Mark Z. Jacobson
Department of Civil and Environmental Engineering, Stanford University, Stanford, California 94305-4020, USA. E-mail: firstname.lastname@example.org
This paper reviews and ranks major proposed energy-related solutions to global warming, air pollution mortality, and energy security while considering other impacts of the proposed solutions, such as on water supply, land use, wildlife, resource availability, thermal pollution, water chemical pollution, nuclear proliferation, and undernutrition. Nine electric power sources and two liquid fuel options are considered. The electricity sources include solar-photovoltaics (PV), concentrated solar power (CSP), wind, geothermal, hydroelectric, wave, tidal, nuclear, and coal with carbon capture and storage (CCS) technology. The liquid fuel options include corn-ethanol (E85) and cellulosic-E85. To place the electric and liquid fuel sources on an equal footing, we examine their comparative abilities to address the problems mentioned by powering new-technology vehicles, including battery-electric vehicles (BEVs), hydrogen fuel cell vehicles (HFCVs), and flex-fuel vehicles run on E85. Twelve combinations of energy source-vehicle type are considered. Upon ranking and weighting each combination with respect to each of 11 impact categories, four clear divisions of ranking, or tiers, emerge. Tier 1 (highest-ranked) includes wind-BEVs and wind-HFCVs. Tier 2 includes CSP-BEVs, geothermal-BEVs, PV-BEVs, tidal-BEVs, and wave-BEVs. Tier 3 includes hydro-BEVs, nuclear-BEVs, and CCS-BEVs. Tier 4 includes corn- and cellulosic-E85. Wind-BEVs ranked first in seven out of 11 categories, including the two most important, mortality and climate damage reduction. Although HFCVs are much less efficient than BEVs, wind-HFCVs are still very clean and were ranked second among all combinations. Tier 2 options provide significant benefits and are recommended. Tier 3 options are less desirable. However, hydroelectricity, which was ranked ahead of coal-CCS and nuclear with respect to climate and health, is an excellent load balancer, thus recommended. The Tier 4 combinations (cellulosic- and corn-E85) were ranked lowest overall and with respect to climate, air pollution, land use, wildlife damage, and chemical waste. Cellulosic-E85 ranked lower than corn-E85 overall, primarily due to its potentially larger land footprint based on new data and its higher upstream air pollution emissions than corn-E85. Whereas cellulosic-E85 may cause the greatest average human mortality, nuclear-BEVs cause the greatest upper-limit mortality risk due to the expansion of plutonium separation and uranium enrichment in nuclear energy facilities worldwide. Wind-BEVs and CSP-BEVs cause the least mortality. The footprint area of wind-BEVs is 2–6 orders of magnitude less than that of any other option. Because of their low footprint and pollution, wind-BEVs cause the least wildlife loss. The largest consumer of water is corn-E85. The smallest are wind-, tidal-, and wave-BEVs. The US could theoretically replace all 2007 onroad vehicles with BEVs powered by 73 000–144 000 5 MW wind turbines, less than the 300 000 airplanes the US produced during World War II, reducing US CO2 by 32.5–32.7% and nearly eliminating 15 000/yr vehicle-related air pollution deaths in 2020. In sum, use of wind, CSP, geothermal, tidal, PV, wave, and hydro to provide electricity for BEVs and HFCVs and, by extension, electricity for the residential, industrial, and commercial sectors, will result in the most benefit among the options considered. The combination of these technologies should be advanced as a solution to global warming, air pollution, and energy security. Coal-CCS and nuclear offer less benefit thus represent an opportunity cost loss, and the biofuel options provide no certain benefit and the greatest negative impacts.
This paper reviews and ranks major proposed energy-related solutions to global warming, air pollution mortality, and energy security while considering impacts of the solutions on water supply, land use, wildlife, resource availability, reliability, thermal pollution, water pollution, nuclear proliferation, and undernutrition. To place electricity and liquid fuel options on an equal footing, twelve combinations of energy sources and vehicle type were considered. The overall rankings of the combinations (from highest to lowest) were (1) wind-powered battery-electric vehicles (BEVs), (2) wind-powered hydrogen fuel cell vehicles, (3) concentrated-solar-powered-BEVs, (4) geothermal-powered-BEVs, (5) tidal-powered-BEVs, (6) solar-photovoltaic-powered-BEVs, (7) wave-powered-BEVs, (8) hydroelectric-powered-BEVs, (9-tie) nuclear-powered-BEVs, (9-tie) coal-with-carbon-capture-powered-BEVs, (11) corn-E85 vehicles, and (12) cellulosic-E85 vehicles. The relative ranking of each electricity option for powering vehicles also applies to the electricity source providing general electricity. Because sufficient clean natural resources (e.g., wind, sunlight, hot water, ocean energy, etc.) exist to power the world for the foreseeable future, the results suggest that the diversion to less-efficient (nuclear, coal with carbon capture) or non-efficient (corn- and cellulosic E85) options represents an opportunity cost that will delay solutions to global warming and air pollution mortality. The sound implementation of the recommended options requires identifying good locations of energy resources, updating the transmission system, and mass-producing the clean energy and vehicle technologies, thus cooperation at multiple levels of government and industry.
Air pollution and global warming are two of the greatest threats to human and animal health and political stability. Energy insecurity and rising prices of conventional energy sources are also major threats to economic and political stability. Many alternatives to conventional energy sources have been proposed, but analyses of such options have been limited in breadth and depth. The purpose of this paper is to review several major proposed solutions to these problems with respect to multiple externalities of each option. With such information, policy makers can make better decisions about supporting various options. Otherwise, market forces alone will drive decisions that may result in little benefit to climate, air pollution, or energy–security problems.
Indoor plus outdoor air pollution is the sixth-leading cause of death, causing over 2.4 million premature deaths worldwide.1 Air pollution also increases asthma, respiratory illness, cardiovascular disease, cancer, hospitalizations, emergency-room visits, work-days lost, and school-days lost,2,3 all of which decrease economic output, divert resources, and weaken the security of nations.
Global warming enhances heat stress, disease, severity of tropical storms, ocean acidity, sea levels, and the melting of glaciers, snow pack, and sea ice.5 Further, it shifts the location of viable agriculture, harms ecosystems and animal habitats, and changes the timing and magnitude of water supply. It is due to the globally-averaged difference between warming contributions by greenhouse gases, fossil-fuel plus biofuel soot particles, and the urban heat island effect, and cooling contributions by non-soot aerosol particles (Fig. 1). The primary global warming pollutants are, in order, carbon dioxide gas, fossil-fuel plus biofuel soot particles, methane gas,4,6–10 halocarbons, tropospheric ozone, and nitrous oxide gas.5 About half of actual global warming to date is being masked by cooling aerosol particles (Fig. 1 and ref. 5), thus, as such particles are removed by the clean up of air pollution, about half of hidden global warming will be unmasked. This factor alone indicates that addressing global warming quickly is critical. Stabilizing temperatures while accounting for anticipated future growth, in fact, requires about an 80% reduction in current emissions of greenhouse gases and soot particles.
Because air pollution and global warming problems are caused primarily by exhaust from solid, liquid, and gas combustion during energy production and use, such problems can be addressed only with large-scale changes to the energy sector. Such changes are also needed to secure an undisrupted energy supply for a growing population, particularly as fossil-fuels become more costly and harder to find/extract.
This review evaluates and ranks 12 combinations of electric power and fuel sources from among 9 electric power sources, 2 liquid fuel sources, and 3 vehicle technologies, with respect to their ability to address climate, air pollution, and energy problems simultaneously. The review also evaluates the impacts of each on water supply, land use, wildlife, resource availability, thermal pollution, water chemical pollution, nuclear proliferation, and undernutrition.
Costs are not examined since policy decisions should be based on the ability of a technology to address a problem rather than costs (e.g., the U.S. Clean Air Act Amendments of 1970 prohibit the use of cost as a basis for determining regulations required to meet air pollution standards) and because costs of new technologies will change over time, particularly as they are used on a large scale. Similarly, costs of existing fossil fuels are generally increasing, making it difficult to estimate the competitiveness of new technologies in the short or long term. Thus, a major purpose of this paper is to provide quantitative information to policy makers about the most effective solutions to the problem discussed so that better decisions about providing incentives can be made.
The electric power sources considered here include solar photovoltaics (PV), concentrated solar power (CSP), wind turbines, geothermal power plants, hydroelectric power plants, wave devices, tidal turbines, nuclear power plants, and coal power plants fitted with carbon capture and storage (CCS) technology. The two liquid fuel options considered are corn-E85 (85% ethanol; 15% gasoline) and cellulosic-E85. To place the electric and liquid fuel sources on an equal footing, we examine their comparative abilities to address the problems mentioned by powering new-technology vehicles, including battery-electric vehicles (BEVs), hydrogen fuel cell vehicles (HFCVs), and E85-powered flex-fuel vehicles. We examine combinations of PV-BEVs, CSP-BEVs, wind-BEVs, wind-HFCVs, geothermal-BEVs, hydroelectric-BEVs, wave-BEVs, tidal-BEVs, nuclear-BEVs, CCS-BEVs, corn-E85 vehicles, and cellulosic-E85 vehicles. More combinations of electric power with HFCVs were not compared simply due to the additional effort required and since the options examined are the most commonly discussed. For the same reason, other fuel options, such as algae, butanol, biodiesel, sugar-cane ethanol, or hydrogen combustion; electricity options such as biomass; vehicle options such as hybrid vehicles, heating options such as solar hot water heaters; and geoengineering proposals, were not examined.
In the following sections, we describe the energy technologies, evaluate and rank each technology with respect to each of several categories, then provide an overall ranking of the technologies and summarize the results.
2. Description of technologies
Below different proposed technologies for addressing climate change and air pollution problems are briefly discussed.
2a. Solar photovoltaics (PVs)
Solar photovoltaics (PVs) are arrays of cells containing a material that converts solar radiation into direct current (DC) electricity.11 Materials used today include amorphous silicon, polycrystalline silicon, micro-crystalline silicon, cadmium telluride, and copper indium selenide/sulfide. A material is doped to increase the number of positive (p-type) or negative (n-type) charge carriers. The resulting p- and n-type semiconductors are then joined to form a p–n junction that allows the generation of electricity when illuminated. PV performance decreases when the cell temperature exceeds a threshold of 45 °C.12 Photovoltaics can be mounted on roofs or combined into farms. Solar-PV farms today range from 10–60 MW although proposed farms are on the order of 150 MW.
2b. Concentrated solar power (CSP)
Concentrated Solar Power is a technology by which sunlight is focused (concentrated) by mirrors or reflective lenses to heat a fluid in a collector at high temperature. The heated fluid (e.g., pressurized steam, synthetic oil, molten salt) flows from the collector to a heat engine where a portion of the heat (up to 30%) is converted to electricity.13 One type of collector is a set of parabolic-trough (long U-shaped) mirror reflectors that focus light onto a pipe containing oil that flows to a chamber to heat water for a steam generator that produces electricity. A second type is a central tower receiver with a field of mirrors surrounding it. The focused light heats molten nitrate salt that produce steam for a steam generator. By storing heat in a thermal storage media, such as pressurized steam, concrete, molten sodium nitrate, molten potassium nitrate, or purified graphite within an insulated reservoir before producing electricity, the parabolic-trough and central tower CSP plants can reduce the effects of solar intermittency by producing electricity at night. A third type of CSP technology is a parabolic dish-shaped (e.g., satellite dish) reflector that rotates to track the sun and reflects light onto a receiver, which transfers the energy to hydrogen in a closed loop. The expansion of hydrogen against a piston or turbine produces mechanical power used to run a generator or alternator to produce electricity. The power conversion unit is air cooled, so water cooling is not needed. Thermal storage is not coupled with parabolic-dish CSP.
Wind turbines convert the kinetic energy of the wind into electricity. Generally, a gearbox turns the slow-turning turbine rotor into faster-rotating gears, which convert mechanical energy to electricity in a generator. Some late-technology turbines are gearless. The instantaneous power produced by a turbine is proportional to the third power of the instantaneous wind speed. However, because wind speed frequency distributions are Rayleigh in nature, the average power in the wind over a given period is linearly proportional to the mean wind speed of the Rayleigh distribution during that period.11 The efficiency of wind power generation increases with the turbine height since wind speeds generally increase with increasing height. As such, larger turbines capture faster winds. Large turbines are generally sited in flat open areas of land, within mountain passes, on ridges, or offshore. Although less efficient, small turbines (e.g., 1–10 kW) are convenient for use in homes or city street canyons.
Geothermal energy is energy extracted from hot water and steam below the Earth’s surface. Steam or hot water from the Earth has been used historically to provide heat for buildings, industrial processes, and domestic water. Hot water and/or steam have also been used to generate electricity in geothermal power plants. Three major types of geothermal plants are dry steam, flash steam, and binary.13 Dry and flash steam plants operate where geothermal reservoir temperatures are 180–370 °C or higher. In both cases, two boreholes are drilled – one for steam alone (in the case of dry steam) or liquid water plus steam (in the case of flash steam) to flow up, and the second for condensed water to return after it passes through the plant. In the dry steam plant, the pressure of the steam rising up the first borehole powers a turbine, which drives a generator to produce electricity. About 70% of the steam recondenses after it passes through a condenser, and the rest is released to the air. Since CO2, NO, SO2, and H2S in the reservoir steam do not recondense along with water vapor, these gases are emitted to the air. Theoretically, they could be captured, but they have not been to date. In a flash steam plant, the liquid water plus steam from the reservoir enters a flash tank held at low pressure, causing some of the water to vaporize ( flash ). The vapor then drives a turbine. About 70% of this vapor is recondensed. The remainder escapes with CO2 and other gases. The liquid water is injected back to the ground. A binary system is used when the reservoir temperature is 120–180 °C. Water rising up a borehole is kept in an enclosed pipe and heats a low-boiling-point organic fluid, such as isobutene or isopentane, through a heat exchanger. The evaporated organic turns a turbine that powers a generator, producing electricity. Because the water from the reservoir stays in an enclosed pipe when it passes through the power plant and is reinjected to the reservoir, binary systems produce virtually no emissions of CO2, NO, SO2, or H2S. About 15% of geothermal plants today are binary plants.
Hydroelectric power is currently the world’s largest installed renewable source of electricity, supplying about 17.4% of total electricity in 2005.14 Water generates electricity when it drops gravitationally, driving a turbine and generator. While most hydroelectricity is produced by water falling from dams, some is produced by water flowing down rivers (run-of-the-river electricity). Hydroelectricity is ideal for providing peaking power and smoothing intermittent wind and solar resources. When it is in spinning-reserve mode, it can provide electric power within 15–30 s. Hydroelectric power today is usually used for peaking power. The exception is when small reservoirs are in danger of overflowing, such as during heavy snowmelt during spring. In those cases, hydro is used for baseload.
Winds passing over water create surface waves. The faster the wind speed, the longer the wind is sustained, the greater the distance the wind travels, and the greater the wave height. The power in a wave is generally proportional to the density of water, the square of the height of the wave, and the period of the wave.15 Wave power devices capture energy from ocean surface waves to produce electricity. One type of device is a buoy that rises and falls with a wave, creating mechanical energy that is converted to electricity that is sent through an underwater transmission line to shore. Another type is a floating surface-following device, whose up-and-down motion increases the pressure on oil to drive a hydraulic ram to run a hydraulic motor.
Tides are characterized by oscillating currents in the ocean caused by the rise and fall of the ocean surface due to the gravitational attraction among the Earth, Moon, and Sun.13 A tidal turbine is similar to a wind turbine in that it consists of a rotor that turns due to its interaction with water during the ebb and flow of a tide. A generator in a tidal turbine converts kinetic energy to electrical energy, which is transmitted to shore. The turbine is generally mounted on the sea floor and may or may not extend to the surface. The rotor, which lies under water, may be fully exposed to the water or placed within a narrowing duct that directs water toward it. Because of the high density of seawater, a slow-moving tide can produce significant tidal turbine power; however, water current speeds need to be at least 4 knots (2.05 m s−1) for tidal energy to be economical. In comparison, wind speeds over land need to be about 7 m s−1 or faster for wind energy to be economical. Since tides run about six hours in one direction before switching directions for six hours, they are fairly predictable, so tidal turbines may potentially be used to supply baseload energy.
Nuclear power plants today generally produce electricity after splitting heavy elements during fission. The products of the fission collide with water in a reactor, releasing energy, causing the water to boil, releasing steam whose enhanced partial pressure turns a turbine to generate electricity. The most common heavy elements split are 235U and 239Pu. When a slow-moving neutron hits 235U, the neutron is absorbed, forming 236U, which splits, for example, into 92Kr, 141Ba, three free neutrons, and gamma rays. When the fragments and the gamma rays collide with water in a reactor, they respectively convert kinetic energy and electromagnetic energy to heat, boiling the water. The element fragments decay further radioactively, emitting beta particles (high-speed electrons). Uranium is originally stored as small ceramic pellets within metal fuel rods. After 18–24 months of use as a fuel, the uranium’s useful energy is consumed and the fuel rod becomes radioactive waste that needs to be stored for up to thousands of years. With breeder reactors, unused uranium and its product, plutonium, are extracted and reused, extending the lifetime of a given mass of uranium significantly.
2i. Coal–carbon capture and storage
Carbon capture and storage (CCS) is the diversion of CO2 from point emission sources to underground geological formations (e.g., saline aquifers, depleted oil and gas fields, unminable coal seams), the deep ocean, or as carbonate minerals. Geological formations worldwide may store up to 2000 Gt-CO2,16 which compares with a fossil-fuel emission rate today of 30 Gt-CO2 yr−1. To date, CO2 has been diverted underground following its separation from mined natural gas in several operations and from gasified coal in one case. However, no large power plant currently captures CO2. Several options of combining fossil fuel combustion for electricity generation with CCS technologies have been considered. In one model,17 integrated gasification combined cycle (IGCC) technology would be used to gasify coal and produce hydrogen. Since hydrogen production from coal gasification is a chemical rather than combustion process, this method could result in relatively low emissions of classical air pollutants, but CO2 emissions would still be large18,19 unless it is piped to a geological formation. However, this model (with capture) is not currently feasible due to high costs. In a more standard model considered here, CCS equipment is added to an existing or new coal-fired power plant. CO2 is then separated from other gases and injected underground after coal combustion. The remaining gases are emitted to the air. Other CCS methods include injection to the deep ocean and production of carbonate minerals. Ocean storage, however, results in ocean acidification. The dissolved CO2 in the deep ocean would eventually equilibrate with that in the surface ocean, increasing the backpressure, expelling CO2 to the air. Producing carbonate minerals has a long history. Joseph Black, in 1756, named carbon dioxide fixed air because it fixed to quicklime (CaO) to form CaCO3. However, the natural process is slow and requires massive amounts of quicklime for large-scale CO2 reduction. The process can be hastened by increasing temperature and pressure, but this requires additional energy.
2j. Corn and cellulosic ethanol
Biofuels are solid, liquid, or gaseous fuels derived from organic matter. Most biofuels are derived from dead plants or animal excrement. Biofuels, such as wood, grass, and dung, are used directly for home heating and cooking in developing countries and for electric power generation in others. Many countries also use biofuels for transportation. The most common transportation biofuels are various ethanol/gasoline blends and biodiesel. Ethanol is produced in a factory, generally from corn, sugarcane, wheat, sugar beet, or molasses. Microorganisms and enzyme ferment sugars or starches in these crops to produce ethanol. Fermentation of cellulose from switchgrass, wood waste, wheat, stalks, corn stalks, or miscanthus, can also produce ethanol, but the process is more difficult since natural enzyme breakdown of cellulose (e.g., as occurs in the digestive tracts of cattle) is slow. The faster breakdown of cellulose requires genetic engineering of enzymes. Here, we consider only corn and cellulosic ethanol and its use for producing E85 (a blend of 85% ethanol and 15% gasoline).
3. Available resources
An important requirement for an alternative energy technology is that sufficient resource is available to power the technology and the resource can be accessed and used with minimal effort. In the cases of solar-PV, CSP, wind, tidal, wave, and hydroelectricity, the resources are the energy available from sunlight, sunlight, winds, tides, waves, and elevated water, respectively. In the case of nuclear, coal-CCS, corn ethanol, and cellulosic ethanol, it is the amount of uranium, coal, corn, and cellulosic material, respectively.
Table 1 gives estimated upper limits to the worldwide available energy (e.g., all the energy that can be extracted for electricity consumption, regardless of cost or location) and the technical potential energy (e.g., the energy that can feasibly be extracted in the near term considering cost and location) for each electric power source considered here. It also shows current installed power, average capacity factor, and current electricity generated for each source.
Globally, about 1700 TW (14 900 PWh yr−1) of solar power are theoretically available over land for PVs, before removing exclusion zones of competing land use or high latitudes, where solar insolation is low. The capture of even 1% of this power would supply more than the world’s power needs. Cumulative installed solar photovoltaic power at the end of 2007 was 8.7 GW (Table 1), with less than 1 GW in the form of PV power stations and most of the rest on rooftops. The capacity factor of solar PV ranges from 0.1 to 0.2, depending on location, cloudiness, panel tilt, and efficiency of the panel. Current-technology PV capacity factors rarely exceed 0.2, regardless of location worldwide, based on calculations that account for many factors, including solar cell temperature, conversion losses, and solar insolation.12
The total available energy worldwide for CSP is about one-third less than that for solar-PV since the land area required per installed MW of CSP without storage is about one-third greater than that of installed PV. With thermal storage, the land area for CSP increases since more solar collectors are needed to provide energy for storage, but so does total energy output, resulting in a similar total available energy worldwide for CSP with or without storage. Most CSP plants installed to date have been in California, but many projects are now being planned worldwide. The capacity factor of a solar–thermal power plant typically without storage ranges from 13–25% (Table 1 and references therein).
The globally-available wind power over land in locations worldwide with mean wind speeds exceeding 6.9 m s−1 at 80 m is about 72 TW (630–700 PWh yr−1), as determined from data analysis.23 This resource is five times the world’s total power production and 20 times the world’s electric power production (Table 1). Earlier estimates of world wind resources were not based on a combination of sounding and surface data for the world or performed at the height of at least 80 m. The wind power available over the US is about 55 PWh yr−1, almost twice the current US energy consumption from all sources and more than 10 times the electricity consumption.23 At the end of 2007, 94.1 GW of wind power was installed worldwide, producing just over 1% of the world’s electric power (Table 1). The countries with the most installed wind capacity were Germany (22.2 GW), the United States (16.8 GW), and Spain (15.1 GW), respectively.25 Denmark generates about 19% of its electric power from wind energy. The average capacity factor of wind turbines installed in the US between 2004–2007 was 33–35%, which compares with 22% for projects installed before 1998.26 Of the 58 projects installed from 2004–2006, 25.9% had capacity factors greater than 40%.
For land-based wind energy costs without subsidy to be similar to those of a new coal-fired power plant, the annual-average wind speed at 80 meters must be at least 6.9 meters per second (15.4 miles per hour).33 Based on the mapping analysis,23 15% of the data stations (thus, statistically, land area) in the United States (and 17% of land plus coastal offshore data stations) have wind speeds above this threshold (globally, 13% of stations are above the threshold) (Table 2). Whereas, the mean wind speed over land globally from the study was 4.54 m s−1, that at locations with wind speeds exceeding 6.9 m s−1 (e.g., those locations in Table 2) was 8.4 m s−1. Similarly, the mean wind speed over all ocean stations worldwide was 8.6 m s−1, but that over ocean stations with wind speeds exceeding 6.9 m s−1 was 9.34 m s−1.
Although offshore wind energy is more expensive than onshore wind energy, it has been deployed significantly in Europe. A recent analysis indicated that wind resources off the shallow Atlantic coast could supply a significant portion of US electric power on its own.24 Water depths along the west coast of the US become deeper faster than along the east coast, but another recent analysis indicates significant wind resources in several areas of shallow water offshore of the west coast as well.34
The Earth has a very large reservoir of geothermal energy below the surface; however, most of it is too deep to extract. Although 1390 PWh yr−1 could be reached,16 the technical potential is about 0.57–1.21 PWh yr−1 due to cost limitations.27
About 5% or more of potential hydroelectric power worldwide has been tapped. The largest producers of hydroelectricity worldwide are China, Canada, Brazil, US, Russia, and Norway, respectively. Norway uses hydro for nearly all (98.9%) of its electricity generation. Brazil and Venezuela use hydro for 83.7% and 73.9%, respectively, of their electricity generation.20
Wave potential can be estimated by considering that 2% of the world’s 800 000 km of coastline exceeds 30 kW m−1 in wave power density. Thus, about 480 GW (4.2 PWh yr−1) of power output can ultimately be captured.16
The globally-averaged dissipation of energy over time due to tidal fluctuations may be 3.7 TW.35 The energy available in tidal fluctuations of the oceans has been estimated as 0.6 EJ.36 Since this energy is dissipated in four semi-diurnal tidal periods at the rate of 3.7 TW, the tidal power available for energy generation without interfering significantly with the tides may be about 20% of the dissipation rate, or 0.8 TW. A more practical exploitable limit is 0.02 TW.13
As of April 1, 2008, 439 nuclear power plants were installed in 31 countries (including 104 in the US, 59 in France, 55 in Japan, 31 in the Russian Federation, and 20 in the Republic of Korea). The US produces more electric power from nuclear energy than any other country (29.2% of the world total in 2005).20 France, Japan, and Germany follow. France uses nuclear power to supply 79% of its electricity. At current nuclear electricity production rates, there are enough uranium reserves (4.7–14.8 MT16) to provide nuclear power in current once-through fuel cycle reactors for about 90–300 yr (Table 1). With breeder reactors, which allow spent uranium to be reprocessed for additional fuel, the reprocessing also increases the ability of uranium and plutonium to be weaponized more readily than in once-through reactors.
4. Effects on climate-relevant emissions
In this section, the CO2-equivalent (CO2e) emissions (emissions of CO2 plus those of other greenhouse gases multiplied by their global warming potentials) of each energy technology are reviewed. We also examine CO2e emissions of each technology due to planning and construction delays relative to those from the technology with the least delays ( opportunity-cost emissions ), leakage from geological formations of CO2 sequestered by coal-CCS, and the emissions from the burning of cities resulting from nuclear weapons explosions potentially resulting from nuclear energy expansion.
4a. Lifecycle emissions
Table 3 summarizes ranges of the lifecycle CO2e emission per kWh of electricity generated for the electric power sources considered (all technologies except the biofuels). For some technologies (wind, solar PV, CSP, tidal, wave, hydroelectric), climate-relevant lifecycle emissions occur only during the construction, installation, maintenance, and decommissioning of the technology. For geothermal, emissions also occur due to evaporation of dissolved CO2 from hot water in flash- or dry-steam plants, but not in binary plants. For corn ethanol, cellulosic ethanol, coal-CCS, and nuclear, additional emissions occur during the mining and production of the fuel. For biofuels and coal-CCS, emissions also occur as an exhaust component during combustion.
4a.i. Wind. Wind has the lowest lifecycle CO2e among the technologies considered. For the analysis, we assume that the mean annual wind speed at hub height of future turbines ranges from 7–8.5 m s−1. Wind speeds 7 m s−1 or higher are needed for the direct cost of wind to be competitive over land with that of other new electric power sources.33 About 13% of land outside of Antarctica has such wind speeds at 80 m (Table 2), and the average wind speed over land at 80 m worldwide in locations where the mean wind speed is 7 m s−1 or higher is 8.4 m s−1.23 The capacity factor of a 5 MW turbine with a 126 m diameter rotor in 7–8.5 m s−1 wind speeds is 0.294–0.425 (ESI ), which encompasses the measured capacity factors, 0.33–0.35, of all wind farms installed in the US between 2004–2007.26 As such, this wind speed range is the relevant range for considering the large-scale deployment of wind. The energy required to manufacture, install, operate, and scrap a 600 kW wind turbine has been calculated to be 4.3 × 106 kWh per installed MW.37 For a 5 MW turbine operating over a lifetime of 30 yr under the wind-speed conditions given, and assuming carbon emissions based on that of the average US electrical grid, the resulting emissions from the turbine are 2.8–7.4 g CO2e kWh−1 and the energy payback time is 1.6 months (at 8.5 m s−1) to 4.3 months (at 7 m s−1). Even under a 20 yr lifetime, the emissions are 4.2–11.1 g CO2e kWh−1, lower than those of all other energy sources considered here. Given that many turbines from the 1970s still operate today, a 30 yr lifetime is more realistic.
4a.ii. CSP. CSP is estimated as the second-lowest emitter of CO2e. For CSP, we assume an energy payback time of 5–6.7 months38,39 and a CSP plant lifetime of 40 yr,39 resulting in an emission rate of 8.5–11.3 g CO2e kWh−1 (ESI ).
4a.iii. Wave and tidal. Few analyses of the lifecycle carbon emissions for wave or tidal power have been performed. For tidal power, we use 14 g CO2e kWh−1,40 determined from a 100 MW tidal turbine farm with an energy payback time of 3–5 months. Emissions for a 2.5 MW farm were 119 g CO2e kWh−1,40 but because for large-scale deployment, we consider only the larger farm. For wave power, we use 21.7 g CO2e kWh−1,41 which results in an energy payback time of 1 yr for devices with an estimated lifetime of 15 yr.
4a.iv. Hydroelectric. By far the largest component of the lifecycle emissions for a hydroelectric power plant is the emission during construction of the dam. Since such plants can last 50–100 yr or more, their lifecycle emissions are relatively low, around 17–22 g CO2e kWh−1.40,31 In addition, some CO2 and CH4 emissions from dams can occur due to microbial decay of dead organic matter under the water of a dam, particularly if the reservoir was not logged before being filled.42 Such emissions are generally highest in tropical areas and lowest in northern latitudes.
4a.v. Geothermal. Geothermal power plant lifecycle emissions include those due to constructing the plant itself and to evaporation of carbonic acid dissolved in hot water drawn from the Earth’s crust. The latter emissions are almost eliminated in binary plants. Geothermal plant lifecycle emissions are estimated as 15 g CO2e kWh−1 43 whereas the evaporative emissions are estimated as 0.1 g CO2e kWh−1 for binary plants and 40 g CO2e kWh−1 for non-binary plants.27
4a.vi. Solar-PV. For solar PV, the energy payback time is generally longer than that of other renewable energy systems, but depends on solar insolation. Old PV systems generally had a payback time of 1–5 years.41,44,45 New systems consisting of CdTe, silicon ribbon, multicrystalline silicon, and monocrystaline silicon under Southern European insolation conditions (1700 kWh/m2/yr), have a payback time over a 30 yr PV module life of 1–1.25, 1.7, 2.2, and 2.7 yr, respectively, resulting in emissions of 19–25, 30, 37, and 45 g CO2e kWh−1, respectively.46 With insolation of 1300 kWh m−2 yr−1 (e.g., Southern Germany), the emissions range is 27–59 g CO2e kWh−1. Thus, the overall range of payback time and emissions may be estimated as 1–3.5 yr and 19–59 g CO2e kWh−1, respectively. These payback times are generally consistent with those of other studies.47,48 Since large-scale PV deployment at very high latitudes is unlikely, such latitudes are not considered for this payback analysis.
4a.vii. Nuclear. Nuclear power plant emissions include those due to uranium mining, enrichment, and transport and waste disposal as well as those due to construction, operation, and decommissioning of the reactors. We estimate the lifecycle emissions of new nuclear power plants as 9–70 g CO2e kWh−1, with the lower number from an industry estimate49 and the upper number slightly above the average of 66 g CO2e kWh−150 from a review of 103 new and old lifecycle studies of nuclear energy. Three additional studies51,48,16 estimate mean lifecycle emissions of nuclear reactors as 59, 16–55, and 40 g CO2e kWh−1, respectively; thus, the range appears within reason.
4a.viii. Coal-CCS. Coal-CCS power plant lifecycle emissions include emissions due to the construction, operation, and decommissioning of the coal power plant and CCS equipment, the mining and transport of the coal, and carbon dioxide release during CCS. The lifecycle emissions of a coal power plant, excluding direct emissions but including coal mining, transport, and plant construction/decommissioning, range from 175–290 g CO2e kWh−1.49 Without CCS, the direct emissions from coal-fired power plants worldwide are around 790–1020 g CO2e kWh−1. The CO2 direct emission reduction efficiency due to CCS is 85–90%.32 This results in a net lifecycle plus direct emission rate for coal-CCS of about 255–440 g CO2e kWh−1, the highest rate among the electricity-generating technologies considered here. The low number is the same as that calculated for a supercritical pulverized-coal plant with CCS.52
The addition of CCS equipment to a coal power plant results in an additional 14–25% energy requirement for coal-based integrated gasification combined cycle (IGCC) systems and 24–40% for supercritical pulverized coal plants with current technology.32 Most of the additional energy is needed to compress and purify CO2. This additional energy either increases the coal required for an individual plant or increases the number of plants required to generate a fixed amount of electricity for general consumption. Here, we define the kWh generated by the coal-CCS plant to include the kWh required for the CCS equipment plus that required for outside consumption. As such, the g CO2e kWh−1 emitted by a given coal-CCS plant does not change relative to a coal plant without CCS, due to adding CCS; however, either the number of plants required increases or the kWh required per plant increases.
4a.ix. Corn and cellulosic ethanol. Several studies have examined the lifecycle emissions of corn and cellulosic ethanol.53–61 These studies generally accounted for the emissions due to planting, cultivating, fertilizing, watering, harvesting, and transporting crops, the emissions due to producing ethanol in a factory and transporting it, and emissions due to running vehicles, although with differing assumptions in most cases. Only one of these studies58 accounted for the emissions of soot, the second-leading component of global warming (Introduction), cooling aerosol particles, nitric oxide gas, carbon monoxide gas, or detailed treatment of the nitrogen cycle. That study58 was also the only one to account for the accumulation of CO2 in the atmosphere due to the time lag between biofuel use and regrowth.62 Only three studies58,60,61 considered substantially the change in carbon storage due to (a) converting natural land or crop land to fuel crops, (b) using a food crop for fuel, thereby driving up the price of food, which is relatively inelastic, encouraging the conversion of land worldwide to grow more of the crop, and (c) converting land from, for example, soy to corn in one country, thereby driving up the price of soy and encouraging its expansion in another country.
The study that performed the land use calculation in the most detail,61 determined the effect of price changes on land use change with spatially-distributed global data for land conversion between noncropland and cropland and an econometric model. It found that converting from gasoline to ethanol (E85) vehicles could increase lifecycle CO2e by over 90% when the ethanol is produced from corn and around 50% when it is produced from switchgrass. Delucchi,58 who treated the effect of price and land use changes more approximately, calculated the lifecycle effect of converting from gasoline to corn and switchgrass E90. He estimated that E90 from corn ethanol might reduce CO2e by about 2.4% relative to gasoline. In China and India, such a conversion might increase equivalent carbon emissions by 17% and 11%, respectively. He also estimated that ethanol from switchgrass might reduce US CO2e by about 52.5% compared with light-duty gasoline in the US. We use results from these two studies to bound the lifecycle emissions of E85. These results will be applied shortly to compare the CO2e changes among electric power and fuel technologies when applied to vehicles in the US.
4b. Carbon emissions due to opportunity cost from planning-to-operation delays
The investment in an energy technology with a long time between planning and operation increases carbon dioxide and air pollutant emissions relative to a technology with a short time between planning and operation. This occurs because the delay permits the longer operation of higher-carbon emitting existing power generation, such as natural gas peaker plants or coal-fired power plants, until their replacement occurs. In other words, the delay results in an opportunity cost in terms of climate- and air-pollution-relevant emissions. In the future, the power mix will likely become cleaner; thus, the opportunity-cost emissions will probably decrease over the long term. Ideally, we would model such changes over time. However, given that fossil-power construction continues to increase worldwide simultaneously with expansion of cleaner energy sources and the uncertainty of the rate of change, we estimate such emissions based on the current power mix.
The time between planning and operation of a technology includes the time to site, finance, permit, insure, construct, license, and connect the technology to the utility grid.
The time between planning and operation of a nuclear power plant includes the time to obtain a site and construction permit, the time between construction permit approval and issue, and the construction time of the plant. In March, 2007, the U.S. Nuclear Regulatory Commission approved the first request for a site permit in 30 yr. This process took 3.5 yr. The time to review and approve a construction permit is another 2 yr and the time between the construction permit approval and issue is about 0.5 yr. Thus, the minimum time for preconstruction approvals (and financing) is 6 yr. We estimate the maximum time as 10 yr. The time to construct a nuclear reactor depends significantly on regulatory requirements and costs. Because of inflation in the 1970s and more stringent safety regulation on nuclear power plants placed shortly before and after the Three-Mile Island accident in 1979, US nuclear plant construction times increased from around 7 yr in 1971 to 12 yr in 1980.63 The median construction time for reactors in the US built since 1970 is 9 yr.64 US regulations have been streamlined somewhat, and nuclear power plant developers suggest that construction costs are now lower and construction times shorter than they have been historically. However, projected costs for new nuclear reactors have historically been underestimated64 and construction costs of all new energy facilities have recently risen. Nevertheless, based on the most optimistic future projections of nuclear power construction times of 4–5 yr65 and those times based on historic data,64 we assume future construction times due to nuclear power plants as 4–9 yr. Thus, the overall time between planning and operation of a nuclear power plant ranges from 10–19 yr.
The time between planning and operation of a wind farm includes a development and construction period. The development period, which includes the time required to identify a site, purchase or lease the land, monitor winds, install transmission, negotiate a power-purchase agreement, and obtain permits, can take from 0.5–5 yr, with more typical times from 1–3 yr. The construction period for a small to medium wind farm (15 MW or less) is 1 year and for a large farm is 1–2 yr.66 Thus, the overall time between planning and operation of a large wind farm is 2–5 yr.
For geothermal power, the development time can, in extreme cases, take over a decade but with an average time of 2 yr.27 We use a range of 1–3 yr. Construction times for a cluster of geothermal plants of 250 MW or more are at least 2 yr.67 We use a range of 2–3 yr. Thus, the total planning-to-operation time for a large geothermal power plant is 3–6 yr.
For CSP, the construction time is similar to that of a wind farm. For example, Nevada Solar One required about 1.5 yr for construction. Similarly, an ethanol refinery requires about 1.5 yr to construct. We assume a range in both cases of 1–2 yr. We also assume the development time is the same as that for a wind farm, 1–3 yr. Thus, the overall planning-to-operation time for a CSP plant or ethanol refinery is 2–5 yr. We assume the same time range for tidal, wave, and solar-PV power plants.
The time to plan and construct a coal-fired power plant without CCS equipment is generally 5–8 yr. CCS technology would be added during this period. The development time is another 1–3 yr. Thus, the total planning-to-operation time for a standard coal plant with CCS is estimated to be 6–11 yr. If the coal-CCS plant is an IGCC plant, the time may be longer since none has been built to date.
Dams with hydroelectric power plants have varying construction times. Aswan Dam required 13 yr (1889–1902). Hoover Dam required 4 yr (1931 to 1935). Shasta Dam required 7 yr (1938–1945). Glen Canyon Dam required 10 yr (1956 to 1966). Gardiner Dam required 8 yr (1959–1967). Construction on Three Gorges Dam in China began on December 14, 1994 and is expected to be fully operation only in 2011, after 15 yr. Plans for the dam were submitted in the 1980s. Here, we assume a normal range of construction periods of 6–12 yr and a development period of 2–4 yr for a total planning-to-operation period of 8–16 yr.
We assume that after the first lifetime of any plant, the plant is refurbished or retrofitted, requiring a downtime of 2–4 yr for nuclear, 2–3 yr for coal-CCS, and 1–2 yr for all other technologies. We then calculate the CO2e emissions per kWh due to the total downtime for each technology over 100 yr of operation assuming emissions during downtime will be the average current emission of the power sector. Finally, we subtract such emissions for each technology from that of the technology with the least emissions to obtain the opportunity-cost CO2e emissions for the technology. The opportunity-cost emissions of the least-emitting technology is, by definition, zero. Solar-PV, CSP, and wind all had the lowest CO2e emissions due to planning-to-operation time, so any could be used to determine the opportunity cost of the other technologies.
We perform this analysis for only the electricity-generating technologies. For corn and cellulosic ethanol the CO2e emissions are already equal to or greater than those of gasoline, so the downtime of an ethanol refinery is unlikely to increase CO2e emissions relative to current transportation emissions.
Results of this analysis are summarized in Table 3. For solar-PV, CSP, and wind, the opportunity cost was zero since these all had the lowest CO2e emissions due to delays. Wave and tidal had an opportunity cost only because the lifetimes of these technologies are shorter than those of the other technologies due to the harsh conditions of being on the surface or under ocean water, so replacing wave and tidal devices will occur more frequently than replacing the other devices, increasing down time of the former. Although hydroelectric power plants have very long lifetimes, the time between their planning and initial operation is substantial, causing high opportunity cost CO2e emissions for them. The same problem arises with nuclear and coal-CCS plants. For nuclear, the opportunity CO2e is much larger than the lifecycle CO2e. Coal-CCS’s opportunity-cost CO2e is much smaller than its lifecycle CO2e. In sum, the technologies that have moderate to long lifetimes and that can be planned and installed quickly are those with the lowest opportunity cost CO2e emissions.
4c. Effects of leakage on coal-CCS emissions
Carbon capture and sequestration options that rely on the burial of CO2 underground run the risk of CO2 escape from leakage through existing fractured rock/overly porous soil or through new fractures in rock or soil resulting from an earthquake. Here, a range in potential emissions due to CO2 leakage from the ground is estimated.
The ability of a geological formation to sequester CO2 for decades to centuries varies with location and tectonic activity. IPCC32 summarizes CO2 leakage rates for an enhanced oil recovery operation of 0.00076% per year, or 1% over 1000 yr and CH4 leakage from historical natural gas storage systems of 0.1–10% per 1000 yr. Thus, while some well-selected sites could theoretically sequester 99% of CO2 for 1000 yr, there is no certainty of this since tectonic activity or natural leakage over 1000 yr is not possible to predict. Because liquefied CO2 injected underground will be under high pressure, it will take advantage of any horizontal or vertical fractures in rocks, to try to escape as a gas to the surface. Because CO2 is an acid, its low pH will also cause it to weather rock over time. If a leak from an underground formation occurs, it is not clear whether it will be detected or, if it is detected, how the leak will be sealed, particularly if it is occurring over a large area.
Here, we estimate CO2 emissions due to leakage for different residence times of carbon dioxide stored in a geological formation. The stored mass (S, e.g., Tg) of CO2 at any given time t in a reservoir resulting from injection at rate I (e.g., Tg yr−1) and e-folding lifetime against leakage is
S(t) = S(0)e−t/ + I(1−e−t/ ) (1)
The average leakage rate over t years is then
L(t) = I−S(t)/t (2)
If 99% of CO2 is sequestered in a geological formation for 1000 yr (e.g., IPCC,32 p. 216), the e-folding lifetime against leakage is approximately =100 000 yr. We use this as our high estimate of lifetime and = 5000 yr as the low estimate, which corresponds to 18% leakage over 1000 yr, closer to that of some observed methane leakage rates. With this lifetime range, an injection rate corresponding to an 80–95% reduction in CO2 emissions from a coal-fired power plant with CCS equipment,32 and no initial CO2 in the geological formation, the CO2 emissions from leakage averaged over 100 yr from eqn 1 and 2 is 0.36–8.6 g CO2 kWh−1; that averaged over 500 yr is 1.8–42 g CO2 kWh−1, and that averaged over 1000 yr is 3.5–81 g CO2 kWh−1. Thus, the longer the averaging period, the greater the average emissions over the period due to CO2 leakage. We use the average leakage rate over 500 yr as a relevant time period for considering leakage.
4d. Effects of nuclear energy on nuclear war and terrorism damage
Because the production of nuclear weapons material is occurring only in countries that have developed civilian nuclear energy programs, the risk of a limited nuclear exchange between countries or the detonation of a nuclear device by terrorists has increased due to the dissemination of nuclear energy facilities worldwide. As such, it is a valid exercise to estimate the potential number of immediate deaths and carbon emissions due to the burning of buildings and infrastructure associated with the proliferation of nuclear energy facilities and the resulting proliferation of nuclear weapons. The number of deaths and carbon emissions, though, must be multiplied by a probability range of an exchange or explosion occurring to estimate the overall risk of nuclear energy proliferation. Although concern at the time of an explosion will be the deaths and not carbon emissions, policy makers today must weigh all the potential future risks of mortality and carbon emissions when comparing energy sources.
Here, we detail the link between nuclear energy and nuclear weapons and estimate the emissions of nuclear explosions attributable to nuclear energy. The primary limitation to building a nuclear weapon is the availability of purified fissionable fuel (highly-enriched uranium or plutonium).68 Worldwide, nine countries have known nuclear weapons stockpiles (US, Russia, UK, France, China, India, Pakistan, Israel, North Korea). In addition, Iran is pursuing uranium enrichment, and 32 other countries have sufficient fissionable material to produce weapons. Among the 42 countries with fissionable material, 22 have facilities as part of their civilian nuclear energy program, either to produce highly-enriched uranium or to separate plutonium, and facilities in 13 countries are active.68 Thus, the ability of states to produce nuclear weapons today follows directly from their ability to produce nuclear power. In fact, producing material for a weapon requires merely operating a civilian nuclear power plant together with a sophisticated plutonium separation facility. The Treaty of Non-Proliferation of Nuclear Weapons has been signed by 190 countries. However, international treaties safeguard only about 1% of the world’s highly-enriched uranium and 35% of the world’s plutonium.68 Currently, about 30 000 nuclear warheads exist worldwide, with 95% in the US and Russia, but enough refined and unrefined material to produce another 100 000 weapons.69
The explosion of fifty 15 kt nuclear devices (a total of 1.5 MT, or 0.1% of the yields proposed for a full-scale nuclear war) during a limited nuclear exchange in megacities could burn 63–313 Tg of fuel, adding 1–5 Tg of soot to the atmosphere, much of it to the stratosphere, and killing 2.6–16.7 million people.68 The soot emissions would cause significant short- and medium-term regional cooling.70 Despite short-term cooling, the CO2 emissions would cause long-term warming, as they do with biomass burning.62 The CO2 emissions from such a conflict are estimated here from the fuel burn rate and the carbon content of fuels. Materials have the following carbon contents: plastics, 38–92%; tires and other rubbers, 59–91%; synthetic fibers, 63–86%;71 woody biomass, 41–45%; charcoal, 71%;72 asphalt, 80%; steel, 0.05–2%. We approximate roughly the carbon content of all combustible material in a city as 40–60%. Applying these percentages to the fuel burn gives CO2 emissions during an exchange as 92–690 Tg CO2. The annual electricity production due to nuclear energy in 2005 was 2768 TWh yr−1. If one nuclear exchange as described above occurs over the next 30 yr, the net carbon emissions due to nuclear weapons proliferation caused by the expansion of nuclear energy worldwide would be 1.1–4.1 g CO2 kWh−1, where the energy generation assumed is the annual 2005 generation for nuclear power multiplied by the number of yr being considered. This emission rate depends on the probability of a nuclear exchange over a given period and the strengths of nuclear devices used. Here, we bound the probability of the event occurring over 30 yr as between 0 and 1 to give the range of possible emissions for one such event as 0 to 4.1 g CO2 kWh−1. This emission rate is placed in context in Table 3.
4e. Analysis of CO2e due to converting vehicles to BEVs, HFCVs, or E85 vehicles
Here, we estimate the comparative changes in CO2e emissions due to each of the 11 technologies considered when they are used to power all (small and large) onroad vehicles in the US if such vehicles were converted to BEVs, HFCVs, or E85 vehicles. In the case of BEVs, we consider electricity production by all nine electric power sources. In the case of HFCVs, we assume the hydrogen is produced by electrolysis, with the electricity derived from wind power. Other methods of producing hydrogen are not analyzed here for convenience. However, estimates for another electric power source producing hydrogen for HFCVs can be estimated by multiplying a calculated parameter for the same power source producing electricity for BEVs by the ratio of the wind-HFCV to wind-BEV parameter (found in ESI ). HFCVs are less efficient than BEVs, requiring a little less than three times the electricity for the same motive power, but HFCVs are still more efficient than pure internal combustion (ESI ) and have the advantage that the fueling time is shorter than the charging time for electric vehicle (generally 1–30 h, depending on voltage, current, energy capacity of battery). A BEV-HFCV hybrid may be an ideal compromise but is not considered here.
In 2007, 24.55% of CO2 emissions in the US were due to direct exhaust from onroad vehicles. An additional 8.18% of total CO2 was due to the upstream production and transport of fuel (ESI ). Thus, 32.73% is the largest possible reduction in US CO2 (not CO2e) emissions due to any vehicle-powering technology. The upstream CO2 emissions are about 94.3% of the upstream CO2e emissions.58
Fig. 2 compares calculated percent changes in total emitted US CO2 emissions due to each energy-vehicle combination considered here. It is assumed that all CO2e increases or decreases due to the technology have been converted to CO2 for purposes of comparing with US CO2 emissions. Due to land use constraints, it is unlikely that corn or cellulosic ethanol could power more than 30% of US onroad vehicles, so the figure also shows CO2 changes due to 30% penetration of E85. The other technologies, aside from hydroelectric power (limited by land as well), could theoretically power the entire US onroad vehicle fleet so are not subject to the 30% limit.
Converting to corn-E85 could cause either no change in or increase CO2 emissions by up to 9.1% with 30% E85 penetration (ESI , I37). Converting to cellulosic-E85 could change CO2 emissions by +4.9 to −4.9% relative to gasoline with 30% penetration (ESI , J16). Running 100% of vehicles on electricity provided by wind, on the other hand, could reduce US carbon by 32.5–32.7% since wind turbines are 99.2–99.8% carbon free over a 30 yr lifetime and the maximum reduction possible from the vehicle sector is 32.73%. Using HFCVs, where the hydrogen is produced by wind electrolysis, could reduce US CO2 by about 31.9–32.6%, slightly less than using wind-BEVs since more energy is required to manufacture the additional turbines needed for wind-HFCVs. Running BEVs on electricity provided by solar-PV can reduce carbon by 31–32.3%. Nuclear-BEVs could reduce US carbon by 28.0–31.4%. Of the electric power sources, coal-CCS producing vehicles results in the least emission reduction due to the lifecycle, leakage, and opportunity-cost emissions of coal-CCS.
5. Effects on air pollution emissions and mortality
Although climate change is a significant driver for clean energy systems, the largest impact of energy systems worldwide today is on human mortality, as indoor plus outdoor air pollution kills over 2.4 million people annually (Introduction), with most of the air pollution due to energy generation or use.
Here, we examine the effects of the energy technologies considered on air pollution-relevant emissions and their resulting mortality. For wind, solar-PV, CSP, tidal, wave, and hydroelectric power, air-pollution relevant emissions arise only due to the construction, installation, maintenance, and decommissioning of the technology and as a result of planning-to-operation delays (Section 4b). For corn and cellulosic ethanol, emissions are also due to production of the fuel and ethanol-vehicle combustion. For non-binary geothermal plants (about 85% of existing plants) emissions also arise due to evaporation of NO, SO2, and H2S. The level of direct emissions is about 5% of that of a coal-fired power plant. For binary geothermal plants, such emissions are about 0.1% those of a coal-fired power plant. For nuclear power, pollutant emissions also include emissions due to the mining, transport, and processing of uranium. It is also necessary to take into the account the potential fatalities due to nuclear war or terrorism caused by the proliferation of nuclear energy facilities worldwide.