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America's Energy Future: Technology and Transformation (2009)

Chapter: 3 Key Results from Technology Assessments

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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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3
Key Results from Technology Assessments

This chapter summarizes the detailed assessments presented in Part 2 of this report, organized by subject and chapter as follows:

The chapter annex, Annex 3.A, describes the key methods and assumptions that were used to develop the energy supply, savings, and cost estimates in this report. Additional detailed supporting information can be found in Part 2 of this report and in the following National Academies reports derived from this America’s Energy Future (AEF) Phase I study:

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

ENERGY EFFICIENCY

The potential for increasing energy efficiency—that is, for reducing energy use while delivering the same energy services—in the United States is enormous. Technology exists today, or is expected to be developed over the normal course of business between now and 2030, that could save about 30 percent of the energy used annually in the buildings, transportation, and industrial sectors. These savings could easily repay, with substantial dividends, the investments involved. In particular, if energy prices were high enough to motivate investment in energy efficiency or if public policies had the same effect, energy use could be lower by 15–17 quads (about 15 percent) in 2020 and by 32–35 quads (about 30 percent) in 2030 than the reference case projection of the U.S. Department of Energy’s Energy Information Administration (EIA). The opportunities for achieving these savings reside in hundreds of technologies, many of them already commercially available and others just about to enter the market.

This section summarizes the capability of energy efficiency technologies to reduce energy use or moderate its growth. Technologies that pay for themselves (in reduced energy costs) after criteria have been applied to reflect experience with consumer and corporate decision making are considered cost-effective. For the buildings sector, supply curves were developed that reflect implementation of efficiency technologies in a logical order, starting with lowest-cost technological options. Using discounted cash flow1 and accounting for the lifetimes of technologies and infrastructures involved, the reported efficiency investments in buildings generally pay for themselves in 2–3 years. For the industrial and transportation sectors, the AEF Committee relied on results from the report by the America’s Energy Future Panel on Energy Efficiency Technologies (NAS-NAE-NRC, 2009c).2 For industry, the panel reported industry-wide potential for energy savings reflecting improvements that would offer an internal rate-of-return on the efficiency investment of at least 10 percent. For transportation (which addresses fewer technologies and thus includes more in-depth assessments of each), the panel focused on how the performance and costs of vehicle technologies might evolve relative to one another (and the capability of these technologies to reduce fleet fuel consumption).

1

The discounted cash flow approach describes a method of valuing a project, company, or asset such that all future cash flows are estimated and discounted to give their present values.

2

Further details on these estimates can also be found in Chapter 4 in Part 2 of this report.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

The panel examined the available energy efficiency literature and performed additional analyses. For each sector, comparisons were made to a “baseline” or “business as usual” case to estimate the potential for energy savings. These are described in Annex 3.A.

Buildings Sector

About 40 percent of the primary energy used in the United States, and fully 73 percent of the electricity, is used in residential and commercial buildings. Diverse studies for assessing this sector’s energy-savings potential, although they take many different approaches, are remarkably consistent and have been confirmed by the supply curves developed for this report. The consensus is that savings of 25–30 percent relative to current EIA (2008) reference case projections could be achieved over the next 20–25 years. These savings, which would come principally from technologies that are more efficient for space heating and cooling, water heating, and lighting, could hold energy use in buildings about constant even as population and other drivers of energy use grow. Moreover, the savings could be achieved at a cost per energy unit that would be lower than current average retail prices for electricity and gas.3 For the entire buildings sector, the supply curves in Chapter 2 of this report (Figures 2.5 and 2.6) as well as in the panel report (NAS-NAE-NRC, 2009c) show that a cumulative investment of $440 billion4 in existing technology between 2010 and 2030 could produce an annual savings of $170 billion in reduced energy costs.

Advanced technologies just emerging or under development promise even greater gains in energy efficiency. They include solid-state lighting (light-emitting diodes); advanced cooling systems that combine measures to reduce cooling requirements with emerging technologies for low-energy cooling, such as evaporative cooling, solar-thermal cooling, and thermally activated desiccants; control sys-

3

The average residential electricity price in the United States in 2007 was 10.65¢/kWh (in the commercial sector, the average price was 9.65¢/kWh). The average residential price for natural gas in the United States in 2007 was $12.70/million Btu (in the commercial sector, the average price was $11/million Btu).

4

The investments include both the full add-on costs of new equipment and measures (such as attic insulation) and the incremental costs of purchasing an efficient technology (e.g., a high-efficiency boiler) compared with purchasing conventional-counterpart technology (e.g., a standard boiler). These investments would be made instance-by-instance by the individuals and public or private entities involved. The costs of policies and programs that would support, motivate, or require these improvements are not included.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

tems for reducing energy use in home electronics; “superwindows” with very low U-values;5 dynamic window technologies that adjust cooling and electric lighting when daylight is available; and very-low-energy houses and commercial buildings that combine fully integrated design with on-site renewable-energy generation.

Transportation Sector

The transportation sector, which is almost solely dependent on petroleum, produces about one-third of the U.S. greenhouse gas emissions6 arising from energy use. The sector is dominated by use of the nation’s highways, for both freight and passengers.

Current technologies offer many potential improvements in fuel economy, and they become increasingly competitive and attractive as fuel prices rise. Reductions in fleet fuel consumption over the next 10–20 years will likely come primarily from improving today’s spark-ignition (SI), diesel, and hybrid vehicles that are fueled with petroleum, biofuels, and other nonpetroleum hydrocarbon fuels.

Over the subsequent decade, plug-in hybrid vehicles (PHEVs) that use electricity plus any of the fuels just mentioned may be deployed in sufficient volume to have a significant effect on petroleum consumption. Longer term, after 2030, major sales of hydrogen fuel-cell vehicles (HFCVs) and battery-electric vehicles (BEVs) are possible.

  • Light-duty vehicles. Power-train improvements for LDVs offer the greatest potential for increased energy efficiency over the next two decades. Technologies that improve the efficiency of SI engines could reduce average new-vehicle fuel consumption by 10–15 percent by 2020 and a further 15–20 percent by 2030. Turbocharged diesel engines, which are some 10–15 percent more efficient than equal-performance SI engines, could steadily replace nonturbocharged engines in the SI fleet. Improvements in transmission efficiency and reductions in rolling resistance, aerodynamic drag, and vehicle size, power, and weight can all increase vehicle fuel efficiency.

5

U-values represent how well a material allows heat to pass through it. The lower the U-value, the greater a product’s ability to insulate.

6

In this report, the cited quantities of greenhouse gases emitted are expressed in terms of CO2-equivalent (CO2-eq) emissions.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

Currently, corporate average fuel economy (CAFE) standards for new LDVs are targeted to reach 35 miles per gallon by 2020, which would equate to a 40 percent improvement in average new-vehicle fuel efficiency (and a 30 percent reduction in average fuel consumption).7 Achieving this goal, and further improving fuel efficiency after 2020, will require that the historic emphasis on ever-increasing vehicle power and size be reversed in favor of fuel economy.

Gasoline hybrid-electric vehicles (HEVs) currently offer vehicle fuel-consumption savings of as much as 30 percent over SI engines. Thus it is likely that meeting the new CAFE standards by 2020 will require a large fraction of new vehicles to be HEVs or smaller, less powerful vehicles. PHEVs and BEVs could begin to make a large impact beyond 2020; however, the success of these technologies is crucially dependent on the development of batteries with much higher performance capabilities than today’s batteries, and with lower costs. Research and development on battery technology continues to be a high priority.

If they could be equipped with batteries that powered the vehicle for 40–60 miles, gasoline PHEVs could reduce gasoline/diesel consumption by 75 percent. While HEVs mainly improve performance or fuel economy, PHEVs actually get most of their energy from the electric grid.

Improvements in battery and fuel-cell technologies are expected to pave the way for possible large-scale deployments of BEVs and HFCVs in the 2020–2035 period. Because BEVs and HFCVs could reduce and ultimately eliminate the need for petroleum in transportation, they could also reduce and possibly even eliminate LDV tailpipe greenhouse gas emissions.

  • Freight transportation. Future technologies for heavy-duty trucks include continuously variable transmissions and hybrid-electric systems to modulate auxiliaries (such as air-conditioning and power steering) and reduce idling. Significant reductions in aerodynamic drag are also possible. Reductions in fuel consumption of 10–20 percent in heavy-and medium-duty vehicles appear feasible over the next decade or so.

7

As noted in Chapters 1 and 2, the Obama administration recently announced new policies that will accelerate the implementation of these fuel economy standards.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

Rail is about 10 times more energy-efficient than trucking, so shifting freight from trucks to rail can offer considerable energy savings.

  • Air transportation. The latest generation of airliners offers a 15–20 percent improvement in fuel efficiency.8 The newer airplanes, however, are likely to do little more than offset the additional fuel consumption caused by projected growth in air travel over the next several decades.

  • Long-term system-level improvements. Examples of system-level innovations that could substantially improve efficiency include the utilization of intelligent transportation systems to manage traffic flow; better land-use management; and greater application of information technology in place of commuting and long-distance business travel.

Industrial Sector

Estimates from independent studies using different approaches agree that the potential for cost-effective reduction in energy use by industry range from 14 to 22 percent—about 4.9 to 7.7 quads—by 2020, compared with current EIA reference case projections. Most of the gains will occur in energy-intensive industries, notably chemicals and petroleum, pulp and paper, iron and steel, and cement.9 Growth in the energy-efficient option of combined heat and power production is also likely to be significant. Beyond 2020, new technologies such as novel heat and power sources, new products and processes, and advances in recycling could bring about even greater gains in energy efficiency. Important progress might also come from adapting new technology (such as fuel cells for combined heat and power generation) and adopting alternative methods of operation (e.g., “on-demand” manufacturing).

  • Chemicals and petroleum. Technologies for improving energy efficiency include high-temperature reactors, corrosion-resistant metal- and ceramic-lined reactors, and sophisticated process controls. Cost-effective improvements in efficiency of 10–20 percent in petroleum refining by 2020 are possible.

8

Increases in passenger airliner efficiency will also benefit air freight transport.

9

Further details on the potential improvements in these industries can be found in Chapter 4 in Part 2 of this report and in the report of the America’s Energy Future Panel on Energy Efficiency Technologies (NAS-NAE-NRC, 2009c).

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
  • Pulp and paper. The industry could use more waste heat for drying, advanced water-removal and filtration technologies, high-efficiency pulping processes, and modernized lime kilns. Estimates of cost-effective gains in energy efficiency by 2020 range from 16 to 26 percent.

  • Iron and steel. Promising advances in technology that could be available by 2020 involve electric-arc furnace (EAF) melting, blast-furnace slag-heat recovery, integration of refining functions, and heat capture from EAF waste gas. The American Iron and Steel Institute recently announced a goal of using 40 percent less energy for iron and steel production by 2025 compared with 2003.

  • Cement. Major energy savings would require significant upgrades to an advanced dry-kiln process. Efficiency could also be enhanced with advanced control systems, combustion improvements, indirect firing, and optimization of certain components. A combination of these changes could yield a reduction in energy use of about 10 percent. In addition, changing the chemistry of cement to decrease the need for calcination could result in reduced energy use of another 10–20 percent. Advanced technologies for yielding further improvements are under development. Overall savings of 20 percent are possible by 2020.

A set of crosscutting technologies exists that could improve energy efficiency in a wide range of industrial applications. This includes the expansion of combined heat and power systems; separation processes based on membranes and other porous materials; advanced materials that resist corrosion, degradation, and deformation at high temperatures; controls and automation; steam- and process-heating technologies that improve quality and reduce waste; high-efficiency fabrication processes that improve yields and reduce waste; remanufacturing of products for resale; and sensor systems that reduce waste by improving control.

Barriers to Deployment and Drivers of Efficiency

Numerous barriers impede deployment of energy efficiency technologies in each of the sectors previously discussed. In the buildings sector, regulatory policies do not usually reward utility investments in energy efficiency; building owners in rental markets and builders are not responsible for paying energy costs and thus lack incentives to make investments that reduce energy use; information about

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

the energy costs of specific appliances and equipment is often not readily available; and access to capital for such investments is limited. Drivers for greater efficiency—that is, for overcoming these barriers—could include rising energy costs, growing environmental awareness, improved and publicized building codes and appliance efficiency standards, and state and local utility programs.

In the transportation sector, barriers that limit energy efficiency include the lack of clear signals about future oil prices (expectations for future prices strongly affect technology and investment decisions) and the lack of sufficient production capability to manufacture energy-efficient vehicles across vehicle platforms.

The barriers to deployment in the industrial sector include the technical risks of adopting a new industrial technology; high investment costs for industrial energy efficiency improvements; intra-firm competition for capital, which may favor improvements in products and processes over energy efficiency; the lack of specialized knowledge about energy efficiency technologies; and unfavorable provisions of the tax code.

These barriers are formidable, and sustained public and private support will be needed to overcome them. Particular attention must be paid to infrastructure, industrial equipment, and other long-lived assets in order to ensure that energy efficiency technologies and systems are put into place when these assets are constructed or renewed.

Meanwhile, there are several drivers for greater efficiency. They include expected increases in energy prices and concern about availability of fuels and electricity; more stringent air-quality standards, which raise the prices of pollution allowances; demand charges and demand-response incentives; collateral benefits such as higher product quality and productivity; and corporate sustainability initiatives.

In general, substantial energy savings in all sectors will be realized only if efficient technologies and practices achieve wide use. Experience demonstrates that these barriers can be overcome with the aid of well-designed policies. Many policy initiatives have been effective, including efficiency standards (vehicle and appliance) combined with U.S. Department of Energy R&D on efficient equipment; promotion of combined heat and power, largely through the Public Utilities Regulatory and Policy Act of 1978; the ENERGY STAR® product-labeling program; building-energy codes; and utility- and state-sponsored end-use efficiency programs. These initiatives have already resulted in a nearly 13-quad-per-year reduction in primary energy use.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

ALTERNATIVE TRANSPORTATION FUELS

The U.S. transportation sector consumed about 14 million barrels of oil per day in 2007, 9 million of which was used in light-duty vehicles. Total U.S. liquid fuels consumption in 2007 was about 21 million barrels per day, about 12 million of which was imported. The nation could reduce its dependence on imported oil by producing alternative liquid transportation fuels from domestically available resources to replace gasoline and diesel, and thereby increase energy security and reduce greenhouse gas emissions.

Two abundant domestic resources with such potential are biomass and coal. The United States has at least 20 years’ worth of coal reserves in active mines and probably sufficient resources to meet the nation’s needs for well over 100 years at current rates of consumption. Biomass can be produced continuously over the long term if sustainably managed, but the amount that can be produced at any given time is limited by the natural resources required to support biomass production. However, a robust set of conversion technologies needs to be developed or demonstrated and brought to commercial readiness to enable those resources to be converted to suitable liquid transportation fuels.

Biomass Supply

Biomass for fuels must be produced sustainably to avoid excessive burdens on the ecosystems that support its growth. Because corn grain is often used for food, feed, and fiber production, and also because corn grain requires large amounts of fertilizer, the committee considers corn grain ethanol to be a transition fuel to cellulosic biofuels or other biomass-based liquid hydrocarbon fuels (for example, biobutanol and algal biodiesel). About 365 million dry tonnes (400 million dry tons) per year of cellulosic biomass—dedicated energy crops, agricultural and forestry residues, and municipal solid wastes—could potentially be produced on a sustainable basis using today’s technology and agricultural practices, and with minimal impact on U.S. food, feed, and fiber production or the environment. By 2020, that amount could reach 500 million dry tonnes (550 million dry tons) annually. A key assumption behind these estimates is that dedicated fuel crops would be grown on idle agricultural land in the Conservation Reserve Program. The size of the facilities for converting biomass to fuel will likely be limited by the supply of biomass available from the surrounding regions.

Producers will likely need incentives to grow biofeedstocks that not only do not compete with other crop production but also avoid land-use practices

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

that cause significant net greenhouse gas emissions. Appropriate incentives can encourage lignocellulosic biomass production in particular. To ensure a sustainable biomass supply overall, a systematic assessment of the resource base—which addresses environmental, public, and private concerns simultaneously—is needed.

Conversion Technologies

Two conversion processes can be used to produce liquid fuels from biomass: biochemical conversion and thermochemical conversion.

Biochemical Conversion

Biochemical conversion of starch from grains to ethanol has already been deployed commercially. Grain-based ethanol was important for stimulating public awareness and initiating the industrial infrastructure, but cellulosic ethanol and other advanced cellulosic biofuels have much greater potential to reduce U.S. oil use and CO2 emissions and have minimal impact on the food supply.

Processes for biochemical conversion of cellulosic biomass into ethanol are in the early stages of commercial development. But over the next decade, improvements in cellulosic ethanol technology are expected to come from evolutionary developments gained from commercial experience and economies of scale. Incremental improvements of biochemical conversion technologies can be expected to reduce nonfeedstock costs by about 25 percent by 2020 and about 40 percent by 2035. In terms of transport and distribution, however, an expanded infrastructure will be required because ethanol cannot be transported in pipelines used for petroleum transport.

Studies have to be conducted to identify the infrastructure that will be needed to accommodate increasing volumes of ethanol and to identify and address the challenges of distributing and integrating these volumes into the fuel system. Also, research on biochemical conversion technologies that convert biomass to fuels more compatible with the current distribution infrastructure could be developed over the next 10–15 years.

If all the necessary conversion and distribution infrastructure were in place, 500 million dry tonnes of biomass could be used to produce up to 30 billion gallons of gasoline-equivalent fuels per year (or 2 million barrels per day [bbl/d]). However, potential fuel supply does not translate to amount of actual supply. When the production of corn grain ethanol was commercialized, U.S. production capacity grew by 25 percent each year over a 6-year period. Assuming that the

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

rate of building cellulosic ethanol plants would exceed that of building corn grain ethanol plants by 100 percent, up to 0.5 million bbl/d of gasoline-equivalent cellulosic ethanol (1 barrel of oil produces about 0.85 barrel of gasoline equivalent) could be added to the fuels portfolio by 2020. By 2035, up to 1.7 million bbl/d of gasoline equivalent could be produced in this manner, resulting in about a 20 percent reduction in oil used for LDVs at current consumption levels.

Thermochemical Conversion

Without geologic CO2 storage, technologies for the indirect liquefaction of coal to transportation fuels could be commercially deployable today, but life-cycle greenhouse gas emissions would be more than twice the CO2 emissions of petroleum-based fuels. Requiring geologic CO2 storage with these processes would have a relatively small impact on engineering costs and efficiency. However, the viability of geologic CO2 storage has yet to be adequately demonstrated on a large scale in the United States, and unanticipated costs could occur. Although enhanced oil recovery could present an opportunity for early demonstrations of carbon capture and storage (CCS), that storage would be small compared with the large amounts of CO2 that would be captured if coal-to-liquid fuels production became widely deployed, potentially in the gigatonne-per-year range.

Liquid fuels produced from thermochemical plants that use only biomass feedstock are more costly than fuels produced from coal, but biomass-derived fuels can have life-cycle CO2 emissions that are near zero without geologic CO2 storage or highly negative emissions with geologic CO2 storage. To make such fuels competitive, the economic incentive for reducing CO2 emissions has to be sufficiently high.

When biomass and coal are co-fed in thermochemical conversion to produce liquid fuels, the process allows a larger scale of operation and lower capital costs per unit of capacity than would be possible with biomass alone. If 500 million dry tonnes of biomass were combined with coal (60 percent coal and 40 percent biomass on an energy basis), production of 60 billion gallons of gasoline-equivalent fuels per year (4 million bbl/d) would be technically feasible. That amount of fuel represents about 45 percent of the current volume (140 billion gal/yr or 9 million bbl/d) of liquid fuel used annually in the United States for LDVs. Moreover, when biomass and coal are co-fed, the overall life-cycle CO2 emissions are reduced because the CO2 emissions from coal are countered by the CO2 uptake by biomass during its growth. Combined coal-and-biomass-to-liquid fuels without geologic

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

CO2 storage have life-cycle CO2 emissions similar to those of gasoline; with geologic CO2 storage, these fuels have near-zero life-cycle CO2 emissions.

A program to aggressively support first-mover commercial coal-to-liquid and coal-and-biomass-to-liquid fuel production plants with integrated geologic CO2 storage would have to be undertaken immediately if the United States were to produce fuels with greenhouse gas emissions similar to or less than petroleum-based fuels to address energy security in the near term.

Whether thermochemical conversion involves coal alone or coal and biomass combined, the viability of CO2 geologic storage is critical to its commercial implementation. This means that large-scale demonstrations of and the establishment of regulatory procedures for CO2 geologic storage would have to be aggressively pursued in the next few years if thermochemical conversion plants integrated with CCS are to be ready for commercial deployment in 2020 or sooner. If such demonstrations are initiated immediately, and geologic CO2 storage is proven viable and safe by 2015, the first commercial plants could be operational in 2020.

Because plants for the conversion of combined coal and biomass into liquids are much smaller than those that convert coal alone, and because they will probably have to be sited in regions that are close to coal and biomass supplies, build-out rates will be lower than for the cellulosic plants discussed above. The committee estimates that at a 20 percent growth rate until 2035, 2.5 million barrels per day of gasoline equivalent could be produced in combined coal and biomass plants. This would consume about 270 million dry tonnes (300 million dry tons) of biomass per year—thus tapping less than the total projected biomass availability—and about 225 million tonnes of coal.

Given the vast coal resource in the United States, the actual supply of such fuel will be limited by its market penetration rather than feedstock availability. At a build rate of two to three plants per year, in 20 years up to 3 million bbl/d of gasoline equivalent could be produced from about 525 million tonnes of coal each year. However, all costs and social and environmental impacts of the associated level of coal production—an increase of about 50 percent—would have to be considered. At a build out of three plants starting up per year, five to six plants would be under construction at any one time.

Costs, Barriers, and Deployment

The committee estimated the costs of cellulosic ethanol, coal-to-liquid fuels with or without geologic CO2 storage, and coal-and-biomass-to-liquid fuels with or

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

TABLE 3.1 Estimated Costs of Different Fuel Products With and Without a CO2-Equivalent (CO2-eq) Price of $50 per Tonne

Fuel Product

Cost Without CO2-eq Price ($/bbl gasoline equivalent)

Cost With a CO2-eq Price of $50 per Tonne ($/bbl gasoline equivalent)

Gasoline at crude price of $60/bbl

75

95

Gasoline at crude price of $100/bbl

115

135

Cellulosic ethanol

115

110

Biomass-to-liquids without CCS

140

130

Biomass-to-liquids with CCS

150

115

Coal-to-liquids without CCS

65

120

Coal-to-liquids with CCS

70

90

Coal-and-biomass-to-liquids without CCS

95

120

Coal-and-biomass-to-liquids with CCS

110

100

Note: The numbers in this table are rounded to the nearest $5. Estimated costs of fuel products for coal-to-liquids conversion represent the mean costs of products from Fischer-Tropsch and methanol-to-gasoline conversion processes.

without geologic CO2 storage using a consistent set of assumptions (shown in Table 3.A.1 at the end of this chapter). Although those estimates do not represent predictions of future prices, they allow comparisons of fuel costs relative to each other. As shown in Table 3.1, coal-to-liquid fuels with CCS can be produced at a cost of $70/bbl of gasoline equivalent and thus are competitive with $75/bbl gasoline. In contrast, the costs of fuels produced from biomass without geologic CO2 storage are $115/bbl of gasoline equivalent for cellulosic ethanol produced by biochemical conversion and $140/bbl for biomass-to-liquid fuels produced by thermochemical conversion. The costs of cellulosic ethanol, and coal-and-biomass-to-liquid fuels with CCS, become more attractive if a CO2 price of $50 per tonne is included.

Attaining supplies of 1.7 million bbl/d of biofuels, 2.5 bbl/d of coal-and-biomass-to-liquid fuels, or 3 million bbl/d of coal-to-liquid fuels will require the permitting and construction of tens to hundreds of conversion plants, together with the associated fuel transportation and delivery infrastructure. Given the magnitude of U.S. liquid-fuel consumption (14 million barrels of crude oil per day in the transportation sector in 2007) and the scale of current petroleum imports (about 56 percent of the petroleum used in the United States in 2008 was imported), a business-as-usual approach for deploying these technologies would be

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

insufficient to address the need to develop alternative liquid transportation fuels, particularly because the development and demonstration of technology, the construction of plants, and the implementation of infrastructure require 10–20 years per cycle. In addition, investments in alternative fuels have to be protected against crude oil price fluctuations.

Because geologic CO2 storage is key to producing liquid fuels from coal with life-cycle greenhouse gas emissions comparable to those of gasoline, commercial demonstrations of coal-to-liquid and coal-and-biomass-to-liquid fuel technologies integrated with geologic CO2 storage would have to proceed immediately if the goal is to deploy commercial plants by 2020. Moreover, detailed scenarios for market-penetration rates of biofuels and coal-to-liquid fuels would have to be developed to clarify the hurdles preventing full feedstock utilization and to establish the enduring policies required to overcome them. Further, current government and industry programs would have to be evaluated to determine whether emerging biomass- and coal-conversion technologies could further reduce U.S. oil consumption and CO2 emissions over the next decade.

Other Transportation Fuels

Technologies for producing transportation fuels from natural gas—such as gas-to-liquid diesel, dimethyl ether, and methanol—have been deployed or will be ready for deployment by 2020. But only if large supplies of natural gas were available at acceptable costs—for example, from natural gas hydrates—would the United States be likely to use natural gas as the feedstock for transportation fuel production.

Hydrogen has considerable potential, as discussed in Transitions to Alternative Transportation Technologies—A Focus on Hydrogen (NRC, 2008) and The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs (NRC, 2004). Hydrogen fuel-cell vehicles could yield large and sustained reductions in U.S. oil consumption and greenhouse gas emissions, but it will take several decades to realize these potential long-term benefits.

RENEWABLE ENERGY

The level of electricity generation from renewable resources has risen significantly over the past 20 years. Nonhydroelectric renewable sources, however,

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

still provide a very small proportion of the U.S. total (about 2.5 percent of all electricity generated). In the 2008 reference-case estimates of the Energy Information Administration (EIA, 2008), the contribution of nonhydroelectric renewables was projected to be about 7 percent of total electricity generation by 2030. But the AEF Committee found that with a sustained effort and accelerated deployment, nonhydroelectric renewables could collectively provide 10 percent of the nation’s electricity generation by 2020 and 20 percent or more by 2035. With current hydropower included, more than 25 percent of electricity generation could come from renewables by 2035.

Generation Capacity and Resource Base

Renewables currently represent a small fraction of total electricity generation. According to the EIA, conventional hydroelectric power is the largest source of renewable electricity in the United States, generating about 6 percent (almost 250,000 GWh out of a total 4 million GWh) of electricity produced by the electric power sector in 2007.10

The largest growth rates in renewable resources for electricity generation are currently in wind power and solar power. Though wind power in 2007 represented less than 1 percent of total electricity generation, wind electricity grew at a 15.5 percent compounded annual growth rate over the 1990–2007 time period and at a 25.6 percent rate between 1997 and 2007.

In 2007, wind power supplied over 34,000 GWh, almost 8,000 GWh more than in the year before. An additional 8,400 MW of capacity was added in 2008, representing an additional yearly generation of 25,000 GWh (assuming a 35 percent capacity factor). Total wind power capacity at the end of 2008 was approximately 25,000 MW. However, the overall economic downturn at that time caused financing for new wind power projects and orders for turbine components to slow, and layoffs in the wind turbine-manufacturing sector began. Thus, 2009 recently looked to be considerably smaller in terms of new capacity than 2008. However, recent data reveal that 2.8 GW of new wind power generation capacity was installed in the first quarter of 2009. Over the long term, the impacts of state renewable portfolio standards and the federal production tax credit will continue to spur installation of wind power capacity.

10

The electric power sector includes electricity utilities, independent power producers, and large commercial and industrial generators of electricity.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

Central-utility electricity generation from concentrating solar power (CSP) and photovoltaics (PV) combined to supply 600 GWh in 2007, 0.01 percent of the total electricity generation for the United States. This level has been approximately constant since 1990. However, it does not account for the increase in residential and other small-PV installations, the sector that has displayed the largest growth rate for solar electricity. Solar PV in the United States has grown at a compounded annual growth rate of more than 40 percent from 2000 to 2005, with an installed generation capacity of almost 480 MW that, assuming a 15 percent capacity factor, produces approximately 630 GWh.

The United States has sufficient renewable-energy resources to significantly expand the amount of electricity generated from them. Solar in particular, followed by wind, offers the greatest potential among the domestic renewable resources. Solar energy derived from sunlight reaching Earth’s surface could produce many times the current and projected future electricity consumption. And the total estimated electrical energy derivable from the continental U.S. wind resource in Class 3 and higher wind-speed areas is 11 million GWh per year—far greater than the estimated 2007 electricity generation of about 4 million GWh. But these numbers, which represent the total resource base, exceed what can be developed at an acceptable cost. Moreover, the resource bases for wind and solar energy are not evenly distributed, spatially as well as temporally, and they are more diffuse compared to fossil and nuclear energy sources. Finally, though the size of the resource base is impressive, there are many technological, economic, and deployment-related constraints on using sources of renewable energy on a large scale.

Technologies

Several renewable-energy technologies are available for deployment or are under active development.

  • Wind. Turbine technology has advanced substantially in recent years. Future development will be evolutionary and will focus on improved efficiency and lower production costs. Major objectives are to increase the capacity factors and improve integration into the electric grid.

  • Solar photovoltaics. The two major types of PV are silicon flat plates and thin films on various substrates. The former are more mature, with primary development objectives being higher efficiency and lower production costs. Thin films have the potential for substantial cost advan-

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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tages and can use a wider array of materials, but they are less well developed.

  • Concentrating solar power. The three main options are parabolic troughs, power towers, and dish-Stirling engine systems. The first two are now the lowest-cost utility-scale solar electricity technology for regions of high solar flux. Design improvements and advances in high-temperature and optical materials are the major paths to cost reduction.

  • Geothermal. Conventional geothermal, which relies on hydrothermal sources within 3 km of the surface to drive a heat engine, is a fairly mature technology, but it has a rather limited resource base. A study of the western United States found that 13 GW of electrical power capacity exists in identified geothermal resources in this region. Greatly expanding that base will require enhanced geothermal systems to mine heat down to a depth of 10 km. Such systems, however, face many technical challenges and are not now in operation.

  • Hydropower. Conventional hydropower is the least expensive source of electricity. The technology is well developed, and objectives are to increase efficiency and reduce impacts on associated water bodies, as efforts to expand are likely to be limited by environmental concerns. Hydrokinetic technologies produce electricity using currents, tides, and ocean waves; many designs and demonstration plants exist, but there are no commercial deployments.

  • Biopower. There are three main sources: wood/plant waste, municipal solid waste/landfill gas, and other (e.g., agriculture waste, used tires). A variety of technologies may be used to produce electricity, including current technologies based on the steam-Rankine cycle and future applications involving gasification combined-cycle plants. The use of biomass for biopower competes with its use for alternative liquid fuels.

Deployment Potential

Between now and 2020, there are no technological constraints to accelerated deployment of the major renewable resources with existing technologies. However, there are other kinds of barriers. The main ones currently include the cost-competitiveness of existing technologies relative to most other sources of electricity (with no prices assigned to carbon emissions or other externalities); markets not sufficiently shaped so as to allow the existing technologies to reach full scale

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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and thus realize economies of scale; the lack of sufficient transmission capacity to move distant resources to demand centers; and the absence of sustained policies. Also, continued research to reduce costs and increase efficiencies is needed.

A reasonable target is that 20 percent of all electricity be supplied by renewable resources—including hydropower—by 2020. This would mean that approximately 10 percent of electricity generation would be from nonhydropower renewables. Continued accelerated deployment and sustained policies could permit nonhydropower renewables to reach 20 percent of total U.S. electricity generation by 2035.

The most in-depth scenario for increased renewables penetration into the electricity sector is the Department of Energy’s (DOE’s) 20 percent wind-penetration scenario (DOE, 2008; see Chapter 6 in Part 2 of this report for details), which includes an assessment of wind resources and available technologies; manufacturing, materials, and labor requirements; environmental impacts and siting issues; transmission and system integration; and market requirements. The scenario requires that installations reach an annual rate of about 16,000 MW by 2018, almost double the current annual deployment in the United States but less than the current global deployment of 27,000 MW. The committee considered this projected installation rate together with the reliability of wind facilities, and it concluded that this level of wind power deployment would be achievable with accelerated deployment as defined in Chapter 2.

Another accelerated deployment scenario for reaching 20 percent non-hydropower renewables is reliance on multiple renewable sources. Obtaining 20 percent of electricity generation solely from wind power would be a challenge because the 20 percent refers to an annual average, whereas wind power is intermittent. Balancing wind with multiple renewable resources—including solar, which does not normally peak when wind does, and baseload power from geothermal and biomass—could mitigate the temporal variability in generation. Reaching the goal of 20 percent nonhydropower renewables by 2035 could be achieved by adding 9.5 GW per year of wind power and a total of 70 GW of solar PV and 13 GW each of geothermal and biomass. Using multiple renewable resources to reach this level would take advantage of the geographical variability in the resource base.

Relying on multiple renewable resources would not eliminate the need to expand transmission capacity or make other improvements in the electricity infrastructure to enable the integration of renewables, nor would it reduce the magnitude of costs. However, such an approach to reaching 20 percent nonhydropower

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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renewables could offer other attributes, such as providing baseload generation and combining different intermittent renewables to reduce the temporal variability in generation. The installation rate for wind under this option is approximately the current rate of deployment, and the installation rates of the other renewables technologies are consistent with the accelerated-deployment definition.

Greatly expanding electricity generation from renewable sources will require changes in the present electric system because of the intermittency, spatial distribution, and scalability of renewable resources. Integrating an additional 20 percent of renewable electricity, whether it comes from wind, solar, or some combination of renewable sources, requires expansion of the transmission system (to enable the power to reach demand centers and regional electricity markets) as well as large increases over current levels in manufacturing, employment, and investment. Further, although electricity storage is not needed, integrating intermittent renewables up to the 20 percent level would also require improvements in the electricity distribution system and fast-responding backup electricity generation.

Integrating renewables at a much greater level so that they account, say, for more than 50 percent of U.S. electricity generation would require scientific advances and major changes in electricity production and use. It would also necessitate the deployment of electricity storage technologies to offset renewables’ intermittency. More details on deployment are available in Chapter 6 in Part 2 of this report, and an extensive discussion is presented in the panel report Electricity from Renewable Resources: Status, Prospects, and Impediments (NAS-NAE-NRC, 2009a).

Cost

Given the experience with renewables over the past 20–30 years, it is clear that their economics have generally not been attractive compared to most competing sources of electricity. The most favorable technology out to 2020 is onshore wind; with a federal production tax credit for renewables, or with high natural gas prices, wind is competitive with electricity generation from natural gas. Solar PV presents a different economic picture. It is much more expensive than current sources of electricity generated by centralized generating facilities, but PV installed for residential and commercial consumers provides electricity directly to the consumer.

Thus, the economics for a so-called distributed renewable generation source (termed a “distributed” source because the electricity generation occurs on the

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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distribution side of the electricity system) depends on costs being competitive with retail electricity prices. Many residential and commercial systems are unlikely to have high capacity factors, given that such systems would be installed on roofs that are not currently designed to maximize sun exposure. Additionally, the full electricity distribution system and centralized power sources are still required for periods when electricity generation from distributed sources is not available. However, if electricity prices continue to increase and more utilities adopt time-of-day pricing (which charges the highest rate during the middle of the day), solar PV could become more widely competitive.

Nearly all of the costs associated with renewable energy are in the manufacture and installation of the equipment; fuel costs during operation—except for biomass—are zero. Economies of scale occur primarily during equipment manufacturing for nonhydropower renewable technologies and much less so with respect to plant size. The plants, however, can be built quickly and incrementally compared to conventional coal and nuclear electricity plants, allowing utilities and developers to begin recouping costs much more quickly. Thus, technological innovations will play a major role in how costs for renewables evolve in the future.

One estimate of the costs of obtaining 20 percent of electricity from renewables is provided by the DOE 20 percent wind energy study (DOE, 2008) referred to earlier and discussed in greater detail in Chapter 6 of this report and in NAS-NAE-NRC (2009a). Though this is a single study on the costs, it was developed with contributions from a wide array of stakeholders in the electric utility industry, wind power developers, engineering consultants, and environmental organizations. The study, which was externally peer reviewed (as mandated by the U.S. Office of Management and Budget), considered the direct costs both of installing the generating capacity and of integrating this power into the electricity system. Overall, it projects that increases in wind power generation costs (capital, operation, and maintenance expenses) in net present value would be approximately $300 billion—covering the installation of approximately 300 GW of new wind power capacity, of which about 250 GW would be installed onshore and 50 GW installed offshore. The total number of wind turbines required is estimated to be about 100,000. Estimates of the transmission costs range widely, from the $23 billion estimated within the DOE (2008) study to American Electric Power’s $60 billion estimate (AEP, 2007) to the recent estimate of $80 billion by the Eastern Wind Integration and Transmission Study/Joint Coordinated System Planning Study (JCSP, 2009) for integrating 20 percent in the eastern part of the United States.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Barriers to Deployment

The major barrier to greater deployment of renewable electricity sources has been their high costs. And recent capacity limitations—in personnel, materials, and manufacturing—have raised the costs of PV and wind power projects even higher. Moreover, the variability of renewable energy makes integration into the electric power system more difficult as deployment grows. Integrating renewables at levels approaching 20 percent of all electricity generation requires not only greater transmission capacity but also the increased installation of fast-responding generation to provide electricity when renewables are not available. Expansion of the transmission system, improving its flexibility through advanced control technologies, and co-siting with other renewable or conventional generation can help this integration. Expansion of the transmission system also gives providers of renewable electricity access to regional wholesale electricity markets, thus improving its marketability. However, at a high level of renewable technology deployment, land-use and other local impacts would become quite important. In the past, such impacts have provoked local opposition to the siting of renewable electricity-generating facilities and associated transmissions lines, and opposition is likely to occur in the future. This represents an additional potential barrier.

In order to facilitate investment in the face of high costs and, as a result, allow renewable electricity generation to meet its potential, consistent and long-term policies are essential. As is shown in Chapter 6, the on-and-off nature of the federal production tax credit has direct impacts, positive and negative, respectively, on the installation of new renewable-energy generation facilities. The 20-percent-by-2030 target can be reached, but substantial increases in manufacturing capacity, employment, investment, and installation will be needed.

Impacts

Renewable-energy sources have significantly smaller lifetime emissions of CO2 and criteria pollutants per kilowatt-hour than does fossil energy, although renewables’ emissions are about the same as those of nuclear power (see Figure 2.15). Renewable electricity technologies (except biopower, some geothermal, and high-temperature solar technologies) also use significantly less water than do nuclear and gas- or coal-fired electricity technologies. On the other hand, land-use requirements are substantially higher for renewables but could be mitigated to some degree by multiuse features that allow some of the land to be devoted, say, to agricultural activities. However, land-use and related issues associated with renew-

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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ables deployment, such as noise and aesthetics, often fall to local jurisdictions for approvals, and the resulting procedures can be controversial.

FOSSIL-FUEL ENERGY

Fossil fuels—petroleum, natural gas, and coal—have been the dominant energy source in the United States for decades past and will continue to be a major source for decades to come. At present, they collectively supply about 85 percent of the nation’s primary energy (see Figure 1.2).

Resource Base for Petroleum and Natural Gas

Worldwide, the amount of petroleum and natural gas that could ultimately be produced is very large, but most of this resource is located outside the United States. In 2008, the United States imported about 56 percent of the petroleum it consumed, a drop from the peak of 60 percent in 2006. This drop can be attributed mainly to the growth in production of a half million barrels per day from the deepwater Gulf of Mexico, illustrating that domestic production depends on the ability to develop discovered resources to make up for the decline from existing fields.

Maintaining domestic petroleum production at current levels over the long run will be very challenging, however. Production of petroleum from U.S. unconventional resources (primarily oil shales), which is not likely to occur in significant volumes before 2020, will be more expensive than that from conventional oil sources and may have more negative environmental impacts. In any case, because U.S. crude oil reserves and production are 2 percent and 8 percent, respectively, of world levels, the actions of other countries could have greater effects than those of the United States on world oil production. By contrast, because U.S. petroleum consumption is 24 percent of world consumption, changes in U.S. demand are a significant factor in determining world demand. Growing demand in other countries could, however, offset any downward price pressures resulting from reduced U.S. demand.

Natural gas is the cleanest of the fossil fuels and has the lowest greenhouse gas emissions per unit of energy (emitting about half of the CO2 of coal when burned for electricity generation). While the U.S. natural gas resource base is only about 9 percent of the known world total, some 86 percent of the natural gas con-

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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sumed in the United States is produced domestically, with much of the remainder coming from Canada. In recent years, natural gas production from conventional resources has continued to decline, but production from unconventional resources such as coal beds, tight gas sands (rocks through which flow is very slow), and particularly from natural gas shales has increased. Higher natural gas prices in 2007 and 2008 led to expanded drilling in tight gas sands and gas shales, which increased total U.S. gas production by about 9 percent in 2008 after a decade of its being roughly constant.

If the increase in domestic natural gas production continues and is sustained over long periods, some portion of potential growth in domestic demand for natural gas could be accommodated. If, on the other hand, growth in U.S. natural gas production is limited by a combination of production declines from existing resources and modest growth from new resources, the United States may have to import liquefied natural gas (LNG) at prices subject to international market fluctuations. Which of these futures occurs will depend on some combination of linked factors that include the magnitude of demand growth, production technology, resource availability, and price.

About 12 percent of U.S. petroleum resources and 20 percent of U.S. natural gas resources are believed to lie in areas that, for a variety of policy reasons, are currently off-limits. These estimates are highly uncertain, however, and the technologies for exploration and production (which might permit more of these activities elsewhere) have advanced considerably since the estimates were made. Further, estimates of production from the restricted areas are moderate—for petroleum, they are on the order of several hundred thousand barrels per day by the mid-2020s (compared to current domestic production of 5.1 million barrels per day). The contribution to gas production from these areas could be about 1.5 trillion cubic feet per year in the 2020–2030 period, compared to current domestic production of 19.3 trillion cubic feet per year.

The issue for policy makers is to balance the energy security and economic benefits of developing these currently off-limits resources against the potentially negative environmental impacts. Most observers believe that the effect of incremental U.S. oil production from restricted areas on world oil price would be small, but because natural gas markets are more regional, they might respond differently; increased natural gas production from restricted areas could potentially offset the need for LNG imports.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Resource Base for Coal

U.S. recoverable reserves of coal are well over 200 times the current annual production of 1 billion tonnes, and additional identified resources are much larger. Thus the coal resource base is unlikely to constrain coal use for many decades to come. Rather, environmental, economic, geographic, geologic, and legal issues will likely be the primary constraints. Of particular concern regarding the greenhouse gas problem is that burning coal to generate electricity produces about 1 tonne of CO2 equivalent per megawatt-hour, about twice the amount produced by natural gas. If CCS technologies were successfully developed, it is possible that future coal consumption could remain at current levels or increase (as a result, for example, of demand from a new coal-to-liquid-fuels industry), even if policies were put in place to constrain greenhouse gas emissions. On the other hand, if practical CCS technologies fail to materialize, coal use would be severely curtailed in a carbon-constrained world.

Fossil Energy Use for Electric Power Generation

In 2006, about 52 percent of U.S. electricity was generated from coal and 16 percent from natural gas. Many of these plants could operate for 60 years or more, and there is great reluctance on the part of plant operators to shorten their period of operation, given that new plants would require large amounts of capital and new permitting. Yet significant mitigation of U.S. greenhouse gas emissions will require dramatic reductions in the emissions from these plants. Alternatives include (1) retiring the plant; (2) raising the generating efficiency, thereby reducing greenhouse gas emissions per unit of electricity produced; (3) retrofitting with CO2 “post-combustion” capture capability; or (4) repowering/rebuilding at the site, resulting in an entirely new or mostly new unit.

The two principal technologies for future coal-burning power plants are pulverized coal (PC) and integrated gasification combined cycle (IGCC), though the possibility of coal combustion with pure oxygen (oxyfuel) instead of air would simplify subsequent CO2 capture. This option is also being investigated and may be competitive in the future. PC units now produce nearly all of the coal-based electric power in the United States. PC plants with 40–44 percent efficiency11

11

Potential PC efficiencies as high as 48 percent have been estimated in the literature. This would require steam pressures and temperatures of 5000 psi and 1400°F main steam, 1400°F reheat, whereas the most robust current ultrasupercritical plants operate at pressures of around

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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(ultrasupercritical plants) could be achieved in the 2020–2035 period, as compared with a typical efficiency of 34–38 percent for older subcritical and supercritical steam plants. Replacing a 37 percent efficient plant with a 42 percent efficient plant, for example, would reduce CO2-eq emissions and fuel consumption per kilowatt-hour of output by about 12 percent. To reduce emissions more dramatically in PC plants, CCS would be required.

Retrofitting for 90 percent CO2 capture at existing PC plants with technology available today would require capital expenditures approaching those of the original plant itself; and 20–40 percent of the plant’s energy would be diverted for separation, compression, and transmission of the CO2, thereby significantly reducing thermal efficiency and increasing the levelized cost of electricity. In addition, retrofits face the added problems of site constraints and steam-management limitations, rendering the feasibility of installing CO2 capture retrofits in existing plants highly plant dependent. Also, the optimum percentage of CO2 capture in a retrofitted coal plant could be lower than that of a new coal plant. In any case, further engineering analyses to establish the shape of these cost-versus-percent-capture curves would aid policy analysis considerably.

Electricity demand and CO2 price will have a strong effect on the rate of introduction of new coal plants. If the CO2 price is zero and electricity demand stays relatively flat (as a result of increasing end-use efficiency, for instance), hardly any of the existing PC plants will be retired or modified and very few new plants will be built.

New natural gas combined cycle (NGCC) plants compete with new coal plants. Favoring natural gas plants are their lower capital costs and shorter construction times, but of primary importance is the price of natural gas. For example, in the committee’s calculations, at a price of $6 per million British thermal units (Btu), NGCC plants have the lowest levelized cost of electricity (LCOE) of any baseload generating option, while at $16/million Btu they have the highest LCOE (see Figure 2.10 in Chapter 2). (Over the course of this study, U.S. natural gas prices have risen above $13/million Btu and fallen to below $4/million Btu.) Future rules governing greenhouse gas emissions and the pace at which CCS technologies can be commercialized will also affect the coal-gas competition.

If domestic natural gas (e.g., from shale gas deposits) proves plentiful, and

4640 psi and temperatures of 1112–1130°F. Thus, achieving this potential efficiency would require major R&D breakthroughs. In addition, operating plants often do not realize their full design efficiencies.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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confidence grows that prices will remain in the range of $7–9/million Btu or lower for decades, as some commentators think may happen,12 then NGCC plants with CCS could compete economically with PC and IGCC plants with CCS. In such a world, the cheapest way to gain large CO2 reductions would be to use NGCC with CCS to replace existing and future coal units over time.

Although a large shift in this direction would increase natural gas demand significantly and put upward pressure on prices, the committee still considers it wise to plan for a broad range of future natural gas prices and domestic availabilities. Consequently, the committee envisions some CCS projects involving NGCC technology being part of the recommended 10 GW of CCS demonstrations (see Chapter 7 in Part 2). The committee did not make a judgment about the mix of NGCC, PC, and IGCC plants with CCS that would be appropriate.

The committee compared the costs of new PC and IGCC plants, with and without CCS, built with components available today and with various prices for CO2 emissions. (It also considered as feedstocks not only coal but also natural gas, biomass, and biomass and coal in combination.) If no price is put on CO2 emissions, PC without CCS is the cheapest option. However, the extra cost to add CCS to IGCC is less than the extra cost to add CCS to PC, because in IGCC, CO2 is captured at high pressure13 after gasification but before power generation (precombustion capture). For bituminous coal—at a price of $50 per tonne of CO2 emitted—IGCC with CCS is the cheapest of the four options, although all have a higher cost than current plants. These cost estimates, and similar estimates for the capture of CO2 from natural gas plants and low-rank coal plants, have significant uncertainties particularly in fuel costs, capital costs for first-of-a-kind plants, and the costs of CO2 capture and storage technologies.

Based on historical experience, and assuming that all goes well in the development and operation of CCS demonstrations from pilot plants to commercial scale, 10 GW of demonstration fossil-fuel CCS plants could be operating by 2020 with a strong policy driver (e.g., a CO2 emissions price of about $100 per tonne or comparably strong regulation), but not a crash program. With similar assumptions, 5 GW per year could be added between 2020 and 2025, and a further 10–20 GW per year from 2025 to 2035, resulting in a total of 135 to 235 GW

12

CERA, “Rising to the Challenge: A Study of North American Gas Supply to 2018,” www.cera.com/aspx/cda/public1/news/pressReleases/pressReleaseDetails.aspx?CID=10179.

13

However, additional compression is still needed before the CO2 can be injected underground.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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of fossil-fuel power with CCS in 2035. Whether any coal plants and natural gas plants without CCS would still be operating in 2035 would depend on the nature of greenhouse gas policies at that time.

Carbon Capture and Storage

CCS technologies have been demonstrated at commercial scale, but no large power plant today captures and stores its CO2. The few large storage projects now under way are all coupled to CO2 capture at nonpower facilities; for example, in one offshore operation in Norway, 50 million standard cubic feet per day of CO2 (1 million tonnes per year) are separated from natural gas before the fuel is inserted into the European grid; the CO2 is injected under the North Sea.

CO2 storage could be implemented in oil and gas reservoirs, deep formations with salt water, and deep coal beds. Specific sites would have to be selected, engineered, and operated with careful attention to safety. In particular, the deep subsurface rock formations that hold the CO2 must allow injection of large total quantities at sufficient rates and have geologic layers that prevent, over centuries to millennia, the upward migration of injected CO2. Current surveys suggest that the available storage within 50 miles of most of the major U.S. sources of CO2 would be more than sufficient to handle all emissions for many decades and that up to 20 percent of current emissions could be stored at estimated costs of $50 per tonne of CO2 or less. However, given the large volumes of CO2 involved, the storage challenges should not be underestimated. At typical densities in the subsurface, a single 1 GW coal-fired plant would need to inject about 300 million standard cubic feet of CO2 per day, or a volume flow equivalent to about 160,000 barrels per day—comparable to the petroleum production from a large oil field.

Too little is known at present to determine which power-generation technologies and which storage options could best produce electricity after 2020 if carbon emissions were constrained. Reliable cost and performance data are needed, both for capture and storage, and they can be obtained only by construction and operation of full-scale demonstration facilities. Such demonstrations could assure vendors, investors, and other private-industry interests that power plants that incorporate advanced technologies, and the associated storage facilities, could be built and operated in accordance with commercial criteria. Because of the variety of coal types and the myriad of technology-conversion options for coal, natural gas, and biomass fuels, a diverse portfolio of demonstrations of CO2 capture technology will actually be required. Similarly, to sort out storage options and

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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gain experience with their costs, risks, environmental impacts, legal liabilities, and regulatory and management issues, it will be necessary to operate a number of large-scale storage projects in a variety of subsurface settings.

The investments in this portfolio of CCS demonstrations will certainly be large, but there is no benefit in waiting to make them. The committee judges that the period between now and 2020 could be sufficient for acquiring the needed information on CCS viability, provided that the deployment of CCS demonstration projects proceeds as rapidly as possible. If these investments are made now, 10 GW of CCS projects could be in place by 2020. If not, the ability to implement CCS will be delayed.

Fossil Energy Use for Transportation

About 95 percent of the energy for transportation comes from crude oil, of which about 56 percent is imported. The transportation sector also generates about one-third of U.S. greenhouse gas emissions, which are difficult to eliminate from moving vehicles. Coal-to-liquid and natural-gas-to-liquid technologies with CCS can produce liquid transportation fuels with no more greenhouse gas emissions than those of crude oil. Other technologies to replace petroleum in the transportation sector are described in the “Energy Efficiency” and “Alternative Transportation Fuels” sections of this chapter.

Impacts and Barriers to Deployment

The widespread use of fossil fuels in the United States creates a substantial array of environmental impacts, most of which (with the notable exception of greenhouse gas impacts) have been addressed in principle by a broad array of laws and regulations over the last few decades. The continual challenge regarding most of these policy instruments is to keep them up-to-date and enforced while increases occur in the consumption of conventional or unconventional fuels.

All of these environmental issues need to be fully considered in assessing the real costs of different energy options. Further, agencies, other stakeholders, and funders concerned with environmental impacts must enhance their readiness for new challenges that are likely to emerge in the future regarding systems that make use of fossil fuels. These new challenges include the capture and storage of CO2; potentially increased use of coal for coal-to-liquid fuel or coal-to-natural-gas production; shale oil and tar sands development; LNG safety; and water use.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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A regulatory structure must be developed during the 2010–2020 period to enable large-scale deployment of the CCS necessary for continued use of fossil fuels. Pertinent issues include CO2 pipeline-transport safety and land use, stability and leakage from underground carbon storage, and public acceptance of such storage.

Increased use of coal will intensify concerns about environmental and safety aspects of extraction as well as about pollutant emissions arising from power generation. Oil shale and tar sands production will also result in extraction issues, along with those pertaining to water availability and CO2 production. Expansion of LNG imports may raise concerns about the potential coastal-area impacts of LNG storage facilities and their vulnerability to terrorist attacks, and the impacts of pipeline-capacity enlargements in some regions may raise concern as well. In general, increased fossil-fuel use for electricity generation will add to power plants’ already substantial requirements for fresh water. In addition, there will be greater impacts on water quality, aquatic life, and surrounding ecosystems. Finally, although technologies exist to achieve high levels of control for most of the conventional pollutants produced in coal-to-liquid or gas-to-liquid fuel plants, performance standards relating to CCS will need to be written during the 2010–2020 period.

NUCLEAR ENERGY

Energy companies in the United States are expressing increased interest in constructing new nuclear power plants. Reasons cited include the need for additional baseload generating capacity; growing concerns about greenhouse gas emissions from fossil-fuel plants; volatility in natural gas prices; and favorable experience with existing nuclear plants, including ongoing improvements in reliability and safety.14 No major R&D is needed for an expansion of U.S. nuclear power through 2020 and, likely, through 2035.

Nonetheless, the high cost of construction of new nuclear plants is a major concern, and the experience with the handful of new plants that could be built before 2020 will be critical to assess the future viability of the nuclear option. If

14

The $18.5 billion in loan guarantees for new nuclear plants arising from the Energy Policy Act of 2005 may also contribute to this interest.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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these plants are not built on time and on budget, or if the electricity produced is not cost competitive, few additional new plants are likely to follow, at least for a while.

Technologies

The nuclear plants now in place in the United States were built with technology developed in the 1960s and 1970s. In the intervening decades, ways to make better use of existing plants have been developed, along with new technologies that improve safety and security, decrease costs, and reduce the amount of generated waste—especially high-level waste. These technological innovations, now available or under development, include the following:

  • Improvements to existing plants. The trend of technical and operational improvements in nuclear technology that has developed over the past few decades is expected to continue. Incremental improvements to the 104 currently operating U.S. nuclear plants have enabled them to produce more power over their operating lifetimes. Modifying existing plants to increase power output, referred to as “uprates,” is considerably less costly than adding new capacity, and additional power uprates are expected in the future. In fact, nearly as much new nuclear capacity could be added in this way before 2020 as could be produced during that period by building new plants. Additionally, most currently operating nuclear power plants have received or are expecting to receive 20-year operating-license extensions, which will allow them to operate for a total of 60 years; discussions have recently commenced about extending licenses an additional 20 years (for a total of 80 years). Also, the periods when plants are off line have been reduced and can be further reduced. Average plant capacity factors have grown from 66 percent in 1990 to 91.8 percent in 2007, primarily through shortened refueling outages and improved maintenance, thereby greatly improving the plants’ economic performance.

  • Evolutionary nuclear plants. New plants constructed before 2020 will be based on modifications of existing plant designs, using technologies that are largely ready for deployment now.

  • Alternative nuclear plants. Alternative designs in two broad categories are being developed or improved: thermal neutron reactor designs (all

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

current U.S. reactors are thermal) and fast neutron reactor designs. Thermal neutron reactor designs include plants that operate at higher temperatures, thereby offering process heat (which could be used, for example, for producing hydrogen) in addition to electricity production. Fast neutron reactor designs include plants intended to destroy undesirable isotopes associated with much of the long-lived radioactive waste burden in used fuel, and, in some cases, to breed additional fuel. These plants could reduce the volume of and the heat emitted by long-lived nuclear waste that must go to a repository for disposal.15 Much R&D will be needed before any of these alternative reactor types can be expected to make significant contributions to the U.S. energy supply.

  • Alternative fuel cycles. The United States currently employs a once-through nuclear fuel cycle in which used fuel is disposed of after removal from the reactor. In contrast, alternative (closed) nuclear fuel cycles involve the reprocessing of used fuel to produce new fuel. In principle, these alternative fuel cycles could extend fuel supplies and reduce the amount of long-lived nuclear waste requiring disposal. The reprocessing technology in common use today, called plutonium and uranium extraction (PUREX), is associated with an increased risk of nuclear weapons proliferation, as well as an increased risk of theft or diversion of nuclear materials,16 because it yields a separated stream of plutonium. A modified version of PUREX that keeps uranium with the plutonium could result in modestly reduced proliferation risks relative to PUREX and could be deployed after 2020. Other alternatives are being investigated, but they are unlikely to be ready for commercial deployment before 2035. R&D is still needed on fuel design, separation processes, fuel fabrication, and fuel qualification, as well as on the associated alternative reactors.

15

For about the first century, the major challenges for managing high-level waste are the heat and radioactivity emitted by short-lived fission products. If a closed fuel cycle is implemented, these fission products will likely need to be removed from the waste and dealt with separately to achieve a significant reduction in the number of repositories needed.

16

The United States is a nuclear weapons state and the primary proliferation risk applies to the use of such technologies in countries that are not nuclear weapons states. There is also concern about the theft of weapons-usable materials from reprocessing, wherever it takes place. The risk of proliferation is a controversial subject, and there are differing points of view about how it should affect technology trajectories within the United States.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
Deployment Potential

As many as five to nine new nuclear plants could be built in the United States by 2020; however, in light of the long lead times expected for construction, the first one is unlikely to be operating before 2015. These new plants will have evolutionary designs that are similar to existing power plants. Combining new power plants with increased capacity obtained by uprating currently operating plants, a 12–20 percent increase in U.S. nuclear capacity is possible by 2020.

After 2020, the potential magnitude of nuclear power’s contribution to the U.S. energy supply is uncertain. The operating licenses of existing plants will begin to expire in 2028, and the plants will have to be shut down if license extensions (to 80-year total operating lifetimes) are not obtained; under these circumstances, about 24 percent of the current U.S. nuclear capacity would be retired by 2035. Because of the long construction times, many companies will need to decide soon whether to replace retiring plants with new nuclear plants. As noted previously, the major barrier to new construction is financial; thus, companies will need to know whether evolutionary plants can be built on budget and on schedule. One important purpose of providing federal loan guarantees is to acquire experience with a few early plants that will guide these decisions.17 This experience will affect the U.S. electricity portfolio up to and after 2035.

The scale of new nuclear deployment after 2020 will depend on the performance of plants built during the next decade. If the first handful of new plants (say, five) to be constructed in the United States meet cost, schedule, and performance targets, many more plants could be deployed after 2020. Construction of as many as three plants per year could take place up to 2025, and as many as five

17

The statute authorizes DOE to provide guarantees for loans covering up to 80 percent of the total project cost. When the government provides a guarantee for 100 percent of the debt instrument, the standard government loan-guarantee rules require that the government itself allocate and provide the capital for the investment (through the Department of the Treasury’s Federal Financing Bank [FFB]), which is then repaid by the entity receiving the guarantee over the period of the loan. If an entity other than the FFB provides the loan, there is no federal money that changes hands at the outset. The program is intended to be revenue neutral to the government; that is, the company benefiting from the guarantee is required to pay a fee to cover the risk of failure to repay the loan, as well as the administrative costs. DOE is authorized to provide $18.5 billion in loan guarantees for nuclear power facilities, but it is not yet clear whether this allocation will be sufficient for the four to five plants the committee judges will be needed to demonstrate whether new nuclear plants can be built on schedule and on budget. DOE has found it difficult to implement the program, in part because of the challenge associated with estimating the appropriate fee.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

plants per year could be constructed between 2026 and 2035. This could grow to 5–10 plants per year after 2035 if there is sufficient demand. However, if the first new plants do not meet their targets, few others are likely to follow, at least for a while.

Costs

The committee estimates that the LCOE at the busbar from new evolutionary nuclear plants could range from 8¢/kWh to 13¢/kWh (see Figure 2.10). Existing federal incentives—including loan guarantees such as those of the Energy Policy Act of 2005—could reduce the LCOE to about 6–8¢/kWh for plants that receive them. These levelized costs are higher than the current average cost of wholesale electricity, but they are likely to be comparable to future costs of electricity from other sources, particularly if fossil-fuel plants are required to store CO2 or pay a carbon fee. The LCOEs for improvements to existing plants are from one-tenth to one-third those of new plants. The possible LCOEs from advanced plant designs and alternative fuel cycles are highly uncertain at this time. However, these costs are likely to be higher than the LCOEs from current designs using the once-through cycle, although cost advantages from reductions in long-lived high-level waste could offset some of these differences.

Barriers to Deployment

The potential barriers to the deployment of new nuclear plants are several:

  • Economics. The high cost of new plants, with the resulting financial risk, is the most significant barrier to new deployment. Nuclear power plants have low operating costs per unit of electricity generation, but they incur high capital costs that present a financing challenge for generating companies, particularly given the long lead times for construction and the possibility of expensive delays.

  • Regulatory processes. The U.S. Nuclear Regulatory Commission (USNRC) is implementing a revised licensing process that allows for reactor design certification, early site permits, and combined construction and operating licenses. Nevertheless, in light of the surge in recent applications, bottlenecks and delays could occur in the near term.

  • Public concerns. Public opinion about nuclear power has improved in recent years, at least in part because of the safe and reliable perfor-

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

mance of existing plants, but it would likely become more negative if safety or security problems arose. The absence of a policy decision regarding the disposal of long-lived nuclear wastes, while not technically an impediment to the expansion of nuclear power, is still a public concern.18 New reactor construction has been barred in 13 states as a result, although several of these states are reconsidering their bans.

  • Shortages of personnel and equipment. These current shortages could limit construction during the next decade. The market should respond, however, and over time, the shortages should disappear.

Impacts

The impacts of an increased use of nuclear power include the following:

  • Diversity of supply. Barring a crash program, renewable-energy sources and fossil fuels with CCS are unlikely to be able to provide all of the U.S. electricity demand projected for 2035, even with gains in energy efficiency. Future deployment of nuclear plants would help to ensure a diversity of sources for electric supply—at present, they provide a significant proportion (about 19 percent). Thus, they could serve as an insurance policy for the United States, which would be particularly needed if carbon constraints were applied.

  • Environmental quality. A major factor in favor of expanding nuclear power is the potential for reduction in greenhouse gas emissions. Avoided CO2 emissions could reach 150 million tonnes per year by 2020 and 2.4 billion tonnes per year by 2050 under the maximum nuclear power deployment rate discussed in this report.19 However, an environmental challenge is presented by the disposal of the result-

18

The USNRC previously determined that the used fuel could be safely stored without significant environmental impacts for at least 30 years beyond the licensed life of operation of a reactor, at or away from the reactor site, and that there was reasonable assurance that a disposal site would be available by 2025 (10 CFR 51.23). The USNRC is now revisiting this determination and has proposed to find that used fuel can be stored safely and without significant environmental impacts until a disposal facility can reasonably be expected to be available (73 Fed. Reg. 59,547 [Oct. 9, 2008]).

19

This calculation assumes that nuclear plants replace traditional baseload coal plants emitting 1000 tonnes of CO2 equivalent per gigawatt-hour and that nuclear plants emit 24–55 tonnes of CO2 equivalent per gigawatt-hour on a life-cycle basis.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

ing radioactive waste, particularly used fuel. The one site previously envisioned for such disposal—Yucca Mountain, Nevada—would not be ready until after 2020, if at all. And the prospects for the Yucca Mountain repository are substantially diminished by the declared intent of the Obama administration not to pursue this disposal site. Nonetheless, the safe and secure on-site or interim storage of used fuel for many decades—until a location for a permanent disposal location is agreed upon—is technically and economically feasible.

  • Safety and security. Accidents or terrorist attacks involving nuclear reactors or used fuel storage could result in the release of radioactive material. Measures have been taken in recent years to reduce the likelihood and consequences of such events for existing plants, and evolutionary and advanced designs have features that further enhance safety and security.

  • Adequacy of resources. The estimated supply of uranium is sufficient to support a doubling of current world nuclear power capacity through the end of this century.

ELECTRICITY TRANSMISSION AND DISTRIBUTION

The U.S. electric power transmission and distribution (T&D) systems—the vital link between generating stations and customers—are in urgent need of expansion and upgrading. Growing loads and aging equipment are stressing the system and increasing the risk of widespread blackouts.

Adding transmission lines and replacing vintage equipment currently in operation would solve this problem. But with an investment only modestly greater, new technology could be incorporated that would have many additional advantages. Among the benefits of modern T&D systems are the following:

  • Superior economics. By improving the reliability of power delivery, enabling the growth of wholesale power markets, optimizing assets (reducing the need for new generating stations and transmission lines), and providing price signals to customers.

  • Better security. By improving resilience against major outages and speeding restoration after a system failure.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
  • Environmental quality. In particular by accommodating a large fraction of generation from renewable-energy sources.

Technologies

Technologies used to modernize the T&D systems must be implemented systematically and nationwide, particularly with respect to the transmission system, to achieve maximum benefit. R&D will be important for reducing costs and improving performance, but except in a few cases, breakthroughs are not needed. In fact, most of the technologies already exist and could be deployed now.

Included among these key modernizing technologies are the following:

  • Advanced equipment and components. Power electronics and high-voltage AC and DC lines offer the potential for long-distance transmission and grid operation that are more efficient. Power electronics both for transmission (Flexible Alternating Current Transmission System—FACTS) and distribution (Custom Power) currently exist and have been deployed in limited applications. Corresponding higher-voltage long-distance lines and substations could be deployed by 2020. High-voltage DC systems can be more economical than AC under some conditions, especially when lines must be underground or underwater, and several DC lines are already in operation. Cost-effective electric storage would be valuable in smoothing power disruptions, preventing cascading blackouts, and accommodating intermittent renewable-energy sources. Some storage technologies (e.g., compressed air energy storage and perhaps advanced batteries) will be ready for deployment before 2020, but significant development is still needed.

  • Measurements, communications, and control. Modern T&D systems will have the ability to gather, process, and convey data on the state of the system far more effectively than can be done at present. Sampling voltage, frequency, and other important factors many times per second will give operators a much clearer picture of changes in the system and enhance their ability to control it. Most of the necessary technologies are available and have been installed to a limited degree. The communications and control software needed to take full advantage of these technologies could use further development but should be ready by

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

2020. The costs of installation of the technologies and development of the required software will be significant, however, and the monitoring, sensing, and communications technologies for distribution systems differ from those for transmission systems. Nevertheless, full deployment of modern T&D systems could be achieved by 2030.

  • Improved decision support tools. The data that a modern grid collects and analyzes can assist operators in deciding when action must be taken, but only if the data are presented in timely and useful forms. During disruptions, split-second decision making may be necessary to prevent cascading failures. Improved decision support tools (IDST) will provide grid visualization to help operators understand the problem and the options available to resolve it. In addition, IDST can strengthen longer-term planning by identifying potential vulnerabilities and solutions. These technologies could be developed by 2020 and continually improved afterward.

  • Integrating technologies. The technologies discussed in this section can achieve their maximum benefit only through integrated deployment, which poses the primary challenge to creating modern T&D systems. Even though many of these technologies are available now, continued R&D will be important for improvements and cost reductions.

Costs

Modernization and the necessary expansion of T&D systems could be completed in the next 20 years. The total costs are estimated to be about $225 billion for the transmission system and $640 billion for the distribution system. Expansion alone without modernization would cost $175 billion and $470 billion, respectively. Such estimates are complicated by the expansive and interconnected nature of the system and the difficulty of determining development costs, particularly for software.

Barriers to Deployment

Significant barriers hinder the development of modern T&D systems. First, even though most of the necessary technologies are now available, many are expensive and present some performance risk. Second, in the short term it is more costly to develop modern T&D systems than to just expand current systems, and utilities tend to be risk averse; many consumers are more interested in low rates than in

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

reliability of service. And third, legislative and regulatory changes are needed to provide utilities and customers with adequate incentives to invest in modernization. Shortages of trained personnel and equipment could also be a barrier to T&D systems modernization, especially over the near term.

A clear vision for the modern grid is tantamount to providing an environment where utilities, regulators, and the public can understand the benefits and accept the costs, especially as the ownership, management, and regulation of the T&D systems are highly fragmented and collaboration will thus be required. Moreover, investments will be needed in locations and jurisdictions that do not directly benefit—e.g., areas that must be crossed by transmission lines to link generation and load centers. Such a vision would also provide a road map for integrating modernization of the various parts of the enormously complicated transmission system. It might also help expedite the construction of new transmission lines that are now subject to long delays. Clear metrics that measure benefits and progress, as well as the costs of not following this path, should be part of the strategy. In contrast, distribution systems can be modernized on a regional level, and some elements, such as smart meters, are appearing already.

Impacts

Modern T&D systems will provide substantial economic benefits by correcting the inefficiency and congestion of the current system and by reducing the number and length of power disruptions. Some estimates are that benefits will exceed costs by four to one. In addition, expanded capacity and improved information flows will raise the efficiency of the electricity markets. Modern T&D systems will be less vulnerable to potential disruptions because of their greater controllability and higher penetration of distributed generation, but the overlay of computer-driven communications and control will make cybersecurity an integral part of modernization. Environmental benefits from modern T&D systems will result from the greater penetration of large-scale intermittent renewable sources and of distributed and self-generation sources; better accommodation of demand-response technologies and electric vehicles; and improved efficiency. Finally, modern systems will be safer because improved monitoring and decision making allow for quicker identification of hazardous conditions, and less maintenance will be required.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

REFERENCES

AEP (American Electric Power). 2007. Interstate transmission vision for wind integration. AEP white paper. Columbus, Ohio.

DOE (Department of Energy). 2008. 20 Percent Wind Energy by 2030—Increasing Wind Energy’s Contribution to U.S. Electricity Supply. Washington, D.C.: U.S. Department of Energy, Energy Efficiency and Renewable Energy.

EIA (Energy Information Administration). 2008. Annual Energy Outlook 2008. DOE/EIA-0383(2008). Washington, D.C.: U.S. Department of Energy, Energy Information Administration.

EIA. 2009. Annual Energy Outlook 2009. DOE/EIA-0383(2009). Washington, D.C.: U.S. Department of Energy, Energy Information Administration.

JCSP (Joint Coordinated System Plan). 2009. Joint Coordinated System Plan 2008. Available at www.jcspstudy.org.

NAS-NAE-NRC (National Academy of Sciences-National Academy of Engineering-National Research Council). 2009a. Electricity from Renewable Resources: Status, Prospects, and Impediments. Washington, D.C.: The National Academies Press.

NAS-NAE-NRC. 2009b. Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts. Washington, D.C.: The National Academies Press.

NAS-NAE-NRC. 2009c. Real Prospects for Energy Efficiency in the United States. Washington, D.C.: The National Academies Press.

NRC (National Research Council). 2004. The Hydrogen Economy: Opportunities, Costs, Barriers, and R&D Needs. Washington, D.C.: The National Academies Press.

NRC. 2008. Transitions to Alternative Transportation Technologies—A Focus on Hydrogen. Washington, D.C.: The National Academies Press.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

ANNEX 3.A:
METHODS AND ASSUMPTIONS

This annex provides a description of some of the key methods and assumptions that were used to develop the energy supply, savings, and cost estimates made in this report. More detailed explanations of these methods and assumptions can be found in Chapters 49 of Part 2.

Energy Supply and Cost Estimates

The methodologies and assumptions used to develop the energy supply and cost estimates in this report are shown in Table 3.A.1. Each row in the table is described in the bulleted list that follows:

  • Reference scenario. The statement of task for this study (see Box 1.1) called for the development of a reference scenario “that reflects a projection of current economic, technology cost and performance, and policy parameters into the future. This reference scenario is the “base case” for comparison with the AEF Committee’s energy savings and supply estimates resulting from the accelerated deployment of technology. The committee adopted the Energy Information Administration’s reference case as the reference scenario for this study (see Box 2.1). The reference case for 2007 (EIA, 2008) was used for all but one of the energy supply assessments. The exception was renewable energy, which used the reference case for 2008 (EIA, 2009) because it contained estimates of capital costs for renewable energy technologies that the committee judged to be more realistic than the EIA (2008) estimates.

  • Source of cost estimates and models used to obtain estimates describe the methodologies that were used by the AEF Committee to estimate energy supply costs—either the levelized cost of electricity (LCOE; see Box 2.3) or the costs of liquid fuels. Committee-derived model estimates (i.e., developed by the committee itself or for the committee by consultants) were used for the costs of fossil, nuclear, and alternative liquid fuel technologies. The fossil- and alternative-liquid fuel cost estimates were developed using a common set of models and assumptions (see Box 7.2 in Chapter 7). The nuclear energy cost estimates were developed using a different but comparable set of models and assumptions (see Box 8.4 in Chapter 8). The renewable energy cost estimates were

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

developed through a critical review of published studies that employed a range of models and assumptions; two examples are shown in the table. The AEF Committee used expert judgment in selecting the estimates from these studies that it considered to be reliable.

  • Cost estimate limitations are key knowledge gaps and uncertainties that could affect the accuracy of the cost estimates. These limitations arise primarily from technology immaturity or a lack of experience with deploying technologies at commercial scales. One would expect these uncertainties to be reduced as technologies mature and deployment experience is gained.

  • Plant maturity. The costs of initial deployments of a new technology, sometimes referred to as first plant costs, are generally higher than the costs of deployments of mature proven technologies, sometimes referred to as Nth plant costs. The cost estimates presented in this report reflect the AEF Committee’s judgments about the state of technology maturity in 2020. The committee presents first plant cost estimates for immature technologies, Nth plant costs for mature technologies (e.g., pulverized coal plants), and intermediate plant costs for technologies that are still maturing (e.g., IGCC, liquid fuels production). In some cases, cost contingencies were added for immature technologies to bring them closer to Nth plant estimates.

  • Plant size is the nameplate capacity of the energy supply plant assumed in the cost estimates. The AEF Committee selected plant sizes that it deemed to be typical of each technology class.

  • Plant life is the time over which the energy supply plant is assumed to generate electricity or liquid fuels. The AEF Committee generally followed industry convention in selecting plant lives for each technology class. In some cases, the plant lives selected were less than the lives of current generating assets (e.g., pulverized coal plants).

  • Feedstock and fuel costs are the costs for the feedstocks and fuels that are used to produce electricity and liquid fuels. The fuel costs used in this report were selected by the committee based on examinations of historical costs, recent costs, and cost trends. In some cases, ranges of costs were used in the estimates. There are no fuel costs for some renewable energy supplies (e.g., solar and wind).

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
  • CO2prices represent potential future costs to operators for emitting CO2 to the atmosphere from energy production. A base-case CO2 price of $0 per tonne was assumed for all of the energy supply cost estimates presented in this report; prices of $50 and $100 per tonne were also considered in the fossil energy and alternative liquid fuels estimates in order to assess the sensitivity of energy supply costs to CO2 prices for a future in which climate change is taken seriously.

  • Financing period is the length of time that capital borrowed for constructing the energy supply plant would be financed. The financing periods used in this report reflect current industry practices, which vary across technology classes.

  • Debt/equity indicates the ratio of borrowed capital to equity capital in financing the construction of the energy supply plant. The ratios used in this report reflect current industry practices, which vary across technology classes. In some cases ranges were used.

  • Before-tax discount rate was used to convert future energy supply costs into present values. The ratios used in this report reflect standard industry practice.

  • Overnight costs represent the present-value costs, paid as a lump sum, for building an energy supply plant. The overnight costs do not include any costs associated with the acquisition of capital, the acquisition of land on which the plant would be built, or site improvements such as new or upgraded transmission equipment. In some cases, overnight costs are given as ranges. For the fossil-fuel estimates, however, 10 percent of the capital costs were added to account for owners’ costs.

  • Source of supply estimates describe the methodologies that were used by the AEF Committee to estimate the supply of electricity and liquid fuels. Many factors can affect deployment rates of a technology beyond its readiness for deployment. Consequently, it was not possible to develop a single methodology for estimating deployment rates for all of the energy supply technologies considered in this report. The committee’s estimates of deployment rates were instead based on expert judgment informed by historical rates of technology deployments or by current deployment trends. The supply estimates represent new electricity or liquid fuel supplies and do not account for possible future supply reductions arising from retirements of existing assets.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
  • Build time is the estimated time required to construct a new energy supply plant. This estimate represents actual construction time; it does not include the time required to acquire a site, to design the plant, and to obtain any needed licenses, permits, or other approvals. The build times used in this report reflect current industry practices, which vary across technology classes.

  • Capacity factor is the ratio (expressed as a percent) of the energy output of a plant over its lifetime to the energy that could be produced by that plant if it was operated at its nameplate capacity. Some capacity factors are expressed as ranges. The capacity factors used in this report reflect current experience and projected future improvements, both of which vary across technology classes.

  • Near-term build-rate limitations identifies important factors that could limit the rates of plant deployments between 2009 and 2020. These limitations arise from a lack of experience in deploying new technologies (e.g., CCS), bottlenecks in obtaining critical plant components (e.g., large forgings for nuclear plants), and reduced availabilities of other materials and personnel. Most of these bottlenecks are expected to be temporary and should not present major impediments to deployment after 2020.

  • Resource limitations are factors that could restrict the supply of energy obtained from the deployment of existing and new technologies. These limitations relate mainly to the availability of feedstocks and fuels that are needed to operate the energy supply plants.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

TABLE 3.A.1 Sources and Key Assumptions Used to Develop Cost and Energy Supply Estimates in This Report

 

Fossil-Fuel Energy (Chapter 7)

Nuclear Energy (Chapter 8)

Renewable Energy (Chapter 6)

Reference scenario

EIA (2008)

EIA (2008)

EIA (2009)

COST ESTIMATES: SOURCES AND KEY ASSUMPTIONS

Source of cost estimates

Committee-derived model estimates

Committee-derived model estimates

Critical assessment of the literaturea

Models used to obtain estimates

NETL (2007) and Princeton Environmental Instituteb

  • Keystone (2007) model for LCOEc

  • Monte Carlo for sensitivity analysis

  • NEMS model for EIA (2009) cost estimates

  • MERGE model for EPRI (2007) cost estimates

  • Other literature estimates are not model based

Cost estimate limitations

  • IGCC, USPC, and CCS technologies are not yet mature and have not been deployed

  • Geologic storage of CO2 has not been demonstrated on a commercial scale

Evolutionary nuclear technologies are mature but plants have not yet been deployed in the United States.

Solar technologies are undergoing rapid technological improvements that could bring down future costs.

Plant maturity

  • Nth plant for pulverized coal

  • 3 percent premium on capital costs added for IGCC, PC-CCS, and IGCC-CCS to account for immaturity of technologies

  • 20 percent premium on CCS capital costs added for CCS 2020 estimates to account for immaturity of technologies

Nth plant

Nth plant

Plant size

500 MW (coal and gas)

1.35 GW, based on weighted average of current plant license applications

Variable

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

Alternative Transportation Fuels (Chapter 5)

Cellulosic Ethanol

Coal to Liquid

Coal + Biomass to Liquid

EIA (2008)

EIA (2008)

EIA (2008)

Committee-derived model estimates

Committee-derived model estimates

Committee-derived model estimates

See NAS-NAE-NRC (2009), Appendix I

Princeton Environmental Instituteb

Princeton Environmental Instituteb

Cellulosic technologies are not yet mature and have not been deployed

Geologic storage of CO2 has not been demonstrated on a commercial scale

Geologic storage of CO2 has not been demonstrated on a commercial scale

  • Intermediate plant

  • No capital cost contingency included in estimate for CCS

  • Intermediate plant

  • No capital cost contingency included in estimate for CCS

  • Intermediate plant

  • No capital cost contingency included in estimate for CCS

4,000 bbl/d

50,000 bbl/d

10,000 bbl/d

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

 

Fossil-Fuel Energy (Chapter 7)

Nuclear Energy (Chapter 8)

Renewable Energy (Chapter 6)

Reference scenario

EIA (2008)

EIA (2008)

EIA (2009)

COST ESTIMATES: SOURCES AND KEY ASSUMPTIONS

Plant life (yr)

20

40

Variable

Feedstock and fuel costs

Coal: $1.71/GJ ($46/tonne)

Gas: $6/GJ, $16/GJ

Average: 1.25¢/kWh

Range: 0.8–1.7¢/kWh

Biomass: $15–35/MWh

Others: $0

CO2prices ($/tonne)

0, 50, 100

0

0

Financing period (yr)

20

Average: 40

Range: 30–50

Variable

Debt/equity

55/45

  • IPP: Average 60/40 Range: 50/50 to 70/30

  • IOU: Average 50/50 Range: 45/55 to 55/45

  • Also considered: 80/20 for IPP and IOU with federal loan guarantees

Variable

Before-tax discount rate (percent/yr)

7

  • IOU: 6.9

  • IPP: 7.7

Variable

Overnight costs

(Millions of 2007$/kW)

(Millions of 2007$/bbl)

  • PC: 1625

  • PC+CCS: 2961

  • IGCC: 1865

  • IGCC+CCS: 2466

  • NGCC: 572

  • NGCC+CCS: 1209

  • −20%/+30% uncertainty

Average: 4500

Range: 3000–6000

  • Biopower: 3390

  • Traditional geothermal: 1585

  • CSP: 2860–4130

  • PV: 2547–5185

  • Onshore wind: 916–1896

  • Offshore wind: 2232–3552

ELECTRICITY OR LIQUID FUELS SUPPLY ESTIMATES: SOURCES AND KEY ASSUMPTIONS

Source of supply estimates

Committee-generated, based on historical build rates of plants in the United States

Committee-generated, based on historical build rates of plants in the United States

Committee-generated, based on an examination of natural resource base and other factorsd

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

Alternative Transportation Fuels (Chapter 5)

Cellulosic Ethanol

Coal to Liquid

Coal + Biomass to Liquid

EIA (2008)

EIA (2008)

EIA (2008)

20

20

20

$111/tonne dry biomass

$46/tonne coal

$46/tonne coal

$111/tonne dry biomass

0, 50

0, 50

0, 50

20

20

20

70/30

55/45

55/45

7

7

7

349

4000–5000 (with CCS)

(0.08–0.09/bbl per day)

1340 (with CCS)

(0.134/bbl per day)

Committee-generated, based partly on corn-ethanol plant build rates in the United Statese

Committee-generated, based on historical build rates of plants in the United States

Committee-generated, based partly on corn-ethanol plant build rates in the United Statesf

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

 

Fossil-Fuel Energy (Chapter 7)

Nuclear Energy (Chapter 8)

Renewable Energy (Chapter 6)

Reference scenario

EIA (2008)

EIA (2008)

EIA (2009)

ELECTRICITY OR LIQUID FUELS SUPPLY ESTIMATES: SOURCES AND KEY ASSUMPTIONS

Build time (yr)g

3h

Average: 5.5

Range: 4–7

  • 1–2 for solar and wind

  • Longer for biopower and hydrothermal

Capacity factor (percent)

85

Average: 90

Range: 75–95

  • Biopower: 83–85

  • Traditional geothermal: 90

  • CSP: 31–65

  • PV: 21–32

  • Wind: 32.5–52

Near-term build-rate limitations

Learning curve for CCS slows build rate before 2025

Build rates slowed before 2020 by:

  • Time to acquire license and construct plants

  • Lack of domestic experience

  • Potential bottlenecks in obtaining plant components

Barriers to reach 20 percent renewables generation:

  • Availability of raw materials

  • Manufacturing capacity

  • Availability of personnel

Resource limitations

Historical resources limits considered

None

None for wind and solar; limited resource bases for biomass, traditional hydropower, hydrokinetic, and traditional geothermal

Note: CCS = carbon capture and storage; CSP = concentrating solar power (i.e., solar thermal); IGCC = integrated gasification combined cycle; IOU = investor-owned utility; IPP = independent power producer; MERGE = Model for Evaluating Regional and Global Effects [of greenhouse gases]; NEMS = National Energy Modeling System; NGCC = natural gas combined cycle; PC = pulverized coal; PV = photovoltaics; USPC = ultrasupercritical pulverized coal.

aThe following studies were used to “bookend” the renewable energy cost estimates: ASES (2007), EIA (2008, 2009), EPRI (2007), and NREL (2007).

bSee Kreutz et al. (2008) and Larson et al. (2008).

cThis model was run using committee-developed assumptions as described in Chapter 8 in Part 2 of this report.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

Alternative Transportation Fuels (Chapter 5)

Cellulosic Ethanol

Coal to Liquid

Coal + Biomass to Liquid

EIA (2008)

EIA (2008)

EIA (2008)

1

3

3

90

90

90

None

None

None

Biomass availability

Coal extraction rates

Biomass availability

dThese additional factors included manufacturing and materials constraints, employment and capital requirements, and necessary deployment rates. The committee also considered current growth rates of renewables technologies and historical build rates of other types of plants.

eThe committee assumed twice the capacity achieved for corn grain ethanol.

fThe committee assumed a build-out rate slightly slower than that for corn grain ethanol because of issues involving accessing sites with about 1.0 million tonnes of biomass per year and a similar availability of coal.

gEstimates do not include the time required for permitting and other approvals.

hThis estimate does not account for differences in complexity of different types of coal and natural gas plants.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
Energy Savings and Cost Estimates

The methodologies and assumptions used to develop the energy savings and cost estimates are provided in Table 3.A.2. Each row in the table is described in the following bulleted list:

  • Reference scenarios. The reference case for 2006 (EIA 2007) was used for the buildings and industrial sector estimates, but these were adjusted in some cases to reflect the 2007 reference case provided in EIA (2008). The transportation estimates were based on a committee-derived, no-change baseline.

  • Source of cost estimates describes the methodologies that were used to estimate energy savings costs. As shown in the table, these estimates were derived from critical assessments of the literature.

  • Source of savings estimates describes the methodologies that were used to estimate energy savings. As shown in the table, these estimates were derived from critical assessments of the literature and, for buildings and transportation, committee-derived analyses.

  • Key cost-effectiveness criteria describes the criteria that were used to determine which energy savings were cost-effective. Different criteria were used in the buildings, transportation, and industrial sectors, as described in the table.

  • Technology lifetimes are average useful lifetimes of the technologies used to obtain energy savings. These estimates are highly technology specific.

  • Before-tax discount rate was used to convert future energy supply costs into present values. The ratios used in this report reflect standard industry practice.

  • Other considerations describe other factors that were considered in developing the energy-savings cost and supply estimates.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×

TABLE 3.A.2 Sources and Key Assumptions Used to Develop Energy Savings and Cost Estimates

 

Buildings Sector

Transportation Sector

Industry Sectora

Reference scenario

EIA (2007, 2008)

Developed by committeeb

EIA (2007, 2008)

Source of cost estimates

Critical assessment of the literature

Critical assessment of the literature

Critical assessment of the literature

Source of savings estimates

Critical assessment of the literature on individual technologies and committee-derived conservation supply-curve analysis

  • Critical assessment of the literature on specific technologies

  • For light-duty vehicles (LDVs), committee-derived illustrative scenario analysis of overall savings in fuel consumption

Critical assessment of the literature on industry-wide savings, industry-specific savings, and savings from specific crosscutting technologies

Key cost-effectiveness criteria

Levelized cost of energy savings is less than the average national electricity and natural gas prices

Recovery of discounted costs of energy savings over the life of the vehicle

Energy savings provide an internal rate of return on investment of at least 10 percent or exceed the company’s cost of capital by a risk premium

Technology lifetimes

Technology specific

Average vehicle lifetime

Technology specific

Before-tax discount rate (percent/yr)

7

7

15

Other considerations

Assessment accounts for stock turnover in buildings and equipment

For LDVs, assessment considers how the distribution of specific vehicle types in the new-vehicle fleet affects the on-the-road fleet

Assessment of savings in specific industries used to confirm industry-wide estimates

aManufacturing only.

bThis is a “no-change” baseline in which, beyond 2020 (when Energy Independence and Security Act targets are met), any efficiency improvements are fully offset by increases in vehicle performance, size, and weight.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
References for Annex 3.A

ASES (American Solar Energy Society). 2007. Tracking Climate Change in the U.S.: Potential Carbon Emissions Reductions from Energy Efficiency and Renewable Energy by 2030. Washington, D.C.

EIA (Energy Information Administration). 2007. Annual Energy Outlook 2007. DOE/EIA-0383(2007). Washington, D.C.: U.S. Department of Energy, Energy Information Administration.

EIA. 2008. Annual Energy Outlook 2008. DOE/EIA-0383(2008). Washington, D.C.: U.S. Department of Energy, Energy Information Administration.

EIA. 2009. Annual Energy Outlook 2009. DOE/EIA-0383(2009). Washington, D.C.: U.S. Department of Energy, Energy Information Administration.

EPRI (Electric Power Research Institute). 2007. The Power to Reduce CO2 Emissions: The Full Portfolio. Palo Alto, Calif.

Keystone Center. 2007. Nuclear Power Joint Fact-Finding. Keystone, Colo.

Kreutz, T.G., E.D. Larson, G. Liu, and R.H. Williams. 2008. Fischer-Tropsch fuels from coal and biomass. In 25th Annual International Pittsburgh Coal Conference. Pittsburgh, Pa.

Larson, E.D., G. Fiorese, G. Liu, R.H. Williams, T.G. Kreutz, and S. Consonni. 2008. Coproduction of synthetic fuels and electricity from coal + biomass with zero carbon emissions: An Illinois case study. In 9th International Conference on Greenhouse Gas Control Technologies. Washington, D.C.

NAS-NAE-NRC (National Academy of Sciences-National Academy of Engineering-National Research Council). 2009. Liquid Transportation Fuels from Coal and Biomass: Technological Status, Costs, and Environmental Impacts. Washington, D.C.: The National Academies Press.

NETL (National Energy Technology Laboratory). 2007. Cost and Performance Baseline for Fossil Energy Plants. DOE/NETL-2007/1281, Revision 1, August. U.S. Department of Energy, National Energy Technology Laboratory.

NREL (National Renewable Energy Laboratory). 2007. Projected Benefits of Federal Energy Efficiency and Renewable Energy Programs. NREL/TP-640-4137. Golden, Colo. March.

Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
×
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×
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×
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×
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×
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Suggested Citation:"3 Key Results from Technology Assessments." National Academy of Sciences, National Academy of Engineering, and National Research Council. 2009. America's Energy Future: Technology and Transformation. Washington, DC: The National Academies Press. doi: 10.17226/12091.
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Energy touches our lives in countless ways and its costs are felt when we fill up at the gas pump, pay our home heating bills, and keep businesses both large and small running. There are long-term costs as well: to the environment, as natural resources are depleted and pollution contributes to global climate change, and to national security and independence, as many of the world's current energy sources are increasingly concentrated in geopolitically unstable regions. The country's challenge is to develop an energy portfolio that addresses these concerns while still providing sufficient, affordable energy reserves for the nation.

The United States has enormous resources to put behind solutions to this energy challenge; the dilemma is to identify which solutions are the right ones. Before deciding which energy technologies to develop, and on what timeline, we need to understand them better.

America's Energy Future analyzes the potential of a wide range of technologies for generation, distribution, and conservation of energy. This book considers technologies to increase energy efficiency, coal-fired power generation, nuclear power, renewable energy, oil and natural gas, and alternative transportation fuels. It offers a detailed assessment of the associated impacts and projected costs of implementing each technology and categorizes them into three time frames for implementation.

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