Regional Definitions in the International Energy Outlook 2005

Regular readers of the International Energy Outlook (IEO) will notice that, in this edition, the names used to describe country groupings have been changed. Although the organization of countries within the three major groupings has not changed, the nomenclature used in previous editions to describe the groups— namely, industrialized, EE/FSU, and developing— had become somewhat dated and did not accurately reflect the countries within them. Some analysts have argued that several of the countries in the “developing” group (South Korea and China, for instance) could fairly be called “industrialized” today.

IEO2005 uses country grouping designations based on relative levels of economic development. The three major groupings (or “regions”) used in this report are the mature market economies, transitional economies, and emerging economies. The mature market economies include nations whose energy markets are generally well-established, and whose industrial sectors have trended away from more energy-intensive manufacturing industries toward less energy-intensive service industries. As shown in the map, the mature market economies include the countries of North America (the United States, Canada, and Mexico), Western Europe, and “mature market” Asia (Japan, Australia, and New Zealand). The grouping of countries may be subject of some debate. For example, some may argue that Mexico should not be considered a mature market economy; however, it is included in North America because of its importance in energy trade in the region.

The transitional economies include those nations that are transitioning away from the centrally planned economies of the Soviet Union to free market economies. This region is subdivided into Eastern Europe (EE) and the former Soviet Union (FSU), and within the FSU separate projections are provided for Russia. Although several countries in Eastern Europe, notably the Czech Republic and Poland, may be seen as approaching the same level of economic development as their Western European neighbors, the Eastern Europe aggregation still is useful, particularly given its importance to analysis of the impacts of the Kyoto Protocol: in most of the EE/FSU countries, carbon dioxide emissions in 2010 are expected to be well below their emissions targets for the first commitment period of the Protocol (2008-2012). Thus, in a modeling sense, the traditional grouping is useful.

The emerging economies include those countries whose economies are currently less developed, but whose energy use patterns, in general, are expected to begin resembling those of the mature market economies over the next two decades. The nations in this region, which typically have fairly energy-intensive industrial sectors, include such rapidly growing economies as China and India. Emerging Asia, the Middle East, Africa, and Central and South America are regional subgroups in the emerging economies region.

GDP Comparisons Based on Purchasing Power Parity Exchange Rates

Regular readers of the International Energy Outlook (IEO) will notice that, in this edition, the projections of real gross domestic product (GDP) for different countries and regions have been converted to U.S. dollars by using purchasing power parity (PPP) exchange rates. In all previous editions of the IEO, starting from 1985, market exchange rates were used for the conversion of real GDP projections.

PPP exchange rates are defined as rates of currency conversion that equalize the purchasing power of different currencies. For example, if the price of a hamburger in India is 60 rupees and in the United States it is $2.20, then the PPP exchange rate for hamburgers between India and the United States is 60 rupees to $2.20 or 27.3 rupees to the dollar. This concept of PPP for one good is generalized to a common basket of goods and services in the different countries to obtain PPP rates in practice. Market exchange rates on the other hand are the foreign currency prices of the dollar (or alternatively the dollar prices of foreign currencies) as traded in the foreign exchange markets.

In 2004 the average market exchange rate for a dollar in terms of Indian rupees was 45.3, compared with an average PPP rate of 7.3. Generally, PPP rates are much lower than market exchange rates in emerging economies, implying that a dollar buys a lot more in, for example, India or China than in the United States. Thus, converting emerging countries’ GDPs into dollars at market exchange rates can understate the true size of their economies and their living standards.

Real GDP projections for country and regions have been employed as one of the major determinants in the world energy forecasts contained in every edition of IEO. It was stated in the International Energy Outlook 2004 (pp. 17-18) that the energy projections were not affected by the choice between market exchange and PPP rates for GDP conversions, because both rates of conversion would leave unchanged the underlying rates of growth of real economic activity.^a in the various countries/regions. However, some readers have rightly objected to the presentation of real GDP projections in a common currency based on market exchange rates,^b because they understate the true size of emerging economies. As a result, their growth rates get relatively less weight than they should, and when they are aggregated to regions and finally to the world, the regional and world growth rates are underestimated. Furthermore, the internationally agreed System of National Accounts 1993, to which the United States is a signatory, states, “When the objective is to compare volumes of goods and services produced or consumed per head, data in national currencies must be converted into a common currency by means of purchasing power parities and not exchange rates.”^c

The use of PPP rates for converting national GDPs to a common currency has become widely accepted, and the Energy Information Administration has also adopted their use. Nevertheless, care needs to be exercised in interpreting the results.^d Market exchange rates are appropriate when the outcome is closely linked to the current exchange rate (for example, for exports and imports, especially of internationally traded commodities like crude oil, automobiles, etc.). PPP exchange rates are generally regarded as providing a better measure of the change in global economic well-being and cost of living. In addition, they are generally thought to provide a more balanced estimate of the relative importance of rich and poor countries. On the other hand, while PPP is useful for showing how much a country’s currency is worth in its home market, it does not measure effective purchasing power across borders.

^aFor IEO2005, GDP projections were first prepared for individual countries in terms of their own currencies and the 2000 prices of goods and services. The projections were then converted to 2000 U.S. PPP dollars by dividing each country’s real GDP projections by the PPP exchange rate between the United States and that country in 2000. Had the market exchange rate that existed, on average, in 2000 between each currency and the dollar been used instead, the growth rate of the resulting series would not differ from the growth rate of the real GDP series derived by using the 2000 PPP rate.

^bIan Castles, Visiting Fellow, Asia Pacific School of Government, the Australian National University (formerly head of Australia’s National Statistical Office); and David Henderson, Visiting Professor, Westminster School of Business, University of Westminster (formerly Chief Economist at the Organization for Economic Cooperation and Development).

^cSNA 1993, para. 1.38. See web site http://unstats.un.org/unsd/sna1993/toctop.asp.

^dThe International Monetary Fund, the Organization for Economic Cooperation and Development, and some private-sector organizations use PPP exchange rates for their world economic growth projections. The World Bank and other groups in the private sector use market exchange rates.

World Oil Prices in IEO2005

World oil prices in IEO2005 are defined on the basis of “average refiner acquisition cost” of imported oil to the United States (IRAC). The IRAC price tends to be a few dollars less than the widely cited West Texas Intermediate (WTI) spot price. WTI is a higher quality, lighter, low-sulfur crude than that represented by IRAC. In recent months, IRAC has been as much as 6 dollars a barrel lower than the WTI. In 2004, WTI averaged $41.44 per barrel and IRAC averaged $36.00 per barrel (in nominal dollars).

Gas to Liquids: A New Frontier for Natural Gas

The relatively high world crude oil prices of the past 3 years have drawn attention to the potential for developing previously uneconomical natural gas reserves, such as associated gas (gas found jointly with oil in an oil field) or stranded gas (gas that lies far from markets, thus requiring major investments to commercialize). Converting these resources to liquids—either to liquefied natural gas (LNG) or to petroleum liquid substitutes, such as diesel, naphtha, motor gasoline, or other products (such as lubricants and waxes) by employing “gas to liquids” (GTL) technology—could provide a way to bring these gas resources to market. GTL has recently become attractive as an option for monetizing stranded gas and complementing traditional commercialization opportunities such as LNG or pipeline transportation. 

Cost to Produce a Barrel of Diesel Fuel Grass Roots Gas to Liquids Plant vs. Refinery  (2002 Dollars per Barrel)  Printer friendly version Cost Component  GTL  Refinery  Natural Gas (at $1.00 per Million Btu)  $10.00    Crude Oil (at $20 per Barrel)    $20.00    Operating Costs  $ 4.00  $ 2.50    Capital Recovery, Taxes  $14.00  $ 6.50      Total  $28.00  $29.00

The economics of GTL continue to improve with advances in technology and scale. Capital costs have dropped significantly, from more than $100,000 per barrel of total installed capacity for the original plants to a range of $25,000 to $30,000 per barrel of capacity today.^a Moreover, Royal/Dutch Shell has commented that it expects to be able to reduce the costs to below $20,000 per barrel. By comparison,the costs associated with conventional petroleum refining are around $15,000 per barrel per stream day after several decades of technology improvements. The high oil prices of recent years, moreover, have made transportation fuels produced through GTL technology more commercially viable. Few companies release the detailed costs of their GTL conversion technologies, but according to ConocoPhillips, assuming that the cost of natural gas is $1.00 per million Btu, GTL fuel is cost  competitive with diesel fuel at world oil prices above $20 per barrel (see table). 

Among the different GTL products, the diesel fraction, in particular, is highly valued in the downstream market because of its unique properties that meet environmental regulations aimed at tightening emissions standards for light- and heavy-duty diesel vehicles. The GTL fuel reduces emissions relative to conventional diesel, as it contains near-zero sulfur and aromatics. GTL fuel also exhibits a high cetane number that enhances engine combustion performance.^b Because they are compatible with existing vehicle engines and fuel distribution infrastructures, GTL fuels are the most cost-effective in reducing emissions among the nonconventional fuels. 

Figure Data

GTL Joint Venture Projects in Qatar (2002 Dollars per Barrel)  Printer friendly version Project  Initial Capacity (Barrels per Day)  Start Date  Final Capacity (Barrels per Day)  Oryx (QP/Sasol Chevron)    34,000  2005  100,000  Pearl (Shell)    70,000  2009  140,000  ExxonMobil  154,000  2011  154,000  QP/Sasol Chevron  130,000  Delayed  130,000  Marathon    60,000  Delayed  120,000  ConocoPhillips    80,000  Delayed  160,000    Total  528,000    804,000

At present, worldwide there are at least 9 commercial GTL projects at various stages of planning and development for the period 2009 to 2012 that could bring to market an additional capacity of 580 thousand barrels per day (see figure). More than 19 additional proposed projects could double that capacity beyond 2012.^c 

These projects are being initiated by companies operating in gas-rich countries such as Qatar, Iran, Russia, Nigeria, Australia, and Algeria, where natural gas can be developed at a cost of less than $1.00 per million Btu.^d Qatar’s North Field, with an estimated 900 trillion cubic feet of natural gas reserves, and the adjoining South Pars field in Iran with an estimated 500 trillion cubic feet of reserves, are the cheapest natural gas resources in the world.^e For other countries, such as Nigeria and Algeria, GTL complements their LNG industries. GTL offers promise for use in Nigeria to convert natural gas that would otherwise be flared. Huge capital investments are required for GTL, however, and project financing and the availability of qualified contractors and operators may limit the growth of GTL projects on a year-to-year basis.^f 

Six of the nine confirmed GTL projects are located in the state of Qatar as joint ventures based on an integrated development and production sharing agreement (DPSA) with major international oil companies. Foreign companies have favored this approach, because it gives them an opportunity to book part of the gas reserves on their balance sheet and support their upstream and downstream activities.^g By 2011, Qatar is set to produce about 394,000 barrels of GTL products per day, the equivalent of 68 percent of the total confirmed new capacity.^h A list of Qatar’s GTL ventures is shown in the table below. 

Unlike many other gas-producing countries, Qatar has established a favorable climate in terms of transparent  business and investment policies. Foreign investors have also been encouraged to invest in Qatar’s energy sector because of its stable tax regulations, enforcement of formal agreements, and the government’s willingness to protect foreign investors through its legislature. In addition to the stable political climate, Qatar has invested substantially to develop infrastructure and services to support development of its natural gas resources. The country also provides guarantees for the safety of foreign employees and the potential for future development through expansion of existing facilities.ⁱ In the second quarter of 2005, Moody’s Investor Service upgraded Qatar’s rating for long-term foreign currency bonds and bank bonds from A3 to A1.^j 

Qatar has been able to reach agreements with a group of financial institutions to fund their gas-related projects (which exceed $60 billion) and has developed a master plan to expand its port and double the size of Ras Laffan Industrial city from 39 square miles to 77 square miles, in order to accommodate 7 GTL projects, 16 LNG trains, 5 gas processing plants, 6 to 7 ethylene plants, and a variety of other gas-related industries. By 2012, Qatar must produce nearly 25 billion cubic feet of natural gas per day to support its commitments. Some 10.3 billion cubic feet per day will be needed to produce 77 millions metric tons of LNG per year; 4 billion cubic feet per day for the 394,000 barrels per day of GTL; about 5 billion cubic feet per day for petrochemical, local power, and industrial projects; and about 2 billion cubic feet per day for exports through the Dolphin pipeline.

Over a 25-year period (the duration of a long-term LNG or GTL contract), Qatar would need to produce 225 trillion cubic feet, or one-fourth of its North Field reserve.^k Although the 900 trillion cubic feet of natural gas reserves from the North Field should be sufficient to support these projects on a sustainable basis, the quality of the gas and cost of development will vary from project to project. As a result, there could be delays in some of the plans. 

In the IEO2005 reference case, world demand for oil in the transportation sector is projected to grow by 2.1 percent per year, from 41.7 million barrels per day in 2002 to 67.3 million barrels per day in 2025. Even if all the proposed GTL projects worldwide materialized by 2025, assuming a 70-percent yield for diesel fuel from the natural gas stock, the expected GTL diesel supply of 1.2 million barrels per day in 2025 would represent only a fraction of total world transportation sector demand. Nevertheless, GTL diesel projects do provide gas-producing companies with an opportunity to add new value-added activities to their portfolios, as well as providing governments with an effective approach to meeting policy and environmental objectives. 

^aPersonal correspondence with Sylvia Williams, Business Development Manager, Global GTL Development, Shell International Gas Limited (May 3, 2005). 

^bACTED Consultants, “Gas to Liquids,” Chemicals Australia Web Site, http://www.chemlink.com.au/gtl.htm (1999).

^cFACTS Inc., Gas Databook I: Asia-Pacific Natural Gas & LNG (Honolulu, HI, 2005), p. 87.

dEnergy Information Administration, Model Documentation: Natural Gas Transmission and Distribution Module, DOE/EIA-M062 (Washington, DC, May 2005), Appendix F-27.

eFACTS Inc., “Iran’s Gas Industry and Export Projects,” Gas Insights, No. 45 (March 2005).

fM. Culligan, ConocoPhillips, Director of Business Development-Qatar GTL Project, “GTL: New Technology for a New Industry,” presentation at the Fifth Doha Gas Conference (March 1, 2005).

gWorld Markets Research Centre, “Shell Holds Back on FID for Qatar GTL,” web site www.worldmarketsanalysis.com (January 20, 2005).

hFACTS Inc., Gas Databook I (Honolulu, HI, 2005), p. 87.

iKeynote speech by Abdulla bin Hamad Al-Attiyah, Qatar Minister of Energy and Industry, at the Fifth Doha Gas Conference (February 28, 2005).

k“Qatar Seeks New Math From North Field,” World Gas Intelligence (June 1, 2005), pp. 2-3.

Recent Developments in World Coal Trade

The years 2003 and 2004 saw two solid back-to-back increases in international coal shipments. In 2003, world coal trade rose to 714 million tons, an increase of 9 percent from 2002. Preliminary data for 2004 indicate that world coal trade reached approximately 760 million tons, for an additional increase of 6 percent over 2003.^a Gains in coal shipments to each of the three major coal import demand regions discussed in this chapter contributed to the 100-million-ton-plus increase in world coal trade for the 2-year period.

In addition to the substantial increases in international coal trade in 2003 and 2004, other notable developments for the period were sharp upward movements in both ocean freight rates and coal export prices. During 2003, ocean freight rates for coal rose to near all-time record highs. Much of the increase was attributable to substantial growth in imports of iron ore by Chinese steel producers, which in turn created a shortage of ocean vessels for transporting other dry bulk products, including coal.^b China imported 163 million tons of iron ore in 2003, an increase of 33 percent from 2002.^c According to Global Insight, Inc., substantial amounts of new shipping capacity projected to come on line by the end of 2007 should help to alleviate the current capacity shortage, which in turn should lead to some reductions in freight rates.^d Global Insight estimates that between the beginning of 2004 and the end of 2007 annual dry-bulk-shipping capacity will expand by approximately 550 million tons, while demand for annual dry-bulk-shipping will increase by only 309 million tons.

While freight rates for coal retreated some from the historic highs reached in early 2004, coal export prices (both steam and coking) began increasing in late 2003 and continued to rise throughout 2004. Limited supply of export coal is the primary explanation given for the substantial rise in coal export prices. Some of the factors that restrained export supply during the year included (1) substantial shipping delays at Australian coal ports, as expansions in port infrastructure have not kept pace with the recent surge in China’s demand for iron ore and coking coal; (2) reduced exports of steam coal out of South Africa, mostly due to rail-related shipping delays; and (3) reduced exports and increased imports of coking coal by China. Relative to 2003, China imported an additional 4 million tons of coking coal in 2004 and exported 8 million tons less. Other factors affecting coal export prices in 2003 and 2004 were the effects of higher freight rates on international coal markets, increasing concentration in the ownership of coal export supply, and increasing importance of coal-on-gas competition in international power supply.^e

Taken together, higher freight rates and coal export prices led to considerably higher prices for imports of steam and coking coal. Quarterly data on average steam coal prices, published by the International Energy Agency, indicate that the average price of coal imported to the European Union in the fourth quarter of 2004 (nominal dollars per ton) was up by 92 percent from the fourth quarter of 2002,^f and the average price of steam coal imported to Japan was up by 67 percent. For coking coal, the prices of imported coal to the European Union and Japan in the fourth quarter of 2004 were 60 and 54 percent higher, respectively, than in the fourth quarter of 2002. In late 2004, annual negotiations between Japanese steel mills and Australian coking coal producers established a new benchmark price for Japan’s current fiscal year (ending on March 31, 2006) at $113.40 per ton free-on-board (f.o.b.) port of exit, which was more than double the benchmark price of $51.70 per ton for the previous year.^g

To date, higher coal prices do not appear to have had a significant effect on the demand for coal in international markets. In the electric power sector, the price of natural gas, coal’s key competitor in this sector, has also been high. In the industrial sector, steel producers have seen increasing profits despite higher prices for coking coal and iron ore, as strong worldwide demand for steel has led to considerably higher prices for their products. As indicated, coal freight rates are expected to retreat some from recent high levels as new shipping capacity comes on line over the next few years. In turn, this should lead to some downward pressure on the non-transportation component of the delivered price of coal in markets such as Europe, where Australian coal should again be able to compete with coal originating from South Africa and South America.

Along with strong growth in world coal trade in recent years, the geographical composition of coal supply for international markets has changed. While emerging coal exporting countries such as China, Colombia, and Indonesia have increased their output substantially over the past few years, several of the more established coal-exporting countries such as the United States, South Africa, Canada, and Poland have seen their exports remain relatively constant or decline. Between 1998 and 2003, coal exports from China expanded by a substantial 190 percent, from 36 million tons to 103 million tons.^h

^aSSY Consultancy and Research Ltd., SSY’s Coal Trade Forecast, Vol. 14, No. 2 (May 2005); and Energy Information Administration, Quarterly Coal Report, October-December 2004, DOE/EIA-0121(2004/4Q) (Washington, DC, March 2005), Tables 10, 12, and 14.

^b“Ocean Freight Rates Continue To Soar, Little Relief in Sight,” Coal Americas, Energy Publishing LLC, No. 29 (November 3, 2003), p. 1.

^c“Steel/Iron Ore: Iron Ore Exports, Iron Ore Imports and Steel Production,” Monthly Shipping Review SSY (April 21, 2005), p. 7.

^dGlobal Insight, Inc., Global Coal Trade and Price Report (2004) (Lexington, MA, December 2004), pp. xviii-xxii.

^e“Worsening Australian Coal Port Congestion,” Monthly Shipping Review SSY (April 21, 2005), p. 4; and “Supply Dynamics on the Move,” Petroleum Economist (October 6, 2004).

^fInternational Energy Agency, Databases for Energy Prices and Taxes, 2nd Quarter 2005, web site http://data.iea.org.

^gT. Grant-Taylor, “Coal Prices Steaming Ahead,” The Courier Mail (February 7, 2005), p. 18; and S. Wyatt, “Coup for Coking Coal Exports,” Australian Financial Review (December 13, 2004), p. 17.

^hSSY Consultancy and Research Ltd, SSY’s Coal Trade Forecast, Vol. 14, No. 2 (May 2005).

Electricity Consumption per Capita

Figure Data

Figure Data

Net electricity consumption in the world’s emerging economies is projected to grow by 149 percent from 2002 to 2025. By that measure, the emerging economies would surpass the mature market economies in terms of total annual electricity consumption; in terms of per capita consumption, however, the emerging economies are expected to continue trailing the mature market economies (see figure on Electricity Consumption per Capita). With the emerging economies expected to account for 82 percent of the world’s population in 2025, the projected increase in demand forecast for the region translates to an increase in per capita net electricity consumption from 950 kilowatthours per person in 2002 to 1,807 kilowatthours per person in 2025. Even with this strong growth, per capita consumption for the emerging economies as a whole would remain much lower than that for the mature market economies. Net electricity use per capita in the mature market economies is projected to increase from 8,371 kilowatthours per person in 2002 to 10,632 kilowatthours per person in 2025.

The differences in per capita electricity consumption among the emerging, transitional, and mature market economies are especially stark in the residential sector, which can serve as a proxy for living standards. For example, in the residential sector on a per person basis, Canada and the United States consumed over 24 times more electricity than China in 2002, 29 times more than Africa, and 47 times more than India. Although the differences are expected to narrow over the forecast period, they still would be substantial in 2025, with per capita electricity use in the United States remaining 9 times higher than in China, 14 times higher than in Africa, and 17 times higher than in India (see figure on Residential Sector Electricity Consumption per Capita by Country Group, 2002 and 2025).

How Nuclear Power Could Shape World Electricity Markets: Two Nuclear Power Development Scenarios

Two opposing scenarios of nuclear power development can be used to assess the potential of nuclear power in the electricity markets of the future. In a “strong nuclear power revival” case developed for IEO2005, few nuclear plants are retired, and new builds increase the world’s total nuclear generating capacity to 570 gigawatts in 2025. In contrast, a “weak nuclear power” case assumes that nuclear power programs, especially in Western Europe and the EE/FSU, are dismantled, few new nuclear power plants are constructed, and installed nuclear power capacity falls to 297 gigawatts in 2025. The IEO2005 reference case projects an increase in world nuclear capacity, from 361 gigawatts in 2002 to 422 gigawatts in 2025.

In very few instances is the decision to build nuclear power capacity left entirely to corporations or utilities that would base their decisions solely on economics. In general, government policy (with an eye to public opinion) guides the development of nuclear power. The OAPEC oil embargo of 1973-74 led some nations to pursue nuclear power programs aggressively in the 1970s, mostly with strong public support; but subsequent accidents at the Three Mile Island nuclear power plant in the United States in 1979 and Chernobyl in the Soviet Union in 1986 pushed public opinion and national energy policies away from nuclear power. In the United States, rapidly increasing capital costs and repeated construction delays virtually ended construction of nuclear power plants; and in Europe, both before and after the Chernobyl disaster, several European governments, including Italy, Austria, Belgium, Germany, and Sweden announced their intentions to withdraw from the nuclear power arena.

For many years analysts expected social, economic, and political pressures to cause a substantial slowdown of nuclear power expansion in the short term and a decline in nuclear generating capacity in the long term. More recently, however, there has been talk of a “renaissance” in the nuclear power programs of the United States and some European countries, as fossil fuel prices have remained relatively high, and energy security issues, concerns about air pollution and global warming, and the high performance levels of existing nuclear power plants have come to the forefront.^a On the other hand, a future adverse event involving nuclear power, such as another Chernobyl-sized nuclear power plant accident or a terrorist event involving an attack on a nuclear plant or using processed nuclear materials to commit an act of terrorism, could strengthen negative perceptions of nuclear power.

The table on the opposite page summarizes the projected fuel mix for the world’s installed electric power capacity in three cases: the IEO2005 reference case, strong nuclear power revival case, and weak nuclear power case. With the same macroeconomic assumptions in each of the three cases, it is not surprising that they all project the same total (about 5,500 gigawatts) for world installed electricity capacity in 2025.

Much of the expansion in nuclear generating capacity projected in the strong nuclear power revival case—a total of 148 gigawatts—is in regions with older, more mature nuclear power markets. Many Western European and EE/FSU countries have established nuclear power industries, and they would be capable of staving off the decline in nuclear power capacity projected in the reference case by reversing planned phaseouts of existing nuclear power plants, lengthening operating lives, and constructing new nuclear capacity in response to, for example, concerns about climate change.

World Installed Electricity Generation Capacity by Fuel in Three Nuclear Capacity Cases, 2002-2025 (Gigawatts) Printer friendly version Analysis Case and Fuel Type 2002 Projections Average Annual Percent Change, 2002-2025 2010 2015 2020 2025 IEO2005 Reference Case   Natural Gas and Oil 1,207 1,851 2,071 2,304 2,560  3.3   Coal    987 1,151 1,232 1,322 1,403  1.5   Nuclear    361    390    401    411    422  0.7   Renewable    763    927    980 1,036 1,110  1.6     Total 3,318 4,319 4,684 5,073 5,495  2.2 Strong Nuclear Power Revival Case   Natural Gas and Oil 1,207 1,849 2,041 2,254 2,464  3.2   Coal    987 1,153 1,232 1,320 1,397  1.5   Nuclear    361    395    449    498    570  2.0   Renewable    763    928    970 1,020 1,078  1.5     Total 3,318 4,326 4,692 5,092 5,509  2.2 Weak Nuclear Power Case   Natural Gas and Oil 1,207 1,865 2,087 2,342 2,626  3.4   Coal    987 1,160 1,245 1,339 1,426  1.6   Nuclear    361    360    357    340    297 -0.8   Renewable    763    934    987 1,050 1,127  1.7     Total 3,318 4,318 4,677 5,071 5,476  2.2

In the strong nuclear case, Western Europe’s projected nuclear generating capacity in 2025 is 52 gigawatts higher than in the reference, the EE/FSU’s is 36 gigawatts higher, and Japan’s is 15 gigawatts higher. The IEO2005 strong nuclear case assumes that emerging economies with nuclear power expansion plans, including China, India, and South Korea, expand the development of nuclear power to the greatest extent possible. Therefore, in the strong nuclear revival case the emerging nations are able to increase their nuclear capacity by adding a combined 37 gigawatts of additional capacity by 2025 relative to the reference case values.

Construction and operation of 148 gigawatts of additional nuclear capacity in 2025 in the strong nuclear revival case would have the greatest impact on the fuel shares of natural gas, oil, and renewables in the fuel mix for world electricity generation (see table). Because Western Europe, the EE/FSU, and Japan all are projected to see declines or minimal growth in coal-fired capacity in the reference case, there is little or no opportunity for new nuclear capacity to displace coal. As a result, the strong nuclear revival case shows declines of 96 gigawatts in natural gas and oil capacity and 32 gigawatts in renewable electricity capacity in 2025 relative to the reference case projections.

In the weak nuclear power case, almost every region loses some nuclear capacity by 2025 relative to the reference case. Only for the Middle East and Mexico, with their relatively small nuclear power industries, are the 2025 projections unchanged from those in the reference case.^b Total world installed nuclear capacity in 2025 is 125 gigawatts lower in the weak nuclear case than in the reference case. Western Europe sheds the largest amount of nuclear capacity in 2025 in the weak nuclear case (50 gigawatts), followed by the EE/FSU (27 gigawatts), emerging Asia (24 gigawatts), and Japan (14 gigawatts).

In emerging Asia, coal-fired capacity makes up for most of the loss of nuclear capacity in the weak nuclear case, with 20 gigawatts of additional coal capacity constructed in China, India, and South Korea compared to the reference case in 2025. The other emerging Asian countries construct an additional 7 gigawatts of natural-gas-fired and oil-fired capacity in the weak nuclear case. In Western Europe, the EE/FSU, and Japan, natural gas, oil, and renewables are used to make up for the loss of nuclear capacity, with 63 gigawatts of additional natural-gas- and oil-fired capacity and 10 gigawatts of additional renewable capacity constructed relative to the reference case projections in 2025.

^aS. Taub and J.-L. Wang, The U.S. Nuclear Power Business: Poised for Expansion? (Cambridge, MA: Cambridge Energy Research Associates, May 2005), p. 1 (private report).

^bFor the purposes of this analysis, U.S. nuclear capacities were not varied across the nuclear cases. While EIA recognizes that there is potential for increases or decreases in U.S. nuclear power capacity in the future, no analysis has been done to quantify that potential. As a result, U.S. numbers are held constant to levels reported in the Annual Energy Outlook 2005.

Market Mechanisms Under the Kyoto Protocol

In order to help participating countries meet their goals, the Kyoto Protocol includes market mechanisms that are designed to allow some flexibility in reaching reduction targets. The three primary market mechanisms are described below.

Clean Development Mechanism (CDM): The CDM is designed to promote participation by emerging economies in projects that lead to certified and verifiable emissions reductions. It allows Annex I countries to invest in emissions reduction projects in non-Annex I countries and apply credits received for those projects toward meeting their commitment goals. Currently, CDM reductions achieved between 2000 and 2012 may be used to meet requirements in the first commitment period, 2008 to 2012.

Several recent studies have estimated that the average annual demand for CDM Certified Emissions Reductions (CERs) will be between 50 and 500 million metric tons, and that the cost of a CER will be between $5 and $15 per metric ton.^a Emission reductions in 2010 of 400 million metric tons carbon dioxide equivalent would require annual investments of $10 billion. For reference, annual foreign direct investment in emerging economies between 1997 and 2002 averaged $140 billion,^b and it is estimated that the emerging economies will need a total of $192 billion annually in energy investments between 2001 and 2010.

Finally, CDM projects generally require a leadtime of 4 to 5 years to begin receiving credits. Because of risks to both the buyers and sellers of CERs derived from CDM projects and the abundance of excess emissions credits—so-called “hot air”—that could be sold internationally over the forecast period, the IEO2005 Kyoto Protocol case does not explicitly include CDM projects.

However, CDM projects serve as a mitigating factor to prevent the countries in possession of hot air credits from exercising monopoly power, since in many cases CDM projects would offer the best alternative to emissions trading after participating countries have met their domestic goals.

Emissions Trading: This market mechanism allows emitters who are in an advantageous position with regard to emissions reductions (as most of the EE/FSU countries currently are) to make further reductions below their target levels and sell the difference to emitters whose domestic reduction costs are relatively high. In theory, such trading would allow the necessary emission reduction to be achieved in the aggregate at the lowest possible cost, regardless of where they take place. Indeed, Russia and Ukraine could in theory meet all the required reductions of Annex B countries.^c After domestic emissions reduction goals are achieved, the IEO2005 Kyoto Protocol case assumes that additional reductions will be achieved by emissions trading.

Joint Implementation (JI): This market mechanism is similar to the CDM, except that JI projects would involve only the Annex B countries, and only reductions achieved during the 2008-2012 commitment period may be used. Because the SAGE model aggregates all the Western European countries into one region, JI is implicit in the projections for Western Europe. In contrast, because Canada and Japan are represented as single regions in SAGE, each must achieve its domestic goals (in the modeling process) independently of JI projects. As with CDM projects, the IEO2005 Kyoto Protocol case assumes that emissions trading will be the least-cost alternative to reductions once domestic goals are achieved.

^aE. Haites, Estimating the Market Potential for the Clean Development Mechanism: Review of Models and Lessons Learned. Prepared for the World Bank Carbon Finance Business PCFplus Research Program, the International Energy Agency, and the International Emissions Trading Association (Washington DC: PCFplus Report 19, June 2004), p. v, web site www.iea.org/textbase/papers/2004/cdm.pdf.

^bE. Haites, Estimating the Market Potential for the Clean Development Mechanism: Review of Models and Lessons Learned, p. iv.

^cAnnex B countries are the mature market economies that are part of Annex I, excluding the transitional economies.