Uncertainty in Measures of Gross Domestic Product

The GDP forecasts underlying the IEO2001 energy forecasts are themselves subject to uncertainty from two sources. First, because the GDP forecasts are projections of trend growth, abstracting from cyclical movements and unexpected shocks to the economy, there is the possibility that the perceived trends may not actually achieve expected levels. This type of uncertainty is inherent in all forecasts, and forecasters try to minimize it by looking at past experience. Clearly, the longer the period of the forecast the greater the uncertainty, because the more likely it is that events will not go as expected.

The second source of uncertainty about GDP forecasts has to do with the variation in the methods and accuracy with which GDP is measured among countries and over time. This source of uncertainty is the result of methodological and measurement issues and would be minimized if a common methodology and data collection method were used across countries and over time to estimate GDP.

The GDP forecasts for IEO2001 depend on the national statistical agencies’ definition of what is included in the measurement of output. IEO2001 uses real (inflation-adjusted) GDP, which ultimately relies on the statistics released by each national statistical agency. Comparing across countries, even though conceptually GDP has common meaning, it may not be measured consistently across nations. There are several examples illustrating differences in treatment both within the more industrialized nations and among the developing countries.

Over the past year, the United States has released revised historical GDP numbers, incorporating changes in estimation of inflation, reclassification of certain investment expenditures, and more complete data. As a result, the historical GDP growth rate from 1959 to 1998 has been revised upward by 0.2 percent per year. The Bureau of Economic Analysis (BEA), the statistical agency responsible for estimating U.S. GDP, uses a methodology to estimate inflation that is not commonly used in the other industrialized countries. If a common methodology were adopted, the economic growth forecasts for some countries would be different from those published in the past.

Measurement of price changes is a central source of differences in the calculation of real output growth. The United States changed to a chain-weighted approach in 1992, rather than fixed-year prices, in order to remove substitution bias and reduce the impact of changing the base year much less noticeable in understanding economic growth.^a Most of the other industrialized nations have not calculated price changes using chain-weighted indices but continue to use fixed-year prices to calculate real output.

Some nations, such as China and other centrally planned economies, use a “comparable prices” approach that applies constant “administrative prices” to value nominal output, rather than calculating a deflator-based estimate of price change. Data from state enterprises determine the administrative prices. Typically, state enterprise price data are applied to a wide variety of similar goods without adjusting for variation in product characteristics. Relying on administrative prices to value real output leads to greater uncertainty in estimates of inflation and, consequently, real output growth.

In developing countries, some economic activities are not recorded or monetized. National statistical agencies have devised various methods to estimate their contribution to GDP. As methodologies improve and/or more complete information becomes available over time, their GDP estimates probably will be revised. At present, however, it is difficult to predict for each economy how the changes will be made—a consideration that adds to the uncertainty about their expected GDP growth.

Finally, many countries are moving toward United Nations System of National Accounts for reporting their statistics, which is a step toward reporting country growth in a consistent framework. When all countries can convert their detailed national statistics into this framework, the “measurement uncertainty” in GDP estimates will be significantly reduced.

^aFor a description of chain-weighted indexes, see J.S. Landefeld and R. Parker, “BEA’s Chain Indexes, Time Series and Measures of Long-Term Economic Growth” Survey of Current Business (May 1997).

Natural Gas and Electricity in Western Europe

The natural gas and electric power industries in Europe are becoming increasingly interconnected. Both industries have been set on a course of change by parallel directives from the European Union (EU) calling for deregulation. Growing availability of natural gas supplies, efforts to introduce greater competition in energy supply, and improvements in natural gas turbine technology are driving the convergence of natural gas and electricity in Western Europe.

Until the early 1970s, gas supplies in Europe came predominantly from sources within the region. Around that time, however, supplies started to come from other sources as well, with the beginning of liquefied natural gas (LNG) deliveries from North Africa (Algeria and Libya) and pipeline gas from the Soviet Union. Also at that time, the United Kingdom (UK) and later Norway began to develop North Sea hydrocarbon resources. Gas demand, along with economic growth, waned in the early 1980s just when earlier investments in gas transportation infrastructure were adding capacity—particularly the Trans-Mediterranean pipeline (from Algeria to Italy), pipelines from Norway, and additional pipeline capacity from the Soviet Union. As gas demand grew stronger in the late 1980s and 1990s, the supply mix continued to reflect growing pipeline imports with a smaller share of imported LNG.^a Growth in the more separated UK gas market was especially strong, supplied by rising domestic from the North Sea and eventually imports from Norway. Only with the 1998 commissioning of the UK-Belgium Interconnector pipeline has a more integrated, cross-channel European gas market become possible.

Currently, pipelines transport more than three-quarters of the natural gas imported by EU members. About 40 percent of those pipeline imports arrive from the Russian Federation and 15 percent from North Africa (predominantly Algeria).^b Intra-EU trade, primarily in gas from the Netherlands, accounts for just about 20 percent of the pipeline imports; however, when exports from Norway are included, the countries of Western Europe obtain nearly 45 percent of their pipeline gas imports from other countries in the region.

Gas fields in the Netherlands are beginning to near depletion, which will constrain future exports. Norwegian gas discoveries have also dropped off, limiting current export possibilities to known resources (although the region is believed to still have gas potential, particularly in the offshore Norwegian Sea).^c Thus, future incremental gas supplies are expected to arrive primarily from North Africa, the Middle East, and Russia.

As in the United States, energy policies have had an important effect on the availability of natural gas in Western Europe and its development as a fuel for electricity generation. In the 1970s, gas availability issues led to intervention in the industry by the European Community (EC, predecessor to the EU). In 1975, a perceived scarcity of gas resources led to an EC directive restricting the use of gas in power plants, which eventually was revoked in the early 1990s, when perceptions about the availability of gas resources and the competitiveness of gas turbine technologies had changed.^d In contrast, the European Parliament and Council Directive of June 22, 1998 (with an implementation deadline of August 10, 2000) was not about safeguarding supplies, but about promoting market-based development of the gas industry.

The 1998 gas directive—part of a regulatory trend worldwide in which (among other changes) both gas and power transmission systems are being made available to multiple users—seeks to end monopoly control of national gas transmission systems, which were once viewed as natural monopolies. Not all EU member countries have met the deadline for implementing the directive, however, and its effectiveness has been limited as a result. EU officials are continuing to focus on compliance while drafting further guidelines in case they are needed to promote an EU-wide gas market.

The increasing use of gas for power generation in Western Europe has played a central role in prompting the dual EU directives to alter gas and power market regulations. In turn, the current regulatory changes are having an important effect on corporate strategies and structures. European gas transmission companies, which increasingly must allow third-party access to their pipelines, are now seeking to move into both upstream and downstream businesses, expanding their profit base beyond the deregulating gas transmission market. Gas de France, for example, has bought offshore Dutch production assets from TransCanada. Some companies may have sought growth in order to compete more internationally. Others may have sought to protect their domestic markets from foreign investors.^e Some of the mergers have involved corporations that hold extensive assets in both the gas and power industries, such as the combining of Germany’s Veba and Viag to become E.ON. If the current trends in gas-fired generating technology, improving access to natural gas supplies, and EU regulation continue, further interconnection of the natural gas and electricity industries in Western Europe can be expected.

_____________________

aJ. Estrada, H.O. Bergesen, A. Moe, and A.K. Sydnes, Natural Gas in Europe: Markets, Organisation and Politics (New York, NY: Pinter Publishers, 1988). 
bBP Energy, World Energy Statistics 2000, web site www.bp.com.  
cU.S. Geological Survey, World Petroleum Assessment 2000, web site http://greenwood.cr.usgs.gov/energy/WorldEnergy/ DDS-60/.
dP. Soderholm, “Fuel for Thought: European Energy Market Restructuring and the Future of Power Generation Gas Use,” International Journal of Global Energy Issues (forthcoming).
^eP. Carpentier and A. Tagheghi, “Commercial Opportunities in European Gas Markets,” in World Power 2000 (London, UK: Isherwood Production Ltd., 2000).

World Natural Gas Resources: A 30-Year USGS Perspective

The U.S. Geological Survey (USGS) periodically assesses the long-term production potential of worldwide petroleum resources (oil, natural gas, and natural gas liquids) resources. The most recent USGS estimates, released in the World Petroleum Assessment 2000 (WPA2000),^a are the culmination of a 5-year effort based on extensive geologic information from Petroconsultants, Inc.^b and NRG Associates.^c Previous analyses by the USGS^d and the U.S. Minerals Management Service^e were used for the purpose of including U.S. estimates in the world totals.

The WPA2000 is the fifth in a series of assessments that began in 1981. Two aspects of the WPA2000 analysis represent departures from the methodology used in previous assessments. First, the current assessment adopts a 30-year forecast period (1995-2025), whereas earlier USGS assessments assumed an unlimited forecast span. The use of a finite forecast span allows for a more detailed evaluation of petroleum-related activities whose availability during the forecast period is uncertain. For example, certain political (ecologically sensitive areas) or physical (extreme water depths) attributes might preclude some fields from being developed over the next 25 years.

Second, the current assessment segregates future petroleum resources into two categories: undiscovered and reserve growth. Previous USGS assessments defined future petroleum only in terms of ultimately recoverable resources and did not separately address the concept of reserve growth. This concept refers to an increase in estimated field size due mainly to technological factors that enhance a field’s recovery rate. As sophisticated technologies become more transferrable worldwide, reserve growth will become an increasingly important component of ultimate resource estimates. The methodologies employed in the WPA2000 are considered important refinements to those used in previous assessments.

Highlights of the WPA2000 projection for worldwide natural gas resources include:

• A significant volume of natural gas remains to be discovered. The mean estimate for worldwide undiscovered gas is 5,196 trillion cubic feet, or 886 billion barrels of oil equivalent. This mean estimate is more than double worldwide cumulative production but is less than the sum of remaining reserves and reserve growth estimates. About one-fourth of worldwide undiscovered gas resides in undiscovered oil fields.

• More than half of the mean undiscovered gas estimate is expected to come from the former Soviet Union, the Middle East, and North Africa. An additional 1,169 trillion cubic feet is expected to come from a combination of North, Central, and South America. The figure below shows the regional distribution of existing gas (remaining reserves) and potential gas (undiscovered).

World Natural Gas Resources by Region

• Of the new natural gas resources expected to be added over the next 25 years, reserve growth accounts for 3,660 trillion cubic feet.

• The United States has produced more than 40 percent of its total estimated natural gas endowment and carries less than 10 percent as remaining reserves. Outside the United States, the world has produced less than 10 percent of its total estimated natural gas endowment and carries more than 30 percent as remaining reserves.

Many energy analysts are more familiar with worldwide statistics for oil than they are with those for natural gas. For comparison, the USGS gas estimates can be expressed in terms of equivalent volumes of conventional oil. The figure below shows world oil and gas estimates out to 2025 in terms of trillion barrels of oil equivalent, including mean estimates as well as high and low estimates to indicate a range of uncertainty for reserve growth and undiscovered resources. Cumulative production and remaining reserves are also included.

World Oil and Gas Resources, 1995-2025

The following relationships between oil and gas resources are derived from the USGS mean estimates:

• Almost one-quarter of estimated worldwide oil resources have already been produced, compared with only slightly more than 10 percent of worldwide gas resources.

• The amount of oil expected to be either discovered or added to reserves as a result of enhanced

• recovery is approximately equal to the amount of gas expected to be discovered or added to reserves. For both oil and gas, the bulk of the resource that has yet to be produced resides in fields that have already been discovered.

• On an energy equivalent basis, world oil consumption over the next 25 years is expected to be almost double world consumption of natural gas.

• Whereas the estimates of undiscovered oil volumes in WPA2000 are 20 percent greater than those in the previous (1994) USGS assessment, the estimates of undiscovered gas volumes are 14 percent smaller as a result of reduced estimates for the former Soviet Union, China, and Canada.

While the analytical rigor and information depth of the WPA2000 are impressive, it is important to recognize that all long-term assessments are imperfect. The USGS acknowledges that petroleum economics and technological improvements are critical unknowns whose evolution over time will have a profound impact on the world’s petroleum resource potential. In addition, the USGS assessments are limited to conventional resources only, excluding trillions of barrels of oil equivalent from the resource base. Estimates of worldwide heavy oil and tar sands exceed 3.2 trillion barrels, with Canada and Venezuela accounting for most of the deposits.^f The range of estimates for worldwide shale oil resources is staggering, running from a conservative 12 trillion barrels to a considerably more optimistic 2.1 quadrillion barrels.^g Coalbed methane deposits are estimated to hold more than 1 quadrillion cubic feet of gas, with most of the resource located in the United States, Canada, and China.^h

The USGS petroleum assessments will continue to provide an important foundation for additional geologic, economic, geopolitical, and environmental studies. With many of the world’s economies intrinsically linked to energy resource availability, such studies also provide essential long-term strategic guidance. 

____________________

^aU.S. Geological Survey, World Petroleum Assessment 2000, web site http://greenwood.cr.usgs.gov/energy/WorlEnergy/
DDS/60.
^bPetroconsultants, Inc., Petroleum Exploration and Production Database (Houston, TX, 1996).
^cNRG Associates, Inc., The Significant Oil and Gas Pools of Canada Data Base (Colorado Springs, CO, 1995).
^dD.L. Gautier et al., National Assessment of United States Oil and Gas Resources: Results, Methodology, and Supporting Data, U.S. Geological Survey Data Series DDS-30, Release 2 (Denver, CO, 2000).
^eU.S. Department of Interior, Minerals Management Service, An Assessment of the Undiscovered Hydrocarbon Potential of the Nation’s Outer Continental Shelf, OCS Report MMS 96-0034 (Washington, DC, 1996).
^fAbout Oil/Gas, Heavy Oil and Tar Sands–A Present and Future Resource, on-line version  web site http://petroleum.about.com/ industry/petroleum/library/weekly/aa032999.html (March 29, 1999).
^gW. Youngquist, Shale Oil—The Elusive Energy, Newsletter No. 98/4 (Golden CO: M. King Hubbert Center for Petroleum Supply Studies, Fourth Quarter 1998).
^hD.D. Rice, Coalbed Methane—An Untapped Energy Resource and An Environmental Concern, U.S. Geological Survey Fact Sheet FS-019-97 (Denver, CO, 1997).

U.S. Electricity Deregulation: The California Experience

California’s recent experience with electricity deregulation could have repercussions for the many governments around the world that are seeking to achieve electricity reform. Just as the earlier experience with reforms in the United Kingdom encouraged others to adopt similarly aggressive attempts at liberalizing electricity markets, the recent Californian experience with electricity reform may give some pause about reforming too quickly or ambitiously . . . or at all.^a Motivating California’s electricity reform efforts was the desire to reduce some of the highest electricity rates in the United States. In 1996, California’s average electricity revenue per kilowatthour sold, at 9.54 cents, was 38 percent higher than the average U.S. rate.^b California’s residential consumers paid 36 percent more than the average U.S. residential consumer, and industrial users in the State paid 52 percent more than average.

California began its recent experience with electricity reform on January 1, 1998, when Assembly Bill 1890 (A.B. 1890) became effective. Influenced strongly by electricity reforms undertaken in the United Kingdom almost a decade earlier, California created a new means of electricity exchange and allowed consumers greater choice in selecting their electricity suppliers. California’s reforms implemented a pricing mechanism that would recover “stranded” electricity costs, most of which were related to past investments in nuclear power and uneconomical power purchase contracts. To ensure that consumers benefited during the transition period, California required that the State’s three major utilities provide their residential and small commercial customers a 10-percent rate reduction, freezing rates at 10 percent below the prevailing rates as of June 10, 1996, until at least April 2002. What was essentially a performance-based rate (PBR) system was adopted during the transition period.^c

California’s electricity reform addressed the industry’s stranded cost problem. Stranded costs were allocated to all classes of customers in accordance with the amount of electricity they consumed. The State has attempted to pay down stranded costs through the issuance of bonds to be financed over a transitional period, but in practice the financing of the bonds added to consumers’ electricity bills and offset some of the impact of the rate reduction discussed above. In essence, the rate reduction was financed by the bonds used to recover the stranded costs, and the costs of the financing were transferred to consumers. The financing is due to be completed either by March 31, 2002, or at the time that all authorized costs for utility generation assets (stranded costs) have been recovered.

A.B. 1890 provided customer choice by allowing more than 70 percent of California’s electricity customers to change providers. By the time the retail market was opened to competition, 250 power marketing companies had signed up to sell electricity directly to California consumers.^d Consumers have been reluctant, however, to switch from their incumbent suppliers. They may have been discouraged by the retail rate caps and by the fees charged for making a switch. The multinational conglomerate Enron, for instance, exited the California retail market only 2 months after beginning operation, due to a low consumer signup rate. Whatever the reason, the introduction of electricity marketing in California was less successful than it has been in the Scandinavian countries, Australia, and the United Kingdom.

A.B. 1890 attempted to reconstruct California’s electricity supply industry along its three distinct components: generation, transmission, and distribution. An electricity pool, the California Power Exchange (PX), and an Independent System Operator (ISO) were created. The California PX and ISO were launched in March 1998. The ISO was given a mandate to operate the high-voltage transmission lines owned by the State’s three dominant investor-owned utilities, Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric.

The purpose of the PX is to act as a market for buying and selling electricity. All investor-owned utilities are required to compete in a power pool to sell their electricity, and independents may compete in the pool on a voluntary basis. The power pool works in the following fashion: suppliers and consumers of electricity submit bids to the PX for electricity needed both during the next day and during the next hour time periods. The PX then calculates the resulting demand and supply curves to determine a market clearing price.

In 2000, much attention was focused on the performance of California’s recently deregulated electricity market. In its third year of operation, the newly reformed electricity sector faced an exceptionally hot weather spell in May 2000, which led to electricity supply problems. Among other factors, the problem was exacerbated by a 3-year drought in the Northwest that significantly reduced the hydroelectric capacity available to the western States; the constrained capacity of transmission lines to bring more electricity into California; the reduced availability of some power plants because they had used their allotted emission allowances and because of their extended use during the previous summer; and the high cost of purchasing emission allowances, which would have allowed the plants to continue to operate.^e

Exceptionally high natural gas prices also contributed to California’s runup in electricity prices. Insufficient pipeline capacity both at the border and within the State severely limited available gas supplies, and border prices spiked to more than six times the New York Mercantile Exchange (NYMEX) price.^f In May, the California ISO had to request industrial customers and other large users, who had agreed to reduce demand when asked, to take those steps. In June 2000, the exceptionally hot weather and a grid operational problem led to rolling blackouts in the San Francisco Bay area.^g The Bay Area’s local utility, Pacific Gas & Electric, was forced to interrupt service to 100,000 customers.

In the summer of 2000, both Pacific Gas & Electric and Southern California Edison were operating under retail rate caps that are scheduled to be in affect until April 2002 according to A.B. 1890. Customers of San Diego Gas & Electric (SDG&E), however, were the first to see rate caps removed, and their electricity bills rose sharply. In the California PX, ancillary prices reached $9,999 per megawatthour.^h The high wholesale power prices led to concerns that power producers could be exercising market power, and SDG&E asked the Federal Energy Regulatory Commission (FERC) “to declare California markets uncompetitive and to impose [price] controls.”ⁱ SDG&E had at the time been passing on its sharply higher purchased wholesale power costs to its retail consumers. Electricity bills in San Diego tripled.

In August, California Governor Gray Davis directed the State’s Attorney General to investigate whether “possible manipulation in the wholesale electricity market” had occurred.ⁱ In September 2000, the governor signed legislation that would cap San Diego electricity prices for residential and small commercial users at 6.5 cents per kilowatthour—less than half the average price in August—retroactive to June 1, 2000. The governor also directed the California Energy Commission to expedite siting reviews for new power plants.ⁱ In August, in order to address the problem of inadequate long-term electricity capacity, the governor signed A.B. 970, accelerating the power plant approval process from 12 months to 6 months.^j

California’s electricity troubles continued to deepen toward the end of 2000 and into the beginning of 2001. In December, the price of electricity skyrocketed to 30 cents per kilowatthour.^k With their ability to raise retail electricity prices restricted, and facing exceptionally high pool prices, Pacific Gas & Electric and Southern California Edison defaulted on hundreds of millions of dollars in debt and power bills. Together, the two utilities accumulated more than $12 billion in debt as a result of the sharp rise in California pool prices, and both utilities have seen their debt downgraded to below investment grade status.^l On the consumer side, the retail price caps shielded electricity customers from the impacts of the market price spikes, and there was no price pressure to encourage demand reductions. In early 2001, the State experienced a series of short-duration, rolling blackouts in which more than 675,000 homes and several large industrial users lost electric power.^m

High wholesale prices in California have contributed to higher prices in neighboring States, resulting in a regional electricity crisis that has caused several State governors to ask for wholesale price caps.ⁿ In December 2000, FERC capped bulk power prices at $150 per megawatthour, although both newly elected President Bush and the recently appointed Commissioner of FERC have opposed price caps.^o Generating companies could petition for higher prices, however, if they could justify them.^p The FERC had undertaken an investigation of California’s electricity market and market structure in July 2000 as part of an investigation examining the national electricity market.

On November 1, 2000, FERC released a draft order calling for changes in California’s market, recommending that the State build more power plants and invest more in transmission lines.^q The Commission also proposed eliminating the requirement that California’s major utilities buy and sell all their electricity through the pool, and recommended that they be allowed to engage in long-term forward contracts.

In December 2000, the U.S. Secretary of Energy, Bill Richardson, issued an immediate order forcing 75 power generators in western States to supply electricity to California. He further ordered that power producers sell power to California “even if they are uncertain of payment.”^r In January 2001, Governor Davis signed an emergency order allowing California’s Department of Water Resources to become a temporary buyer of power, providing the agency with a spending authority of $400 million, and in February 2001 he signed a measure allowing the Department to float an estimated $10 billion in revenue bonds to finance power purchases directed at acquiring electricity through long-term contracts. The bonds are to be paid off by electricity consumers. The bill also includedsome conservation measures, requiring retailers to cut their outdoor lightning use by half or face penalties. In March 2001, the FERC ordered 10 generation companies to reimburse the California ISO $69 million for charging rates deemed not to be “just and reasonable.” The reimbursement amounted to only a fraction of the $550 million sought by State officials for overcharges.^s

Sharp price spikes are not new to pool-based electricity exchange systems. In countries that have adopted pool-based electricity trading systems, such as the United Kingdom and Australia, concerns have arisen about the connection between price spikes and market power. In the wake of California’s recent experience with its electricity pool, a similar concern has arisen that suppliers may have achieved excessive market power.

Several other arguments have also been offered to explain the problems experienced by California’s electricity market in 2000. Long-term underinvestment in the State’s electricity sector has been cited as a contributing factor, given that its rapidly growing economy has produced sharp increases in electricity demand. It has become increasingly difficult to build new generation facilities in the State, and generation capacity additions have severely lagged far behind growth in demand since the early 1990s. The average age of a power plant in California is currently more that 30 years.^t Indeed, operational difficulties have plagued California’s electricity infrastructure over the past year. During the height of the electricity crisis several power plants were pulled out of production, and congestion constraints became apparent on the State’s north-south transmission line.

Pebble Bed Modular Reactors: A New Lease on Life for Nuclear Power?

In 1999, pressurized water reactors (PWRs) provided roughly half of the world’s total nuclear electricity generation. Other reactor types in service around the world include boiling water reactors (BWRs), and pressurized heavy water reactors (PHWRs), among others. Since 1993, South Africa’s state-owned utility, Eskom, has been working to develop a new commercial nuclear power technology, the pebble bed modular reactor (PBMR). Construction of the first PBMR is expected to begin in 2003, and it is scheduled to be operational in 2005.^a If Eskom’s estimates prove to be correct, the PBMR technology could be both safer and more economical than the nuclear power plants now in operation.

The fuel in PBMRs consists of billiard-ball-sized spheres of graphite “pebbles” containing ceramic-coated uranium dioxide particles. About 400,000 pebbles are spread about the graphite-lined reactor vessel to provide the critical mass needed for a sustained nuclear reaction. Helium at a temperature of 500EC is introduced at the top of the reactor.^b The gas then circulates over the hot fuel pebbles, which increase its temperature to 900EC. The heated gas then flows into a gas turbine, which in turn drives a generator to produce electricity. The gas exits the turbines at 600EC and then flows into a recuperator, where the gas temperature is lowered to about 140EC. The gas temperature is reduced to about 30EC by a water-cooled precooler, then repressurized and passed back through the recuperator and sent back into the reactor. The process of using high-temperature gas as the working fluid to convert heat to mechanical energy (the turbine’s rotational energy) is known as a direct Brayton cycle and, characteristically, has high thermal efficiency.

Eskom has high expectations for the new technology, estimating that it will be roughly equivalent in cost to South Africa’s relatively inexpensive mine-sited coal-fired plants^c and more economical than PWR technology. Other potential advantages being promoted by Eskom include design features that could reduce concerns about plant siting, operational safety, refueling outages, nuclear waste disposal, and nuclear arms proliferation.

The PBMR modular design is expected to improve the economics of the plant over conventional nuclear plants. Each unit, about the size of a single-family dwelling, would be factory-constructed, and the total construction time from the start of on-site construction to power generation is expected to be just 24 months when the technology is in full production.^d The first unit is expected to have a capacity of 110 megawatts, about 10 percent of the generation capacity of a conventional PWR. The plant’s relatively small size means that it would not necessarily have to be used for baseload capacity. As demand increased, modules could be added incrementally, and the units could be linked in clusters.

The PBMR technology could also overcome some of the siting problems associated with conventional nuclear plants. Because they do not use water as a coolant, PBMRs would not have to be sited near a body of water, and the passive safety features, in theory, would allow them to be located close to end users. South Africa intends to build PBMRs on the nation’s eastern coast, where coal resources are not available, probably at Koeberg, where its one currently operating nuclear power plant is located.

Eskom expects the PBMR technology, employing passive safety features, to be safer than conventional nuclear reactor technologies. The helium coolant, although more expensive than water, would reduce the risk of a nuclear accident and could be used at very high temperatures without causing corrosion.^e The graphite moderator would allow for much higher operating temperatures—750EC versus 350EC for a conventional PWR—which would eliminate the possibility of a core meltdown. If the PBMR system failed, it would simply shut down.

Another expected advantage is that, in theory, a PBMR could be refueled continuously while in operation, reducing the need for refueling outages. Fresh fuel pebbles could be added to the top of the PBMR fuel bed and old pellets removed from the bottom while the reactor remained in operation. Eskom estimates that its initial PBMR plant will approach an availability rate of 90 percent^f (as compared with the 1999 U.S. average of 86 percent). In addition, the significant improvement in thermal efficiency that would be achieved by using the direct Brayton cycle would allow PBMRs to use less fuel and, thus, produce less spent fuel. As a result, the nuclear waste disposal problem could be reduced.^g

Finally, Eskom has suggested that PBMRs would reduce the risk of nuclear arms proliferation, because they use only 9 percent enriched uranium as a fuel, and the spent fuel generated would have little value as a weapons component. If, as Eskom plans, South African PBMRs become widely exported, the need to export a uranium fuel capable of being transformed into a nuclear weapon would be greatly reduced.

South Africa’s PBMR technology has gained the interest of energy policymakers from abroad and of some foreign private-sector investors. Researchers from the U.S. Nuclear Regulatory Commission (NRC) and the Department of Energy recently visited South Africa to meet with Eskom’s design team, and U.S. Secretary of Energy Bill Richarson stated a desire to cooperate with the South Africans.^h One U.S.-based company, PECO Energy, has joined with British Nuclear Fuels Corporation in making financial commitments to the venture. PECO’s parent company, Excelon Corporation, began discussions with the NRC in late 2000 and early 2001 about building PBMRs in the United States.

Many critics, however, contend that it is doubtful that Eskom will, in the end, build a unit that will be competitive with other electricity production technologies, particularly in a deregulated environment. Eskom has been criticized for adopting overly optimistic estimates of construction costs ($1,000 per kilowatt of capacity) and total generating costs (1.6 cents per kilowatthour, including construction, operation, maintenance, fuel, insurance, and decommissioning costs),ⁱ which are about those for a conventional coal-fired power plant in the United States. One reason for the low estimated costs of building a PBMR is the assumption that many of the safety features required for conventional reactors, such as a containment building, would not be needed. The need for a traditional containment structure for PBMRs has not been demonstrated, because even a total loss of the gas coolant would not produce any radioactive releases; however, critics are concerned about the proposal to build and operate any nuclear reactor without containment.

Moreover, underlying Eskom’s financial assumptions is a very low discount rate of 6 percent. Given that the capital costs of a nuclear plant determine in large measure whether construction is economical, a higher discount factor could easily undermine the financial viability of PBMRs even if all the other claims for the technology were realized. If, however, Eskom meets its goal of completing the construction within 2 years, the borrowing costs for the project will be less critical. Still, the PBMR is an untested technology from a commercial standpoint, and the success of the South African demonstration project will in large measure determine its viability.

________________

^a“PECO Invests in Eskom’s Project,” Africa News Service (August 30, 2000), p. 1.
^bTechnology Services International, web site www.pbmr.co.za/Pebble_bed_new/preface_content.htm.
^c“Eskom’s Pebble Bed Reactor Presented to Government,” Nuclear News (May 2000), p. 39.
^dTechnology Services International, web site www.pbmr.co.za/Pebble_bed_new/preface_content.htm.
^eS. Thomas, “Arguments on the Construction of PBMR Reactors in South Africa,” web site www.earthlife.org.za/campaigns/toxics/pmbr.html.
^fJ. Kupitz and V.M. Mourogov, “The Role of Small and Medium-Sized Reactors,” The Uranium Institute 23rd Annual International Symposium (1998), web site http://uilondon.org/uilondon/sym/1998/kupitz.htm.
^gS. Thomas, “Arguments on the Construction of PBMR Reactors in South Africa,” web site www.earthlife.org.za/campaigns/toxics/pmbr.html.
^hR. Smith, “U.S. Backs South African Effort To Develop Nuclear Reactor—Eskom Seeks Global Investors in Power Project—Design Said To Be Meltdown Proof,” Wall Street Journal (June 15, 2000), p. 4.
ⁱUranium Information Center, Nuclear Issues Briefing Paper 16 (April 2000), web site www.uic.com.au/nip16.html.

Natural Gas Vehicles: Worldwide Status

Natural-gas-fueled vehicles are not a new technology, having been in use since the 1930s and accounting for more than a million of the motor vehicles on the road today worldwide.^a More than 100,000 natural gas vehicles (NGVs) are operating in the United States alone; however, this is not to suggest that NGVs make up a substantial portion of the American automotive fleet. The entire highway vehicle fleet of the United States was 212 million in 1997, and NGVs accounted for less than 0.1 percent of the country’s total vehicle population.^b

Interest in expanding the NGV fleet is growing in many parts of the world. Concerns over the pollutants released by gasoline- and diesel-fueled vehicles has helped NGVs gain momentum, and many of the new emissions standards that have recently been enacted in the United States, Canada, and Europe may increase the penetration of NGVs. For instance, in December 2000, President Clinton approved a proposal by the U.S. Environmental Protection Agency (EPA) to reduce substantially the amounts of sulfur and nitrogen oxide released by heavy-duty vehicles.^c This followed the Tier 2 Motor Vehicle Emissions Standards and Gasoline Sulfur Control Requirements finalized by the EPA earlier in 2000, tightening emissions standards for passenger cars and light-duty trucks, minivans, and sport utility vehicles.

Canada announced in May 2000 that it would launch a national program to study measures for reducing pollution from motor vehicles with the intention to “meet or exceed the new standards that the United States will have in place beginning with the 2004 model year and culminating with the 2009 model year.”^d Similarly, the European Union (EU) passed its Auto Oil I Programme in 1997, which eliminated the use of leaded fuel by EU member countries on January 1, 2000 (except for Spain, Italy, Greece, and the French Territories, for which extensions were granted until 2002) and issued limits on sulfur, benzene, and aromatics.^e The EU is already working on an Auto Oil II Programme, which will further tighten motor vehicle emissions standards.^f

There are two ways in which natural gas is currently used as a motor vehicle fuel: compressed natural gas (CNG) and liquefied natural gas (LNG). CNG is the most common form of natural gas use as an alternative fuel, although there is a growing market for use of LNG in heavy-duty vehicles. The basic difference between CNG and LNG is energy density; the liquid form of the fuel carries more energy per pound than the gaseous form.^g In the United States, an estimated 101,991 CNG vehicles and 1,682 LNG vehicles were operating in 2000.^h In Canada, nearly 40,000 NGVs operate with a network of 125 public fueling stations.ⁱ

In most parts of the world, NGVs are introduced to replace buses and other public vehicle fleets, as well as taxi fleets. This has become increasingly popular in European countries where there is a concern about air quality in congested urban areas with well-established mass transit. It is also increasingly true for cities like Mumbai and Mexico City, both of which have struggled to control worsening air pollution problems. Mexico, however, has only two CNG service stations, although there are plans to increase the number to 30 before 2003.^j Mexico hopes to increase the penetration of NGVs from 2,000 in 2000 to 35,000 to 50,000 vehicles over the next few years. The Mexican Regulatory Commission of Energy estimates that it will be able to increase the number of NGVs to 100,000 by 2008.

In Europe, the penetration of NGVs has been increasing rapidly. The EU’s four largest natural-gas-consuming members, the United Kingdom, Germany, France, and Italy, are all introducing new incentives for CNG-fueled vehicles.^k Germany offers a low tax on CNG, and the government is committed to maintaining the low tax rate until 2009. The tax on CNG is only 15 percent of the service station price of DM 1.10 per kilogram (equivalent to paying about DM 0.75 per liter for the same amount of motor gasoline, whereas the current price of motor gasoline is DM 1.85 per liter). The tax benefit for using CNG will be even more attractive in 2003, when a new ecological tax is scheduled to be levied on petroleum fuels.

France is also trying to expand its NGV fleet. The country currently has 4,500 NGVs operating. In November 1999, state-run Gaz de France joined with PSA Peugeot Citroen, Renault, and Union Francaise des Industries Petrolieres to promote the NGV market, and Gaz de France has created a subsidiary, GNVert, whose purpose it is to develop a network of CNG stations along the country’s road network. France has already managed to introduce CNG-fueled buses in half of its cities with populations over 200,000, and another 500 CNG buses are on order.

The United Kingdom has fewer NGVs operating than does France, only 835 and most are buses and garbage trucks.^k The government is promoting NGVs through the 1995/1996 Powershift Programme, under which subsidies between 40 and 75 percent are offered for conversions of vehicles to CNG or liquefied petroleum gas (LPG). Funding for the project was recently tripled to about $15 million. The primary focus of the program has been on LPG use, which is growing at a rapid pace in the United Kingdom, and LPG-fueled vehicles are expected to reach 33,000 by the end of 2001.

Italy has the greatest number of NGVs in Western Europe, with some 345,000 vehicles currently operating.^l It also has a well-established infrastructure with 340 service stations that can supply consumers with CNG. Italian natural gas supplier, Snam, has ambitious plans to expand the CNG infrastructure by doubling the distribution network and is also working with Fiat in the development of NGVs.^k CNG service stations are expected to reach 600 by 2005.^l

Outside the industrialized world, the potential market for NGVs could be very lucrative. In Argentina, the NGV stock increased from a few hundred in 1990 to about 600,000 in 2000, supported by 850 CNG service stations.^k Low taxes on CNG have helped support the growth; CNG is sold for between 30 and 35 cents per liter, less than one-third the price of motor gasoline (currently about $1.10 per liter).

In Egypt, the NGV market has increased from nearly zero in 1997 to an estimated 20,000 in 2000—with most of the operating vehicles in Cairo. The supporting infrastructure for CNG has increased apace, with up to 30 public stations already operating. The Egyptian government is requiring all taxis and micro-buses to convert to CNG within a 3-year period. Even Russia has more than 200,000 NGVs operating with plans to convert another 1 million vehicles by 2010.ⁱ

India has committed to creating a major fleet of CNG-fueled public transport buses in Delhi, where the state government will invest $48.1 million to buy 1,100 CNG buses and will convert another 1,000 diesel-fueled buses to CNG engines.^m An order for 1,500 CNG buses has already been placed, in part as a response to the Indian Supreme Court deadline of March 31, 2001, for Delhi to phase out all diesel-run buses in an effort to reduce air pollution. Delhi has already established 50 CNG service stations, and there are another 20 operating in Mumbai.ⁿ Overall, India currently has 25,000 vehicles already converted from diesel to CNG.

The major drawback for establishing a strong NGV program is lack of infrastructure. For example, the firm Gas Natural launched a program to introduce NGVs in Bogota, Colombia, but thus far there are only 110 motorists using the gas-fueled cars and only two service stations available to them.^o The company hopes to expand the number of service stations to eight within a year’s time, but the current lack of infrastructure tends to retard expansion of the NGV fleet.

One way in which countries increase their NGV fleets is through conversions of motor-gasoline-fueled cars. In Argentina, for example, vehicle conversions from motor gasoline to natural gas are averaging around 6,000 per month.ⁿ Vehicle conversion costs vary according to the size of the engine (typical sedans can be converted for around $4,000 excluding labor, but the conversion costs for heavy-duty engines, trucks, and buses are between $30,000 and $50,000 because of the number of cylinders needed to obtain the desired travel range of the vehicle).^p New light-duty NGVs can cost as much as $6,000 over the price of conventional gasoline and diesel vehicles.

Environmental Impacts of Hydropower

It is estimated that approximately one-third of the countries in the world currently rely on hydropower for more than half of their electricity supply. Largely considered a “clean” renewable energy source, hydropower has provided many economic and social benefits. Many countries have chosen to develop their hydroelectric resources as a means of improving domestic energy security, providing more energy services, stimulating regional economic development, and increasing economic growth. For example, Brazil started to invest heavily in hydroelectric development in the 1970s, after experiencing the world oil price shocks and their effects on national energy supply and, particularly, electricity costs. Hydroelectric development in Brazil, which has resulted in some of the world’s largest hydropower plants, bolstered growth in the country’s heavy industry sector and helped achieve a high level of electrification.

The benefits provided by hydroelectric development in Brazil and other countries were not achieved without also incurring some negative economic, social, and environmental impacts. In particular, large hydroelectric facilities have tended to demonstrate variable economic performance, and in some cases they have been blamed for increasing the debt burden of developing countries. Most of the negative social and environmental impacts are associated with hydroelectric reservoirs (as well as reservoirs and dams for other purposes), rather than hydropower itself.

It is now widely recognized that dam development, whether for hydropower or other purposes, can disrupt the culture and sources of livelihood of many communities. Studies have indicated that the majority of the people uprooted from their existing settlements as a result of dam development are poor and/or members of indigenous populations or vulnerable ethnic minorities. Displaced populations are also more likely to bear a disproportionate share of the social and environmental costs of large dam projects without gaining a commensurate share of the economic benefits. The negative environmental impacts of dams and their reservoirs include loss of forests, wildlife habitats, species populations, aquatic biodiversity, upstream and downstream fisheries, and services provided by downstream flood plains and wetlands.^a

With the emergence of climate change as an environmental issue of increasing international concern, hydropower has largely been viewed as a “cleaner” energy source than fossil fuels. No carbon dioxide or other greenhouse gas emissions result from the generation of hydroelectricity, because no fuel combustion is involved. However, results from preliminary field studies indicate that the reservoirs associated with hydroelectric dams emit both carbon dioxide and methane. Emissions emanate from the decomposition of biomass in the reservoirs and from biomass flowing in from the river’s catchment area. The scale of emissions is variable, depending on the reservoir location (geography, altitude, latitude), temperature, size, depth, depth of turbine intakes, dam operations, and construction procedures.^b Additional greenhouse gases are also emitted in the process of making cement for dam construction.

The recently discovered evidence of hydroelectric-related greenhouse gas emissions has obvious implications for energy choices made in light of climate change considerations. Some field studies suggest that greenhouse gas emissions from hydroelectric reservoirs (the sum of carbon dioxide and methane, based on their global warming potentials) can be similar in magnitude to those from thermal power plants with equivalent generation capacity. (Because specific site conditions determine the levels of emissions from hydroelectric reservoirs, comparisons must be made on a case-by-case basis.) On the other hand it has been argued that the true measure of “anthropogenic” emissions associated with a hydroelectric plant can only be assessed by comparison with emissions from the same catchment area before the dam was constructed.^a

_________________________

^aWorld Commission on Dams, Dams and Development: A New Framework for Decision-Making (London, UK: Earthscan Publications, 2000).
^bWorld Commission on Dams, “Hydropower and Climate Change: WCD Reviews Evidence on Large Dams and Greenhouse Gas Emissions,” Press Release (June 10, 2000), web site www.dams.org.

Reducing Sulfur Dioxide and Nitrogen Oxide Emissions in the European Union and the United States

Many countries currently have policies or regulations to limit energy-related emissions of sulfur dioxide and nitrogen oxides. Both pollutants are known to contribute to the problems of acid rain and eutrophication of soils and waters, and nitrogen oxides also contribute to the formation of smog caused by ground-level (tropospheric) ozone. Coal-fired electricity generation both in the United States and in the European Union (EU). Electricity generation is also a source of nitrogen oxide emissions, but oil use for transportation is the largest source.

In Europe, efforts to limit sulfur dioxide and nitrogen oxide emissions were first coordinated under the 1979 United Nations/Economic Commission of Europe Convention on Long-Range Transboundary Air Pollution (CLRTAP), which was drafted after scientists demonstrated the link between sulfur dioxide emissions in continental Europe and the acidification of Scandinavian lakes. Since its entry into force in 1983, the Convention has been extended by eight protocols, setting emissions limits for a variety of pollutants. The most recent protocol, the 1999 Gothenburg Protocol to Abate Acidification, Eutrophication, and Ground-Level Ozone, sets new national emissions ceilings for sulfur dioxide, nitrogen oxides, volatile organic compounds, and ammonia.

The national emissions ceilings under the Gothenburg Protocol correspond to a target reduction of total sulfur dioxide emissions in the EU of 75 percent below the 1990 level by 2010 and a 50-percent reduction in its nitrogen oxide emissions from the 1990 level by 2010.^a Like the earlier CLRTAP protocols, the Gothenburg Protocol specifies tight limit values for specific emissions sources, based on the concept of critical loads, and requires best available technologies to be used to achieve the emissions reductions.

More specific measures for abating sulfur dioxide and nitrogen oxide emissions are defined in a number of European Commission directives. The Large Combustion Plant Directive of 1988 and its amendments impose sulfur dioxide and nitrogen oxide emission limits on existing and new plants with a rated thermal input capacity greater than 50 megawatts and sulfur dioxide emissions limits on smaller combustion plants using solid fuels (particularly coal). Other directives impose limits on the sulfur content of certain fuels used in power stations, industry, and motor vehicles; requirements for the use of best available technologies on new and existing plants (e.g., flue gas desulfurization devices, low nitrogen oxide burners); and vehicle emissions standards.

Since 1980, sulfur dioxide and nitrogen oxide emissions in Europe have fallen. The drop in sulfur dioxide emissions was partly due to prescribed emissions limits and technology requirements, particularly in the electricity generation sector. Shifts from coal to natural gas for electricity production in several countries during the 1990s (most notably in Germany and the United Kingdom) also contributed to the reduction. The same factors also contributed to the drop in nitrogen oxide emissions, but the introduction of catalytic converters on vehicles was the most influential factor.^b

In the United States, initiatives to reduce sulfur dioxide and nitrogen oxide emissions stem from the Clean Air Act, the comprehensive Federal law that regulates air emissions from area, stationary, and mobile sources. The 1970 and 1977 Clean Air Act Amendments included emissions standards and requirements for the use of best available control technologies for new sources. The 1990 Amendments set emissions reduction goals for specific air pollutants and designated stricter emissions standards extending across a wider range of sources.

Title IV of the Clean Air Act Amendments of 1990 (CAAA90) was intended to reduce the adverse effects of acid deposition by setting a goal of reducing annual sulfur dioxide emissions by 10 million tons below 1980 levels and annual nitrogen oxide emissions by 2 million tons below 1980 levels. To achieve the sulfur dioxide reductions, a two-phase tightening of emissions restrictions was placed on existing fossil-fired power plants serving utility generators with an output capacity greater than 25 megawatts and on all new utility units. Phase I, which began in 1995, affected mostly coal-burning electric utility plants in 21 eastern and southern States. Phase II, which began in 2000, tightened the annual emissions limits imposed on those large, higher emitting plants and also placed restrictions on smaller, cleaner plants fired by coal, oil, and gas.

CAAA90 Title IV established the world’s first large-scale application of a “cap and trade” program to meet an environmental goal. Under the program, a total annual emissions budget (measured in tons of sulfur dioxide) was established for each year, in accordance with aggregate emissions reduction goals. Generating units were issued tradable emission allowances, based primarily on their historic fuel consumption and specific emissions rates. Each allowance permits a generating unit to emit one ton of sulfur dioxide during or after a given year. At the end of each year, power plant owners must hold an allowance for each ton of sulfur dioxide emitted that year, or else face a penalty. Extra allowances may be bought, sold, or banked (i.e., saved for future use rather than for current use).

Emissions data from Phase I indicate overcompliance: the generating units subject to the Phase I emissions cap emitted, in aggregate, less sulfur dioxide than the total allowable level. Emissions were reduced by a combination of strategies, including the installation of scrubbers, switching to low-sulfur coal, and trading emission allowances.^c It is argued that without the trading option, the reduction in sulfur dioxide emissions that was over and above the required amount would not have been as large.^d Phase II of the program, which is currently in effect, sets a permanent ceiling (cap) of 8.95 million tons on the allowances issued each year; however, the amount of sulfur dioxide actually emitted may exceed the Phase II cap for some time, because allowances banked under Phase I can be carried over to Phase II.

The nitrogen oxide emissions reductions required by CAAA90 Title IV were also scheduled according to a two-phase approach, but no cap was set for aggregate nitrogen oxide emissions from electricity generation, and no allowance trading program was included. Phase I, which began in 1996, set an emissions limit (in pounds of nitrogen oxide per million Btu of fuel input) for two types of coal-fired utility boilers already targeted for Phase I sulfur dioxide emissions reductions. Phase II, which started in 2000, set stricter nitrogen oxide emissions limits for those boiler types and established emissions limits for other coal-fired boiler types.

Other programs for reducing nitrogen oxides and sulfur dioxide emissions in the United States have been established as a result of the Clean Air Act Amendments. In an effort to reduce the transport of emissions over long distances and help States meet the national ambient air quality standards for ground-level ozone, the U.S. Environmental Protection Agency has promulgated a multi-State summer season cap on power plant nitrogen oxide emissions that will take effect in 2004. The new rules, commonly referred to as the “NO_x SIP Call,” require abatement efforts greater than those required to comply with the limits on nitrogen oxides under CAAA90 Title IV. The limits under the NO_x SIP Call have been set in the form of allowances and allowance trading is permitted.

CAAA90 also established emissions standards for motor vehicles. “Tier 1” standards cover emissions of nitrogen oxides (in addition to carbon monoxide, hydrocarbons, and particulate matter) for light-duty vehicles beginning with model year 1994, and the tighter “Tier 2” standards, which apply to all passenger vehicles, will be phased in starting in 2004. Tier 2 standards also require that the sulfur content of gasoline be reduced, in order to ensure the effectiveness of the emission control technologies that will be needed to meet the emission targets. Heavy-duty vehicles (trucks) have also faced emissions standards since 1990, which were easily met by engine controls. Recent rulings impose a new “ultra-low” sulfur content requirement for diesel fuel used by highway trucks and specific nitrogen oxide emissions control technologies by 2007.

____________________