Energy & Technology
This post originally appeared on Txchnologist
At a time when many are adopting the narrative that carbon markets are faltering, the European Union (EU) is aggressively pursuing the expansion of theirs to include aviation. One of only two mandatory greenhouse gas (GHG) cap-and-trade systems in the world, the EU Emissions Trading Scheme (ETS) plans to fold in a new sector beginning in January 2012. Our research shows reducing GHG emissions from aviation is critical if we are to mitigate the impacts of global climate change. Low-carbon fuel technology and other technologies for airplanes are advancing at a rapid clip, but we need a climate policy – either a price on carbon or something else – to get over the hump.
- Anaerobic digesters provide a variety of environmental and public health benefits including: greenhouse gas abatement, organic waste reduction, odor reduction, and pathogen destruction.
- Anaerobic digestion is a carbon-neutral technology to produce biogas that can be used for heating, generating electricity, mechanical energy, or for supplementing the natural gas supply.
- In 2010, 162 anaerobic digesters generated 453 million kWh of energy in the United States in agricultural operations, enough to power 25,000 average-sized homes.
- In Europe, anaerobic digesters are used to convert agricultural, industrial, and municipal wastes into biogases that can be upgraded to 97 percent pure methane as a natural gas substitute or to generate electricity. Germany leads the European nations with 6,800 large-scale anaerobic digesters, followed by Austria with 551.
- In developing countries, small-scale anaerobic digesters are used to meet the heating and cooking needs of individual rural communities. China has an estimated 8 million anaerobic digesters while Nepal has 50,000.
Figure 1: Number of operating anaerobic digesters in select European countries.
Source: Country Report of Member Countries, Istanbul, April 2011. IEA Bioenergy Task 37.
Anaerobic digestion is a natural process in which bacteria break down organic matter in an oxygen-free environment to form biogas and digestate. A broad range of organic inputs can be used including manure, food waste, and sewage, although the composition is determined by the industry, whether it is agriculture, industrial, wastewater treatment, or others. Anaerobic digesters can be designed for either mesophilic or thermophilic operation – at 35°C (95°F) or 55°C (131°F), respectively. Temperatures are carefully regulated during the digestion process to keep the mesophilic or thermophilic bacteria alive. The resulting biogas is combustible and can be used for heating and electricity generation, or can be upgraded to renewable natural gas and used to power vehicles or supplement the natural gas supply. Digestate can be used as fertilizer.
Anaerobic digestion has a defined process flow that consists of four distinct phases: pre-treatment, digestion, biogas processing and utilization, and disposal or reuse of solid waste.
- In pre-treatment, wastes may be processed, separated, or mixed to ensure that they will decompose in the digester;
- During digestion, waste products are broken down by bacteria and biogas is produced;
- Biogas produced is either combusted or upgraded and then used to displace fossil fuels. During upgrading, scrubbers, membranes, or other means are used to remove impurities and carbon dioxide (CO2) from biogas; and
- Reuse or disposal of solid digested waste. Digested waste has a high nutrient content and can be used as fertilizer so long as it is free of pathogens or toxics, or it can be composted to further enhance nutrient content.
Digestion, or decomposition, occurs in three stages. The first stage consists of hydrolysis and acidogenesis, where enzyme secreting bacteria convert polymers into monomers like glucose and amino acids and then these monomers are transformed into higher volatile fatty acids. The second stage is acetogenesis, in which bacteria called acetogens convert these fatty acids into hydrogen (H2), CO2, and acetic acid. The final stage is methanogenesis, where bacteria called methanogens use H2, CO2, and acetate to produce biogas, which is around 55-70 percent methane (CH4) and 30-45 percent CO2.
Types of anaerobic digesters
Though there are many different types of digesters that can be used for agricultural, industrial, and wastewater treatment facility wastes, digesters can be broadly grouped based on their ability to process liquid or solid waste types (Table 1).
Table 1: Types of Anaerobic Digesters
Type of waste
Covered lagoon digester/Upflow anaerobic sludge blanket/Fixed Film
Complete mix digester
Plug flow digester
Covered lagoon or sludge blanket type digesters are used with wastes discharged into water. The decomposition of waste in water creates a naturally anaerobic environment.
Complete mix digesters work best with slurry manure or wastes that are semi-liquid (generally, when the waste’s solids composition is less than 10 percent). These wastes are deposited in a heated tank and periodically mixed. Biogas that is produced remains in the tank until use or flaring.
Plug flow digesters are used for solid manure or waste (generally, when the waste’s solids composition is 11 percent or greater). Wastes are deposited in a long, heated tank that is typically situated below ground. Biogas remains in the tank until use or flaring.
Uses of Anaerobic Digesters
Anaerobic digesters are utilized in many situations where industrial or agricultural operations produce a significant organic waste stream. In addition, municipal solid waste (MSW) landfills produce landfill gas from natural decomposition of organic material in the waste that can be captured for use as an energy source. Many MSW sites now have wells to capture biogas produced from waste decomposition.Wastewater treatment plants (WWTPs) can also be converted to operate anaerobically, and they can be used to produce biogas from a variety of wastes.
In agriculture, animal and crop wastes are typically used as a feedstock for anaerobic digesters. Domestically, there are about 162 agricultural anaerobic digester systems. They collectively produced approximately 453,000 megawatt-hours (MWh) of energy in 2010, enough to power 25,000 average U.S. homes.Different types of digesters are used depending on the existing waste management system for a given farm.
Figure 2: Components and Products of a Biogas Recovery System.
Organic waste generated by industrial processes, particularly waste from the food processing industry, can be used as a feedstock for an anaerobic digester. Food waste makes an excellent feedstock, as it has as much as 15 times the methane production potential that dairy cattle manure does. Food waste substrates may also be combined with manure to improve methane generation in a process known as co-digestion. Much like agriculture, different digesters are used depending on the moisture content of the waste feedstock. Biogas is typically used for heat or other energy production when produced from industrial wastes.
Wastewater treatment plants (WWTP)
Wastewater treatment facilities employ anaerobic digesters to break down sewage sludge and eliminate pathogens in wastewater. Often, biogas is captured from digesters and used to heat nearby facilities. Some municipalities have even begun to divert food waste from landfills to WWTPs; this relieves waste burdens placed on local landfills and allows for energy production.
Municipal solid waste (MSW)
The compaction and burial of trash at MSW facilities creates an anaerobic environment for decomposition. As a result, landfills naturally produce large amounts of methane. Gas emitted from MSW facilities is typically called landfill gas, as opposed to biogas. The primary difference between the two is the lower methane content of landfill gas relative to biogas – approximately 45-60 percent compared to 55-70 percent. There are 510 MSW facilities in the U.S. that utilize landfill gas capture to reclaim naturally emitted methane, which generate enough energy to power 433,000 homes. 
In a landfill gas collection system, gas is directed from various points of origin in waste facilities to a central processing area using a system of wells, blowers, flares, and fans. It is then upgraded and either flared to reduce odor and greenhouse gas (GHG) emissions or combusted to produce energy or heat. Since it has lower methane content than biogas, it requires greater upgrading in order to become a substitute for natural gas. The figure below depicts a MSW landfill gas system.
Figure 3: Diagram of a Landfill Gas Collection System.
Source: Landfill Gas. City of Ann Arbor, MI.
Environmental Benefit/Emission Reduction Potential
Anaerobic digesters make several contributions to climate change mitigation. First, in many cases, digesters capture biogas or landfill gas that would have been emitted anyway because of the nature of organic waste management at the facility where the digester is in operation. By capturing and combusting biogas or landfill gas, anaerobic digesters are preventing fugitive methane emissions. Methane is a potent GHG with a global warming potential 25 times that of CO2. When the captured biogas or landfill gas is combusted, methane is converted into CO2 and water, resulting in a net GHG emissions reduction. Some digesters simply incorporate flares designed to burn the biogas they capture instead of using it for heat or energy applications. This is usually done when it is not cost-effective to install heat or energy generation equipment in addition to the digester.
Another benefit of anaerobic digesters is the displacement of fossil fuel-based energy that occurs when biogas is used to produce heat or electricity. Biogas is generally considered to be a carbon-neutral source of energy because the carbon emitted during combustion was atmospheric carbon that was recently fixed by plants or other organisms, as opposed to the combustion of fossil fuels where carbon sequestered for millions of years is emitted into the atmosphere. As such, substituting energy from biogas for energy from fossil fuels cuts down on GHG emissions associated with energy production.
GHG emissions are also reduced when the nutrient-rich digestate created from anaerobic digestion is used to displace fossil-fuel based fertilizers used in crop production. This digestate makes a natural fertilizer that is produced with renewable energy as opposed to fossil fuels.
Additional environmental benefits outside of GHG reduction stem from the use of anaerobic digesters. For one, the process of anaerobic digestion reduces waste quantities by decomposing organic material. This alleviates the disposal burden on municipal landfills and cuts down on environmental problems associated with landfilling or stockpiling large amounts waste, including problems such as water supply contamination, eutrophication—where oxygen levels in surrounding bodies of water may decrease due to algal blooms brought on by nutrient loading— and land resource constraints. Anaerobic digesters and the combustion of biogas also eliminate noisome odors created by organic decomposition. For MSWs, landfill gas capture facilities prevent hazards associated with the accumulation and subsurface migration of flammable landfill gas. Finally, anaerobic digesters reduce the number of pathogens present in many types of waste.
The net-cost of anaerobic digesters and the production of biogas depend on a number of factors, including the following:
- the methane production potential of the feedstock used;
- digester type;
- volume of waste and intended hydraulic retention time;
- the amount of waste available as a feedstock;
- the capital and operating costs of the digester type needed for a particular application;
- the intended use of the biogas produced; and
- the value of the fertilizer produced as a byproduct of digestion.
The type and size of the digester used will have a large impact on cost, as some digesters are more costly to construct and operate. The use of biogas will also have an effect on the net-cost of an anaerobic digester. Depending on the project and the region in which it is being developed, the type of fuel a digester is displacing will have an effect on its net-cost. For instance, substituting upgraded biogas for natural gas—as opposed to using it to produce electricity—in an area where electricity is a less expensive energy source will make a project more cost-effective. In some cases, the use of a digester will have external benefits that may not be reflected in its cost. For example, anaerobic digestion may cut down on municipal waste disposal costs by decreasing the amount of waste deposited in landfills. It may also decrease environmental regulation compliance costs, such as those associated with water protection or odor control.
The EPA has issued some cost estimates for digesters in livestock operations. These estimates, based on farm and animal size, are expressed in animal units (AUs) equal to 1,000 pounds of live animal weight. Costs estimates are as follows:
- Covered lagoon digester: $150-400 per AU
- Complete mix or plug flow digester: $200-400 per AU
These estimates are based solely on the upfront capital costs associated with installing a digester and do not include operating costs or costs of installing energy generation equipment like turbines.
Current Status of Anaerobic Digesters
Experimentation with controlled, industrialized anaerobic digesters began in the middle of the 19th century. In 1895, Exeter, England used biogas from a sewage treatment facility to power street lamps. While the relatively low cost of fossil fuels has stymied anaerobic digester development in industrialized nations since then, small-scale digesters have been employed by developing nations to provide heat and energy. For example, in China it is estimated that 8 million small-scale digester systems are in operation today, mostly providing biogas for cooking and lighting in households.U.S. farms first began using digesters in the 1970’s. Around 120 agricultural digesters existed by the 1980’s because of federal incentives, but costs and performance issues inhibited further development.A new series of incentives and policies has helped to motivate new growth in agricultural digesters. For example, incentives in the form of grants and loan guarantees offered through the EPA’s AgStar program, and policies in the form of renewable electricity portfolio standards, have helped to catalyze digester installation. Today, there are around 162 agricultural anaerobic digester systems, many of which are new. They collectively produced around 453,000 megawatt hours (MWh) of energy in 2010. Average figures for industrial digesters do not exist, but new digester technology has made it easier to process waste and incentives have made the use of industrial digesters more cost effective.
Many MSW facilities have begun to utilize landfill bioreactors to produce electricity, eliminate odors, and prevent hazards. Currently, the EPA estimates that around 510 MSW facilities combust landfill gas to generate electricity and heat and an additional 510 MSW facilities could be converted for electricity generation cost-effectively.
WWTPs have also begun to employ digesters in greater numbers because of their waste reduction and energy benefits. The EPA estimates that 544 large WWTPs (those that process more than five million gallons of wastewater per day) currently utilize anaerobic digesters to produce biogas. This represents around half of the WWTPs of this size nationally.
Several European nations have ambitious targets for biogas usage in vehicles. Germany and Austria have mandates requiring that 20 percent biogas be used in natural gas vehicles. Feed-in tariffs established for biogas in Germany have also catalyzed the development of anaerobic digesters. Currently, 6,800 agricultural digesters exist in Germany, an increase from 4,000 in 2009. Sweden, which has nearly 11,500 natural gas vehicles, estimates that biogas meets half of its fuel needs, and continues to support the use of biogas as a vehicle fuel. Globally, it is estimated that 70,000 vehicles will be powered with biogas by 2010.
Obstacles to Further Development or Deployment of Anaerobic Digesters
Controlled anaerobic digestion requires sustaining somewhat delicate microbial ecosystems. Digesters must be kept at certain temperatures to produce biogas, and the introduction of inorganic or non-digestible waste can damage systems. Performance issues with agricultural digesters in the 1980’s stalled their development and damaged their reputation amongst farmers.Improvements have been made to the current generation of digesters, but questions about long-term reliability still remain.
Installation, siting, and the operation of digesters remain costly. When biogas is utilized for energy, agricultural digesters have a payback period of around 3 to 7 years; WWTP digesters have a payback period of less than 3 years, and less if food wastes are also accepted as co-digestion fuel. Financial incentives have helped to catalyze the development of digesters with longer payback periods, but uncertainty about long-term support for digester projects, in the form of tax incentives or subsidies, has impeded development.
Interconnection with the electricity grid
While the Energy Policy Act of 2005 required net metering (the ability for electricity consumers to sell electricity generated on-site back to a utility) to be offered to consumers upon request in every state, disparate policy implementation and electricity rates have hindered wide-scale adoption of anaerobic digesters for electricity generation from agricultural sources. California, for example, does not allow utility providers to apply standby charges, minimum monthly charges, or interconnection fees, but utility providers do not buy back excess electricity, leading many farmers to burn-off excess gas rather than to provide the utilities with free energy to the grid. Further hindering adoption are varying limits on the amount of electricity that may be sold back to the grid under net metering rules. The situation should improve as electricity providers gain experience in incorporating anaerobic digesters into the electrical grid.
Policy Options to Help Promote Anaerobic Digesters
Price on carbon
A price on carbon, such as that which would exist under a GHG cap-and-trade program, would raise the cost of coal and natural gas power, making anaerobic digesters more cost competitive.
Renewable Portfolio Standards
A renewable portfolio standard (sometimes called a renewable or alternative energy standard) requires that a certain percentage or absolute amount of a utility’s power plant capacity or generation (or sales) come from renewable sources by a given date. As of June 2011, 30 U.S. states and the District of Columbia had adopted a mandatory renewable or alternative energy portfolio standard and an additional seven states had set renewable energy goals. Renewable portfolio standards encourage investment in new renewable generation and can guarantee a market for this generation.
Tax credits and other subsidies
Ensuring that current incentives, such as the Federal Production Tax Credit, remain in place in the long term will sustain investment and growth in biogas production. Other forms of assistance, like grant programs and loan guarantees to anaerobic digester project developers, will also catalyze the development of digester projects.
Feed-in tariffs require that utilities purchase energy from certain generation facilities at a favorable rate. As demonstrated in Germany, a feed-in tariff that mandates the purchase of biogas energy from anaerobic digesters and provides a financial return to digester projects could catalyze their development.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
- Agriculture’s Role in Greenhouse Gas Mitigation, 2006
- U.S. Agriculture & Climate Change Legislation: Markets, Myths & Opportunities, 2010
Further Reading/Additional Resources
U.S. Environmental Protection Agency (EPA)
- The Benefits of Anaerobic Digestion of Food Waste at Wastewater Treatment Facilities
- Managing Manure with Biogas Recovery Systems: Improved Performance at Competitive Costs
 The Agstar Program. U.S. Farm Anaerobic Digestion Systems: A 2010 Snapshot. U.S. EPA. U.S. EPA. Accessed June 2, 2011.
 IEA Bioenergy Task 37. Country Reports of Member Countries, Istanbul, April 2011. International Energy Agency. Accessed June 3, 2011.
 Lukehurst, C. T., Frost, P., Al Seadi, T. Utilisation of digestate from biogas plants as biofertiliser. IEA Bioenergy. June 2010. Accessed June 3, 2011.
 Fabien, Monnet. An Introduction to the Anaerobic Digestion of Organic Waste. Biogas Max. Remade Scotland, November 2003. Accessed June 13, 2011.
 Supra note 1.
 The Benefits of Anaerobic Digestion of Food Waste At Wastewater Treatment Facilities. U.S. EPA. U.S. EPA. Accessed June 3, 2011.
 Supra note 7.
 The Agstar Program. Managing Manure with Biogas Recovery Systems. Improved Performance at Competitive Costs. U.S. EPA. U.S. EPA, Winter 2002. Accessed June 13, 2011.
 Supra note 5.
 Supra note 3.
 Supra note 7.
 Supra note 1.
 Supra note 12.
 U.S. EPA Combined Heat and Power Partnership. Opportunities for and Benefits of Combined Heat and Power at Wastewater Treatment Facilities. U.S. EPA. U.S. EPA, April 2007. Accessed June 6, 2011.
 Supra note 2.
 Supra note 7.
 Supra note 14.
 Supra note 9.
 Mullins P. A., Tikalsky S. M. Anaerobic Digester Implementation Issues. Phase II – A Survey of California Farmers (Dairy Power Production Program). California Energy Commission. December 2006. Accessed June 13 2011.
The American Recovery and Reinvestment Act of 2009 (Pub.L. 111-5, Recovery Act, ARRA) is the economic stimulus package passed by Congress on February 13, 2009, and signed by President Obama four days later. As of February 2011, the package was expected to total $821 billion in costs through 2019 delivered through a combination of federal tax cuts, temporary expansion of economic assistance provisions, and domestic spending to advance economic recovery and create new jobs, as well as save existing ones. From advancing smart grid development to supporting appliance rebate programs, the Recovery Act has allowed the United States to make significant headway in building the foundation of its clean energy economy. We recently released an update to our 2009 white paper on the U.S. Department of Energy's (DOE) Recovery Act spending. The publication summarizes DOE ARRA spending, the Recovery Act's effects on employment, and highlights a number of notable projects.
This post also appears in the National Journal Energy & Environment Experts blog in response to the question: What should drive fuel efficiency?
At a moment when it appears to many that our government can’t do anything right, the current approach to regulating vehicle fuel economy and greenhouse gas (GHG) emissions is a bright spot.
After decades of failing to tighten corporate average fuel economy (CAFE) standards, and several years when California and other states began to take the matter of setting vehicle GHG standards into their own hands, the federal government finally got its act together. In 2007 Congress enacted the Energy Independence and Security Act of 2007, tightening CAFE. In 2010, NHTSA and the U.S. Environmental Protection Agency (EPA) jointly set GHG and CAFE standards, and California agreed to conform its rules to the federal ones. NHTSA and EPA are hard at work at a second round of standards for light duty vehicles, as well as the first-ever set of similar rules for medium and heavy duty trucks.
We now have the Congress, federal and state regulators, industry and public interest groups aligned on a policy framework that is meeting important national goals of reducing oil dependence and GHG emissions, providing regulatory consistency and certainty to the industry, and creating a climate favorable to investment and innovation.
The auto industry is responding successfully. The plug-in hybrid electric Chevy Volt won the 2011 Motor Trend Car of the Year, 2011 Green Car of the Year, and 2011 North American Car of the Year. It’s also selling well. But PHEVs are just part of the story. The Chevy Cruze and Hyundai Elantra are among the nine vehicles in the U.S. marketplace that get more than 40 miles per gallon. They were also among the 10 top-selling vehicles last month. Higher sales of fuel-efficient vehicles across the board contributed to strong sales and combined profits of nearly $5.9 billion for the three U.S. automakers in the first quarter of this year.
Higher gasoline prices are heightening consumer interest in these vehicles. But we cannot rely on oil prices alone to drive us to the next generation of vehicles. Oil prices are too volatile to motivate the sustained business investment we need. And the price we pay at the pump doesn’t reflect the true cost of oil to our country. Half of the 2010 U.S. trade deficit was from oil – that’s $256.9 billion we sent overseas last year alone. The U.S. EPA estimates that the energy security benefit of reducing oil dependence is on the order of $12 per barrel. And gasoline burning inflicts enormous damage on our air quality and climate. For example, the transportation sector is responsible for more than a quarter of U.S. GHG emissions and is a major contributor to smog.
The beauty of the fuel economy and GHG standards is that they are performance based. They set targets based on important public policy goals – i.e., oil savings and GHG reductions – but leave it to industry to find the best way to meet them. They don’t “pick winners.” They should remain the core of our public policy framework for transportation.
But our current set of vehicles and fuels may not be up to the job of meeting our long-term goals. In order to level the playing field with the incumbent technologies that have benefited from nearly a century of infrastructure development and fuel-vehicle optimization, we need to make some public investment to jumpstart alternative vehicles and fuels. This has to be done carefully. We need a savvy, adaptive strategy that ensures that any subsidies are only temporary, leverages public investment with private dollars, spawns experiments and learns from them, and rewards environmental and efficiency performance.
It is not clear whether hydrogen, natural gas, electricity, or biofuels are the long-term solution to our energy and environmental challenges. But we need to continue to keep the pressure on all of them through performance-based standards, research them all, subsidize limited deployment to see how they perform in the real world, and leave it to industry and consumers to determine their ultimate success in the marketplace.
Judi Greenwald is Vice President for Innovative Solutions
Pew Center Vice President for Innovative Solutions Judi Greenwald spoke at a National Journal event about advancing solutions toward vehicle fuel efficiency. Other speakers at the May 25, 2011, forum were Sen. Lamar Alexander (R-TN), Sen. Ron Wyden (D-OR), Deputy Assistant to the President for Energy and Climate Change Heather Zichal, ANGA-AGA Joint Collaborative on Transportation Executive Director Dr. Kathryn Clay, Edison Electric Institute President Thomas Kuhn, and Association of Global Automakers President and Chief Executive Officer Michael Stanton.
- Unlike conventional fossil fueled electricity generation, nuclear power can provide electricity without direct greenhouse gas (GHG) emissions and with very low lifecycle emissions.
- In 2012 nuclear power provided nearly one fifth of total U.S. electricity and constituted 61 percent of the nation’s total non-GHG-emitting electricity generation. The United States is the largest generator of nuclear power, accounting for about 27 percent of global nuclear generation in 2011. However, absent new policies to reduce GHG emissions and promote non-emitting electricity generation, U.S. nuclear power is not expected to grow substantially in coming decades.
- Globally, nuclear power provides roughly 13 percent of total electricity generation and 39 percent of global non-fossil fueled electric power generation. The United States, France, Russia, South Korea and China account for a little more than 60 percent of global nuclear power generation; and China is rapidly expanding its fleet of nuclear power plants.
- Under new policies to reduce GHG emissions, nuclear power could be an important source of low-carbon electricity, with some analyses suggesting that nuclear power could provide more than 40 percent of U.S. electricity and nearly a quarter of global electricity by mid-century.,
- The 2011 accident at the Fukushima Daiichi power plant in Japan illustrated some of the risks of nuclear power. Addressing the threat of climate change through expanded nuclear power will require continued improvements in the safety of nuclear technology, thorough industry regulation and oversight, and a commitment to safety and security on the part of the nuclear industry.
Electric power generation is a major source of greenhouse gas (GHG) emissions, primarily carbon dioxide (CO2) from fossil fuel combustion. In the United States, electricity generation is responsible for roughly one third of total GHG emissions (80 percent of which come from coal use). Globally, electricity generation accounts for more than 27 percent of total CO2 emissions and more than one fifth of total GHG emissions. Given the magnitude of GHG emissions from the electricity sector, low-carbon electricity generation technologies are crucial for achieving the significant GHG emission reductions necessary to avoid dangerous climate change.
Nuclear power is one option in the portfolio of low-carbon electricity generation technologies, which also includes renewables (e.g., wind, solar, and biomass) and fossil fuels coupled with carbon capture and storage (CCS). Nuclear power emits no GHGs from electric power generation, and its overall lifecycle GHG emissions profile is low and similar to that of solar power. In addition, nuclear power is already a widely deployed technology and can—like coal-fueled generation—provide reliable baseload electric power.
Currently, nuclear power is by far the largest source of low-carbon electricity in the United States. In 2012, nuclear power provided nearly one fifth of total U.S. electricity, which was more than 50 percent higher than the generation from all renewable sources (including conventional hydropower). The United States has 100 operating nuclear reactors at 62 plants in 31 states; there are 4 to 6 new units expected to come online before 2020. Globally, nuclear power generates roughly 13 percent of total electricity.
In order for nuclear power to significantly expand domestically and globally, the United States and the rest of the world must adopt policies to promote low-carbon technology deployment and adequately address concerns about nuclear power safety, nuclear weapons proliferation, and the long-term handling of spent nuclear fuel.
Current nuclear power technology harnesses the energy released by nuclear fission. Atomic nuclei consist of protons and neutrons held together by a strong energy bond. In nuclear fission, a neutron strikes the nucleus of a very heavy atom and splits it apart into lighter atoms, releasing additional neutrons and energy as well. These neutrons, in turn, can fission other atoms. Under precise, controlled conditions, this nuclear fission process can occur as a continuous chain reaction that releases heat in useful amounts.
- Nuclear Fuel: Nuclear power plants predominantly use U-235, a fissile isotope of uranium, as their fuel. Uranium is a naturally occurring heavy metal whose most common isotope is the non-fissile U-238. To make reactor fuel, mined uranium must be enriched to a higher concentration of U-235. Some of the U-238 in nuclear fuel is transformed to fissile plutonium during the nuclear chain reaction, and some of this Pu-239 is, in turned, fissioned to produce useful energy. At regular intervals, nuclear reactors’ fuel must be replaced with fresh fuel when the fuel is spent—i.e., no longer capable of supporting an adequate chain reaction. This spent nuclear fuel consists mostly of uranium (up to 96 percent) mixed with certain highly radioactive elements—namely, fission products (e.g., cesium and strontium) and transuranics (e.g., plutonium and americium). The decay heat and radiotoxicity of spent nuclear fuel is dominated by the fission products for roughly the first hundred years and then by the transuranics for subsequent millennia. Currently, in the United States, spent nuclear fuel is stored first in pools of water at nuclear plants to cool the waste and provide protection from its radiation for at least 10 years; subsequently, spent nuclear fuel can be housed onsite in dry casks made of steel and/or concrete while it awaits permanent disposal or reprocessing (see below).
- Nuclear Reactors: All operating U.S. nuclear power plants are light water reactors (LWRs)—so called because they use ordinary water to transfer heat generated by the reactor to a turbine-generator which produces electricity—and LWRs are the only type of reactors under consideration for the proposed new plants in the United States., There are two types of LWR, the boiling water reactor (BWR) and the pressurized water reactor (PWR). Roughly seventy percent of U.S. nuclear reactors are PWRs. Nuclear reactors are often classified in terms of their reactor generation, or stage of reactor technology development:
- Generation I: these reactors were the prototypes and first commercial plants developed in the 1950s and ‘60s of which very few still operate.
- Generation II: these are the commercial reactors built around the world in the 1970s and ‘80s.
- Generation III/III+: Gen III reactors were developed in the 1990s and feature advances in safety and cost compared to Gen II reactors. Gen III+ reactors are the most recently developed reactor designs and have additional evolutionary design improvements. Only a few Gen III/III+ reactors have been built, but currently planned reactors in the United States are of this type.
- Generation IV: refers to the advanced reactor designs anticipated for commercial deployment by 2030 and expected to have “revolutionary” improvements in safety, cost, and proliferation resistance as well as the ability to support a nuclear fuel cycle that produces less waste.
- Nuclear Fuel Cycles: The conventional, once-through fuel cycle involves nuclear reactors that use enriched uranium as fuel and that discharge spent nuclear fuel for disposal. This is the current approach in the United States. There are two alternative fuel cycles—the current, single-pass recycle option and a fully closed fuel cycle that would use anticipated advanced technology. The single-pass recycle option, which is the approach used in France, involves “reprocessing” spent nuclear fuel to separate fissile uranium and plutonium from other nuclear waste. This uranium and plutonium can then be recycled as fuel in existing nuclear reactors. This fuel cycle reduces the volume of nuclear waste that requires disposal but not necessarily the decay heat and radiotoxicity of the waste. A recent Massachusetts Institute of Technology (MIT) study concluded that the cost of this single-pass recycle option is unfavorable compared to a once-through cycle and that the waste management benefits from a closed fuel cycle do not outweigh the attendant safety, environmental, and security considerations and economic costs. In a proposed fully closed fuel cycle, spent nuclear fuel could be reprocessed with the separated uranium, plutonium, and other long-lived radioisotopes recycled as fuel. This could reduce the long-term burden on the final nuclear waste repositories by reducing long-term decay heat and radioactivity. However, it would not eliminate the need for long-term disposal because there are long-lived fission products and wastes from processing operations that will still require permanent geological disposal. A fully closed fuel cycle, however, requires advanced “fast” burner reactors that are not yet commercially available. In theory, SNF from these “fast” reactors could be repeatedly reprocessed until all the useable fuel was fissioned while also converting nearly all the uranium in the fuel cycle to useful fuel.
Environmental Benefit/Emission Reduction Potential
Many analyses that look at the lowest-cost options for decarbonizing the electric power sector (e.g., via a GHG emissions pricing policy) project a substantial role for new nuclear power plants in meeting demand for non-emitting electricity generation.
In its 2014 outlook for “business as usual” (i.e., a scenario with no new policies), the U.S. Energy Information Administration (EIA) projects no net increase in nuclear generating capacity from now through 2040. Over the same period, EIA projects that total electricity demand will grow by 28 percent.
In contrast, EIA also modeled an economy-wide carbon price and projected that such an emission reduction policy would spur the deployment of 53 GW of additional nuclear generating capacity above the “business as usual” case by 2040.
As one indicator of the significant potential role for nuclear power in global GHG abatement, the International Energy Agency (IEA) estimated that nuclear power could provide 6 percent of total energy-related emission reductions compared to “business as usual” by 2050 (and 19 percent of emission reductions from the power sector). IEA projected that, in this scenario, nuclear power would increase from about 14 percent of global electricity generation currently to nearly one fourth of total power generation by mid-century.
Nuclear power requires very large upfront capital investments in constructing the power plant (e.g., a new 1 gigawatt nuclear power plant might cost $7 billion including the cost of financing). For nuclear power, the capital cost of the plant constitutes roughly three fourths of the levelized cost of electricity, with fuel and operations and maintenance (O&M) costs making up the remainder of the cost in roughly equal proportions., In contrast, capital costs account for roughly 40 percent of the levelized cost of electricity from a new coal power plant, and fuel costs account for about 80 percent of the levelized cost of electricity from a natural gas power plant. In short, nuclear plants are relatively expensive to build but relatively inexpensive to operate.
The cost of new U.S. nuclear power plants is uncertain due to a long hiatus in the construction of new nuclear plants in the United States, and cost estimates have been trending upward. In 2010, EIA increased its annually updated estimate of the capital cost of a generic new nuclear power plant by 37 percent, citing a trend of rising costs for capital-intensive power sector projects, higher global commodity prices, and the relative scarcity of engineering and construction firms capable of undertaking such complex projects. In a 2013 update to this report, the overnight capital costs for new nuclear plants were unchanged.
During the 1980s and early ‘90s, new nuclear power plants experienced long delays in construction schedules and massive cost overruns, which makes potential lenders see new nuclear power plants as riskier than other power plant investments and thus makes new nuclear plant construction more expensive to finance. Given the capital-intensity of nuclear power, financing is challenging for new plants.
EIA’s latest estimates for the levelized cost of electricity from new power plants using various electricity generation technologies put nuclear power at roughly the same cost as electricity from new coal plants but roughly 60 percent more costly than electricity from new natural gas combined cycle plants. This cost differential makes new nuclear power plants hard to justify without a policy that changes the relative costs of different types of electricity generation based on GHG emissions.
The once-through nuclear fuel cycle is currently the least costly approach to nuclear power.
Current Status of Nuclear Power
More than 90 percent of U.S. nuclear capacity came online in the 1970s and ‘80s before cost overruns, construction delays, and safety concerns ended this wave of nuclear plant construction. Whereas the build-out of the existing U.S. nuclear fleet saw a large number of companies building a variety of idiosyncratic nuclear plant designs with a regulatory licensing process that allowed for significant delays, a new wave of new nuclear plants in the United States is foreseen to include a small number of firms with nuclear power experience building a limited number of standardized plant designs under a new licensing framework that front-loads much of the regulatory risk.
The Energy Policy Act of 1992 overhauled the nuclear licensing process, which used to require two licenses—one to build the plant and another to operate it. Under the new process the U.S. Nuclear Regulatory Commission (NRC) can: 1) pre-approve a prospective site for a new nuclear plant, 2) certify a new reactor design, and 3) issue a single combined construction and operating license (COL).
In 2005, Congress enacted new financial incentives (mainly federal loan guarantees) to help spur the first wave of a new generation of nuclear power plants. Subsequently, U.S. electricity providers did begin to pursue new nuclear plants. Currently, COLs have been issued to South Carolina Electric & Gas for Summer (Units 2 and 3) and to Southern Company for Vogtle (Units 3 and 4). There are nine additional license applications under active review by the NRC for up to 14 new reactors, with all of the license applications filed since 2007.
Nonetheless, the high capital costs of new nuclear plants, the relatively lower cost of new natural gas generation following the domestic “shale gas revolution,” and continuing lack of federal policy to reduce GHG emissions and incentivize low-carbon energy technology all limit enthusiasm for new nuclear projects in the United States. As of April 2013, five new nuclear units are actively under construction. Watts Bar Unit 2 in Tennessee is expected to come online in December 2015. Additionally, construction is well underway at Vogtle Unit 3 in Georgia and V.C. Summer Unit 2 in South Carolina.,  The U.S. Department of Energy (DOE) has conditionally awarded a federal loan guarantee to one new nuclear plant (Vogtle) and is negotiating with three other projects. The process of licensing and building the first few new nuclear plants is expected to take approximately 9-10 years, with 4-6 new units expected to start commercial operation by 2020., 
Industry experts consider successful on-time, on-budget completion of this handful of new reactors crucial for creating confidence that new reactor construction can avoid the pitfalls of the past and enabling subsequent nuclear project developers to obtain financing from the private sector without government backing.
Nuclear power also faces potential political and public acceptance hurdles. After decades, the United States still has yet to resolve the issue of long-term handling of spent nuclear fuel. The Obama Administration withdrew the license application for the long-awaited Yucca Mountain geologic repository and appointed a blue-ribbon commission to reassess the options for long-term spent fuel management. The commission delivered its report in January 2012, and it is now up to the Administration and Congress to decide how to proceed. Presently, the United States is pursuing a once-through nuclear fuel cycle. A fully closed fuel cycle would require not just advanced reprocessing and recycling technology but also the capability to manufacture a new type of reactor fuel from the reprocessing outputs. According to the nuclear industry, the new generation of reactors necessary for a fully closed fuel cycle is decades away from commercial development.
In March 2011, a catastrophic earthquake and resultant tsunami struck Japan and led to the failure of reactor and spent fuel storage cooling systems at the Fukushima Daiichi nuclear power station and subsequent damage to the reactors and fuel rods and releases of radioactivity. Global responses to the accident have been mixed. In the immediate aftermath of the disaster, Japan had decided to shut down all of its reactors as well as discontinue a plan to build 14 new nuclear reactors by 2030. However, Prime Minister Abe plans to enhance safety standards and restart reactors. German policymakers are pushing ahead with a plan to shut down all nuclear reactors by 2022, and Switzerland has also decided to not replace its five existing reactors.,  In the United States, the Nuclear Regulatory Commission has identified several lessons learned from the accident and is implementing safety enhancements in the existing fleet. The accident is not expected to impact current U.S. nuclear construction activities. Overall, the use of nuclear power is expected to increase with an increased focus on nuclear safety driven by developing countries, especially China and India.
Worldwide, 67 new reactors are currently under construction in 13 countries. 28 of these reactors are in China, which has only 17 reactors operating now. ,  Other countries currently building multiple new reactors are Russia, India, South Korea, and the United States.
Obstacles to Further Development or Deployment of Nuclear Power
- Lack of Policies to Reduce GHG Emissions from Electricity Generation
In the absence of regulation of GHG emissions, new nuclear power is typically more expensive than existing or new conventional fossil fueled electricity generation.
- Challenges to Financing Initial Nuclear Builds
The up-front capital investments required for nuclear power plants make financing difficult for U.S. electric power generators given their relatively small market capitalizations, especially in restructured electricity markets. Many of the existing nuclear plants proved to be far more expensive to build than expected and faced long delays in construction schedules. Commercial lenders are thus reluctant to finance new nuclear plants on a project finance basis at a cost of capital comparable to other power generation technologies until “first-mover” firms demonstrate that new nuclear plants can be built on time and within budget.
- Long-Term Nuclear Waste Policy
Experts have concluded that geological repositories can safely isolate nuclear waste over the long term; however, so far no country has successfully implemented such an approach for spent nuclear fuel and high-level nuclear waste. final waste disposal facilities , The United States currently has over 60,000 tons of nuclear waste at more than 100 temporary sites (primarily nuclear power plants) around the country, and the fleet of existing nuclear power plants generates approximately 2,000 tons each year. Moreover, even the proposed fully closed fuel cycle that may be a future option will still necessitate long-term geological waste disposal.
Under the provisions of the 1982 Nuclear Waste Policy Act, the federal government has responsibility for managing spent nuclear fuel produced by commercial reactors. The federal government has been collecting fees from nuclear power generators as part of contracts that originally required DOE to begin taking spent nuclear fuel for long-term disposal in 1998. In 1987, Congress designated Yucca Mountain in Nevada as the sole candidate for a federal long-term geological repository for nuclear waste. However, the site engendered intense political opposition from Nevadans, and the Obama Administration has terminated the Yucca Mountain nuclear waste repository program. Given current law, indefinite storage at reactor sites and other existing temporary facilities is the only alternative to Yucca Mountain absent additional congressional action. Given the challenges encountered in opening a long-term geological repository, DOE has not yet begun taking spent nuclear fuel from nuclear plants and is not expected to do so for several years.
Several states—including California and Wisconsin—have laws that effectively ban the construction of new nuclear plants until a federal long-term waste disposal repository is operating. Elsewhere, the lack of a solution for long-term spent nuclear fuel management creates uncertainty for new nuclear power plant sponsors. However, the NRC has determined that spent nuclear fuel can be safely stored at reactor sites for 30 years after a reactor shuts down, and NRC has proposed at least 60 years of storage after reactor shut-down as a safe period.
- Supply Chain and Workforce Constraints
The industrial resources and supply chains needed to build and operate nuclear plants may present challenges to a significant expansion. Moreover, the current nuclear workforce is aging and retirements may exceed new entries resulting in a loss of experienced operator and maintenance personnel.
- Safety and Security
The global nuclear power industry has experienced four serious nuclear reactor accidents—at Windscale (1952) in the United Kingdom, Three Mile Island (1979) in the United States, Chernobyl (1986) in the former Soviet Union, and Fukushima Daiichi (2011) in Japan—and several fuel cycle facility incidents. Neither the Windscale nor Chernobyl facility utilized a modern containment structure. Nuclear reactor damage is a potential threat to public health as it can lead to release of radioactivity to the air and groundwater. To date, the United States has had no immediate radiological injuries or deaths among the public attributable to accidents involving commercial nuclear power reactors. Following the Three Mile Island accident, improvements were made to plant safety equipment, procedures, and training in U.S. reactor operations which significantly increased the safety of the U.S. nuclear fleet. Moreover, new reactor designs have projected risks—particularly vulnerability to loss-of-coolant accidents—that are one to two orders of magnitude less than those of operating LWRs. Nonetheless, the recent Japanese nuclear accident has once again focused attention on the safety of existing and planned nuclear reactors. However, it is important to stress that there have been no deaths attributable to radiation exposure from the Fukushima accident to date.
In addition to accidents, intentional attacks on nuclear power plants by terrorists could theoretically lead to nuclear reactor damage. Following the September 11th terrorist attacks, security at nuclear power plants came under increased scrutiny, and new regulations from the NRC increased the level of protection against terrorist attacks.
- Nuclear Weapons Proliferation
The nuclear proliferation risk stems principally from the potential for countries to covertly use uranium enrichment or spent nuclear fuel reprocessing plants to generate materials for use in nuclear weapons, and theft of poorly secured nuclear materials could result in transfer to a dangerous state or terrorist group. In particular, current commercial reprocessing technology generates separated plutonium that is directly usable in nuclear weapons.
Policy Options to Help Promote Nuclear Power
- Carbon Price
A policy, such as cap and trade (see Climate Change 101: Cap and Trade), that puts a price on GHG emissions would discourage investments in traditional fossil-fuel use and spur investments in a range of low-carbon energy technologies, including nuclear power.
- Clean Energy Standard
A policy that required electric utilities to supply increasing percentages of low-carbon electricity (e.g., a clean energy standard) would likely substantially increase investments in new nuclear power.
- GHG Performance Standards
Policymakers could rely on performance standards to drive nuclear deployment by enacting new regulations that establish maximum allowable CO2 emission rates for power plants (California, Washington, and Oregon have such standards). If stringent enough, such standards could lead power generators to turn to nuclear power and other non-emitting technologies.
- Loan Guarantees and other Financial Incentives for Initial New Nuclear Projects
The Energy Policy Act of 2005 included provisions for loan guarantees, production tax credits, and standby insurance for “first-mover” new nuclear power plants. Commercial lenders have indicated that the first wave of new nuclear plants built in the United States without assured cost recovery from electricity ratepayers would be difficult or impossible to finance without federal loan guarantees owing to the perceived high risk of such projects in light of the poor track record of constructing the existing U.S. nuclear fleet. With the current level of federal loan guarantees available for new nuclear power plants, two or three “first-mover” nuclear plants could obtain financing backed by federal loan guarantees and—if they demonstrate success in on-time, within-budget construction and operation—lower the perceived risk of investing in new nuclear power plants and make subsequent plants’ financing easier and less costly. An expanded loan guarantee program could support more “first-mover” nuclear projects.
- Defining a Long-Term Policy for Nuclear Waste
In January 2010, President Obama established the Blue Ribbon Commission on America’s Nuclear Future, a step also supported by congressional leaders and the nuclear industry. The commission was tasked with evaluating alternatives and recommending a new plan for managing the back end of the nuclear fuel cycle (i.e., the storage, processing, and disposal of spent nuclear fuel). The commission’s final report was issued in 2012. Implementation of the commission’s recommendations will likely require congressional action as the only option for long-term waste management under current federal law is Yucca Mountain.
- Research and Development
MIT’s 2003 report on nuclear power recommended several avenues for research, including: advanced LWRs and high temperature gas reactors; lab-scale research on reprocessing technologies with the potential for lower cost and greater proliferation resistance; establishment of a large nuclear system analysis, modeling, and simulation project; and a global uranium resource evaluation. Several other expert reports have also suggested that efforts related to reprocessing focus on R&D rather than deployment, including reports by the Government Accountability Office, the National Academy of Sciences, and the directors of the Department of Energy’s national laboratories.
- Safety and Security
The NRC and nuclear plant owners can continue to advance nuclear plant safety via adequate regulation and oversight, continuous improvement based on operating experience, and an emphasis on safety culture. In particular, regulators and the nuclear industry will have to learn from and take steps necessary to minimize the risks exposed by the Japanese nuclear accident.
- Non-Proliferation Policies
R&D investments in and international collaboration on technical safeguards—i.e., the technologies used to monitor and protect nuclear materials from proliferation threats domestically and under international agreements—and the inclusion of increased proliferation resistance in next-generation nuclear reactor designs can limit the risk of nuclear proliferation. The MIT nuclear report and the directors of the national laboratories recommend that nuclear supplier states (e.g., the G-8) offer fuel cycle services to nations developing new nuclear capabilities on attractive terms in order to slow the process of additional nations, especially new users with only a few reactors, building enrichment and reprocessing facilities. In December 2010, the International Atomic Energy Agency (IAEA) approved the creation of such an international fuel bank, which will be funded in part by the United States.
- Supply Chain / Workforce
The federal government can foster a robust nuclear workforce via increased educational funding for relevant graduate and undergraduate university education and certification programs at community colleges. Grants for job retraining could also help displaced workers transition into nuclear and other growing energy industries.
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading / Additional Resources
Congressional Budget Office (CBO), Nuclear Power’s Role in Generating Electricity, 2008.
Congressional Research Service (CRS)
- Advanced Nuclear Power and Fuel Cycle Technologies: Outlook and Policy Options, 2008.
- Nuclear Energy Policy, 2008.
- Nuclear Waste Disposal: Alternatives to Yucca Mountain, 2009.
International Atomic Energy Agency (IAEA).
International Energy Agency (IEA)
- Energy Technology Perspectives 2010: Scenarios and Strategies to 2050, 2010.
- Technology Roadmap: Nuclear Energy, 2010.
Keystone Center, Nuclear Power Joint Fact-Finding, 2007.
Massachusetts Institute of Technology (MIT)
- The Future of the Nuclear Fuel Cycle, 2011.
- The Future of Nuclear Power, 2003.
- Update to the 2003 Report, 2009.
National Research Council of the National Academy of Sciences, Disposition of High-Level Waste and Spent Nuclear Fuel: Continuing Societal and Technical Challenges, 2001.
Nuclear Energy Agency (NEA).
Nuclear Energy Institute (NEI).
U.S. Department of Energy (DOE)
U.S. Nuclear Regulatory Commission (NRC).
 International Energy Agency (IEA), Energy Technology Perspectives 2010: Scenarios and Strategies to 2050, 2010, BLUE Map Scenario.
 EPA, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2011, 2013. See Tables ES-7 and 2-13.
 Intergovernmental Panel on Climate Change (IPCC), "Introduction." In Mitigation of Climate Change. Contribution of Working Group III to the Fourth Assessment Report. Cambridge: Cambridge University Press, 2007.
 Fthenakis, VM and HC Kim, “Greenhouse-Gas Emissions from Solar Electric- and Nuclear Power: A Life-Cycle Study,” Energy Policy 35: 2549-2557, 2007.
 Massachusetts Institute of Technology (MIT), The Future of Nuclear Power, 2003. For a helpful overview of nuclear fuel and the nuclear fuel cycle, see “Appendix Chapter 1 – Nuclear Fuel Cycle Primer.”
 Government Accountability Office (GAO), Global Nuclear Energy Partnership: DOE Should Reassess Its Approach to Designing and Building Spent Nuclear Fuel Recycling Facilities, April 2008.
 MIT, 2003.
 Holt, July 2008.
 Nuclear Energy Agency (NEA), Nuclear Energy Outlook 2008. About 20 percent of current nuclear plants today use heavy water as a moderator and coolant (mostly in Canada and India), while the United Kingdom has 18 gas-cooled reactors.
 In a BWR, the water heated by the energy released during the nuclear fission chain reaction in the reactor core turns directly into steam to power the turbine-generator (for an explanation of a BWR, see EIA’s Boiling-Water Reactor). In a PWR, the water passing through the reactor core is kept under pressure so that it does not turn to steam but rather is used to exchange heat with a separate water loop to create steam and power a turbine-generator (an explanation of a PWR, see EIA’s Pressurized-Water Reactor and Reactor Vessel).
 NEA, 2008.
 MIT, 2003.
 Holt, July 2008.
 EIA, Annual Energy Outlook 2013, April 2013. EIA projects 11 GW from new plants and 8 GW of the capacity growth from uprates at existing plants, while there are around 6 GW of plant retirements expected.
 IEA, 2010. IEA developed the BLUE Map roadmap for achieving a 50 percent reduction below current GHG emission levels in order to stabilize atmospheric CO2 concentration at 450ppm.
 The levelized cost of electricity is an economic assessment of the cost of electricity generation from a representative generating unit of a particular technology type (e.g. wind, coal) including all the costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and cost of capital.
 Du and Parsons, 2009.
 EIA, Updated Capital Cost Estimates for Electricity Generation Plants, November 2010.
 EIA, Updated Capital Costs Estimates for Utility Scale Electricity, April 2013.
 EIA, Levelized Cost of New Generation Resources in the Annual Energy Outlook 2013, April 2013.
 MIT, 2009.
 Nuclear Energy Institute (NEI), Status and Outlook for Nuclear Energy in the United States, May 2009.
 NEI, April 2011.
 NEI, April 2011. NEI reports that this 9-10 year process breaks down as follows: approximately two years to prepare an application to the NRC for a COL, approximately three and a half years for NRC review and approval of the COL, and 4-5 years for construction. NEI expects that subsequent plants might have a licensing and construction timeline of only about six years.
 Blue Ribbon Commission on America’s Nuclear Future, January 2012.
 NEI, Advanced Fuel-Cycle Technologies Hold Promise for Used Fuel Management Program, Jan 2009.
 NEI, Jan 2009.
 Tabuchi, Hiroko, “Japanese Nuclear Regulator Announces an Overhaul of Safety Guidelines.” New York Times, 19 June 2013.
 BBC, Swiss to phase out nuclear power. 25 May 2011. Switzerland will continue to utilize nuclear power until the end of the reactor’s operative lifetime. Its five units will be retired between 2019 and 2034.
 WNA, World Nuclear Power Reactors & Uranium Requirements, June 2013.
 Xu, Wan, “China to Erect Nuclear Reactors to Match U.S.,” Wall Street Journal, 27 May 2009.
 MIT, 2009.
 MIT, 2003.
 NEI, “Sweden Picks Location for Its Used Fuel Repository,” Nuclear Energy Insight, July 2009.
 Wald, Matthew, “As Nuclear Waste Languishes, Expense to U.S. Rises,” New York Times, 17 February 2008.
 Vogel, 2009.
 Holt, Mark, Nuclear Waste Disposal: Alternatives to Yucca Mountain, CRS, February 2009.
 Directors of DOE National Laboratories, A Sustainable Energy Future: The Essential Role of Nuclear Energy, Aug 2008.
 Klein, Dale, “Perspectives and Challenges of the Nuclear Renaissance,” Address by NRC Chairman to the American Nuclear Society, Raleigh, NC, 31 January 2008.
 NEI, “New Nuclear Plants Create Opportunities for Expanding US Manufacturing,” August 2008.
 U.S. Department of Energy (DOE), DOE NP2010 Nuclear Power Plant Construction Infrastructure Assessment, 2005.
 MIT, 2003. See the MIT report for examples of fuel cycle facility incidents.
 Keystone, 2007.
 Keystone, 2007.
 Holt, July 2008.
 Nuclear Energy Study Group of the American Physical Society (APS) Panel on Public Affairs, Nuclear Power and Proliferation Resistance: Securing Benefits, Limiting Risk, 2005.
 APS, 2005.
 For more information on CO2 emission performance standards for electric power plants, see Rubin, Edward, A Performance Standards Approach to Reducing CO2 Emissions from Electric Power Plants, prepared for the Pew Center, June 2009.
 NEI, May 2009.
 Roy, Rukmini et al., Loan Guarantees for Advanced Nuclear Energy Facilities: Bankers' Viewpoints on DOE Implementing Regulations, Letter to DOE Secretary Bodman, March 2007.
 To illustrate the potential unmet demand for loan guarantees, project sponsors submitted 10 full applications for nuclear loan guarantees. See Slocum, John and John Reed, “Maximizing U.S. Federal Loan Guarantees for New Nuclear Energy,” Bulletin of the Atomic Scientists, 29 July 2009.
 Blue Ribbon Commission on America’s Nuclear Future, January 2012.
 MIT, 2003.
 Holt, July 2008.
 Directors of DOE National Laboratories, 2008.
 APS, 2005.
 MIT, 2003.
 Directors of DOE National Laboratories, 2008.
This post also appeared in the National Journal Energy & Environment Experts blog in response to a question about oil use and the future of electric vehicles.
Whether or not electric vehicles (EVs) take off will ultimately depend on consumer acceptance of new technology. But public policy and technological progress are just as important, as we highlight in our new report on the transportation sector.
Indeed, electric drive vehicles powered by batteries or hydrogen fuel cells could revolutionize transportation in the United States, saving considerable amounts of oil while also reducing the sector’s impact on our global climate. And the EVs on the market now are off to a great start, winning national and international awards.
Nearly all major automakers are planning to introduce these vehicles in the coming years, and I applaud automakers like Ford that have committed to building alternative drivetrains in significant number for the long haul. Companies like Ford understand climate change and the need to reduce our impact on our global environment while not sacrificing our mobility. For EVs to achieve that goal, we need policies like a clean energy standard that aim to decarbonize our electrical grid. I’m sure Ford is also investing in this space because they see a market opportunity.
The private sector has invested billions of dollars in developing, manufacturing, promoting, and distributing EVs in the last decade. From a map on our website, you can see that policymakers across the country are supporting EVs because they want their region to benefit from this burgeoning market.
Policymakers should rely on private capital as much as possible to build out the EV charging infrastructure so we can balance the desire to support alternative vehicles while also tackling our nation’s budget deficit. To that end, we should coordinate policy related to EV purchase and home charging nationwide so private players can enter new markets more easily. The most efficient way to “refuel” these vehicles is not yet clear, and we should use policy to help provide the foundation to let the market work.
Another element that is critical to the success of these vehicles is its most expensive component – the battery. Not only do we need aggressive R&D to develop batteries with much higher energy density, we also need to figure out what to do with these batteries at the vehicle’s end-of-life. About 80 percent of the battery’s capacity is still usable at this point, resulting in the largest untapped resource in this space today.
If we achieve the right mix of policy, technological progress, and consumer acceptance, there’s little reason to doubt that alternative vehicles will have a significant impact on the car market in this decade. It appears that it will be tough to kill the electric car this time.
Eileen Claussen is President
C2ES develops low-carbon solutions that aim to reduce greenhouse gas (GHG) emissions from all the major-GHG emitting sectors of the economy. Click on a sector below or on the menu on the left for more details:
2012 greenhouse gas emissions by sector according to the U.S. Environmental Protection Agency.
This post first appeared in Txchnologist.
It is too early to pick the ultimate car of the future. Plug-in electric, hydrogen fuel cell, and biofuel vehicles are currently in contention, but it is quite possible that no single alternative will dominate the future the way that gasoline-powered cars own our roads today. The competition will be fierce because these new technologies will not only be competing against each other, but also against the ever-improving internal combustion engine. By 2035, it’s quite possible a new gasoline-powered car will get 50 mpg and a hybrid-electric car (like the Toyota Prius) will achieve 75 mpg.
Whatever technologies win out, it is clear the societal costs of oil are too high. The price at the pump fails to include all the national security and environmental costs of exploration, extraction, distribution, and consumption of oil. Since oil appears cheaper to the consumer than its true cost to society, we end up consuming more than we should. We send hundreds of billions of dollars out of our economy each year – $330 billion in 2010 alone – to oil producers with monopoly power instead of investing the money here at home.
- Lighting accounts for about 11 percent of energy use in residential buildings and 18 percent in commercial buildings.
- Both conserving lighting use and adopting more efficient technologies can yield substantial energy savings. Some of these technologies and practices have no up-front cost at all, and others pay for themselves over time in the form of lower utility bills. In addition to helping reduce energy use, and therefore greenhouse gas emissions, other benefits may include better reading and working conditions and reduced light pollution.
- New lighting technologies are many times more efficient than traditional technologies such as incandescent bulbs, and switching to newer technologies can result in substantial net energy use reduction, and associated reductions in greenhouse gas emissions. A 2008 study for the U.S. Department of Energy (DOE) revealed that using light emitting diodes (LEDs) for niche purposes in which it is currently feasible would save enough electricity to equal the output of 27 coal power plants.
Nearly all of the greenhouse gas (GHG) emissions from the residential and commercial sectors can be attributed to energy use in buildings (see Climate TechBook: Residential and Commercial Sectors Overview). Embodied energy – which goes into the materials, transportation, and labor used to construct the building – makes up the next largest portion. Even so, existing technology and practices can be used to make both new and existing buildings significantly more efficient in their energy use, and can even be used in the design of net zero energy buildings—buildings that use design and efficiency measures to reduce energy needs dramatically and rely on renewable energy sources to meet remaining demand. The Energy Independence and Security Act of 2007 (EISA 2007) calls for all new commercial buildings to be net zero energy by 2030. An integrated approach provides the best opportunity to achieve significant GHG reductions because no single building component can do so by itself and different components often interact with one another to influence overall energy consumption (see Climate TechBook: Buildings Overview). However, certain key building elements can play a significant role in determining a building’s energy use and associated GHG emissions.
Lighting accounts for about 11 percent of energy use in residential buildings and 18 percent in commercial buildings, which means it uses the second largest amount of energy in buildings after heating, ventilation, and air conditioning (HVAC) systems (see Figure 1).
Figure 1: Residential Buildings Total Energy End-Use (2008)
* This chart includes an adjustment factor used by the EIA to reconcile two datasets.
Source: U.S. Department of Energy,2010 Buildings Energy Data Book, Section 2.1.5, 2010. http://buildingsdatabook.eren.doe.gov
Adjustments to lighting systems can be straightforward and achieve substantial cost savings. Consequently, addressing lighting can be a simple way to reduce a building’s energy use, and related GHGs, in a cost-effective manner. Reducing energy use from artificial lighting can be achieved in two ways:
Conservation efforts minimize the amount of time that lights are in use and can include behavioral change, building design, and automation, such as timers and sensors.
Efficiency improvements reduce the amount of energy used to light a given space, generally using a more efficient lighting technology.
This section briefly describes some of the most common ways to reduce the amount of energy consumed by lighting systems. The following options illustrate a range of conservation options—from small adjustments in daily habits to larger building design elements—that can reduce the use of artificial lighting:
- Behavioral Change
Turning off lights when they are not being used reduces energy use, GHG emissions from electricity, and utility bills. This practice may include turning off lights in unoccupied rooms or where there is adequate natural light. Adjusting artificial light output can also provide energy savings; for example, using task lighting (e.g., a desk lamp) rather than room lighting can reduce the number of fixtures in use, and dimmers allow lights to be used at maximum capacity when necessary and at low capacity when less light is needed, such as for safety lighting, mood lighting, or when some daylight is available.
- Technologies that reduce lighting use
Timers and sensors can reduce light usage to the necessary level; these options use technology to mimic the behavior described above. Sensors come in a variety of models that serve different purposes, and certain types of sensors and light fixtures are more appropriate together than others. For example, lamps that take a long time to start are not suitable for sensors that turn off and on frequently.
- Occupancy sensors help ensure that lights are only on when they are being actively used. Infrared sensors can detect heat and motion, and ultrasonic sensors can detect sound. Both must be installed correctly to ensure that they are sensitive to human activity rather than other activity in the vicinity (such as ambient noise). Some estimates suggest that occupancy sensors can reduce energy use by 45 percent, while other estimates are as high as 90 percent.,
- Photosensors use ambient light to determine the level of light output for a fixture. For example, photosensors might be used to turn outdoor lights off during daylight hours.
- Improving building design to maximize natural light
Building designs that incorporate a substantial amount of natural light also reduce the need for artificial lighting; in these cases, artificial light may become a supplement for use during the night or when otherwise needed. Architects and land planners can play a role by designing buildings to include skylights or windows and orienting these toward the south or west. Designers and building occupants can choose light paint colors that maximize reflectance, and they can orient furniture to take advantage of available light.
When addressing GHG emissions through building design, it is important to take a holistic approach that considers not just how design affects natural light, but also the heating and cooling requirements for the building. Increasing the amount of sunlight a building receives may also lead to high levels of heat intake, which can have important implications for the building’s HVAC system. For example, large windows that reduce artificial lighting might also result in heat gain that requires more air conditioning in warm climates, or the same heat gain in a colder climate might reduce the need for additional heating. In some cases, special coatings on windows can help maximize or minimize solar heat gain, depending on the desired effect (see Climate TechBook: Building Envelope). Coordinating window selection, building design, and lighting effectively can result in maximum solar light intake with the desired level of heat intake.
When artificial lighting is necessary, choosing efficient technologies can effectively reduce electricity use and related GHG emissions. In choosing among the available technologies, it is important to consider several factors, including the quality of lighting needed, the frequency of use, and the environment in which the light is being used (e.g., indoor or outdoor). The following types of lighting and fixtures are most common in buildings:
- Incandescent bulbs
These bulbs emit light when an electrical current causes a tungsten filament to glow; however, 90 percent of the energy used for the bulb is emitted as heat rather than light, making these bulbs the least efficient for most household purposes when evaluating them on a lumen (amount of light emitted) output to energy input basis. Halogen bulbs are a type of incandescent that are slightly more efficient than standard incandescent but less efficient than most other alternatives.
- Compact fluorescent lamps (CFLs) and fluorescent tubes
These emit light when an electric current causes an internal gas-filled chamber to fill withTabg ultraviolet (UV) light, which is then emitted as visible light through a special kind of coating on the tube. All fluorescent bulbs require a ballast, a component that regulates the current going through the lamp. Ballasts can be integrated into the bulb, as is the case for most CFLs (allowing them to be used interchangeably with most incandescent bulbs) or non-integrated, which require the ballast to be part of the fixture, as is the case for many fluorescent tubes used in schools and offices. Ballasts come in two varieties: magnetic (which are older and less efficient) and electronic (which are newer and much more efficient). Efficiency upgrades for fluorescent tube lights require consideration of the ballasts because they contribute significantly to the overall energy draw of the fixture.
Both CFLs and fluorescent tubes come in a variety of shapes, sizes, and efficiencies (see Figure 2 for a diagram of a typical CFL bulb). They generally use 75 percent less energy than incandescent light bulbs. A CFL produces between 50-70 lumens per watt, compared to the 10-19 lumens per watt for an incandescent bulb. They are also long-lasting products, with a lifetime of 10,000 hours for CFLs and a lifetime of 7,000-24,000 hours for tubes. Incandescent bulbs, by comparison, have a lifetime of 750-2500 hours.
Figure 2: Diagram of a Compact Fluorescent Bulb
Source: U.S. EPA/ DOE Energy Star Program. “Learn About Compact Fluorescent Light Bulbs” http://www.energystar.gov/index.cfm?c=cfls.pr_cfls_about
- High-intensity discharge (HID) lamps
HID lamps come in several varieties with widespread applications. They emit light when a current—also regulated through a ballast—is passed between two electrodes on either end of a gas-filled tube. Mercury, sodium, or metal halide gas can be used, each with different color outputs, lifetimes, and applications. These types of lights are not appropriate for all types of areas and use; for instance, HID lamps have a long start-up period—up to ten minutes—and are best used in areas where lighting must be sustained for several hours (e.g., on sports fields or for street lights). In general, HID bulbs are 75-90 percent more efficient than incandescent bulbs and have a long lifetime, with metal halide and high-pressure sodium bulbs being far more efficient than mercury vapor bulbs.
- Low-pressure sodium
Though these types of lamps are among the most efficient available for outdoor use, they are only useful for certain applications because of their long start-up time, cool-down time, and poor color rendition. Low-pressure sodium lamps are typically used for street or highway lighting, parking garages, or other security lighting. Because of their niche application, they are not typically considered as a substitute for other types of less efficient bulbs. See Table 1 for a comparison of HID and low-pressure sodium lighting.
Table 1: Characteristics of High-Intensity Discharge and Low-Pressure Sodium Lighting Types
Mercury vapor (HID)
Metal halide (HID)
High-pressure sodium (HID)
Source: U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy “High-Intensity Discharge Lighting.”
“Low-Pressure Sodium Lighting.” http://www.eere.energy.gov/basics/buildings/low_pressure_sodium.html
- Light Emitting Diode (LED)
In light-emitting diodes, electrons and electron holes (atoms that lack an electron) combine, releasing energy in the form of light. This technology has been around for several decades, but many applications of LEDs for lighting have only recently become available commercially as improved color renditions have been developed and costs reduced. LED fixtures use 75-80 percent less electricity than incandescent bulbs, and can have a lifespan 25 times longer than incandescent light bulbs. LEDs produce in the range of 27-150 lumens per watt, depending on the type of LED.10 LEDs have small, very bright bulbs and because of their size, LED fixtures are often found in specialty applications such as decorative lamps as well as functional lamps in difficult-to-reach areas, such as for strip lighting, outside lighting, display lighting, stairway lighting, etc. (see the DOE website for more information about current LED applications). LEDs are more durable than most other lighting alternatives and are more controllable because the light can be focused in a particular direction and the LED can be dimmed. Figure 3 shows the components of a typical LED.
Figure 3: Diagram of a Light Emitting Diode
Source: U.S. EPA/ DOE Energy Star Program. “Learn About LEDs” http://www.energystar.gov/index.cfm?c=lighting.pr_what_are#
The development of LEDs has generated a new field of lighting technology: solid-state lighting. Through the use of LEDs and similar products, researchers are developing an array of lighting options that use solid objects—rather than energy passed through a vacuum or gas—to produce light. The continued development of solid-state lighting will enable an even more widespread, general-use application for these types of products. At the moment, no other lighting technology offers the same level of potential to reduce energy use in the future. The DOE estimates that energy savings in 2030 from solid-state lighting could reach 190 terawatt-hours, the annual electrical output of 24 large power plants (1,000MW). This would result in a 31.4 million metric ton reduction of carbon and $15 billion in energy savings in 2030 alone.
- Hybrid Solar Lighting
In this emerging technology, a roof-mounted solar collector sends the visible portion of solar energy into light-conducting optical cables, where it is piped to interior building spaces. Controllers monitor the availability of solar light and supplement it as necessary with fluorescent lights to provide the desired illumination levels at each location. Early experiments show that hybrid lighting is a viable option for lighting on the top two floors of most commercial buildings.
This technology has other promising benefits as well. The solar collector on the rooftop can separate visible light from infrared radiation; the visible light can then be used for lighting, and the infrared radiation can be used for other purposes, such as to produce electricity, for hot water heating, or for a space heating unit. Because the energy is split, less heat energy is wasted in lighting—it is instead used for other energy-consuming items within the building.
While hybrid solar lighting systems have been developed and demonstrated in various facilities, they are currently not cost-competitive with most other lighting options. Research is underway with the goal of achieving commercial viability.
Environmental Benefit / Emission Reduction Potential
Through conservation and efficiency measures, GHG emissions associated with lighting can be reduced significantly. At the level of individual households and businesses, conservation and efficiency measures can provide lower utility bills, but widespread adoption at the societal level can result in broader GHG emission reductions and environmental benefits from the reduced demand for electricity. A range of options exists to address lighting efficiency, and using less artificial light altogether or using more efficient technologies can realize substantial environmental benefits. CFLs use 75 percent less energy and LEDs use 75 to 80 percent less energy than incandescent light bulbs; substituting these products for traditional lighting technologies, for example, can reduce net energy use.9,16
Widespread application of efficient lighting technologies will be essential for GHG emission reductions. A 2008 study for the U.S. DOE revealed that replacing LEDs for niche purposes in which LEDs are currently feasible would save enough electricity to equal the output of 27 coal power plants (see Figure 4). Though this represents only one percent of total energy consumption for lighting according to the most recent DOE estimates, savings from LED technology will increase as it is implemented on a more widespread basis. McKinsey & Co’s Pathways to a Lower-Carbon Economy, for example, projects significant energy savings from switching from incandescent and CFL bulbs to LED technology by 2030; this would not only provide GHG emission reductions from lower energy consumption, but it is also cost-effective over the lifetime of the bulbs.
Figure 4: Electricity Saved and Potential Savings of Selected Niche Applications
Source: U.S. Department of Energy (DOE). Energy Savings Estimates of Light Emitting Diodes in Niche Lighting Applications, Figure ES.1, 2008. http://www.management.energy.gov/documents/Energy_Savings_Light_Emitting_Diodes_Niche_Lighting_Apps.pdf
Greater GHG emission reductions can be achieved through integrated approaches that consider the entire building as a whole. Improving lighting may increase ambient heat (as in solar heat gain from daylighting) or decrease heat (such as reduced heat loss from inefficient bulbs), and depending on the region, season, and building design, this may relieve pressures on HVAC systems as well.
In addition to the climate benefits of efficiency and conservation in lighting, other benefits may include better reading and working conditions, reduced light pollution, and lower utility bills.
Some conservation efforts to reduce GHG emissions associated with energy use for lighting, such as turning off lights that are not in use, have no cost at all and provide immediate savings from lower utility bills. Newer technologies are more expensive up-front than incandescent light bulbs, but make up for the extra cost in savings within a months, depending on lighting use. For new buildings, incorporating design features that maximize natural light can also be an important, cost-effective element of constructing a net zero energy building.
Other conservation and efficiency measures require an upfront cost that is later recouped through lower utility bills, including:
- Installing timers and sensors
The upfront price of timers and sensors varies depending on the type and scale of installation, and overall savings depend on the net reduction in electricity consumption that results from the use of these technologies. Installation can result in net savings through lower utility bills.
- Replacing incandescent bulbs with CFLs
CFLs are more expensive than incandescent bulbs, but they provide cost savings over the lifetime of the bulb through lower electricity bills. An ENERGY STAR® CFL, for example, saves about $40 over the lifetime of the bulb compared to an incandescent light, and the payback time can be just months, depending on light bulb use.,
- Replacing incandescent or CFL bulbs with LED bulbs
LEDs range from $25 to $60 for small bulbs, but their efficiency and lifetime provide longer term savings. LEDs are currently available for certain types of lighting, such as residential downlights, portable desk lights, and outdoor area lighting. Compared to incandescent bulbs, payback periods for LEDs can range from 1.7-3.4 years, depending on the lighting use. Payback periods for LEDs compared to CFLs can range from 4.5-12.9 years.
As new and emerging technologies, such as hybrid solar lighting, become commercially available, consumers will have more options for lighting indoor and outdoor spaces using less energy, resulting in lower GHG emissions. As these technologies improve and become more widely adopted, their costs are expected to decline.
Behavioral changes to conserve energy from lighting are among the most important options for achieving emission reductions from lighting, and many of these opportunities can be realized without adopting new technology at all (for example, by turning off the lights when they are not in use). When artificial lighting is necessary, many efficient lighting products are currently available. Replacing incandescent bulbs with CFLs, for example, is both accessible and affordable. McKinsey & Company’s Pathways to a Low Carbon Economy also projects significant savings over the lifetime of the bulb by switching from outdated florescent tube bulbs to more efficient models.22
In addition to those technologies that are now widely available, a variety of new and emerging highly efficient lighting systems are currently under development to improve the technology and reduce production costs. Some technologies that are promising but not yet commercially viable, include:
- Hybrid Solar Lighting (HSL)
The technology has existed for decades, but cost considerations have thus far made widespread implementation infeasible. Currently, at least 25 facilities in the United States have installed HSL systems. Researchers are still trying to develop lower-cost systems that are marketable on a wider basis. Most research has been undertaken at the Oak Ridge National Laboratories in conjunction with DOE.
- Light Emitting Diodes (LEDs)/Solid-state Lighting.
DOE has developed a multi-year strategy to advance the research, development, and deployment of solid-state lighting technology for applications beyond the current niche opportunities for LEDs. DOE’s program includes public- and a private-sector participants, and focus areas include basic and applied research, product development, manufacturing and commercial support, and standards development.
Obstacles to Further Development or Deployment
The obstacles to increasing conservation and improving efficiency for lighting are similar to those faced by buildings broadly. These barriers include upfront cost concerns, market barriers, public policy and planning barriers, and customer barriers, such as behavioral change. Up-front costs pose a particularly notable barrier: while efficient lighting technologies and practices can pay for themselves over time, some of them – particularly cutting edge technologies – have significant up-front costs that consumers, businesses, or municipalities may be unable or unwilling to pay. Payback periods also vary in length, and building occupants may be reluctant to install efficient lighting technologies if they will be vacating the building before they can reap the full benefits of these technologies (while new occupants would realize benefits immediately).
Certain lighting technologies face unique challenges, including the following:
- Sensors/Lighting Control
- Sensors are not always able to detect and match the needs of the occupant. This is because sensors react to different wavelengths, such as visible light, ultraviolent radiation, and infrared radiation, and because they are often located far from the area of occupancy. For example, photosensors are often located on the ceiling and cannot necessarily gauge lighting needs closer to the ground.
- Motion and occupancy sensors are not widely utilized because of logistical difficulties and consumer preference. Implementation in existing structures can be problematic because of the need for new fixtures, other wiring problems, and initial costs. Occupants may also object to automatic switch-off technology if it is poorly installed and is prone to premature switching; this can be remedied by more careful installation.
- Compact Fluorescent Lamps
- Skepticism about the quality of CFL bulbs has deterred many consumers. Consumers may install the common spiral or A-shape CFL in an enclosed, recessed fixture without recognizing that only certain CFLs were built with reflectors to withstand the resultant heat, leading to shorter CFL lifespan., Moreover, manufacturers have been able to address other technical problems with early CFL models, including the start-up time, buzzing sounds, and less-appealing color temperature (a measurement that refers to the hue of light). Newer models can start in less than a second, are nearly noiseless, and are available in a variety of color temperatures.
- Concerns about mercury may be a deterrent to some consumers. CFLs contain a very small amount of mercury in each bulb—less than 1/100 of the amount in an older thermometer. However, as incandescent light bulbs require more energy and because mercury is emitted in the coal-burning process, the use of incandescent bulbs powered by coal-fired electricity generation results in mercury emissions that far exceed those of a CFL, particularly if the CFL is recycled.,
Policy Options to Help Promote Lighting Efficiency
Because lighting efficiency can be improved through many different technologies, a broad set of policies is needed to spur the development of new, highly-efficient technologies as well as to promote the adoption of existing efficient ones. Lighting standards are an important policy for driving innovation in lighting efficiency. The Energy Independence and Security Act (EISA) of 2007, for instance, contains mandates for energy efficiency standards for incandescent bulbs; these standards phase out light bulbs that do not meet a certain efficiency standard. Lighting manufacturers have since created more efficient versions of the incandescent bulb, recognizing their popularity and the policy-driven need for efficiency. While these more efficient incandescent bulbs have not approached the level of efficiency that is possible with CFLs, the phase-out of inefficient bulbs from these federal standards and the subsequent development of more efficient technology has illustrated the role federal standards can play in driving innovation.
Other policies can facilitate the adoption of efficient existing lighting technology. Loan programs and tax credits are two examples of policies that can enable people to opt for more efficient lighting as opposed to less efficient lighting options with a lower up-front cost.
Broader building policies can also inspire building owners, managers, and occupants to examine lighting systems and practices in order to reduce both costs and GHG emissions. Such policies include updated building codes, financial incentives, information and education campaigns, lead-by-example initiatives, and research and development assistance. (For more information about each of these options, see Climate TechBook: Buildings Overview.)
Related Business Environmental Leadership Council (BELC) Company Activities
Related C2ES Resources
Further Reading / Additional Resources
DOE, Office of Energy Efficiency and Renewable Energy
Environmental Defense Fund, Make the Switch: How to Pick a Better Bulb
U.S. Environmental Protection Agency (EPA) and U.S. Department of Energy (DOE), ENERGY STAR®
National Institute of Building Sciences’ Whole Building Design Guide
 Fluorescent bulbs, which use devices called “ballasts” to regulate current through the bulb, require special ballasts that can work with dimmers.
 California Department of General Services: Green California. Building Maintenance—Lighting and Occupancy Sensors.
 U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. Energy Performance Ratings for Windows, Doors, and Skylights.
 The phosphor coating on fluorescent bulbs gives them their distinctive white color.
 U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy. High-Intensity Discharge Lighting. The Energy Policy Act of 2005 outlawed mercury vapor; these lights are being phased out.
 Color rendition is a measure of the quality of color light indicating how colors will appear under different light sources, devised by the International Commission on Illumination (CIE). General Electric. GE Lighting.
 U.S. Department of Energy, Office of Renewable Energy and Energy Efficiency. Hybrid Solar Lighting Illuminates Energy Savings for Government Facilities. 2007
 Navigant Consulting, Inc. Energy Savings Estimates of Light Emitting Diodes in Niche Lighting Applications. Prepared for the U.S. Department of Energy’s Office of Energy Efficiency and Renewable Energy. 2008.
 McKinsey & Co. 2009. Pathways to a Low-Carbon Economy: Version 2 of the Global Greenhouse Gas Abatement Curve.
 The payback period is the amount of time it takes for the cost savings of the more energy efficient bulb to equal the difference in initial bulb costs. To calculate the cost of switching to CFL bulbs based on the current average price of electricity, please visit the EPA’s CFL Calculator.
 Recessed downlights are the most commonly installed type of lighting fixture in residential new construction. Please see the DOE’s Solid-State Lighting webpage for more information about specific applications.
 Cleantech Approach. When Considering an LED retrofit or incentive policy, do your research.
 Navigant Consulting, Inc. Energy Savings Potential of Solid-State Lighting in General Illumination Applications 2010 to 2030. 2010.
 Lighting Research Center at the Rensselaer Polytechnic Institute. Recommended Solutions—Photosensor Dimming: Barriers.
 Lighting Research Center at the Rensselaer Polytechnic Institute. Recommended Solutions—Automatic Shut-off Controls: Barriers.
 The EPA also has detailed instructions for safely discarding broken bulbs.
 U.S. Department of Energy, Energy Star. Frequently Asked Questions: Information on Compact Fluorescent Light Bulbs (CFLs) and Mercury. November 2010.