offshore wind power, the 300-megawatt Thanet Wind Farm, the world's largest, was completed in September 2010 [239]. Work is also continuing on other major projects, including the 1,000-megawatt London Array, for which the first foundation was laid in March 2011 [240].
The growth of nonhydropower renewable energy sources in OECD Europe is encouraged by some of the world's most favorable renewable energy policies. The European Union set a binding target to produce 21 percent of electricity generation from renewable sources by 2010 [241] and reaffirmed the goal of increasing renewable energy use with its December 2008 "climate and energy policy," which mandates that 20 percent of total energy production must come from renewables by 2020 [242]. Approximately 18 percent of the European Union's electricity came from renewable sources in 2008.
The IEO2011 Reference case does not anticipate that all future renewable energy targets in the European Union will be met on time. Nevertheless, current laws are expected to lead to the construction of more renewable capacity than would have occurred in their absence. In addition, some individual countries provide economic incentives to promote the expansion of renewable electricity. For example, Germany, Spain, and Denmark—the leaders in OECD Europe's installed wind capacity—have enacted feed-in tariffs that guarantee above-market rates for electricity generated from renewable sources and, typically, last for 20 years after a project's completion. As long as European governments support such price premiums for renewable electricity, robust growth in renewable generation is likely to continue.
Exceptionally generous feed-in tariffs have been falling out of favor in recent years, however. Before September 2008, Spain's solar subsidy led to an overabundance of solar PV projects. When the Spanish feed-in tariff was lowered after September 2008, a PV supply glut or "solar bubble" resulted, driving down the price of solar panels and lowering profits throughout the industry [243]. The Spanish government is now set to reduce its tariffs by a further 45 percent for large ground-based sites, in view of the country's large public deficit and the fear of creating another solar bubble [244]. Germany has taken a similar approach and will cut its feed-in tariff for ground PV units by 15 percent, effective in the summer of 2011 [245]. Italy, with the third-largest installed PV capacity in OECD Europe, is also lowering its solar feed-in tariff in June 2011, after experiencing a financially unsustainable 128-percent increase in solar PV output between November 2009 and November 2010 [246].
Natural gas is the second fastest-growing source of power generation after renewables in the outlook for OECD Europe, increasing at an average rate of 1.8 percent per year from 2008 to 2035. Growth is projected to be more robust than the 1.3-percent annual increase in last year's outlook, as prospects for the development of unconventional sources of natural gas in the United States and other parts of the world help to keep world markets well supplied and global prices relatively low. As a result, natural gas is more competitive in European markets in the IEO2011 Reference case than it was in IEO2010.
Before the Fukushima disaster in Japan, prospects for nuclear power in OECD Europe had improved markedly in recent years, and many countries were reevaluating their programs to consider plant life extensions or construction of new nuclear generating capacity. In the aftermath of Fukushima, it appears that many OECD nations are reconsidering their plans. Although the full extent to which European governments might withdraw their support for nuclear power is uncertain, some countries already have reversed their nuclear policies. For example, the German government has announced plans to close all nuclear reactors in the country by 2022 [247]; the Swiss Cabinet has decided to phase out nuclear power by 2034 [248]; and Italian voters, in a country-wide referendum, have rejected plans to build nuclear power plants in Italy [249]. In addition, the European Commission has announced that it will conduct a program of stress tests on nuclear reactors operating in the European Union. (Turkey, in contrast, has announced that it will proceed with construction of the country's first nuclear power plant [250].) Still, environmental concerns and the importance of energy security provide support for future European nuclear generation. With no phaseout of nuclear power anticipated in the IEO2011 Reference case, nuclear capacity in OECD Europe increases by a net 19 gigawatts from 2008 to 2035.
Coal accounted for 25 percent of OECD Europe's net electricity generation in 2008, but concerns about the contribution of carbon dioxide emissions to climate change could reduce that share in the future. In the IEO2011 Reference case, electricity from coal slowly loses its prominence in OECD Europe, declining by 0.5 percent per year from 2008 to 2035 and ultimately falling behind renewables, natural gas, and nuclear energy as a source of electricity. Coal consumption in the electric power sector is not decreasing uniformly in all countries in OECD Europe, however. Spain's Coal Decree, which went into force in February 2011, subsidizes the use of domestic coal in Spanish power plants. The policy is expected to result in more electricity generation from coal-fired plants at least through 2014, when the subsidy is scheduled to expire [251].
OECD Asia
Total electricity generation in OECD Asia increases by an average of 1.2 percent per year in the Reference case, from 1.7 trillion kilowatthours in 2008 to 2.4 trillion kilowatthours in 2035. Japan accounted for the largest share of electricity generation in the region in 2008 and continues to do so throughout the projection period, despite having the slowest-growing electricity market in the region and the slowest among all OECD countries, averaging 0.8 percent per year, as compared with 1.3 percent per year for Australia/New Zealand and 2.0 percent per year for South Korea (Figure 80). Japan's electricity markets are well established, and its aging population and relatively slow projected economic growth translate into slow growth in demand for electric power. In contrast, Australia/New Zealand and South Korea are expected to see more robust economic growth and population growth, leading to more rapid growth in demand for electricity.
The fuel mix for electricity generation varies widely among the three economies that make up the OECD Asia region. In Japan, natural gas, coal, and nuclear power make up the bulk of the current electric power mix, with natural gas and nuclear accounting for about 51 percent of total generation and coal another 26 percent. The remaining portion is split between renewables and petroleum-based liquid fuels. Japan's reliance on nuclear power increases over the projection period, from 24 percent of total generation in 2008 to 33 percent in 2035. The natural gas share of generation declines slightly over the same period, from 27 percent to 26 percent, and coal's share declines to 18 percent, being displaced by nuclear and renewable energy sources.
On March 11, 2011, a devastating, magnitude 9.0 earthquake, followed by a tsunami, struck northeastern Japan, resulting in extensive loss of life and triggering a nuclear disaster at the Fukushima Daiichi nuclear power plants. At present, it is impossible to assess the ultimate impact on Japan's nuclear program, and IEO2011 makes no attempt to incorporate the ultimate effects of the earthquake in the Reference case. In the immediate aftermath of the earthquake, reactors at Japan's Fukushima Daini and Onagawa nuclear facilities were successfully shut down, and they will not be returned to operation until they have undergone stringent safety reviews [252]. The six reactors at Fukushima Daiichi were damaged beyond repair, removing of 4.7 gigawatts of generating capacity from the grid. Although power had been restored in most of the affected areas by June 2011, the temporary and permanent losses of nuclear power capacity from Japan's electricity grid (in addition to a substantial amount of coal-fired capacity that also remains shut down) will make it difficult for power generators to meet demand in the summer months of 2011 (June, July, and August), when electricity consumption typically is very high [253].
Currently, Japan is reconsidering its electricity supply policies. In May, Prime Minister Naoto Kan stated that the plan to increase the nuclear power share of the country's electricity supply, from about 26 percent at present to 50 percent by 2030, "will have to be set aside" [254]. Instead, the government plans to pursue an aggressive expansion of renewable energy capacity, especially solar power. Japan generates only about 6 percent of its primary energy from renewable energy sources (including hydroelectricity), but government policies and incentives to increase solar power will improve the growth of the energy source in the future. In the IEO2011 Reference case, electricity generation from solar energy increases by 11.5 percent per year from 2008 to 2035, making solar power Japan's fastest-growing source of renewable energy (although it starts from a negligible amount in 2008). In November 2009, the government initiated a feed-in tariff incentive to favor the development of solar power [255]. Wind-powered generation in Japan also increases strongly in the Reference case, by an average of 8.1 percent per year. In the wake of the nuclear disaster, it is likely that additional government incentives for renewable energy sources will follow. Both solar and wind power, however, remain minor sources of electricity, supplying 3 percent and 2 percent of total generation in 2035, respectively, as compared with hydropower's 8-percent share of the total.
Australia and New Zealand, as a region, rely on coal for about 66 percent of electricity generation, based largely on Australia's rich coal resource base (9 percent of the world's total coal reserves). The remaining regional generation is supplied by natural gas and renewable energy sources—mostly hydropower, wind, and, in New Zealand, geothermal.
Australia continues to make advances in wind energy, with 1,712 megawatts of capacity installed at the end of 2009 and a further 588 megawatts under construction [256]. To help meet its 2025 goal of having 90 percent of electricity generation come from renewable sources, New Zealand is focusing on harnessing more of its geothermal potential [257]. Construction of the 250-megawatt Tauhara II project, currently under review by the country's Environmental Protection Authority, would alone power all the homes in the Wellington metro area [258]. The Australia/New Zealand region uses negligible amounts of oil for electricity generation and no nuclear power, and that is not expected to change over the projection period. Natural-gas-fired generation is expected to grow strongly in the region, at 4.0 percent per year from 2008 to 2035, reducing the coal share to 39 percent in 2035.
In South Korea, coal and nuclear power currently provide 42 percent and 34 percent of total electricity generation, respectively. Natural-gas-fired generation grows quickly in the Reference case, but despite a near doubling of electricity generation from natural gas, its share of total generation increases only slightly, from 19 percent in 2008 to 21 percent in 2035. Coal and nuclear power continue to provide most of South Korea's electricity generation, with a combined 73 percent of total electricity generation in 2035.
Non-OECD electricity
Non-OECD Europe and Eurasia
Total electricity generation in non-OECD Europe and Eurasia grows at an average rate of 1.4 percent per year in the IEO2011 Reference case, from 1.6 trillion kilowatthours in 2008 to 2.3 trillion kilowatthours in 2035. Russia, with the largest economy in non-OECD Europe and Eurasia, accounted for about 60 percent of the region's total generation in 2008 and is expected to retain approximately that share throughout the period (Figure 81).
Natural gas and nuclear power supply much of the growth in electricity generation in the region. Although non-OECD Europe and Eurasia has nearly one-third of the world's total proved natural gas reserves, some countries (notably, Russia) plan to export natural gas instead of using it to fuel electricity generation. As a result, the region's natural-gas-fired generation grows modestly in the outlook, at an average rate of 0.7 percent from 2008 to 2035.
Generation from nuclear power grows strongly in the region, averaging 3.0 percent per year. Much of the increase is expected in Russia, which continues to shift generation from natural gas to nuclear, because natural gas exports are more profitable than the domestic use of natural gas for electricity generation.
In 2006, the Russian government released Resolution 605, which set a federal target program (FTP) for nuclear power development. Although the FTP was updated and scaled back in July 2009 as a result of the recession, 10 nuclear power reactors still are slated for completion by 2016, adding a potential 9 gigawatts of capacity. According to the Russian plan, another 44 reactors are to be constructed, increasing Russia's total nuclear generating capacity to 42 gigawatts by 2024. By 2030, the plan would bring the total to nearly 50 gigawatts and increase nuclear generation to 25 or 30 percent of total generation. In January 2010, the Russian government approved an FTP that would shift the focus of the nuclear power industry to fast reactors with a closed fuel cycle. Life extensions have been completed for roughly 30 percent of Russia's operating reactors, and the installed capacity of most reactors has been uprated [259]. In the IEO2011 Reference case, Russia's existing 23 gigawatts of nuclear generating capacity is supplemented by a net total of 5 gigawatts in 2015 and another 23 gigawatts in 2035.
Renewable generation in non-OECD Europe and Eurasia, almost entirely from hydropower facilities, increases by an average of 1.9 percent per year, largely as a result of repairs and expansions at existing sites. The repairs include reconstruction of turbines in the 6.4-gigawatt Sayano-Shushenskaya hydroelectric plant, which was damaged in an August 2009 accident [260]. Four of the plant's 640-megawatt generators are currently operational, and full restoration of the dam is expected to be completed by 2014 [261]. Notable new projects include the 3-gigawatt Boguchanskaya Hydroelectric Power Station in Russia and the 3.6-gigawatt Rogun Dam in Tajikistan. Construction of the Boguchanskaya station began in 1980, and work was started on Rogun in 1976. However, work on both projects ceased when the former Soviet Union experienced economic difficulties in the 1980s.
Despite the recent recession, construction continues on Boguchanskaya, which is on track for completion by 2012 [262]. Although Tajikistan's president announced in May 2008 that construction work on Rogun Dam had resumed, its prospects are less favorable [263]. Neighboring Uzbekistan strongly opposes the dam, fearing that it will reduce the water supply that supports the Uzbek cotton industry [264]. Furthermore, only $200 million of the $4 billion needed to complete the hydroelectric plant has been raised so far, enough to support the construction work for just 2 more years [265].
Other than increases in hydropower, only modest growth in renewable generation is projected for the nations of non-OECD Europe and Eurasia, given the region's access to fossil fuel resources and lack of financing available for relatively expensive renewable projects. In the IEO2011 Reference case, nonhydropower renewable capacity in the region increases by only 5 gigawatts from 2008 to 2035. Although total growth in nonhydropower renewable generation is projected to be small, Romania is one nation in the region that is moving ahead with wind energy projects: its 348-megawatt Fantanele wind farm is on track to be completed in late 2010, and the nearby Cogealac wind farm (253 megawatts) is due for commissioning in 2011 [266].
Non-OECD Asia
Non-OECD Asia—led by China and India—has the fastest projected growth rate for electric power generation worldwide, averaging 4.0 percent per year from 2008 to 2035 in the Reference case. Although the global economic recession had an impact on the region's short-term economic growth, the economies of non-OECD Asia have led the recovery and are projected to expand strongly in the long term, with corresponding increases in demand for electricity in both the building and industrial sectors. Total electricity generation in non-OECD Asia grows by 49 percent, from 5.0 trillion kilowatthours in 2008 to 14.3 trillion kilowatthours in 2035, with electricity demand increasing by 46 percent from 2015 to 2025 and by another 32 percent from 2025 to 2035. In 2035, net electricity generation in non-OECD Asia totals 14.3 trillion kilowatthours in the Reference case. Non-OECD Asia is the world's fastest-growing regional market for electricity in IEO2011, accounting for 41 percent of world electricity generation in 2035.
Coal is used to fuel more than two-thirds of electricity generation in non-OECD Asia (Figure 82), led by coal-fired generation in China and India. Both countries rely heavily on coal to produce electric power. In 2008, coal's share of generation was an estimated 80 percent in China and 68 percent in India. Under existing policies, it is likely that coal will remain the predominant source of power generation in both countries. In the IEO2011 Reference case, coal's share of electricity generation declines to 66 percent in China and 51 percent in India in 2035.
At present, China is installing approximately 900 megawatts of coal-fired capacity (equivalent to one large coal-fired power plant) per week. However, it also has been retiring old, inefficient plants to help slow the rate of increase in the nation's carbon intensity. From 2006 to 2010, China retired almost 71 gigawatts of coal-fired capacity, including 11 gigawatts in 2010, and it plans to retire an additional 8 gigawatts in 2011 [267].
Non-OECD Asia leads the world in installing new nuclear capacity in the IEO2011 Reference case, accounting for 54 percent of the net increment in nuclear capacity worldwide (or 144 gigawatts of the total 266-gigawatt increase). China, in particular, has ambitious plans for nuclear power, with more than 27 nuclear power plants currently under construction and a total of 106 gigawatts of new capacity expected to be installed by 2035.
There is significant uncertainty in the IEO2011 Reference case projections for China's nuclear capacity. Officially, China's nuclear capacity targets are 70 to 86 gigawatts by 2020 and 200 gigawatts by 2030—targets that the Chinese government has been increasing since 2008, when the target was 40 gigawatts by 2020 [268]. Factors that may cause China to undershoot its official targets include limited global capacity of heavy forging facilities required for the manufacture of Generation III reactor components and potential difficulties in training the large number of engineers and regulators needed to operate and monitor the planned power plants. On the other hand, an estimated 226 gigawatts of new capacity has advanced beyond the pre-feasibility study phase, including reactors in at least 20 provinces that are not approved for the national plan [269]. The impact of the March 2011 disaster at Japan's Fukushima Daishi nuclear power plant may also have a negative impact on the pace of China's nuclear power program. In the aftermath of the disaster, China announced it would halt approval processes for all new reactors until the country's nuclear regulator completes a "thorough safety review"—a process that could last for as long as a year [270].
The IEO2011 Reference case assumes that the global lack of heavy forging facilities and the long lead times needed to build or upgrade forging facilities, build new nuclear power plants, and train new personnel will cause China's nuclear power industry to grow more slowly than in official government predictions. Nonetheless, the 115 gigawatts of nuclear capacity projected for 2035 is a 53-percent increase over last year's Reference case. In the IEO2011 Reference case, the nuclear share of China's total electricity generation increases from 2 percent in 2008 to 10 percent in 2035.
India also has plans to boost its nuclear power generating capacity. From 4 gigawatts of installed nuclear power capacity in operation in 2011, India has set an ambitious goal of increasing its nuclear generating capacity to 20 gigawatts by 2020 and to as much as 63 gigawatts by 2032 [271]. Currently, five nuclear reactors are under construction, three of which are scheduled for completion by the end of 2011 [272]. The IEO2011 Reference case assumes a slower increase in nuclear capacity than anticipated by India's government, to 16 gigawatts in 2020 and 28 gigawatts in 2035.
In addition to China and India, several other countries in non-OECD Asia are expected to begin or expand nuclear power programs. In the Reference case, new nuclear power capacity is installed in Taiwan, Vietnam, Indonesia, and Pakistan by 2020. Concerns about security of energy supplies and greenhouse gas emissions lead many nations in the region to diversify their fuel mix for power generation by adding a nuclear component.
Electricity generation from renewable energy sources in non-OECD Asia grows at an average annual rate of 4.9 percent, increasing the renewable share of the region's total generation from 17 percent in 2008 to 21 percent in 2035. Small-, mid-, and large-scale hydroelectric facilities all contribute to the projected growth. Several countries in non-OECD Asia have hydropower facilities either planned or under construction, including Vietnam, Malaysia, Pakistan, and Myanmar (the former Burma). Almost 50 hydropower facilities, with a combined 3,398 megawatts capacity, are under construction in Vietnam's Son La province, including the 2,400-megawatt Son La and 520-megawatt Houi Quang projects, both of which are scheduled for completion before 2015 [273]. The remaining facilities are primarily micro- and mini-hydroelectric power plants. Malaysia expects to complete its 2,400-megawatt Bakun Dam by the end of 2011, although the project has experienced delays and setbacks in the past [274].
Pakistan and Myanmar also have substantial hydropower development plans, but those plans have been discounted in the IEO2011 Reference case to reflect the two countries' historical difficulties in acquiring foreign direct investment for infrastructure projects. Pakistan's electricity development plans have been further hampered by floods that occurred in 2010; power plants that had been in need of refurbishment are now severely damaged or destroyed [275]. Nearly 150 of the 200 small hydroelectric plants in the northern Khyber-Pakhtunkhwa province were destroyed by the floods and may take years to rebuild [276].
India has plans to more than double its installed hydropower capacity by 2030. In its Eleventh and Twelfth Five-Year Plans, which span 2008 through 2017, India's Central Electricity Authority has identified nearly 41 gigawatts of hydroelectric capacity that it intends to build. Nearly one-half of the planned capacity is to be built in the Uttarakhand region. However, environmental concerns recently led to the rejection of two proposed projects in the region, totaling 860 megawatts, which underscores the uncertainty associated with estimating India's future hydroelectric development. Despite $150 million already invested in the 600-megawatt Loharinag Pala project, construction on the project has also been halted, and its future is uncertain [277]. Although the IEO2011 Reference case does not assume that all the planned capacity will be completed, more than one-third of the announced projects are under construction already and are expected to be completed by 2020 [278].
Like India, China has many large-scale hydroelectric projects under construction. The final generator for the 18.2-gigawatt Three Gorges Dam project went on line in October 2008, and the Three Gorges Project Development Corporation plans to increase the project's total installed capacity further, to 22.4 gigawatts by 2012 [279]. In addition, work continues on the 12.6-gigawatt Xiluodu project on the Jinsha River, which is scheduled for completion in 2015 as part of a 14-facility hydropower development plan [280]. China also has the world's second-tallest dam (at nearly 985 feet) currently under construction, as part of the 3.6-gigawatt Jinping I project on the Yalong River. The dam scheduled for completion in 2014 as part of a plan by the Ertan Hydropower Development Company to construct 21 facilities with 29.2 gigawatts of hydroelectric capacity on the Yalong [281].
The Chinese government has set a 300-gigawatt target for hydroelectric capacity in 2020. Including those mentioned above, the country has a sufficient number of projects under construction or in development to meet the target. China's aggressive hydropower development plan is expected to increase hydroelectricity generation by 3.2 percent per year, more than doubling the country's total hydroelectricity generation by 2035.
Although hydroelectric projects dominate the renewable energy mix in non-OECD Asia, generation from nonhydroelectric renewable energy sources, especially wind, also is expected to grow significantly. In the IEO2011 Reference case, electricity generation from wind plants in China grows by 14.2 percent per year, from 12 billion kilowatthours in 2008 to 447 billion kilowatthours in 2035. In addition, government policies in China and India are encouraging the growth of solar generation. Under its "Golden Sun" program, announced in July 2009, the Chinese Ministry of Finance plans to subsidize 50 percent of the construction costs for grid-connected solar plants [282]. India's National Solar Mission, launched in November 2009, aims to have 20 gigawatts of installed solar capacity (both PV and solar thermal) by 2020, 100 gigawatts by 2030, and 200 gigawatts by 2050 [283]. India's targets have been discounted in the IEO2011 Reference case because of the substantial uncertainty about the future of government-provided financial incentives [284]. However, the policies do support robust growth rates in solar generation for China and India, at 22 percent per year and 28 percent per year, respectively, in the Reference case.
Measuring the growth of China's wind capacity has proven difficult as the number of wind farms rapidly expands. According to the Chinese Renewable Energy Industry Association (CREIA), the country had 41.8 gigawatts of installed wind capacity at the end of 2010 [285]. The National Energy Administration and the Chinese Electricity Council, however, report only 31.1 gigawatts of wind capacity connected to the electricity grid at the end of 2010. The discrepancy between the two figures is a result of the inability of some local grids to absorb wind-generated electricity, a lack of long-distance transmission lines [286], and policies (now superseded) that encouraged construction of wind capacity instead of generation of electricity. The IEO2011 Reference case assumes that China had 31.1 gigawatts of wind capacity installed at the end of 2010.
Although geothermal energy is a small contributor to non-OECD Asia's total electricity generation, it plays an important role in the Philippines and Indonesia. With the second-largest amount of installed geothermal capacity in the world, the Philippines generated almost 16 percent of its total electricity from geothermal sources in 2010 [287]. Indonesia, with the world's third-largest installed geothermal capacity, plans to have 3.9 gigawatts of capacity installed by 2014 [288] and 9.5 gigawatts by 2025 [289]. However, those goals are discounted in the Reference case in view of the long lead times and high exploration costs associated with geothermal energy.
Middle East
Electricity generation in the Middle East region grows by 2.5 percent per year in the Reference case, from 0.7 trillion kilowatthours in 2008 to 1.4 trillion kilowatthours in 2035. The region's young and rapidly growing population, along with a strong increase in national income, is expected to result in rapid growth in demand for electric power. Iran, Saudi Arabia, and the United Arab Emirates (UAE) account for two-thirds of the region's demand for electricity, and demand has increased sharply over the past several years in each of those countries. From 2000 to 2008, Iran's net generation increased by an average of 7.5 percent per year, Saudi Arabia's by 6.2 percent per year, and the UAE's by 10.1 percent per year.
The Middle East depends on natural gas and petroleum liquid fuels to generate most of its electricity and is projected to continue that reliance through 2035, although liquids-fired generation declines over the projection period and thus loses market share to natural-gas-fired generation (Figure 83). In 2008, natural gas supplied 59 percent of electricity generation in the Middle East and liquid fuels 35 percent. In 2035, the natural gas share is projected to be 75 percent and the liquid fuels share 14 percent. There has been a concerted effort by many of the petroleum exporters in the region to develop their natural gas resources for use in domestic power generation. Petroleum is a valuable export commodity for many nations in the Middle East, and there is growing interest in the use of domestic natural gas for electricity generation in order to make more oil assets available for export.
Other energy sources make only minor contributions to electricity supply in the Middle East. Israel is the only country in the region that uses significant amounts of coal to generate electric power [290], and Iran and the UAE are the only ones projected to add nuclear capacity. Iran's 1,000-megawatt Bushehr reactor is scheduled to begin operating in 2011, although it has faced repeated delays, the latest being the detection of metal particles in the nuclear fuel rods, with the result that the fuel had to be unloaded and tested for possible contamination [291]. In December 2009, the Emirates Nuclear Energy Corporation (ENEC) in the UAE selected a South Korean consortium to build four nuclear reactors, with construction planned to begin in 2012 [292]. ENEC filed construction license applications for the first two units in December 2010, and it plans to have all four units operational by 2020 [293].
In addition to Iran and the UAE, several other Middle Eastern nations have announced intentions in recent years to pursue nuclear power programs. In 2010, the six-nation Gulf Cooperation Council31 entered into a contract with U.S.-based Lightbridge Corporation to assess regional cooperation in the development of nuclear power and desalination programs [294]. Jordan also has announced its intention to add nuclear capacity [295], and in 2010 Kuwait's National Nuclear Energy Committee announced plans to build four reactors by 2022 [296]. Even given the considerable interest in nuclear power in the region, however, given the economic and political issues and long lead times usually associated with beginning a nuclear program, the only reactors projected to be built in the Middle East in the IEO2011 Reference case are in Iran and the UAE.
Several Middle Eastern countries recently have expressed some interest in increasing coal-fired generation in response to concerns about diversifying the electricity fuel mix and meeting the region's fast-paced growth in electricity demand. For example, Oman announced in 2008 that it would construct the Persian Gulf's first coal-fired power plant at Duqm [297]. According to the plan, the 1-gigawatt plant will be fully operational by 2016, powering a water desalinization facility [298]. The UAE, Saudi Arabia, and Bahrain also have considered building coal-fired capacity [299].
Although there is little economic incentive for countries in the Middle East to increase their use of renewable energy sources (the renewable share of the region's total electricity generation increases from only 1 percent in 2008 to 5 percent in 2035 in the Reference case), there have been some recent developments in renewable energy use in the region. Iran, which generated 10 percent of its electricity from hydropower in 2010, is adding approximately 4 gigawatts of new hydroelectric capacity, even after the droughts of 2007 and 2008 reduced available hydroelectric generation by nearly 75 percent [300]. Although development of Abu Dhabi's Masdar City project has been slowed by the current global economic environment [301], the government still plans to meet its 2020 goal of producing 7 percent of its energy from renewable sources. Solar power is expected to meet the vast majority of that goal, including two 100-megawatt solar power plants that Masdar Power plans to build [302].
Africa
Demand for electricity in Africa grows at an average annual rate of 3.0 percent in the IEO2011 Reference case. Fossil-fuel-fired generation supplied 81 percent of the region's total electricity in 2008, and reliance on fossil fuels is expected to continue through 2035. Coal-fired power plants, which were the region's largest source of electricity in 2008, accounting for 41 percent of total generation, provide a 33-percent share in 2035; and natural-gas-fired generation expands strongly, from 29 percent of the total in 2008 to 45 percent in 2035 (Figure 84).
At present, South Africa's two nuclear reactors are the only commercial reactors operating in the region, accounting for about 2 percent of Africa's total electricity generation. Although the construction of a new Pebble Bed Modular Reactor in South Africa has been canceled, the South African government's Integrated Electricity Resource Plan calls for another 9.6 gigawatts of nuclear capacity to be built by 2030 [303]. In addition, in May 2009, Egypt's government awarded a contract to Worley Parsons for the construction of a 1,200-megawatt nuclear power plant. Although original plans were for one unit, current plans call for four units, with the first plant to be operational in 2019 and the others by 2025 [304]. In the Reference case, 2.3 gigawatts of net nuclear capacity becomes operational in Africa over the 2008-2035 period, although only South Africa is expected to complete construction of any reactors. The nuclear share of the region's total generation remains at 2 percent in 2035.
Generation from hydropower and other marketed renewable energy sources is expected to grow relatively slowly in Africa. Plans for several hydroelectric projects in the region have been advanced recently, and they may help to boost supplies of marketed renewable energy in the mid-term. Several (although not all) of the announced projects are expected to be completed by 2035, allowing the region's consumption of marketed renewable energy to grow by 2.9 percent per year from 2008 to 2035. For example, Ethiopia finished work on two hydroelectric facilities in 2009: the 300-megawatt Takeze power station and the 420-megawatt Gilgel Gibe II [305]. A third plant, the 460-megawatt Tana Beles, was completed in 2010 [306].
Central and South America
Electricity generation in Central and South America increases by 2.4 percent per year in the IEO2011 Reference case, from 1.0 trillion kilowatthours in 2008 to 1.9 trillion kilowatthours in 2035. The fuel mix for electricity generation in Central and South America is dominated by hydroelectric power, which accounted for nearly two-thirds of the region's total net electricity generation in 2008. Of the top five electricity-generating countries in the region, three—Brazil, Venezuela, Paraguay—generate more than 70 percent of their total electricity from hydropower.
In Brazil, the region's largest economy, hydropower provided more than 80 percent of electricity generation in 2008 (Figure 85). The country has been trying to diversify its electricity generation fuel mix away from hydroelectric power because of the risk of power shortages during times of severe drought. In the Brazilian National Energy Plan for 2010-2019, the government set a goal to build 63 gigawatts of installed capacity, with nonhydroelectric capacity making up the majority of additions [307]. To help achieve that target, the government has announced plans to increase nuclear power capacity, beginning with the completion of the long-idled 1.3-gigawatt Angra-3 project [308]. Construction resumed in June 2010, and Angra-3 is expected to be operational at the end of 2015 [309]. Brazil also has plans to construct four new 1-gigawatt nuclear plants beginning in 2015. In the IEO2011 Reference case, the Angra-3 project is completed by 2015, and three more planned nuclear projects are completed by 2035.
In the past, the Brazilian government has tried (with relatively little success) to attract substantial investment in natural-gas-fired power plants. Its lack of success has been attributed mainly to the higher costs of natural-gas-fired generation relative to hydroelectric power, and to concerns about the security of natural gas supplies. Brazil has relied on imported Bolivian natural gas for much of its supply, but concerns about the impact of Bolivia's nationalization of its energy sector on foreign investment in the country's natural gas production has led Brazil to look toward LNG imports for secure supplies. Brazil has invested strongly in its LNG infrastructure, and its third LNG regasification plant is scheduled for completion in 2013 [310]. With Brazil diversifying its natural gas supplies, substantially increasing domestic production, and resolving to reduce the hydroelectric share of generation, natural gas is projected to be its fastest-growing source of electricity, increasing by 8.7 percent per year on average from 2008 to 2035.
Brazil still has plans to continue expanding its hydroelectric generation over the projection period, including the construction of two plants on the Rio Madeira in Rondonia—the 3.2-gigawatt Santo Antonio and the 3.3-gigawatt Jirau hydroelectric facilities. The two plants, with completion dates scheduled for 2012-2013, are expected to help Brazil meet electricity demand in the mid-term [311]. In the long term, electricity demand could be met in part by the proposed 11.2-gigawatt Belo Monte dam, which was given approval for construction in April 2010 [312]. Each of the three projects could, however, be subject to further delay as a result of legal challenges.
Brazil is also interested in increasing the use of other, nonhydroelectric renewable resources in the future—notably, wind. In December 2009, Brazil held its first supply tender exclusively for wind farms. At the event, 1.8 gigawatts of capacity were purchased, for development by mid-2012 [313]. The first signs of wind development are now taking place, with a purchase contract already signed for the 90-megawatt Brotas wind farm, which is scheduled for completion in 2011 [314]. In the IEO2011 Reference case, wind power generation in Brazil grows by 10.8 percent per year, from 530 million kilowatthours in 2008 to 8,508 million kilowatthours in 2035. Despite that robust growth, however, wind remains a modest component of Brazil's renewable energy mix in the Reference case, as compared with the projected growth in hydroelectric generation to 792 billion kilowatthours in 2035.
In the IEO2011 Reference case, natural-gas-fired generation and hydroelectric generation are expected to dominate the electric power sector in Central and South America (excluding Brazil), increasing from 73 percent of total electricity generation in 2008 to 79 percent in 2035 (Figure 86). However, some countries in the region have a more diverse fuel mix. Argentina, for example, generated 6 percent of its electricity from its two nuclear power plants in 2008. Although construction of a third reactor, Atucha 2, was suspended in 1994, the 692-megawatt facility is scheduled to be completed by the end of 2011 [315].
Many countries in Central and South America are continuing their attempts to increase the role of natural gas in the electricity mix to prevent blackouts, caused by a combination of surging electricity demand and droughts that decrease generation from hydroelectric sources. Argentina, which experienced repeated power outages from December 20 through 31 in the summer of 2010, continues to increase LNG imports. The Argentine government has announced plans to build an import terminal outside Buenos Aires by 2012 and has signed a deal to import up to 706 million cubic feet of LNG from Qatar through another new terminal in Rio Negro province [316]. Venezuela has also committed to increasing its use of natural gas for electricity generation to both reduce the nation's heavy reliance on hydroelectricity and to meet fast-paced growth in electricity demand. At present, hydroelectricity accounts for around 63 percent of Venezuela's total installed generating capacity. In 2010, an extremely hot and dry summer reduced available hydroelectric generation so much that the country was forced to ration electricity [317]. The rationing program was suspended on July 30, 2010 as rainfall returned reservoir levels at the Guri hydroelectric plant approached more normal levels. However, despite the government's aggressive investment in power sector infrastructure improvements over the past two years, electricity demand has continued to outpace the growth in generating capacity [318]. Venezuela once again began to experience widespread power outages beginning in March 2011 and in June the government announced it would reinstate electricity rationing in an attempt to reduce electricity demand in addition to continuing to invest in generating capacity increases.
Sections
- Highlights
- World energy demand and economic outlook
- Liquid fuels
- Natural gas
- Coal
- Electricity
- Industrial sector energy consumption
- Transportation sector energy consumption
- Energy-related carbon dioxide emissions
- Preface
Press Conference
Data Tables
Reference Case Summary & Detailed Tables
Interactive Table Viewer ›
Provides custom data views of the IEO2011 Reference case.