International Energy Outlook 2004
Converting Gross Domestic Product for Different Countries to U.S. Dollars: Market Exchange Rates and Purchasing Power Parity Rates
The world energy forecasts in IEO2004 are based primarily on projections of GDP for different countries and regions, which for purposes of comparison are expressed in 1997 U.S. dollars. First, GDP projections are prepared for the individual countries in terms of their own national currencies and 1997 prices of goods and services. Then, the projections are converted to 1997 U.S. dollars by applying average 1997 foreign exchange rates between the various national currencies and the dollar. The resulting projections of real GDP are thus based on national 1997 prices in each country and the 1997 market exchange rate (MER) for each currency against the U.S. dollar.
An alternative method for converting GDP projections in different national currencies to U.S. dollars would employ exchange rates based not on currency markets but on the concept of “purchasing power parity” (PPP). PPP exchange rates are derived through a process of equalizing the purchasing power of different currencies by eliminating differences in price levels for various goods. As one example, if the price of a hamburger is $2.20 in the United States and 60 rupees in India, then the PPP exchange rate for hamburgers between the two currencies can be calculated as 60/2.2, or 27.3 rupees to the dollar.a Similarly, the concept of PPP for one good can be generalized to various baskets of goods and services in different countries to derive PPP rates for converting aggregate national income and product accounts to U.S. dollars.b
The table on the following page shows 2001 GDP and the IEO2004 projections for 2025 GDP, converted to 1997 U.S. dollars based on 1997 MER and PPP rates for various countries and regions, as well as the ratios of the two results. For most of the industrialized countries, the ratio of 2001 GDP based on MER to that based on PPP is close to 1, indicating that the cost of living in those countries generally is reflected in the exchange rates for their currencies. Two exceptions are Mexico and Japan. For Mexico the ratio is 2.3, implying a much lower cost of living than in the United States and thus an economy that is 2.3 times larger than suggested by the MER-based real GDP calculation. For Japan the ratio is 0.7, implying a higher cost of living than in the United States and, in terms of purchasing power, an economy that is 30 percent smaller than suggested by the MER-based GDP. The ratios for the developing countries are much larger—including values of 5.1 for China and 5.6 for India.
In terms of the IEO2004 forecasts, however, the apparent discrepancy between the MER and PPP conversion results for 2001 GDP does not mean that the two methods would yield different energy demand projections. Comparison of the PPP/MER ratios for historical 2001 GDP and projected 2025 GDP shows that, for each country and region, the two ratios are identical. In other words, it makes no difference for the energy demand forecasts whether the GDP forecasts are based on MER or PPP as long as they are consistent over the entire period, because both forecasts are based on volumes, which do not reflect changes in exchange rates and prices over time.
| Comparison of Real GDP by Region and Country for 2001 and 2025 Converted to 1997 U.S. Dollars Based on Purchasing Power Parity Rates (PPP) and Market Exchange Rates (MER) Printer Friendly Version 
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Oil Resources in the 21st Century
Early in 2004, two oil market issues captured the attention of market observers. First, Royal Dutch Shell announced that it was revising its reporting of reserves, moving 3.9 billion barrels of oil equivalent from the proved to the probable category. Second, an article in the New York Times on February 24 implied that Saudi Arabia’s oil fields were in decline, and that the kingdom probably would be unable to expand oil production capacity to meet increasing oil demand. Both of these supply-side issues had a somewhat negative effect on the stock market. The reserve revision by Shell turned out to be a reinterpretation of reporting conventions and had more to do with natural gas than oil; and in an emphatic rebuttal to the New York Times article, Saudi Arabia maintained that its oil producers are confident in their ability to sustain significantly higher levels of production capacity well into the middle of this century.a
As the above examples demonstrate, whenever the sustainability of the oil resource base comes into question, there are always those eager to warn the world of a looming shortage in oil supplies. Inevitably, the question becomes, “Are we running out of oil?” In April 2000, the U.S. Geological Survey (USGS) released the results of its thorough and methodologically sound assessment of worldwide petroleum resources.b The USGS identified at least 3 trillion barrels (mean estimate) of ultimately recoverable conventional oil resources worldwide. The assessment prompted EIA to analyze the long-term world conventional oil supply potential, using alternative assumptions about the levels of ultimately recoverable resources and demand growth.c Based on the EIA analysis, all three of the IEO2004 oil price cases would expect conventional oil to peak closer to the middle than to the beginning of the 21st century.
No one doubts that fossil fuels are subject to depletion, and that depletion leads to scarcity, which in turn leads to higher prices. Resources are defined as “nonconventional” when they cannot be produced economically at today’s prices and with today’s technology. With higher prices, however, the gap between conventional and nonconventional oil resources narrows. Ultimately, a combination of escalating prices and technological enhancements can transform the nonconventional into the conventional. Much of the pessimism about oil resources has been focused entirely on conventional resources. In the IEO2004 forecast, nonconventional liquids include production from oil sands, ultra-heavy oils, gas-to-liquids technologies, coal-to-liquids technologies, biofuel technologies, and shale oil. Total nonconventional liquids production in 2025 is projected at 4.1, 5.2, and 8.0 million barrels per day in the low price, reference, and high price cases, respectively. It is anticipated that nonconventional oil resources will act as a buffer against prolonged periods of high oil prices well into the middle of this century, and perhaps well beyond.
aM. Abdul Baqi and N. Saleri, Fifty-Year Crude Oil Supply Scenarios: Saudi Aramco’s Perspective (Washington, DC, February 2004).
bU.S. Geological Survey, World Petroleum Assessment 2000, web site http://greenwood.cr.usgs.gov/energy/WorldEnergy/DDS-60.
c”World Conventional Oil Supply Expected To Peak in 21st Century,” Offshore (April 2003), p. 90
Qatar LNG: Status and Developments
By 2010 Qatar is expected to be one of the world’s leading producers of LNG. The country has been very successful in finding new markets. In 2002, Qatar earned around $3.7 billion from exporting 15 million metric tons of LNG.a At the LNG Ministerial Summit in December 2003, sponsored by the U.S. Department of Energy, Qatar’s energy minister announced that his country will invest some $25 billion in LNG projects by 2010, quadrupling its export capacity.b
Qatar is a relatively new supplier of LNG, shipping its first LNG to Japan in 1997. Its focus is the Asian market, the proximity of which has been strategic to profitability. As technology has reduced the cost of liquefaction and shipping by almost a third in the last few years, Qatar has become the focus of attention as it negotiates projects that will expand its market share in Asia and allow it to enter the Western market.
With proven reserves of over 900 trillion cubic feet, Qatar’s natural gas resources rank third in size behind Russia’s and Iran’s.c Most of the country’s reserves are located in the North Field, to date the largest known non-associated gas field in the world. Qatar began developing the North Field gas reserves in 1984, for the most part producing condensates.d In addition, the Dukhan field and smaller associated gas reserves in the Id al Shargi, Maydan Mahzam, Bul Hanine, and al-Rayyan oil fields are estimated to contain 10 trillion cubic feet of gas.
For the last few years the Qataris have opted to diversify their gas portfolio by investing in regional gas pipeline projects, gas-to-liquid technology, and the expansion of their liquefaction capacity. The most ambitious regional pipeline project to date is the $4 billion Dolphin Gas project that will pipe gas over 260 miles from Qatar to the United Arab Emirates (UAE) and Oman, delivering an estimated 2 billion cubic feet per day by 2006.e Though these importing countries have their own reserves, and export LNG themselves, they find it less costly to import Qatari gas than to develop and treat their own non-associated gas supplies. Kuwait and Bahrain, two other Gulf States, have also approached Qatar with a view to follow suit.
Qatar has also invested in gas-to-liquid technology (GTL). This approach, developed at great cost, converts natural gas into high-grade gasoline and distillates. Qatar has already drawn up plans to produce 174,000 barrels per day. It is expected that its project with Sasol, the South African oil company, will produce 34,000 barrels per day by 2005; according to current estimates another venture with Shell International will produce 140,000 barrels per day by 2007.f
Currently, Qatar has two LNG export projects that serve mainly the Asian market:
- Qatar Liquefied Gas Company Limited (QatarGas). The first of this three-train project went on stream in 1996. Partners comprise the state-owned Qatar Petroleum (QP), which has a majority interest, ExxonMobil, Total, Marubeni, and Mitsui. At present, the project has a capacity of around 8 million metric tons per year; after debottlenecking is completed in 2005, it will reach 9.5 million metric tons per year. In addition, QatarGas has long-term contracts for the sale of 4 million metric tons per year to Chubu Electric Company in Japan and another 2 million metric tons per year to seven other Japanese electric and gas utilities. It also delivers spot cargoes to Europe and the United States.
- Ras Laffan Liquefied Natural Gas Company Limited (RasGas). With a current capacity of 6.6 million metric tons per year, RasGas sells 4.8 million metric tons per year to Korea Gas under a long-term contract. Two more trains are presently under construction, each with a 4.7 million metric tons per year capacity. Of this, 7.5 million metric tons per year will go to India under a 25-year contract, with additional volumes available for spot sales. Participants in the first phase of RasGas are QP, ExxonMobil, Itochu, and LNG Japan, though only QP and ExxonMobil are involved in the expansion phase.g
Other projects have also been proposed. In 2003, Qatar signed two agreements: one with ExxonMobil, to provide the United Kingdom with 15 million metric tons per year by 2006-2007; and a second, with ConocoPhillips, to provide 9.2 million metric tons per year by 2008-2009, 7.5 million metric tons of which is to be destined for the United States. Total is negotiating a similar volume (9.2 million metric tons per year) with QatarGas, also for delivery by 2008-2009; ExxonMobil too is working on providing an additional 15 million metric tons per year for the United States by 2010.h In all of these projects, Qatar intends partnering international companies across the entire spectrum, ranging from production to liquefying, transporting, regasifying, distributing, etc.
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Qatar LNG is expected to occupy a leading position in the United States market over the next two decades. For the next 6 years, with the U.S. average annual wellhead price of gas not expected to be lower than $ 3.50 per million Btu, Qatar will be in a position to recover its costs in the U.S. market (see map).
The Middle East has the lowest exploration and development costs for gas of any region in the world, with capital costs estimated at less than $0.20 per million Btu.i Even though most of Qatar’s gas is offshore, the transmission pipelines to connect the gas fields to the LNG liquefaction plants are relatively short, comprising only a small share of the overall cost. An added bonus is that most of the proposed liquefaction projects are in Ras Laffan Industrial City, where they take advantage of existing infrastructures and large amounts of land available for development, additional factors that keep spending down. Technological advances are such that the capacity of the new trains might reach 7 million metric tons per year (prior to this the limit was 2 to 3 million metric tons). Once economies of scale are factored in, the competitiveness of Qatar’s LNG should continue to increase.
In order to finance its current projects, Qatar maintains and enjoys a strong credit rating, despite regional unrest.j Qatar’s infrastructure is safer than in most nearby countries because it hosts U.S. military bases.k Costs for Qatar’s new liquefaction facilities will therefore remain stable, despite the region’s strife.
Although LNG imports in 2002 comprised only about 1 percent of the U.S. market, this amount will increase substantially over the next two decades. At present there are four terminals in the continental United States that receive LNG, with a total capacity of about 3 billion cubic feet per day. By 2025 the projected increase is estimated at 14 billion cubic feet per day, necessitating at least 10 more terminals. In fact the major challenge regarding the future of LNG in the United States is not the availability of terminals (a need that is slowly being met), rather it is the reliability of supply. Equally important, there is also the matter of transparent and sustainable rules governing the gas business per se.l
A major concern to a supplier such as Qatar is the uncertainty regarding U.S. restructuring of the gas and electric power industries. LNG suppliers see deregulation as a disadvantage, because it is likely to result in changes to the business environment, such as the insistence on shorter contracts, the removal of the take-or-pay clauses and fixed destination from future contracts, and requiring third-party access to regasification facilities. These changes force suppliers to shoulder a greater portion of the risk, which might hinder the development of liquefaction facilities.
The U.S. regulatory body, the Federal Energy Regulatory Commission (FERC), has lately eased its requirement for open access to regasification capacity. This development has encouraged potential suppliers such as Qatar and its major partners to consider investing in new terminals. At present, many LNG investors who have been monitoring the Henry Hub index of natural gas prices are eager to capture what appears to be a high margin of profitability in supplying LNG to the U.S. market. Although Henry Hub index prices have been higher than the cost of LNG imported to the United States for the past 4 years, some observers believe that the index does not reflect market realities, and may encourage over-investment in LNG that will not be economically sustainable.
LNG projects are multi-billion-dollar undertakings, and at this point it is unclear whether Qatar will be willing to accept the high financial risks associated with increasing its LNG capacity to supply the North American market.
aWorld Market Research Centre, “Country Reports—Qatar” (December 2003), web site www.wmrc.com.
bPersonal communication with Abdullah bin Hamad Al-Attiyah, Minister of Energy & Industry, State of Qatar (Washington, DC, December 18, 2003).
cEmbassy of Qatar, Qatar: The Modern State (Washington, DC, November 2003).
dCondensate is a light hydrocarbon liquid that is suspended in natural gas reservoirs and can be recovered by condensation of hydrocarbon vapors. After it is separated from the gas, it remains liquid without pressurized or refrigerated containment.
ePersonal communication with Khaldoon Al Mubarak, Executive President of Dolphin Energy Limited (Washington, DC, December 18, 2003).
fEnergy Information Administration, Country Analysis Brief: Qatar (November 2003), web site www.eia.doe.gov/emeu/cabs/ qatar.html.
gPersonal communication with Colleen Taylor-Sen, Senior LNG Advisor, Gas Technology Institute (Washington, DC, December 18, 2003).
hEnergy Information Administration, The Global Liquefied Natural Gas Market: Status & Outlook, DOE/EIA-0637(2003) (Washington, DC, December 2003), web site www.eia.doe.gov/oiaf/analysispaper/global/pdf/eia_0637.pdf.
iInternational Energy Agency, World Energy Investment Outlook 2003 (Paris, France, 2003), p. 228, web site www. worldenergyoutlook.org.
jInternational Energy Agency, World Energy Investment Outlook 2003 (Paris, France, November 4, 2003), p. 231.
kWorld Market Research Centre, “Country Reports—Qatar” (March 2004), web site www.wmrc.com.
lPersonal communication with Ibrahim B. Ibrahim, Chairman of Marketing and Vice Chair of the Board of Qatar RasGas Company (Washington, DC, December 18, 2003).
Coal Production and Subsidies in Western Europe
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In Western Europe, recent trends in consumption of hard coala are closely correlated with trends in its production, primarily because coal imports have increased by considerably less than production has declined (see figure). From 1980 to 2002, coal imports to Western Europe increased by 77 million tons, while hard coal production declined by 214 million tons. Following the closure of the last remaining coal mines in Belgium (in 1992) and Portugal (in 1994), only four member states of the European Union (the United Kingdom, Germany, Spain, and France) continued to produce hard coal,b and all have seen their output of hard coal decline since 1990. The European Union will add two additional hard coal producers, Poland and the Czech Republic, in 2004.c In addition to hard coal, Germany and Greece produce and consume substantial amounts of lignite, and some lignite is also produced at two mines in the northwestern area of Spain.
The governments of Germany, Spain, France, and the United Kingdom currently support domestic production of hard coal through subsidies approved by the European Commission (see table on page 82).d In 2001, authorized subsidies amounted to $3,668 million in Germany, $919 million in Spain, $875 million in France, and $90 million in the United Kingdom (in nominal U.S. dollars).e In Germany, Spain and France, the average subsidy per ton of coal produced exceeds the average value of imported coal. Hard coal production is expected to come to an end in France in 2004, but the governments in Germany and Spain plan to continue financial support for their hard coal industries, while acknowledging that future reductions in coal production are inevitable when existing mines exhaust their minable reserves.
After 50 years in force, the European Coal and Steel Community treaty expired in July 2002. The European Commission has proposed a new state aid program for coal, establishing the continuation of subsidies for hard coal production in member states through December 31, 2010.f The Commission wants to establish measures that will promote the development of renewable energy sources while maintaining a minimum level of subsidized coal production in the European Union as an “indigenous primary energy base.” The guiding principle will be that subsidized coal production will be limited to the minimum necessary for energy security—maintaining access to coal reserves, keeping equipment in an operational state, preserving the professional qualifications of a nucleus of coal miners, and safeguarding technological expertise.
In the United Kingdom, hard coal production fell from 104 million tons in 1990 to 35 million tons in 2001.g Of the 2001 total, 19 million tons was from underground operations and 16 million tons from surface mines.h The United Kingdom’s remaining hard coal mines are by far the most productive in Western Europe, and improvements in mining operations in recent years have increased average labor productivity (tons produced per miner per year) from 1,272 in 1990 to 2,929 in 2001.i The price of coal from domestic mines is essentially at parity with the price of coal imports, and it is likely that U.K. coal production will fluctuate with changes in international coal prices.j When international coal prices fell between 1998 and 2000, the government reinstated coal production subsidies for 2000 through 2002 in an effort to protect the country’s remaining coal operations.k
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At 2001 production levels, recent and impending mine closures in the United Kingdom will remove approximately 6 million tons of underground coal production by the end of 2007.l Mines closed or scheduled for closure include Clipstone and Betws (both closed in 2003), Ricall, Stillingfleet, and Wistow (all part of the Selby Complex and to be closed in June 2004), and Ellington (to be closed in 2007).m A recent report by the U.K. government indicates that underground mining operations will continue to be closed as they reach the end of their geologic and economic lives, and production at most of the country’s deep mines is likely to end within the next 10 years.n In 2003, some additional state aid was made available to a number of underground mines, based on the premise that the resulting capital investments would provide access to additional reserves of coal.o
Germany’s hard coal production dropped from 86 million tons in 1990 to 32 million tons in 2001.p Currently, all of its hard coal production comes from 10 underground mines operated by Deutsche Steinkohle.q Recent negotiations and political decisions by the German government, the European Commission, the miners’ trade union, and Deutsche Steinkohle point to the probable closure of 5 of those mines between 2006 and 2012, reducing output to an estimated 18 million tons.r
Germany continues to be the world’s top producer of lignite, despite substantial reductions over the past decade. Between 1990 and 2001, German lignite production fell by 55 percent, from 427 to 193 million tons, primarily because natural gas has displaced both lignite and lignite-based “town gas”s in the eastern states since reunification in 1990.t The collapse of industrial output in the eastern states was a contributing factor.
In Spain, hard coal production fell from 22 million tons in 1990 to 16 million tons in 2001.u Spain has adopted a restructuring plan for 1998 through 2005 that includes a gradual decline to 12 million tons of production.v In addition to hard coal, two lignite mines in Spain produced 9 million tons in 2001. Both mines, however, are scheduled to close in the near future.w
In France, production of hard coal declined from 12 million tons in 1990 to 2 million tons in 2001.x The closure of the country’s three remaining coal mines in 2003 (Gardanne and Merlebach) and 2004 (La Houve) will bring an end to the country’s 200-year history of coal production.y
Greece is another major producer of coal in Western Europe, but its reserves and production consist of lower-ranked lignite. Lignite production in Greece increased from 57 million tons in 1990 to 74 million tons in 2001,z virtually all used for electricity generation. The heat content of lignite reserves in Greece is low, even in comparison with lignite reserves in other countries, and substantial amounts are required per unit of electricity generated.
aInternationally, the term “hard coal” is used to describe anthracite and bituminous coal. In data published by the International Energy Agency, coal of subbituminous rank is classified as hard coal for some countries and as brown coal (with lignite) for others.
bDirectorate-General XVII—Energy, European Commission, The Market for Solid Fuels in the Community in 1996 and the Outlook for 1997 (Brussels, Belgium, June 6, 1997), web site www.europa.eu.int.
cCommission of the European Communities, Proposal for a Council Regulation on State Aid to the Coal Industry (Brussels, Belgium, July 25, 2001), p. 17, web site www.europa.int.
dIn Spain, subsidies support the production of both hard coal and subbituminous coal.
eCommission of the European Communities, Report From the Commission On the Application of the Community Rules For State Aid To The Coal Industry In 2001 (Brussels, Belgium, October 4, 2002), p. 10, web site www.europa.eu.int.
fCommission of the European Communities, Proposal for a Council Regulation on State Aid to the Coal Industry (Brussels, Belgium, July 25, 2001), web site www.europa.eu.int.
gEnergy Information Administration, International Energy Annual 2001, DOE/EIA-0219 (2001) (Washington, DC, February 2003), Tables 2.5 and 5.4.
hUK Department of Trade and Industry, “Energy Statistics: Coal,” Table 2.7, web site www.dti.gov.uk.
iInternational Energy Agency, Coal Information 2003 (Paris, France, November 2003), Table 6.4.
jCommission of the European Communities, Proposal for a Council Regulation on State Aid to the Coal Industry (Brussels, Belgium, July 25, 2001), pp. 24-25, web site www.europa.eu.int.
k“Coal Industry Receives Additional Funds as EU Drafts New Aid Plan,” Financial Times: International Coal Report, No. 530 (July 31, 2001), pp. 8-9.
l“Britain’s Coal Industry,” UK Coal, web site www.rjb.co.uk (accessed: February 8, 2004).
mUK Department of Trade and Industry, “Energy Statistics: Coal,” Table 2.10, web site www.dti.gov.uk; “100 Jobs to Go as Pit Shuts,” BBC News (July 23, 2003), web site news.bbc.co.uk; and “End Predicted for Lone Coal Mine,” BBC News (March 27, 2003), web site news.bbc.co.uk.
nUK Department of Trade and Industry, Energy White Paper: Our Energy Future—Creating a Low Carbon Economy, Cm 5761 (February 2003), pp. 93-94.
oUK Department of Trade and Industry, Energy White Paper: Our Energy Future—Creating a Low Carbon Economy, Cm 5761 (February 2003), pp. 93-94; and “UK Coal PLC (UKC.L) Investment Aid,” Regulatory News Service (December 18, 2003).
pEnergy Information Administration, International Energy Annual 2001, DOE/EIA-0219(2001) (Washington, DC, February 2003), Tables 2.5 and 5.4.
qInternational Energy Agency, Coal Information 2003 (Paris, France, November 2003), Tables 6.1; and “New German Import Surge on the Horizon,” McCloskey’s Coal Report, No 65 (July 25, 2003), p. 8.
r“New German Import Surge on the Horizon,” McCloskey’s Coal Report, No 65 (July 25, 2003), p. 8.
s“Town gas” (or “coal gas”), a substitute for natural gas, is produced synthetically by the chemical reduction of coal at a coal gasification facility.
tDirectorate-General XVII—Energy, European Commission, Energy in Europe: European Union Energy Outlook to 2020 (Brussels, Belgium, November 1999), p. 47.
uEnergy Information Administration, International Energy Annual 2001, DOE/EIA-0219 (2001) (Washington, DC, February 2003), Tables 2.5 and 5.4.
vCommission of the European Communities, Proposal for a Council Regulation on State Aid to the Coal Industry (Brussels, Belgium, July 25, 2001), p. 25, web site www.europa.eu.int.
w“Spain Promises Import Bonanza,” McCloskey Coal Report, No. 19 (September 21, 2001), pp. 21-22.
xEnergy Information Administration, International Energy Annual 2001, DOE/EIA-0219 (2001) (Washington, DC, February 2003), Tables 2.5 and 5.4.
y“French Gardanne Coal Mine to be Shut, Miners Protest,” Platts Commodity News (February 4, 2003); and R. Tieman, “France Puts an End to Its Mining Industry,” The Business ( January 12, 2003).
zEnergy Information Administration, International Energy Annual 2001, DOE/EIA-0219(2001) (Washington, DC, February 2003), Table 5.4.
Small wind turbines (installed capacity up to 100 kilowatts) have the potential to penetrate markets in rural areas of developing countries. There are more than 5,000 units installed worldwide. The United States, a leading producer, has four manufacturers of small turbines, which manufacture about 30 percent of the units sold worldwide.a In addition to wind-only applications, there are numerous hybrid applications, involving wind and other renewables, wind with water pumping systems, or wind with water treatment systems. Hybrids provide a more stable power supply, by smoothing out some of the seasonal variation inherent in wind-only systems.
One barrier to the market penetration of small wind turbines is cost. As with many technologies, there are economies of scale associated with small wind turbine systems. At the 50-watt level, they cost about $8,000 per kilowatt; at the 300-watt level, the cost drops to between $1,500 and $2,500 per kilowatt; and at the 1.5-kilowatt level, the cost is $1,500 per kilowatt.
In the past, reliability has been a major concern for developers of wind turbines; however, some new turbine systems can operate for 5 years without major maintenance or overhaul. This does not negate the need for regular maintenance and visual inspection, but it shows the progress over earlier versions, which had frequent outages.b
Another concern is intermittence—the inability to operate continuously because of a lack of adequate wind resources at some times. In most locations, because of the seasonal nature of wind, there are periods when the wind is either too weak or too strong for the turbine to operate effectively, and capacity factors of 20 to 30 percent are common.
Wind turbine systems can be built in large clusters (farms) to smooth out some of the fluctuations observed with a single turbine. Alternatively, the turbines can be installed with battery energy storage, diesel backup, or photovoltaic hybrids (although wind-photovoltaic hybrids can be considerably more expensive than turbines installed in a cluster). In order to capture the best wind resource, a wind turbine should be at least 30 feet above any obstacles within 300 feet. A 250-watt turbine can be installed on a 30- to 50-foot tower, and a 10-kilowatt turbine may need an 80- to 120-foot tower.
Another consideration is that windy sites may be far from population or load centers. In such situations, a determination must made as to whether it is cheaper to construct a turbine at an optimal wind location and build transmission lines to bring the power to load centers, or to build it at a less then optimal site with lower transmission costs. Wind also follows seasonal patterns, with the best performance in winter months and the poorest in summer months.b
An interesting example of a water treatment system using a hybrid wind turbine and photovoltaic battery has recently been installed in Afghanistan. The idea for the project came from experience with photovoltaic and micro-hydro-powered ozone-based water treatment systems successfully deployed around the Annapurna Circuit in Nepal and with wind and solar installations in Baluchistan province in Pakistan. In the Parwan, Wardak, and Kapisa Districts of Afghanistan, 11 standalone wind-based water treatment systems have been installed and are operating successfully. One water treatment system was installed in a high school in Kabul to provide clean water to the school and community residents. Electricity from the systems is not sold but rather is used directly for water purification or in the local schools.
The equipment for the Afghan water treatment systems consists of a Bergey 1-kilowatt wind turbine on a 42-foot tower, 180 watts of photovoltaic panels, a battery bank, and an inverter. The water treatment technology uses about 160 watts of power to generate 2 grams of ozone per hour. The water is treated in batches, and most communities can treat about 2,000 to 4,000 liters of drinking water per day. These small hybrid systems are easy to ship and install and do not require special tools or concrete. The wind turbine and tower are assembled on the ground and tilted up with a hand winch. At a cost of $5,900 to $6,400 (2003 dollars),c a 1.2-kilowatt hybrid system can produce 3 to 5 kilowatthours of electricity per day.d Similar systems have been installed in Australia, Bangladesh, Bolivia, Brazil, China, Chile, Fiji, Indonesia, Mali, Mexico, Morocco, and Russia.
aAmerican Wind Energy Association, web site www.awea.org. The manufacturers are Bergey Windpower (www.bergey.com), SouthWest Windpower (www.windenergy.com), WindTech International, L.L.C. (www.windmillpower.com), and Wind Turbine Industries Corp. (www.windturbine.net).
bM. Bergey, “A Primer on Small Turbines,” web site www.bergey.com/school/primer.html, previously published in Home Power and Backwoods Home magazines (2002).
cCost does not include wiring, shipping, or installation.
dThe systems generate 3 to 5 kilowatthours net AC energy after storage and conversion losses and can produce close to 5 kilowatthours in good wind resource areas. Capacity factors for the systems are typically 20 percent before storage and conversion losses.
Deregulated Electric Power Markets and Operating Nuclear Power Plants: The Case of British Energy
One issue addressed in almost all electric power restructuring or deregulation plans in both the United States and the United Kingdom was the recovery of spent fuel disposal costs for operating nuclear power plants and the expenditures to decommission the units when they are retired—costs that are often called “back-end liabilities.” Before restructuring, in theory at least, electricity consumers in both countries were made to pay for the back-end costs for operating nuclear power plants. Moreover, in virtually all cases in the United States, individual States included special provisions to ensure that consumers would continue to do so after power markets were deregulated. Indeed, this is probably one reason why operating U.S. nuclear power plants could be sold to firms selling power in deregulated markets and operated profitably.
In contrast to the United States, however, when power markets in the United Kingdom were deregulated, the issues associated with back-end costs were more difficult. Because of a unique set of circumstances, to ensure that operating nuclear power plants would remain viable in deregulated electric power markets, the U.K. government (as opposed to electricity consumers and/or utility shareholders) had to take responsibility for the payment of many of the back-end liabilities.
In 1988, the U.K. government decided to both privatize the electricity generation and transmission industry and create a “competitive” generation market. However, partly because of the concerns about decommissioning and poor operation of some of U.K. nuclear units, the decision was made to keep all the country’s nuclear power plants, which generated about 20 percent of its electricity, in the public sector. The decision was revisited in 1995, when the government decided to privatize its newer advanced gas cooled (AGC) reactors and one light-water nuclear power plant.a Thus, a company called British Energy (BE) was formed. The total capacity of all the power plants owned by BE was about 9.6 gigawatts, all of which was nuclear.
In mid-July 1996, the government “transferred” ownership of BE to the private sector by selling about 700 million shares of BE stock on the open market. The initial selling price of the stock was about 240 pence per share, and the sale netted about 1.7 billion pounds. In the first few years after the privatization, BE’s stock price increased, peaking at more than 700 pence in early 1999. Share prices then fell, and from 2000 to early 2002 BE’s stock traded in the range of 200 to 300 pence. Then, in 2002, serious financial problems arose, and the government intervened with financial assistance in order to forestall bankruptcy. As of early 2004, BE’s stock price was 5 to 10 pence per share.
To explain BE’s financial problems and the government’s response, two general points must be made. First, the bulk of a nuclear power plant’s operating costs are fixed, in the sense that they will be incurred even if the plant is not operating. This is partly due to the need to operate and maintain a nuclear plant’s safety systems even if the unit is not generating electricity. As a result of the fixed nature of the operating costs, profits are sensitive to prices—that is, a 10-percent change in prices will result in almost a 10-percent change in profits. Second, the British reprocess the spent fuel from their gas-cooled nuclear power plants; and as a result, BE had contracts with British Nuclear Fuels Limited (BNFL) for services dealing with the handling of the spent fuel. The contracted costs of these services, as reported in the media, are about 300 million pounds per year, or about 5 pounds per megawatthour of plant output.b In the United States, where nuclear waste is not reprocessed, spent fuel disposal costs collected from consumers are equivalent to 0.67 pounds per megawatthour.c
In the first few years after the privatization, BE’s nuclear plants were indeed profitable, in the sense that the revenues from sales were greater than the operating costs (see table on page 116). Over the 1997-1999 period, BE’s return on equity was about 10 to 12 percent, and it had healthy positive cash flows. The cash was used to purchase a large coal-fired power plant and interests in nuclear units in Canada and the United States.d In 2000, however, the British restructured the wholesale electric power market in England and Wales, and shortly thereafter electricity prices began to fall. By the end of 2001, wholesale electricity prices had fallen by about 30 percent. Because many nuclear operating costs are fixed, the best way to decrease costs is to increase productivity—that is, become more efficient. BE was able to reduce costs by about 15 percent, but not sufficiently to offset the decreases in revenues. As a result, BE lost money in 2001.
As electricity prices continued to fall in 2002-2003, BE incurred some serious liquidity problems and needed inflows of cash to remain solvent. The company was having difficulty obtaining credit from private lenders and was unable to renegotiate its contracts with BNFL. On September 9, 2002, BE borrowed about 400 million pounds from the British government. Initially, the loan was to be repaid by the end of the month. On September 26, 2002, however, the loan was extended to November 29, 2002, and the amount was increased to 650 million pounds. At that point it also became apparent that BE’s financial problems were not limited to a short-term lack of liquidity. In fact, from March 2002 through February 2003, BE lost about 4,300 million pounds, which included a one-time writedown of its generating plants, at about 3,700 million pounds. Thus, BE and the U.K. government began discussions about the longer term restructuring of the company. The discussions dealt with a number of longer term issues, the most important of which were related to back-end liabilities.
In late November 2002, the government announced a complex plan to restructure BE. As part of the plan, the government agreed to extend the loans though September 2004, and BE obtained an agreement from its major creditors to freeze interest and loan repayments. BE’s creditors also agreed to forgive substantial amounts of its debt, partly in exchange for receiving new stock in BE. The savings to BE have been estimated at about 750 million pounds. To generate cash, BE also agreed to sell its shares in U.S. and Canadian nuclear plants. The sales were finalized in late 2003, for which BE received about 950 million pounds.e
The most controversial part of BE’s restructuring plan dealt with back-end liabilities. Before the new agreement, BE was liable for all of the spent fuel reprocessing and disposal costs, plus the expenses to decommission its plants. Under the restructuring plan, the U.K. government assumed responsibility for all the costs of handling, storing, and disposing of the waste generated by the gas-cooled reactors in the past, as well as some of the back-end costs for waste generated in the future. The European Commission estimated that the present value of the costs incurred by the government over the next 80 years would be more than 3 billion pounds—an amount that is 5 times the 2003 book value of BE’s power plants.f
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BE still would be responsible for most of the costs of reprocessing and disposing of the waste generated in the future and for the decommissioning of its power plants. Many of those activities will be funded from a large trust owned by BE; that is, monies would be contributed into the trust and invested in stocks and bonds, and payments for many of BE’s back-end obligations would come out of the trust. The restructuring plan requires that BE contribute to the trust 65 percent of its cash remaining after taxes and interest and dividend payments. Typically, without this requirement, the funds would be used to obtain productive assets, such as additional power plants. Thus the requirement limits the potential for future growth of BE.
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The restructuring plan currently is being reviewed by the European Commission and, therefore, has not been fully implemented.g In BE’s 2003 Annual Report, it presented both its regular balance sheet and one based on the assumption that the restructuring plan was fully in effect as of that date. The table below reproduces the latter balance sheet in a slightly different form. Note that BE’s short- and long-term nuclear back-end liabilities add up to 4,199 million pounds.h
About 334 million pounds of the back-end liabilities will be covered by the trust, and the UK government will cover the remaining 3,865 million pounds. The table also shows the importance of the UK government’s assumption of some of the back-end liabilities. Without it, BE’s liabilities would have been about 3.5 billion pounds greater than its assets. It is difficult to see how BE could remain viable under such circumstances.
In short, many of BE’s financial problems were related to the reprocessing of the spent fuel from its gas-cooled reactors, an activity that even BE recently argued was not economical.i In “regulated” markets, it was easy to shift the costs of such activities to consumers. In deregulated markets, without some type of government intervention, the forces of competition can limit a firm’s ability to recover such costs. This point was recognized by U.S. State and Federal authorities when they deregulated wholesale power markets. They explicitly decided to shift the costs of prudent but ex post uneconomical actions (dealing mainly with the construction of many nuclear power plants) to the current generation of consumers by means of “stranded cost recovery.” In the United Kingdom, 15 years after a deregulated electric power market was created in England and Wales, the government finally decided to shift many of the back-end costs to present and future taxpayers.
aThe British also owned about 5 gigawatts of very old and very small gas-cooled nuclear power plants, often called Magnox reactors. They were kept in the public sector, and currently about 50 percent of them have been retired. In all probability, the remaining ones will be retired by 2010.
bS. Thomas, “The Collapse of British Energy: The True Cost of Nuclear Power or a British Failure?” (University of Greenwich, July 2003).
cAn exchange rate of 1 pound to 1.5 dollars was used to convert the 1 mill per kilowatthour charge.
dBE acquired a long-term lease for a number of Canadian nuclear units and thus, in a technical sense, was not a partial owner of the plants.
eBritish Energy, Interim 2003 Annual Report (December 2003).
f“State Aid—United Kingdom: Invitation To Submit Comments Pursuant to Article 88(2) of the EC Treaty, Concerning Aid C 52/03 (ex NN 45/03)—Restructuring Aid in Favour of British Energy plc,” Official Journal of the European Union, C 180/5 (July 31, 2003).
g“State Aid—United Kingdom: Invitation To Submit Comments Pursuant to Article 88(2) of the EC Treaty, Concerning Aid C 52/03 (ex NN 45/03)—Restructuring Aid in Favour of British Energy plc,” Official Journal of the European Union, C 180/5 (July 31, 2003).
iNote that nuclear liabilities are expressed in present value terms. Thus, if all the back-end costs were incurred today, they would total 4,199 million pounds.
hBritish Energy, “Nuclear Waste: British Energy’s Views,” submission of British Energy to the House of Commons: Environment, Food and Rural Affairs Committee (November 13, 2001).
Noncommercial Biomass Energy Use in Developing Countries
The International Energy Agency estimates that 14 percent of the energy consumed for end use throughout the world comes from noncommercial biomass fuels.a Noncommercial, or traditional, biomass consists mostly of solid fuels—wood, charcoal, agricultural residues, and wood and animal wastes—used in developing countries. An estimated 2.4 billion people in developing countries use biomass as their primary fuel for cooking and heating. Although more than half of the people who rely on biomass live in India and China (1.3 billion), the proportion of the population depending on biomass fuels is largest in Sub-Saharan Africa, where more than 85 percent of the population use biomass as their primary source of energy. In Latin America, only 23 percent of the population rely on biomass fuels for cooking and heating.b
Biomass fuels are less efficient for providing end-use energy services than are other fuels. For example, wood is less efficient than either kerosene or liquefied petroleum gas (LPG) for cooking. Although the use of biomass fuels can have negative effects on the environmental and, particularly, on human health, they are widely used because of their availability and low cost. Noncommercial biomass is available almost everywhere, and many people think of it as being “free” if they collect it themselves, or very cheap if they purchase it. In comparison, the overhead cost of acquiring kerosene or LPG stoves and bottles can discourage people from using those fuels, and even if some families can afford other fuels, the required infrastructure may not be available.c
Although the direct economic costs of using biomass may be small, the indirect costs in terms of agriculture, environment, and public health can be high. For example, time spent gathering fuel could be used instead for agricultural production; and biomass used for fuel, such as agricultural residues and dung, could be used instead for fertilizer. It has been estimated that, in India, dung used for fuel in 1998 would have been worth $800 million as fertilizer for use in agriculture.d
The use of biomass as fuel, when managed sustainably (that is, when biomass is planted or naturally replaced at the same rate it is harvested), does not harm either the local or global environment. Unsustainable harvesting of wood can, however, cause local deforestation and, potentially, loss of biodiversity. Globally, the extraction and burning of biomass releases carbon dioxide into the atmosphere; however, there is no net release of carbon dioxide if biomass is planted and harvested at the same rate, because growing plants remove and sequester carbon dioxide from the atmosphere.
Harvesting of fuelwood in developing countries is not considered to be a significant cause of large-scale deforestation. In general, people do not fell trees in their search for firewood, preferring instead to collect woody shrubs, fallen branches, or debris from cleared agricultural fields. In addition, fuelwood is rarely harvested from natural forests. Near cities with large numbers of urban poor and a lack of electrification, fuelwood or charcoal (made locally from wood) continues to be used widely as a household energy source, and the high demand for woody biomass concentrated geographically can lead to over-exploitation of forest resources near the city.
More significant adverse consequences from the use of biomass as a household energy source are associated with the indoor air pollution caused by fumes and emissions from stoves. For example, one recent study has shown that 24-hour average indoor concentrations of small particle emissions in Indian households that use solid fuels for cooking and heating can be as high as 2,000 micrograms per cubic metere and can exceed World Health Organization guidelines by a factor of 10, 20, or more. For comparison, average annual outdoor concentrations of small particles (less than 10 microns in diameter) are generally less than 30 micrograms per cubic meter in U.S. cities and between 90 and 600 micrograms per cubic meter at outdoor urban monitoring stations in India.f
Exposure to indoor air pollution is especially high for women and children in developing countries. Women usually have primary responsibility for cooking, and small children (under the age of five) tend to remain indoors with their mothers. One of the major health risks associated with small particle air pollution in developing countries is acute respiratory infections associated with a wide range of viruses and bacteria. In India, acute respiratory infections account for nearly three-quarters of the deaths from causes associated with indoor air pollution.g Chronic obstructive pulmonary disease and lung cancer have also been associated with exposure to particulate matter from indoor air pollution, as have increases in risk for cataracts (leading to blindness), tuberculosis, asthma, and adverse pregnancy outcomes (including low birth weight, prematurity, and early infant death).
Indoor air pollution affects approximately 2.4 billion people worldwide and many countries have programs to address the issue. National policy initiatives include temporary or permanent subsidies for cleaner burning, better ventilated stoves; improved delivery of energy services to the poor, particularly in rural areas; microfinancing schemes to help the poor with initial investments in improved stoves; and investments in research and development for new technologies, financing mechanisms, and exposure and health assessments.h
aInternational Energy Agency, Biomass Energy: Data, Analysis, and Trends (Paris, France, 1998).
bInternational Energy Agency, World Energy Outlook 2002 (Paris, France, 2002).
cInternational Energy Agency, World Energy Outlook 2002 (Paris, France, 2002).
dTata Energy Research Institute (India), Energy Research Institute (China), Wageningen Agricultural University (Netherlands), and International Institute for Applied Systems Analysis (Austria), Potential for Use of Renewable Sources of Energy in Asia and Their Cost Effectiveness in Air Pollution Abatement, Final Report on Work Package 1 (December 1999), web site www.dow.wau.nl/msa/renewables/ Downloads/workpackage1/Final_report_workpackage_1.pdf.
eK.R. Smith, “National Burden of Disease in India from Indoor Air Pollution,” PNAS, Vol. 97, No. 24 (November 21, 2000), p 13285.
fThe World Bank Group, “The Inside Story: Indoor Air Pollution Implicated in Alarming Health Problems,” Indoor Air Pollution Newsletter: Energy and Health for the Poor, No. 1 (September 2000), web site http://wbln0018.worldbank.org/sar/sa.nsf/ 2991b676f98842f0852567d7005d2cba/a169d6e66c9c0c7585256990006a2631?OpenDocument.
g K.R. Smith, “National Burden of Disease in India from Indoor Air Pollution,” PNAS, Vol. 97, No. 24 (November 21, 2000), p 13291.
hThe World Bank Group, “Regional Workshop on Household Energy, Indoor Air Pollution and Health,” Indoor Air Pollution Newsletter: Energy and Health for the Poor, No. 8 (August 2002), web site http://lnweb18.worldbank.org/sar/sa.nsf/General/ 54F998E632F70B3685256DB70073A19A?OpenDocument.
COP-9 Climate Change Negotiations in Milan, Italy
The Ninth Session of the Conference of the Parties to the UNFCCC (COP-9) was held in Milan, Italy, from December 1 to December 12, 2003. Discussion continued on the Kyoto Protocol and the implementation of the UNFCCC. With the United States publicly stating that it will not ratify the Protocol, entry into force is dependent on ratification by Russia; however, signals from the Russian government were mixed. Early in the conference, a spokesman for the Russian treasury department stated that Russia would not ratify the Protocol. Shortly thereafter, another cabinet member expressed Russia’s full intent to ratify the Protocol.
The EU has stated that it will undertake policies and measures, including a cap and trade regime, to reach the Kyoto targets regardless of Russia’s final decision on ratification. It is clear, however, that the costs of reaching the targets will increase in the absence of tradable permits from Russia. By virtue of the economic collapse of the Soviet Union, Russia is below its target under the Protocol. By the end of COP-9, the Russian delegation had made explicit its calls for EU concessions on non-Protocol matters, such as trade and EU membership, as a condition for Russia’s ratification.
The most important decisions reached at COP-9 pertained to rules for carbon sink projects during the first commitment period. Two years earlier, at COP-7, the parties agreed that afforestation and reforestation projects would be allowed under CDM but did not set detailed rules for such projects. The problem with establishing rules for afforestation and reforestation projects is that forests are not permanent. Before COP-9, the parties had not decided who should be liable if a sink began releasing its sequestered carbon dioxide into the atmosphere—the project developer, the host country, or the holder of emissions reductions credits for the project. At COP-9 they decided to create temporary emissions reductions credits that would be valid for only one commitment period, as well as long-term credits that could be renewed for 20-year periods. This accounting system would assign responsibility for maintaining sinks to the holder of the reduction credits, ensuring that holders could take credit only for current emission reductions. The EU delegation also sought to open discussion of the second commitment period (2012-2016), but others were not prepared to do so. The Kyoto Protocol calls for negotiations for the second commitment period to begin no later than 2005.
In addition to the official negotiations at COP-9, there were more than 100 side events hosted by various governmental and nongovernmental organizations. Participants discussed a wide array of subjects, among which the CDM was prominent. Topics in the CDM discussions included rules to help reduce poverty in the developing world and to increase private-sector involvement in CDM projects.a Other subjects of discussion included countries’ domestic climate change policies, technical issues related to greenhouse gas inventories, directions and proposals for the climate regime after 2012, and examples of corporate responses to climate change. Although the side events were not part of the official negotiations, they were an important part of COP-9, allowing participants to share mitigation strategies, suggest ideas for future negotiations (for instance, rulemaking for the CDM), and consider the future of the UNFCCC beyond the Kyoto Protocol.
aUnited Nations Framework Convention on Climate Change, Ninth Session of the Conference of the Parties and the Nineteenth Session of the Subsidiary Bodies, 1-12 December 2003, Milan, Italy, “Side Events and Exhibits,” web site: http://unfccc.int/cop9/se/se_ schedule.html.
Leaded Gasoline: The Global Phaseout
Since the early 1920s, lead has been blended with gasoline to boost octane levels. In the 1970s and 1980s, however, it was established that lead is a toxin that particularly affects the neurological development of children: even low-level exposure to lead can cause reading and learning disabilities, changes in behavior, reduced attention span, and hearing loss; and greater exposure can lead to permanent mental retardation, convulsions, coma, and death.a As a result, many countries have banned the use of leaded gasoline—a transition that was facilitated in 1975 by the introduction of automobiles with catalytic converters that require lead-free fuel.b
The global phaseout of leaded gasoline has proceeded rapidly. Between 1970 and 1993, the total amount of lead added to gasoline worldwide dropped by 75 percent, from more than 375,000 tons to less than 100,000 tons.c Leaded gasoline made up more than 57 percent of the world gasoline market in 1990, but its share was less than 10 percent in 2003. As of January 1, 2004, 73 countries, mostly in Africa and Eastern Europe, were still using leaded gasoline (see Figure 75), and many of those countries, including Azerbaijan, Benin, Kazakhstan, Nigeria, and Uzbekistan, have plans to phase it out in the next few years.d
Some countries phased out lead in gasoline over relatively long periods; others did it in just 1 or 2 years. The United States moved relatively slowly, starting when the U.S. Environmental Protection Agency began to regulate the use of lead in gasoline in 1975. In 1973, the average lead content of gasoline in the United States was 2 to 3 grams per gallon, totaling about 200,000 tons of lead a year. In 1995, leaded fuel accounted for only 0.6 percent of total U.S. gasoline sales and less than 2,000 tons of lead per year. Lead was completely banned from use in on-road vehicle fuel in the United States as of January 1, 1996.e
In Pakistan, the phaseout was rapid by comparison. As recently as early 2001, only leaded gasoline was sold in Pakistan, but by mid-2002 its gasoline supply was virtually lead-free. The government of Pakistan partnered with the United Nations Development Programme and the World Bank in the Pakistan Clean Fuels Project to facilitate its phaseout of leaded gasoline. In July 2001, the government accelerated the phaseout by having three of the four refineries in the country begin selling only unleaded gasoline. Although environmental regulations in Pakistan still permit 0.35 grams per liter of lead in gasoline, all four of the country’s refineries were producing unleaded gasoline by the end of 2003.f
aM. Lovei, Phasing Out Lead From Gasoline: Worldwide Experience and Policy Implications, World Bank Technical Paper No. 397: Pollution Management Series (1998).
bJ. Lewis, “Lead Poisoning: An Historical Perspective,” EPA Journal (May 1985), web site www.epa.gov/history/topics/perspect/ lead.htm.
cUnited Nations Environmental Program, Global Opportunities for Reducing the Use of Leaded Gasoline (1998), web site www. chem.unep.ch/pops/pdf/lead/toc.htm.
dInternational Fuel Quality Center, Current Status of Leaded Gasoline Phase Out Worldwide (February 4, 2003) (updated by personal communication, October 30, 2003).
eU.S. Environmental Protection Agency, “EPA Takes Final Step in Phaseout of Leaded Gasoline” (Press Release, January 29, 1996), web site www.epa.gov/history/topics/lead/02.htm.
fInternational Fuel Quality Center, Asian Office, personal communication, November 5, 2003.
Controlling Emissions of Mercury from Energy Use
In response to scientific research indicating potential adverse ecological and human health impacts caused by exposure to mercury, many nations are considering regulation and control of mercury emissions—including those attributed to energy use.
Recent estimates of global mercury emissions indicate that Europe and North America contribute less than 25 percent of global anthropogenic emissions (see table below). The majority of emissions originate from combustion of fossil fuels, particularly in Asian countries that rely heavily on coal for electricity generation, including China, India, and South and North Korea.a Other sources of mercury include processing of mineral resources at high temperatures, such as roasting and smelting of ores, kiln operations in the cement industry, incineration of waste materials, and production of certain chemicals.
Traditionally, regulation of energy-related mercury emissions has focused on municipal solid waste combustion.b Mercury is found in relatively higher concentrations in waste incineration exhaust gases than in the gases released from coal combustion and is thus simpler and less expensive to remove. As a result, most industrialized and many developing countries already have standards in place to control mercury levels in the exhaust gases from waste incineration facilities and in wastewater from the cleaning of their exhaust gases (see table on page 151).c
Emissions of Mercury from Anthropogenic Sources by World Region, 1995
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A number of countries, including Canada, the United States, and the European Union, are now considering standards to control mercury emissions from coal-fired electricity generators:d
- Under the umbrella of the Canadian Council of Ministers of the Environment, federal, provincial, and territorial governments in Canada have agreed to develop a nationwide emission standard for the coal-fired electricity generation sector by the end of 2005 and to reduce mercury emissions from coal-fired power plants by 2010.e
- The United States is debating various multipollutant legislative initiatives, with mercury as one of the targeted pollutants. In December 2002, the EPA found that it is appropriate and necessary to regulate hazardous air pollutants, including mercury from electric power plants.f The EPA proposed Utility Mercury Reductions in December 2003 and currently is seeking comment on two types of emissions reductions mechanisms, one based on maximum achievable control technologies (MACT) and another based on a cap and trade system. A final rule will be promulgated in December 2004.
- The European Union is in the process of developing emissions monitoring procedures and control strategies based on Best Available Technology (BAT) as part of a subsequent directive under the 1996 Air Quality Framework Directive (96/62/EC).
To address transboundary issues related to the long-range transport of mercury emissions, countries are also working under the auspices of the United Nations Environment Programme (UNEP) to develop a global assessment of mercury and its compounds.
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The assessment, to include options for addressing any significant global adverse impacts of mercury, was presented to the UNEP Governing Council at its 22nd session in February 2003 for further action by the global community. A meeting of UNEP’s Working Group on Mercury took place in Geneva, Switzerland, in September 2002 to develop options for addressing global adverse impacts of mercury. Proposals included the creation of an international legally binding treaty to reduce or eliminate mercury use and emissions.g
aEuropean Commission, Ambient Air Pollution by Mercury (Hg): Position Paper (Luxembourg: Office for Official Publications of the European Communities, 2001), web site http://europa.eu.int/comm/environment/air/background.htm.
bMunicipal solid waste combustion is considered an energy source, because many incinerators produce steam for heating.
cUnited Nations Environment Programme, Global Mercury Assessment. Appendix: Overview of Existing and Future National Actions, Including Legislation, Relevant to Mercury as of November 1, 2002 (Geneva, Switzerland, December 2002), web site www.chem.unep.ch/ mercury/Report/Finalreport/final-appendix-1Nov02.pdf; and “Directive 2000/76/EC of the European Parliament and of the Council of 4 December 2000 on the Incineration of Waste,” Official Journal of the European Communities, L332/91 (December 28, 2000), web site http://europa.eu.int/comm/environment/wasteinc/newdir/2000-76_en.pdf.
dUnited Nations Environment Programme, Global Mercury Assessment. Appendix: Overview of Existing and Future National Actions, Including Legislation, Relevant to Mercury as of November 1, 2002 (Geneva, Switzerland, December 2002), web site www.chem.unep.ch/ mercury/Report/Finalreport/final-appendix-1Nov02.pdf.
eCanadian Council of Ministers of the Environment, “CWS for Mercury From Coal-Fired Electric Power Generation Sector,” web site www.ccme.ca/initiatives/ standards.html?category_id=53.
fU.S. Environmental Protection Agency, “Fact Sheet: EPA To Regulate Mercury and Other Air Toxics Emissions From Coal- and Oil-Fired Power Plants” (December 14, 2000), web site www.epa.gov/ttn/oarpg/t3/fact_sheets/fs_util.pdf.
gUnited Nations Environment Programme, Global Mercury Assessment (Geneva, Switzerland, December 2002), web site www.chem. unep.ch/mercury/Report/Finalreport/final-assessment-report-25nov02.pdf.
Multipollutant Control Legislation in the United States
Electric power plant operators in the United States may face new requirements to reduce emissions of sulfur dioxide, nitrogen oxides, and mercury beyond the levels called for in current regulations. Some proposed Federal legislative initiatives would also require mandatory reduction of carbon dioxide emissions. Whereas in the past each pollutant was addressed through a separate regulatory program, the new legislative initiatives focus on simultaneous reductions of multiple emissions in order to reduce the cost and administrative burden of compliance. The legislative initiatives now being considered would also modify the New Source Review requirements of the 1990 Clean Air Act Amendments for modernization at older power plants.
Three major legislative initiatives were introduced in Congress during the 107th legislative session and have been referred to committee for further consideration. A fourth was announced early in the 108th Congress. Introduced first by Senator Jim Jeffords in 2002 and later in 2003, the Clean Power Act of 2003 is the most far-reaching of the multipollutant initiatives. As shown in the table below, it covers emissions of sulfur dioxide, nitrogen oxides, mercury, and carbon dioxide.
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The bill proposes a cap and trade scheme for meeting sulfur dioxide, nitrogen oxide, and carbon dioxide emission targets and a MACT requirement to reduce mercury emissions. The current Clean Air Act requires the EPA to adopt a performance standard based on MACT in the next few years, with compliance required by the end of 2007. In addition, the Clean Power Act of 2003 would require every power plant to be equipped with the most recent pollution controls required for new sources by the plant’s 40th year of operation or by 2014, whichever is later.
The Clear Skies Initiative, announced by President Bush in February 2002 and introduced as House and Senate bills, proposes nationwide caps for sulfur dioxide and mercury and regional (East and West) caps for nitrogen oxides. The Clear Skies Initiative differs from the proposed Clean Power Act primarily in targeted emission reductions and proposed compliance dates. The final nitrogen oxides and sulfur dioxide targets are close to those proposed in the Clean Power Act of 2003, but mercury reductions are not as stringent, and the timetable for reaching the targets is delayed by 5 to 10 years, depending on the pollutant. The Clear Skies Initiative provides for market-based cap and trade programs for nitrogen oxides and sulfur dioxide and also provides for mercury emissions trading. It includes carbon dioxide emission provisions that would be voluntary only.
The third bill, the Clean Air Planning Act of 2003, was introduced by Senator Tom Carper in October 2002 and later in April 2003. Its emissions targets are generally between those of the Clean Power Act and those of the Clear Skies Initiative. The Clean Air Planning Act would establish caps on emissions of sulfur dioxide, nitrogen oxides, and mercury, but they would be phased in over a longer period than proposed in the Clean Power Act. The bill would also introduce limited caps on carbon dioxide emissions. The bill proposes to reduce carbon dioxide emissions to 2006 levels by 2009 and to 2001 levels by 2013, whereas the Clean Power Act would reduce carbon dioxide emissions to 1990 levels by 2009. The nitrogen oxide, sulfur dioxide, and mercury reduction targets and timelines included in the legislation are more aggressive than those outlined in the President’s Clear Skies Initiative but less stringent than those proposed in the Clean Power Act.
In early January 2003, Senators McCain and Lieberman introduced legislation to reduce annual emissions of greenhouse gases by emitters in the electricity, transportation, industrial, and commercial sectors that produce 10,000 metric tons carbon dioxide or more per year.a The bill would create a system of tradable allowances allocated to emitters in each sector free of charge, with the goal of reducing greenhouse gas emissions to 2000 levels by 2010 and to 1990 levels by 2016. It does not address emissions of nitrogen oxides, sulfur dioxide, or mercury.
aU.S. Senator Joseph Lieberman, “Summary of Lieberman/McCain Draft Proposal on Climate Change,” Press Release (Washington, DC, January 8, 2003), web site www.senate.gov/~lieberman/press/03/01/2003108655.html
Released: April 2004