Energy Supply Systems
Energy supply can come from a wide variety of systems. Since most of them are discussed extensively in the technical literature, the panel does not attempt here to provide a comprehensive review. Rather, the panel indicates the range of possible energy supply systems in the United States and their implications for greenhouse gas emissions at the current time. The panel leaves to more specialized analyses the detailed consideration of system design and selection. Projections as to the cost and path of technological development of various energy supply systems in the future are not attempted, but are discussed generally in terms of their relevance to greenhouse warming.
Our energy supply is currently obtained in basically three ways: (1) combustion of fossil fuels such as oil, natural gas, and coal; (2) nuclear fission; and (3) other nonfossil-fuel-based sources such as biomass and hydroelectric power. The level at which we use each of these primary energy sources has a major impact on greenhouse gas emissions, primarily because of the differing levels of CO2 that these sources introduce into the atmosphere.
It is particularly relevant to examine how fossil fuels are used since they are currently our principal source of energy. One estimate of the carbon contained in fossil fuels, and hence of the potential for mankind to alter the CO2 concentration of the atmosphere, is given in Table 24.1 (Fulkerson et al., 1989). The atmosphere currently contains about 750 Gt of carbon as CO21Figure 24.1 documents the course of fossil fuel burning over the last 30 years and the simultaneous increase in the mass of atmospheric CO2.
The mass of carbon in the recoverable resources of conventional oil and natural gas (250 Gt C, see Table 24.1) is notably smaller than the mass of carbon in the atmosphere (750 Gt C, where 1 ppmv of CO2 in the atmosphere is equal to 2.13 Gt C). Consequently, the CO2 doubling so often
TABLE 24.1 Estimated Remaining Recoverable World Resources of Fossil Fuels and Their Potential Effect on Atmospheric CO2
examined in climate models could not be accomplished even if all of the conventional oil and gas were burned. The world recoverable resources of coal, on the other hand, are very large. Over the long term, if mankind is to produce perturbations of atmospheric CO2 up to and beyond a doubling, it will be because of the oxidation of large quantities of coal and low-grade, unconventional fuels such as oil shale. Estimates of ultimately recoverable resources are, of course, very uncertain. As currently understood, world recoverable resources of coal are heavily concentrated in three large northern hemisphere nations: the United States, the former USSR, and the People's Republic of China. These three nations contain an estimated 87 percent of world recoverable resources of coal.
As primary sources of usable energy, fossil fuels release heat through the exothermic reaction of atmospheric oxygen with the carbon and hydrogen of fuel. The consequent release of CO2 is fundamentally different from many traditional pollutant releases in which a low grade (e.g., trace metal) or otherwise unintended (e.g., CO or SO2) by-product is released to the environment or a purposeful product reaches beyond its intended application (e.g., pesticides). The emission of CO2 is an essential consequence of burning fossil fuels.
Largely because the carbon to hydrogen ratios of fossil fuels differ, their rate of CO2 production per unit of useful energy differs. Natural gas is principally CH4, with a 1:4 ratio of carbon to hydrogen, and it releases 13.8 kg C per gigajoule (GJ). Although coal has a wide range of chemical compositions, it contains less hydrogen than natural gas, and to a first approximation the heating value varies with the carbon content. The value 24.1 kg C/GJ can be used to estimate the CO2 release on combustion for most coals, although for very low grade coals this ratio increases slightly. Liquid petroleum products fall somewhere in between natural gas and coal. The CO2 release for average world crude oil (and hence the average for a mixture for all products) can be taken at about 19.9 kg C/GJ. For a discrete refined product, the value differs: for example, 18.5 is appropriate for automotive gasoline (Marland, 1983).
While CO2 can be intimately and accurately related to fossil fuel combustion, there are other, less well characterized, greenhouse gas emissions from the fossil fuel cycle. The production, processing, and distribution of natural gas inevitably allow some CH4 to escape to the atmosphere, and the natural gas that is associated with petroleum production can result in venting (as CH4) or flaring (to produce CO2). Methane also exists dispersed in coal seams and is generally released to the atmosphere during coal mining.
Nitrous oxide (N2O) emissions from fossil fuel combustion may be very small. Recent studies (Muzio et al., 1989) have cast doubt on all earlier measurements, and it is not now clear how much N2O is released during combustion processes. (Note that N2O is different from the more common oxides of nitrogen (NOx)NO and NO2associated with fuel combustion.)
An initial step in looking at recent trends is to review the sources of the U.S. energy supply, and these are shown in Figure 24.2. Oil is the largest source of energy supply at 41 percent, and coal is second at 23 percent. Renewables account for 8 percent, with hydropower providing almost half
of that. Biomass used in the industrial, buildings, and electricity sectors provides roughly the same amount of energy as hydropower. Very little energy currently comes from solar, wind, geothermal, or other sources of renewable energy (Solar Energy Research Institute, 1990).
Table 24.2 shows electricity generation and the carbon emissions from generation in the United States in 1988. Coal is the largest generation source of U.S. electricity at 57 percent, with nuclear second at 19.5 percent. Renewables represent only a small portion of U.S. electric power generation. Electricity generation in the United States is responsible for approximately 35 percent of U.S. CO2 emissions and 8 percent of worldwide anthropogenic CO2 emissions (Edmonds et al., 1989).
To contrast the various energy systems and their greenhouse gas implications, it is necessary to inventory full fuel cycle costs. For a gasoline-powered automobile, for example, CO2 emissions are not simply those discharged from the engine but also those CO2 (and other trace gas) emissions discharged during petroleum exploration, production, refining, and product distribution.
Although there are many difficulties in detail with using a CO2 accounting, in theory comparisons can be made. One estimate is that for every direct use of liquid fuel, CO2 emissions equivalent to those that would result from the use of an additional 11.8 percent of petroleum products are produced in activities upstream from the final products at the refinery. Under this accounting system, these greenhouse gas emissions should be charged
TABLE 24.2 Electric Power Generation in the United States, 1988
at the point of product use. Similar values for natural gas and coal are less well established but have been estimated at 18.8 percent for gas delivered to the customer and 2.2 percent for coal at the minehead (Marland, 1983).
In the 1987 global economy, 95 percent of total commercial energy (energy that is traded in commercial markets but not including ''traditional fuels" such as wood) was produced from fossil fuels. This varied from virtually 100 percent in some resource-poor countries largely dependent on imported petroleum, to 62 percent for France (where 77 percent of electricity is from nuclear plants) and 29 percent for Norway (where hydroelectric plants contribute a large fraction of the total energy). The value was 89 percent in the United States. (These fractions are based on numbers from the United Nations, but they count nuclear power and hydroelectricity at their conventional fuel equivalents by assuming fuels could be converted to electricity at a 33 percent net plant conversion efficiency.)
On the global scale, petroleum contributes the largest share (44 percent) of the energy from fossil fuels, with coal (32 percent) and natural gas (24 percent) following, but coal is the dominant fuel in a number of countries (China, India, and the former German Democratic Republic). In the United States, 83 percent of coal is used in electric power plants and another 5 percent is used in the iron and steel industry (Organization for Economic Cooperation and Development, 1987). The transportation sector is the largest user of petroleum in the United States (62 percent), with the remainder spread over many applications, including nonfuel applications (some of which do not emit greenhouse gases). Twenty-five percent of U.S. natural gas is used in residences, with another 17 percent used for electric power generation and the remainder scattered throughout the commercial and industrial sectors (U.S. Department of Energy, 1988).
Emission Control Methods
A number of alternatives are available for reducing net greenhouse gas emissions from the production of energy. In this chapter, the discussion is divided into two major topics. Energy supply systems purely for electricity generation are discussed first. Then energy supply systems on a broader basis are examined. Some examples of existing efficient energy systems are given, and a concept called integrated energy systems is discussed. The relevance of new fuel supply and conversion options is treated in this context. Following the descriptions of the technical options, a separate section illustrates how the cost-effectiveness of different options can be compared. Because of the number and complexity of options available, it is not possible to make this discussion comprehensive and all-inclusive. Rather the attempt here is to convey a picture of the technological options available and the methodology employed.
Electricity can be generated from coal, oil, natural gas, nuclear energy, and a variety of renewable forms of energy including hydraulic resources, wind, geothermal, solar thermal, and solar photovoltaic energy. With the exception of oil, each is discussed below. Although oil historically has been used for power generation in some regions of the United States (principally in the Northeast), its use has declined dramatically in the past decade and no significant increase is foreseen. The primary use of oil for electricity and steam generation in the United States is in the industrial sector, which is discussed in Chapter 22. The power generation technology options discussed below for coal and natural gas also are applicable to oil in many instances.
Coal is the most abundant fossil fuel resource in the United States and is the principal fuel powering the economies of several other nations including China and the former USSR. Coal is used primarily for electric power generation, but also for industrial process heat and, in some cases (mostly in developing countries), domestic heating and cooking. Barring severe environmental repercussions, coal is likely to continue to be a major energy source for power generation and other energy needs well into the twenty-first century.
From the point of view of greenhouse gas emissions, the principal issues are the quantities of coal that will be used and the efficiency of coal combustion and energy conversion. Conventional pulverized-coal-fired power plants now being built are capable of overall thermal efficiencies (the efficiency with which coal is converted to electricity) of about 38 percent without scrubbers (the SO2 removal systems that reduce emissions of acid rain precursors but also reduce net power plant efficiency). The average for all coal-fired power plants now in place in the United States, however, is about 33 percent (U.S. Department of Energy, 1989).
Several technological developments hold promise for continued improvement in coal-based electric power generation (Rubin, 1989). Table 24.3 summarizes performance estimates by the Electric Power Research Institute (EPRI) for several power generation options, which range from improvements in current technology to newer systems not yet commercially demonstrated (Electric Power Research Institute, 1986).
Overall, efficiency improvements on the order of 10 percent or more are expected from technological advances over the next decade. The most promising near-term options include integrated gasification combined cycle (IGCC) systems and pressurized fluidized-bed combustion (PFBC) systems. The latter technology is planned for demonstration in the United States
TABLE 24.3 Efficiency of Coal-Based Power Generation Systems
under the Department of Energy's (DOE's) Clean Coal Technology Program, and other PFBC demonstration plants are being constructed in Europe.
Integrated gasification combined cycle technology has been demonstrated at the 100-MW scale at the Cool Water Facility operated by Southern California Edison. Although a number of U.S. utilities are studying the feasibility of building additional IGCC capacity, that technology in most cases is not yet economically competitive with conventional pulverized coal combustion. Advanced IGCC designs employing the concept of "hot gas cleanup" (i.e., removing pollutants without having first to cool the flue gas) hold promise of greater efficiency gains and lower cost (Bajura, 1989). Such technologies are currently under development.
In the near term, boiler repowering, in which an older existing unit is replaced with a more efficient new one, is another method by which the overall efficiency of coal utilization can be improved. In this type of application, atmospheric fluidized-bed combustion (AFBC) units may be attractive because of their compact size and fuel versatility. Several repowering projects are now under way in the United States using AFBC boilers.
As mentioned above, a negative impact on CO2 emission can result from the flue gas desulfurization (FGD) systems, or "scrubbers," used to remove SO2. Because the energy needed to operate the scrubber reduces overall power plant efficiency, CO2 emissions per unit of useful electricity increase proportionately. Modern FGD systems require only 1 to 2 percent of the power plant output for operation, down by a factor of 2 from systems built in the early 1980s. This improvement has resulted from more efficient scrubber designs and the elimination of stack gas reheat systems.
Fluidized-bed combustion systems have a comparable loss of thermal energy when limestone is used for SO2 control. The SO2 removal systems using lime or limestone reagents (whether in scrubbers or fluidized beds) release additional CO2 directly through the chemistry of sulfur removal. This additional CO2 stream is small, however, in comparison with the CO2 emissions from coal combustion.
There are small differences in CO2 emissions due to differences in coal quality. In general, coals with higher sulfur content emit less CO2 per unit of energy, complicating any policy designed to reduce both CO2 and SO2 emissions. High-rank bituminous coals produce 5 to 10 percent less CO2 than do lower-rank subbituminous and lignite coals (Winschel, 1990); however, most coals actually burned at the present time fall within a narrower range of 2 to 3 percent. Thus the differences in CO2 emissions resulting from the combustion of different coal types are roughly the same order of magnitude as the reductions anticipated from near-term combustion efficiency improvements.
For the immediate future, perhaps the most cost-effective means of CO2 reduction from existing coal-fired power plants lies in heat rate (efficiency) improvements achievable by improved plant maintenance and operation. EPRI estimates that such measures could result in a 2 to 4 percent reduction in current CO2 emissions at a very small cost (Gluckman, 1990). The resulting efficiency improvements have the potential for saving roughly 2 to 4 percent in fuel consumption, offsetting the small costs that are incurred (and perhaps even generating net additional revenues and thus yielding a net negative cost of CO2 abatement). Heat rate improvements are actively being pursued by many utilities today.
Finally, future developments for coal-fired power plants conceivably could include control technology for the removal of CO2 from flue gases. This option, which could apply generally to fossil fuels, is discussed later in this chapter.
As pointed out previously, the combustion of natural gas emits less CO2 than the combustion of coal because of the higher ratio of hydrogen to
carbon. There are a number of ways natural gas can be used in place of coal for electricity generation.
Combined Cycle Systems In a gas turbine combined cycle (GTCC) system, the exhaust from a gas turbine is fed into a residual heat boiler that generates steam for a bottoming steam turbine cycle. If natural gas is used to fuel the gas turbine, the overall efficiency of the system can be slightly more than 50 percent. The capital cost of such a system is about $500/kW. Combined cycle systems have not been considered a serious option in the planning of future power generation until very recently, largely because of the uncertainty in the availability of natural gas and the poor reliability of GTCC systems in the past. The latter was not due to inherent technical barriers but to a lack of attention from the industry.
Two recent events changed the situation. First, EPRI, in cooperation with Southern California Edison and Texaco, proposed the organization of a consortium to develop a $300 million IGCC systemthe Cool Water project. For the first time, the issue of the reliability of combined cycle systems received serious attention. Second, Japan, in an effort to diversify energy sources, ordered several gigawatts of combined cycle systems to use liquefied natural gas.
Further, as discussed in a number of reports (e.g., Tabors and Flagg, 1986), GTCC is competitive economically with alternative forms of energy supply. The attractiveness of GTCCs, therefore, has been broadly recognized both in its economics and in its potential contribution to the reduction of greenhouse gases.
Other Natural Gas Options One of the most difficult issues in the global greenhouse warming problem is how developing nations can participate in mitigation efforts without damaging their economic development. Some of these nations might require options with capital costs even lower than those of GTCC. Steam injection in aircraft-type gas turbines might be an option to consider, even though the efficiency may be slightly lower (Williams, 1989). For small plants, El-Masri (1988) has proposed a regenerative system that is attractive from the viewpoints of both cost and efficiency. This system has not yet been tried, but the technical and economic basis is sufficiently sound to warrant consideration. In addition, the Kalina cycle, a type of steam cycle used in conjunction with a natural gas turbine, can have an efficiency of more than 55 percent with today's commercial gas turbines (Exergy Inc., 1989).
Apart from the CO2 emitted in the exploration, production, and enrichment of uranium, nuclear plants do not emit CO2. Reactors based on nuclear fission have operated for many years and provide a significant contribution
to the production of electric power in many countries of the world19 percent in the United States.
In the United States, however, the nuclear reactor market is, for all practical purposes, moribund, in spite of industry's efforts to reactivate it. There are five concerns:
• waste disposal,
• proliferation, and
The lack of acceptance of nuclear power in the United States is a complex issue. Utilities are no longer willing to order new nuclear plants, principally because of economics and perceived financial risk. The unattractive economics of nuclear energy is due to a host of problems. Another concern is the current lack of radioactive waste disposal facilities in the United States.
Utility companies argue that the present generation of reactors is safe enough and can be improved further by the ongoing development work on advanced light water reactors both in and outside the United States. Nonetheless, passively safe reactors have been proposed by others as alternatives. By definition, a passively safe reactor requires no action by any component or subsystem to prevent an accident. This is different from the "defense in depth" concept of present reactors, in which, if there is a malfunction, other systems will intervene. However, whether any specific reactor technology is passively safe is often a subject for debate.
Appendix G provides a description of some of the proposed new technologies. These descriptions are not intended to be a comprehensive and critical analysis of the technological options for future development of nuclear power nor an endorsement of particular technologies. Such an analysis will be provided in a forthcoming report by a committee of the National Research Council's Energy Engineering Board.
Proliferation may be the ultimate problem of nuclear energy. There will always be the fear that an irresponsible party may develop a nuclear weapon capability with the help of plutonium from recycled power reactor fuel. Proliferation is an international issue. Whether greenhouse warming will stimulate a new international cooperative effort on proliferation, only time will tell.
A long-term commitment to nuclear power would also confront the resource issue. Is there enough uranium for nuclear energy to have a significant impact? To give some perspective on this issue, Weinberg (1989) proposed the following assumptions:
• In the year 2040 the world will require 500 quads of energy (the current figure is 300 quads); 2
• If the present trend of retaining only half of the CO2 emitted in the atmosphere continues, the CO2 concentration in the atmosphere can be stabilized if the emission is limited to 3 Gt C/yr (the total emission is currently about 6 Gt C/yr). (This is a controversial "if.")
• All nonfission, nonfossil sources will supply 50 quads/yr by 2040.
Weinberg raised the question of whether there is enough uranium to supply 300 quads of primary energy with nuclear energy (limiting the fossil supply to 150 quads). This would mean 5000 reactors, or 10 times the number of nuclear reactors now in existence worldwide. Weinberg estimated that at $130/kg, there may be 31 × 106 tons of uranium if one includes the speculative resources (Organization for Economic Cooperation and Development, IEA, 1983). With that much uranium, the 5000 reactors could be sustained for about 40 years without recycle, 80 years with recycle, and 2000 years with breeders.
Weinberg also raised the question of the importance, at this scale, of the energy needed in the production of uranium, in particular the CO2 emitted from fossil fuels used for uranium mining and processing. The analysis of Rotty et al. (1976) showed that this is a small fraction of the CO2 from a comparable coal-fired plant.
Each of these nuclear fission issuessafety, economics, waste disposal, proliferation, and resourcesis currently being addressed by the Energy Engineering Board committee. The committee's report, projected for release in 1992, will discuss what is needed to preserve nuclear power as an option. It should shed more light on the complex problem of nuclear power acceptance.
An alternative nuclear option that has been under development since the 1950s is nuclear fusion. The theoretical attractiveness of this concept is why the efforts in many countries have continued. It has the potential to solve many of the safety and environmental concerns of nuclear fission, but the technical and economic feasibility have yet to be proven. Considering the advances needed, fusion cannot be considered an energy option at this time. Research and development should continue, however. A brief description of the state of the art can be found in Appendix G.
In summary, acceptance of nuclear energy as a principal source of energy supply would change in important respects the prospects of greatly reducing the discharge of CO2 into the atmosphere. Whether this is feasible is a complex question that goes beyond the charge of this panel, which here limits itself to observing nuclear energy's close connection with the problem of greenhouse warming.
In addition to energy supply systems that rely on the extraction, consumption, and ultimate depletion of resources, there are others that rely on
natural energy flows and, hence, are renewable if not inexhaustible. These range from the large and virtually inexhaustible flow of energy from the sun, to the smaller but still inexhaustible flow of water from high elevation, to the comparatively small and probably exhaustible flow of steam or hot water in wet geothermal systems.
For the application of each of these energy sources, one needs to inquire into the magnitude of the flow that can be tapped, the cost of doing so, and the ecological repercussions of altering or harnessing the natural flows. A series of new questions involving factors such as regional distribution and energy storage must also be confronted. Each of these energy supply systems is presumably sustainable at some level with little or no net CO2 release other than from fossil fuel investments in plant capital and fossil fuel supplements to system operation. In the latter case, especially, it is apparent that CO2 emissions are a function of energy supply system design and are not inherent in system utilization (as is the case with fossil fuel burning). As an example, ethanol fuels could theoretically be derived from a sustainable corn crop with all of the carbon recycled and no net CO2 emissions to the atmosphere.
On the other hand, the current ethanol production system uses diesel fuel to plant and harvest corn, natural gas to produce nitrogen fertilizers, and coal to generate power and heat for grinding and processing. The result is that total energy supply system CO2 emissions from ethanol use in the United States are nearly as high (80 percent) (Marland and Turnhollow, 1990) as those from the direct utilization of gasoline as a motor fuel. This need not be the case, however, because the system could operate with ethanol fuels for farm machinery and nuclear electricity for corn processing.
In general, it is useful to keep in mind both how each energy supply system currently operates at the margin of the U.S. or world economy and how it could operate in a closed economy or if it were a dominant component of the energy supply.
The list of technologies in this class includes hydroelectric, wind, geothermal, solar photovoltaic, and solar thermal electric.
Hydroelectric Power Conventional hydroelectric generation currently represents 12 percent of the total U.S. electricity supply, with an installed capacity of approximately 69,000 MW and an identifiable potential for another 46,000 MW of capacity (Fulkerson et al., 1989). However, the real potential for future development is undoubtedly less than this because of competing demands on water and other resources. Fulkerson et al. (1989) estimate that hydroelectric systems could produce an additional 125 million kilowatt hours (MkWh) of electricity annually in the United States, from a base of 231 MkWh, but the Solar Energy Research Institute (1990) estimates the increased capacity by 2030 will be less than one-fifth of Fulkerson's potential 46,000 MW.
Wind Energy More than 660 MW of installed capacity of wind-generated electric power exists in the United States (Fulkerson et al., 1989). Substantial additional resources exist, but a precise estimate is hard to achieve because of the importance of site-specific characteristics that include the temporal variability of the wind. Wind power is on the threshold of economic viability, and advances in technology, economics, and resource analysis can be expected. The Solar Energy Research Institute (1990) maintains that "wind has the potential to make meaningful contributions in virtually all areas of the country."
Geothermal Energy Potentially usable geothermal energy exists at steam vents, in deep hot waters, in hot, dry rocks, and in near-surface magmas. According to the U.S. Geological Survey (USGS), approximately 23,000 MW of electrical power will be available over the next 30 years with current geothermal technology. The CO2 emissions are less than 5 percent of those from coal, and the cost of the 2,800 MW of geothermal electricity currently in production is $0.04 to $0.06/kWh. In California, for example, geothermal resources are currently providing 7 percent of the state's electric power and are displacing 1,700 MW (thermal) of fossil fuels in heating and industrial applications at a cost savings of 25 to 35 percent (Solar Energy Research Institute, 1990). The currently exploited high-quality resource in California is, however, relatively rare.
There are a number of constraints on the development of geothermal energy. First, the majority of present geothermal plants are relatively small, between 1 to 5 MW and 25 to 60 MW, with a few at 110 MW, resulting in a lack of acceptance by utilities. Second, most usable sites are at locations where concerns for scenic values, wildlife issues, or other environmental problems make it difficult to develop the geothermal power. A number of technological constraints limit the development of geothermal energy, including the risk associated with the discovery of the resource, verification of the well size, projection of long-term reservoir performance, well integrity, operational uncertainties, and energy conversion (Solar Energy Research Institute, 1990).
In sum, geothermal energy will probably continue to contribute to the U.S. energy mix, but resource constraints will limit its role in minimizing greenhouse gas emissions.
Solar Photovoltaics Photoelectric technology has experienced considerable progress over the last decade (Hubbard, 1989). Efficiencies of more than 22 percent have been achieved for the conversion of solar to electrical energy under ordinary sunlight. Atlantic Richfield and Pacific Gas and Electric have completed a 6.5-MW power plant, and "tens of thousands of PV [photovoltaic] systems are already providing power for a variety of applications" (Hubbard, 1989), mostly in remote areas. Photovoltaic modules
are now expected to last 20 to 30 years. Hubbard believes that photovoltaic power systems should be competetive for generating central station peaking power by the late 1990s.
Because of the intermittent character of the solar resource, solar power cannot be expected to grow beyond some fraction of total electric power demand unless some form of energy storage can be devised. Displacement of baseline power production for daytime usage plus peaking power accounts for about 17 percent of today's installed capacity, and one study suggests that reliance on photovoltaics for more than 13 percent of powerwithout storage capabilitycould lead to serious problems (Hubbard, 1989).
The potential for photovoltaics to avoid fossil fuel burningand CO2 emissionsis high if costs continue to drop as forecasted and some appropriate scheme can be devised for energy storage. Although solar photovoltaics are relatively expensive at this time, some analysts suggest that continuing developments could reduce the cost by 70 percent (Hubbard, 1989). Further, a viable storage system would increase system potential, albeit at some cost. A more detailed discussion of photovoltaics can be found in Appendix H.
Solar Thermal Electric Systems In California, parabolic trough solar thermal electric systems of 194 MW have been installed. In these systems a parabolic trough concentrator with a highly reflective surface focuses solar energy on a heat-collecting pipe, called the receiver. A fluid, either water or some other heat transfer material, circulates in the pipe, collecting the solar energy and transferring it to the power block of the plant to generate electricity. The design has evolved to a hybrid form in which natural gas is used to extend the operation of the plant during periods of the day when solar energy is unavailable.
With additional development, the cost of electricity from this type of system is expected to improve. Again, the environmental benefits may improve the economic outlook further if externalities are internalized (California Energy Resources, Conservation and Development Commission, 1989). Cost-effectiveness is discussed in Appendix J.
Integrated Energy Systems
Different technologies can be thought of as elements of "integrated energy systems" (IESs). As technologies evolve and externalities are internalized, the economic attractiveness of different energy supply options changes. To the degree that this may occur, the energy supply structure can change to accommodate different ways of supplying energy and of reducing emissions from the generation of that energy. Therefore it is useful to examine some technologies as elements in an energy systems instead of viewing electricity production alone. Integrated energy systems themselves are discussed first,
followed by five technologies that are potential elements in the system: biomass to produce ethanol and methanol; solar energy to produce hydrogen fuels; fuel cells; superconducting cables; and collection and disposal of CO2 in the deep ocean or in natural gas wells.
In integrated energy systems, supply and demand are not treated separately but are considered elements of a system. A number of papers have been written on IESs (e.g., Hafele et al., 1986; Lee et al., 1990). The concept is not new. The oil refinery/petrochemical complex and the steel mill, which have been in existence for years, are two good examples of IESs, even though they are never referred to as such. In an oil streams/petrochemical, there is no clear distinction between product streams and energy streams. Crude oil, liquefied petroleum gas, natural gas, and other industrial gases are the primary materials used, but each is used for many purposes. For example, natural gas is used as fuel in heaters, as a feedstock, or as fuel for the unit making hydrogen. The entire steam cycle is integrated: high-quality steam for turbines and low-quality steam for preheaters. The result is a robust, flexible system, highly efficient and economically sound.
In a steel mill the primary raw materials are coal and iron ore. Despite the mill's huge need for energy, it does not burn coal but uses it as a chemical raw material. The coal is coked. By using the gas released as a fuel, the coal is heated to remove all chemicals, which are recovered. The associated fuel gas is used in both coke ovens and open hearth furnaces. The coke is used as the chemical reducing agent for iron oxide in the blast furnaces.
By extending this experience to energy systems in general, one can formulate the general concept of an IES as shown in Figures 24.3 and 24.4. Although Figure 24.3 contains a number of boxes, representing technological steps, the boxes represent options, not required components. There are five aspects to the system: (1) energy sources, including sunshine, fuels, air, and water; (2) transformation processes (incoming fuels are transformed to
One of the simplest IESs, the co-generation system using natural gas to generate both electricity and heat, can be traced, for example, from gas to combined cycle to electricity, process heat, and steam. Another system can utilize two primary energy sources, nuclear energy and natural gas, for both electricity and process heat generation, with much lower CO2 emissions than would result from burning gas alone.
The heavy lines in Figure 24.4 trace an IES that includes a high-temperature gas-cooled reactor (HTGR), a steam reformer (for the conversion of natural gas to hydrogen and CO), a gas turbine combined cycle system that utilizes CO and oxygen, and a system for gas separation that allows the recovery of CO2 either as a by-product or for disposal. The system is designed to have nuclear fuels, natural gas, and air as inputs and to have electricity, hydrogen, and CO2 as outputs. The economic of such a system
can no longer be assessed as easily as the traditional cents per kilowatt hour calculation. For example, the cost of electricity now depends on the price of hydrogen and CO2. If an end use can be found for the CO2, such as enhanced oil recovery, and hydrogen can be sold at today's market price, the electricity generated can be competitive with that produced by a GTCC system. On the other hand, if hydrogen can be sold at its heating value only, and there is no end use for the CO2, then the cost of electricity is much higher. Under these conditions, one might want to resort to the conventional air-fired gas turbine combined cycle system and also eliminate the gas separation system for the synthesis gas. The CO2 must then be removed downstream. It should be noted that, per kilowatt hour, this system generates much less CO2 because only part of the primary energy is from fossil fuel, the remainder being from nuclear energy. The synthesis gas behaves as the carrier of nuclear energy.
An important feature of the IES concept is the ability to accept and adopt new technologies when they are developed. Systems can be designed with combinations of existing technologies and can be modified to accept new technologies, be they solar photovoltaic or superconducting transmission lines.
Two questions need to be addressed:
1. If IESs are so good, why are they not being used today?
2. What is the role of government if more IESs are to become a reality in the energy economy?
There are two answers to the first question. First, IESs are not the practice today largely because our current economic and business system is not horizontally integrated, but vertically integrated in the energy and chemical sector. (Vertically integrated systems for coal, for example, involve integration from mining to transport to electricity generation. Horizontally integration involves electricity generation, steel mills, and coal gasification for production of synthesis gas.) In spite of that, steel mills and refineries do exist. Second, many of the social costs of energy systems are not internalized. As the emphasis on environmental protection intensifies, some of the social costs may become the responsibility of the polluters in the future. The economics of IESs will then change. One study (Organization for Economic Cooperation and Development, 1981) showed that the costs of SO2 scrubbers can be justified by the social costs of the effects of SO2. Another study (Styrikovich and Chizhov, 1988) showed that the social costs of coal combustion can be higher than the current market price of coal.
Legal, informational, and institutional barriers do exist. The second question is really the other side of the first one. Probably the most critical role of the government is to ensure that viable, horizontally integrated alternatives will not be overlooked because of institutional barriers.
Fuels from wood, grain, herbaceous crops, and urban waste are considered under the collective heading of biomass fuels. Biomass fuels, mostly wood but including animal dung and crop residues, supplied a large fraction of man's energy needs until very recent times, and moving from these traditional fuels to commercial fossil fuels is still often perceived as representing social progress and economic development. This progression may represent environmental progress as well because traditional fuels are often used in very inefficient ways, with large atmospheric effluent streams, and are not produced in a sustainable manner. The challenge for biomass in the future is to ensure a sustainable harvest, possibly from energy plantations, and to develop efficient and nonpolluting systems for fuel conversion and use. Among the attractive features of biomass fuels are that they avoid the storage problems of the intermittent flows of solar energy and that they can be used to provide both central station fuels and liquid transportation fuels.
Great strides are being achieved in the area of biomass yield and conversion efficiency, and Fulkerson et al. (1989) estimate that biomass could supply 14.6 exajoules (EJ) per year of liquid fuels in the United States (31.0 EJ of gross biomass) if all of the options were aggressively pursued.3 At 14.6 EJ/yr, biomass would provide about 40 percent of total U.S. liquid fuel consumption. Current biomass use in the United States is about 3 EJ/yr. The total cost of biomass fuels is strongly influenced by handling and transportation costs, and successful systems are likely to be of modest size so as to rely on short haul distances. Costs would vary considerably from place to place, depending on plantation productivity and handling and transportation costs.
For energy plantations there remain a variety of questions beyond achievable yield. These include the net effect of sequestering carbon (e.g., in soils), the influence on other environmental issues (e.g., low maintenance intensity should lead to less soil erosion than occurs with agricultural crops), the effect on other greenhouse gas emissions (e.g., fertilization could increase N2O emissions), the vulnerability of large monocultural plantations (e.g., to pests and pathogens), the effect on wildlife species (e.g., plantations may provide a limited habitat but could reduce pressures on natural habitats), and competition for space with agricultural crops. The relatively higher productivities of warmer climates suggest that biomass may play a more important role in some areas than others.
Fulkerson et al. (1989) suggest that the most desired biomass sources, ''in order of importance, desirability, and usage are: (1) already collected wastes and residues, (2) commercial forest wood, (3) new terrestrial energy crops, (4) existing agriculture crops devoted to food and feed, and (5) new aquatic crops" (Fulkerson et al., 1989, p. 94). Already-collected waste and
residues are broadly used now for energy purposes, especially in the paper industry, and more thorough and efficient utilization of other waste makes increasing sense, especially in the face of increasing problems and costs associated with waste disposal and landfills. The emphasis here is on biomass harvested specifically for its energy content, and the case of wood from energy plantations is used for illustrative purposes (see Appendix I). Economic analysis of the fuel supply is complicated by the many possible combinations of yield, fertilization, weed control, spacing, and harvest; studies are currently under way to discover optimal combinations.
There are also a variety of possible ways in which the fuel is used, such as direct burning, gasification, or conversion to alcohol. Ostile (1988) suggests that some savings can be achieved from direct burning of wood in place of coal for electric power generation. There is no need, for example, for SO2 removal and handling. Williams (1989) sees an increase in net conversion efficiency with respect to current power plants, through the use of advanced gas turbine technology. Conversion to liquid fuels will involve a cost increase because of the low efficiency of the conversion process in comparison with that of crude oil refining. The most straightforward case for early implementation focuses on the availability and cost of delivered fuel for electric power generation, although the future holds more opportunities as technologies for gasification and liquefaction are developed and demonstrated. Advances in biotechnology could be useful in altering either the biomass yield or the structure of the plant. It has been suggested that displacement of fossil fuels for electric power generation could be accomplished with little or no difference in the cost of electricity other than the difference in delivered cost of fuel (see, for example, Wright and Ehrenshaft, 1990).
Although productivity, harvest costs, and land costs are highly variable, data from which one can derive a useful estimate for the delivered cost of wood chips are provided in Appendix I. This may turn out to be a high estimate of fuel cost if whole trees can be used, thereby avoiding the cost of chipping the wood (Ostlie, 1988). The numbers used in this analysis are based on short-rotation hardwood crops, with a 6-year rotation on marginal cropland in the U.S. Midwest. The assumed yield is 11 t per hectare of dry biomass, with 15 percent of the material lost or consumed for plantation operation. Wright and Ehrenshaft (1990) assume that 28 million hectares could be available for plantations in the United States, with comparable or lower cost and higher yield, by 2010, if energy crop research proceeds.
Another potential source of fuel supply is the combination of photovoltaic solar power with the generation of hydrogen. In a solar hydrogen
economy, hydrogen would be produced by the electrolysis of water. At the other end of the pipeline, hydrogen would be supplied to power stations, to industry, and eventually to residences for space and water heating. Stored in metal hydrides, hydrogen could also lend itself as a fuel for transportation, replacing gasoline and diesel oil in automobiles, buses, and trucks. Hydrogen could be an important part of an integrated energy system.
Due to the cost and inefficiency of the transmission of electrical power over great distances, solar power by itself might be practical only in regions of high sunshine. For the United States, that would mean the Southwest. To supply power to areas remote from solar energy collecting fields, one would look for a nonpolluting means of energy transport. For this purpose, the transmission of hydrogen gas by pipelines offers many advantages (Ogden and Williams, 1989).
A hydrogen-based power economy is attractive in terms of its impact on the environment but carries with it two concerns (in addition to economic competitiveness)storage and safety. Appendix H has additional details.
Fuel cells utilize hydrogen and oxygen and generate electricity via electrochemical reactions. Since the 1960s, substantial efforts have been made to adapt fuel cells to large-scale applications because of the obvious advantages:
• only water is emitted,
• they are quiet, and
• they can be close to the site where energy is needed.
Most of the work on fuel cells has concentrated on the use of phosphoric acid fuel cells (PAFC). The impediment to this technology has been cost. The cost of fuel cells today is about $2500/kW, a significant part of which is the cost of the reformer to produce hydrogen. If fuel cells could be used as an element in an integrated energy system, where hydrogen is supplied by other means, the overall economics could change.
Another technology under development utilizes a mixture of alkaline carbonates and promises to have even higher efficiencies: 55 percent compared to 44 percent for PAFC.
Transmission of energy is a critical issue. One reason that oil is attractive is the ease with which it can be transported. Natural gas suffers in this respect, which is why so much research and development is devoted to liquefied natural gas, pipeline, and direct conversion technologies. Electrical
energy suffers from the large losses inherent in transmission lines. For this reason, superconducting cables have been of great interest. Studies have been made on the feasibility of operating superconducting cables at liquid helium temperatures. The general conclusion has been that for this technology to be economically attractive, the power transmitted in the cable must be of the order of tens of gigawatts. How to integrate such a cable into a power system from the viewpoint of operations reliability has not been seriously studied. Successful development of high-temperature superconducting materials may significantly alter the economics of electrical power generation and transmission, but the time scale is highly uncertain.
Carbon Dioxide Collection and Disposal
Another possible way of reducing CO2 emissions from fossil fuel systems is the collection and subsequent disposal of CO2 from large concentrated sources. First suggested by Marchetti (1975), and explored further by Baes et al. (1980), CO2 collection and disposal has been elaborated on by Steinberg et al. (1984). Additional studies are under way now. Since Steinberg (1983) demonstrated that it is not feasible to extract CO2 from the ambient atmosphere, and because it does not appear practical to collect CO2 at small or dispersed sources, this possibility focuses on large, concentrated sources such as electric power plants. In 1985, nearly 40 percent of global fossil-fuel-related CO2 emissions came from electric power plants, and it is this approximately 7 Gt of CO2 that might be collected.
In a recent summary of CO2 collection schemes for pulverized coal boilers, Golomb et al. (1989) conclude that the least-energy-intensive system is one that relies on an air separation plant so that combustion takes place in an oxygen-enriched gas stream and the full emission stream is carried to disposal. This scheme has the further advantage that SO2 and NOx are disposed of with the CO2. Table 24.4, from Golomb et al. (1989), compares the energy requirements for several methods of collecting CO2. The analysis includes compression to 150 atmospheres but does not include CO2 transport or disposal. The analysis of Golomb et al. suggests that some schemes could actually result in a net increase in CO2 emissions because CO2 collection is less than 100 percent efficient and the energy demands of the collection process require an increase in coal burning to yield the same power output. The costs of such a collection scheme (based on recent estimates from the Netherlands) would be in the range of $32/t CO2. Most studies assume that disposal will be by injection into the deep ocean.
The consensus to date has been that a regenerable amine scrubber is the most likely candidate for such a collection scheme, although other methods have been explored for smaller systems, such as submarines and space craft cabins, and still others might have application here. A variety of commercial-scale
TABLE 24.4 Energy Requirement Comparison for CO2 Scrubbing at Electric Power Plants
plants have been operated for acid gas processing, and data are available on at least four plants that successfully scrubbed CO2 from flue gases. All four of the later used monoethanolamine as the working solvent. Gagliardi et al. (1989) provide a description of a modern CO2 removal system and discuss some of the system parameters.
Ongoing analysis in the Netherlands has examined the possibility of CO2 collection from an integrated coal gasifier and combined cycle power plant. Efficiency gains associated with the IGCC technology would offset efficiency losses associated with CO2 collection, and the total cost of CO2 collection is about $13/t CO2. The process envisions using a shift reactor to convert synthesis gas to hydrogen and CO2, and then removing the CO2 via physical absorption in a solution. An 88 percent reduction in CO2 emissions results in a 12 percent loss in net power output. With CO2 disposal in nearby gas wells (an especially feasible option for the Netherlands), the impact on electricity cost is about 30 percent (Blok et al., 1990; Hendriks et al., 1990; K. Blok, personal communication, 1990).
Carbon dioxide streams have been collected and transported on a large scale for enhanced oil recovery projects, and the gas handling technology is well established. The questions with respect to collecting large quantities of CO2 at electric generating plants involve the cost of collection and what would be done with the CO2 once it has been collected. The amount of CO2 generated at power plants dwarfs market demand, and the general assumption is that these large quantities of CO2 could be injected into the deep ocean. The ecological consequences of such disposal have not been evaluated seriously. Both Baes et al. (1980) and Steinberg et al. (1984) discuss the prospect of placing at least some of the CO2 in depleted oil and gas fields.
There has also been some discussion of processing fuels so that full fuel oxidation does not occur, and the carbon-bearing product is something other than CO2. Steinberg (1989), for example, discusses the possibility of processing coal so that the final products are carbon black and water. This process extracts from coal only the energy available from hydrogen oxidation, but it yields a solid carbon product that should be easier to store than gaseous or dissolved CO2. Steinberg's estimate is that 19 percent of the energy value of coal would be available in such a scheme with no oxidation of fuel carbon, and the fraction would be higher for liquid and gaseous fuels with higher hydrogen content.
The method used in determining the cost-effectiveness of energy supply options is described in Appendix J. As mentioned in Chapter 20, it is important to note that the Mitigation Panel's analysis of energy supply
options assumes a constant cost. This cost could change for any number of reasons. For example, implementation of the energy efficiency options described in Chapters 21, 22, and 23 could decrease demand and therefore the cost of electricity. The cost impact could also go the other way. As the price of natural gas or electricity changes, so would the cost-effectiveness calculations in Chapters 21, 22, and 23. Further, a change in the availability of a particular commodity could affect price. For example, since natural gas reserves may be limited, a major increase in the demand for natural gas may cause demand to exceed the supply available, and thus the price of natural gas may increase. On the other hand, a new major source of natural gas may be found. A sensitivity analysis conducted by the panel of the impact of the constant cost assumption on the calculation caused the price of the option in the analysis to range from 3.3 to 4.5 cents/kWh for an assumed escalation in natural gas price of 4 percent per year. In addition, a major crisis or deliberate action of some kind anywhere in the world may reduce the supply of a particular commodity and affect the price. This has been recently observed following the invasion of Kuwait, as well as the OPEC oil embargo during the 1970s. Moreover, technology innovation may substantially reduce the price of a particular technology. For example, the price of energy from solar photovoltaics has constantly been decreasing and may continue to do so.
It is for this reason that the panel made a deliberate decision to avoid projections of price or of the potential of a particular technology to replace fossil fuels. Accordingly, the panel assumed a constant cost for existing technology, even though in doing so a number of potentially important variables are neglected. In addition, the panel has not tried to develop a capital replacement scenario but has examined current costs of replacing a fully depreciated facility.
Therefore to estimate the cost of reducing CO2 and the potential magnitude of reductions from electric power generation, the panel has considered the prospect of replacing the existing fossil-fuel-fired plants with other options once those plants have been totally written off and are to be replaced. The replacement process would likely take 30 to 40 years.
Assumptions from the Electric Power Research Institute's Technical Assessment Guide (Electric Power Research Institute, 1989) were used whenever appropriate to estimate the cost and performance of various power generation systems; however, in a few cases, the panel felt that different assumptions were needed. For example, in the case of nuclear power plants, it was felt that the EPRI values did not reflect the full range of costs of bringing a plant to full operation in the different regions of the United States, and a range of capital costs between the EPRI value and twice that figure was evaluated. For natural gas combined cycle, a higher efficiency (representing advanced technology) was combined with a zero fuel escalation rate to obtain a lower bound on cost.
Although four real discount rates (3, 6, 10, and 30 percent) were used to evaluate energy demand, only one (6 percent) was used in the power generation calculations. This value is representative of current utility economics in a regulated environment. A more in-depth discussion of the assumptions and calculation methods used is provided in Appendix J. The results of this analysis are presented in Figure 24.5 and Table 24.5.
Figure 24.5 illustrates the relative cost-effectiveness of different forms of energy supply. Costs should be reviewed in relation to the current price of the U.S. energy mix, which includes coal, oil, natural gas, nuclear power, and renewable sources. As shown here, a fully depreciated coal-fired plant is the least expensive option but generates the most CO2. Nuclear and renewables (solar photovoltaics, wind, geothermal, and biomass) are the most expensive but generate no CO2. Natural gas is roughly the midpoint between depreciated coal plants and the nuclear/renewables options. For new plants, natural gas is much more attractive than new pulverized coal-fired plants. The slope of the line from the high estimate of nuclear to the U.S. mix is equivalent to the CO2 tax that would be needed to make nuclear energy competitive with the current U.S. energy supply (approximately $51/t CO2).
Table 24.5 compares the cost-effectiveness and potential CO2 abatement for different forms of energy supply. Although some forms of energy, such
TABLE 24.5 Cost-Effectiveness of CO2 Reduction for Different Sources of Electricity Supply
as hydroelectric and biomass, are limited in their potential, others, such as nuclear and coal, have no comparable limit.
For the rest of the world, estimates of energy cost are much more difficult because we do not know the capital cost, capital structure, accounting procedures, fuel costs, and so on. However, a rough estimate of the potential costs can be made. To a first approximation, U.S. electricity consumption is about 45 percent of consumption by the Organization for Economic Cooperation and Development (OECD) countries. The fraction that comes from coal is about the same, around 56 percent of the total. For non-OECD countries, coal is responsible for almost 70 percent of the total. Also, demand outside OECD has grown faster. In 1971, non-OECD electricity consumption was 47 percent of the sum of OECD countries. In 1987, it grew to 69 percent. Thus, to a first approximation, the potential emission
reduction in CO2 is 1.2 times that of the United States in the rest of the OECD and 2 times that of the United States in non-OECD countries (International Energy Agency, 1989).
While the panel makes no attempt to evaluate potential CO2 savings from energy supply systems outside the United States, the potential is very large because in many areas the efficiency of current electric power and other conversion facilities is markedly lower than in the United States and other developed countries such as Japan.
Barriers to Implementation
There are varied and complex barriers to changing the way electricity is generated. Some of these barriers were identified in a recent U.S. Department of Energy (1989) report:
• Although the utility industry is concentrated, it has many varied actors including the utility itself, the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC), the financial community, state and federal environmental regulators, equipment vendors, architectural and engineering firms, ratepayers, and independent power producers. There is a complex decision making system. The varied actors are often contentious and have different objectives and time frames, which slows decision making.
• The utilities themselves are of differing size and complexity, ranging from large private holding companies with multiple operating entities in some cases to large private utilities to small publicly run distributors. In some cases, they may provide just one of the three servicespower generation, transmission, or distributionor they may be vertically integrated and provide all three.
• Utilities are reluctant to commit to additional power due to past problems with public utility commissions' (PUCs) not allowing in the rate base the costs of new plants. This is because of optimistic forecasts of demand growth as well as Public Utility Regulatory Policies Act (PURPA) requirements that they purchase power from independent power producers (IPPs). Therefore utilities have little incentive to purchase new sources of power to replace the coal they currently use.
• The previous problems result in a low capital turnover rate as utilities extend the physical lifetime (40+ years) of their plants beyond their financial life (30 years). Figure 24.6 shows the age distribution of fossil fuel plants still operating in 1986.
• The use of gas to replace coal with either conventional plants or combined cycle technologies is perceived as limited by domestic supplies of natural gas.
• In addition, projected domestic supplies of natural gas (as estimated
by DOE) will increase from 16.6 quads (1988) to 17.5 quads (1995) but then decline to 13.5 quads (2010) and continue to decline until conventional reserves are depleted. Therefore, the conclusion is that natural gas could replace coal in the short term, but imported natural gas or the discovery of additional reserves is needed for long-term replacement of coal with natural gas.
Because of these and other circumstances, it will take many decades to replace existing coal-fired plants. For renewable sources, both economics and resource limitations present further barriers to implementation.
The resource limitation issue for natural gas is a controversial issue. While Fulkerson et al. (1989) pointed out that the recoverable resources of conventional natural gas are about 35 times the current annual usage, a paper one year later (Fisher, 1990) gave an estimate of 50 times. The situation is also similar worldwide. The annual world reserves estimates as published by the Oil and Gas Journal from 1977 to 1989 showed an increase of almost 60 percent. The reasonable conclusion is that our knowledge
of gas reserves is not reliable. But as long as the perception of resource limitation is there for some, it is a constraint on accelerated substitution of gas for coal.
A recent white paper, developed by a committee representing several national laboratories, identified the barriers to increased use of renewable sources of energy (Solar Energy Research Institute, 1990). A summary of its judgment is illustrated in Figure 24.7 and expanded more fully, to include potential methods for removing these barriers, in Table 24.6. The basis of the committee's judgment, as summarized below, divides the barriers into four categories: regulatory, financial, infrastructural, and perceptual:
• Transmission access rulings may constrain grid connection of remote renewable technology installations.
• Utility ownership of qualifying facilities (co-generation and renewable generation facility) is limited by the Public Utility Regulatory Policies Act (PURPA).
TABLE 24.6 Institutional Constraints for Renewable Energy
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(Table 24.6 continued from page 360)
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(Table 24.6 continued from page 361)
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(Table 22.6 continued on page 362)
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(Table 24.6 continued from page 363)
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(Table 24.6 continued from page 364)
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(Table 24.6 continued from page 365)
• Hydropower facilities are licensed and relicensed under the Energy Policy and Conservation Act.
• Siting of waste-to-energy facilities in municipalities is problematic.
• Capital markets generally perceive the deployment of emerging technologies as involving more risk than established technologies. The higher the perceived risk, the higher is the rate of return demanded on the capital.
• The perceived length and difficulty of the permitting process are an additional determinant of risk.
• The high front-end financing requirements of many renewable technologies often present additional cost-recovery risks for which capital markets demand a premium.
• Fragmentation and lack of standardization in the building construction industry can hinder the adoption of many cost-effective solar buildings technologies.
• The existing automobile production and gasoline marketing and delivery infrastructure may retard development and integration of biomas-derived alternative fuels.
• The longer-term biofuels contribution may be limited if sufficient land and resources are not devoted to appropriate biomass production, unless the production of biofuels becomes attractive to farmers.
• Aesthetic problems exist, such as the visual impact of a large ''farm," or array of wind turbines, or residential active solar heating systems.
• Environmental issues, such as the damming of wild rivers and streams for hydropower development or effluents from waste-to-energy plants, are problematic.
Also listed in Table 24.6 are opportunities for overcoming these barriers.
In Chapter 21, one potential supply-side option, least-cost utility planning (LCUP), was discussed as a policy option for conservation. Additional supply-side options that should be evaluated include
• regulatory and economic incentives to increase the capital turnover rate.
• carbon or greenhouse gas taxes, and
• technology or emission standards (U.S. Department of Energy, 1989).
The capital turnover rate can be increased through a number of actions.
including allowing accelerated depreciation for investments in new generating equipment; revising rate-of-return regulations to change the risk distributing for investing in generating capacity; and expedited siting, permitting, and certification procedures. Economic incentives such as accelerated depreciation reduce the present value of capital costs and encourage investment in new capital. The actions would likely reduce federal revenue. An alternative would be to change present rate-of-return regulations to reduce the present risk burden to utility shareholders. The question here, however, is how to guard ratepayers from opportunistic exploitation by shareholders. Another regulatory improvement change might be to streamline the permitting process (U.S. Department of Energy, 1989).
A carbon or greenhouse gas emission tax is a direct and flexible market incentive. A disadvantage is that setting an appropriate emission tax rate is not a simple task, and there are many problems with unilateral adoption of such taxes. There is little practical experience with emission taxes in the United States, and they have been unpopular politically because some view them as "licenses to pollute" and their effectiveness is uncertain. A disadvantage of applying the tax to the utility is related to who pays the tax. If the tax is paid by the ratepayers, there may be a stimulus to reduce energy consumption, but it might have no effect on the utility's incentive to switch fuels, improve efficiency, or invest in technologies with lower emissions (and vice versa). If a tax were targeted toward electricity only, other forms of energy (with potentially equivalent greenhouse gas emissions) might be encouraged to fill the gap (U.S. Department of Energy, 1989). This option is discussed more fully in Chapter 21.
Technology or emission standards are a third alternative. Although emission and technology standards for SO2 and NOx are in place today, CO2 technology standards beyond efficiency requirements are much harder to envision (U.S. Department of Energy, 1989). Standards or limits may be based on unrealistic expectations of the potential of these technologies. If a commercial-scale experiment began immediately, it would probably still take 10 to 15 years to set the standards or limits, and it would take even longer for these regulations to have any impact on greenhouse gas emissions. The advantage of this method is that standards are a simple and direct method of reaching emission goals if they can be monitored and enforced (U.S. Department of Energy, 1989). However, standards can become obsolete because of technological changes, and the slowness in changing standards can impede progress.
Other Benefits and Costs
Although there are many costs associated with changing the energy supply strategy of the nation, there are a variety of benefits. First, with the
United States continuing to increase the amount of energy it imports, development of alternative domestic sources of energy would improve energy security. Second, actions to change to alternative sources of energy may help other environmental problems such as air and water pollution. Third, if renewable sources can be tapped, their capacity is very large and may resolve future problems of diminishing worldwide supplies of oil and gas.
One concern with the analysis presented here is that the cost and benefits calculated are not "full cycle"; that is, it does not include the costs and benefits from production to consumption of the energy. For example, there are important questions even within the greenhouse gas discussion. Methane leakage could increase if natural gas consumption increased. The rate of this leakage is very uncertain, and better information on the leakage rate in existing natural gas systems is needed. Methane emissions from coal mining also constitute a factor to be considered.
The costs beyond actual implementation costs in the energy sector are tremendous and difficult to enumerate. For example, a massive reduction in coal consumption could create major economic dislocations in coal mining areas and the rail transport sector. Past experience with attempts to reduce SO2 emissions under the Clean Air Act illustrates the potential distributional costs of such an effort.
Research and Development Needs
A recent study by the Alternative Energy Committee of the National Research Council's Energy Engineering Board entitled Confronting Climate Change: Strategies for Energy Research and Development offers a number of recommendations as to where energy research and development funds should be spent (National Research Council, 1990). A number of actions recommended by the Alternative Energy Committee under its "focused research and development strategy" are summarized below:
• Increase the efficiency of fossil generating equipment by using currently available, high-efficiency options such as the gas turbine/steam turbine combined cycle.
• Develop substantial improvements in the combined cycle and other advanced gas-turbine-based technologies for firing with natural gas or a gaseous fuel derived from biomass.
• Achieve economic recovery of gas from known domestic reserves.
• Improve reservoir characterization through basic geoscience research to enable future resource recovery.
• Define greenhouse gas emissions as one criterion in evaluating new approaches to coal combustion.
• Determine through social science research the conditions under which nuclear options would be publicly acceptable in the United States.
• Conduct an international study to establish criteria for globally acceptable nuclear reactors.
• Provide research, development, and demonstration support to new and improved technology for electric storage, and for alternating current and direct current system components.
• Develop an efficient, flexible, and reliable network to operate the electric power system in the most environmentally acceptable way.
• Accelerate research and development on materials and module manufacturing to increase efficiency and reduce costs of photovoltaic systems.
• Expand through basic research the understanding of the mechanisms of photosynthesis and genetic factors that influence plant growth.
• Perform systems analyses to define and prioritize infrastructure requirements with expanded use of biomass-derived fuels.
• Assess the potential environmental impacts of biomass production (e.g., through silviculture), including impacts on biodiversity and the availability of water resources.
The Alternative Energy Committee believes that these research and development activities would need to be supplemented by government actions to stimulate the adoption of these technologies and processes.
The Alternative Energy Committee also discusses an "insurance strategy" to pursue research and development in energy systems that would be viable only in the presence of concerns about global climate change. These technologies, according to the committee, are not cost-competitive today and may never be feasible without federal support of research and development and market intervention. These strategies include the following:
• Fund an exploratory study to ascertain if there are viable approaches (economically and environmentally) for removing and sequestering CO2.
• On the strength of public acceptability and global reactor studies performed under the focused research and development strategy, fund an industry-led or industry-managed program to develop and demonstrate an advanced reactor.
• Stimulate production (at the rate of about 10 MW/yr each) of the three to five most promising photovoltaic technologies; the same should be done in the areas of solar thermal and wind energy conversion.
• Demonstrate "new" projected storage systems such as compressed gas, battery arrays, and superconducting magnets.
• Develop approaches for federal cost-sharing and utility procurements of renewable energy technologies or of electricity generated by them. Such financing mechanisms should enable manufacturers to compete in niche markets (both domestic and export) to sustain production at levels sufficient to determine the ultimate potential of the technologies.
• Develop and demonstrate photovoltaic electricity resources for buildings, including lighting and water heating
• Develop and demonstrate promising biomass-to-fuel conversion processes, particularly for cellulose and hemicellulose.
• Select and demonstrate on a large scale the use of improved plant species to enhance biomass production.
• Develop strategies to mitigate the environmental impacts of large-scale use of biomass.
Although one might argue about these details, they are beyond the scope of this inquiry and the panel finds general accord with these earlier National Research Council recommendations. In addition, as mentioned earlier, another report, forthcoming from the National Research Council, will focus on nuclear energy. The challenge is to develop a range of options for providing energy with maximum efficiency and minimum greenhouse gas emissions so that society can respond as it evaluates the threat of greenhouse warming.
After reviewing the various methods by which energy can be supplied and the interaction of the entire energy system, the Mitigation Panel has come to the following conclusions:
• Coal is likely to remain a major source of energy for many years. Therefore efforts to improve the efficiency with which coal is burned (as well as improving end-use efficiency, as described in Chapter 21) should be pursued. This includes the development of more efficient combined cycle systems.
• Natural gas can potentially replace some coal use in the near term, but concerns for availability of the supply remain.
• Nuclear fission can potentially replace some coal use. However, concerns about safety, economics, waste disposal, proliferation, and resources have resulted in a lack of acceptance. To what extent the concern about greenhouse warming will induce a fresh look at the possibilities of developing "passively safe" nuclear plants and eliminating long-lived radioactive waste is not clear at this time. What is clear, however, is that research and development efforts on alternative reactor concepts should continue. Although nuclear fusion is still far in the future, research and development should proceed.
• Hydroelectric, wind, and geothermal energy represent a limited potential energy supply because of resource constraints.
• Solar photovoltaics constitute another potential source of energy. A number of advances need to be made before the cost of photovoltaics is close to present energy prices, and storage problems still remain to be solved. To the extent that these problems are solved, solar energy can usefully replace a portion of the U.S. energy supply.
• Fuels from other solar energy technologies (including direct heat) and biomass offer potential, but advancesboth technical and economicmust still be made.
• Carbon dioxide sequestration is a potentially viable option, but CO2 disposal is problematic. Further inquiry seems appropriate.
• The many actors involved in energy supply, the low capital turnover rate, and the long lead times are major barriers to the implementation of new energy supply options.
• Social and economic costs of energy systems that are not internalized should become more important considerations in evaluating future energy supply systems.
1. Throughout this report, tons (t) are metric; 1 Mt = 1 megaton = 1 million tons; and 1 Gt = 1 gigaton = 1 billion tons.
2. 1 quad = 1 quadrillion (1015) British thermal units (Btu).
3. 1 EJ = 1 exajoule = 1018 joules.
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