A key issue in mid-term forecasting is the representation of changing and developing technologies. How existing technologies will evolve, and what new technologies might emerge, cannot be known with certainty. The issue is of particular importance in AEO2006, the first AEO with projections out to 2030. 

For each of the energy supply and demand sectors represented in NEMS, there are key technologies that, while they may not be important in the market today, could play a role in the U.S. energy economy by 2030 if their cost and/or performance characteristics improve with successful R&D. Moreover, it is possible, if not likely, that technologies not yet conceived could be important 20 to 30 years from now. Although the direction and pace of change are unpredictable, technological progress is certain to continue. 

Buildings Sector 

A variety of new technologies could influence future energy use in residential and commercial buildings beyond the levels projected in AEO2006. Two such technologies are solid-state lighting and “zero energy” homes. 

Solid-state lighting. Solid-state lighting (SSL) is an emerging technology for general lighting applications in buildings. Two types of SSL currently under development are semiconductor-based light-emitting diode (LED) and organic light-emitting diode (OLED) technologies. Both are commercially available for specialized lighting applications. Consumers are likely to be familiar with the use of LEDs in traffic signals, exit signs and similar displays, vehicle tail lights, and flashlights. They are less likely to be familiar with OLEDs, used in high-resolution display panels for computers and other electronic devices. 

Lighting accounted for 16 percent of total primary energy consumption in buildings in 2004, second only to space heating at 20 percent. Thus, changes in the assumptions made about development and enhancement of SSL technologies could have a significant impact on projected total energy consumption in residential and commercial buildings through 2030. 

Beginning with AEO2005, SSL based on LED technology has been included as an option in the NEMS Commercial Module, based on currently available products. Those products are more than four times as expensive as comparable incandescent lighting, with only slightly greater efficiency (called “efficacy” and measured in lumens per watt), and so have virtually no impact in the AEO2006 projections. In order for LEDs and OLEDs to compete successfully in general lighting applications, several R&D hurdles must be overcome: costs must be reduced, efficacy must be increased, and improved techniques must be developed for generating light with a high color rendering index (CRI) that more closely approximates the spectrum of natural light and is needed for many building applications. 

DOE’s R&D goals call for SSL costs to fall dramatically by 2030. The real promise for LED lighting is that efficacies could approach 150 to 200 lumens per watt—more than twice the efficacy of current fluorescent technologies and roughly 10 times the efficacy of incandescent lighting [30]. An additional goal is to increase LED operating lifetimes from 30,000 hours to 100,000 hours or more, which would far exceed the useful lifetimes of conventional technologies (generally, between 1,000 and 20,000 hours). Longer useful operating lives are particularly valuable in commercial applications where lamp replacement represents a major element of lighting costs. 

For general illumination applications, OLED technology lags behind LED technology. If research goals are realized, the advantages of OLED technology will be lower production costs than LEDs, similar theoretical efficacies (200 lumens per watt for white light), and the flexibility to serve as a source of distributed lighting, as is currently provided by fluorescent lamps. 

Zero energy homes. DOE’s Zero Energy Homes (ZEH) program encompasses several existing technologies rather than a single emerging technology. The ZEH program takes a “whole house” approach to reducing nonrenewable energy consumption in residential buildings by integrating energy-efficient technologies for building shells and appliances with solar water heating and PV technologies to reduce annual net consumption of energy from nonrenewable sources to zero [31]. This is an emerging integrated technology; the ZEH concept is novel for conventional housing units [32]. ZEH prototypes have been shown to generate more electric energy than they consume during periods of peak demand for air conditioning, while approaching the goal of zero net annual energy purchases. The technological hurdle is to make ZEH homes without subsidies both cost-competitive and attractive as alternatives to conventional homes. 

ZEH homes currently are not characterized or identified as an integrated technology in the NEMS Residential Module; however, most of the constituent ZEH technologies are characterized as separate options. Several whole-house options are modeled, characterized according to their efficiencies relative to current residential energy codes, with the following options: 

• Current residential code 
• 30 percent more efficient than current code (modeled to meet ENERGY STAR requirements) 
• 40 percent more efficient than current code 
• 50 percent more efficient than current code (modeled along the lines of PATH concepts [33]) 
• Solar PV and solar water heating technologies. 

In addition to ZEH, a long list of emerging buildings technologies has been compiled by the American Council for an Energy-Efficient Economy. They included six identified as high-priority technologies on the basis of such criteria as the cost of conserved energy, savings potential, and likelihood of success: 

• For residential and small commercial buildings: 1-watt standby power for consumer appliances, aerosol-based duct sealing, and leak-proof ducts 
• For commercial buildings: integrated building design, computerized building diagnostics, and “retro-commissioning” [34]. 

Because they are still in the early stages of development, the information needed to characterize these six high-priority technologies or programs is not yet available, and they are not included in AEO2006; however, they do hold promise if they can be successfully commercialized. 

Industrial Sector 

The industrial sector is diverse, and there are many potential technological innovations that could affect industrial energy use over the next 25 years. Two technologies, fuel gasification and nanotechnologies, could have impacts across a broad array of industries. Gasification could be especially important to the paper business; successful nanotechnologies could have very broad impacts. 

Black liquor gasification. Black liquor is a waste product from papermaking. It contains inorganic chemicals that are recovered for reuse in the papermaking processes and lignin from the initial pulpwood inputs that is also recovered and used as a fuel for boilers and for cogeneration. Current practice uses Tomlinson boilers to recover the inorganic chemicals and combust the organics to produce steam [35]. Black liquor gasification coupled with a combined-cycle power plant (BLGCC) has been proposed as a way to make better use of the lignin and recover a larger portion of the inorganic chemicals from the liquor. 

R&D on BLGCC technology has been underway for several years. The American Forest and Paper Association’s Agenda 2020: Technology Vision and Research Agenda for America’s Forest, Wood and Paper Industry, first published in 1994, has been revised several times over the years. A recent progress report indicates that successful industry-wide implementation of BLGCC could provide an additional 30 gigawatts of on-site electricity generation capacity beyond the 8 gigawatts operating in 2004 [36]. 

DOE-sponsored R&D activities in support of BLGCC were evaluated by the National Academy of Sciences (NAS) in a 2001 report [37], in which it was indicated that DOE’s expectation that Tomlinson boilers would be replaced in a 10- to 20-year time frame probably was optimistic. The report also noted that “moving from the existing black liquor gasification units to systems suitable for use with combined cycle requires bench-scale research as well as demonstration.” The technology is not explicitly represented in AEO2006 and is not expected to have an impact on the industrial sector in the reference case. In the high technology case, the potential impact of BLGCC is represented as an increasing amount of biomass-based CHP capacity, up to 3 gigawatts (43 percent) more than in the reference case in 2030. 

Nanotechnology. Nanotechnology refers to a wide range of scientific or technological projects that focus on phenomena at the nanometer (nm) scale (around 0.1 to 100 nm) [38]. While not as far along as BLGCC, nanotechnologies have much larger potential impacts if they are successfully developed. Indeed, it has been suggested that nanotechnology applications in the industrial sector could yield a new industrial revolution [39]. Possible applications include, for example, very thin solar silicon panels that could be embedded in paint [40]; very thin video screens with about the same thickness and flexibility as newspapers, which could be updated continuously with current news [41]; and very strong, very light materials that could revolutionize transportation systems and dramatically reduce per capita energy consumption [42]. 

While the potential applications of nanotechnologies are diverse, many issues, including potential impacts on human health, remain to be studied. AEO2006 does not include potential energy applications of nanotechnology, because they still are speculative. 

Transportation Sector 

The transportation module in NEMS addresses technologies specific to light-duty vehicles, heavy trucks, and aircraft. The majority of the advanced technologies represented reflect improvements to conventional power train components, including such technologies as variable valve timing and lift, camless valve actuation, advanced light-weight materials, six-speed and continuously variable transmissions, cylinder deactivation, and electronically driven parasitic devices (power steering pumps, water pumps, etc.). Vehicles powered by batteries or fuel cells are also explicitly represented in AEO2006, but their penetration results largely from legislatively mandated sales. 

Transportation technologies not currently included in NEMS that could potentially become viable market options include homogeneous charge compression ignition (HCCI), grid-connected hybrid vehicles, and hydraulic hybrid vehicles. HCCI—which combines features of both spark-ignited (gasoline) and compression-ignited (diesel) engines—can operate on a variety of fuels. In the HCCI engine, an extremely lean mixture of fuel and air is autoignited in the cylinder via compression. Autoignition can damage the pistons in spark-ignited engines, but the extremely high air-to-fuel ratio in HCCI engines prevents flame propagation and results in a much cooler burn. As a result, HCCI engines are very efficient, with low levels of emissions that do not require expensive after-treatment devices. The fuel properties and cylinder conditions needed for HCCI combustion are well understood; however, it is extremely difficult to control ignition in multiple-cylinder engines across a wide range of load conditions, as needed for vehicle applications. 

Grid-connected hybrid vehicles are similar to the hybrid vehicles sold today, except that the batteries provide an all-electric range of about 50 miles, and an external source to charge the batteries is required. Unlike current hybrid vehicles that use high-power batteries to supplement the power of gasoline engines, grid-connected hybrid vehicles are also designed to operate as all-electric vehicles and, as such, require a much larger battery pack for energy storage, a larger electric motor, and related components that enable them to function over a much wider range of driving conditions. Although all-electric driving greatly reduces the vehicles’ gasoline consumption, the costs of the battery pack and other components are significant. Marketing studies have indicated that there is a lack of consumer interest in “plug-in” vehicles but that a limited market would exist if their incremental costs relative to conventional vehicles could be reduced to at most $5,000. 

Hydraulic hybrid vehicles use hydraulic and mechanical components to store and deliver energy. In a hydraulic hybrid, the gear-driven transmission is replaced by a hydraulic pump/motor that is also used to store and recoup energy through the transfer of fluid between hydraulic accumulators. Recent hydraulic hybrid prototypes are designed to provide launch assist in heavy vehicle applications, allowing acceleration with less engine power. The hydraulic hybrid system has been shown to provide a 50-percent improvement in fuel economy at a cost of about $600. Current hydraulic systems are large and heavy, however, and the EPA is funding R&D to reduce their size and weight while improving their efficiency. 

Oil and Natural Gas Supply 

In the oil and natural gas supply area, new technologies for the economical development of unconventional resources could grow in importance. One of the most plentiful unconventional resources is natural gas hydrates—ice-like solids composed of light hydrocarbon molecules, primarily methane, trapped in a cage-like crystalline lattice of water and ice. 

The 1995 National Oil and Gas Resource Assessment, conducted by the USGS and the Minerals Management Service, produced the first systematic appraisal of in-place natural gas hydrate resources in U.S. onshore and offshore regions [43]. Its mean (expected value) estimate of in-place natural gas hydrates offshore in U.S. deepwater areas was 320,000 trillion cubic feet, and its mean estimate of in-place natural gas hydrate resources onshore in Alaska’s North Slope was 590 trillion cubic feet. In comparison, total U.S. natural gas production in 2003 was 19 trillion cubic feet, and year-end 2003 reserves were 193 trillion cubic feet. According to these estimates, if natural gas hydrate resources could be developed economically, they could supply U.S. natural gas needs for many years. 

Commercial production of natural gas hydrates has not yet been attempted. Short-term production tests have been conducted in Canada’s MacKenzie Delta region, however, and natural gas hydrates may have been produced unintentionally at the Messoyakha Field in Russia’s West Siberian Basin. 

Commercial production of natural gas hydrates is expected to use one or more of three techniques: pressure reduction, heat injection, and solvent phase change. The techniques used will depend on the characteristics of the natural gas hydrate formation being developed. Each has advantages and disadvantages. The pressure reduction technique has the lowest cost, but it requires a free-gas (non-hydrate) zone below the hydrate deposit, and the production rate would be limited by heat transfer rates within the formation. The heat injection technique, using steam or hot water, does not require a free-gas zone, and it would achieve higher production rates than are possible with pressure reduction. On the other hand, it is more complex and more costly, requiring large amounts of water and energy to heat it. The solvent phase change technology is the most expensive, and it could lead to water contamination problems, but it does not require energy for water heating and is not subject to the formation of ice dams, which can be a problem for the heat injection technique. 

In the United States, the existence of large conventional natural gas deposits in the Prudhoe Bay and Point Thomson Fields on Alaska’s North Slope is expected to preclude any significant production from hydrates on the North Slope for many years to come. For example, if the Alaska natural gas pipeline became operational in 2015, it would take about 21 years (until 2036) to deplete the 35 trillion cubic feet of proven North Slope conventional natural gas resources at a pipeline capacity of 4.5 billion cubic feet per day, or 17 years (until 2032) at a pipeline capacity of 5.6 billion cubic feet per day. Moreover, the North Slope has a large undiscovered base of conventional natural gas resources beyond the volumes estimated to be recoverable in currently known fields. Therefore, any significant commercial production of North Slope natural gas hydrates could be 30 years or more into the future. 

Production of oceanic natural gas hydrates is at least as problematic, because the deposits are not as well mapped and characterized, and because no production of oceanic hydrates has yet occurred. Moreover, akin to the situation on the Alaska North Slope, there are considerable conventional natural gas deposits yet to be found and developed in the deepwater Gulf of Mexico. Considerable R&D will also be required before any exploitation of oceanic natural gas hydrates can be considered. Research on oceanic hydrates is almost certain to continue, given the vast size of the potential resource. 

Biorefineries 

Rising world oil prices in recent years have heightened interest in alternative sources of liquid fuels, including biofuels. Currently, two biologically derived fuels, biodiesel and ethanol, are used in the United States to augment and improve supplies of gasoline and diesel fuel. As petroleum becomes more scarce and expensive, these and potentially other biofuels could become important alternatives. 

Biodiesel. The term biodiesel applies specifically to methyl or ethyl esters of vegetable oil or animal fat. In principle, biodiesel can be blended into petroleum diesel fuel or heating oil in any fraction, so long as the fuel system that uses it is constructed of materials that are compatible with the blend. The actual maximum allowable fraction of biodiesel in diesel fuel varies by engine manufacturer and by specific model line. Fuel system materials are a concern, because methyl and ethyl esters are strong solvents that can damage certain plastics or rubbers. 

The solvent properties of biodiesel also make it unlikely that biodiesel blends could be shipped through petroleum product pipelines. There would be a risk of contamination when the biodiesel dissolved any material deposited on the walls of pipes, manifolds, or storage tanks. On the positive side, the addition of biodiesel to petroleum diesel reduces engine emissions of carbon monoxide, unburned hydrocarbons, and particulates. On the negative, it tends to increase nitrogen oxide emissions, and that may limit the use of biodiesel in places with excess levels of ozone at ground level. 

The production of methyl esters is an established technology in the United States, but the product typically has been too expensive to be used as fuel. Instead, methyl esters have been used in products such as soaps and detergents. Proctor and Gamble, Peter Cremer, Dow Haltermann, and other large firms currently supply methyl esters to the industrial market. Most dedicated biodiesel producers are much smaller, and delivery of a consistent product is proving to be a challenge. 

Several other processes for making diesel fuel from biomass are under consideration. The most mature of these technologies is biomass-to-liquids (BTL). The biomass is first reacted with steam in the presence of a catalyst to form carbon monoxide and hydrogen, or synthesis gas. Any other elements contained in the biomass are removed during the gasification step. The carbon monoxide and hydrogen are then reacted to form liquid hydrocarbons and water. 

Although BTL products are high in quality, BTL plants face several challenges. They have high capital and operating costs, and their feedstock handling costs are especially high. BTL gasifiers are significantly more expensive than the gasifiers used in CTL or GTL facilities. Furthermore, the cost of a BTL plant per barrel of output is several times the cost of expanding an existing petroleum refinery or building a new one. As a result, while new BTL plants are being built in Germany, there is no commercial production of BTL in the United States. BTL production and its market implications are discussed under “Nonconventional Liquid Fuels,” below. 

In another process, vegetable oils and animal fats can be reacted with hydrogen to yield hydrocarbons that blend readily into diesel fuel. The oil or fat is pressurized and combined in a reactor with hydrogen in the presence of a catalyst similar to those used in hydrotreaters at petroleum refineries. The products of the process are bioparaffins. Bioparaffin diesel fuel is similar in quality to BTL diesel, with the added benefit of being free of byproducts. The improvement in quality over methyl esters (biodiesel) is not free, however. A bioparaffin plant is less expensive than a BTL plant but more expensive than a biodiesel plant, because the bioparaffin reaction takes place under pressure, and a hydrogen plant is needed. Bioparaffins also share with biodiesel the problem of feedstock costs. Vegetable oils are expensive, especially if they are food grade. The catalyst needed also adds significant expense. The world’s first bioparaffin plant is being built at a petroleum refinery in Finland, but there are no plans for U.S. bioparaffin capacity at this time. 

Ethanol. Ethanol can be blended into gasoline readily at up to 10 percent by volume. All cars and light trucks built for the U.S. market since the late 1970s can run on gasoline containing 10 percent ethanol. Automakers also produce a limited number of vehicles for the U.S. market that can run on blends of up to 85 percent ethanol. Ethanol adds oxygen to the gasoline, which reduces carbon monoxide emissions from vehicles with less sophisticated emissions controls. It also dilutes sulfur and aromatic contents and improves octane. Because newer vehicles with more sophisticated emissions controls show little or no change in emissions with the addition of oxygen to gasoline, ethanol blending in the future will depend largely on octane requirements, limits on gasoline sulfur and aromatics levels, and mandates for the use of renewable motor fuels. 

Ethanol production from starches and sugars, such as corn, is a well-known technology that continues to evolve. In the United States, most fuel ethanol currently is distilled from corn, yielding byproducts that are used as supplements in animal feed. Three factors may limit ethanol production from starchy and sugary crops: all such crops are also used for food, and only a limited fraction of the available supply could be diverted for fuel use without driving up crop prices to the point where ethanol production would no longer be economical; there is a limit to the amount of suitable land available for growing the feedstock crops; and only a portion of the plant material from the feedstock can be used to produce ethanol. For example, corn grain can be used in ethanol plants, but the stalks, husks, and leaves are waste material, only some of which needs to be left on cornfields to prevent erosion and replenish soil nutrients. 

The underutilization of crop residue has driven decades of research into ethanol production from cellulose; however, several obstacles continue to prevent commercialization of the process, including how to accelerate the hydrolysis reaction that breaks down cellulose fibers and what to do with the lignin byproduct. Research on acid hydrolysis and enzymatic hydrolysis is ongoing. The favored proposal for dealing with the lignin is to use it as a fuel for CHP plants, which could provide both thermal energy and electricity for cellulose ethanol plants, as well as electricity for the grid; however, CHP plants are expensive. 

Currently, Canada’s Iogen Corporation is trying to commercialize an enzymatic hydrolysis technology for ethanol production. The company estimates that a plant with ethanol capacity of 50 million gallons per year and lignin-fired CHP will cost about $300 million to build. By comparison, a corn ethanol plant with a capacity of 50 million gallons per year could be built for about $65 million, and the owners would not bear the risk associated with a new technology. Co-location of cellulose ethanol plants with existing coal-fired electric power plants could reduce the capital cost of the ethanol plants but would also limit siting possibilities. 

Electricity Production 

Some of the electricity generating technologies and fuels represented in NEMS are currently uneconomical, and there are still other fossil, renewable, and nuclear options under development that are not explicitly represented. Those technologies are not expected to be important throughout most of the projections, but with successful development they could have impacts in the market in the later years. 

Fossil Fuels 

Advanced Coal Power. FutureGen is a demonstration project announced by DOE in February 2003 that will have 275 megawatts of electricity generation capacity and will also produce hydrogen for other uses. Of the project’s $1 billion cost, 80 percent will come from DOE, and 20 percent is expected to be provided through a consortium of firms from the coal and electric power industries. The demonstration plant, fueled by coal, will include carbon capture and sequestration equipment to limit GHG emissions. It will operate in an IGCC configuration and sequester approximately 1 million metric tons of CO₂ annually. The sequestered CO₂ will be used to enhance oil recovery in depleted oil fields. SO₂ and mercury emissions from the plant will also be captured. 

In 2003, it was anticipated that the FutureGen project would be operational within 10 years. Site selection and environmental impact studies are expected to be completed in 2007. The site must include geological formations that can be used to store at least 90 percent of the plant’s CO₂ emissions, with an annual leakage rate below 0.01 percent. 

If the project proves to be technically and economically successful, it could offer a partial solution for the continued use of fossil fuels without contributing further to rising atmospheric concentrations of GHGs, by injecting CO₂ into depleted oil and gas wells while adequate space is available. Coal gasification plants with carbon capture and sequestration equipment have yet to be demonstrated, however, and many challenges remain. The capital costs for IGCC plants with carbon capture and sequestration equipment are much higher than those for conventional coal-fired plants, and their conversion efficiencies are lower. Moreover, the current conventional solvent-based absorption process for carbon capture remains energy intensive. 

Advanced Fuel Cells. Fuel cells operate similarly to batteries but do not lose their charge. Instead, they rely on a supply of hydrogen, which is broken into free protons and electrons within the cell. There are several types of fuel cells, using different materials and operating at different temperatures. Stationary power fuel cells can be connected to the electricity grid, and smaller cells are envisioned for the transportation sector. Although the costs of fuel cells have been reduced since their inception, they currently remain too high for widespread market penetration. 

Phosphoric acid fuel cells, which operate at relatively low temperatures, are currently being used in several applications with efficiency rates of 37 to 42 percent. An advantage of this cell type is that relatively impure hydrogen is tolerated, broadening the source of potential fuels. The major disadvantage is the high cost of the platinum catalyst. 

Molten carbonate fuel cells, which use nickel in place of more costly metals, can achieve a 50-percent efficiency rate and are operating experimentally as power plants. Solid oxide fuel cells, also currently being developed, use ceramic materials, operate at relatively high temperatures, and can achieve similar efficiencies of around 50 percent. They have applications in the electric power sector, providing exhaust to turn gas turbines, and could also have future uses in the transportation sector. 

The costs of fuel cells must be reduced significantly before they can become competitive in U.S. markets, and an inexpensive, plentiful source of hydrogen fuel must also be found. If those hurdles can be met, fuel cells offer several advantages over current generation technologies: they are small, quiet, and clean, and because no combustion is involved, their only byproduct is water. 

Carbon Capture with Sequestration 

Capturing CO₂ from the combustion of fossil fuels may allow for their continued use without significant additional contributions to GHG emissions and global warming. Currently, however, sequestration technologies are too costly for implementation on a significant scale. One of the greatest challenges is separation of CO₂ from other emissions, given typical CO₂ concentrations of 3 to 12 percent in the smokestack gases of coal-fired power plants. 

One potential solution for capturing CO₂ is the use of amine scrubbers. Amines react with CO₂, and the resulting product can be heated and separated in a desorber. Another option is the IGCC process to be used in FutureGen, which will produce highly concentrated CO₂ ready for storage. 

Carbon storage will most likely be underground. For example, enhanced oil recovery technologies pump CO₂ into depleted oil and natural gas fields to extend their yields and lifetimes. Other options include placing the CO₂ in coalbeds and saline formations. Ocean storage is a possibility, although the potential environmental impacts are unknown. Preliminary geological studies have shown that underground storage, if successful, has the potential to store all the CO₂ from industrial and power sector emissions for several decades. Major issues include the proximity of the geologic storage formations to potential CO₂ production sites, the long-term permanence of the storage sites, and the development of the monitoring systems needed to ensure that leakage is limited and controlled. 

In 2005, DOE announced the second phase of seven partnerships involving small, field-level demonstrations to determine the feasibility of carbon sequestration technologies. In one project, ConocoPhillips, Shell, and Scottish and Southern Energy will begin designing the world’s first industrial-scale facility to generate “carbon-free electricity” from hydrogen. The planned project will convert natural gas to hydrogen and CO₂, then use the hydrogen gas as fuel for a 350-megawatt power station, reducing the amount of CO₂ emitted to the atmosphere by 90 percent. The CO₂ will be exported to a North Sea oil reservoir for increased oil recovery and eventual storage. Smaller demonstration projects are already operating in Algeria and Norway. 

Renewables 

In the face of international concern over GHG emissions, the eventual peaking of world oil production, and recent volatility in fossil fuel prices, many have seen promise in exploiting an ever-increasing range of renewable energy resources. Renewable energy resources used to generate electricity generally reduce net GHG emissions compared to fossil generation, are accepted as being nondepletable on a time scale of interest to society, and tend to have low and stable operating costs. 

To date, however, market adoption of most renewable technologies has been limited by the significant capital expense of capturing and concentrating the often diffuse energy fluxes of wind, solar, ocean, and other renewable resources. With the most successful renewable generation technology, hydropower, nature has largely concentrated the diffuse energy of falling water through the geography of watersheds. The challenge for emerging technologies, as well as those on the horizon, will be to minimize both the monetary and environmental costs of collecting and converting renewable energy fuels to more portable and useful forms. 

Wind. Through a combination of significant cost reductions over the past 20 years and policy support in the United States, Europe, and elsewhere, electricity generation from wind energy has increased substantially over the past 5 to 10 years. In fact, in some areas of Western Europe, viable new sites for wind are seen as severely limited, because the best sites already are being exploited, leaving sites with poor resources, too close to populated areas, and/or in otherwise undesirable locations. In response, a number of European countries have begun to build wind plants offshore, where they are more remote from population centers and can take advantage of better resources. Although firm data on costs has been scarce, it is believed that offshore wind plants cost substantially more to construct, to transmit power, and to maintain than comparable onshore wind plants. 

There have been a number of proposals for offshore wind plants in the United States, including at least two under serious consideration for near-term development, off Cape Cod, Massachusetts, and Long Island, New York. The United States has substantially larger and better wind resources than most countries of Europe, and thus is unlikely to see its onshore resources exhausted in the mid-term outlook. Still, localized factors such as State renewable energy requirements and constraints on electricity transmission from conventional power plants into coastal areas may make some offshore resources economically attractive, despite the abundance of lower cost wind resources further inland. Because NEMS models 13 relatively large electricity markets, it cannot fully account for localized effects at the State or metropolitan level, and thus is likely to miss the few economical opportunities for offshore development of wind-powered generators. 

Hydropower. In addition to ocean-based wind power technologies, there are a number of technologies that could harness energy directly from ocean waters. They include wave energy technologies (which indirectly harness wind energy, in that ocean waves usually are driven by surface winds), tidal energy technologies, “in-stream” hydropower, and ocean thermal energy technologies. 

Although a number of wave energy technologies are under development, including some that may be near pre-commercial demonstration, the publicly available data on resource quantity, quality, and distribution and on technology cost and performance are inadequate to describe the specifics of the technologies. A handful of tidal power stations around the world do operate on a commercial basis, but prime tidal resources are limited, and the technology seems unlikely to achieve substantial market penetration unless more marginal resources can be harnessed economically. 

In-stream hydropower technologies generally use freestanding or tethered hydraulic turbines to capture the kinetic energy of river, ocean, or tidal currents without dams or diversions. As with wave energy technologies, while some of these technologies appear to be in fairly advanced pre-commercial development, there is insufficient available information to support reasonable market assessment within the NEMS framework. 

Ocean thermal technologies harness energy from temperature differentials between surface waters and waters at depth. These technologies have received funding from the Federal Government in the past, and U.S. development continues today under fully private funding. To date, however, there have been no new pre-commercial demonstrations beyond those previously funded by the Federal Government. Resources suitable for ocean thermal energy development are geographically limited to tropical or near-tropical waters near land, with a relatively steep continental shelf. (Although a fully offshore deepwater technology is plausible, it would be significantly more expensive than a shore-based implementation.) These requirements eliminate virtually the entire continental United States as a potential resource base, and the technology is not included in AEO2006. 

Geothermal. Although U.S. geothermal resources have been exploited for decades to produce electricity, commercial development to date has been limited to hydrothermal deposits at relatively shallow depths. In hydrothermal deposits, hot rock close to the surface heats naturally occurring groundwater, which is extracted at relatively low cost to drive a conventional generator. Steam may be used directly from the ground, or superheated water may be used to heat a secondary working fluid that drives the turbine. Suitable hydrothermal deposits, however, are limited in quantity and location, and in most cases they would be too expensive for development in the mid-term. Enhanced geothermal technologies to exploit deeper, drier resources are not likely to be cost-effective for widespread commercial deployment until well after 2030. 

Solar. Sunlight is a renewable resource that is almost universally available. NEMS models several different technologies for harnessing solar energy, including PV cells deployed at end-user locations, PV deployed at central, utility-owned locations, and thermal conversion of sunlight to electricity. Each is based on commercially available technologies, with substantial allowances made for future improvements in cost and performance. In view of the significant contribution of government-funded R&D to the progress of solar energy technologies, much of the future improvements occur independently from actual market growth (although significant market growth is projected). 

Research is continuing on a number of solar technologies—both direct conversion and thermal conversion—that could substantially improve the efficiency or reduce the cost of producing electricity from sunlight. Examples include organic PV, highly concentrated PV, “solar chimneys,” and a range of improvements to PV efficiency and manufacturing. Given the wide variety of potential technologies and uncertainty as to the success of any particular one, solar technology is modeled from the known cost and performance parameters of commercial technologies, along with both production-based and production-independent improvements in cost and performance. 

Hydrogen 

Widespread use of hydrogen as an energy carrier has been presented by some as a long-term solution to the limitations of our largely fossil-energy based economy. Significant quantities of molecular hydrogen (H₂) are not found in nature but must be released from water, hydrocarbons, or other “chemical reservoirs” of hydrogen. Thus, hydrogen is an energy carrier, in much the same way that electricity is an energy carrier, rather than a primary source of energy. Hydrogen has a wide variety of potential end uses, including the production of electricity; but hydrogen production based on fossil fuels (primarily through methane steam reforming or other thermochemical processes), currently the least costly means of production, would at best provide only limited relief from the use of fossil fuels (by increasing the efficiency of energy end uses) and potentially could lead to more use of fossil fuels (by reducing overall “wells-to-wheels” system efficiency). 

Hydrogen could also be produced from non-fossil fuels, including nuclear and renewable resources, either through electrolysis of water or by direct thermochemical conversion. Significant use of hydrogen would likely evolve as a system, with development and deployment of technologies for production, distribution, and end use closely linked. Many technologies for producing hydrogen are commercially available today, but they are expensive. Without significant technological progress, it seems unlikely that substantial incremental amounts of hydrogen will be produced before 2030. 

Nuclear 

The nuclear cost assumptions for AEO2006 are based on the realized costs of advanced nuclear power plants whose designs have been certified by the U.S. Nuclear Regulatory Commission (NRC) and/or have been built somewhere in the world—specifically, the generation 3 light-water reactors (LWRs). To account for technological improvements, it is assumed that costs will fall, with cost reductions reflecting incremental improvements in the designs of reactors as they evolve from the generation 3 to generation 3+. Recently, some vendors have reported cost estimates for generation 3+ reactors that are much lower than those assumed in NEMS, even after allowing for cost reductions; however, their estimates were based on incomplete designs, and history has shown that cost estimates based on incomplete designs tend to be unreliable [44]. For AEO2006, the vendor estimates are used in a sensitivity analysis. 

Although the nuclear capital cost assumptions used in both the reference case and the sensitivity analysis are representative of the costs of building LWRs whose designs reflect incremental improvements over those that have been built in the Far East or are being built in Europe, a number of small-scale and large-scale LWR designs that differ significantly from generation 3 plants could be commercially available by 2030 [45]. Because of technical and economic uncertainties, however, they are not included in AEO2006. 

A number of non-LWR designs for nuclear power plants have also been suggested, including variants on the traditional fast breeder technology, such as lead-cooled and sodium-cooled reactors. These designs are often referred to as “generation 4” nuclear power plants. The technologies have all the advantages and disadvantages of the traditional breeder reactors that have been built in Europe and the Far East, and because of their large size they would be more economically advantageous in regulated electricity markets, where financial risks are not borne entirely by investors. 

Examples of the small, modular power plant designs include the Pebble Bed Modular Reactor (PBMR), the Gas-Turbine Modular Helium (GT-MH) reactor and the International Reactor Innovative and Secure (IRIS) reactor. In theory at least, these plants might be built in competitive markets where it is economically advantageous to add small amounts of capacity in response to volatile and uncertain electricity prices [46]. 

The PBMR and the GT-MH reactor are also designed to operate at much higher temperatures than the LWRs currently in operation. Thus, both of these designs could potentially be used to produce both electricity and hydrogen. In fact, EPACT2005 authorizes $1.25 billion to build a prototype of such a reactor that could be used to cogenerate electricity and hydrogen. The law specifies that a prototype reactor should be completed by 2021. The economic potential of such a reactor is considerable, in that the hydrogen could be used in fuel cells or in other industrial processes; however, the technological uncertainties involved are substantial.

Notes and Sources

Contact: Alan Beamon
Phone: 202-586-2025
E-mail: joseph.beamon@eia.doe.gov